***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

EO12866_ CO2 RCRA Exclusion 2050

- AG60 NPRM EA _20110303

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

CONDITIONAL EXCLUSION FROM THE RCRA DEFINITION OF HAZARDOUS WASTE

FOR CO 2 STREAMS MANAGED IN UIC CLASS VI WELLS FOR THE PURPOSES OF

GEOLOGIC SEQUESTRATION, AS PROPOSED

Economics and Risk Analysis Staff Office of Resource Conservation and Recovery

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

March 1

, 201 1***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 2 of 133 ACKNOWLEDGMENTS

The Agency recognizes ICF International for the overall organization and development of this report. Lyn D. Luben of the U.S. Environmental Protection Agency,

Office of Resource Conservation and Recovery (ORCR) , provided guidance and review.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 3 of 133 TABLE OF CON TENTS

ES. EXECUTIVE SUMMA RY 5

1. INTRODUCTION 12

1.1 Need for Regula tion 13

1.2 Summary of Current Rules 14

1.3 Summary of Proposed Changes 16

1.4 Analysis of Alternatives Considered (Regulatory and Non

- Regulatory) 16

2. CHARACTERIZATION OF THE REGULATED COMMUN ITY 16

2.1 CO 2 Capture Facilities 17

2.1.1 Current CO 2 Capture Facilities 17

2.1.2 Planned CO 2 Capture Facilities 19

2.1.3 Summary of Current and Planned CO 2 Capture Facilities Considered in this Analysis 23

2.2 CO 2 Transporters 24

2.3 CO 2 Sequestration Facilities 26

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

PROPOSED RULE 29

3.1 Analytical Approach/Methodology 29

3.2 Baseline Practices 29

3.2.1 Hazardous Waste Determination Proc ess for CO 2 Capture Facilities 30

3.2.2 Baseline Practices for CO 2 Capture Facilities 31

3.2.2.1 Factors that Influence The Bas eline Practices of CO 2 Carbon Capture

Facilities 32

3.2.2.2 Expected Baseline Practices of CO 2 Carbon Capture Facilities 33

3.2 .3 Baseline Practices for CO 2 Sequestration Facilities 36***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 4 of 133 3.3 Post Rule Practices 37

3.3.1 Post Rule Practices for CO 2 Capture F acilities 37

3.3.2 Post Rule Practices for CO 2 Sequestration Facilities 38

3.4 Incremental Costs of the Proposed Rule 38

3.4.1 Compliance Costs 38

3.4.2 Social Costs 42

3.4.3 Costs to Governme nt Entities 43

3.5 Incremental Cost Savings and Benefits of the Proposed Rule 47

3.5.1 Waste Determination Savings for CO 2 Captu re Facilities 47

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

Facilities 48

3.5.3 CO 2 Treatm ent Savings for CO 2 Capture Facilities 48

3.5.4 Summary of Savings to CO 2 Capture Facilities 49

3.5.5 Waste Determination Savings for CO 2 Sequestration Facili ties 51

3.5.6 RCRA Training, Planning, and Reporting Requirement Savings for CO 2 Sequestration Facilities 52

3.5.7 Summary of Sa vings to CO 2 Sequestration Facilities 53

3.5.8 Unquantified Benefits of the Proposed Rule 55

3.6 Conclusions 55

4. REGULATORY FLEXIBILI TY ANALYSIS 56

5. REFERENCES 57

APPENDIX A: COST FO R DET ERMINING RCRA TOXICI TY OF CO 2 STREAM 59

APPENDIX B: TREATMEN T COSTS 71

APPENDIX C. SENSITIVITY ANALYSES 77

SENSITIVITY ANALYSIS 1

– FEWER AFFECTED FACIL ITIES 77

APPENDIX D. ASSESSMENT OF ENVIRO NMENTAL JUSTICE IMPA CTS 82

APPENDIX E. UNFUNDED MANDATES RE FORM ACT ANALYSIS 131

APPENDIX F. OTHER REQUIRED ANALY SES 131***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 5 of 133 ES. Executive Summary

The U.S. Env ironmental 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, c arbon dioxide (CO 2 ) streams are not listed as RCRA hazardous wastes, but may be classified as a RCRA hazardous waste if they exhibit hazardous characterist ics such as ignitability, corrosivity, reactivity, or toxicity. At present, EPA has little information to

conclude that CO 2 streams would qualify as RCRA hazardous wastes ; however, EPA is proposing to revise the regulations for hazardous waste management under RCRA to conditionally exclude carbon dioxide ( CO 2 ) streams ( that are otherwise hazardous ) from th e definition of hazardous waste, provided these CO 2 streams are captured from emission sources, are injected into Class VI Underground Injection Control (UIC) wells for purposes of geologic sequestration (GS), and meet certain other conditions. 1 2

EPA is taking this action because the Agency believes that the management of these CO 2 streams under the proposed conditions does not present a substantial risk to human health or the environment, such that additional regulation pursuant to RCRA‟s hazardous waste regulations is unnecessary. EPA expects that this amendment will substantially reduce the uncertainty associated with identifying these CO 2 streams und er RCRA subtitle C, and will also facilitate the deployment of GS by providing regulatory clarity

.

Th is analysis characterizes the regulated community that will be directly affected by the proposed rule

, estimates the expected incremental costs and bene fits of the prop osed rule,

and certifies that the rule will not have a significant economic impact on a substantial number

of small entities.

ES.1 Characterization of the Regulated Community

The entities that may be directly affected by the proposed rule include CO 2 capture facilities, transporters, and sequestration facilities.

Many electric power plants and other industrial facilities generate CO 2 as a byproduct of their operations. These facilities typically release that CO 2 into the environment. CO 2 capture
facilities are entities that collect their CO 2 byproducts and manage them in a manner other

1 EPA has finalized re quirements for the sequestration of CO 2 in Class VI underground injection wells under 40 CFR Parts 144 and 146 (Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO 2 ) Geologic Sequestration (GS) Wells) i n a sepa rate rulemaking

, (75 FR 77230) December
10, 2010 (see Docket ID EPA

– HQ

– OW

– 2008

– 0390).

2 Regulations under the Safe Drinking Water Act Underground Injection Control program contains extensive technical requirements for ensuring that underground sources of drinking water are protected during geologic sequestration (GS) of CO 2

.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 6 of 133 than releasing them into the atmosphere

. Currently EPA estimates that 27 CO 2 capture
facilities to be affected by the proposed rule. This estimate inc ludes ten facilities that currently capture CO 2 , along with 1 7 facilities expected to begin CO 2 capture in the future

. These 27 capture facilities include fossil fuel electric power generators, oil and gas extraction facilities, natural gas distribution f acilities, ethyl alcohol manufacturers, and nitrogenous fertilizer manufacturers, and appear to represent a mix of large corporations and mid

- sized companies. Exhibit ES

- 1 shows the number of CO 2 capture facilities considered in this analysis by North Ame rican Industry Classification System (NAICS) code.

Exhibit ES

- 1 : Number of Current and Planned CO 2 Capture Facilities Considered in this Analysis by Industry Sector

NAICS Industry Sector Number of Facilities

211111 Oil and Gas Extraction 9

221112 Foss il Fuel Electric Power Generation 1 5

221210 Natural Gas Distribution 1

325193 Ethyl Alcohol Manufacturing 1

325311 Nitrogenous Fertilizer Manufacturing 1

At present, for economic reasons, captured CO 2 is transported by pipeline in a supercritical

stat e (i.e., dense vapor state). 3 As of 2008 there were 30 operating CO 2 pipelines, operated by 29 separate entities. 4 Pipeline transportation of captured CO 2 falls under the “all other pipeline transportation” (i.e., transportation of substances other than crude oil, natural gas and refined petroleum products) industry (NAICS 486990). 5 These CO 2 pipelines generally appear to be operated by large corporations

. EPA has not identified any commercial entities that transport CO 2 by alternative methods, such as truck or rail that would be subject to the standards for hazardous waste transporters if the CO 2 in question was found to be hazardous

. Therefore, this analysis assumes that all transportation of CO 2 is

, and will continue to be

, conducted by pipeline

, sub ject to the Department of Transportation (DOT) Pipeline and Hazardous Material Safety Administration (PHMSA) requirements applicable to CO 2

.

CO 2 sequestration facilit ies receive captured CO 2 streams and inject them into UIC wells for the purposes of sequ estration

. EPA estimates that 29 planned sequestration facilities to be affected by the proposed rule. This estimate includes 15 planned commercial CO 2 sequestration projects and 14 planned projects funded by DOE. The 15 planned commercial projects are expected to include 12 enhanced oil recovery projects that transition to

3 56 Federal Register 26922, June 12, 1991.

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

H azardous Liquids Annual Data http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/ LIQANN08.zip

. 5 Some of the entities conducting pipeline transportation of CO 2 also may fall in to 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.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 7 of 133 sequestration in the long term and 3 saline reservoir sequestration projects. 6 Class VI UIC

wells fall under the o ther non

- hazardous waste treatment and disposal (i.e., management b y methods other than landfill, combustion, and incineration) industry (NAICS 562219). Because these Class VI well facilities are not currently operational, the characteristics of

these facilities are uncertain.

ES.2 A nalysis 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 lay s out the

“baseline” behavior that affect ed 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 , gener ators of captured CO 2
streams destine d for disposal (i.e., geological sequestration) must determine whether their

CO 2 stream is RCRA hazardous waste or non

- hazardous waste. As already stated, CO 2
streams are not listed hazardous waste, so would only be de fined 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 characterist ic 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 ove r applying RCRA characteristics to CO 2 streams, and EPA acknowledges these commenters‟ concerns. However, t his analysis assume s that

, depending

on the CO 2 generation process used by the CO 2 capture facilities , the facilities would either

test the CO 2 stre am as a gas, or rely on process knowledge and limited testing to determine

whether their CO 2 stream is a RCRA hazardous waste

.

Under the baseline scenario, if the owner/operator generator determines that the CO 2 stream is not RCRA hazardous, the generator (capture) facility may transport the CO 2 to a Class VI well for sequestration. If , however, the CO 2 stream is a RCRA hazardous waste, this analysis

assumes that the capture facility has three options: ( i) transport the CO 2 stream to a UIC

Class I hazardo us well for sequestration, ( ii) treat the CO 2 stream to render it non

- hazardous, and send it to a Class VI well for sequestration, or ( iii) cease CO 2 capture. The flow chart in

Exhibit 10 shows the possible baseline practices for CO 2 capture facilities de pending on the

results of the hazardous waste determination

.

6 Department of Energy, National Energy Tec hnology Laboratory, Carbon Capture and Storage Database, http://www.netl.doe.gov/technologies/carbon_seq/database/ index.html***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 8 of 133 Exhibit ES

- 2 : Flow Chart of Baseline Practices of CO 2 Capture Facilities

Waste

Determination CO 2 Capture Facility's

Baseline Practice

T he CO 2 stream is

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

Captured CO 2 Stream Destine for Disposal

Cease capturing the CO 2
stream

T he CO 2 stream is

RCRA hazardous Transport the CO 2 stream to a
sequest ration facility for injection in a Class I

hazardous well

Treat the CO 2 stream and transport it to a sequestration facility for injection in a

Class VI well

Note : This assessment is o f the geologic sequestration of CO 2

. While f acilitie s may capture CO 2 stream s for use in Class II well s for Enhanced Oil Recovery (EOR) , that is beyond the scope of the proposed rule

.

Exhibit ES

- 3 below presents the assumptions regarding the relative prevalence of each baseline practice for CO 2 cap ture facilities. It is important to note that these hazardous CO 2 percentages where formed as conservative assumptions for analytical purposes only. Based on early literature reviews and current CO 2 capture technologies the percentage of CO 2 streams tha t are expected to be classified as hazardous may be low.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 9 of 133 Exhibit ES

- 3 : Conservative Assum ption for the Prevalence of Hazardous Waste

Determination and Baseline Practices for CO 2 Capture Facilities a

Hazardous Waste

Determination Baseline Prac tice Assumed Baseline Percentage of Capture

Facilities a

Non

- hazardous Send the CO 2 stream to a Class VI well 10 %

Hazardous Cease capture 30 %

Send the CO 2 stream to a Class I

hazardous well that is assumed to meet the Class VI requirements 30 %

T reat the CO 2 stream such that the

stream is non

- hazardous and send it to a

Class VI well 30 %

a For purposes of this analysis EPA assumes these values due to a lack of data on the relative distribution

of CO 2 streams‟ hazardous waste designation . The se nsitivity analysis in Appendix C considers the alternative assumption that 90 percent of the CO 2 capture facilities would generate non

- hazardous CO 2 streams in the baseline.

This analysis assumes that all CO 2 transportation is done via pipelines in the baseline. Other

forms of CO 2 transportation are possible (e.g., truck, rail), but pipeline transport is the most efficient and commonly used method of transporting CO 2. 7

CO 2 sequestration facilities

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

wells and facilities with Class I hazardous wells that EPA has assumed also will meet the Class VI requirements. This analysis assumes that, in the baseline, approximately 57 percent of the sequestration wells would manage non

- hazardous CO 2 streams and treated CO 2
streams in Class VI wells. 8 The remaining wells would manage RCRA hazardous CO 2
streams in Class I hazardous wells. As mentioned above, the assumption that 90% CO 2
streams would be RCRA hazardous represents a very conservative app roach for assessing potential costs in the absence of hazardous waste characterization dat a

. At this time, EPA

has little information to conclude that CO 2 streams would qualify as RCRA hazardous

wastes

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

Post

- Rule Behavior

7 Paul W. Parfomak and Peter Folger. “Carbon Dioxide (CO2) Pipelines for Carbon Sequestration: Emerging Policy Issues,” Congressional Research Service

, Report for Congress , updated January 17, 2008

, http://assets.opencrs.com/rpts/RL 33971_20080117.pdf

. 8 The reasoning behind this assumption is explained in Section 3.2.3 of this document***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 10 of 133 This analysis assumes that all CO 2 capture facilities will claim the proposed exclusion and

send their CO 2 streams to Class VI wells a s a result of the proposed rule, because the savings associated with claiming the exclusion would exceed the implementation costs. As a result,

all CO 2 sequestration facilities are expected to manage CO 2 in permitted Class VI wells. All transportation of CO 2 would continue to be done by pipeline.

Costs of the Proposed Rule

In order to claim the exclusion

, generators and well owner/operators would have to satisfy

the conditions found in the proposed rule . This includes that both CO 2 capture faciliti es and

Class VI UIC wells each would be required to sign a certification statement which they must

maintain onsite and make available to EPA or the State

, on request. 9 The facilities would be required to renew the certification statement each year in whic h 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 stateme nt, $171 to renew the certification statement annually, and $3 each time they are requested to submit the certification. EPA would incur $47 in labor costs for each certification statement it requests and reviewed. Similarly, the States would incur $61 i n labor costs for each certification statement they request and review.

T he Agency believes that the management of these CO 2 streams under the proposed conditions does not present a substantial risk to human health or the environment, such that

additional regulation pursuant to RCRA‟s hazardous waste regulations is unnecessary. EPA does not anticipate any negative externalities as a result of this action. As a result, no social costs are expected to result from the proposed exclusion

.

Savings and Benefit s

The proposed exclusion would result in three areas of savings for CO 2 capture facilities : exclusion from hazardous waste determination, exclusion from compliance with RCRA training, planning, and reporting requirements 10 , and exclusion from hazardous was te

treatment requirements

. The analysis estimates that exclusion from hazardous waste determination would save each facility $5, 500 in one

- time costs and $3,000 in annual costs.

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

9 A single certification statement would be signed by only one facility. Each capture facility and each sequestration facility would sign its own ce rtification statement.

10 Note that facilities regulated under the Clean Air Act GHG Reporting Program (see 74 CFR 56260 and 75 FR
75060) will be required to follow the applicable reporting requirements.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 11 of 133 have treated their RCRA hazardous waste CO 2 stream in the baseline (i.e., in order to send it

to a Class VI well ) will not need to do so post

- rule and would each save approximately $10.3

million in annual treatment costs.

CO 2 sequestration facilities also would 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 c arbon capture sequestration (CCS) technology. The rule will help provide the regulatory certainty needed to foster industry adoption of CCS.

50

- Year and Annualized Net Costs and Savings

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

Exhibit ES

- 4 summarizes the undiscounted 50

- year and annualized costs and benefits of the proposed rule. Exhibits ES

- 5 and ES

- 6 summarize the 50

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

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

. 0 million. 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 expect ed to be economically significant, as defined under Executive

Order 12866.

Exhibit ES

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

Type of Entity 50

- year Costs 50

- year Savings 50

- year Net Savings Average Net

Savings
Capture Facilit ies $164,544 $2,829,383,941 $2,829,219,397 $56,584,388
Sequestration Facilities $198,456 $2,817,487 $2,619,031 $52,381

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

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

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

Exhibit ES

- 5 : Net Costs and Savings of the Proposed Rule

– 3% Discount Rate (2010 $ )

Type of Entity Present Value

of 50

- year Costs Present Value

of 50

- year Savings Present Value of 50

-

year Net Savings Annualized

Net Savings
Capture Facil ities $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)***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 12 of 133 Type of Entity Present Value

of 50

- year Costs Present Value

of 50

- year Savings Present Value of 50

-

year Net Savings Annualized

Net Savings

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

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

Exhibit ES

- 6 : Net Costs and Savings of the Proposed Rule

– 7% Discount Rate (2010 dollars)

Type of Entity Present Value

of 50

- year Costs Present Value

of 50

- year Savings Present Value of 50

-

year Net Savings Annualized

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

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

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

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

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

ES.3 Regulatory Flexibility Analysis

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

substantial number of small entities. The proposed rule relieves the regulatory burden associated with EPA‟s hazardous waste reg ulations on CO 2 capture and sequestration facilities by exempting CO 2 captured for the purpose of geological sequestration in Class VI

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

exclusion , these savings are expec ted to outweigh the cost to prepare and maintain the required certification statement. The Agency estimates that this proposed rule will lead to net cost savings in the range of $3 2.0 to $ 56.6 million annually. 11

1. Introduction

The U.S. Environmental Prot ection 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 ma nner that protects human health and the environment. Currently, c arbon dioxide (CO 2 ) stream s are not listed as RCRA hazardous wastes , but may be classified as a RCRA hazardous waste if they exhibit hazardous characteristics such as ignitability,

corrosivi ty, reactivity, or toxicity

. The Agency believes that the management of these CO 2 streams under the proposed conditions , which includes the injection into a Class VI UIC well, does not present a substantial risk to human health or the environment . As such

,

11 The estimated savings are $56.6 million undiscoun ted, $32.0 million applying a 7 percent discount rate, and $44.9 million applying a 3 percent discount rate.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 13 of 133 additional regulation pursuant to RCRA‟s hazardous waste regulations is unnecessary

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

.

This introductory chapter explains the need for regulation, summarizes the current and proposed rules, and discusses the regulatory and non

- regulatory alternatives that EPA considered. The second chapter characterizes the regulated community that will be directly affected by the proposed rule. The third chapter estimates the expected incremental c osts and benefits of the proposed rule. The fourth chapter evaluates the expected impact of the proposed rule on small businesses. The fifth chapter contains references to the data sources used to conduct the economic assessment described in this report. Other required analyses and supporting data analyses are included as appendices.

1.1 Need for Regulation

Currently if a carbon dioxide (CO 2 ) stream was determined to be a h azardous waste it would

be subject to the requirements of RCRA Subtitle C. However, EPA believes that the full set of hazardous waste regulations is unnecessary for captured CO 2 streams because existing regulations governing the transport and injection into a UIC Class VI permitted injection well

are sufficient to ensure that CO 2 streams can be safely managed when captured for the purpose of geologic sequestration (GS)

.

As discussed in EPA‟s preamble to the Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO 2 ) Geologic Sequestration (GS)

Wells final rule, a n improperly managed CO 2 GS project has the potential to endanger underground sources of drinking water (USDWs). While CO 2 itself is not a drinking water contaminant, a CO 2 stream can pose a risk to USDWs as follows: 13

CO 2 streams may c ontain impurities such as hydrogen sulfide or mercury,

CO 2 in the presence of water can cause leaching and mobilization of naturally

occurring metals or other contaminants from geologic formations into ground water (e.g., arsenic, lead, and organic compoun ds) , and

P ressures induced by injection may force native brines (naturally occurring salty water) into USDWs, causing degradation of water quality and affecting drinking

water treatment processes.

12 EPA has proposed requirements for the sequestration of CO 2 in Class VI underground injection wells under 40 CFR Parts 144 and 146 (Federal Requir ements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO 2 ) Geologic Sequestration (GS) Wells) in a separate rulemaking (see Docket ID EPA

– HQ

– OW

– 2008

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

13 Jens Birkholzer, John Apps, Liange Zheng, Yingqi Zhang, Tianfu Xu, and Chin

- Fsu Tsang

, “Research Project on CO 2 Geological Storage and Groundwater Resources: Water Quality Effects Caused by CO 2 Intrusion into Shallow Groundwater,” Lawrence Berkeley National Laboratory, #LBNL

- 1251E, 2008. http://repositories.cdlib.org/lbnl/LBNL

- 1251E , as cited by EPA in the preamble to the Federal Requirements Under the Underground Injection Cont rol (UIC) Program for Carbon Dioxide (CO 2 ) Geologic Sequestration (GS) Wells F inal R ule

, RIN 2040

- AE98

.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 14 of 133 The Class VI UIC final rule sets minimum technical crit eria for Class VI GS wells to protect

USDWs from the unique risks associated with CO 2 injection , including: 14

Site characterization that includes an assessment of the geologic, hydrogeologic, geochemical, and geomechanical properties of the proposed GS si te 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 CO 2 and is based on available site characterization, m onitoring, and operational data. Periodic reevaluation of the AoR to incorporate monitoring and operational data and verify that the CO 2 is moving as predicted within the subsurface. Well construction using materials that can withstand contact with CO 2 ov er the life of the GS project. Robust monitoring of the CO 2 stream, injection pressures, integrity of the injection well, ground water quality and geochemistry, and monitoring of the CO 2 plume and position of the pressure front throughout injection. Compr ehensive post

- injection monitoring and site care until it can be demonstrated

that movement of the CO 2 plume and pressure front have stabilized and the injectate does not pose a risk to USDWs. Financial responsibility requirements to ensure that funds wil l be available for all corrective action, injection well plugging, post

- injection site care (PISC), site closure, and emergency and remedial response.

