1 

Regulatory Impact Analysis 

For EPA’s Proposed RCRA Regulation 

Of Coal Combustion Residues (CCR) 

Generated by the Electric Utility Industry 

Prepared by: 

US Environmental Protection Agency 

Office of Resource Conservation & Recovery (ORCR) 

(formerly Office of Solid Waste) 

1200 Pennsylvania Avenue NW (Mailstop 5305P) 

Washington DC, 20460 USA 

30 April 2010 
2 

Acknowledgements 

EPA Contractor Support & EPA Staff Assistance for this RIA 

In 2009 under EPA contract EP-W-07-0011, work assignment 2-33, Industrial Economics Inc. (Cambridge MA) and its subcontractor DPRA Inc (Minneapolis MN) provided data analysis support for identifying affected entities and estimating 

baseline CCR disposal practices and costs (Chapter 3), and for estimating costs of regulatory engineering control 

requirements (Chapter 4) in this RIA. 

EPA ORCR staff contributing to this RIA: Rachel Alford, Richard Benware, Mark Eads, Christina Kager, and Scott Palmer. 
3 

Table of Contents

Executive Summary 5 

Chapter 1: Problem Statement: The Need for RCRA Regulation of CCR Disposal 13 

Chapter 2: Potentially Affected Industries & RCRA Regulatory Options 18 

 2A. Identity of Potentially Affected Industries (Electric Utility Industry) 18 

 2B. Other Industries with CCR Disposal Units Not Covered by the Proposed Rule 20 

 2C. RCRA Regulatory Options Evaluated in this RIA 24 

Chapter 3: Baseline CCR Disposal in the Electric Utility Industry 27 

3A. Identity of Coal-Fired Electric Utility Plants 27 

3B. Types of CCR Disposal Units 33 

 3C. Types of CCR Generated and Annual Quantities 36 

 3D. Size of CCR Disposal Units 41 

3E. Cost of Baseline CCR Disposal 42 

Chapter 4: Estimated Cost for RCRA Regulation of CCR Disposal 67 

 4A. EPA_s Prior Cost Estimates for RCRA Regulation of CCR Disposal at Electric Utility Plants 67 

 4B. Regulatory Cost Estimation Algorithms & Results 68 

 4B.1 Engineering Control Costs 69 

 4B.2 Ancillary Regulatory Requirement Costs 73 

 4B.3 Land Disposal Restriction (CCR Dewatering Treatment) Cost 83 

4C. State-by-State Distribution of Regulatory Cost 105 

4D. Cost Estimation Uncertainty 107 

Chapter 5: Potential Benefits of RCRA Regulation of CCR Disposal in the Electric Utility Industry 110 

 5A. Groundwater Protection Benefits (Avoided Future Cancer Risks & Groundwater Remediation Costs) 111 

 5B. Preventing Future CCR Impoundment Catastrophic Failures (Avoided Future Cleanup Costs) 133 

 5C. Induced Effect of RCRA Regulation of CCR Disposal on Future CCR Beneficial Use 149 

Chapter 6: Comparison of Regulatory Benefits to Costs 191 

 6A. Comparison of Benefits to Costs Based on Alternative Discount Rates (7%, 3%, 0%) 191 

 6B. Factors Applied for Scaling Benefits and Costs to the Regulatory Options 198 

Chapter 7: Supplemental Analyses Required by Congressional Statutes or White House Executive Orders 204 

7A. Electricity Price Impact (Executive Order 13211) 204 

 7B. Small Business Impact Analysis (RFA/SBREFA) 208 

7C. Minority & Low-Income Populations Near Electric Utility Plants (Executive Order 12898) 216 

7D. Child Population Statistics (Executive Order 13045) 229 

7E. Unfunded Mandates (UMRA) & Federalism Implications Analysis (Executive Order 13132) 237 

 Appendix Provided as separate document (the contents of the Appendix are displayed on the next page of this RIA) 
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Table of Appendices 

Note: Because of its large number of pages (>400 pages), the Appendix is provided as a separate companion document to this RIA.

Appendix A Chronology of EPA_s Regulatory Evaluation of CCR (1978 to March 2009) 

Appendix B List of Other Industries with Coal-Fired Electricity Plants Not Covered by the Proposed Rule or this RIA 

Appendix C List of 495 Operating Electric Utility Plants Potentially Affected by the CCR Rulemaking (2007) 

Appendix D Identity of 200 Entities Which Own the 495 Potentially Affected Electric Utility Plants (2007) 

Appendix E Baseline State Government Regulatory Requirements for CCR Disposal Units in Top-34 Coal Utility States 

Appendix F Baseline Engineering Controls Installed at CCR Disposal Units in the Electric Utility Industry 

Appendix G Description of CCR Landfill & Surface Impoundment Engineering Control Cost Model 

Appendix H Baseline Cost Estimates for CCR Disposal by the Electric Utility Industry 

Appendix I Geological Conditions at Electric Utility Industry CCR Disposal Unit Locations 

Appendix J Incremental Regulatory Cost Estimates for Compliance with the CCR Proposed Rule Regulatory Options 

Appendix K Appendices Supporting the Regulatory Benefits Evaluation 

Appendix L Electricity Price Impact Analysis Spreadsheet (Executive Order 13211) 

Appendix M Small Entity Impact Data & Analysis Spreadsheet (RFA/SBREFA) 

Appendix N Minority & Low-Income Population Data (Executive Order 12898) 

Appendix O Child Population Data (Executive Order 13045) 

Appendix P UMRA Written Statement 

Appendix Q Documentation for EPA_s Social Cost Estimate Assigned to the TVA Kingston 2008 CCR Impoundment Failure Event 
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Executive Summary 

This RIA evaluates the expected regulatory compliance costs, economic and environmental benefits, and potential impact on CCR beneficial 

use, of EPA_s proposed regulation of coal combustion residual (CCR) disposal by coal-fired electric utility plants. The CCR disposal 

regulatory options evaluated in this RIA are based on EPA_s statutory authority contained in the 1976 Resource Conservation and Recovery 

Act (RCRA). The main findings of this RIA are summarized below according to six sections: 

ES-1: Regulatory Options Evaluated in this RIA 

ES-2: Benefits of Avoided Future Groundwater Contamination (Human Health Protection & Avoided Remediation Costs)

ES-3: Benefits of Avoided Future CCR Impoundment Structural Failures (Avoided Cleanup Costs)

ES-4: Economic and Environmental Benefits from Future Increase in CCR Beneficial Uses by Other Industries

ES-5: Regulatory Compliance Costs

ES-6: Comparison of Regulatory Benefits to Costs

ES-1: Regulatory Options Evaluated in this RIA 

This RIA evaluates three options for RCRA regulation of CCR disposal at coal-fired electric utility plants. All options (a) maintain the existing 

Bevill regulatory exclusion for CCR beneficial uses, and (b) propose the same set of 10 custom-tailored engineering controls (i.e., technical 

design and operating standards) for CCR disposal units: 

1. Subtitle C gSpecial Wasteh Option: Regulate CCR landfills and impoundments as a gspecial wasteh under Subtitle C requirements, and 

would require phase out of impoundments within five years. 

2. Subtitle D Option (version 2): Composite liners required for all (i.e., existing and future new) CCR impoundments but only for new 

landfills. For any CCR landfills and impoundments that closed before the effective date, there would be no regulatory controls over 

those units, unless the states choose to adopt controls over such units. Also, all surface impoundments (existing and new) would need 

to have composite liners within 5-years of the effective date. 

3. Subtitle gD primeh Option: Composite liners required only for new impoundments and landfills; unlined units could continue to 

operate. This approach would be the same as the Subtitle D option above, except that existing impoundments would not be required to 

retrofit and install a composite liner, or close. 
6 

ES-2: Benefits of Avoided Future Groundwater Contamination (Human Health & Avoided Remediation Costs) 

By establishing management and permit standards for CCR disposal units under RCRA, the proposed regulatory options will reduce 

uncontrolled releases and cancer risks, and improve detection and, if necessary, response to future groundwater contamination. This RIA 

quantifies two components of groundwater protection benefits: (a) human cancer risks avoided from drinking contaminated groundwater, and 

(b) groundwater contamination remediation costs avoided. Summary Exhibit 1 below presents the monetized results of this evaluation. 

x Estimate of avoided human cancer risks from avoided future groundwater contamination by CCR disposal units: 

o Individual skin cancer risks avoided (by eliminating the groundwater pathway for arsenic at CCR impoundments) are estimated 

up to 2 x 10-2 (i.e., a probability equal to 2 individual human skin cancer incidence risks for every 100 persons exposed) using 

the current IRIS skin cancer slope factor for arsenic. 

o 30,400 people use drinking water wells within one mile of coal-fired electric utility plants; of which 8,150 (27%) are children. 

o Taking into account current CCR disposal unit designs, an estimated 145 (using the IRIS cancer slope factor) to 2,509 (using the 

NRC lung and bladder cancer slope factor1) future human cancer risks are expected to occur in absence of the proposed RCRA 

regulation, based on drinking water exposure to arsenic in CCR. 

x Other human health risks from CCR disposal units not quantified in this RIA: 

o Human non-cancer risks, including from selenium, cobalt, nitrate/nitrite, and molybdenum, which may be released to 

groundwater at levels above the MCL or 3 times the human hazard quotient (HQ). 

o Cancer and non-cancer risks from arsenic and other metals released in effluent from CCR impoundments to surface waters. 

Summary Exhibit 1 

Future Avoided Human Cancer Risks & Avoided Groundwater Remediation Cost Benefits 

($millions present value @7% discount rate over 50-years) 

Groundwater Protection Benefit Category Subtitle C 

special waste 

Subtitle D 

(version 2) Subtitle gD primeh 

Groundwater Remediation Costs Avoided $466 $168 $84 

Monetized Value of Cancer Risks Avoided $504 $207 $104 

Total = $970 $375 $188 

ES-3: Benefits of Avoided Future CCR Impoundment Structural Failures (Avoided Cleanup Costs) 

This RIA estimated future avoided cleanup costs from catastrophic impoundment failures, like the one that occurred at TVA_s Kingston TN 

coal-fired electricity plant in December 2008, which would be prevented under the proposed rule. Given the increasing age of CCR 

 

1

 EPA calculated a new cancer slope factor for arsenic from data in the National Research Council report gArsenic in Drinking Water: 2001 Updateh at 

http://www.nap.edu/openbook.php?isbn=0309076293 
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impoundments, the relative number that present high or significant hazard potential, and the history of CCR impoundment failures to date, this 

RIA presents three alternative scenarios of future catastrophic failures, the result for which are displayed in Summary Exhibit 2 below: 

x Failure Scenario #1: Extrapolation of future CCR impoundment failure probability based on the relative (a) recent historical occurrence 

frequency, (b) CCR quantity release magnitude, and (c) cleanup costs, associated with three recent (2005, 2008, 2009) CCR 

impoundment failures which exceeded 1 million gallons in release quantity each. 

x Failure Scenario #2: Assumes 10% of CCR impoundments in the high failure risk group (i.e., above 40 feet tall and over 25 years old) 

fail over the next 20 years in absence of RCRA regulation.2

x Failure Scenario #3: Assumes 20% of CCR impoundments in the high failure risk group (i.e., above 40 feet tall and over 25 years old) 

fail over the next 20 years in absence of RCRA regulation. 

Summary Exhibit 2 

Avoided Future CCR Impoundment Catastrophic Failure Cleanup Costs 

($millions present value @7% discount rate) 

Impoundment Failure Scenarios Subtitle C 

special waste 

Subtitle D 

(version 2) Subtitle gD primeh 

Failure Scenario #1: 

Extrapolation of three recent (2005, 2008, 2009) 

CCR impoundment failure events 

$5,285 $2,378 $1,216 

Failure scenario #2: 

Assuming 10% of 96 high-risk impoundments fail $8,366 $3,795 $1,897 

Failure Scenario #3: 

Assuming 20% of 96 high-risk impoundments fail $16,732 $7,590 $3,795 

The proposed regulation has categories of other benefits from avoiding future CCR impoundment structural failures which this RIA did not 

quantify and monetize, including potential avoided costs associated with a few possible benefit categories: 

1. Litigation costs: Avoided litigation and related costs associated with such damage events. 

2. Riparian damages: Reduction of toxic chemical contaminated effluent discharges from CCR impoundments to surface waters (i.e., 

rivers and lakes) through future phase-out of surface impoundments.3

3. Non-cancer health risks: Reduction in human health risks from future reduction in human exposure to non-carcinogenic but otherwise 

toxic chemicals contained in CCR, such as selenium, cobalt, nitrate/nitrite, and molybdenum, which, as currently managed in CCR

 

2

 Based on the responses to our CERCLA 104(e) information requests to utilities with impoundments, there are 96 impoundments that meet these criteria. However, this 

RIA estimates that 16 of these impoundments have closed or are expected to close before the CCR rule is finalized and goes into effect. Therefore, this analysis removed 

these 16 impoundments and based the estimated future impoundment failure cleanup costs on a subset of 80 CCR impoundments meeting the oat risk_ criterion. 3

 EPA is developing a regulatory proposal under the Clean Water Act to revise the current effluent guidelines for steam electric utilities. Current guidelines only control 

pH, total chlorine, and total suspended solids (TSS). EPA_s proposed CCR rule would eliminate CCR surface impoundments, eliminating much of the risk that would be 

addressed under revisions to the effluent guidelines, including risks posed by arsenic, selenium, mercury, cadmium, copper, chromium, and nickel. 
8 

disposal units, can exceed the human health hazard quotient (HQ) or Maximum Contaminant Limit (MCL). Chapter 5 of this RIA 

provides a list of contaminants of concern in CCR surface impoundment effluent and potential human health and environmental effects. 

4. Dry CCR disposal risks: Human health effects from improperly managed dry disposal, which are based on ongoing research by EPA_s 

Office of Research & Development (ORD), may pose greater risks than previously estimated by EPA in 2000 and 2007. 

ES-4: Economic & Environmental Benefits from Future Increase in CCR Beneficial Uses by Other Industries 

This RIA evaluated the potential impact that the CCR proposed rule may have on beneficial uses of CCR by other industries. Baseline CCR 

beneficial use at the current 62 million tons per year rate (2009) is estimated in this RIA to provide $26 billion per year in nationwide social 

benefits consisting of: (a) materials cost savings, plus (b) lifecycle avoided pollution benefits, plus (c) avoided CCR disposal costs to the 

electric utility industry. On a present value basis over the 50-year future period-of-analysis (2012-2061) applied in this RIA, the present value 

of CCR beneficial use amounts to $778 billion (@7% discount). Although the industries which use CCR for beneficial uses are not subject to 

the requirements of the CCR proposed rule, this RIA presents three alternative scenarios of potential induced effect of the CCR rule on future 

CCR beneficial use, consisting of increased use (scenario #1), decreased use (scenario #2), and no change (scenario #3). This RIA quanfities 

both scenario #1 and scenario #2 incrementally in relation to the gno changeh scenario #3. EPA believes the increasing beneficial use scenario 

#1 is most likely because (a) the proposed CCR regulation is targeted at CCR disposal not at CCR beneficial uses, (b) all CCR regulatory 

options retain the existing RCRA Bevill exemption for CCR beneficial uses, and (c) the added cost of regulatory compliance will make 

beneficial use relatively more cost-effective and represent an gavoided disposal cost incentiveh4 to electric utility plants to increase their supply 

of CCR to industrial markets for CCR as a raw or intermediate input into industrial manufacturing and construction activities. Furthermore, 

EPA does not believe that market gstigmah of CCR regulation under RCRA Subtitle C --- as alleged in numerous stakeholder letters to the EPA 

in 2009 --- will result in a reduction in future annual CCR beneficial use, because the proposed rule designates the Subtitle C option as a 

gspecial wasteh rather than as a ghazardous waste.h Summary Exhibit 3 below presents the results for both the increase scenario #1 and the 

decrease scenario #2. 

 

4

 The concept of gavoided disposal cost incentiveh is recognized and defined by the American Coal Ash Association (ACAA) on its website as follows: 

gIf a [coal-fired electric utility] plant markets its [CCR] into commercial applications, then disposal of this [CCR] is not required. Not only is a revenue stream 

created for the [coal-fired electricity plant] but also the need to dispose of the [CCR] is avoided. As discussed above, disposal is not just the transportation and 

placement of [CCR] in a disposal site. The need for future space is a concern. If [CCR is] marketed, then the need to develop future [CCR disposal] sites 

(including land acquisition, permitting, design and construction costs) is avoided .... It is not uncommon for a company to help offset the costs of transportation or 

placement at construction sites by providing the contractor or trucking firm a payment of some sort. For example, if the cost of disposal at a plant is normally four 

dollars a ton, then the company may arrange a payment of four dollars or less to the contractors to cover transportation and placement costs. The difference 

between the amount of this payment and the cost of disposal is also referred to as “avoided disposal costs.h Source: ACAA Frequently Asked Question nr. 14 

webpage at: http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=5#Q14 
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Summary Exhibit 3 

Induced Effect of RCRA Regulation of CCR Disposal on Future Annual CCR Beneficial Use 

($millions present value @7%) 

Scenarios Subtitle C 

special waste 

Subtitle D 

(version 2) Subtitle gD primeh 

Scenario #1: Induced Increase in CCR Beneficial Use 

Percentage increase relative to baseline CCR beneficial use +11% +4% +2% 

Economic market value +$5,560 +$2,224 +$890 

Lifecycle social value +$84,489 +$33,796 +$13,518 

Scenario #2: Induced Decrease in CCR Beneficial Use 

Percentage decrease relative to baseline CCR beneficial use -18% No impact No impact 

Economic market value -$18,744 No impact No impact 

Lifecycle social value -$233,549 No impact No impact 

ES-5: Regulatory Compliance Costs 

Chapter 4 of the RIA presents the estimated costs for industry compliance (and for government implementation) of each regulatory option. 

Summary Exhibit 4 below presents the estimated costs on a present value basis. The RIA presents three categories of regulatory compliance 

cost. These regulatory costs are incremental to an estimated $5,556 million per year average annual baseline (i.e., current) cost to the electric 

utility industry for CCR disposal, which represents a baseline cost of $76,678 million in present value on a 7% and 50-year discounting basis. 

Summary Exhibit 4 

Estimate of Regulatory Implementation & Compliance Cost 

($millions present value @7% over 50-years) 

Cost Category 

Subtitle C 

special waste 

Subtitle D 

(version 2) Subtitle gD primeh 

1. Engineering controls $6,780 $3,254 $3,254 

2. Ancillary costs $1,480 $5 $5 

3. Dry conversion cost $12,089 4,836 $0 

Total Cost (1+2+3) = $20,349 $8,095 $3,259 

Increase over baseline CCR disposal cost = +27% +11% +4% 

The dry conversion cost estimate incorporates projection of the recent (1995-2009) electric utility industry trend converting away from wet 

CCR disposal to dry CCR disposal. In fact, there are several upcoming EPA regulations which could accelerate this trend but are not reflected 

in the cost estimate of this RIA. These are anticipated rules under the Clean Air Act which will increase the installation of air pollution 

scrubbers and other air emission control technology at coal-fired power plants, as well as new wastewater effluent guidelines under the Clean 

Water Act which will require installation of treatment technology for wastewater discharges from CCR impoundments to surface waters. 
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ES-6: Comparison of Regulatory Benefits to Industry Compliance Costs 

The set of three Summary Exhibits 5, 6 and 7 below compare the estimated regulatory costs to estimated regulatory benefits, using gnet 

benefitsh and gbenefit-cost ratioh comparison indicators. The three Exhibits are based on the three alternative scenarios about the potential 

induced impact of the CCR rule on future annual CCR beneficial use as presented in Section 5C of this RIA (i.e., increase, decrease, and no 

change, respectively). All three Summary Exhibits below present costs, benefits, and net benefits on both a present value and average 

annualized equivalent basis, based on a 7% discount rate. A set of exhibits in Chapter 6 of this RIA present these values based on a 3% rate. 

Summary Exhibit 5 

Comparison of Regulatory Benefits to Costs 

Scenario #1 – Induced Increase in Future Annual CCR Beneficial Use 

($Millions @2009$ Prices and @7% Discount Rate over 50-Year Future Period-of-Analysis 2012 to 2061) 

Impact Element 

Subtitle C 

gSpecial Wasteh 

Subtitle D 

(version 2) Subtitle gD primeh 

A. Present Values: 

1. Regulatory Costs (1A+1B+1C): $20,349 $8,095 $3,259 

 1A. Engineering Controls $6,780 $3,254 $3,254 

 1B. Ancillary Regulatory Requirements $1,480 $5 $5 

 1C. Conversion to Dry CCR Disposal $12,089 $4,836 $0 

2. Regulatory Benefits (2A+2B+2C+2D): $87,221 to $102,191 $34,964 to $41,761 $14,111 to $17,501 

 2A. Monetized Value of Human Cancer Risks Avoided $504 (726 cancer risks) $207 (296 cancer risks) $104 (148 cancer risks) 

 2B.Groundwater Remediation Costs Avoided $466 $168 $84 

 2C. CCR Impoundment Failure Costs Avoided $1,762 to $16,732 $793 to $7,590 $405 to $3,795 

 2D. Induced Impact on Future CCR Beneficial Use $84,489 $33,796 $13,518 

3. Net Benefits (2 - 1) $66,872 to $81,842 $26,869 to $33,666 $10,852 to $14,242 

4. Benefit/Cost Ratio (2 / 1) 4.286 to 5.022 4.319 to 5.159 4.330 to 5.370 

B. Average Annualized Equivalent Values:* 

1. Regulatory Costs (1A+1B+1C) $1,474 $587 $236 

 1A. Engineering Controls $491 $236 $236 

 1B. Ancillary Regulatory Requirements $107 <$1 <$1 

 1C. Conversion to Dry CCR Disposal $876 $350 $0 

2. Regulatory Benefits (2A+2B+2C+2D): $6,320 to $7,405 $2,533 to $3,026 $1,023 to $1,268 

 2A.Monetized Value of Human Cancer Risks Avoided $37 $15 $8 

 2B. Groundwater Remediation Costs Avoided $34 $12 $6 

 2C. CCR Impoundment Failure Cleanup Costs Avoided $128 to $1,212 $58 to $550 $29 to $275 

 2D. Induced Impact on Future CCR Beneficial Use $6,122 $2,450 $980 

3. Net Benefits (2 - 1) $4,845 to $5,930 $1,947 to $2,439 $786 to $1,032 

4. Benefit/Cost Ratio (2 / 1) 4.286 to 5.022 4.319 to 5.159 4.330 to 5.370 

* Note: Average annualized equivalent values calculated by multiplying 50-year present values by a 50-year 7% discount rate gcapital recovery 

factorh of 0.07246. 
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Summary Exhibit 6 

Comparison of Regulatory Benefits to Costs 

Scenario #2 – Induced Decrease in Future Annual CCR Beneficial Use 

($Millions @2009$ Prices and @7% Discount Rate over 50-Year Future Period-of-Analysis 2012 to 2061) 

Impact Element 

Subtitle C 

gSpecial Wasteh 

Subtitle D 

(version 2) Subtitle gD primeh 

A. Present Values: 

1. Regulatory Costs (1A+1B+1C) $20,349 $8,095 $3,259 

 1A. Engineering Controls $6,780 $3,254 $3,254 

 1B. Ancillary Costs $1,480 $5 $5 

 1C. Conversion to Dry CCR Disposal $12,089 4,836 $0 

2. Regulatory Benefits (2A+2B+2C+2D): ($230,817) to ($215,847) $1168 to $7,965 $593 to $3,983 

 2A. Monetized Value of Human Cancer Risks Avoided $504 (726 cancer risks) $207 (296 cancer risks) $104 (148 cancer risks)

 2B. Groundwater Remediation Costs Avoided $466 $168 $84 

 2C. CCR Impoundment Failure Costs Avoided $1,762 to $16,732 $793 to $7,590 $405 to 3,795 

 2D. Induced Impact on CCR Beneficial Use ($233,549) $0 (no impact) $0 (no impact) 

3. Net Benefits (2-1) ($251,166) to ($236,196) ($6,927) to ($130) ($2,666) to $724 

4. Benefit/Cost Ration (2/1) (11.343) to (10.607) 0.144 to 0.984 0.182 to 1.222 

B. Average Annualized Equivalent Values:*

1. Regulatory Costs (1A+1B+1C) $1,474 $587 $236 

 1A. Engineering Controls $491 $236 $236 

 1B. Ancillary Costs $107 $0.36 $0.36 

 1C. Dry Conversion $876 $350 $0 

2. Regulatory Benefits (2A+2B+2C+2D): ($16,725) to ($15,640) $85 to $577 $43 to $289 

 2.A Monetized Value of Human Cancer Risks Avoided $37 $15 $8 

 2.B Groundwater Remediation Costs Avoided $34 $12 $6 

 2.C CCR Impoundment Failure Cleanup Costs Avoided $128 to $1,212 $57 to $550 $29 to $275 

 2.D Induced Impact on CCR Beneficial Use ($16,923) NA NA 

3. Net Benefits (2-1) ($18,199) to ($17,115) ($502) to ($9) ($193) to $52 

4. Benefit/Cost Ration (2/1) (11,347) to (10.610) 0.145 to 0.983 0.182 to 1.225 

* Note: Average annualized equivalent values calculated by multiplying 50-year present values by a 50-year 7% discount rate gcapital recovery 

factorh of 0.07246. 
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Summary Exhibit 7 

Comparison of Regulatory Benefits to Costs 

Scenario #3 – No Impact on Future Annual CCR Beneficial Use 

($Millions @2009$ Prices and @7% Discount Rate over 50-Year Future Period-of-Analysis 2012 to 2061) 

Impact Element 

Subtitle C 

gSpecial Wasteh 

Subtitle D 

(version 2) Subtitle gD primeh 

A. Present Values: 

1. Regulatory Costs (1A+1B+1C) $20,349 $8,095 $3,259 

 1A. Engineering Controls $6,780 $3,254 $3,254 

 1B. Ancillary Costs $1,480 $5 $5 

 1C. Conversion to Dry CCR Disposal $12,089 4,836 $0 

2. Regulatory Benefits (2A+2B+2C+2D): $2,732 to $17,702 $1168 to $7,965 $593 to $3,983 

 2A. Monetized Value of Human Cancer Risks Avoided $504 (726 cancer risks) $207 (296 cancer risks) $104 (148 cancer risks)

 2B. Groundwater Remediation Costs Avoided $466 $168 $84 

 2C. CCR Impoundment Failure Costs Avoided $1,762 to $16,732 $793 to $7,590 $405 to $3,795 

 2D. Induced Impact on CCR Beneficial Use $0 (no change) $0 (no change) $0 (no change) 

3. Net Benefits (2-1) ($17,617) to ($2,647) ($6,927) to ($130) ($2,666) to $724 

4. Benefit/Cost Ration (2/1) 0.134 to 0.870 0.144 to 0.984 0.182 to 1.222 

B. Average Annualized Equivalent Values:*

1. Regulatory Costs (1A+1B+1C) $1,474 $587 $236 

 1A. Engineering Controls $491 $236 $236 

 1B. Ancillary Costs $107 $0.36 $0.36 

 1C. Dry Conversion $876 $350 $0 

2. Regulatory Benefits (2A+2B+2C+2D): $198 to $1,283 $85 to $577 $43 to $289 

 2.A Monetized Value of Human Cancer Risks Avoided $37 $15 $8 

 2.B Groundwater Remediation Costs Avoided $34 $12 $6 

 2.C CCR Impoundment Failure Cleanup Costs Avoided $128 to $1,212 $57 to $550 $29 to $275 

 2D. Induced Impact on CCR Beneficial Use $0 $0 $0 

3. Net Benefits (2-1) ($1,277) to ($192) ($502) to ($9) ($193) to $52 

4. Benefit/Cost Ration (2/1) 0.134 to 0.870 0.145 to 0.983 0.182 to 1.225 

* Note: Average annualized equivalent values calculated by multiplying 50-year present values by a 50-year 7% discount rate gcapital recovery 

factorh of 0.07246. 
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Chapter 1 

Problem Statement: The Need for RCRA Regulation of CCR Disposal 

1A. Institutional Context 

For purpose of evaluating Federal regulations, the 1993 Executive Order 12866 gRegulatory Planning and Reviewh (Section 1(b)(1)) requires 

each Federal regulatory agency to identify the problem that it intends to address, including where applicable, the failures of private markets or 

public institutions that warrant new agency action, as well as to assess the significance of the problem. In line with this requirement, this 

Chapter provides a problem statement consisting of the institutional context (i.e., prior EPA actions), significance of the problem (i.e., evidence 

of environmental damages), and characterization of market failure. 