1.2 Summary of Current Rules

Captured CO 2 streams destine for geological sequestration qualify as solid was tes, as defined

in 40 CFR 261.2 (Definition of solid waste)

. RCRA h azardous waste is a subset of solid waste to which EPA applies special requirements. A waste is considered RCRA hazardous

waste if it is specific ally l isted as hazardous in 40 CFR 261 Sub part D (Lists of Hazardous Wastes) , or if it exhibits hazardous characteristics such as ignitability, corrosivity, reactivity, or toxicity as described in 40 CFR 261 Subpart C (Characteristics of Hazardous Waste)

. CO 2 is not a listed hazardous waste but m ay 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. I f a waste is specificall y 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 exclusion s

. Because CO 2 is neither a listed waste nor excluded as a hazardous waste, generators would be required to determine if their CO 2

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

14 Preamble to the Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO 2 ) Geologic Sequestration (GS) Wells F inal R ule

, RIN 2040

- AE98

.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 15 of 133 specified in the RCRA regulations

, or by applying knowled ge of the materials and processes that generated the CO 2 stream

.

If the captured CO 2 s tream is determined to be a RCRA hazardous waste (and assuming it is to be discarded, such as through geologic sequestration, and therefore is a solid waste), the

gener ator is subject to the various hazardous waste generator standards in 40 CFR 262 (Standards Applicable to Generators of Hazardous Waste)

. Hazardous waste CO 2 s treams that are transported to an injection facility would be required to be managed in a Class I UIC

hazardous waste well that is permitted to accept RCRA hazardous waste

. A RCRA

hazardous waste CO 2 stream could not be injected into a well that is permitted as a Class VI well under the UIC Class VI regulations. The owners and operators of Class I h azardous

waste wells are subject to the hazardous waste management requirements in 40 CF R 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 (se e 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 V I UIC well

. 15

If the CO 2 s tream is not a RCRA hazardous waste , the generator would no t 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 h azardous waste wells permitted

under UIC Class I , but are geared specifically toward CO 2 sequestration. 16

, 17

CO 2 streams captured for the purpose of injection are t ypically transported by pipeline and

are subject to the Department of Transportation (DOT) P ipeline 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 theref ore pipeline transport ation would be subject to the same DOT requirements regardless of a CO 2 stream‟s RCRA status

. If a RCRA

hazardous waste CO 2 stream was to be transported by other means, such as truck or rail, the transporter would be subject to EPA‟s 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 1 71 (General

15 Permit writers also may require the RCRA hazardous waste CO 2 injection well to meet the Class VI UIC requirements as well as the Class I hazardous UIC requirements; however, there is no specific UIC regulation that would requi re permit writers to apply both the Class I hazardous and Class VI standards to a RCRA

hazardous waste CO 2 injection well.

16 Note that certain U.S. Department of Energy CO 2 injection demonstration projects have been permitted under

the UIC Class V experi mental technology well program, while other demonstration projects have been permitted under the UIC Class I non

- hazardous waste well program.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 16 of 133 Information, Regulations, and Definitions) t hrough 18 0 ( 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 th e requirements for Class VI Underground Injection Control wells, including the requirements in 40 CFR Parts 144 and 146 of the Underground Injection Control Program of the Safe Drinking Water Act

, is not a hazardous waste, provided selected conditions are met

. 18 Class VI wells injecting excluded

CO 2 would therefore not be subject to EPA‟s RCRA hazardous waste requirements. The

exclusion would apply to captured CO 2 streams o nly and would not apply to any hazardous

wastes that are mixed with or co

- injected w ith CO 2 streams.

Owners and operators of CO 2 capture facilities and sequestration wells claiming the

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

the CO 2 stream for which they are claim ing the exclusion mee ts the conditions of the

exclusion and is being injected into a well subject t o the Class VI UIC requirements.

1.4 Analysis of Alternatives Considered (Regulatory and Non

- Regulatory)

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

No action

– Under this alternative CO 2 streams captured for GS would not be

excluded from the definition of hazardous waste. CO 2 streams determined to be hazardous would be subject to EPA‟s RCRA hazardous waste requirements. EPA did not select this op tion because it would provide similar protection for human health and the environment as the proposed rule, but would maintain an unnecessary regulatory burden on CO 2 capture and sequestration facilities to comply with the hazardous waste requirements.

No n

- regulatory alternatives

– Although n on

- regulatory approaches such as educational outreach programs could increase awareness of the safety and

effectiveness of CO 2 sequestration, but would not effectively reduce the unnecessary regulatory burden placed on CO 2 capture and sequestration facilities to comply with the hazardous waste requirements under the current regulatory framework.

2. Characterization of the Regulated Community

The entities that may be directly affected by the proposed rule include CO 2 ca pture facilities, transporters, and sequestration facilities. This section identifies the regulated entities and

discusses their characteristics.

18 See : §261.4 Exclusions (h)

– Carbon Dioxide Stream Injected for Geologic Sequestration***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 17 of 133 2.1 CO 2 Capture Facilities

Many electric p ower plants and other industrial facilities generate CO 2 as a bypr oduct of their operations. These facilities typically release that CO 2 into the environment. CO 2 capture
facilities are entities that collect their CO 2 byproducts and manage them in a manner other than releasing them into the atmosphere

.

EPA estimates that 27 CO 2 capture facilities will be affected by the proposed rule. This

estimate includes ten facilities that currently capture CO 2 , along with 1 7 facilities expected to begin CO 2 capture in the future, including 1 4 commercial projects , two non

- commer cial DOE pilot projects, and one other private/federal partnership project

. The data sources that

EPA used to estimate the number of current and planned CO 2 capture facilities are presented

below in Sections 2.1.1 and 2.1.2 respectively

. Section 2.1.3 sum marizes the number of capture facilities by type of project, industry sector, and expected first year of CO 2 sequestration.

2.1.1 Current CO 2 Capture Facilities

Ten facilities are currently capturing CO 2 from chemical production or combustion processes

for the purpose of injection in a Class II UIC well for enhanced oil recovery (EOR)

. T hese

ten facilities generate d and capture d approximately 11 million metric tons of CO 2 in 2008. 19

Exhibit 1 lists these existing carbon capture facilities and their industry cl assification 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,

a t some point in the future, the existing EOR sequestrat ion facilities will likely run out of producible oil, and these existing CO 2 capture facilit ies will have to choose a different management method for their captured CO 2 streams. This analysis assumes that this transition will occur in the year 2030 for nin e of the ten current CO 2 capture facilities. The analysis assumes that the Coffeyville Fertilizer Plant will begin sequestration in 2034. 20

Exhibit 1 : U.S. Facilities C urrently C apturing CO 2 Streams a

Facility State Description Assumed

First Year of

S equestration

b NAICS NAICS

Description

Val Verde Gas

- Pikes Peak

Plant TX Processing of high CO 2 gas prod. 2030 211111 Oil and Gas

Extraction

Val Verde Gas TX Processing of high CO 2 2030 211111 Oil and Gas

19 EPA, “ Inventory of U. S. Greenhouse Gas Emissions and Sinks: 1990

- 2008,” April 15, 2010, Table 3

- 47:

Potential Emissions from CO 2 Capture and Transport, p. 3

- 53

, http://www. epa.gov/climatechange/

emissions/downloads10/US

- GHG

- Inventory

- 2010_Report.pdf

. 20 See footnote b in Exhibit 1.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 18 of 133 Facility State Description Assumed

First Year of

S equestration

b NAICS NAICS

Description

- Grey Ranch

Plant gas prod. Extraction

Val Verde Gas

- Puckett Plant TX Processing of high CO 2 gas prod. 2030 211111 Oil and Gas

Extraction

Val Verde Gas

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

Extraction

Val Verde Gas

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

Extraction La Barge Gas

Plant WY Processing of high CO 2 gas prod. 2030 211111 Oil and Gas

Extraction

Enid Ammonia

Fertilizer Plant OK Fertilizer plant CO 2 production 2030 325311 Nitrogenous

Fertilizer Manufacturing Coffeyville

Ammonia

Fertilizer Plant KS Fertilizer plant CO 2 production 2034 325311 Nitrogenous

Fertilizer Manufacturing

Antrim Gas

Plant MI Processing of high CO 2 gas prod. 2030 211111 Oil and Gas

Extraction

Great Plains

Coal

Gasification ND Synthetic Natural Gas

Plant 2030 221210 Natural Gas

Distribution

a Sources: Department of Energy, National Energy Technology Laboratory, Carbon Capture and Storage Database, http:/

/www.netl.doe.gov/technologies/ carbon_seq/database/index.html , and M assachusetts I nstitute

of T echnology, Largescale Power Plant CCS Projects Worldwide. Power Plant Carbon Dioxide Capture and Storage Projects

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

b In the research that EPA Office of Water conducted to determine the baseline for the “Cost Analysis for the Federal Requirements Under the Underground Injection Control P rogram 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 th e other current CO 2 capture facilities as a part of that research, but it did assume that EOR projects transitioning to GS would conduct EOR for 20 years before transitioning to GS (see cost analysis for the Final GS Rule). This analysis of the CO 2 exclus ion assumes that the existing EOR projects for which more specific information is not available will transition to GS 20 years f rom the present date (i.e.

, 2030 )

.

The existing CO 2 capture facilities and their parent companies vary in size. For example, th e Enid Ammonia Fertilizer Plant is operated by Koch Industries, Inc. , which has over 7 0,00 0 employees. 21 The Coffe y ville Fertilizer Plant (Coffeyville Resources LLC) employs 250 to

21 Koch Industries, 2009, http://www.kochind.com/files/070709KIILeadershipKansas.pdf.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 19 of 133 499 individuals. 22 The Great Plains Coal Gasification (Dakota Gasification CO) facility has between 500 and 999 employees. 23

2.1.2 Planned CO 2 Capture Facilities

EPA has identified an additional 3 1 planned CO 2 capture facilities

. These facilities are listed

in Exhibit 2. C ommercial CO 2 capture projects represent 2 8 of these planne d capture project s

. 24 Although all of these projects are planned, some of the m may be cancelled or delayed due to approval and funding issues. This analysis considers only fourteen planned commercial projects that EPA has deemed likely to proceed, althoug h the other planned projects are included in Exhibit 2 for reference. 25 In addition to these planned commercial projects, there are two other non

- commercial CO 2 capture pilot projects plus one other private/federal partn ership

. EPA expects all three of th ese additional projects to be

constructed , and these projects are included in Exhibit 2

.

Most of the planned commercial and DOE pilot CO 2 capture facilities are existing or proposed fossil fuel

- fired power plant s (NAICS 221112). The one other planned ca pture
facilit y considered in this analysis is a DOE pilot project involving an ethyl alcohol manufacturing plant (NAICS 325193).

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

- resources

- llc

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

- gasification

- co

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

. 25 As a part of the research that EPA Office of Water conducted to determine the baseline for the “Cost Analysis for the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule),” EPA reviewed all of the proposed projects and identified 15 commercial projects that were likely to proceed. One of those 15 projects, Coffeyville Fertilizer Plant, is already conducting

CO 2 capture and is accounted for in Exhibit 1, above. Therefore Ex hibit 2 lists only 14 planned commercial capture projects included in the analysis.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 20 of 133 Exhibit 2 : Planned CO 2 Capture and Sequestration Projects a

Project State Compan y Assumed

First Year of Sequestration

b NAIC S Industry Sector

Planned Commercial Projects Included in the Analysis

AEP Alstom Mountaineer (Ph.2) WV AEP and

Alstom 2012 221112 Fossil Fuel

Electric Power

Generation

AEP Alstom

Northeastern OK AEP and

Alstom 2032 221112 Fossil Fuel

Electric Power

Ge neration

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

G eneration

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

E lectric Power

Generation

Tenasca

Sweetwater/Trailblaze TX Tenasca Inc., Arch

Coal 2035 221112 Fossil Fuel

Electric Power

Generation

Tenasca Taylorville Energy IL Tenasca

Inc. 2035 221112 Fossil Fuel

Electric Power

Generation

Texas Clean Energy Project T X Summit

Power 2032 221112 Fossil Fuel

Electric Power

Generation***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 21 of 133 Project State Compan y Assumed

First Year of Sequestration

b NAIC S Industry Sector

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

esser 2032 221112 Fossil Fuel

Electric Power

Generation

Wallula Energy Res.

Center WA Wallula

Resource Recovery 2013 221112 Fossil Fuel

E lectric Power

Generation

Worsham

- Steed (ZENG) TX CO 2 Global

and Falcon Gas Storage 2032 221112 Fossil Fuel

Electric Power

Generation

Non

- commercial DOE Pilot Projects

Cincinnati Arch Mt.

Simon Saline

Reservoir OH Andersons

Marathon 2010 325193 Ethyl Alc ohol Manufacturing

San Joaquin Basin,

CA Saline Formation CA Clean Energy Systems 2012 221112 Fossil Fuel

Electric Power

Generation FutureGen Private/Federal Partnership

Mt. Simon Saline

Reservoir IL FutureGen

Alliance 2017 221112 Fossil Fuel

Electric P ower Generation

Planned Commercial Projects Not Included in th is Analysis

ADM Ethanol Plant

CO 2 Capture IL ADM N/A 325193 Ethyl Alcohol Manufacturing

Antelope Valley ND Basin Electric,

HTC Pure Energy N/A 221112 Fossil Fuel

Electric Power

Generation

Ba ttelle Boise White Paper Mill WA Battelle and

Boise Inc. N/A 322121 Paper Mills

C6 Resources CA C6

Resources (Shell affiliate) N/A 324110 Petroleum

Refineries

Cash Creek KY Erora Group N/A 221112 Fossil Fuel

Electric Power

Generation***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 22 of 133 Project State Compan y Assumed

First Year of Sequestration

b NAIC S Industry Sector

Cemex Odessa Projec t 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 L ake

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

P roducts, 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 B ed 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 M assachusetts I nstitute of

T echnology

, 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 t he research that EPA Office of Water

conducted to determine the bas eline for the “Cost Analysis for the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule)

. ” No sequestration start dates were determined for the projects that are not expected to proceed

.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 23 of 133 2.1.3 Summary of Current and Planned CO 2 Capture Facilities Considered in this Analysis

Exhibit 3 summarizes the number of current and proposed CO 2 capture facilities considered in the analysis by type of project

.

Exhibit 3 : Number of Curre nt and Planned CO 2 Capture Projects Identified and Considered in the Analysis

Type of Project Number of Facilities Considered in the Analysis Current Capture Plants 10 Planned Commercial Projects 14

Planned Non

- commercial DOE Pilot Projects 2

FutureGen Private/Federal Partnership 1

Total 27

Exhibit 4 summarizes the number of current and proposed CO 2 capture facilities considered in this analysis by industry sector

.

Exhibit 4 : Number of Current and Planned CO 2 Capture Facilities Considered in thi s Analysis by Industry Sector

NAICS NAICS Industry Sector Number of Facilities

211111 Oil and Gas Extraction 9

221112 Fossil Fuel Electric Power Generation 1 5

221210 Natural Gas Distribution 1

325193 Ethyl Alcohol Manufacturing 1

325311 Nitrogenous Fe rtilizer Manufacturing 1

Exhibit 5 presents the number of current and proposed CO 2 capture facilities expected to begin and practice sequestration of their CO 2 streams each year.

Exhibit 5: Number of Current and Planned CO 2 Capture Facilities Consider ed in this

Analysis Expected to Begin and Practice Sequestration by Year

Year Number of CO 2

Facilities Beginning Sequestration of their

CO 2 Streams Total Number of CO 2

Facilities Practicing Sequestration of their

CO 2 Streams

2010

- 2012 4 4

2013 1 5

2 014 0 5

2015 0 5

2016 0 5

2017 1 6***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 24 of 133 Year Number of CO 2

Facilities Beginning Sequestration of their

CO 2 Streams Total Number of CO 2

Facilities Practicing Sequestration of their

CO 2 Streams

2018 0 6

2019 0 6

2020 0 6

2021 0 6

2022 0 6

2023 0 6

2024 0 6

2025 0 6

2026 0 6

2027 0 6

2028 0 6

2029 0 6

2030 9 15

2031 1 16

2032 4 20

2033 0 20

2034 5 25

2035 2 27

2036 0 27

Post

- 2036 0 27

Tota l 27 27

2.2 CO 2 Transport ers

Captured CO 2 is t ypically transported by pipeline

. As of 2008 there were 30 operating CO 2 pipelines , operated by 29 separate entities

. 26 Several other CO 2 pipeline operators reported zero miles of pipeline in operation in 2 008 but did report miles of pipeline in operation for previous calendar years, which may indicate that the CO 2 pipeline is still in place but was idle and did not transport any CO 2 in 2008 . Therefore

, the total number of CO 2 pipelines and pipeline operator s considered in this analysis may exceed the number reported to be operating in 2008. T his analysis only considers the 29 operators of pipelines reported to be operating in 2008. Exhibit 6 lists these active CO 2 pipeline operators. The exhibit also

pres ents the miles of pipeline operated and barrel

- miles 27 of CO 2 transported in 2008 by each

operator.

Pipeline transportation of captured CO 2 falls under the “all other pipeline transportation” (i.e., transportation of substances other than crude oil, natura l gas and refined petroleum products)

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

. 27 A standard barrel contains 42 gallons.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 25 of 133 industry (NAICS 486990). 28 These CO 2 pipelines appear to be generally operated by large companies . For example, ExxonMobil Production Corp brings in between $50 and $100 million in annual revenue, and is a subsidiary of the much larger ExxonMobil C orporation. 29
EPA has not identified any commercial entities that transport CO 2 by alternative methods,

such as truck or rail that would be subject to the standards for hazardous waste transporters.

Some U

. S

. DOE demonstrati on projects have received shipments of CO 2 by truck, however, these have generally been short

- term demonstration projects involving relatively small quantities of CO 2 , Therefore, this analysis assumes that all transportation of CO 2 is , and will

continue to be conducted by pipeline.

Exhibit 6 : CO 2 Pipeline Operators in the U.S. as of 2008

CO 2 Pipeline Operator Name Miles of CO 2 P ipeline

O perated Barrel M iles

of CO 2 transported Amerada Hess Co., N. Jersey Public Svc Pipeline 23 0 Anadarko Petroleum Corp 155 14,167,044 Apache Corporation 42 288 BMC Holdings, Inc. 5 154,539

BOC Gases 7 370,392 Bravo Pipeline System 880 19,194,374 Buckeye Gulf Coast Pipeline LP 3 27,281 Chaparral Energy, LLC 105 846,088 Chevron Pipe Line Co 129 2,339,079

Dakota Gasif

ication 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

Exxon M obil Refining And Supply Company 23 0

Exxon M obil Production Company 185 54,256,4 59

Genesis Co 2 Pipeline, L.P. 9 7,130,397 Genesis Free State Pipeline, LLC 91 9,079,929 Hess Corporation 32 19,325 Kinder Morgan CO 2 Co. LP 1,207 34,250,124,275 Merit Energy Company (2 Pipelines) 138 4,343,448

Occidental Permian Ltd 8 189,000

P CS Ni trogen Fertilizer LP 1 669,939 Sandridge CO 2 , LLC 143 5,578,863 Resolute Natural Resources Company 28 14,085,537

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

29 Manta, “Exxon Mobil Corp,” http://www.manta.com/c/mmcckrf/exxon

- mobil

- corp***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 26 of 133 CO 2 Pipeline Operator Name Miles of CO 2 P ipeline

O perated Barrel M iles

of CO 2 transported The George R. Brown Partnership, L.P. 8 2,371,011 Transpetco Transport Co. 121 171,933 Trinity CO 2 LLC 137 10,426,899 XTO Energy Inc 17 3 ,218,730

Total 4,203 34,420,239,914

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

. .

2. 3 CO 2 Sequestration Facilities

CO 2 sequestration facility owners and operators are defined for the purposes of this analysis

as facilities that will rec eive captured CO 2 streams and inject them into UIC wells for the purposes of sequestration

. EPA estimates that 29 planned sequestration facilities will be affected by the proposed rule. These recommendations are consistent with EPA‟s current assumptions f

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

the Class VI rule. 30 The Class VI rule cost analysis assumes that there is no Climate Change legislation, and the baseline is based upon the most likely scenario under current law s and regulations. This EPA project forecast is a mix of actual operating or planned sites and hypothetical sites.

This estimate includes 1 5 planned commercial CO 2 sequestration projects and 14 planned projects funded by DOE. The 15 planned commercial pro jects that are expected to be

con structed are anticipated to include 12 enhanced oil recovery projects that transition to sequestration in the long term and 3 saline reservoir sequestration projects. 31

Class VI UIC wells fall under the o ther 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 facilitie s are not currently operational, the

characteristics of these facilities are uncerta in

.

Exhibit 7 summarizes the number of sequestration facilities by type. These counts are based

on the research that EPA Office of Water conducted to determine the baseline for the “Cost Analysis for the Federal Requirements Under the Underground Inject ion 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 i n the future

. EPA expects t hat 8

30 Based on the research that EPA Office of Water conducted to determine the baseline for the “Cost Analysis for the Federal Requirements Under the Un derground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule),”

31 DOE sequestration project database website http://www.netl.doe.gov/technologies/carbon_seq/database/index.html***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 27 of 133 additional DOE funded projects will be constructed, with most being in saline reservoirs

. EPA also expects that the 15 planned commercial capture facilities considered in this analysis will each have its own sequestration site and that mo st of these sites will conduct

E nhanced Oil Recovery (E OR )

.