In September 2003, the White House Office of Management and Budget (OMB) updated its guidance to federal agencies on the development 

of regulatory analysis required under Section 6(a)(3)(c) of the 1993 Executive Order 128665 gRegulatory Planning and Review.h The updated 

guidance is OMB_s September 17, 2003 gCircular A-4 Regulatory Analysis.h6 Section A (Introduction) of Circular A-4 defines three key 

elements of good regulatory analysis: 

1. Statement of the need for the proposed regulation. 

2. Examination of alternative approaches. 

3. Evaluation of the benefits and costs (quantitative and qualitative) of the proposed regulation and the main alternatives. 

Concerning the first basic element listed above (i.e., statement of the need for regulation), Section B of Circular A-4 requires federal agencies 

to demonstrate that the proposed regulation is necessary. The Circular defines four categories of possible regulatory need: 

1. Required by law: If the need results from statutory or judicial directive, agencies should describe the: 

a. specific authority for the proposed regulation 

b. extent of discretion available to the agency 

c. regulatory instruments available 

2. Necessary to interpret law. 

3. Market failure: Three examples cited in Circular A-4 (pages 4 & 5) are: 

a. externality, common property resources and public goods 

b. non-competitive market power 

c. inadequate or asymmetric information 

4. Other social purposes: Six examples cited in Circular A-4 (page 5) are: 

a. make government operate more efficiently 

 

5

 1993 Executive Order 12866 (11 pages) is available at: http://www.whitehouse.gov/OMB/inforeg/eo12866.pdf 6

 2003 OMB Circular A-4 (48 pages) is available at: http://www.whitehouse.gov/OMB/Circulars/a004/a-4.pdf 
14 

b. redistribute resources to select groups 

c. prohibit discrimination 

d. protect privacy 

e. permit more personal freedom 

f. promote other democratic aspirations 

As explained below, EPA_s proposed RCRA7 regulation of coal combustion residual (CCR) disposal at coal-fired electricity plants is both 

required by law and will correct market failure. 

1B. EPA’s Proposed Regulation of CCR Disposal Is Required by Law

In 1976, Congress amended the 1965 Solid Waste Disposal Act (the first federal statute that specifically focused on improving solid waste 

disposal methods) by adding industrial hazardous waste management requirements as Subtitle C, among other new requirements. This 

amendment is the 1976 Resource Conservation & Recovery Act (RCRA). The EPA_s regulatory evaluation of coal combustion residues (CCR) 

dates back to 1978, two years after enactment of RCRA. In December 1978, the EPA proposed the first industrial hazardous waste regulations 

to implement Subtitle C (i.e., Sections 3001 to 3020 of RCRA). At that time, the EPA recognized that certain large-volume industrial wastes, 

including wastes from the combustion of fossil fuels (aka gCCRh as named in this RIA), might warrant special treatment under RCRA 

regulation. On 18 December 1978, EPA proposed but deferred and never finalized a relatively limited set of ten RCRA Subtitle C industrial 

hazardous waste regulations for the management of CCR.8 Included in this deferral of hazardous waste requirements were six categories of 

industrial wastes --- which EPA termed gspecial wastesh9 --- until further study and assessment could be completed by EPA to determine their 

risk to human health and the environment. The six categories of special wastes included: 

1. Cement kiln dust 

2. Mining waste 

3. Oil and gas drilling muds and oil production brines 

4. Phosphate rock mining, beneficiation, and processing waste 

5. Uranium waste 

6. Utility waste (i.e., fossil fuel combustion waste by electric utility plants) 

These wastes typically are generated in large volumes and, at the time, were believed to possess less risk to human health and the environment 

than the wastes being identified for regulation as RCRA hazardous waste. On 12 October 1980, Congress enacted the Solid Waste Disposal 

Act Amendments of 1980 (Public Law 96-482) which amended RCRA in several ways. Pertinent to gspecial wastesh were the Bentsen and 

 

7

 RCRA = Resource Conservation & Recovery Act of 1976: http://www.epa.gov/waste/laws-regs/rcrahistory.htm 8

 Federal Register, Vol. 43, No. 243, 18 December 1978, page 59015, section 250.46-2 gUtility Wasteh of gHazardous Waste Guidelines and Regulations.h This action 

proposed the following ten regulatory conditions: (a) waste analysis standards, (b) waste site selection standards, (c) waste site security, (d) waste shipment manifesting, (e) 

recordkeeping, (f) reporting, (g) waste site visual inspections, (h) waste site closure, (i) waste site post-closure care, and (j) groundwater monitoring. 9

 To learn more about these six gspecial wastesh see EPA_s special waste website at http://www.epa.gov/osw/nonhaz/industrial/special/index.htm 
15 

Bevill Amendments10 which exempted gspecial wastesh from regulation under Subtitle C of RCRA until further study and assessment of risk 

could be performed: 

x 1980 Bentsen Amendment (RCRA 3001(b)(2)(A)): Exempted drilling fluids, produced waters, and other wastes associated with the 

exploration, development, and production of crude oil or natural gas or geothermal energy. 

x 1980 Bevill Amendment (RCRA 3001(b)(3)(A)(i-iii)): Exempted fossil fuel combustion waste; waste from the extraction, beneficiation, 

and processing of ores and minerals (including phosphate rock and overburden from uranium ore mining); and cement kiln dust. 

The Bevill and Bentsen Amendments required EPA to complete full assessments of each exempted waste and submit a formal report to 

Congress on its findings. As itemized in Appendix A to this RIA, since 1978, EPA continued to evaluate CCR (as well as the other five waste 

categories) for different possible RCRA hazardous and non-hazardous waste regulatory approaches. The proposed RCRA regulation this RIA 

supports is a continuation of those prior evaluations. 

1C. EPA’s Proposed Regulation of CCR Disposal Will Correct Market Failure

OMB_s 2003 Circular A-4 gRegulatory Analysish guidance (pages 4 to 5) to Federal agencies for implementation of Executive Order 12866 

identifies three major types of market failure: 

1. Externality, common property resource, and public good 

2. Market power (i.e., lack of market competition from monopolies) 

3. Inadequate or asymmetric information 

The CCR proposed rule which this RIA supports may be characterized as addressing the gnegative externalityh of environmental pollution and 

damages from CCR disposal landfills and impoundments. As summarized in the gBenefitsh Chapter 5 of this RIA, there are a number of 

historical and recent environmental damage cases which represent externalities, in that some or all of the (a) human health damages (i.e., 

human cancer cases from contaminated groundwater near CCR disposal sites) and (b) environmental damages (i.e., ecological damages, natural 

resource damages, and socio-economic damages from CCR spills/releases from structural failures in CCR disposal impoundments) may be 

external to the capital and operating costs of the electric utility plants. If implemented, the CCR proposed rule may be expected to reduce this 

market failure externality, by internalizing into the capital and operating costs of the electric utility plants, the added costs of installing 

engineering controls and oversight of the physical integrity of CCR disposal units. 

Firms are sometimes held accountable for some of the external costs through lawsuits brought by affected citizens. However, the system of 

accountability can be imperfect. The primary human bearers of the external costs from CCR disposal are households residing disposal units. 

When an unorganized group of households suffer external costs, they face a host of obstacles to having their costs recuperated. They must 

 

10 These 1980 RCRA gspecial wasteh amendments are named after US Senator Lloyd Bentsen (D-TX; Senate service years 1971-1993) and US House Congressman Tom 

Bevill (D-AL; House service years 1967-1997). Source: Biographical Directory of the US Congress at http://bioguide.congress.gov/biosearch/biosearch.asp 
16 

form a coherent organization and they must have enough funding to launch and maintain a lawsuit. On the other side of such litigation, 

households usually face a single firm often with greater legal funding resources. This imbalance suggests that external costs of leachate 

contamination from industrial waste disposal sites (such as CCR landfills and impoundments) may not be recuperated. 

The CCR proposed rule also addresses a second source of market failure v inadequate or asymmetric information. Citizens residing near CCR 

disposal sites may be unaware of exposure to chemical contaminants contained in CCR leaching from disposal units. Thus, while nearby 

citizens may have the right to legal lawsuits to recuperate health and property damages, citizens may not be aware of the need to do so until 

health risks (and health costs) have already been incurred. 

A very recent example of negative externalities associated with structural failures is the ecological and socio-economic damages and costs 

associated with a large environmental disaster involving the collapse of a CCR impoundment in 2008. On 22 December 2008, over a billion 

gallons (i.e., 5.4 million cubic yards) of CCR was unintentional environmental released over 300 acres from the collapse of a Tennessee Valley 

Authority (TVA) coal-fired electric utility surface impoundment in Kingston TN. This event caused significant damage to 40 homes, the 

Emory River, a nearby recreational lake, community roadways, a gas pipeline, and a railroad. As indicated in Exhibit 5B-2 of this RIA, the 

estimated cleanup costs to the TVA --- not including social costs of ecological damages and community socio-economic damages --- are 

estimated at $933 million to $1.2 billion. This event attracted major citizen, national press, and Congressional interest in the subject of CCR 

management and the urgent need for prevention of such future environmental and community damages. In the wake of this disaster, during her 

14 January 2009 Senate confirmation hearing, EPA Administrator-designate Lisa P. Jackson, testified11: 

gI think that you’ve put your finger on a very important thing that EPA must do right away, which is to assess the hundreds 

of other sites that are out there. Many of them ... are ... up hill from schools or from areas where just the physical hazard 

of having this mountain of wet coal ash, if there’s a break, can endanger lives immediately. So I would think that EPA needs 

to first and foremost assess the current state of what’s out here and where there might be another horrible accident waiting 

to happen ... EPA currently has and has in the past, assessed its regulatory options with respect to coal ash, and I think it’s 

time to re-ask those questions and re-look at the state of regulation of them from an EPA perspective.h 

According to a 23 January 2009 news report,12 there was growing Congressional interest for either the EPA with its existing RCRA regulatory 

authorities, or the Congress with potential new legislation, to regulate CCR disposal units: 

gSeveral lawmakers have introduced, or announced plans to introduce, competing legislation to regulate CCR. For example, 

Senate Environment & Public Works Committee Chairwoman Barbara Boxer (D-CA) said she would introduce legislation 

compelling EPA to regulate CCR in the event the Obama EPA fails to act soon. "If we are not satisfied with action we may 

move legislatively," Boxer told EPA Administrator-designate Lisa Jackson at a January 14 [2009] confirmation hearing. "I 

don't want to get to that point because I think you have the authority to regulate this. It needs to be done."h 

 

11 Lisa Jackson_s 14 January 2009 Senate confirmation hearing testimony and webcast is available from the US Senate Committee on Environment and Public Works_ 

website at: http://epw.senate.gov/public/index.cfm?FuseAction=Hearings.Hearing&Hearing_ID=ae2c3342-802a-23ad-4788-d1962403eb76 12 Source: Waste Business Journal, gEPA Vows to Act on Coal Waste,h 23 January 2009, http://www.wastebusinessjournal.com/news/wbj20090127B.htm 
17 

Just three weeks after the TVA_s Kingston TN CCR impoundment disaster, House Natural Resources Committee Chairman Nick Rahall (DWV) introduced legislation requiring federal standards to regulate the engineering of CCR impoundments.13 Introduced on 14 January 2009, 

the Coal Ash Reclamation and Environmental Safety Act of 2009 (H.R. 493) directs the Department of Interior to impose uniform federal 

design, engineering, and performance standards on CCR impoundments to avoid a repeat of the damage done in Kingston TN. The legislation, 

which requires minimum design and stability standards for all surface impoundments constructed to hold coal ash, draws on the regulatory 

model for impoundments that is used for coal slurry management under the Surface Mining Control and Reclamation Act of 1977 (SMCRA). 