Exhibit 7 : Summary of Sequestration Facilities Considered in this Analysis a
Category Count DOE Projects

- Named Projects/Specific Locations Followups at Existing DOE Pilots 5 FutureGen, Matoon, IL 1

Subtotal: 6 DOE Projects

- General Unspecified Projects

Small Saline Pilots 2

Commercial Scale Saline 5

Commercial Scale EOR 1

Subtotal: 8

Non

- DOE (Commercial) Projects

Commercial Saline 3 Commercial EOR Converting to G S 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 Geolog ic Sequestration Wells (Final GS

Rule )

. ”

Exhibit 8 lists the DOE Phase III sequestration demonstration projects and highlights the six projects included in the project counts above

. The Phase III of the DOE project is the demonstration phase in which a large volume of CO 2 is injected typically over several years.

Exhibit 8 : DOE Phase III Sequestration Demonstration Projects a

Regional Organization Project Name Included

in This Analysis

MGSC Illinois Basin Mt. Simon Saline Reservoir

(Decatur, IL) yes

P COR Williston Basin EOR Sequestration; ND yes PCOR Fort Nelson, BC Sandstone Saline Reservoir

(Brit. Columbia) no

Big Sky Green River Basin Nugget Sand Saline

Reservoir Moxa Arch, Western Wyoming yes

SWCARB Saline Reservoirs, Farnham Dome, Price, UT

and J through PR Sands); Uinta Basin no***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 28 of 133 SECARB Phase 1: Athropogenic CO2 in Tuscaloosa

Citronelle Oilfield EOR, Mobile AL no

SECARB Phase 2: Mississippi Tuscaloosa Massive

Saline Reservoir; SW Mississippi (Cranfield , MS ) no

MRCSP Cincinnati Arch Mt. Simon Saline

Reservoir; Greenville, OH yes

WESTCARB San Joaquin Basin, CA Saline Formation;

Olcese and Vedder Sands yes

FutureGen Project

Mt. Simon Saline Reservoir (Matoon, IL) yes

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

Exhibit 9 presents the number of CO 2 sequestration facilities expected to begin operation and

to continue to operate each year.

Exhibit 9 : Existing and Planned CO 2 Capture Facilities Expected to Begin Sequestration by Year

Year Number of Sequestration

Facilities Beginning Operation Total Number of

Sequestration Facilities in Operation

2010

- 2012 2 2

2013 1 3

2014 1 4

2015 0 4

2016 2 6

2017 10 16

2018 1 17

2019 0 17

2020 0 17

2021 0 17

2022 0 17

2023 0 17

2024 0 17

2025 0 17

2026 0 17

2027 0 17

2028 0 17

2029 0 17

2030 0 17

2031 1 18

2032 4 2 2

2033 0 22***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 29 of 133 Year Number of Sequestration

Facilities Beginning Operation Total Number of

Sequestration Facilities in Operation

2034 5 27

2035 2 29

2036 0 29

Post

- 2036 0 29

Total 29 29

3. Analysis of the Incremental Costs and Benefits of the Proposed Rule

This section analyzes the expected costs and benefits of the proposed rule. Section 3.1

describes the analy tical 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 propo sed 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 b e 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 beha vior have been established, the

a nalysis then estimates the incr emental costs and benefits of the proposed rule relative to the

baseline over a 50

- year period. 32

3.2 Baseline Practices

Depending on whether or not their captured CO 2 is RCRA hazardous

, and other site

- specific factors, generators of hazardous waste may eng age in different baseline practices to manage their captured CO 2 streams. CO 2 sequestration facilities may base their own practices on

32 Consistent with the EPA Office of Water ‟s “ Cost Analysis for the Federal Requirements Under the Underground Injection Control Program for Carbon D ioxide Geologic Sequestration Wells (Final GS Rule), ”

EPA 816

- R

- 10

- 013, July 2010.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 30 of 133 generators‟ behavior. This section discusses the hazardous waste determination process and

the n presents the possible b aseline practices for CO 2 capture and sequestration facilities. This section does not include a detailed discussion of baseline transportation practices. The most efficient and commonly used method of transporting CO 2 is by pipeline

. 33 Although

other fo rms of CO 2 transportation are possible (e.g., truck, rail), t his analysis assumes that all

CO 2 transportation is done via pipelines both in the baseline and under the proposed rule

.

3.2.1 Hazardous Waste Determination Process for CO 2 Capture Facilities

In the absence of the proposed rule, generators of captured CO 2 streams must determine

whether their capture d CO 2 stream destine for geological sequestration is RCRA hazardous

waste or non

- hazardous waste. A captured CO 2 stream may be a RCRA hazardous waste depe nding on its characteristics. Facilities must determine whether the captured CO 2 stream qualifies as hazardous waste either by testing the waste for hazardous characteristics or by applying knowledge of the materials and processes used to generate the was te, as required by

40 CFR 262.11 (Hazardous waste determination)

.

EPA has identified three methods to test CO 2 streams for RCRA hazardous characteristics.

The first method is to test the CO 2 stream as a gas prior to compression and transport. EPA

esti mates that a CO 2 capture facility would expend approximately $ 7

, 0 00 in one

- time costs and $4,0 00 in annual costs to test its CO 2 stream as a gas. The second option is to test the

CO 2 stream in its compressed, supercritical fluid or liquid under high press ure state. EPA

estimates that a CO 2 capture facility would expend approximately $27 ,000 in one

- time costs and $ 3

, 5 00 in annual costs to test its CO 2 stream in its supercritical or liquid under high

pressure state. The third option is for CO 2 streams from a coal or gas fired combustion source that has undergone some particulate and VOC removal , and combines process knowledge with limited testing. T his option is based on the assumption that the stream would not contain pesticides or most metals, and, conse quently, samples only for semivolatile organic compounds, volatile organic compounds

, and mercury. 34 This third option is the least expensive

– EPA estimates that a CO 2 capture facility would expend approximately $4, 5 00 in one

- time costs and $ 2

, 5 00 in annu al costs to utilize this method of

RCRA hazardous waste determination. 35

This analysis assumes that the 18 facilities capturing CO 2 streams from fossil fuel electric power generation, natural gas distribution, ethyl alcohol manufacturing, and nitrogenous fertilizer manufacturing would rely on process knowledge and limited testing to determine if

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

33 Paul W. Parfomak and Peter Folger. “Carbon Dioxide (CO2) Pipelines for Carbon Sequestration: Emerging Policy Issues,” Congressional Research Service Report for Congrees, u pdated January 17, 2008

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

. 34 We recognize that, besides mercury

, other heavy metals such as arsenic and selenium may be present at very

low levels.

35 See Appendix A for further detail on the calculation of these costs. Labor hours were converted to costs using loaded hourly wages of $110.99 for Senior Chemists, and $55.95 for Chemists and Sampling Technicians.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 31 of 133 remaining 9 facilities capturing CO 2 streams from oil and gas extracti on would test their CO 2 streams as a gas to determine whether their CO 2 stream is a RCRA hazardous waste (i.e., Option 1)

. 36

3.2.2 Baseline Practices for CO 2 Capture Facilities

Depending on whether its CO 2 stream is RCRA hazardous, a capture facility may engag e in

one of four baseline practices to manage its CO 2 stream. The flow chart in Exhibit 10

presents the possible baseline practices for CO 2 capture facilities depending on whether they

determine their CO 2 stream to be RCRA hazardous waste

.

Exhibit 10 : Fl ow Chart of Baseline Practices of CO 2 Capture Facilities

Waste

Determination CO 2 Capture Facility's

Baseline Practice

T he CO 2 stream is

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

Captured CO 2 Stream Destine for Disposal

Cease capturing the CO 2
stream

T he CO 2 stream is

RCRA hazardous Transport the CO 2 stream to a sequestration facility for injection in a Class I

hazardous well 37

Trea t the CO 2 stream and transport it to a sequestration facility for injection in a

Class VI well

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

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

37 Permit writers also may require the well to meet the Class VI UIC requirements. However, there is no specific UIC regulation that would require permit writers to apply both the Class I a nd Class VI standards to a RCRA

hazardous waste CO 2 injection well.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 32 of 133 3.2.2.1 Factors that Influence The Baseline Practices of CO 2 Carbon Capture

Facilities

Each generator‟s choice in how to manage a RCRA hazardous waste CO 2 stream would depend on several factors. The cost of each management option is a significant factor in this

decision. Ceas ing capture and releasing the CO 2 stream would be the lowest cost option, as the process of releasing the CO 2 stream would have little to no incremental cost and the generator would a void costs associated with the RCRA hazardous waste requirements. 38
Transporting the waste to a Class I hazardous waste well would be the second least expensive option. EPA assumes that the cost of sequestration in a Class VI well is generally similar to the cost of sequestration in a Class I hazardous waste well. 39 However, a facility that captures CO 2 waste and sends it to a Class I hazardous waste well would not be required to

treat the waste. I n order to send a RCRA hazardous waste CO 2 stream to a Cla ss VI well, a generator would first have to treat the CO 2 stream to make it non

- hazardous, because RCRA hazardous waste could not be injected into a Class VI injection well . The hazardous CO 2
treatment process represents a significant cost

. Treating the CO 2 stream and sending it to a

Class VI well would be the most expensive option for RCRA hazardous CO 2 capture
facilities.

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

determine that their waste is RCRA hazardous wast e would cease capture

. However, factors beyond the cost of managing the CO 2 stream may affect their decisions. Capture projects may have been initiated in order to be eligible for government subsidies, to improve marketing public image, or to prepare for anticipated regulatory or market changes (i.e., to avoid early obsolescence). These same factors may influence generators‟ decisions to

38 EPA has assumed that the generator determines that the CO 2 stream is a RCRA hazardous waste and then decides to forego capturing the CO 2 stream before any capital expenditure is incurr ed. The analysis assumes that there are no „sunk costs‟ or other economic harm associated with the decision to forego capture. Starting in 2011, the facility may need to modify their permit as part of the planning process as in Starting in

2011 EPA int ends to apply the Clean Air Act Prevention of Significant Deterioration (PSD) program to new electric power plants emitting greater than 100,000 TPY CO 2 or modified electric power plants emitting greater

than 75.000 TPY CO 2 ( 75 Federal Register 31514, June 3, 2010). Therefore, starting in 2011 CO 2 emissions would be included in operating permits for power plants as a permit condition. Any change to the CO 2 emissions from a proposed new or modified power plant after issuance of the PSD permit for the pow er plant would require formal modification of the permit. Costs to modify the permit are not included in this analysis.

39 Although the Class VI requirements are more stringent than the Class I requirements, EPA assumes that UIC permit writers would ensu re that Class I wells used for CO 2 sequestration also meet the Class VI requirements. However, EPA acknowledges that there is no explicit regulatory requirement for permit writers to apply the Class VI requirements to Class I wells. For purposes of this a nalysis, the difference in cost of obtaining a Class I UIC Permit versus a Class VI UIC permit has not been estimated and the cost of obtaining a permit is assumed to be the same regardless of the class of injection well or whether the CO 2 stream to be inj ected 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.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 33 of 133 continue CO 2 capture projects despite the RCRA hazardous waste characteristics of their CO 2
streams.

Although seque stration 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 , s ome generators nonetheless

, may adopt the latter practice. EPA‟s requirements allow

the sequestration of RCRA hazardous waste CO 2 streams in a Class I hazardous waste well

. However, EPA has assumed that UIC Permit writers would require that any Class I

hazardous waste well injecting a RCRA hazardous waste CO 2 stream meet requirements

similar to the Class VI requirements . 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 proxi mity of the well to USDWs. Therefore, RCRA hazardous waste CO 2 stream generators may not have access

to a Class I hazardous waste well permit that allows RCRA hazardous waste CO 2 stream sequestration.

3.2.2.2 Expected Baseline Practices of CO 2 Carbon Capture Fac ilities

As shown in Exhibit 10 above, the analysis assumes that non

- hazardous CO 2 streams will be transported to a Class VI well for sequestration. Those who generate hazardous CO 2 streams have three options: ( i) transport their streams to Class I hazard ous waste wells for sequestration, ( ii) treat their streams and send them to Class VI wells for sequestration, and ( iii) cease CO 2 capture. Due to uncertainty in the hazardous constituent content of CO 2 streams that will be captured and the complexity of the factors that will influence the baseline practices for generators of hazardous streams, Exhibit 11 presents the assumptions regarding the relative prevalence of each baseline practice in the absence of the proposed rule

. 40 It is important to note that

, due to the lack of definitive data, t hese hazardous CO 2 percentages where formed as conservative assumptions for analytical purposes only . Based on early

literature reviews and current CO 2 capture technologies the percentage of CO 2 streams that

are expe cted to be classified as hazardous may be low.

40 This analy sis assumes that CO 2 is not stored at the capture site and is sent off

- site in a more

- or

- less

continuous fashion.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 34 of 133 Exhibit 11 : Conservative Assum ption for the Prevalence of Hazardous Waste

Determination and Baseline Practices for CO 2 Capture Facilities

Hazardous Waste

Determination Baseline Practice Assumed Bas eline

Percent age of Capture

Facilities a

Non

- hazardous Send the CO 2 stream to a Class VI well 10 %

Hazardous Cease capture 30 %

Send the CO 2 stream to a Class I well

that is assumed to meet the Class VI requirements 30 %

Treat the CO 2 stream such t hat the

stream is non

- hazardous and send it to a

Class VI well 30 %

a For purposes of this analysis EPA assumes these values due to a lack of data on the relative distribution of

CO 2 streams‟ hazardous waste designation . The sensitivity analysis in Appe ndix C considers the alternative assumption that 90 percent of the CO 2 capture facilities would generate non

- hazardous CO 2 streams in the baseline.

Exhibit 12 presents the number of CO 2 capture facilities that EPA expects will be active each year, and a pplies the percentages from Exhibit 11 to estimate the number of CO 2 capture facilities that would engage in each baseline practice each year in the absence of the proposed rule. 41

Exhibit 12 : Expected Number of CO 2 Capture Facilities That Would Engage In Each

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

Year Non

hazardou s

Send to Class

VI Hazardous

- Cease Capture Hazardous

-

Treat and

Send to

Class VI Hazardous

- Send

to Class I that is

A ssumed to M eet
Class VI

R equirements Total

201 2 0 1 1 2 4

2013 1 1 1 2 5

2014 1 1 1 2 5

2015 1 1 1 2 5

2016 1 1 1 2 5

2017 1 1 2 2 6

2018 1 1 2 2 6

2019 1 1 2 2 6

2020 1 1 2 2 6

2021 1 1 2 2 6

2022 1 1 2 2 6

2023 1 1 2 2 6

2024 1 1 2 2 6

41 After applying the weights from Exhibit 11, the number of facilities practicing each baseline practice was adjusted slightly to eliminate rounding errors in the total number of capture facilities.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 35 of 133 Year Non

hazardou s

Send to Class

VI Hazardous

- Cease Capture Hazardous

-

Treat and

Send to

Class VI Hazardous

- Send

to Class I that is

A ssumed to M eet
Class VI

R equirements Total

2025 1 1 2 2 6

2026 1 1 2 2 6

2027 1 1 2 2 6

202 8 1 1 2 2 6

2029 1 1 2 2 6

2030 2 4 4 5 15

2031 2 4 5 5 16

2032 2 6 6 6 20

2033 2 6 6 6 20

2034 3 7 7 8 25

2035 3 8 8 8 27

2036 3 8 8 8 27

Post 2036 b 3 8 8 8 27

a The numbers in this table are derived by applying the percentages of capture facil ities conducting each baseline practice presented in Exhibit 11 to the number of capture facilities expected to practic e sequestration of their CO 2 streams each year presented in Exhibit 5. The numbers are rounded to integer values while ensuring the tota l number of capture facilities in each year matches the total from Exhibit 5.

The analysis makes the following assumptions regarding the costs that CO 2 capture incur

un der the baseline : 42

E ach CO 2 capture facilit y would incur one

- time and annual costs t o determine if the

CO 2 stream is RCRA hazardous waste or is non

- hazardous. Facilities that would

continue CO 2 capture in the baseline would incur the annual costs in each subsequent

year. C apture facilities that would cease capture in the baseline would not retest their

CO 2 streams in subsequent years and therefore would incur the annual costs for the first year only

CO 2 capture facilities that generate a CO 2 stream that is not RCRA hazardous waste

, and CO 2 capture facilities that determine that their C O 2 stream is RCRA hazardous

waste and therefore decide to cease capture

, would not be considered hazardous waste generators and would face no further costs associated with the hazardous waste regulations.

CO 2 capture facilities that generate RCRA hazardo us waste CO 2 streams and do not

cease capture would qualify as large quantity generators (LQGs) in the baseline (i.e. they would generate more than 1,000 kilograms of hazardous waste per month).

42 A facility would be required to treat or dispose of any already captured RCRA hazardous CO 2 in compliance with RCRA standards, including test samples after testing is complete (see 40 CFR 261.4(d )). The tests to

determine a CO 2 stream‟s hazardous characteristics require the capture of only a very small quantity of CO 2 (the facility would likely qualify as a conditionally exempt small quantity generator), so this analysis assumes the

associated co sts to be negligible for handling the samples.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 36 of 133 Therefore, they would be subject to the full set of hazardou s waste generator requirements and would incur the associated costs.

CO 2 capture facilities that treat their RCRA hazardous waste CO 2 streams would

incur treatment costs. 43

The avoidance of these costs under the proposed exclusion is quantified as a sa ving s in

Section 3.5.

3.2.3 Baseline Practices for CO 2 Sequestration Facilities

I n the baseline, the universe of CO 2 sequestration facilities would include a mix of facilities

with Class VI wells and facilities with Class I hazardous waste wells that EPA has a ssumed will also meet the Class VI requirements. The Class VI wells would manage non

- hazardous

CO 2 streams and CO 2 streams that have been treated prior to sequestration , while the Class I

hazardous waste wells would manage the untreated RCRA hazardous was te CO 2 streams. This analysis assumes that, in the baseline, approximately 57 percent of the sequestration wells would manage non

- hazardous CO 2 streams and treated CO 2 streams in Class VI wells. The remaining sequestration wells would manage RCRA hazardo us CO 2 streams in Class I

hazardous waste wells. 44 Exhibit 13 estimates the number of CO 2 sequestration facilities that would engage in each baseline practice.

Exhibit 13 : Expected Number of CO 2 Sequestration Facilities That Would Engage In

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

Year Manage Non

- Hazardous CO 2

(Class VI) Manage Hazardous CO 2 (Class I)

2012 1 1

2013 2 1

2014 2 2

2015 2 2

2016 3 3

2017 9 7

2018 10 7

2019 10 7

2020 10 7

2021 10 7

2022 10 7

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

hazar dous waste treatment permits.

44 The analysis assumes, in Section 3.2.2.2, that 40 percent of CO 2 capture facilities would transport non

hazardous or treated CO 2 streams to Class VI sequestration wells for injection. Another 30 percent of CO 2 capture facili ties would transport hazardous CO 2 streams to Class I sequestration wells for injection. Of this 70 percent of capture facilities transporting their CO 2 to a sequestration well, four out of seven (i.e. 40 out of 70 percent) of them transport their waste t o Class VI wells. The analysis assumes that 4 out of 7 (57 percent) of

CO 2 sequestration wells in the baseline are Class VI wells to match the practices of CO 2 capture facilities. The remaining 3 out of 7 (43 percent) of CO 2 sequestration wells in the b aseline are Class I wells.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 37 of 133 Year Manage Non

- Hazardous CO 2

(Class VI) Manage Hazardous CO 2 (Class I)

2023 10 7

2024 10 7

2025 10 7

2026 10 7

2027 10 7

2028 10 7

2029 10 7

2030 10 7

2031 10 8

2032 13 9

2033 13 9

2034 15 12

2035 17 12

2036 17 12

Post 20 36 17 12

a The numbers in this table are derived by applying the percentages of sequestration faciliti es conducting each baseline practice presented discussed above to the number of sequestration facilities expected to be in operation each year presented in Exhibit 9. The numbers are rounded to integer values while ensuring the total number of capture fac ilities in each year matches the total from Exhibit 9.

3.3 Post Rule Practices

This section discusses the change in practices of CO 2 capture and sequestration facilities due

to the rule, as proposed.

3.3.1 Post Rule Practices for CO 2 Capture Facilities

This analysis assumes that all CO 2 capture facilities will claim the proposed exclusion and

send their CO 2 streams to Class VI wells as a result of the proposed rule. 45 Under the proposed rule, CO 2 capture facilities claiming the proposed exclusion would avoid the costs

of determin ing whether their CO 2 stream is RCRA hazardous or non

- hazardous. Exempt generators would not be required to conduct testing of their CO 2 streams for hazardous characteristics or be required to evaluate the hazardous constituent conten t of the CO 2 stream based on the materials and processes used to generate the waste . They would only be required to submit an annual certification that the captured CO 2 stream is exempt. CO 2 capture facilities would be able to send their CO 2 streams to C lass VI wells without the

additional cost of treating the CO 2 stream.

45 It is possible that some facilities may continue to send their RCRA hazardous waste CO 2 stream to a Class I well that is assumed to meet the Class VI requirements. However, based on this assumption, the costs

associated with t his 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.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 38 of 133 3.3.2 Post Rule Practices for CO 2 Sequestration Facilities

Under the proposed rule, all CO 2 sequestration facilities are expected to be permitted as Class

VI wells. 46 Because under the pro posed rule CO 2 managed by GS would not be classified as RCRA hazardous waste, there would be no need for the owners and operators of injection wells to pursue a Class I hazardous waste well permit.

3.4 Incremental Costs of the Proposed Rule

This section esti mates 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 cost s of the rule to federal and state governments.

3.4.1 Compliance Costs

In order to claim the proposed exclusion

, authorized representatives at both the CO 2 capture facilities and Class VI UIC wells would be required to sign a certification statement which they must maintain onsite and make available to EPA on request. 47 The facilities are required to renew the certification statement each year in which they claim the exclusion

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

g overnments upon request. Exhibit 14 presents the estimated labor costs per facility

associated with the certification requirements . These costs are expected to be similar for CO 2 capture facilities and Class VI UIC wells.

Exhibit 14 : Estimated Costs to Prepare and Renew the CO 2 Exclusion Certification

Statement Per CO 2 Capture Facility or Sequestration Well (2010 dollars)

Labor Category Loaded

Hourly Wage a Prepare Initial

Certification

Statement Renew

Certification

Statement Make Certification

Statement Available

to State or EPA

Hours b Cost Hours b Cost Hours b Cost Legal $101.13 1.00 $101.13 0.50 $50.57 0.00 $0.00
Management $77.67 1.50 $116.51 0.75 $58.25 0.00 $0.00

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

Clerical $25.06 0.25 $6.2 7 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 b ased on u nloaded average hourly labor rates from the “Occupational Employment Statistics, May 2009 National Occupational Employme nt and Waste Estimates, United States” of the Bureau of Labor Statistics (BLS). Wages for technical labor reflect the average of the wage

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

exp erimental wells.

47 A single certification statement would be signed by only one facility. Each capture facility and each sequestration facility would sign its own certification statement.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 39 of 133 Labor Category Loaded

Hourly Wage a Prepare Initial

Certification

Statement Renew

Certification

Statement Make Certification

Statement Available

to State or EPA

Hours b Cost Hours b Cost Hours b Cost
for a petroleum geologist with 15 years experience in the 2008 American Association of Petroleum Geologists (AAPG) Sa lary 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 enginee r (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/

. W ages 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/echi strynaics.pdf

, and multiplied by a loading factor of 1.6.

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

.

Exhibit s 15 and 16 multipl y these per facility costs times the number of capture facilities and

Class VI wells

, respectively

, expe cted to incur each cost in each year over the 50

- year period beginning in 2012. Facilities are assumed to sign the certification in the first year of operation and renew the certification in each subsequent year. 48 Combined, EPA and state

governments are assumed to request certification statements from approximately 30 percent of capture facilities and Class VI well operators annually. 49 The exhibit presents the undiscounted certification costs, and also presents the discounted certification costs applying 3 percent and 7 percent discount rate to costs incurred after 2012.

Exhibit 15 : Certification Costs for CO 2 Capture Facilities 2012 to 2061

, (2010 dollars)

Year Initial Certifications Certifications Renewals Certification

Submissions to State

or EPA To tal 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 $8 15 $601

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

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

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

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

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

48 See Exhibits 10 and 11 for the number of CO 2 capture and sequestr ation facilities expected to operate in each year. All of these facilities, regardless of their baseline practice, are expected to incur these certification costs.

49 This estimate is based on EPA‟s best professional judgment.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 40 of 133 Year Initial Certifications Certifications Renewals Certification

Submissions to State

or EPA To tal Cost

Number

A Cost

B = A X $363 Number

C Cost D = C X $171 Number

E Cost

F = C X $3 Undiscounted

B + D +F 3%

Discount

Rate 7%

Discount

Rate

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

2048 0 $0 27 $4,617 8 $24 $4,641 $1,601 $4 06

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

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

2051 0 $0 27 $4,617 8 $24 $4,641 $1,465 $332

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

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

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

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

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

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

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

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

20 60 0 $0 27 $4,617 8 $24 $4,641 $1,123 $180

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

50

Year

Total 27 $9,801 900 $153,900 281 $843 $164,544 $70,474 $29,098***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 41 of 133 Exhibit 1 6 : Certification Costs for Class V I 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%

Discoun t

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 $1 5 $2,907 $1,812 $985

2029 0 $0 17 $2,907 5 $15 $2,907 $1,759 $920

2030 0 $0 17 $2,907 5 $15 $2,907 $1,708 $860

2031 1 $363 17 $2,907 5 $15 $3,270 $1,865 $904

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

2033 0 $0 22 $3,762 7 $21 $3,762 $2,022 $9 09

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 $1,92 6 $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 $4,95 9 9 $27 $4,959 $1,613 $379***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 42 of 133 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%

Discoun t

Rate

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

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

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

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

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

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

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

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

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

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

2061 0 $0 29 $4,959 9 $2 7 $4,959 $1,165 $180

50

Year

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

Under the proposed rule, some CO 2 sequestration facilities that would have been permitted as Class I wells in the baseline are expected to be permitted as Class VI wells instead

. The analysis assumes that this change in behavior will not result in a cost to these facilities. The planned CO 2 sequestration sites are not yet operational and have not yet acquired permits. The cost to obtain the Class VI permi t is assumed to be similar to the cost of obtaining a Class I permit, and the Class I hazardous waste wells in the baseline were already assumed in this analysis to be built to Class VI standards. Therefore EPA has assumed that there is no

difference in co st 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 CO 2 streams are designed to protect the human health and the environment. However, EPA believes that CO 2 streams may be managed in a n equally protective manner outside of the RCRA hazardous waste program. The Class VI UIC well requirements are designed to isolate the CO 2 stream and prevent it from migrating to USDWs. In addition, permit writers for Class V I UIC wells have discretion in whether to allow the sequestration of certain wastes depending on factors such as the composition of the waste, the structure of the well, and the proximity of the well to USDWs. Therefore, EPA believes that the management o f exempted CO 2 streams in Class VI UIC wells would not pose a significant risk to human health and the environment. EPA does not anticipate any negative externalities as a result of this action. As a result, no social

costs are expected to result from th e proposed exclusion

.

The proposed rule may also have productivity and output implications. This analysis does not model the potential productivity impact of the proposed rule. However, EPA anticipates***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 43 of 133 that these impacts primarily would be positive, as affected facilities could use savings associated with the proposed rule to increase output or productivity.

3.4.3 Costs to Government Entities

Under the proposed rule, CO 2 capture facilities and Class VI well operators would be required to sign a certification statement and make it available to EPA or state governments upon request. This analysis assumes that , combined, EPA and state governments will request certification statements from approximately 30 percent of capture facilities and Class VI well operato rs annually, and that state governments will account for about 90 percent of those requests. 50 Exhibits 1 7 and 1 8 present the costs per request to EPA and state governments, respectively.

Exhibit 1 7 : Estimated Cost to EPA to Request and Review a CO 2 Exc lusion

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 Incorp orating 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 rate s 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 th e standard government loading factor of 1.6 to reflect overhead

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

Exhibit 1 8 : Estimated Costs to States to Request and Review a CO 2 Exclusion

Certification (2010 dollars)

Labor Category Load ed 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 Employmen t 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 profess ional judgment.

50 These estimates are based o n EPA‟s best professional judgment.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 44 of 133 Exhibits 1 9 and 20 calculate the total costs to EPA and state governments to request and review certification statements related to the proposed exclusion over the 50

- year period beginning 2012 . The exhibits present undiscounted costs, a nd also appl y 3 percent and 7 percent discount rate s to costs incurred after 2012

.

. Exhibit 19 : Costs to EPA to Request and Review Certification Statements

, 2012 to 2061 (2010 dollars)

Year Number of

Requests Per Year

A Undiscounted Cost

A X $47 3% Di scounted 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 $2 2

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 $4 6 $19

2037 2 $94 $45 $17

2038 2 $94 $44 $16

2039 2 $94 $42 $15

2040 2 $94 $41 $14

2041 2 $94 $40 $13***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 45 of 133 Year Number of

Requests Per Year

A Undiscounted Cost

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

2042 2 $94 $39 $12

2043 2 $94 $38 $12

2044 2 $94 $37 $11

2045 2 $94 $35 $10

2046 2 $94 $34 $9

2047 2 $94 $33 $9

2048 2 $94 $32 $8

2049 2 $94 $ 31 $8

2050 2 $94 $31 $7

2051 2 $94 $30 $7

2052 2 $94 $29 $6

2053 2 $94 $28 $6

2054 2 $94 $27 $5

2055 2 $94 $26 $5

2056 2 $94 $26 $5

2057 2 $94 $25 $4

2058 2 $94 $24 $4

2059 2 $94 $23 $4

2060 2 $94 $23 $4

2061 2 $94 $22 $3

50 Year Total 73 $3,4 31 $1,498 $626

Exhibit 20 : Costs to State Governments to Request and Review Certification

Statements

, 2012 to 2061 (2010 dollars)

Year Number of Requests

Per Year

A Undiscounted Cost

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

2012 2 $122 $122 $122

2013 3 $183 $178 $171

2014 3 $183 $172 $160

2015 3 $183 $167 $149

2016 4 $244 $217 $186

2017 6 $366 $316 $261

2018 6 $366 $307 $244

2019 6 $366 $298 $228

2020 6 $366 $289 $213

2021 6 $366 $281 $199***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 46 of 133 Year Number of Requests

Per Year

A Undiscounted Cost

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

2022 6 $366 $272 $186

2023 6 $366 $264 $174

202 4 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

203 5 15 $915 $464 $193

2036 15 $915 $450 $180

2037 15 $915 $437 $169

2038 15 $915 $424 $158

2039 15 $915 $412 $147

2040 15 $915 $400 $138

2041 15 $915 $388 $129

2042 15 $915 $377 $120

2043 15 $915 $366 $112

2044 15 $915 $355 $105

2045 15 $915 $345 $ 98

2046 15 $915 $335 $92

2047 15 $915 $325 $86

2048 15 $915 $316 $80

2049 15 $915 $307 $75

2050 15 $915 $298 $70

2051 15 $915 $289 $65

2052 15 $915 $280 $61

2053 15 $915 $272 $57

2054 15 $915 $264 $53

2055 15 $915 $257 $50

2056 15 $915 $249 $47

2057 15 $915 $242 $44***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 47 of 133 Year Number of Requests

Per Year

A Undiscounted Cost

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

2058 15 $915 $235 $41

2059 15 $915 $228 $38

2060 15 $915 $221 $36

2061 15 $915 $215 $33

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

3.5 Incremental Cost Savings and Benefits of the Proposed Rule

CO 2 streams managed by GS would be e xcluded from the RCRA hazardous waste requirements under the proposed rule. 51 This change would result in three areas of savings for the generators of CO 2 streams: exclusion from hazardous waste determination, exclusion from compliance with RCRA training, planning, and reporting requirements , and exclusion

from hazardous waste treatment requirements

. CO 2 sequestration facilities managing RCRA

hazardous waste CO 2 streams under a Class I hazardous waste well permit in the baseline would also see savings rela ted to hazardous waste determination and compliance with the training, planning, and reporting requirement s.

3.5.1 Waste Determination Savings for CO 2 Capture Facilities

In the absence of the proposed rule, facilities capturing CO 2 destine for geological

seque stration would be required to determine whether the CO 2 stream qualifies as RCRA hazardous waste either by testing the content of the waste or by applying knowledge of the materials and processes used to generate the waste, as required by 40 CFR 262.11 (Ha zardous waste determination). Appendix A of this document discusses the available testing options for waste determination. As stated in Section 3.2 , t his analysis assumes that

the 18 facilities capturing CO 2 streams from fossil fuel electric power genera tion, natural gas distribution, ethyl alcohol manufacturing, and nitrogenous fertilizer manufacturing would rely on process knowledge and limited testing to determine if their CO 2 stream is a RCRA hazardous waste (i.e., Option 3). The analysis assumes tha t the remaining 9 facilities capturing CO 2 streams from oil and gas extraction would test their CO 2 streams as a gas to
determine whether their CO 2 stream is a RCRA hazardous waste (i.e., Option 1 ). This analysis applies weighted average waste determinati on costs of approximately $5, 5 00 in one

time costs and $3,0 00 in annual costs. 52 Under the proposed rule, exempt generators would not be required to determine whether their CO 2 stream is or is not RCRA hazardous waste.

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

CO 2 in the baseline.

52 See Appendix A for further detail on the calculation of waste determination costs. This draf t applies a single weighted average testing cost. The seventeen facilities that capture CO 2 from fossil fuel power generation, ethyl alcohol manufacturing, and nitrogenous fertilizer manufacturing are expected to combine process knowledge with limited che mical analytical testing. The remaining ten facilities that capture CO 2 from oil and***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 48 of 133 3.5.2 RCRA Training, Planning, and Repor ting Requirement Savings

for CO 2 Capture Facilities

This analysis assumes that generators who send RCRA hazardous waste CO 2 streams to Class

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

it to Class VI wells are LQGs in the baseline and are subject to the full set of RCRA hazardous waste regulations including training, planning, and reporting requirements

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

. Exhibit 2 1 estimates the annual savings per facility that would no longer be subject to the

RCRA training, planning and reporting requirements under the proposed rule.

Exhibit 21 : Estimated Annual RCRA Training, Planning, and Reporting Requirement Savings Per Ha zardous CO 2 Capture Facility as a Result of the Proposed Rule (2010 dollars) Requirement Citation Savings Per Facility a

EPA ID b 262.12 $0 Personnel Training c 262.34 $2,762

Contingency Planning c 262.34 $733

Emergency Planning c 262.34 $482

Recordke eping c 262.40 $711

Manifest d 262 Subpart B $0 Manifest Exception Report d 262.42 $0 Biennial Report c 262.41 $369

Total $5,057

a These savings apply to facilities that capture hazardous waste CO 2 streams that did not cease capture in the baseline

. b Acquiring an EPA ID is not an incremental cost for existing facilities, and is assumed to be a negligible cost for new facilities.

c These savings are consistent with the savings estimated in EPA‟s “ Regulatory Impact Analysis : 2008 Final Rule Amendments to the Industrial Recycling Exclusions of the RCRA Definition of Solid Waste, ” which also excluded certain generators from the RCRA training, planning, and reporting requirement s. The savings are adjusted to 2010 dollars using the Bureau of Labor Statist ics (BLS) Inflation Calculator.

d The analysis assumes that generators transport their CO 2 by pipeline only. The manifest requirements do not apply to pipeline transportation, so no savings are anticipated.

gas extraction and natural gas distribution are expected to test their CO 2 streams as gas prior to compression. The weighted average costs associated with waste determin ation are $5,366 in one time costs and $3,113 in

annual costs***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 49 of 133 3.5.3 CO 2 Treatment Sa vings for CO 2 Capture Faci lities

Generators that treat their CO 2 stream so that they can send it to a Class VI well in the baseline would not need to do so under the proposed rule. Treating a CO 2 stream to render it

non

- hazardous is an expensive process. EPA estimates that treat ment of a CO 2 stream generated at an oxy

- fuel power plant would cost $9.74 per metric ton of CO 2 , and treatment
of a CO 2 stream generated at an IGCC power plant would cost $8. 94 per metric ton of CO 2

. 53
Taking the average of these two costs, this analysis estimates that treating a CO 2 stream to
render it non

- hazardous costs $9. 33 per metric ton of CO 2

. T he ten current CO 2 capture operations combined (which are currently capturing CO 2 for use in EOR, not for sequestration ) capture d 11 million metric tons of CO 2 waste in 2008, or about 1. 1 million metric tons per facility. 54 55 If the planned CO 2 capture facilities generate CO 2 streams at a similar rate, each facility that treat s its CO 2 stream in the baseline will save approximately $ 10

. 3 million in CO 2 stream treatment costs annually under the proposed rule.

3.5.4 Summary of Savings to CO 2 Capture Facilities

Exhibit 22 multiplies each of the savings identified above times the appropriate number of facilities that would receive each saving in 2012, and calculate s a total expected savings of approximately $ 10.3 million to CO 2 capture facilities in the first year under the proposed

rule.

Exhibit 22 : Savings to CO 2 Capture Facilities as a Result of the Proposed Rule, By

Baseline Practice in 2012 (2010 dollars)

Baselin e 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

R eporting Requirement s c 3 $5,057 $15,171

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

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

54 EPA, “ Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990

- 2008

, ” April 15, 2010, Table 3

- 47:

Potential Emissions f

rom CO 2 Capture and Transport, p. 3

- 53

, http://www.epa.gov/climatechange/emissions/

downloads10/US

- GHG

- Inventory

- 2010_Report.pdf

. . 55 We evaluating o ther options to develop an average annual quantity of captured CO 2 . In addition, the Val Verde Gas Plants in Texas are 5 plants rather than one that is implied in the original table. This facility count was realized after the EA was completed. Hence, the average is closer to 1.1 Million and the treatment costs per plant will decrease in the next draft of the EA.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 50 of 133 Baselin e Practice Number of

Facilities

A Savings Per Facility

Under the Proposed Rule

B Total Savings Under the

Proposed Rule

A X B

Total $10,313,678

a One

- time waste determination savings apply only to those CO 2 capture facilities claiming the exclusion for the

first time.

b Annual waste determin ations savings apply to all CO 2 capture facilities claiming the exclusion in each year beginning with the first year of capture, except for those facilities that would have ceased capture in the absence of the propose rule. Those facilities would only see the “annual” waste determination savings in the first year of capture because they would not have conducted waste determinations in subsequent years after ceasing

capture.

c RCRA training, planning, and reporting requirement savings apply only to those CO 2 capture facilities that generate RCRA hazardous waste CO 2 streams and do not cease capture in the baseline (i.e. facilities that treat

their CO 2 or send their RCRA hazardous waste CO 2 stream to a Class I well in the baseline)

. d CO 2 treatment savings app ly only to those CO 2 capture facilities that treat their RCRA hazardous waste CO 2 streams and send them to Class VI wells in the baseline.

Exhibit 23 uses this methodology to calculate the expected savings to CO 2 Capture Facilities as a result of the pr oposed rule for each year over a 50

- year period beginning in 2012. The

exhibit presents the undiscounted savings and also applies 3 percent and 7 percent discount

rates to savings accrued after 2012.

Exhibit 23 : Savings to CO 2 Capture Facilities as a Result of the Proposed Rule

, 2012 to

2061 (2010 dollars)

Year Waste

Determination Hazardous

Waste Requirements CO 2 Treatment Total Savings (Undiscounted) Total Savings

(3% Discount Rate) Total Savings

(7% Discount Rate)

2012 $28,112 $15,171 $10,270,395 $10,313,678 $10,313,678 $10,313,678

2013 $17,566 $15,171 $10,270,395 $10,303,132 $10,003,041 $9,629,096

2014 $12,293 $15,171 $10,270,395 $10,297,859 $9,706,720 $8,994,549

2015 $12,293 $15,171 $10,270,395 $10,297,859 $9,424,000 $8,406,121

2016 $12,293 $ 15,171 $10,270,395 $10,297,859 $9,149,515 $7,856,188

2017 $20,639 $20,228 $20,540,791 $20,581,658 $17,753,919 $14,674,438

2018 $15,366 $20,228 $20,540,791 $20,576,385 $17,232,398 $13,710,914

2019 $15,366 $20,228 $20,540,791 $20,576,385 $16,730,484 $12,8 13,938

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 $20,5 76,385 $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 $20,2 28 $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 $12,194,79 4

2031 $42,152 $50,570 $51,351,976 $51,444,699 $29,338,193 $14,224,888***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 51 of 133 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 $72,053,37 9 $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 $80,91 2 $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 $82,302,4 67 $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

20 53 $58,393 $80,912 $82,163,162 $82,302,467 $24,495,519 $5,136,626

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

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

2056 $58,393 $80,912 $82,163,162 $82,302,467 $22,41 6,870 $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 $82,163,16 2 $82,302,467 $19,917,098 $3,198,833

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

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

3.5.5 Waste Determination Savings for CO 2 Sequestration Fa cilities

In the absence of the proposed rule, sequestration facilities managing CO 2 in Class I

hazardous waste or Class VI well s would be required to confirm the characteristics of the waste stream to ensure it has been properly characterized by the gener ator or transporter.

Post

- rule, the CO 2 stream would be excluded from the definition of RCRA hazardous and this testing would not be needed. EPA estimates that each sequestration well would save approximately $4,500 in one time testing costs and $1,500 i n annual testing costs. 56

56 See Appendix A for further detail on the calculation of waste determination costs.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 52 of 133 3.5.6 RCRA Training, Planning, and Reporting Requirement Savings

for CO 2 Sequestration Facilitie s

In the baseline, Class I hazardous waste injection wells that are assumed to follow the Class

VI standards would be used to manage RCRA hazardous waste CO 2 streams, and would be subject to hazardous waste management requirements in the baseline , per 40 CFR 144.14 ( Requirements for wells injecting hazardous waste )

. The injection wells used to manage exempt CO 2 streams are expected to be p ermitted 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 , result ing in a savings to these wells. Some of these savings would be negligible or offset by requirements for Class VI wells. Exhibit 24 lists the requirements for

UIC Class I hazardous waste wells from which these CO 2 sequestration wells would be

exempt if the y claim the proposed exclusion . The exhibit also presents the expected savings associated with each requirement

.

Exhibit 24 : Estimated Annual RCRA Training, Planning, and Reporting Requirement Savings as a Result of the Proposed Rule Per Hazardous CO 2 Se questration 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

Bi ennial 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 CO 2 streams in the baseline under Class I UIC permits.

b Exclusion from these requirements may result in slight savings, but this analysis assumes th os e savings to be negligible.

c Acquiring an EPA ID is assumed to be a negligible cost for new facili ties.

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 LQ Gs 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 requir ement s. The savings are adjusted to 2010 dollars using the Bureau of Labor Statistics (BLS) Inflation

Calculator.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 53 of 133 3.5.7 Summary of Savings to CO 2 Sequestration Facilities

Exhibit 25 multiplies each of the savings to CO 2 sequestration facilities identified in sections 3.5.5 and 3.5.7 times the appropriate number of facilities that would receive each saving in 2012, to calculate the total expected savings to CO 2 sequestration facilities in the first year under the proposed rule.