In a letter dated 02 March 2009, the Environmental Integrity Project and Earthjustice, joined by the National Resources Defense Council, the 

Sierra Club, Environmental Defense, and 104 other environmental groups requested EPA Administrator Lisa Jackson gto act as soon as 

possibleh to regulate CCR. A letter signed by the groups and delivered to EPA on 03 March 2009 identified 12 principles to guide the 

development of EPA standards. These include the phase-out of CCR surface impoundments, locating CCR disposal sites away from 

groundwater or surface water, requiring liners, leachate collection systems and adequate monitoring, and requiring industry to assume long 

term liability for cleanup: 

gThe recent disaster at TVA's Kingston Plant stands as a startling reminder that federal standards for CCR are long 

overdue. For too long, power companies have been able to dump CCR, laden with a host of toxic metals like arsenic, 

selenium, lead, mercury, and boron, in unlined mines, quarries, landfills, and surface impoundments. Without 

federal standards governing disposal practices, contaminants can leak or spill from these dump sites, threatening 

human health, natural resources and wildlife.h14

On 04 March 2009, US Senators Barbara Boxer (D-CA) and Tom Carper (D-DE) submitted Senate Resolution 64 to the Senate Committee on 

Environment and Public Works. This resolution calls on the EPA to gimmediatelyh inspect all CCR impoundments and landfills operating at 

coal-fired electricity plants, and to propose and finalize gas quickly as possibleh rules to regulate CCR under RCRA.15

 

13 The text of the 14 January 2009 H.R. 493 bill is available at: http://www.govtrack.us/congress/billtext.xpd?bill=h111-493 14 Source: http://www.environmentalintegrity.org/pub608.cfm 

15 US Senate Resolution 64 is available at: http://www.govtrack.us/congress/bill.xpd?bill=sr111-64&tab=committees 
18 

Chapter 2 

Potentially Affected Industries & RCRA Regulatory Options 

2A. Identity of Potentially Affected Industries 

There are two categories of industries which may be directly affected by the CCR regulatory options. gDirectly affected entitiesh are 

entities potentially subject to any of the rule_s requirements.16 In addition, there are 14 or more industries which beneficially use CCR. 

1. Coal-Fired Electric Utility Industry 

The scope of industrial plants directly affected by the regulatory options is classifiable according to at least two different glossary systems: 

x Classification #1 of 2: The scope of industrial plants is classifiable as gcoal-fired electric utility plantsh under the US Census Bureau_s 

North American Industrial Classification Systemh NAICS code 22 gUtilitiesh economic sector, and in that sector, as a subgroup of the 

1,245 establishments within the NAICS 221112 gFossil Fuel Electric Power Generationh industry:17

NAICS 221112: This industry comprises establishments primarily engaged in operating fossil fuel powered electric power 

generation facilities. These facilities use fossil fuels, such as coal, oil, or gas, in internal combustion or 

combustion turbine conventional steam process to produce electric energy. The electric energy produced in 

these establishments is provided to electric power transmission systems or to electric power distribution 

systems. 

x Classification #2 of 2: The scope of industrial plants is classifiable as gelectric utilities plus independent power producersh under the 

Energy Information Administration (EIA) categorization system for its coal combustion electric power sector statistics:18

Electric utility: Any entity that generates, transmits, or distributes electricity and recovers the cost of its generation, transmission or 

distribution assets and operations, either directly or indirectly, through cost-based rates set by a separate regulatory 

authority (e.g., State Public Service Commission), or is owned by a governmental unit or the consumers that the 

entity serves. Examples of these entities include: investor-owned entities, public power districts, public utility 

districts, municipalities, rural electric cooperatives, and State and Federal agencies.

Independent power A corporation, person, agency, authority, or other legal entity or instrumentality that owns or operates

producer: facilities for the generation of electricity for use primarily by the public, and that is not an electric utility. 

 

16 Source: gEPA_s Action Development Process: Final Guidance for EPA Rulewriters: Regulatory Flexibility Acth, OPEI Regulatory Development Series, Nov 2006, see 

footnote 14 at http://www.epa.gov/sbrefa/documents/rfafinalguidance06.pdf 17 Source: NAICS codes are defined at http://www.census.gov/cgi-bin/sssd/naics/naicsrch?chart=2007 18 Source: EIA glossary of terms at http://www.eia.doe.gov/glossary/index.html 
19 

2. Waste & Environmental Management Services Industries 

In addition, because some electric utility plants transport their CCR to either company-owned or to commercial offsite landfills, and because 

some regulatory options may trigger RCRA facility-wide corrective action, the regulatory options of the proposed rule may also affect: 

NAICS 562211: Hazardous waste treatment and disposal industry (may be affected under the RCRA Subtitle C regulatory 

options evaluated in this RIA). 

NAICS 562212: Solid waste landfill industry (may represent baseline offsite CCR landfills to which the estimated 149 of the 

495 electric utility plants may transport some or all of the 15 million tons per year CCR for offsite disposal). 

NAICS 562219: Other non-hazardous waste treatment and disposal industry (may represent baseline offsite CCR landfills to 

which some or all of 149 of the 495 electric utility plants may transport some or all of the 15 million tons per 

year CCR for offsite disposal). 

NAICS 562910: Environmental cleanup/remediation services industry. 

3. Industries Which “Beneficially Use” CCR 

According to the American Coal Ash Association (ACAA)19 as of 2007 there are over 15 industries which gbeneficially useh CCR for 

industrial applications. These industrial applications are listed below with corresponding NAICS20 codes estimated by EPA ORCR. Because 

the regulatory options evaluated in this RIA establish CCR disposal requirements, industries which beneficially use CCR are characterized in 

this RIA as potentially gindirectlyh affected by the proposed rule rather than gdirectlyh affected (i.e., subject to the rule_s requirements). 

1. Concrete/concrete products/grout NAICS 3273 Cement & Concrete Product Manufacturing 

2. Blended cement/raw feed for clinker NAICS 3273 Cement & Concrete Product Manufacturing 

3. Flowable fill NAICS 23 Construction 

4. Structural fills/embankments NAICS 23 Construction 

5. Road base/sub-base NAICS 237310 Highway, Street & Bridge Construction 

6. Soil modification/stabilization NAICS 23 Construction 

7. Mineral filler in asphalt NAICS 324121 Asphalt Paving Mixture & Block Manufacturing 

8. Snow and ice control NAICS 488490 Other Support Activities for Road Transportation 

9. Blasting grit/ 

 Roofing granules 

NAICS 212319 Other Crushed & Broken Stone Mining & Quarrying 

NAICS 324122 Asphalt Shingle & Coating Materials Manufacturing 

10. Mining applications NAICS 212 Mining 

 

19 Source: American Coal Ash Association (ACAA) g2007 Coal Combustion Product (CCP) Production & Use Survey Results (Revised)h at http://www.acaausa.org/associations/8003/files/2007_ACAA_CCP_Survey_Report_Form%2809-15-08%29.pdf 

20 NAICS = North American Industrial Classification System; NAICS codes definitions are available at http://www.census.gov/cgi-bin/sssd/naics/naicsrch?chart=2007

x 2-digit codes represent economic sectors 

x 3-digit codes represent economic sub-sectors 

x 4-digit codes represent industry groups 

x 5-digit and 6-digit codes represent single industries 
20 

11. Gypsum panel products (e.g., wallboard) NAICS 327420 Gypsum Product Manufacturing 

12. Waste stabilization/solidification NAICS 5622 Waste Treatment & Disposal 

13. Agriculture NAICS 111 Crop Production 

14. Aggregate NAICS 23 Construction 

15. Miscellaneous/other (unidentified industries) NAICS not identified 

2B. Other Industries with CCR Disposal Units Not Covered by the Proposed Rule 

The scope of the proposed rule excludes two other categories of CCR disposal units from the regulatory options. These other two categories 

are identified here to provide a rough estimate of potential additional cost for regulation if they were added to the scope of the rulemaking or 

addressed in a separate but similar rulemaking. 

x Inactive/Abandoned CCR Disposal Units Excluded from Scope 

The scope of the proposed rule only covers active (i.e., operating) CCR disposal units used by electric utility plants. There are two other 

operating status categories consisting of an estimated count of at least 197 additional CCR disposal units excluded from the scope of the rule:21

x Inactive units: CCR impoundments and landfills not in operation or not receiving CCR. Inactive impoundments may receive CCR in

the future, becoming active again, and therefore have not been closed permanently. 

x Abandoned units: CCR impoundments and landfills not in operation and closed. These impoundments usually have been filled to 

capacity and have been permanently closed. 

In absence of inventory data on inactive units, the nationwide count of such inactive and abandoned units is indirectly and roughly estimated in 

this RIA based on known data for large volume coal mining slurry waste impoundments. There are an estimated 1,600 coal waste 

impoundments in operation across the US in coal-related industries (i.e., coal mining industry plus industries which burn coal). In addition, 

there are another 670 coal waste impoundments which are no longer in operation but still contain coal waste slurry (i.e., inactive or 

abandoned).22 These two counts represent a ratio of 0.42 inactive/abandoned:to:active (i.e., 670:to:1,600). 

In absence of national survey data, multiplying the 0.42 inactive:to:active coal waste impoundments ratio by the 158 coal-fired electric utility 

plants estimated in this RIA using CCR impoundments, yields an estimate of at least 66 inactive/abandoned CCR impoundments may be 

located at electric utility plants (i.e., (158 impoundment using electric utility plants) x (0.42 ratio) = 66). 

 

21 Source: Definitions of ginactiveh and gabandonedh coal waste impoundments from page 23 of the National Research Council book Coal Waste Impoundments: Risks, 

Responses and Alternatives, National Academy Press, 2002 at http://www.nap.edu/openbook.php?isbn=030908251X 22 Source: Counts of 1,600 active coal waste impoundments and 670 inactive or abandoned coal waste impoundments from the prior footnoted source. 
21 

This RIA did not discover similar data for coal waste landfills in active and inactive/abandoned status. For purpose of a rough estimate in this 

RIA, multiplying the 0.42 inactive/abandoned:to:active ratio by the 311 electric utility plants which use landfills, indicates there may be at least 

131 inactive or abandoned CCR landfills at or near electric utility plants (i.e., (311 landfill using electric utility plants) x (0.42 ratio) = 131). 

As of 2004, the Mine Safety & Health Administration (MSHA) oversees 646 active coal mining slurry impoundments in the US, which implies 

954 remainder active coal slurry impoundments (i.e., 1,600 v 646 = 954).23 Of these, this RIA estimates at least 158 active impoundments at 

158 electric utility plants, which implies that a fraction of 796 other active coal waste impoundments (i.e., 954 v 158 = 796) may be located at 

electric power plants in non-utility industries (see the next sub-section below gOther Industries Excluded from Scopeh). 

x Other Industries Excluded from Scope 

The scope of the proposed rule only includes NAICS code 22 coal-fired electric utility plants (495 plants). However, there is a range of 139 to 

759 non-utility facilities which currently, or have the capacity to, burn coal and thus generate CCR. Adding these facilities to the scope of the 

proposed rule could increase the cost estimates by 2% to 28%. This range is based on the following two data sources: 

Source #1: As displayed below in Exhibit 2A based on 2005 data from the DOE-EIA, there are 139 non-utility coal-fired electricity plants 

owned and operated by 8 other industrial sub-sectors involving 27 industries. Appendix B of this RIA contains a list of these 

other industry plants according to NAICS industry codes. If these other non-utility industries were to be added to the scope of 

the CCR proposed rule, a rough estimate of potential additional cost and benefit impacts would be between 2% and 28% relative 

to the impacts estimated in this RIA: 

x >2%: Compared to the 369,183 megawatts (MW) nameplate capacity for the coal-fired electricity plants contained in 

the 2005 DOE-EIA database (which contains data on electricity plants at least 10 MW nameplate capacity in 

size), the 5,959 MW capacity of the 139 non-utility electricity plants represents about 2% of national coal-fired 

electricity generation capacity. For purpose of rough estimation v in so far that electricity plant capacity 

correlates to annual CCR generation and thus to annual CCR disposal costs and to regulatory costs --- this 

percentage indicates that the additional economic impact of including these additional 139 non-utility plants in 

the proposed rule might add at least 2% to the cost estimates under each regulatory option. 

x <28%: On the other hand, some CCR disposal costs and regulatory costs better correlate to the count and size (footprint) 

of CCR landfills and impoundments, not to electricity generating capacity. For such costs, adding the 139 nonutility plants to the scope of the proposed rule could increase the cost estimates for each regulatory option by up 

to 28% (i.e., (495 + 139) / (495)). 

 

23 Source: MSHA gSupporting Statementh for Information Collection Request (ICR) 1219-0015 gRefuse Piles and Impoundment Structures, Recordkeeping and Reporting 

Requirementsh, March 2008: http://www.msha.gov/regs/fedreg/paperwork/2004/04-24046.pdf 
22 

Source #2: EPA_s 2002 analysis24 of the results from a 2001 survey of non-utility CCR generation identified 759 non-utility facilities gwith 

the capacity to burn coal, and therefore, generate CCR.h The estimated annual CCR generation for these facilities is 7.8 million 

tons (as of year 2000), which is 5.5% to 6.3% of the 123.1 million to 141.2 million tons CCR generated by electric utility plants 

in 2005 as estimated in Exhibit 3D of this RIA. Allowing for annual growth of the 7.8 million tons since 2000 suggests that 

adding these 759 facilities to the scope of the proposed rule could increase the cost estimates by 7%.