Exhibit 25 : Savings to CO 2 Se questration Facilities as a Result of the Proposed Rule, By

Baseline Practice in 2012 (2010 dollars)

Saving Number of

Facilities

A Savings Per Facility

B Total Savings

A X B

Waste Determination (One Time) 2 $4,440 $8,879

Waste Determination (Annual) 2 $ 1,536 $3,073

Hazardous Waste Requirements 1 $2,762 $2,762

Total $14,714

Exhibit 26 uses this methodology to calculate the expected savings as a result of the proposed

rule to CO 2 Sequestration Facilities for each year over a 50

- year period beginni ng in 2012. The exhibit presents the undiscounted savings and also applies 3 percent and 7 percent

discount rat e s to savings accrued after 2012.

Exhibit 26 : Savings to CO 2 Sequestration Facilities as a Result of the Proposed Rule

, 2012 to 2061 (2010 do llars)

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***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 54 of 133 Year Waste

Determination Hazardous Waste

Generator Requirements Total Savings

(Undiscounted) Total Savings

(3% Discount Rate) Total Savings

(7% Discount Rate)

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

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

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

2030 $26,119 $13,810 $39,929 $23,454 $1 1,814

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

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

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

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

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

2036 $44,556 $24,85 8 $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 $2 4,669 $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

205 9 $44,556 $24,858 $69,414 $17,302 $2,887

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

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

50 Year Total $1,861,835 $955,652 $2,817,487 $1,316,526 $615,507***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 55 of 133 3.5.8 Unquantified Benefits of the Proposed Rule

In addit ion 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 pr ovide the regulatory certainty needed to foster industry adoption of CCS

.

3.6 Conclusions

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

summarizes the undiscounted 50

- year and annualized costs and benefits of the proposed rule.

Exhibits 28 and 29 summarize the 50

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

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

. 0 million. 57 Under Executive Order 12866, a rule qualifies as economically significant if its annual effect on the economy is $100 million or more. This proposed rule is not expected to be economically significant, as defined under Executive Order 12866.

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

Type of Entity 50

- year Costs 50

- year Savings 50

- year Net Savings Average Net

Savings
Capture Facilities $164,544 $2,829,383,941 $2,829,219,397 $56,584,388
Sequestration Facilities $198,456 $2,817,487 $2,61 9,031 $52,381

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

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

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

Exhibit 28 : Net Costs and Savings of the Proposed Rule

– 3% Discount Rate (2010 dollars)

Type of Entity Present Value

of 50

- year Costs Present Value

of 50

- year Savings Present Value of 50

-

year Net Savings Annualized

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

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

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

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

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

57 Appendix C presents two sensitivity analyses that co nsider the costs and savings of the proposed rule under assumptions that differ from the main analysis. The first sensitivity analysis considers a fewer number of affected facilities than the main analysis. The second sensitivity analysis makes different assumptions regarding the hazardous characteristics of captured CO 2 streams in the baseline.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 56 of 133 Exhibit 29 : Net Costs and Savings of the Proposed Rule

– 7% Discount Rate (2010 dollars)

Type of Entity Present Value

of 50

- year Costs Present Value

of 50

- year Savings Present Value of 50

-

year Net Savings Annualized

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

Facilities $42,294 $615,507 $5 73,213 $38,818

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

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

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

In addition to the quantified savings, the proposed rule will help establish a supporting regulatory fram ework for the future development and deployment of carbon capture sequestration (CCS) technology and will help provide the regulatory certainty needed to foster industry adoption of CCS. There are no environmental costs expected as a result of the

propose d rule, because both the Class I hazardous waste and Class VI UIC regulations are

sufficient to ensure that CO 2 streams are managed so as to protect public health and the

environment.

4. Regulatory Flexibility Analysis

The Regulatory Flexibility Act (RFA), as amended by the Small Business Regulatory Enforcement and Fairness Act, 5 U.S.C. §§ 601

- 612, generally requires an agency to conduct a regulatory flexibility analysis for any rule subject to notice and comment rulemaking requirements unless the agency ce rtifies 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 CO 2 capture and sequestration facilities by exempting CO 2 captured for the purpose of geological sequestration in Class VI well from the definition of hazardous waste. For each facility claiming the proposed exclusion , these savings are expected to outweigh the cost to prepare and maintain the required certification statement. The Agency estimates that this proposed rule will lead to net cost savings in the range of $ 3 2.0 to $ 56.6 million annually. Accordingly, EPA certifies that the rule will not have a significant economic impact on a

substantial number of small entities.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 57 of 133 5. References

Birkholze r, J., J

. Apps, L

. Zheng, Y

. Zhang, T

. Xu, and C

. F

. Tsang. “ Research Project on

CO 2 Geological Storage and Groundwater Resources: Water Quality Effects Caused by CO2

Intrusion into Shallow Groundwater

. ” Lawrence Berkeley National Laboratory

. #LBNL

1251E . O ctober, 2008. Available: http://repositories.cdlib.org/lbnl/LBNL

- 1251E

. A s cited by EPA in the p reamble to the Federal Requirements Under the Underground Injection Control Program for Carbon D ioxide Geologic Sequestration Wells Final Rule, RIN 2040

- AE98

.

D epartment of Energy, National Energy Technology Lab. Carbon Capture and Storage

D atabase

. 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: ht tp://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 Indus trial 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

- Inventory

2010_Report.pdf

EPA. “ Cost Analysis for the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule)

. ” Office of Water (460 M). EPA 816

- R

- 10

- 013 . 2010

.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 58 of 133 EPA. Final Rule for Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells . Signed by the Administrator on November 22, 2010.

Koch Industries

. “ Koch Industries Welcomes 2009 Leadership Kansas Class

. ” July 27, 2009

. Av ailable: 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/dakota

gasification

- co

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

- mobil

corp

Massachusetts Institute of Technology (MIT). Largescale Power Plant CCS Projects Worldwide. Power Plant Carbon Dioxide Captu re and Storage Projects website. http://sequestration.mit.edu/tools/projects/index.html

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

Office of Personnel Management

. “ Salary Table 2010

- GS Incorporating the 1.50% General Schedule Increase Effective January 2010

. ” Available: http://www.opm.gov/oca/10tables/indexGS.asp

.

Parfomak

, P

. W.

, and P

. Folger. “ Carbon Dioxide (CO 2 ) Pipelines for Carbon Sequestration: Emerging Policy Issues

. ” C ongressional R esearch S ervice

, Report for Congress. Updated January 17, 2008. Available: http://assets.opencrs.com/rpts/RL33971_20080117.pdf

PetroSource Energy Company, “Petrosource Energy Pipeline,” http://www.petrosourceenergy.com/ images_large/pipelineco_map.html

.

The Society of Petroleum Engineers. “Annual Membership Salary Survey Highlight Report, 2008 Salary Survey.” Available: http://www.spe.org/career/salary_survey/

.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 59 of 133 Appendix A

Cost for Determining RCRA Toxicity of CO 2 Stream

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

the CO 2 stream is clas sified 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 als o potentially applicable to the classification of CO 2 streams as hazardous waste under RCRA, however, this analysis does not address the costs associated with the corrosivity characteristic.

A.1 Summary of the RCRA Toxicity Characteristic

Determining if a solid waste is classified as hazardous under RCRA requires the generator to first determine if the material is a “Listed” waste, (i.e.

, contained in a list of wastes defined as hazardous by the regulation). If it is not listed then the waste material mu st 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 o f the materials or the processes used” (under 40 CFR 262.11(c)(2)) to determine whether the waste is RCRA hazardous . For the purposes of this analysis, ICF developed separate cost estimates for generators of CO 2 streams that will conduct physical testing of the waste and generators of CO 2 streams that will apply process knowledge with limited chemical analytical testing

. EPA a lso evaluate d testing for operators of sequestration facilities. RCRA regulations under 40 CFR 261.24 (Toxicity characteristic) pro vide 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 was te.

Under 40 CFR 261.24 of RCRA the waste is considered a RCRA hazardous waste if the waste contains hazardous constituents and if the concentration of certain components resulting from the RCRA test method exceeds the numerical concentration limits in the regulation. The list of hazardous contaminants and concentration criteria are presented in

Exhibit A

- 1.

Exhibit A

- 1: Maximum Concentration of Contaminants for the Toxicity Characteristic

from 40 CFR 261.24 (Toxicity characteristic)

EPA

HW

No. 1 Analyt e 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 tetrachlo ride 56

– 23

– 5 0.5***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 60 of 133 EPA

HW

No. 1 Analyt e Group Contaminant CAS No. 2 Regulatory

Level (mg/L)

D020 Pesticide Chlordane 57

– 74

– 9 0.0

D021 Volatile Organic Compound Chlorobenzene 108

– 90

– 7 100.0

D022 Volatile Organic Compound Chloroform 67

– 66

– 3 6.0

D007 Metal Chromium 7440

– 47

– 3 5.0

D023 Semivolatile Organic Compound o

- Cresol 95

– 48

– 7 200.0 4

D024 Semivolatile Organic Compound m

- Cresol 108

– 39

– 4 200.0 4

D025 Semivolatile Organic Compound p

- Cresol 106

– 44

– 5 200.0 4

D026 Semivolatile Organic Compound Cresol 200.0 4

D016 Pesticide 2,4

- D 94

– 75

– 7 10.0

D027 Volatile Organic Compound 1,4

- D ichlorobenzene 106

– 46

– 7 7.5

D028 Volatile Organic Compound 1,2

- Dichloroethane 107

– 06

– 2 0.5

D029 Volatile Organic Compound 1,1

- Dichloroethylene 75

– 35

– 4 0.7

D030 Semivolatile Organic Compound 2,4

- Dinitrotoluene 121

– 14

– 2 0.13 3

D012 Pesticide Endrin 72

– 20

– 8 0.0

D031 Pesticide Heptachlor (and its epoxide) 76

– 44

– 8 0.0

D032 Semivolatile Organic Compound Hexachlorobenzene 118

– 74

– 1 0.13 3

D033 Semivolatile Organic Compound Hexachlorobutadiene 87

– 68

– 3 0.5

D034 Semivolatile Organic Compound Hexachloroethane 67

– 72

– 1 3.0

D008 Metal Lead 7439

– 92

– 1 5.0

D013 Pesticide Lindane 58

– 89

– 9 0.4

D009 Metal Mercury 7439

– 97

– 6 0.2

D014 Pesticide Methoxychlor 72

– 43

– 5 10.0

D035 Volatile Organic Compound Methyl ethyl ketone 78

– 93

– 3 200.0

D036 Volatile Organic Compound Nitrob enzene 98

– 95

– 3 2.0

D037 Semivolatile Organic Compound Pentrachlorophenol 87

– 86

– 5 100.0

D038 Pesticide Pyridine 110

– 86

– 1 5.0 3

D010 Metal Selenium 7782

– 49

– 2 1.0

D011 Metal Silver 7440

– 22

– 4 5.0

D039 Volatile Organic Compound Tetrachloroethylene 127

– 18

– 4 0.7

D015 Pesticide Toxaphene 8001

– 35

– 2 0.5

D040 Volatile Organic Compound Trichloroethylene 79

– 01

– 6 0.5

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 Pe sticide 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.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 61 of 133 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 summ arizes four key issues for consideration in evaluating the testing of CO 2
st r eams.

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 solu tion 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 wast e is classified as a RCRA hazardous waste. In the case of a liquid waste, the RCRA regulation under 40 CFR 261.24(a) allows the waste itself to be considered to be the leachate for the purpose of comparison with the concentration

standards. However, there is no RCRA regulation or guidance that specifies test procedures

for wastes that are gas
, supercritical fluid , or dense liquid under high pressure

. 58 CO 2 streams captured for the purposes of injection will typically be either gas

, supercritical fluids , or liquids under high pressure

. At the point of capture CO 2 streams will typically be in the gas phase (14.5 to 500 psi)

. 59 Transport and injection is commonly as a dense liquid or supercritical fluid. 60 Under the RCRA regulations and test procedures there a re 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 Nee ds 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

b y EPA.

58 A supercritical fluid has properties of a gas and properties of a liquid, but is neither. CO 2 must be compressed to approximately 1100 psi to become supercritic al and is normally injected as a supercritical fluid. CO 2 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. Pa ul W. Parfomak and Peter Folger. January 17, 2008

59 Volk, Ronald H., 2009. Proceedings of the Workshop on Future Large CO2 Compression Systems, Sponsored by NIST, US DOE and EPRI. March 30

- 31, 2009. Gaithersburg MD.

60 Mohitpour, Mo, Andy Jenkins, and Gabe Nahas. 2008. A generalized overview of the requirements for design, construction and operation of new pipelines for CO2 sequestration. Journal of Pipeline Engineering, Volume 7, No. 4 Fourth quarter 2008***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 62 of 133 Issue 3: Measurement of Concentrations in S upercritical and Liquid Under High Pressure

CO 2 St r eams is Complex. CO 2 streams currently injected and transported generally contain some impurities when in supercritical or liquid under high pressure s tate that can complicate the measurement the composition of the CO 2 stream due to differences in the density and the compressibility of the components. The concentration of components in CO 2 in a supercritical or liquid under high pressure state may not be representative of the composition at a lower pressure.

A.3 Options and Associated Costs for Testing CO 2 St r eam

This section presents four options and costs for testing a CO 2 Stream:

Option 1

– Testing CO 2 Stream as a Gas; Option 2

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

Pressure ; Option 3

– Using Process Knowledge and L imited A nalytical T esting to Meet RCRA Characterization Requirements; and Option 4

– Injection Facility Testing to Ensure Compliance with RCRA

.

Option 1

– Tes ting CO 2 Stream as a Gas

Under this option, facilities that generate CO 2 as a gas will sample the gas at a low pressure prior to compression and transport of the CO 2 stream, thus avoiding the issues associated with sampling and analyzing a supercritical f luid 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 CO 2 s treams 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 nee d to construct a special sampling port on the process line to collect a representative sample of the CO 2 stream for analysis. Facilities may already have sampling ports for operational testing, but the stream would not normally be sampled for the full rang e of RCRA contaminants listed in Exhibit A

- 1, and the existing ports may not be at appropriate sampling locations for CO 2 stream characterization. Construction of a sampling port would require stainless steel or similar metal to ensure sample quality and m inimize the

effects of the corrosive CO 2 stream. Samples of the CO 2 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 CO 2 stream for corrosivity; however, the generator would be required

to determine if the CO 2 stream meets the corrosivity characteristic which would incur similar cost for developing the approach and perf orming the tests.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 63 of 133 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 engine er to develop and document a calculation method to convert the gas concentration measurements to liquid concentration measurements considering all the physical and chemical properties of the CO 2 stream and listed constituents. We have not developed the det ails 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 r eport 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

concentra tions based on the dilutions used in the toxicity leaching test specified in EPA

Publication SW

- 846.

A breakdown of the costs and labor hours for this option are presented in Exhibit A

- 2. Additional details are provided in Exhibit A

- 6.

Exhibit A

- 2: Lab or Hours and Costs for Option 1: Testing CO 2 Stream as a Gas

Labor Time:

Labor Category Frequency of

Occurrence Hours

Senior Chemist One

- time 40

Chemist Annual 12 Sampling Technician Annual 4

Vendor/Equipment Costs:

Cost Category Frequency of

Occurrence Cost Facility Improvement (installation of sampling port) One

- time $2,500 Sampling Equipment Annual $450 Sample Analysis (includes QC sample) Annual $2,448

Vendor/Equipment Subtotal $5,398 (first Year) $2,898 annually

Option 2

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

Under this option, facilities that generate CO 2 as a gas would compress the CO 2 stream to supercritical fluid or liquid under high pressure conditions for transport and then sample it as

su percritical fluid or liquid under high pressure . A special sampling port designed for high pressure and corrosive fluids would be required on the high pressure CO 2 stream line . CO 2 generator facilities would likely not have such a port already installed under normal***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 64 of 133 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 withst and 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 i t 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 a nalysis of gas samples, this option assumes that the facility would develop and document a procedure to gasify the supercritical fluid or liquid under high pressure and then analyze it as a gas. The analytical method development would require creating data quality and performance indicators by a senior chemist, and would require demonstrating that the integrity of the sample composition is maintained during phase shift from supercritical fluid or liquid under high pressure to gas. Analytical method developm ent 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 w hich 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 concentr ation 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 l iquid 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 CO 2 Stream as a

Supercritical Fluid or Liquid Under High Pressure

Labor Time:

Labor Category Frequency of

Occurrence Hours

Senior Chemist One

- time 200

Chemist Annual 12 Sampling Technician Annual 4 Vendor/Equipment Costs:

Cost Category Frequency of

Occurrence Cost Facility Improvement (installation of One

- time $5,000***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 65 of 133 sampling port) Sampling Equipme nt Annual $200 Sample Analysis (includes QC sample) Annual $2,448

Vendor/Equipment Subtotal $7,648 (first year) $2,648 annually

Option 3

– Using Process Knowledge and L imited A nalytical T esting to Meet RCRA Characterization Requirements

RCRA regulat ions 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 CO 2 stream is assumed to be subjected to some treatment of impurities and solids prior to transport to support air quality, processing, a nd pipeline requirements, therefore the generator would test for a few key components such as mercury, volatile and semi volatile organic compounds. For this cost estimate we have assumed that

the CO 2 stream is from a coal or gas fired combustion source th at has undergone some particulate and VOC removal, and it is unlikely that the waste stream would contain pesticides, or most metals listed in Exhibit A

- 1. Under Option 3, the generator would only sample for semivolatile organic compounds, volatile organic compounds

, and mercury. 61

The generator would be required to document the CO 2 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 pla nt 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 d etails are provided in Exhibit A

- 8.

Exhibit A

- 4: Labor Hours and Costs for Option 3: Using Process Knowledge to Meet

RCRA Characterization Requirements

Labor Time:

Labor Category Frequency of

Occurrence Hours

Senior Chemist One

- time 40

Chemist Ann ual 12 Sampling Technician Annual 2

61 We recognize that, besides mercury

, other heavy m etals such as arsenic and selenium may be present at very

low levels.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 66 of 133 Vendor/Equipment Costs:

Cost Category Frequency of

Occurrence Cost Sampling Equipment Annual $400 Sample Analysis (includes QC sample) Annual $1,530

Vendor/Equipment Subtotal $1,930 annually

Option 4

– Testin g to Ensure Compliance with RCRA by Injection Facility

Facilities that inject the CO 2 would have responsibility to confirm the characteristics of the waste stream to ensure it has been properly characterized by the generator. CO 2 received for injection by pipeline may be commingled from multiple sources and have a range of non

CO 2 constituents. Under Option 4, an injection facility would test a sample of the CO 2 stream annually for RCRA constituents at the point where ownership of the CO 2 is transferred to the facility, or at a location immediately prior to injection. The RCRA testing would be done at

the same time as the CO 2 stream composition testing required under the UIC Class VI and would use the same sampling port, but would analyze for different cons tituents.

The injection facility would need to determine if the results of the gas analysis contain concentrations of hazardous constituents above the RCRA toxicity characteristic limits, which are in liquid concentration units (milligrams per liter). 62 As in Option 1, an injection facility would need to construct a methodology to relate the sampled gas concentrations to a liquid concentration for direct comparison. The development and documentation of this

method would take a one

- time effort of about 40 hours for a senior chemist or chemical engineer. After the method is developed and documented the results of the analysis and waste determination would be summarized in an annual report by a staff level chemist would prepare an annual report of findings.

A breakdown of the costs and labor hours for Option 4 are presented in Exhibit A

- 5. Additional details are provided in Exhibit A

- 9

Exhibit A

- 5: Labor Hours and Costs for Option 4: Testing to Ensure Compliance with RCRA by Injection Facility

Labor Time:

Labor Category Frequency of

Occurrence Hours

Senior Chemist One

- time 40

Chemist Annual 12

62 Alternatively an injection facility could consider assessing the result of a spill of the material into the soil, water and air media and determine if the resulting media exceeds the R CRA toxicity characteristic. While this does not meet the RCRA characterization standard for waste streams it may provide a cost effective method for the facility to estimate the concentration of supercritical or gaseous CO 2 for comparison to RCRA toxicity

characteristic standards.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 67 of 133 Vendor/Equipment Costs:

Cost Category Frequency of

Occurrence Cost Sampling Equipment Annual $100 Sample Analysis (no QC sample) Annual $765

Vendor/Equipm ent Subtotal $865 annually

A.4 Additional Details on Cost Estimates

This section presents additional details on the cost components, assumptions, and data sources for developing the cost estimates for each testing option. The information is

summarized in four exhibits:

Exhibit A

- 6: Option 1 Cost and Labor Estimate;

Exhibit A

- 7: Option 2 Cost and Labor Estimate;

Exhibit A

- 8: Option 3 Cost and Labor Estimate; and

Exhibit A

- 9: Option 4 Cost and Labor Estimate.

Exhibit A

- 6: Option 1 Cost and Labor Estim ate

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

op erational 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 y ear 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

Pestic ides $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 Estima te

Mid Level Chemist 12 annual QC data, Compare results,

prepare report ICF Estimate***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 68 of 1 33 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 r elief

valve. Ref: 2009 Means Heavy constr/Envl cost

Book

- doubled cost of iron

bronze valve to account for high pressure and non

corrosive materials. Sampling equipment $200 for bomb sampler rental 2 samples

- 1 QC 1 sample Pressurized pipeline or

downhol e 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 Remediat ion

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 pre ssure 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***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 69 of 133 Exhibit A

- 8: Option 3 Cost and Labor Estimate

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

Cost Category Range of Costs Frequency of

Cost Occurrence Notes Data Source

Sam pling 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 Co sts

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 Ch em 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***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 70 of 133 Exhibit A

- 9: Option 4 Cost a nd 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 CO 2 concentration sampling
Sampling equipment $100 for bomb sampler rental 1 Pressurized sampling bomb Estimate from lab

Technician 0 0 Technician is already collecting samples for Subpart RR or UIC compliance

Analytical Laboratory

Costs Metals (Mercury only) $31 1 Mercury by EPA Method

245.2 RS Means Env'l Remediation Unit Costs. No QC sample required because sam ple 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

Uni t 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 fr om Analytical

Chemist

Mid Level Chemist 12 annual QC data, Compare results,

prepare report ICF Estimate***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 71 of 133 Appendix B

Treatment Costs

This appendix presents the costs for treating the CO 2 streams such that it is non

- RCRA

hazaroudous. Section B.1 summaries the three major capture technology systems and associated treatment options. Section B.2 presents the treatment costs.

B.1 CO 2 Capture Technologies and Treatment Options for CO 2 Streams

Currently, there are three major CO 2 capture technology systems, with two based on pulverized coal system, and one based on gasification:

Post

- combustion capture involves the capture of CO 2 from a typical pulverized coal plant. In this process, a clean flue gas stream is sent to an absorption tower where the flue gas is brought in contact with an absorbent solvent (such as amines). The CO 2 binds with the solvent and the flue gas, separated from most of its CO 2 , is sent to the

stack. The CO 2 - rich solvent is pumped to a regeneration vessel (or stripper) throug h a heat exchanger. Under a higher atmospheric pressure and temperatures (ranging

from 100 to 140 o C 63 ), the solvent is regenerated and CO 2 is stripped. The heat supplied to the regeneration vessel to strip CO 2 from the solvent carries a significant

energy cost. 64 The CO 2 is then cooled, dried, and compressed to a supercritical fluid or liquid under high pressure state at which point it can be stored geologically or used commercially. The regenerated „lean‟ solvent is cooled and pumped back to the absorptio n tower through a heat exchanger to be reused in the process. 65 Amine scrubbing system is currently a proven technology and it is capable of removing

between 80% and 95% CO 2 from a flue gas stream. However, acid gases such as NO

x and SO

x must be removed fro m the flue gas prior to passing through the absorber

tower. 66

Oxy

- fuel combustion is a process in which high purity oxygen is substituted for air during combustion in a pulverized coal plant, to produce an extremely concentrated

stream of CO 2 that is easil y compressed and delivered by pipeline for storage. The process involves the recirculation of flue gas to maintain similar mass

- flow and lower temperatures in the boiler. The raw flue gas consists of water vapour and CO 2 , which is then dehydrated and purif ied. The nearly pure CO 2 stream is then compressed for transportation and storage. 67

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

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

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

66 NO

x and SO

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

67 Alstom, Oxyfuel combustion capture

.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 72 of 133 Pre

- combustion capture is mostly applicable to gasification

- based system such as Integrated Gasification Combined Cycle (IGCC) power plants, and natural gas based

combin ed cycle plants. A gasifier converts coal (or other feedstock) using steam and oxygen to a synthetic gas (syngas) consisting mostly of CO, H 2 , H 2 O. The syngas is subsequently cooled and cleaned. In order to remove the carbon, the carbon monoxide in the sy ngas 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 cyc le plant. Typically, sulfur, in the form of H 2 S, is not removed during

gas treatment stage, but rather removed in the CO 2 removal stage using a two

- stage Selexol process, for example. The separated H 2 S is then converted into elemental

sulfur in a sulfur re covery unit.

As part of the standard process, post

- combustion capture process using amine

- based scrubbing will be relatively free of SO

x and NO

x , as discussed earlier, and therefore the CO 2 streams from power plants with post

- combustion capture are not exp ected to have these hazardous components. However, the CO 2 streams could contain other hazardous elements that are present in coal, such as mercury, arsenic, cadmium, etc.

In oxyfuel and gasification based systems, however, there are process options that c ould be added or taken out such that the hazardous components in the CO 2 stream can be lowered or

increased.

In an oxyfuel system, there is an option of either installing or not installing a flue gas desulfurizer (FGD) in which the SO

x from a flue gas can be taken out. With a FGD within the recirculating stream removing about 98% of the SO

x , the SO

x concentration in the flue gas would be about 0.3%, whereas without the FGD, the concentration would be about 1%. With an FGD, the concentration of SO

x in the C O 2 stream would be more than 100 times lower (i.e., 0.01%), compared to a CO 2 stream without FGD (1%). However, one needs to consider the economic impact of adding an FGD. Furthermore, the production of NOx in an oxyfuel system is significantly

lower becau se of the use of oxygen instead of air as an oxidant for combustion, and NOx concentration could be about 40 ppm. 68

In an IGCC system, there is an option of removing both H 2 S and CO 2 using a single stage Selexol gas separation process, instead of two stage s (one stage for H 2 S and

another for CO 2 ), as mentioned earlier. The single stage process eliminates the need for the sulfur processing and handling facilities (which is typically used to convert

H 2 S into elemental sulfur). The cost of a single stage selex ol unit is lower than a two stage unit, in addition the cost of the sulfur processing unit is eliminated.

68 See Case C2 of Table 3.8 in IEA 2004

– “Impact of Impurities in CO 2 capture, transport, and storage” Report PH4/32, International Energy Agency, August 2004.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 73 of 133 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

- 200 7/1291, “Pulverized Coal Oxycombustion Power Plants”, Revision 2, August 2008), and estimates for the difference between co

capture of H 2 S and CO 2 vs. separated capture of CO 2 and H 2 S was calculated using a 2007 NETL report (NETL, 2007. DOE/NETL

- 2007/1281, “Cost and Performance Baseline for Fossil Energy Plants”, Revision 1, August 2007).

Economic A ssumptions

The economic assumptions were based on NETL, 2008, and the relevant parameters are

shown in Exhibit B

- 1.

Exhibit B

- 1 : Economi c Assumptions for Cost Estimates
Capital Charge Rate 0.175
Weight Cost of Capital 9.67%

Levelization Factor for FOM and

VOM 1.1568 price of coal $/MMBtu $ 1.80

The cost estimates have an accuracy of +/

- 30%, consistent with a screening study, and the year of construction of the plant is assumed to be 2007. However, the “overnight” total plant cost numbers from the NETL studies, which were in January 2007 dollars, were converted to

1 st quarter 2010 dollars using NIPA tables from the Bureau of Economic A nalysis. 69 The total plant cost includes the cost of (NETL, 2007):

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

• Materials,

• Labor (direct and indirect),

• Engineering and construction management, and

• Contingencies (process and project).

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

In both cases, bituminous high sulfur Illinois

- 6 coal with 2.51% sulfur (as

- received basis)

was used for the techno

- economic analysis. The energy content of the coal was assumed to be 11,666 BTU/lb.

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

70 Costs do not account for environmental permitting costs. It is assumed that treatm ent 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.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 74 of 133 FG D 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 CO 2 stream is scrubbed of SO 2 . The CO 2 stream after the flue gas recycle is only dehydrated to 0.015% by volume, such that the CO 2 concentration in the stream is about 83%. See NETL, 2008 re port for more details on the plant configuration and assumptions

In order to assess the impact of not having an FGD, cost of the FGD (capital cost, fixed and variable O&M) was taken from the recent Technical Support Document for EPA‟s Transport

Rule. 71 The cost of the FGD was given in 2006 dollars and was converted to 1 st quarter 2010 dollars using the NIPA tables from BEA as shown in Exhibit B

- 2 in the “FGD” column.
Therefore, the cost of the FGD was subtracted from the Case 5 numbers to derive the cost of the plant without an FGD.

It was assumed that the same amount of fuel and oxidant would be used in this case, and the only change was the removal of the FGD. Reduction in the auxiliary consumption from the FGD removal was about 7.26 MW, which included the removal of power consumption associated with limestone handling and reagent preparation, FGD pumps and agitators, and 2 MW of power associated with induced fans for the FGD. 72

Exhibit B

- 2 below shows the key assumptions and results for the two oxyfuel cases , with and without FGD, and differences between the two (“FGD” column) highlights the impact of adding an FGD to treat the CO 2 stream. The levelized cost was calculated using the numbers

in Exhibit B

- 1 and the formulation given in section 2.9.2 of NETL, 20 08.

Exhibit B

- 2 : Summary of Assumptions and Results for Oxyfuel
Oxyfuel System

Unit Without

FGD With FGD

(case 5) FGD

Size of Plant MW 557.27 550.01

- 7.26

Net Heat Rate BTU/kWh 11,503 11,655 152 Capacity

Factor 0.85
Captured CO 2 tons/hr 592.58
Capital Cost $/kW

- net $ 2,493 $ 2,776 $ 283

Fixed O & M $/kW

- year $ 25.59 $ 35.81 $ 10.22

Variable O & M cents/kWh 0.51 0.68 0.17

71 See Table 5 (500 MW capacity, 11,000 BTU) of Technical Support Document of Transport Rule (“Updates to EPA Base Case v3.02 EISA Using the Integrated Planning Model”, June 17, 2010).

72 See Table 5

- 8 of NETL, 2008.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 75 of 133 Oxyfuel System

Unit Without

FGD With FGD

(case 5) FGD

Levelized Cost Over 20 Years
Capital Cost cents/kWh 5.86 6.53 0.6 7

Fixed O & M cents/kWh 0.40 0.56 0.16

Variable O &

M cents/kWh 0.59 0.79 0.20

Fuel cents/kWh 2.64 2.64 0.00

Total cents/kWh 9.49 10.51 1.02

Single Stage Selexol for IGCC

The economic analysis for the IGCC system was based on Case 2 and Case 1 of the NETL, 2007 report. These two cases are based on IGCC using a GE gasifer with (Case 2) and without (Case 1) CO 2 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 CO 2 from the syngas. See NETL, 2007 report for more details on the plant configuration and assumptions.

The cost impact of only having a single stage Selexol un it was calculated using the total plant cost details of Case 1 and Case 2 given in NETL, 2007 report. The difference between the

co

- capture of H 2 S and CO 2 and separated capture was given by the cost difference in $/kW

between Case 2 and Case 1 for the sele xol units, and the cost of the sulfur plant and mercury

removal. It was assumed that the co

- capture plant would not include the mercury capture

units that are in Case 2. 73 The differential in fixed cost was assumed to be same in the oxyfuel system multiplie d by the capital cost differential between the oxyfuel and IGCC cases. The differential variable cost between the two cases is negligible, as the only

difference is the amount of Selexol used. All of the cost numbers were converted to 1 st
quarter 2010 doll ars 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, re lative to the separated capture plant, derives from the power consumption for Selexol unit auxiliaries between Case 2 and Case 1, and the power for Claus plant compressor and

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

73 See Exhibit 3

- 46, account 5A of NETL, 2007 report.

74 See Exhibit 3

- 34 of NETL, 200 7 report.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 76 of 133 Exhibit B

- 3 : Assumptions and Summary of Results for IGCC Cases
IGCC System

Unit Co

- capture Separated

capture Difference

Size of Plant MW 570.77 555.675

- 15.09

Net Heat Rate BTU/kWh 10,227 10,505 278
Capacity Factor 0.85
Captured CO 2 tons/hr 505.65
Capital Cost $/kW

- net $2,236 $2,494 $259

Fixed O & M $/kW

- year $36.31 $45.65 $9.34

Variable O & M cents/kWh 0.84 0.84 0.01

Levelized Cost Over 20 Years
Capital Cost cents /kWh 5.25 5.86 0.61

Fixed O & M cents/kWh 0.56 0.71 0.15

Variable O & M cents/kWh 0.97 0.98 0.01

Fuel cents/kWh 2.38 2.38

Total cents/kWh 9.16 9.93 0.76***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 77 of 133 Appendix C.

Sensitivity Analyses

This appendix considers the costs and savings under two sets of assumptions that differ from the assumptions made in the main analysis. The first sensitivity analysis considers a smaller

number of affected facilities than the main analysis . The second sensitivity analysis makes different assumptions regarding the ha zardous characteristics of captured CO 2 streams in the

baseline.

Sensitivity Analysis 1

– Fewer Affected Facilities

The main analysis in this document consider s the impacts of the proposed rule on both existing CO 2 capture and sequestration projects and several planned projects that do not yet

exist . This sensitivity analysis assumes that only facilities associated with existing capture and sequestration projects and projects associated with named DOE pilot projects and federal/private partnerships will b e affected by the proposed rule. All other assumptions are consistent with the main analysis.

This sensitivity analysis considers only 1 3 capture facilities: 10 existing capture facilities,

2 capture projects associated with named DOE pilot projects, a nd 1 capture facility associated with the FutureGen federal/private partnerships.

This sensitivity analysis considers only 6 sequestration facilities: 5 sequestration projects associated with named DOE pilot projects, and 1 sequestration facility associat ed with the FutureGen federal/private partnerships.

Exhibit C

- 1 presents the number of CO 2 capture and sequestration facilities expected to begin sequestration activities in each year under the proposed rule.

Exhibit C

- 1: CO 2 Capture and Sequestration Facilities Assumed to Begin and Practice

Sequestration Activities by Year Under Sensitivity Analysis 1

Year Number of CO 2

Facilities Beginning Sequestration of their

CO 2 Streams Total Number of CO 2

Facilities Practicing Sequestration of their

CO 2 Streams Number of Sequestration

Facilities Beginning Operation Total Number of

Sequestration

Facilities in Operation

2010

- 2012 2 2 0 0

2013 0 2 0 0

2014 0 2 0 0

2015 0 2 0 0

2016 0 2 0 0

2017 1 3 6 6

2018 0 3 0 6

2019 0 3 0 6

2020 0 3 0 6***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 78 of 133 Year Number of CO 2

Facilities Beginning Sequestration of their

CO 2 Streams Total Number of CO 2

Facilities Practicing Sequestration of their

CO 2 Streams Number of Sequestration

Facilities Beginning Operation Total Number of

Sequestration

Facilities in Operation

2021 0 3 0 6

2022 0 3 0 6

2023 0 3 0 6

2024 0 3 0 6

2025 0 3 0 6

2026 0 3 0 6

2027 0 3 0 6

2028 0 3 0 6

2029 0 3 0 6

2030 9 12 0 6

2031 0 12 0 6

2032 0 12 0 6

2033 0 12 0 6

2034 1 13 0 6

2035 0 13 0 6

2036 0 13 0 6

Post

- 2036 0 13 0 6

Total 13 13 6 6

Exhibit C

- 2 summarizes the undiscounted 50

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

- 3 and C

- 4

summarize the 50

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

. 7 million. Applying a 7 percent discount rate, the annualized net savings are approximately $ 1 8 .7 million.

Exhibit C

- 2: Undiscounted Net Costs and Savings of the Proposed Rule Under

Sensitivity Analysis 1 (2010 dollars)

Type of Entity 50

- year Costs 50

- year Savings 50

- year Net Savings Average Net

Savings
Capture Facilities $81,765 $1,502,025,66 7 $1,501,943,902 $30,038,878
Sequestration Facilities $47,322 $690,052 $642,730 $12,855

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

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

Total $143,035 $1,502,715,719 $1,502,572,684 $30,051,454***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 79 of 133 Exhibit C

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

– 3%

Discount Rate (2010 dollars)

Type of Entity Present Value

of 50

- year Costs Present Value

of 50

- year Savings Present Value of 50

-

year Net Savings Annualized

Net Savings
Capture Facilities $35,353 $653,373,965 $653,338,612 $24,652,746 Sequestration

Facilities $23,345 $344,138 $320,793 $12,105

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

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

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

Exhibit C

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

– 7% Discount Rate (2010 dollars)

Type of Entity Present Value

of 50

- year Costs Present Value

of 50

- year Savings Present Value of 50

-

year Net Savings Annualized

Net S avings
Capture Facilities $14,644 $275,492,457 $275,477,813 $18,655,216 Sequestration

Facilities $11,471 $172,014 $160,543 $10,872

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

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

Total $28,958 $275,664,470 $275,635,5 12 $18,665,895

Sensitivity Analysis 2

– 90 Percent of CO 2 Capture Facilities Generate Streams are Non

hazardous in the Baseline

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

of CO 2 capture facilities gener ate streams that are hazardous in the baseline. This sensitivity analysis makes the opposite assumption

– that 90 percent of CO 2 capture facilities generate

streams that are non

- hazardous in the baseline. Consequently, this sensitivity analysis

assumes a different prevalence of baseline practices by CO 2 capture and sequestration facilities. All other assumptions are consistent with the main analysis. Exhibit s C

- 5 present s the assumptions of this sensitivity analysis regarding the relative prevalence of each baseline practice in the absence of the proposed rule for CO 2 capture facilities.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 80 of 133 Exhibit C

- 5: Assumed Prevalence of Hazardous Waste Determination and Baseline

Practices for CO 2 Capture Facilities

Hazardous Waste

Determination Baseline Pr actice Assumed Baseline

Percentage of Capture

Facilities

Non

- hazardous Send the CO 2 stream to a Class VI well 90 %

Hazardous Cease capture 3.3 %

Send the CO 2 stream to a Class I well

that is assumed to meet the Class VI requirements 3.3 %

Treat the CO 2 stream such that the

stream is non

- hazardous and send it to a

Class VI well 3.3 %

Corresponding to the baseline practices of capture facilities, this sensitivity analysis assumes that, in the baseline, approximately 97 percent of the sequestration facilities would manage

untreated and treated non

- hazardous CO 2 in Class VI wells. The remaining sequestration wells would manage RCRA hazardous CO 2 streams as Class I hazardous waste wells. 75

Exhibit C

- 6 summarizes the undiscounted 50

- year and annual ized costs and benefits of the proposed rule under the assumptions of this sensitivity analysis. Exhibit s C

- 7 and C

- 8

summarize the 50

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

- hazardous waste in the baseline than for facilities that generate hazardous waste in the baseline. Therefore, the expected savings under the assumptions of this sensitivity analysis ar e significantly lower than under the main analysis. Under the assumptions of this sensitivity analysis, the proposed rule is expected to result in

undiscounted average net savings of approximately $ 9.3 million. Applying a 3 percent discount rate, the ann ualized net savings are approximately $ 8.5 million. Applying a 7 percent discount rate, the annualized net savings are approximately $ 7.3 million.

75 This sensitivity analysis assumes that 93 percent of CO 2 capture facilities would transport non

- hazardous or

treated CO 2 streams to Class VI sequestration wells for injection. Another 3.3 percent of CO 2 capture facilities would transport hazardo us CO 2 streams to Class I sequestration wells for injection. Under this assumption, 93 out of 97 (97 percent) of CO 2 capture facilities injecting into a sequestration well transport their waste to Class VI wells. The analysis assumes that 97 percent of C O 2 sequestration wells are Class VI wells to match the practices of CO 2 capture facilities.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 81 of 133 Exhibit C

- 6: Undiscounted Net Costs and Savings of the Proposed Rule Under

Sensitivity Analysis 2 ( 2010 dollars)

Type of Entity 50

- year Costs 50

- year Savings 50

- year Net Savings Average Net

Savings
Capture Facilities $164,544 $465,458,254 $465,293,710 $9,305,874
Sequestration Facilities $199,494 $1,986,125 $1,786,631 $35,733

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

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

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

Exhibit C

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

– 3%

Discount Rate (2010 dollars)

Type of Entity Present Value

of 50

- year Costs Present Value

of 50

- year Savings Present Value of 50

-

year Net Savings Annualized

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

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

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

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

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

Exhibit C

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

– 7% Discount Rate (2010 doll ars)

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 $7,284,909Appendix D.

Assessment of Environmental Justice Impacts

D.1 Introduction

Executive Order 12898 (59 FR 7629, Fe bruary 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 dir ects 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 as sess potential EJ impacts associated with the proposed

RCRA conditional exclusion at 40 CFR 261.4(h). Section D.2 provides background on the proposed rule. Section D.3 presents a comparison of the federal regulations applicable to generators of hazardous waste CO 2 , pipelines

, and geological sequestration (GS) facilities operating under the baseline requirements and proposed RCRA exclusion . The comparison identifies key regulatory differences. Section D.4 presents a screening analysis of EJ impacts

assoc iated 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. Sectio n D.5 presents a qualitative screening assessment of potential EJ impacts associated with pipelines that might be used to transport CO 2 under the proposed rule. 76 Section D.6 summarizes the conclusions of these analyses and identifies possible next steps.

D.2 Background on Proposed Rule

EPA is proposing a conditional exclusion from the definition of hazardous waste for carbon dioxide (CO 2 ) 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 we ll who claim that a CO 2 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 CO 2 stream itself (as defined in 40 CFR 146.81(d)), and would no t apply to hazardous wastes that are mixed with, or are otherwise

co

- injected with, CO 2 streams. The exclusion would be codified at 40 CFR 261.4(h).

76 EPA did not conduct a quantitative, pipeline

- specific screening analysis. Refer to Section 4.5 for EPA‟s reasons for conducting a qualitative analysis.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 83 of 133 There are three primary types of facilities that would be affected by EPA‟s proposed action:

Generato rs (i.e., capture facilities). Electric power plants and other industrial facilities generate CO 2 as a byproduct of their operations. CO 2 capture facilities are entities

that collect their CO 2 byproducts and manage them in a manner other than releasing

th em into the environment. EPA estimates that 27 facilities might capture CO 2 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 CO 2 would qualify as a RCRA hazardous waste if it exhibits any

of the RCRA hazardous characteristics.

Pipelines. Captured CO 2 is typically is transported by pipeline

. As of 2008, there were 30 operating CO 2 pipelines, operated by 29 sepa rate entities. 77

GS Facilities. EPA estimates that 29 geological sequestration facilities might claim

the exclusion . Geological sequestration (GS) refers to the process of injecting CO 2 captured from an emission source (e.g., a power plant) into deep s ubsurface rock formations in order to permanently isolate the CO 2

.

D.3 Comparative Analysis

This section presents a summary comparison of the federal regulations applicable to generators of hazardous waste CO 2 and geological sequestration (GS) facilities operating under the baseline requirements and proposed RCRA exclusion

. The design and function of

the r egulatory 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 CO 2 streams that would be RCRA hazardous. Additionally, the comparison is not intended to compare regulatory requirements for CO 2 streams found to be non

- hazardous under RCRA.