 

24 Source: gAnalysis of Non-Utility Coal Combustion Waste Generation and Management Based on the 2001 CIBO Voluntary Survey,h prepared for EPA-OSWER by 

Science Applications International Corp (SAIC) Engineering & Environmental Management Group (Reston VA) under subcontract to Eastern Research Group (Arlington 

VA), April 2002, EPA contract No. 68-W-02-036, WA 12:. 
23 

Exhibit 2A 

Identity of Other Industries Operating Coal-Fired Electricity Plants Not Covered by the Proposed Rule or this RIA

2005 

Count 

NAICS 

Sector 

NAICS 

Industry NAICS Industry Code Definition 

2005 

Boiler count 

2005 

Plant count 

1 21 2122 Ore mining 4 1 

2 31 311 Food Manufacturing 63 29 

3 31 3122 Tobacco Manufacturing 3 2 

4 31 314 Textile Product Mills 11 4 

5 32 321 Wood Product Manufacturing 1 1 

6 32 322 Paper Manufacturing 9 4 

7 32 322122 Newsprint Mills 98 39 

8 32 32213 Paperboard Mills 19 9 

9 32 325 Chemical Manufacturing 31 6 

10 32 325188 All Other Basic Inorganic Chemical Manufacturing 5 3 

11 32 325211 Plastics Material and Resin Manufacturing 9 4 

12 32 326 Plastics and Rubber Products Manufacturing 4 1 

13 32 327 Nonmetallic Mineral Product Manufacturing 8 3 

14 32 32731 Cement Manufacturing 2 1 

15 33 331 Primary Metal Manufacturing 5 3 

16 33 331111 Iron and Steel Mills 1 1 

17 33 331312 Primary Aluminum Production 3 1 

18 33 333 Machinery Manufacturing 7 2 

19 33 3345 Navigational, Measuring, Electromedical, Control Instruments Mfg 10 1 

20 33 336 Transportation Equipment Manufacturing 1 1 

21 33 337 Furniture and Related Product Manufacturing 1 1 

22 33 339 Miscellaneous Manufacturing 1 1 

23 48 482 Rail Transportation 2 1 

24 48 483 Water Transportation 3 1 

25 61 611 Educational Services 37 14 

26 62 624 Social Assistance 2 1 

27 92 92 Public Administration 14 4 

 Count = 8 Count = 27 Column Totals = 354 139 

2005 electricity generation nameplate capacity (megawatts) = 5,959 

Notes: 

(a) Source: US Dept of Energy, Energy Information Administration (EIA), 2005 Form EIA-860 "Annual Electric Generator Report" 

"Existing Electric Generating Units in the United States, 2005" at http://www.eia.doe.gov/cneaf/electricity/epa/epat2p2.html

(b) NAICS codes: The first two digits designate the economic sector, the third digit designates the subsector, the fourth digit designates the industry 

group, the fifth digit designates the NAICS industry, and the sixth digit designates the national industry. The five-digit NAICS code is the level at 

which there is comparability in code and definitions for most of the NAICS sectors across the three countries participating in NAICS (the United 

States, Canada, and Mexico). The six-digit level allows for the United States, Canada, and Mexico each to have country-specific detail. A complete 

and valid NAICS code contains six digits. Source: http://www.census.gov/eos/www/naics/faqs/faqs.html#q5 
24 

2C. RCRA Regulatory Options Evaluated in this RIA 

This RIA evaluates three RCRA regulatory options which are defined with reference to the two alternative regulatory authorities --- Subtitle C 

and Subtitle D --- contained in EPA_s 1976 RCRA waste management statutory authority: 

Option 1: RCRA Subtitle C gspecial wasteh: 

x Regulate CCR disposed in landfills and surface impoundments as gspecial wastesh under Subtitle C, and require 

phase out of surface impoundments within five years. This approach: 

x Eliminates health risks from groundwater and surface water contamination for both landfills and surface 

impoundments, and avoids damages from uncontrolled ground gfillh operations (e.g., Gambrills MD and 

Chesapeake VA) and attendant environmental remediation costs. 

x Eliminates the future threat of catastrophic failures of surface impoundments. 

x Provides for corrective action, including at closed units at facilities with surface impoundments or landfills 

regulated under the rule, and imposes groundwater monitoring requirements. 

x Provides for Federal oversight, which EPA experience has shown is necessary for successful implementation of 

RCRA industrial waste regulations, especially as it relates to ground-water monitoring and corrective action, 

when needed. Without Federal oversight, it is highly questionable whether CCR will be properly managed, 

considering EPA_s experience with the RCRA program of the last 10 years, which illustrate the limited results 

that could be expected of a Subtitle D rule. 

Option 2: RCRA Subtitle D gnon-hazardoush industrial waste (version 2): 

x Liners required for all (i.e., existing and future new) CCR surface impoundments but only for new landfills. 

Subtitle D requirements would set national criteria for landfills and surface impoundments that manage CCR 

after the rule goes into effect. For any CCR landfills and impoundments that closed before the effective date, 

there would be no regulatory controls over those units, unless the states choose to adopt controls over such units. 

Also, all surface impoundments (existing and new) would need to have composite liners within 5-years of the 

effective date. Consistent with the Subtitle C approach, existing landfills would not need to be lined. 

x Requirements would not be enforceable by EPA or the states (unless states had similar requirements under state 

law). Lack of enforcement and Federal oversight may significantly reduce compliance and effective 

implementation of regulatory requirements. 

x Although this option does not require phase-out of existing surface impoundments, it could cause some phase-out 

because all surface impoundments would need to have composite liners by a certain date, or they would need to 

close down, assuming the rule is effectively implemented by the states. 

x Eliminates some ground-water contamination over the current situation (e.g., because of surface impoundment 

retrofitting), thus avoiding some damage cases, again assuming effective implementation. 
25 

x Require review of surface impoundments for stability by independent experts, but because impoundments could 

remain in operation (because they are currently lined or owners choose to retrofit line them rather than phase 

them out), there would still be a risk of future structural failures of impoundments. 

Option 3: RCRA Subtitle gD primeh: 

x Regulation of disposal under subtitle D, with liners required only for new surface impoundments and landfills. This 

approach would be the same as the subtitle D approach above, except that existing surface impoundments would not 

be required to retrofit and install a composite liner, or close. Unlined existing impoundments could continue to 

operate, but new landfills and surface impoundments or expansions of existing landfills must have composite liners. 

x Under this approach the potential for catastrophic failure of surface impoundments would remain significant, since 

phase-out of surface impoundments wouldn_t occur. 

x Would be less effective than the subtitle C or subtitle D approaches in eliminating groundwater contamination (or in 

having it be discovered sooner), but would still provide some benefits over no national regulation. (The same caveats 

on state regulations and enforcement would apply as in the subtitle D option.) 

x Would reduce regulatory costs significantly since conversion to dry disposal would not be required, but would also 

provide fewer benefits. 

Evaluation of three regulatory options is consistent with OMB_s 2003 gCircular A-4: Regulatory Analysish best practices guidance for Federal 

agencies, which requires analysis of at least three regulatory options.25 All three regulatory options are identical in two ways: 

1. Beneficial use: All options propose to replace the 1980 RCRA gBevill exclusionh under 40 CFR 261.4(b)(4) for CCR disposal with new 

RCRA waste regulation, but to retain the existing Bevill exclusion for CCR beneficial uses. Beneficial uses of CCR will retain the 

Bevill exclusion and will not be subject to any regulation, either under Subtitle C or Subtitle D. 

2. Engineering controls: All options propose the same set of 10 custom-tailored engineering controls (i.e., technical design and 

operating standards) for CCR disposal units. For purpose of launching this RIA in April 2009, the waste disposal gmanagement 

standardsh described in EPA_s August 1999 cement kiln dust (CKD) proposed rule26 were used in absence of uniquely defined controls 

specific to CCR disposal units. This was a reasonable starting point because the CKD management standards are similar or identical to 

the technical standards defined in the CCR proposed rule. 

 

25 OMB_s 2003 Circular A-4 (p.16) directs Federal agencies to analyze at least three regulatory options: http://www.whitehouse.gov/omb/assets/omb/circulars/a004/a-4.pdf 26 EPA_s 20 August 1999 CKD proposed rule (Federal Register, 67 pages). 
26 

During EPA_s April 2009 launch of this RIA, EPA defined three other RCRA options which are very similar to the above three options. The 

initial set of options is included in EPA_s October, 8 2009 initial draft (165 pages) of this RIA which EPA submitted to OMB for review in 

mid-October 2009. The regulatory cost estimation in Chapter 4 and the supplemental analyses in Chapter 7 of this RIA are based on the 

initial set of three options, defined as follows: 

2009 Option 1: RCRA Subtitle C ghazardoush industrial waste: 

x Subtitle C provides Federal enforceability. 

x RCRA Section 3004(x)27custom-tailor engineering controls (i.e., technical standards) for CCR disposal units. 

x Subject CCR to Subtitle C land disposal restriction (LDR) treatment standards prior to disposal: 

x Dry CCR (landfills): Moisture conditioning and compaction to attain 95% dry density value. 

x Wet CCR (impoundments): Dewatering and dry disposal within 5 years after rule_s effective date. 

2009 Option 2: RCRA Subtitle D gnon-hazardoush industrial waste (version 1): 

x This option is different from the 2010 Option 2: Subtitle D option because it does not require liners for existing 

impoundments as the 2010 Option 2 does, but it only requires liners for new impoundments (and only for new 

landfills). 

x Regulate CCR disposal as RCRA Subtitle D non-hazardous waste based on the same custom-tailored engineering 

controls as the 2009 Option 1. 

x Except under RCRA Section 7003 gimminent and substantial endangermenth authority, this option is not Federally 

enforceable because RCRA Subtitle D directs EPA only to assist state government waste management programs.28

2009 Option 3: Hybrid RCRA Subtitle C & Subtitle D: 

x Subtitle C regulation of CCR impoundments (same as the 2009 Option 1) 

x Subtitle D regulation of CCR landfills (same as the 2009 Option 2) 

 

27 The following excerpt from RCRA Section 3004(x) pertains specifically to CCR, by providing EPA with authority gto modifyh the RCRA Subtitle C technical standards 

for regulation of CCR disposal: 

gSection 3004(x): If... (2) fly ash waste, bottom ash waste, slag waste, and flue gas emission control waste generated primarily from the combustion of coal or 

other fossil fuels... is subject to regulation under this subtitle, the [EPA] Administrator is authorized to modify the requirements of subsections (c), (d), (e), (f), (g), 

(o) and (u) and section 3005(j), in the case of landfills or surface impoundments receiving such solid waste, to take into account the special characteristics of such 

wastes, the practical difficulties associated with implementation of such requirements, and site-specific characteristics, including but not limited to the climate, 

geology, hydrology and soil chemistry at the site, so long as such modified requirements assure protection of human health and the environment.h 28 Section 4001 of Subtitle D of the 1976 RCRA statute prescribes the Federal role under Subtitle D as assistance to state governments: gThe objectives of this subtitle are 

to assist in developing and encouraging methods for the disposal of solid waste... Such objectives are to be accomplished through Federal technical and financial 

assistance to States or regional authorities for comprehensive planning pursuant to Federal guidelines designed to foster cooperation among Federal, State and local 

governments and private industry.h 
27 

Chapter 3 

Baseline CCR Management in the Electric Utility Industry 

This Chapter characterizes baseline (i.e., current) CCR management practices within the electric utility industry. This baseline consists of two 

components described in this Chapter: CCR disposal and CCR beneficial use. This Chapter begins with a description of baseline CCR 

management quantities (i.e., annual tonnages of CCR) and CCR disposal methods used by the electric utility industry. This Chapter also 

presents an evaluation of baseline operating conditions (i.e., gengineering controlsh and gancillary costsh) of CCR disposal units and an 

estimate of the associated costs to the electric utility industry. This Chapter concludes with a characterization of baseline CCR gbeneficial useh 

(for CCR which is not disposed) and an estimate of associated net benefits to the environment and the national economy. 

3A. Identity of Coal-Fired Electric Utility Plants 

This RIA initially identified the sub-group of potentially affected coal-fired electric utility plants using the 2007 US Department of Energy 

(DOE), Energy Information Agency (EIA) database for electricity power plants from the Form EIA-860 "Annual Electric Generator Report.h 

This data was supplemented with the master list of utility plants from the 2007 EIA-860 database entitled gexistingunits2007h. 29 This RIA 

applied three database filters to identify the subset of electricity plants which may potentially be affected by the proposed rule: 

x Database filter #1 of 3: EPA sorted the 2007 EIA-860 electric plant database by the North American Industry Classification 

System (NAICS) industrial codes, and deleted all plants not assigned utility sector NAICS code 22 (only 2-digit NAICS 

codes are provided by the EIA database). 

NAICS 22: The Utilities sector comprises establishments engaged in the provision of the following utility services: 

electric power, natural gas, steam supply, water supply, and sewage removal. Within this sector, the specific 

activities associated with the utility services provided vary by utility: electric power includes generation, 

transmission, and distribution; natural gas includes distribution; steam supply includes provision and/or 

distribution; water supply includes treatment and distribution; and sewage removal includes collection, 

treatment, and disposal of waste through sewer systems and sewage treatment facilities. Excluded from this 

sector are establishments primarily engaged in waste management services classified in Subsector 562 Waste 

Management and Remediation Services. These establishments also collect, treat, and dispose of waste 

 

29 The EIA-860 database is itemized on an electricity generator unit basis, not on a per-plant basis. It includes specific information about generators at electric power plants 

owned and operated by electric utilities and non-utility industries (i.e., including independent power producers, combined heat and power producers, and other industrials). 

The file contains generator-specific information such as initial date of commercial operation, prime movers, generating capacity, energy sources, status of existing and 

proposed generators, proposed changes to existing generators, county and State location (including power plant address), ownership, and FERC qualifying facility status. 