EPA developed Exhibit D

- 1 for purposes of comparing these federal regulations. Column 1 of the exhibit presents the RCRA hazardous waste regulations and other federal regulations applicable to generators, pipelines and GS facilities operating under the hazardous waste regulatory program. 78 Column 2 presents the proposed rule‟s conditions and other federal regulations applicable to generators, pipelines and GS facilities operating under the proposed rule. Column 3 briefly compares these regulations to determine if the federal regulations applicable to generators, pipelines and GS facilities operating under the proposed rule (Column 2) are comparable to the federal regulations applicable to hazardous waste

77 Depart ment of Transportation, Pipeline and Hazardous Materials Safety Administration (PHMSA), 2008 Hazardous Liquids Annual Dat a http://www.phmsa.dot.gov/staticfiles/PHM SA/DownloadableFiles/Files/LIQANN08.zip

. 78 Column 1 presents hazardous waste regulations applicable to large quantity generators only.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 84 of 133 generators, pipelines, and GS facilities operating under the federal hazardous waste regulations (Column 1).

Below is a brief summary of the regulatory comparison for CO 2 streams found to be RCRA

hazar dous waste under the current regulations to CO 2 streams that would be governed under the proposed rule

.

Generators of hazardous CO 2 operating under the proposed conditional exclusion would be subject to less stringent federal regulation than generators o perating 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.

P ipelines carrying CO 2 streams managed under the proposed conditional exclusion would be subject to the same federal regulations as pipelines carrying CO 2 streams managed under the baseline. Pipeline transport of CO 2 would be subject to DOT regulation unde r both the baseline and proposed rule. Pipeline transport covered by

DOT is generally not subject to RCRA regulation.

GS facilities of hazardous CO 2 operating under the proposed conditional exclusion (i.e., facilities subject to Class VI UIC 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 pr oposed 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 CO 2 streams under the baseline would also be required by the permit writers to meet the Class VI UIC well requirements. There is no regulatory requirement, however, that permit writers apply the Class VI require ments
to Class I hazardous waste wells.Exhibit D

- 1. Comparison of Federal Regulations Applicable to Facilities and Pipelines Operating Under the Baseline and Proposed Rule

Federal Regulations Applicable to Facilities and Pipelines Operating under th e Baseline Federal Regulations Applicable to Facilities and Pipelines Operating under the Proposed Rule Comments

1. Generators a
Reporting and Recordkeeping RCRA Regulations

Notification under RCRA 3010 to obtain EPA identification number (40 CFR 262. 12) Biennial reporting of hazardous waste quantities and types (40 CFR 262.41) Recordkeeping of biennial report, waste analyses, and other documents as specified (40 CFR 262.40) Recordkeeping and annual renewal of signed

certification statement. Certifica tion 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 CO 2 , and subpart RR (40 CFR 98.440) for geological sequestration facilities. The proposed rule does not include initial or ongoing notification or reporting to EPA on

their activities as do the hazardous waste regulations. However, it requires facilities to renew the certification annually and provide it to EPA if requested

The baseline and proposed rule r equire facilities to keep specified records to demonstrate their compliance with applicable requirements Emergency Preparedness and Response RCRA Regulations
Personnel training on emergencies (40 CFR 262.34 and 265.16) Contingency planning, emergency p rocedures, and emergency equipment (40 CFR Part 265, Subpart C and D) No relevant requirement The proposed rule does not require facilities to prepare for or respond to emergencies, as do the hazardous waste regulations. Refer to “Other Regulations” belo w for information on other federal regulations that might require emergency preparedness and response
Other Federal Regulations CAA (Chemical Accident Prevention) : A facility that is a stationary source that has more than a threshold quantity of a “regul ated 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 consequ ences as specified) must prepare an emergency response program or make alternative arrangements with offsite authorities b These other federal regulations establish requirements for emergency preparedness that may be comparable to the hazardous waste requi rements in some cases. However, it is doubtful that these requirements will address all facilities and potential releases to the same extent as the hazardous waste regulations. First, most of these regulations give facilities the option of developing eit her an emergency response plan or evacuation plan. An evacuation plan is not comparable to the hazardous waste requirements (e.g., for CERCLA/EPCRA (Emergency Notification) : A generator must immediately notify the National Response Ce nter of a release of hazardous substance equal to or exceeding its reportable quantity in any 24

- hour period, as required

at 40 CFR Part 302 b

OSH Act (Process Safety Management) : A facility that has a process (e.g., use, storage, handling) which involve s 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***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 86 of 133

Federal Regulations Applicable to Facilities and Pipelines Operating under th e Baseline Federal Regulations Applicable to Facilities and Pipelines Operating under the Proposed Rule Comments

OSH Act (Hazardous Waste Operations and Emergency Response (HAZWOPER)) : A facility is required to

establish an emer gency 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), suc h as designated response employees, as required by 29 CFR 1910.120(q). If the facility will evacuate employees and will not allow employees to assist in response, it need not prepare an emergency response plan. It must prepare an evacuation plan b personnel training and equipment to address onsite releases). In addition, most of these regulations are triggered only when a

CERCLA hazardous substance exceeds a specified quantity (e.g., threshold quantity). A carbon dioxide stream may contain hydrogen sulfide, mercury, and/or other chemicals that

are CERCLA hazardous substances. However, these substances must be pres ent in sufficient quantities to trigger the specified regulatory quantity. For example, the threshold quantity for hydrogen sulfide in 40 CFR Part 68 is 10,000 pounds. Hence, a facility‟s carbon dioxide stream would not be subject to these emergency requ irements if it

does not contain a hazardous substance that exceeds its respective threshold quantity.

Carbon dioxide itself is not a hazardous

substance NA O SH 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

f orms 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 no

migration unit (40 CFR Part 268) No relevant requirement The proposed rule does not require treatment

of waste CO 2 streams or, alternatively, disposal of untreated waste i n a unit with a no

migration variance, as do the hazardous waste regulations 2. Pipelines RCRA Regulations RCRA does not regulate transportation by pipeline Refer to “Other Regulations” below for information on other federal regulations that apply to pi pelines Other Federal Regulations Pipeline transportation of CO 2 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 CO 2 would be subject to DOT regulation under both the baseline and proposed rule 3. Geological Sequestration Facilities***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 87 of 133

Federal Regulations Applicable to Facilities and Pipelines Operating under th e Baseline Federal Regulations Applicable to Facilities and Pipelines Operating under the Proposed Rule Comments

RCRA Regulations Class I injectio n wells disposing of hazardous waste are permitted by rule under RCRA if they meet the requirements of 40 CFR 270.60:

Have a UIC permit Comply with UIC permit conditions and applicable UIC requirements at 40 CFR 144.14 Comply with 40 CFR 246.101 (i.e., co rrective action) Submit permit application information on solid waste management units at the facility, if applicable Class VI UIC wells disposing of exempt CO 2 must
meet the r equirements of 40 CFR 261.4(h)(1 ):

Be subject to Class VI UIC program, includin g UIC requirements at 40 CFR Parts 144 and 146 Dispose of CO 2 streams, but not CO 2 streams that are

mixed with or otherwise co

- injected with hazardous

waste Keep onsite records of signed certification statement, renew it annually, and provide it to EPA if requested The baseline regulations establish a permit

by

- rule program for Class I wells injecting hazardous waste that meet specified requirements. The proposed rule would allow Class VI wells to inject exempt CO 2 streams, provided that the generator and well owner/operator claim the exclusion and meet specified conditions. The baseline and proposed rule both rely heavily on the UIC program requirements (e.g., permit conditions) to ensure protective management and disposal of the waste. Both also establi sh additional administrative requirements as needed to ensure compliance (e.g., recordkeeping and reporting)

Refer to “Other Regulations” below for information on other federal regulations that apply to pipelines Other Federal Regulations

The UIC Class I hazardous regulations and UIC Class VI regulations address the same broad areas:

Siting

Area of review and corrective action Financial responsibility

Construction Logging, sampling, and testing prior to operation Operation Mechanical integrity tests

Mon itoring Closure/post

- closure care

In addition, Class I hazardous injection wells also may be subject to the no

- migration requirements of 40 CFR Part 148 if they will dispose of RCRA hazardous wastes that do not meet applicable treatment standards The UIC Class I hazardous regulations differ from the UIC Class VI regulations in a number of ways. Some key differences include the following: c

Class VI regulations impose additional siting standards. For example, at the Director‟s discretion, the owner/opera tor
must characterize additional zones that will impede vertical fluid movement, allow for pressure dissipation, are free of faults and fractures, and provide additional opportunities for monitoring, mitigation and

remediation***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 88 of 133

Federal Regulations Applicable to Facilities and Pipelines Operating under th e Baseline Federal Regulations Applicable to Facilities and Pipelines Operating under the Proposed Rule Comments

The Class I hazardous regula tions require that the area of review (AoR) be a fixed distance of 2 miles around the well, whereas the Class VI regulations require AoR radius

to be determined based on site

- specific computational modeling that accounts for the physical and chemical prope rties of all phases of the injected CO 2 stream, CO 2 plume, and pressure front over an appropriate timeframe. In addition, Class VI regulations require continual re

assessment of the AoR radius

Class VI regulations require same monitoring during well oper ation as Class I

hazardous regulations, in addition to monitoring of groundwater quality and geochemical changes above the confining zone. In addition, surface air monitoring and soil monitoring may be required at the Director‟s discretion. The owner/ope rator must submit and gain approval of the monitoring plan before injection

Class VI regulations establish a 50

- year post

- closure period during which the owner/operator must conduct monitoring. The Class I regulations do not require a 50

- year post

- closur e period

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

b A carbon dioxide stream may contain hydrogen sulfide, mercury, and/or other chemicals that are “hazardous substances”. If a hazardous substance meets or exceeds the applicable threshold quantity spelled out in these federal regulations, it would trigger the emergency requirements, as appli cable. For example, the threshold quantity for hydrogen sulfide in 40 CFR Part 68 is 10,000 pounds. A facility‟s carbon dioxide stream would not be subject to these emergency requirements if it does not contain a hazardous substance that exceeds its respective threshold quantity. Carbon dioxide itself is not a hazardous substance. Not e that the requirements of 29 C FR 1910.120(q) and 1910.1200 are not triggered by threshold quantities.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 89 of 133

c EPA anticipates that a Class I well used for injection of hazardous waste CO 2 streams would also be required by the permit writers to meet the Class VI UIC well requirements; howeve r, there is no regulatory requirement that permit writers apply the Class VI requirements to Class I wells.D.4 Screening Analysis of Capture and GS Facilities

This section presents an EJ screening analysis of carbon capture and GS facilities with known

l ocations that might claim the exclusion

. Similar to the regulatory comparison found in D.3

, the screening analysis of capture and GS facilities is not an assessment of risk. Instead, t he analysis uses demographic information to identif y communities of con cern

. . The next two sections describe the methodology and results.

D.4.1 Methodology

EPA took the following steps to complete the analysis:

1. Ascertained the location of planned, major commercial (non

- DOE) and FutureGen capture facilities, existin g capture facilities, and DOE and FutureGen GS projects that may claim the exclusion . Please note the following:

EPA estimates that 27 capture facilities may claim the exclusion

, including 14 planned major commercial facilities, one FutureGen facility,

1 0 existing fertilizer and gas facilities, and two DOE sequestration projects. These facilities are included in this screening analysis.

Appendix D.A . identifies the 31 facilities (33 less two DOE dual facilities) included in this screening analysis.

2. Conducted a screening analysis of these facilities and surrounding residential populations to identify vulnerable populations based on demographic and other indicator data. EPA performed the analysis using Geographic Information System (GIS) mapping tools. This analysis involved the following activities:

Identified indicators to include in the analysis: percent minority (e.g., indigenous populations), percent below 150% of poverty level, and

percent 0

- 4 years and 65+ years within a 1

- and 3

- mile ra dius. 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 wast e treatment, storage and disposal facilities and Superfund sites). EPA referred to its Facility Registry System (FRS), which is a centrally managed database, to ascertain the location of these

sites. 79 This indicator is meant to clarify the proximity and

79 The FRS has over 1.5 million unique facility records related to such systems as the Toxic Release Inventory (TRI), Res ource Conservation and Recovery Act Information System (RCRAInfo), Aerometric Information***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 91 of 133 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 Cen sus 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 t he 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 i ndicator 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 dete rmine 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 perce ntage to the state‟s percentage.

Identified those populations whose 1

- and 3

- mile indicator percentages exceeded the respective state‟s percentages; and

Produced tabular summaries of the data. Detailed data are presented in Appendix D.B. A summary of the data is presented in Section D.4.2.

D.4.2 Results

Exhibits D

- 2 and D

- 3 summarize the results of the screening analysis. Exhibit D

- 2 presents the results of the analysis of indicators within a 1

- mile radius of facilities and Exhibit D

- 3 presents

the results for the analysis of indicators within a 3

- mile radius of facilities. Each exhibit lists the facilities alphabetically, indicates its type (e.g., commercial capture), and uses an “X” to indicate if an indicator within its radius exceeds the state p ercentage. In addition, each exhibit uses gray shading to identify facilities whose minority populations and/or low

- income populations (i.e.,

Retrieval System (AIRS)/AIRS Facility Subsystem, and Comprehensive Environmental Response, Compensation, and Liability Information System (CERCLIS). For additional i nformation, refer to http://www.epa.gov/enviro/html/.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 92 of 133 populations living below 150% of the poverty level) exceed the state percentage, as these may be among the most v ulnerable populations 80

.

Exhibit D

- 2 shows the following in regard to population characteristics within a 1

- mile radius of

the facilities:

21 of the 31 GS and capture facilities examined (68%) have populations within a

1

- mile radius that exceed their resp ective state‟s percentage of minority populations and/or populations below 150% of the poverty level. They are shaded in gray in the exhibit.

3 of the 31 GS and capture facilities (10%) have populations within a 1

- mile radius that exceed their respective state‟s percentage of minority populations and populations below 150% of the poverty level. 81 These facilities include:

- Coffeyville Fertilizer Plant;

- Kemper County Plant; and

- Lima Plant.

Each of these 3 facilities has populations within a 1

- mile radius w ith 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 the ir 1

- mile radius, 4 facilities have 3 sites located within their 1

- mile radius, and 6

facilities have 4 or more sites located within their 1

- mile radius.

No facility‟s 1

- mile radius bisects Tribal land.

80 This analysis focuses on selected demographics surrounding the identified capture and sequestration facilities.
We have not conducted an exposure or risk assessment of CO 2 sequestration in Class I or Class VI facilities. Our
experience with deep well injection indicates that the risk of exposure resulting from CO 2 movement outside of the
permitted injection zone is low. However, we recognize that there is a potential for CO 2 movement outside the
inj ection zone that may impact USDWs. (See: U.S. EPA, Office of Water. 2003. “Relative Risk Assessment of
Management Options for Treated Wastewater in South Florida,” April 2003.

81 These 3 facilities are a subset of the 21 facilities noted above

.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 93 of 133 Exhibit D

- 3 shows the following in regard to popula tion characteristics within a 3

- mile radius of

the facilities:

20 of the 31 GS and c apture facilities examined (65%) have populations within a

3

- mile radius that exceed their respective state‟s percentage of minority populations and/or populations below 1 50% 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 th e poverty level. 82 These facilities include:

- Coffeyville Fertilizer Plant;

- Kemper County Plant;

- Lima Plant; and

- San Joaquin Basin Project, CA Saline Formation.

Each of these 4 facilities has populations within a 3

- mile radius with children 0 to 4 years an d/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 Ke mper 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 h ave 2 sites located within their 3

- mile radius, 5 facilities have 3 sites located within their 3

- mile radius, and 16

facilities have 4 or more sites located within their 3

- mile radius.

No facility‟s 3

- mile radius bisects Tribal land.

Refer to Appendix D. B. for detailed data on the incidence of the indicators within a 1

- and 3

- mile radius of the facilities.

82 These 4 facilities are a subset of the 20 facilities noted above.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 94 of 133 Exhibit D

- 2. Characteristics of Populations within 1

- Mile Radius of Facilities*

Facility Name Facility Type Facilities Whose 1

- Mile Populations

Exceed ed 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

Nort heastern Commercial Capture - - - 3 No

Antrim Gas Plant Existing Gas and

Fertilizer Plant - - X 0 No

Cincinnati Arch Mt.

Simon Saline Major DOE Sequestration Project - X** X** 3 No

Coffeyville Fertilizer

Plant Commercial Capture X X X 9 No

Edwardsport Commercial Capture - X X 4 No

Enid Gas Plant Existing Gas and

Fertilizer Plant - - X 1 No

Futuregen Futuregen

- X

- 1 No

Great Bend Commercial Capture - X** X 3 No

Great Plains Coal

Gasification Existing Gas and

Fertilizer Plant - X X 3 No

Green River Basin Nugget Sand Saline

Reservoir Major DOE Sequestration Project - - X 1 No

Hydrogen Energy

HECA Commercial Capture - - - 1 No

Illinois Basin Mt.

Simon Saline

Reservoir Major DOE Sequestration Project - X X 5 No

Kemper County Commercial Capture X X X 1 No

La Barge Gas Plant Existing Gas and

Fertilizer Plant - - X 2 No

Lima Commercial Capture X X X 31 No

Mesaba Commercial Capture - - X 1 No

Mt. Simon Saline

Reservoir Major DOE Sequestration Project - X

- 1 No

San Joaquin Basin, CA

Saline Formation Major DOE Sequestration - X X 2 No***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 95 of 133 Facility Name Facility Type Facilities Whose 1

- Mile Populations

Exceed ed the State Percentage Number of

FRS Sites

within 1

- Mile

Radius On Tribal

Land? % Minority (All Races) % Below

150 Percent of Poverty

Level % 0 to 4

Years or

65+ Years

Project

Tenasca

Sweetwater/Trailblazer Commercial Capture - X X 9 No

Tenasca Taylorville Energy Commercial Capture - - X 2 No

Texas Clean Energy Project Commercial Capture - - X 1 No

Val Verde Gas Plant, Gray Ranch E xisting 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 Sequestra tion 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 t he 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 popula tion group did not.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 96 of 133 Exhibit D

- 3. Characteristics of Populations within 3

- Mile Radius of Facilities*

Facility Name Facility Type Facilities Whose 3

- Mile Populations Exceeded the State Percentage Number of

FRS Sites

within 3

- Mile

Radius On Tribal

Land? % Minority (All Races) % Below 150

Percent of Poverty Level % 0 to 4

Years or

65+ Years

AEP Alstom Mountaineer (Ph.2) Commercial

Capture - X** X 11 No

AEP Alstom

Northeastern Commercial

Capture - - X 4 No

Antrim Gas Plant Existing Gas and

Fertilizer Plant - X

- 0 No

Cincinnati Arch Mt.

Simon Saline Major DOE

Sequestration Project - - X 9 No

Coffeyville

Fertilizer Plant Commercial

Capture X X X 31 No

Edwardsport Commercial

Capture - X X 9 No

Enid Gas Plant Existing Gas and

Fertilizer Plant - - X 5 No

Futuregen Futuregen

- X X 13 No

Great Bend Commercial

Capture - X** X 8 No

Great Plains Coal

Gasification Existing Gas and

Fertilizer Plant - X X 4 No

Green River Basin Nugget Sand Saline

Reservoir Major DOE

Sequestration Project - - X 1 No

Hydroge n 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 Commercia l

Capture X X X 88 No

Mesaba Commercial

Capture - - X 3 No

Mt. Simon Saline

Reservoir Major DOE

Sequestration Project - X X 13 No

San Joaquin Basin,

CA Saline

Formation Major DOE

Sequestration Project X X X 3 No***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 97 of 133 Facility Name Facility Type Facilities Whose 3

- Mile Populations Exceeded the State Percentage Number of

FRS Sites

within 3

- Mile

Radius On Tribal

Land? % Minority (All Races) % Below 150

Percent of Poverty Level % 0 to 4

Years or

65+ Years

Tenasca

Sweetwater/Trailbla

zer Commercia l

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 e xhibit uses gray shading to identify facilities whose minority populations and/or low

- income populations (i.e., populations living below 150% of the poverty level) exceed the state percentage, as these may be among the most vulnerable populations.

** The 3

- mile radius around these facilities falls in two states. The population within the 3

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

D.5 Qualitative Screening Analysis of Pipelines

This sectio n presents a qualitative screening analysis of EJ issues associated with pipelines carrying carbon dioxide (CO 2 ) under the proposed RCRA conditional exclusion . The analysis provides a preliminary characterization of potential health impacts to human popul ations near the pipelines. Section D.5.1 of this document provides background information about the existing hazardous waste regulations (i.e., the “baseline”) and proposed rule that would exempt CO 2 streams from RCRA regulation. Section D.5.2 describes the likelihood of CO 2 pipeline failures that could lead to a release. Section D.5.3 describes some of the possible health impacts to***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 98 of 133 surrounding populations from a CO 2 pipeline release. Section D.5.4 sets forth some preliminary

conclusions about CO 2 rele ases from pipelines.

The primary data source used in this qualitative analysis is the document, “Final Risk Assessment Report for the FutureGen Project Environmental Impact Statement,” dated October

2007. 83

, 84 The Risk Assessment addresses the potential releases of captured gases at the proposed FutureGen power plant, during transportation via pipeline to the geological sequestration (GS) facility, and during subsurface storage. The Risk Assessment was prepared under contract to the U.S. Department of E nergy (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 chem ical concentration effect levels related to health impacts to human and biological receptors.

Note that a quantitative, pipeline

- specific analysis of EJ issues under the RCRA proposed rule was not performed for several reasons. There are over 3,000 miles of existing CO 2 pipelines and uncertainty exists about the particular pipelines that would be used to transport CO 2 streams under the baseline and proposed rule by capture facilities that now are being planned. In addition, new pipelines may be built to transport CO 2 streams from capture facilities to distribution pipelines and wells and the location of these new pipelines is not known. Because of these uncertainties, EPA determined that a qualitative screening analysis based on existing

information woul d be an appropriate first step to characterize some of the potential health impacts to human populations under the proposal and then to assess the need for additional research and analysis.