Also included are data related to the ability to use multiple fuels; specifically, data on co-firing and fuel switching are included. The DOE spreadsheet gexistingunits2007h 

is available at http://www.eia.doe.gov/cneaf/electricity/page/capacity/capacity.html. 
28 

materials; however, they do not use sewer systems or sewage treatment facilities” Source: US Bureau of 

Census at: http://www.census.gov/eos/www/naics/ 

x Database filter #2 of 3: EPA deleted all of the units that did not use coal as either a primary or secondary energy source 

using the coal type codes displayed in Exhibit 3A below. In addition to these five categories of coal, examples of other 

primary or secondary energy sources reported by coal burning electric utility plants are agriculture byproducts, distillate fuel 

oil, natural gas, petroleum coke, propane, and wood & waste solids. 

Exhibit 3A 

Types of Coal Used by Electric Utility Plants as Coded in the 2007 DOE-EIA Database 

Item Code Type of Coal 

1 BIT Anthracite Coal, Bituminous Coal 

2 LIG Lignite Coal 

3 SUB Sub-bituminous Coal 

4 WC Waste/Other Coal (Anthracite Culm, Bituminous Gob, Fine Coal, Lignite Waste, Waste Coal) 

5 SC Coal Synfuel. Coal-based solid fuel that has been processed by a coal synfuel plant, and coal-based fuels such as 

briquettes, pellets, or extrusions, which are formed from fresh or recycled coal and binding materials. 

x Database filter #3 of 3: The first two filter criteria resulted in a subset of 506 coal-fired electric utility plants. Based on the 

reported operating status of the generators at these plants (i.e., OP, OS, SB, RE, OA)30, 11 plants reported that all generators are 

out-of-service, 2 plants reported that all generators are on standby and all remaining plants reported that at least one of their 

generators is operating. Removal of the 11 out-of-service plants from the master list resulted in a total affected plant population of 

495 coal-fired electric utility plants.

31 Appendix C presents the list of 495 plants.32

For purpose of identifying the types and size classifications for owner entities, this RIA initially used the utility code reported in the 2007 EIA860 database to identify which plants are owned by the same company. Company owner classifications were also checked for many plants 

using internet searches by plant and company name which sometimes revealed parent company owners. As summarized in Exhibit 3B and 

 

30 OP = Operating - in service (commercial operation) and producing electricity. Includes peaking units that are run on an as needed (intermittent or seasonal) basis, OS = 

Out of service v was not used for some or all of the reporting period and is NOT expected to be returned to service in the next calendar year, SB = Standby/Backup - 

available for service but not normally used (has little or no generation during the year) for this reporting period, RE = Retired - no longer in service and not expected to be 

returned to service, and OA = Out of service v was not used for some or all of the reporting period but was either returned to service on Dec 31 or will be returned to service 

in the next calendar year. Note: Units undergoing maintenance or repair of less than 12 months and are expected to be returned to service are assigned operating status.

31 This RIA filtered out 11 out-of-service electricity plant identification codes: 508, 511, 996, 1732, 2341, 2468, 2529, 2531, 2908, 3419, and 55612. 32 In comparison, a 2008 EPA Office of Water (OW) study estimated a nationwide total of 497 coal-fired electric plants using the same 2005 EIA-767 database; the 495 

plants estimated in this RIA are less than the 2008 EPA OW estimate because this RIA takes account of more recent plant operating status information (i.e., plants which 

have converted to other non-coal fuels or are not operating). Source: Table 3-1 (page 3-9) of EPA Office of Waster gSteam Electric Power Generating Point Source 

Category: 2007/2008 Detailed Study Report,h report nr. 821-R-08-011, August 2008; http://www.epa.gov/guide/304m/2008/steam-detailed-200809.pdf 
29 

Exhibit 3C below, these 495 coal-fired electric utility plants are owned and operated by 200 entities which are listed in Appendix D to this 

RIA. The 495 plants have a combined electricity generation nameplate capacity of 369,183 MW (megawatts), ranging in individual plant size 

from 2.3 MW to 3,969 MW, with an average size of 746 MW and a median size of 497 MW. This combined capacity represents 34% of the 

1.088 million MW total US electricity generation capacity as of 2007.33

Exhibit 3B 

Summary Classification of 495 Coal-Fired Electric Utility Plants by Type/Size of Owner Entities (2007) 

Item Type of Owner Entity* 

Entity Size 

Class** 

Coal-Fired Electric 

Utility Plant Count 

Owner Entity 

Count 

1 Federal government Non-small 11 1 

2 State government jurisdictions (authorities, districts) Non-small 13 7 

3 Medium & large population municipal government jurisdictions Non-small 27 19 

4 Medium & large companies Non-small 372 110 

5 Medium & large cooperatives (this RIA assumes all privately-owned) Non-small 20 12 

6 Small county government jurisdictions (commission) Small 1 1 

7 Small municipal government jurisdictions (agencies, commissions) Small 33 33 

8 Small companies Small 12 11 

9 Small cooperatives (this RIA assumes all privately-owned) Small 6 6 

Summary: 

Column totals = 495 200 

Private sector sub-total (items 4+5+8+9) = 410 (83%) 139 (70%) 

State/local government sub-total (items 2+3+6+7) = 74 (15%) 60 (30%) 

Small entity sub-total (items 6+7+8+9) = 52 (11%) 51 (26%) 

Notes: 

* Type of owner entity estimated and assigned by EPA ORCR based on owner name or internet research on type of ownership. 

** Size class determined according to the following numerical threshold criteria consistent with EPA_s Nov 2006 guidance for Regulatory 

Flexibility Act (RFA) Small Business Regulatory Enforcement Fairness Act (SBREFA) compliance: 

x Small non-government = Based on the US Small Business Administration NAICS code 221112 small business size standard of <4 

million megawatt hours per year total annual electricity generation by all plants owned by the entity). 

x Non-small non-government = entity_s total annual electricity generation >4 million megawatt hours per year. 

x Small government = Based on the RFA_s definition (5 US Code section 601(5)) of gsmall government jurisdictionh as the 

government of a city, county, town, township, village, school district, or special district with a population of less than 50,000. 

x Non-small government = entity_s jurisdiction population >50,000 people. 

 

33 Source: US Dept of Energy (DOE), Energy Information Administration (EIA) website at http://www.eia.doe.gov/cneaf/electricity/epa/epat2p2.html 
30 

Exhibit 3C 

State-by-State Electric Utility Plant Counts by Type/Size of Owner Entity (2007) 

Count of Plants Owned by Non-Small Entities Count of Plants Owned by Small Entities 

Item State 

Federal 

government 

State 

Government 

Non-small 

municipal 

Non-small 

company 

Non-small 

cooperative 

County 

government 

Small 

municipal 

Small 

company 

Small 

cooperative 

Row total 

plants 

1 AK 2 2 

2 AL 2 7 1 10 

3 AR 3 3 

4 AZ 2 3 1 6 

5 CA 6 6 

6 CO 1 2 11 14 

7 CT 2 2 

8 DC 0 

9 DE 3 3 

10 FL 5 9 1 15 

11 GA 10 1 11 

12 HI 2 2 

13 IA 1 13 3 2 19 

14 ID 0 

15 IL 2 21 2 25 

16 IN 21 5 26 

17 KS 2 6 8 

18 KY 2 1 14 3 1 21 

19 LA 4 4 

20 MA 4 4 

21 MD 8 8 

22 ME 1 1 

23 MI 2 13 5 2 22 

24 MN 1 10 5 16 

25 MO 5 10 2 2 1 20 

26 MS 3 1 1 5 

27 MT 4 1 5 

28 NC 19 3 22 

29 ND 2 5 7 

30 NE 4 3 7 

31 NH 2 2 

32 NJ 1 6 7 

33 NM 3 3 

34 NV 2 2 

35 NY 11 1 1 13 

36 OH 2 20 4 26 

37 OK 1 4 1 6 

38 OR 1 1 
31 

Exhibit 3C 

State-by-State Electric Utility Plant Counts by Type/Size of Owner Entity (2007) 

Count of Plants Owned by Non-Small Entities Count of Plants Owned by Small Entities 

Item State 

Federal 

government 

State 

Government 

Non-small 

municipal 

Non-small 

company 

Non-small 

cooperative 

County 

government 

Small 

municipal 

Small 

company 

Small 

cooperative 

Row total 

plants 

39 PA 32 2 34 

40 RI 0 

41 SC 4 10 14 

42 SD 2 2 

43 TN 7 7 

44 TX 1 2 14 1 1 19 

45 UT 1 4 1 6 

46 VA 15 1 16 

47 VT 0 

48 WA 1 1 

49 WI 12 3 2 17 

50 WV 16 16 

51 WY 8 1 9 

Column totals= 11 13 27 372 20 1 33 12 6 495 

The annual amount of coal burned by these 495 operating plants is 1.036 billion tons per year as reported in the 2007 EIA-923 database, 

according to the following five types of coal fuel categories: 

x Bituminous coal (DOE-EIA data code = BIT): 330 plants (67% of 495 plants) 

x Lignite coal (LIG): 21 plants (4%) 

x Coal-based synthetic fuel (SC): 19 plants (4%) 

x Sub-bituminous coal (SUB): 201 plants (41%) 

x Waste/other coal (WC): 33 plants (7%) 

Many plants use more than one coal fuel type so the above percentages exceed 100%. Appendices B & C present the quantity of coal burned 

and the types of coal burned for the list of 495 plants. As displayed in the state-by-state Exhibit 3D below, 47 states have coal-fired electric 

utility plants (3 states --- ID, RI, VT --- and DC do not have electric utility plants). The top-5 state coal-fired electric utility plant counts are: 

1. PA 34 plants

2. IN & OH 26 plants each

3. IL 25 plants

4. MI & NC 22 plants each

5. KY 21plants
32 

Exhibit 3D 

State-by-State Count of NAICS Code 22 Electric Utility Plants 

and Associated CCR Generation 

Item State 

Count of 

Plants 

(2007) % of Plants 

CCR Generated 

(tons as of 2005) 

% of CCR 

Generation 

1 AK 2 0.40% 46,179 0.03% 

2 AL 10 2.02% 3,210,337 2.27% 

3 AR 3 0.61% 744,267 0.53% 

4 AZ 6 1.21% 3,334,030 2.36% 

5 CA 6 1.21% 159,927 0.11% 

6 CO 14 2.83% 1,704,432 1.21% 

7 CT 2 0.40% 172,280 0.12% 

8 DC 0 0% 0 0% 

9 DE 3 0.61% 251,205 0.18% 

10 FL 15 3.03% 6,132,345 4.34% 

11 GA 11 2.22% 6,077,700 4.30% 

12 HI 2 0.40% 58,968 0.04% 

13 IA 19 3.84% 1,136,290 0.80% 

14 ID 0 0% 0 0% 

15 IL 25 5.05% 3,856,748 2.73% 

16 IN 26 5.25% 8,798,844 6.23% 

17 KS 8 1.62% 1,495,099 1.06% 

18 KY 21 4.24% 9,197,567 6.51% 

19 LA 4 0.81% 1,614,800 1.14% 

20 MA 4 0.81% 363,150 0.26% 

21 MD 8 1.62% 1,932,740 1.37% 

22 ME 1 0.20% 48,000 0.03% 

23 MI 22 4.44% 2,369,673 1.68% 

24 MN 16 3.23% 1,525,979 1.08% 

25 MO 20 4.04% 2,679,742 1.90% 

26 MS 5 1.01% 1,229,400 0.87% 

27 MT 5 1.01% 1,830,624 1.30% 

28 NC 22 4.44% 5,504,531 3.90% 

29 ND 7 1.41% 3,038,100 2.15% 

Exhibit 3D 

State-by-State Count of NAICS Code 22 Electric Utility Plants 

and Associated CCR Generation 

Item State 

Count of 

Plants 

(2007) % of Plants 

CCR Generated 

(tons as of 2005) 

% of CCR 

Generation 

30 NE 7 1.41% 614,473 0.44% 

31 NH 2 0.40% 176,900 0.13% 

32 NJ 7 1.41% 735,214 0.52% 

33 NM 3 0.61% 3,983,300 2.82% 

34 NV 2 0.40% 391,500 0.28% 

35 NY 13 2.63% 1,479,792 1.05% 

36 OH 26 5.25% 10,429,446 7.39% 

37 OK 6 1.21% 1,490,800 1.06% 

38 OR 1 0.20% 99,900 0.07% 

39 PA 34 6.87% 15,359,680 10.88% 

40 RI 0 0% 0 0% 

41 SC 14 2.83% 2,178,359 1.54% 

42 SD 2 0.40% 103,753 0.07% 

43 TN 7 1.41% 3,240,120 2.29% 

44 TX 19 3.84% 13,165,728 9.32% 

45 UT 6 1.21% 2,582,144 1.83% 

46 VA 16 3.23% 2,388,527 1.69% 

47 VT 0 0% 0 0% 

48 WA 1 0.20% 1,405,220 1.00% 

49 WI 17 3.43% 1,412,534 1.00% 

50 WV 16 3.23% 9,231,718 6.54% 

51 WY 9 1.82% 2,224,848 1.58% 

 Total 495 100% 141.2 million* 100% 

* Note: In comparison to this estimate based on DOE-EIA databases cited in this 

RIA, the American Coal Ash Association (ACAA) estimated 123.1 million tons 

CCR generated in 2005 based on its annual voluntary participation survey : 

http://acaa.affiniscape.com/associations/8003/files/2005%20CCP%20Survey%20

%2809-19-06%29Corrected-11-09-07.pdf 
33 

3B. Types of CCR Disposal Units 

x Estimated Plant Counts by Type of CCR Disposal Unit 

The scope of CCR disposal units covered by this RIA is active units (i.e., operational units which were receiving CCR as of year 2005). 