D.5.1 Background on Baseline and Proposed RCRA Rule

This section provides a brief description of the baseline regulations and proposed regulations as applicable to this analysis.

Baseline . Under the baseline, CO 2 streams that exhibit a RCRA hazardous characteristic under

40 CFR Part 261 must be classified hazardous w aste and managed and disposed of in accordance with the RCRA hazardous waste regulations. This includes, for example, treatment of the CO 2 stream to meet applicable RCRA treatment standards before land disposal, if applicable, and disposal in a UIC well t hat meets applicable UIC and RCRA requirements.

A CO 2 stream generator under the baseline may have several options for addressing its hazardous

waste CO 2 . It may treat the hazardous waste CO 2 to render it non

- hazardous (i.e., by removing

the characteri stics that make the CO 2 stream hazardous) and dispose of it as non

- hazardous waste in a Class VI UIC well. Note that, under EPA‟s Class VI UIC amendments, injection of a RCRA hazardous waste in a Class VI UIC well would be prohibited. Alternatively, a CO 2 stream

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

84 FutureGen is a public

- private partnershi p to build a first

- of

- its

- kind coal

- fueled power plant. It will generate electricity while capturing and injecting CO 2 into geological sequestration (GS) facilities.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 99 of 133 generator may opt for other methods, such as disposing of untreated RCRA hazardous waste CO 2 stream in a UIC Class I hazardous well that that meets applicable no

- migration requirements

under 40 CFR Part 148.

Pipeline transport of CO 2 streams is subject to Department of Transportation (DOT) regulation. For example, 49 CFR Part 195 applies to pipeline facilities and the transportation of hazardous liquids or carbon dioxide associated with those facilities in or affecting interstate or foreign

comm erce, except as otherwise specified. This regulation includes requirements for the design, construction, testing, operation and maintenance, reporting, and corrosion control of pipelines.

Proposed Rule . Under the proposal, CO 2 streams would be exempt f rom 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 CO 2 streams as non

- hazardous waste in Class VI UIC wells. Captured CO 2 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 CO 2 streams under th e proposed rule would continue to be subject to U.S. DOT regulation. U.S. DOT regulatory requirements for transport of CO 2 streams would not be affected by the exclusion

.

D.5.2 Risks of Pipeline Failure

The FutureGen Risk Assessment presents data concer ning the probability of a release from an aboveground CO 2 pipeline, based on data from the US Department of Transportation Office of Pipeline Safety and based on the length of the pipeline. 85 According to the Risk Assessment, rupture and puncture failure f requencies were calculated to be 5.92 x 10 - 5 /(kilometer

- year) and

1.18 x 10 - 4 /(kilometer

- year), respectively. 86

The Risk Assessment based its incident probability calculations on a number of data and assumptions, such as the following:

The CO 2 pipeline fa ilure 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 i nvolving CO 2 pipelines occurred during this time period.

DOE assumes the total length of pipeline s in operation in the U.S. during this time period was approximately 1,616 miles (2,600 kilometers).

85 See page 6

- 14 of the FutureGen Risk Assessment.

86 The Risk Assessment mentioned thes e estimates on pages 4

- 4 and 6

- 14; however, it mentions different risk values for ruptures and punctures in mile

- year. EPA believes this is an error in converting between mile

- year and

kilometer

- year. EPA used the risk values expressed in kilometer

- year in preparing Figures 1 and 2.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 100 of 133 Based on the Risk Assessment data and formulas, Figure 1 shows the probability of at least one pipeline rupture over a 50 year period, given three different pipeline lengths. Exhibit D

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

- 5 shows that, over a 50 year period, there is an estimated 60% probability of a pipeline puncture i n a 150 kilometer pipeline. 87

Exhibit D

- 4 . Probability of CO 2 Pipeline Rupture over 50 Year Period:

50

- , 100

- and 150

- Mile Pipelines a

a Based on data and formulas in “Final Risk Assessment Report for the FutureGen Project

Environmental Impact Statement,” dated October 2007 (see page 6

- 14).

Exhibit D

- 5 . Probability of CO 2 Pipeline Puncture over 50 Year Period:

50

- , 100

- and 150

- Mile Pipelines a

87 The Risk Assessment identifies some data gaps and limitations in its risk estimates (see page 6

- 20). For example, there are many established techniques for minimizing the chances and consequences of a pipeline rupture or

puncture.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 101 of 133 a Based on data and formulas in “Final Risk Assessment Report for the Futur eGen Project Environmental Impact Statement,” dated October 2007 (see page 6

- 14).

D.5.3 Potential Health Impacts of CO 2 Pipeline Releases

The Risk Assessment describes release simulations from pipeline transmission lines that were performed. The simula tions examined emissions of CO 2 and H 2 S. The SLAB air dispersion

model was used to simulate the emission of CO 2 for various release scenarios involving the pipeline when the gas is in a supercritical gas state. 88 Pipeline release simulations were

evaluate d 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 exam ined. 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 CO 2 releases due to pipeline ruptures or punctures at any

of the four candidate sites. This is shown in Exhibit D

- 4. In all cases, the expected number of

individuals affec ted is less than one.

Exhibit D

- 6 shows that the largest number of people potentially affected by H 2 S 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 H 2 S 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 H 2 S release from a puncture is six at the Jewett

Site and one at the Tuscola Site. The maximum number of individua ls expected to experience

irreversible

- adverse or life threatening effects for the Jewett pipeline is one. No adverse or life

threatening effects are predicted for H 2 S releases from pipeline ruptures or punctures at the

Odessa and Mattoon sites.

88 The SLAB model was developed by the Lawrence Livermore National Laboratory, and is designed to

simulate denser

- than

- air gas releases for both horizontal jet and vertically elevated jet scenarios. SLAB is approved by U.S. EPA as a hazardous air dispersion model.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 102 of 133 Exhibit D

- 6 : Summary of Expected Numbers of Individuals from

the Public Affected by Pipeline Releases a
Mattoon,

IL Tuscola,

IL Jewett,

TX Odessa, TX

(A) Ruptures

CO 2 Health Effects

Adverse 0 <0.1 <0.5 0

Irreversible

Adverse 0 <0.1 <0.5 0

Life Threat ening 0 <0.1 <0.5 0

H 2 S Health Effects

Adverse 0.12 7.4 52 0.19

Irreversible

Adverse 0.001 <0.2 1 0.004

Life Threatening <0.001 <0.2 1 <0.004 (B) Punctures

CO 2 Health Effects

Adverse 0.01 <0.1 0.2 <0.1 Life Threatening <0.01 <0.1 <0.2 <0.1

H 2 S Hea lth 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 Octobe r 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‟ analys is 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 H 2 S concentration (0.51 ppmv) is associated with the perception of an objectionable odor. Likewis e,***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 103 of 133 the life threatening effects of H 2 S exposures are associated with long exposure levels that can be

detected and avoided.” 89

D.5.4 Preliminary Conclusions on Potential Releases

Under the baseline, generators of hazardous waste CO 2 streams must conduct treatment to remove its RCRA characteristic(s) and thereby render it non

- hazardous before sending it to a Class VI UIC well. This is because, pursuant to EPA‟s UIC amendments, injection of RCRA hazardous waste into a Class VI UIC well would be prohibited. Treatment of the CO 2 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 CO 2 streams in other ways ( e.g., disposing of untreated hazardous waste CO 2 streams in a Class I UIC well that meets no migration requirements).

Under the proposed rule, generators could dispose of their exempt CO 2 stream in Class VI UIC wells, provided that the generator and UIC w ell 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 CO 2 streams will be transported by pipeline for injection i n UIC wells under the proposed rule than the baseline. For example, generators that

would have treated their hazardous waste CO 2 under the baseline for injection in a Class VI UIC well could forgo treatment under the proposed rule. In addition, some gene rators that would not have captured their hazardous waste CO 2 at all under the baseline (e.g., because of treatment costs) may be induced to capture it under the proposed rule for transport via pipeline to Class VI

UIC wells.

The Risk Assessment concludes that its results indicate that the potential human

- health effects due to pipeline ruptures or punctures at all sites under examination are minimal. The primary predicted effect identified in the „pipeline

- walk‟ analysis in the event of a release is mild

t ransient health effects. It also indicates that the potential for human exposure to hazardous

constituents from accidental releases from CO 2 pipelines is related to several factors, including the composition of the CO 2 stream among other things. A greate r quantity of untreated CO 2 streams being transported by pipeline under the proposed rule could potentially be associated with a higher potential for exposures of hazardous constituents to surrounding populations, although the health effects appear to be m ild.

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

D.6.1 Comparative Analysis

Results

The comparative analysis identified the following potential regulatory differences :

89 See page 6

- 7 of the FutureGen Risk Assessment.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 104 of 133 Generators operating under the proposed conditional exclus ion 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 CO 2 streams managed unde r the proposed conditional exclusion would be subject to the same federal regulations as pipelines carrying CO 2 streams managed under the baseline. In particular, pipeline transport of CO 2 would be subject to DOT regulation under both the baseline and pro posed 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 CO 2 streams under the baseline would also be required by the permit writers to meet the Class VI UIC well requirements. There is no regulatory requirement, however, that permit writers apply the Class VI requirements to Class I hazardous wells.

Possible Ne xt 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 analys is. However, additional analysis could be done on other potentially relevant federal regulations.

D.6.2 Screening Analysis of Capture and GS Facilities

Results

EPA‟s screening analysis found that:

21 of the 31 GS and capture facilities examined (68 %) have populations within a

1

- mile radius that exceed their respective state‟s percentage of minority populations and/or populations below 150% of the poverty level. Of these 21 facilities, 3 have populations within a 1

- mile radius that exceed their resp ective 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).***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 105 of 133 Each o f these 3 facilities has populations within a 1

- mile radius with children 0 to 4 years and/or adults 65 years and older in percentages that exceed their respective state‟s percentages. In addition, each has at least one existing FRS site

located within a 1

- mile radius. The Coffeyville Fertilizer Plant has 9 sites within

a 1

- mile radius, the Kemper County Plant has 1 site within a 1

- mile radius, and

the Lima Plant has 31 sites within a 1

- mile radius.

20 of the 31 GS and capture facilities examined (65%) have populations within a

3

- mile radius that exceed their respective state‟s percentage of minority populations and/or populations below 150% of the poverty level. They are shaded in gray in the exhibit. Of these 20 facilities, 4 have populations within a 3

- mile radius that exceed their respective state‟s percentage of minority populations and populations below 150% of the poverty level. These facilities

include:

- Coffeyville Fertilizer Plant (capture facility);

- Kemper County Plant (capture facility);

- Li ma 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

r espective 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 8 8 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 sc reening 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 f

or 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***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 106 of 133 Results

Under the baseline, generators of hazardous waste CO 2 strea ms 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 woul d be prohibited. Treatment of the CO 2 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 CO 2 streams in other ways.

Under the proposed rule, generators could dispose of their exempt CO 2 stream in Class VI UIC wells, provided that the generator and UIC well owner/operator claim the exclusion and comply with its conditions. No treatment would be required under the RCRA regulations. As a result, it is possible that a greater quantity of untreated CO 2 streams will be transported by pipeline for injection in UIC wells under the proposed rule than the baseline.

The FutureGen Risk Assessment concludes that the results of its “pipe

- walk” analysis indicate that the potential human

- health effects due to pipeline ruptures or punctures at all four sites under examination are minimal. The primary predicted effect in the event of a release is mild

transient health effects.

It also indicates that the potential for human exposure to hazardous constituents from accidental

releases from CO 2 pipelines is related to several factors, including the composition of the CO 2 stream among other things. A greater quantity of untreated CO 2 streams being transported by pipeline under the proposed rule could potentially be associated with a higher potential for exposures of hazardous constituents to surrounding populations, although the health effects appear to be mild.

Possib le Next Steps

The conclusions of this analysis are based on a single source, i.e., the FutureGen Risk Assessment. Additional research and analysis may be appropriate to learn more about the potential risks and health impacts to populations near CO 2 pipel ines.

Appendix D.A.

– Facilities Included in the Environmental Screening Analysis

The facilities in Exhibits D.A

- 1 through D.A

- 3 are included in the EJ screening analysis presented in Chapter 4 of this document.

Exhibit D.A

- 1. Planned Major Commerci al (Non

- DOE)

and FutureGen Capture Facilities

Facility Name State Lat

D/M/S Long

D/M/S

Commercial

AEP Alstom Mountaineer WV 38/58/44 81/56/20***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 107 of 133 (Ph.2)

AEP Alstom Northeastern OK 36/25/51 95/42/03 Edwardsport IN 38/48/24 87/14/49

Great Bend OH 38/59/56 81/45/47 Hydrogen Energy HECA CA 35/17/03 119/26/44 Kemper County MS 32/48/53 88/43/24

Lima OH 40/44/33 84/06/49

Mesaba MN 47/33/55 92/08/47 Tenasca Taylorville Energy IL 39/35/21 89/11/20

Tenasca

Sweetwater/Trailblazer TX 32/28/04 100/24/27

Texas C lean Energy Project TX 31/44/46 102/36/30 WA Parish, Sugarland TX 29/28/40 95/38/06 Wallula Energy Res. Center WA 46/07/14 118/54/15

Worsham

- Steed (ZENG) TX 32/27/41 97/53/27

FutureGen Futuregen IL 39/29/49 88/26/26

Exhibit D.A

- 2. Existing Gas and Fertilizer Plants

Facility State Lat

D/M/S Long

D/M/S

Val Verde Gas

- Pikes Peak

Plant TX 30/38/1

7 102/56/34

Val Verde Gas

- Grey Ranch

Plant TX 30/33/1

6 102/26/33

Val Verde Gas

- Puckett Plant TX 30/44/4

0 102/29/30

Val Verde Gas

- Terrell Plant T X 30/22/1

9 101/50/39

Val Verde Gas

- Mitchell Plant TX 30/40/1

6 102/29/37

La Barge Gas Plant WY 42/15/4

3 110/11/41

Enid Ammonia Fertilizer Gas

Plant OK 36/22/4

4 97/45/38

Coffeyville Ammonia

Fertilizer Plant KS 37/05/1

9 95/43/39

Antrim Gas Plant MI 45/ 1/27 84/36/7

Great Plains Coal Gasification ND 47/21/4 101/49/54***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 108 of 133 8

Exhibit D.A

- 3. Major DOE Sequestration Projects

Facility State Lat

D/M/S Long

D/M/S

Illinois Basin Mt. Simon

Saline Reservoir IL 39/52/4

5 88/53/41

Williston Basin EOR Sequestration ND 48/31/2

8 102/58/11 Green River Basin Nugget

Sand Saline Reservoir WY 43/15/3

0 110/12/60

Cincinnati Arch Mt. Simon

Saline OH 38/54/1

3 84/50/56 San Joaquin Basin, CA

Saline Formation CA 36/33/4

9 119/12/19

Mt. Simon Saline Reservoir IL 39/29/4

9 88/26/26

.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 109 of 133 Appendix D.B. Characteristics of Populations Within 1

- and 3

- Mile Radius of Facilities: Detailed Exhibits Supporting the Environmental Justice Screening Analyses

This appendix presents detailed results of the environmental justice screening analysis presented in Chapter 4 of this document. Data are presented on the incidence of each indicator that EPA

examined within a 1

- and 3

- mile radius of capture and GS facilities. These data are presented in the following exhibits:

Exhibit D.B

- 1. Percentage of Population that is Minority (by Race and in Total) Within

1

- Mile Radius of Facility

Exhibit D.B

- 2. Percentage of Population that is Below150% of Poverty Level Within 1

- Mile Radius of Facility

Exhibit D.B

- 3. Percentage of Population 0 to 4 Years and 65+ Years Within 1

- Mile Radius of Facility

Exhibit D.B

- 4. Number of FRS Sites Within 1

- Mile Radius of Facility

Exhibit D.B

- 5. Percentage of Population that is Minority (by Race and in Total) Within

3

- Mile Radius of Facility

Exhibit D.B

- 6. Percentage of Pop ulation that is Below150% of Poverty Level Within 3

- Mile Radius of Facility

Exhibit D.B

- 7. Percentage of Population 0 to 4 Years and 65+ Years Within 3

- Mile Radius of Facility

Exhibit D.B

- 8. Number of FRS Sites Within 3

- Mile Radius of Facility

Each exh ibit 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 respec tive indicators in each state. In addition, the exhibits use a gray highlight to identify indicators whose percentage within the 1

- or 3

- mile radius of the facility exceeds the state‟s percentage.Exhibit D.B

- 1. Percentage of Population that is Minority ( by Race and in Total) Within 1

- Mile Radius of Facility***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 111 of 133

Exhibit D.B

- 1. Percentage of Population that is Minority (by Race and in Total) Within 1

- Mile Radius of Facility (Cont’d)***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 112 of 133

Exhibit D.B

- 1. Percentage of Population that is Minority (by Race and i n Total) Within 1

- Mile Radius of Facility (Cont’d)Exhibit D.B

- 2. Percentage of Population that is Below150% of Poverty Level Within 1

- Mile Radius of Facility***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 114 of 133 Exhibit D.B

- 2. Percentage of Population that is Below150% of Poverty Level Within 1

- Mile

R adius of Facility (Cont’d)***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 115 of 133 Exhibit D.B

- 3. Percentage of Population 0 to 4 Years and 65+ Years Within 1

- Mile Radius of Facility***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 116 of 133 Exhibit D.B

- 3. Percentage of Population 0 to 4 Years and 65+ Years Within 1

- Mile Radius of Facility (Cont’d)***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 117 of 133Exhibit D. B

- 4. Number of FRS Sites Within 1

- Mile Radius of FacilityExhibit D.B

- 4. Number of FRS Sites Within 1

- Mile Radius of Facility (Cont’d)Exhibit D.B

- 5. Percentage of Population that is Minority (by Race and in Total) Within 3

- Mile Radius of FacilityExhibit D.B

- 5. Percentage of Population that is Minority (by Race and in Total) Within 3

- Mile Radius of Facility (Cont’d)***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 122 of 133

Exhibit D.B

- 5. Percentage of Population that is Minority (by Race and in Total) Within 3

- Mile Radius of Facility (Cont’d)***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 123 of 133***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 124 of 133Exhib it D.B

- 6. Percentage of Population that is Below150% of Poverty Level Within 3

- Mile Radius of Facility***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 126 of 133 Exhibit D.B

- 6. Percentage of Population that is Below150% of Poverty Level Within 3

- Mile Radius of Facility (Cont’d)***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 127 of 133

Exhibit D.B

- 7. Percentage of P opulation 0 to 4 Years and 65+ Years Within 3

- Mile Radius of Facility***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 128 of 133

Exhibit D.B

- 7. Percentage of Population 0 to 4 Years and 65+ Years Within 3

- Mile Radius of Facility (Cont’d)***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 129 of 133 Exhibit D.B

- 8. Number of FRS Sites Within 3

- Mile Radius of FacilityE xhibit D.B

- 8. Number of FRS Sites Within 3

- Mile Radius of Facility (Cont’d)***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 131 of 133 Appendix E.

Unfunded Mandates Reform Act Analysis

No analysis is required under the Unfunded Mandates Reform Act (UMRA) because the proposed rule does not include any mandate that is e xpected 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 insignifica nt costs to state governments.

Appendix F.

Other Required Analyses

F

- 1 Executive Order 12866: Regulatory Planning and Review

EPA has determined that the proposed rule is a "significant regulatory action" as defined by

Executive Order 12866 because it raises novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order. Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for review under EO 12866, and any cha nges 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 Fe deralism 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 CO 2 c apture or sequestration

facilities.***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 132 of 133 F

- 4 Executive Order 13045: Protection of Children from Environmental Health and Safety Risks

EPA does not believe that the rule will have environmental health or safety impacts that disproportionately affect children . Therefore, no additional analysis is required under this

Executive Order.

F

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

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

F

- 6 National Technology Transfer Advancement Act

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

F

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

- Income Populations

The proposed rule is not expected to have disproportion ately high and adverse human health or environmental effects on minority or low

- income populations. EPA believes that the actions allowed by the proposed exclusion s are safe and do not present significant adverse health or environmental impacts (See Appen dix D)

.

F

- 8 Executive Order 12 630: 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 12 988: 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 effec t; and defines key terms. Therefore, no additional analysis or actions are required under EO 12988.

F

- 10 Executive Order 1 3352: Facilitation of Cooperative Conservation

The proposed rule is designed to promote cooperative conservation between EPA, state , and local governments by identifying clear criteria for excluding carbon dioxide injectate from***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review***

Page 133 of 133 the regulatory requirements for hazardous waste, when managed in Class VI UIC wells for purposes of geologic sequestration.

F

- 11 Joint Impacts of Rules

The proposed rule will exempt CO 2 streams captured for the purpose of geological sequestration in a Class VI UIC well from the definition of hazardous waste. Such waste will not be subject to EPA‟s hazardous waste regulations. These CO 2 streams would still q ualify as solid wastes per the definition in 40 CFR 261.2 (Definition of solid waste). The management of these CO 2 streams would be subject to the Underground Injection Control Program (UICP) requirements in 40 CFR Parts 144 (Requirements for wells inject ing hazardous waste) and the proposed technical criteria and standards for Class VI UIC wells in

40 CFR Part 146 (Underground Injection Control Program: Criteria and Standards). 90 CO 2 capture and sequestration facilities claiming the proposed exclusion wou ld remain subject to the mandatory reporting requirements for greenhouse gas emissions in 40 CFR Part 98 (Mandatory Greenhouse Gas Reporting) . The transportation of captured CO 2 streams by pipeline would remain subject to the Department of Transportation (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA) under 49 CFR Parts 195

- 199

. The transportation of captured CO 2 by air, water, or highway would remain subject to the PHMSA requirements in 49 CFR Parts 171

- 180.

90 Non

- hazardous solid wastes that are subject the UICP requirement are not subject to the requirements for

non

- hazardous solid waste in 40 CFR Parts 257 and 258.