Inactive or abandoned units (i.e., non-operating units) are excluded from the scope of this RIA. The data source used to identify baseline CCR 

management practices and active units is the 2005 U.S. Department of Energy (DOE) Energy Information Administration (EIA) Form EIA-767 

gSteam-Electric Plant Operation and Design Reporth database.34 The EIA-767 database is the primary data source for reporting annual CCR 

disposition for plants generating greater than 100 MW (megawatts) of electricity. Plants smaller than 100 MW are not required to report CCR 

tonnage and disposition (i.e., type of disposal and beneficial use) data to the EIA-767 database. Schedule 3 of the EIA-767 database contains 

the annual disposition of CCR in one or more of the following five forms of CCR management categories, according to annual tons disposed 

for each plant. EIA-767 does not contain counts of CCR disposal units for each plant: 

1. Company-owned landfill 

2. Company-owned disposal ponds (i.e., surface impoundments) 

3. Onsite use and storage (this RIA assumes all of this quantity eventually goes to beneficial use, not disposal) 

4. Sold (for beneficial use) 

5. Disposed off site 

The 2005 EIA-767 database contained annual CCR disposal data for 363 of the 495 plants identified in the 2007 EIA-860 database. The 363 

plants are over 100 MW in size and thus are covered by the EIA-767 database. For the 132 plants which did not report CCR disposal practices 

in the 2005 EIA-767 database because they are less than 100 MW in size, disposal of CCR is assumed to take place in on-site or off-site 

landfills (whichever is the lowest-cost method as assigned by the CCR disposal engineering control cost model used for this RIA). For each of 

the 495 coal-fired utility plants identified in the prior section of this RIA using the 2007 EIA-860 database, baseline CCR disposal practices 

were assigned using the methodology and data sources presented below. Based on this analysis, 467 of the 495 plants dispose CCR using the 

following methods. The 28 remainder of the 495 plants do not dispose because they solely supply their CCR for beneficial uses. A total of 272 

of the 495 plants supply CCR for beneficial uses. The total count of disposal methods exceeds the 467 total count of disposing plants because 

some plants use more than one disposal method. The EIA-767 database does not contain counts of disposal units for each plant so only plant 

counts are summarized below according to disposal method, not CCR disposal unit counts. Because some plants use more than one disposal 

unit, the total count of CCR disposal units v although unknown for purpose of this RIA -- exceeds the 467 total count of disposing plants. 

 

34 Source: The EIA-767 database includes annual data from organic-fueled or combustible renewable steam-electric plants with a generator nameplate rating of 10 or more 

megawatts (MW) regardless of current ownership and/or operation. However, it contains annual tonnage CCR generation, CCR disposal, and CCR beneficial use data only 

for plants over 100MW in size. The EIA terminated the EIA-767 database after year 2005. Beginning with calendar year 2007 data, two other surveys, the Form EIA-860 

and the Form EIA-923, will collect most of the data formerly collected by Form EIA-767. No data will be collected for 2006. The following weblink provides a crosswalk 

of the data elements previously collected on the Form EIA-767 for 2005 with the corresponding data elements to be collected beginning with calendar year 2007 on the 

Form EIA-860 or the Form EIA-923: http://www.eia.doe.gov/cneaf/electricity/2008forms/consolidate.html 
34 

x Onsite landfills: 311 plants operate onsite CCR landfills (this RIA refers to these as gonsiteh landfills although some may be 

located off plant property). This estimate consists of two sources (i.e., 212 plants + 99 plants): 

 212 plants: dentified through actual data reporting of 363 coal-fired electric plants in size >100 MW 

contained in the 2005 EIA-767 database, out of the total 495 plants identified using the 2007 EIA860 database (as described in the previous section above). 

 99 plants: This estimate is based on the remainder 132 electric utility plants (i.e., 495 minus 363 

plants = 132 plants) between 1 MW and 100 MW size for which there is no CCR disposal data in the 

EIA-767 database, and for which the CCR disposal engineering control cost model used in this RIA 

assigned the lowest-cost of three landfill options: (1) onsite dug landfill, (2) onsite pile landfill, or 

(3) offsite landfill. The cost model assignment was dependent upon the level of baseline engineering 

controls assumed required by each plant_s state location and annual CCR disposal tonnage. The cost 

model estimated that 99 of the 132 plants without data dispose CCR in onsite landfills. 

x Onsite impoundments: 158 plants operate onsite CCR surface impoundments (aka gponds,h gembankments,h gdams,h gdikes,h gwet 

dumps,h gconstructed wetlandsh). This RIA assumes that all impoundments are gonsiteh although some may 

be located off plant property. 

The non-duplicative count of plants using onsite landfills and/or onsite impoundments is 383 plants. 

x Offsite disposal: 149 plants assigned as sending CCR offsite for disposal to commercial landfills (of which 84 plants solely 

ship CCR for offsite disposal). Off-site landfills receiving CCR are assumed to already be in compliance 

with EPA_s RCRA Subtitle D guidance. The 149 plants assigned as using offsite landfills consist of the 

following assignments according to data sources (i.e., 116 plants + 33 plants): 

 116 plants: Electric utility plants >100 MW size (source: 2005 EIA-767 database): Final disposition 

of wastes is reported as either (a) company-owned landfill, (b) company-owned disposal pond, (c) 

on-site use & storage, (d) sold, or (e) off-site disposal. This RIA assumes that off-site disposal 

means offsite commercial landfill. Plants could have reported offsite minefill in this category if it 

was not "sold" (e.g., they paid to dispose it in a mine or it was used as minefill and no payment was 

made to the electric utility). However, it is unknown the sub-quantity of goffsite disposalh which 

includes plants reporting tonnages for non-sold uses as offsite minefill.35

 

35 In July 2009, ORCR contacted the DOE-EIA Form 767 questionnaire contact person (Natalie Ko, Electric Power Division) to clarify this RIA_s assignment of all goffsite 

disposalh tonnages as commercial landfills. The DOE-EIA contact person responded with additional information from four 2005 Form EIA-767 questionnaires regarding 

how electricity plant respondents optionally characterized the fly ash and bottom ash reported in the Form EIA-767 survey questionnaire as gOff Site Disposalh : 

· gThis quantity of fly ash was given away at no costh 

· gThe fly ash was sent off site for beneficial useh 

· gThe fly ash is injected into the nearby mines for recharging the minesh 

· gAsh is recycled as a beneficial re-use product for flowable fill in the construction industryh 
35 

x 92 plants Offsite landfill fly ash 

x 76 plants Offsite landfill bottom ash 

x 4 plants Offsite landfill gypsum 

x 16 plants Offsite landfill FGD 

x 7 plants Offsite landfill other CCR (i.e., coal combustion by-products) 

x Sub-total = 116 plants (non-duplicative count) 

 33 plants: This estimate is based on the 132 electric utility plants between 1 MW and 100 MW size 

for which there is no CCR disposal data in the EIA-767 database, and for which the CCR disposal 

engineering control cost model used in this RIA assigned the lowest-cost of three landfill options: 

(1) onsite dug landfill, (2) onsite pile landfill, or (3) offsite landfill. The cost model assignment was 

dependent upon the level of baseline engineering controls assumed required by each plant_s state 

location and annual CCR disposal tonnage. 

x Estimated Counts of CCR Disposal Units 

The methodology of this RIA does not estimate or use secondary information about the actual count of CCR disposal units (i.e., landfill units 

and impoundment units) used by these 467 onsite or offsite disposing plants. However, there are two sources of CCR disposal unit counts: 

x Source #1 of 2: ASTSWMO: The February-March 2009 ASTSWMO voluntary participation survey36 of 42 states (which is incomplete 

coverage of the 47 states identified in this RIA for the 495 coal-fired electric plants) estimates a total of 484 electric utility plant CCR 

disposal units: 

x 227 electric utility plant CCR landfill units in 41 states 

x 257 electric utility plant CCR impoundment units in 33 states 

x Total electric utility plant CCR disposal units = 484 (i.e., 227 landfills + 257 impoundments) 

But it is not clear whether the ASTSWMO CCR disposal unit counts (a) are restricted in the ASTSWMO survey to electric utility plants in 

NAICS code 221112, (b) may also include counts of CCR disposal units associated with other industries which generate coal-fired electricity 

in the surveyed states, (c) may include inactive/abandoned as well as active CCR disposal units, or (d) may include landfills or impoundments 

operated by electric utility plants which contain other types of waste streams (e.g. waste water treatment ponds without co-mingled CCR). 

Source #2 of 2: EPA: In March 2009 EPA sent letters37 to 210 coal-fired electric plant facilities and owner companies in order to identify the 

location of CCR impoundments and evaluate their structural integrity in the wake of the December 2008 CCR impoundment collapse and 

 

36 Source: Association of State and Territorial Solid Waste Management Officials (ASTSWMO), 01 April 2009 letter to Matt Hale, Director, EPA Office of Resource 

Conservation and Recovery: http://www.astswmo.org/files/publications/Positionpapers/ASTSWMO-CCB-letter-attachments.pdf 
36 

flooding at the TVA Kingston TN electricity plant. Although not used in this RIA other than for reference here, the responses received to the 

March 2009 EPA letters resulted in identification of 584 CCR impoundments units at electric utility plants. The letters did not collect 

information about CCR landfills38

3C. Types of CCR and Annual Quantities 

As of 2008, coal-fired utilities burn approximately 1.036 billion tons of coal per year using a variety of conventional combustion technologies. 

NAICS 22 electric utility coal combustion results in the generation of five types of CCR: 

1. Fly ash 

2. Bottom ash 

3. Flue gas desulfurization (FGD) sludge 

4. Gypsum 

5. Other residues (including boiler slag) 

These wastes may be (a) disposed in onsite landfills and surface impoundments (i.e., ponds, dams, embankments, lagoons), or (b) may be 

applied to beneficial uses, or (c) disposed offsite. At the time of preparing this RIA in 2009, waste generation and disposition data from 

Schedule 8, Part A of the 2007 DOE EIA database for the Form EIA-932 gPower Plant Operations Reporth database had yet to be finalized. 

Instead, the most currently available waste data was from the 2005 DOE EIA Form 767 gSteam-Electric Plant Operation and Design Reporth 

database. Therefore, the 2005 EIA-767 database is the primary source used in this RIA to quantify CCR generation and identify the ultimate 

disposition of CCR (i.e., type of disposal or beneficial use). CCR generation and final disposition are reported under the above five CCR type 

categories in the 2005 EIA 767 database. As estimated in this RIA and displayed below in Exhibit 3E, the 495 electric utility plants generated 

141.2 million tons per year of CCR (2005/2007 mixed data). 

Interpretive Note: This RIA_s CCR generation estimate of 141.2 million tons is 15% and 8% higher, respectively, than the 

123.1 million tons (2005) and the 131.1 million tons (2007) annual CCR generation estimates published by 

the American Coal Ash Association (ACAA).39 The numerical discrepancy between this RIA_s estimate and 

the ACAA estimates may be explained by the fact that both estimates (i.e., this RIA and the ACAA) are 

based on incomplete CCR tonnage disposition data for less than the guniverseh of all known operating 

 37 Source: Additional information about these March 2009 EPA letters is available at http://www.epa.gov/osw/nonhaz/industrial/special/fossil/coalashletter.htm 38 Source: EPA_s 584 CCR impoundment unit count is documented at http://www.epa.gov/osw/nonhaz/industrial/special/fossil/surveys/faqs.htm#18 39 As of the date of this RIA, ACAA_s gCoal Combustion Products Production & Use Statisticsh website contains annual CCR generation and annual CCR beneficial use 

tonnage estimates for the US electric utility industry for years 2001, 2002, 2003, 2004, 2005, 2006, 2007, and 2008. As reported in footnotes on ACAA_s annual survey 

results data tables, ACAA_s CCR generation and CCR beneficial use annual tonnage estimates are based on the following survey coverages: 2001 coverage not indicated on 

data table; 2002 2/3rd coal burn; 2003 60% coal burn; 2004 60% coal burn; 2005 54% coal burn; 2006 57% coal burn reported by 58 electric utilities; 2007 161 plants; and 

2008 274 plants. ACAA_s annual CCR tonnage data webpage is at http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=3 
37 

electric utility plants in the data year, extrapolated to plants for which there is no CCR tonnage data in the 

EIA database (in the case of this RIA_s estimation methodology) and in the case of the ACAA estimates, 

extrapolated to plants not covered by ACAA_s annual utility industry survey by supplementing with EIA 

data. 

The estimate of CCR generation developed in this RIA consists of the following breakout of generation estimates according to two electric 

utility plant size categories, which correspond to the CCR tonnage disposition data reporting cut-off requirement in the EIA-767 database: 

x >100 MW plants: Exhibit 3E below presents CCR disposition data for a sub-total of 120.9 million tons CCR generated per year as 

reported by plants with annual electricity generation >100 MW from Schedule 3A of the 2005 EIA-767 database for 

each plant. 

x Ash generation data (fly ash and bottom ash) were available for 385 plants. 

x FGD sludge generation data were available for 72 plants. 

x Gypsum generation data were available for 31 plants. 

x Other byproduct generation data were available for 40 plants. 

If plants > 100 MW reported either company landfill, company disposal ponds, sold for beneficial use, or off-site 

disposal of CCR in the EIA-767 database, these final disposition practices are assumed in this RIA for the baseline. A 

total 179 plants with company-owned CCR landfills and 158 plants with company-owned CCR surface 

impoundments were reported in the 2005 EIA-767 database (i.e., 337 of the 495 electric plants).40 112 of the 495 

plants reported 8.2 million gon-site use and storageh which this RIA assigned as beneficial use not as disposal. This 

assumption is supported by (a) DOE_s August 2006 report41 gCoal Combustion Waste Management at Landfills and 

Surface Impoundments 1994-2004h which interpreted the entire "onsite use & storage" quantity as beneficial use, and 

(b) the American Coal Ash Association (ACAA) which indicates that 49.6 million tons of coal ash were beneficially 

used in 200542. However, the beneficial use estimate in Exhibit 3E below is much less at 38.8 million tons which is 

based on the EIA-767 gSoldh (i.e., beneficial use) CCR tonnage category. But adding the 8.2 million tons reported as 

"onsite use & storage" yields an estimate of 47.0 million tons (Exhibit 3G), which nearly matches the ACAA 

beneficial use estimate of 49.6 million tons. This suggests it is valid to assign the tonnage reported in the EIA-767 

database as "onsite use & storage" to beneficial use rather than to disposal. 

 

40 In the 2005 DPRA Report, an additional step was included after step 1 that identified additional disposal practices using landfill and surface impoundment as reported in 

the 1995 EPRI Comanagement Survey. This data source was not used to identify CCR management units in this RIA given it dates back to 1995. The data source is only 

used to identify existing engineering controls for the units identified in the 2005 EIA 767 database. In the 2005 DPRA Report, 14 additional landfills and 10 surface 

impoundments were identified using this information source.

41 Source: Footnote c of Table 1 on page 6 of DOE_s August 2006 report at http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=2008 42 Source: ACAA_s 2005 beneficial use data are available at http://acaa.affiniscape.com/associations/8003/files/2005%20CCP%20Survey%20%2809-19-06%29Corrected11-09-07.pdf 
38 

x 1MW to 100 MW Exhibit 3F below presents an additional sub-total of 20.3 million tons per year of CCR generated by 132 electric 

utility plants between 1 MW and 100 MW in capacity which had no CCR management information in the EIA767 

database, because plants less than 100 MW are not required to report their CCR management annual tonnages in the 

EIA-767 database. Therefore, this RIA formulated an estimate for this size category of plants based on the 

following approach. Coal use and percent ash content data from Schedule 4A of the 2005 EIA-767 database were 

used to estimate ash generation quantities for 102 plants within this smaller size category. For 5 plants for which 

EIA-767 coal use data were unavailable for 2005, coal use data from Schedule 4A of the 2007 EIA-923 database 

were used to estimate CCR generation quantities for those 5 plants. FGD sludge generation data obtained from 

Schedule 843 of the 2005 EIA-767 database were used for 115 plants. Landfill (either on-site or off-site whichever 

is more economical) is the assumed CCR disposal practice. No gypsum or other byproduct generation quantities 

were estimated. For plants between 1 MW and 10 MW, ash generation quantities estimated using generator 

nameplate capacity rating data from the 2007 DOE Form 860 database. This 1 MW to 100 MW subtotal of 132 

plants consists of two sub-categories: 

x 10 MW to 100 MW: 5.4 million tons of CCR for 110 plants estimated by multiplying the quantity of coal they 

burned by the percent CCR content of the coal data from Schedule 4A of the 2005 EIA-767 database and 2007 

DOE EIA 923 database, or using generator nameplate rating data from the 2007 EIA-860 database and an 

average percent ash content. 

x 1 MW to 10 MW: 14.9 million tons of FGD sludge reported for 22 plants in Schedule 8 of the 2005 EIA-767 

database that did not report any FGD sludge in Schedule 3A of the 2005 EIA-767 database. 

 

43 In general, data obtained from Schedule 8 of the 2005 EIA-767 database reflects information reported by plants between 10 MW and 100 MW. However, if a plant 

greater than 100 MW reported no final disposition quantities for FGD sludge in Schedule 3A of the 2005 EIA-767 database, the reported FGD sludge quantity in Schedule 8 

is assumed in this RIA to be placed in a landfill for that plant. 
39 

Exhibit 3E 

Annual CCR Disposition for NAICS 22 Electric Utility Plants >100 MW Capacity (tons per year as of 2005) 

Item CCR Category A B C D E F (A+{+E) 

Company-Owned 

Landfill 

(Dry Disposal) 

Company-Owned 

Disposal Ponds 

(Wet Disposal) 

Onsite Use & 

Storage (assumed 

as beneficial use) 

Sold for 

Beneficial Use 

Offsite Disposal 

(assumed offsite 

landfills) 

Row Totals 

1 Fly Ash 21,324,280 15,212,590 3,744,370 20,760,230 9,314,540 70,356,010 

2 Bottom Ash 5,707,740 4,311,630 3,487,660 5,453,717 1,907,480 20,868,227 

3 Flue Gas Desulfurization Sludge 9,526,400 1,886,200 465,600 408,910 2,506,540 14,793,650 

4 Gypsum (salable) 54,620 872,100 372,100 8,437,400 782,800 10,519,020 

5 Other CCR 226,510 82,900 108,830 3,729,400 247,680 4,395,320 

6 Totals 36.8 million 22.4 million 8.2 million 38.8 million 14.8 million 120.9 million 

Exhibit 3F 

Annual CCR Disposition for NAICS 22 Electric Utility Plants 1 MW to 100 MW Capacity (tons per year as of 2005) 

A B C D (A+B+C) 

Item CCR Category 

Fly Ash Disposed in 

Off-site Landfill 

(Plants 1 MW 

to 100 MW) 

Fly Ash Disposed in 

Company-owned 

Landfill 

(Plants 1 MW to 100 MW) 

FGD Disposed in 

Company-Owned Landfill 

(Plants >10 MW) Row Totals 

1 Fly Ash 274,917 5,147,468 NA 5,422,385 

2 Bottom Ash Included under Fly Ash Included under Fly Ash NA Included under fly ash 

3 Flue Gas Desulfurization Sludge NA NA 14,852,300 14,852,300 

4 Gypsum (salable) NA NA Included in row 3 Included in FGD 

5 Other Byproducts Included under Fly Ash Included under Fly Ash NA Included under fly ash 

6 Totals 0.3 million 5.1 million 14.9 million 20.3 million 

Exhibit 3G 

Annual CCR Disposition for NAICS 22 Electric Utility Plants All Sizes (tons per year as of 2005) 

(Source: Exhibit 3E + Exhibit 3F) 

A B C D E (A+B+C+D) 

Item CCR Category 

Company-Owned 

Landfill 

(Dry disposal) 

Company-Owned 

Disposal Ponds 

(Wet disposal) 

Beneficial Use 

(onsite BU + offsite 

BU + storage for BU) 

Offsite Disposal 

(assumed offsite 

commercial landfills) Row Totals 

1 Fly Ash 26,471,748 15,212,590 24,504,600 9,589,457 70,356,010 

2 Bottom Ash 5,707,740 4,311,630 8,941,377 1,907,480 20,868,227 

3 Flue Gas Desulfurization Sludge 24,378,700 1,886,200 874,510 2,506,540 14,793,650 

4 Gypsum (salable) 54,620 872,100 8,809,500 782,800 10,519,020 

5 Other CCR 226,510 82,900 3,838,230 247,680 4,395,320 

6 Totals 56.8 million 22.4 million 47.0 million 15.0 million 141.2 million 

 Percentages 40% 16% 33% 11% 100% 
40 

Exhibit 3H below summarizes the respective plant counts, annual tonnage CCR disposal, and electricity generation nameplate capacities of the 

467 plants which dispose CCR, according to type of CCR disposal method (i.e., CCR landfills and CCR impoundments). Because some plants 

reported more than one management method, the sum of the plants across each disposal method exceeds the total count of 467 disposing plants. 

Exhibit 3H 

Summary of Plant Size and CCR Disposal Methods Estimated in this RIA

A B C D 

Plants Using CCR Landfills (dry disposal) 

Characterizing Metrics Onsite Landfills Offsite** 

Plants Using CCR 

Impoundments*** 

(wet disposal) 

Row Totals 

(non-duplicative) 

1. 2007 Count of Coal-Fired 

Electric Utility Plants which 

Dispose CCR 

311 plants 

(63% of 495) 

149 plants 

 (30% of 495) 

(84 plants solely use 

offsite landfills) 

158 plants 

(32% of 495) 

467 plants dispose CCR 

(94% of 495) 

(CCR from the remainder 

28 plants is solely for 

beneficial uses) 

2. Annual CCR Disposal (2005) 

x Minimum per plant = 

x Maximum per plant = 

x Mean per plant = 

x Median per plant = 

56.8 million tons (60%) 

x 400 tons 

x 1.82 million tons 

x 205,196 tons 

x 90,700 tons 

15.0 million tons (16%) 

x 20 tons 

x 1.28 million tons 

x 100,899 tons 

x 33,000 tons 

22.4 million tons (24%) 

x 500 tons 

x 1.04 million tons 

x 141,550 tons 

x 67,300 tons 

94.2 million tons (100%) 

x 110 tons 

x 2.11 million tons 

x 201,796 tons 

x 89,300 tons 

3. Nameplate capacity* (2007) 

x Minimum per plant = 

x Maximum per plant = 

x Mean per plant = 

x Median per plant = 

213,978 MW (58%) 

x 11 MW 

x 3,969 MW 

x 772 MW 

x 538 MW 

90,547 MW (25%) 

x 2 MW 

x 2,911 MW 

x 608 MW 

x 350 MW 

180,901 MW (49%) 

x 75.3 MW 

x 3,564 MW 

x 1,145 MW 

x 893 MW 

369,183 MW (100%) 

x 2 MW 

x 3,969 MW 

x 746 MW 

x 497 MW 

Notes: 

* Nameplate capacity = electricity generation output potential in megawatts (MW). 

** This RIA assumes all reported gnon-company offsite disposalh in the EIA-767 database involves offsite landfill dry disposal, because it is expensive to 

transport large volumes of wet (i.e., watery) CCR long distances. 

*** Surface impoundments are reported in the EIA-767 database as gcompany-owned ponds.h This RIA assumes all are located onsite. 
41 

3D. Size of CCR Disposal Units 

The size of CCR disposal units ranges from modest to very large, with some impoundments covering 1,500 acres or more. Sizing of the units 

is based on the annual tonnage of CCR placed in the unit. CCR disposal unit size assumptions for this RIA are adopted from Section 4.4.1 of 

the 2005 DPRA Report: 

x Landfills sizes:

Designed as gcombination fill landfillsh  3.8 million cubic yards capacity  50% of the capacity excavated below grade  40-year capacity (i.e., operating lifespan)44 

 Per-unit surface area size ranges from 12 acres for 10,000 tons per year to over 2,000 acres for 2,000,000 tons per year.

Designed as gpile fill landfillsh  3.4 million cubic yards capacity  5% of the capacity excavated below grade  40-year capacity (i.e., operating lifespan)  Per-unit surface area ranges from 16 acres for 10,000 tons per year to over 3,000 acres for 2,000,000 tons per year.

x Surface impoundment sizes:

o 100% of capacity below grade o 40-year capacity o Per-unit surface area ranges from 30 acres for 10,000 tons per year, 140 acres for 50,000 tons per year, 500 acres for 200,000 tons per 

year, 1,400 acres for 500,000 tons per year, and 5,500 acres for 2,000,000 tons per year.

 

44 For the 30 Nov 2005 DPRA report (gEstimation of Costs for Regulating Fossil Fuel Combustion Ash Management at Large Electric Utilities Under Part 258h, docket 

document ID nr. EPA-HQ-RCRA-2006-0796-0469), the EPA asked utility industry representatives for the typical lifespan years of CCR landfills and impoundments. 

Industry representatives provided a 40-year estimate for both. This estimate is supported by data provided by industry in the 1995 EPRI Comanagement Survey. In the 

EPRI Survey, data describing six CCR landfills noted the year the unit was opened and the estimated date of closure. The average life expectancy is 34 years and the 

median life expectancy is 38 years. Similarly, data provided for 18 CCR impoundments indicate an average life expectancy of 45 years and a median life expectancy of 46 

years. Therefore, this RIA assumes a 40-year lifespan for both landfills and impoundments. 
42 

3E. Cost of Baseline CCR Disposal 

This Chapter presents characterizing data and estimates of the costs to the electric utility industry and to government, for baseline (i.e., current) 

industry engineering controls and other costs associated with CCR disposal. OMB_s 2003 Circular A-4 gRegulatory Analysish (page 15) 

requires RIAs to measure the benefits and costs of regulations against a baseline defined as: 

Baseline = g[T]he best assessment of the way the world would look absent the proposed rule.h 

The baseline developed here uses the most recent data year available and relies solely on publicly available data used in prior studies and 

reports, updated using empirically-justifiable factors. For purpose of this RIA, the possible types of baseline costs include:

A. Baseline gengineering control gcosts for CCR disposal units: 

1. Ground water monitoring 

2. Bottom liners 

3. Leachate collection system 

4. Dust controls v applicable to landfills only 

5. Rain and surface water run-on/run-off controls v applicable to landfills only 

6. Financial assurance for disposal unit closure and post-closure 

7. Disposal unit location restrictions (6 types: water tables, floodplains, wetlands, fault areas, seismic zones, karst terrain) 

8. Closure capping to cover unit 

9. Post-closure monitoring requirements 

10. Storage design and operating standards (tanks, containers, containment buildings) v not evaluated in this RIA 

B. Baseline gancillary costsh directly related to CCR disposal: 

11. Offsite disposal 

12. Structural integrity inspections v impoundments only 

13. RCRA facility-wide investigation (RFI) 

14. Corrective action 

15. Waste disposal permits 

16. Inspection & enforcement 

17. Remediation of environmental releases 

x Characterization of Industry Baseline CCR Disposal 

For each of the 467 operating electric utility plants which currently (2007) dispose CCR onsite or offsite (28 of the 495 total plants solely send 

their CCR for beneficial uses not disposal), this RIA estimated baseline engineering controls at disposal units and associated baseline disposal 
43 

costs for each type of disposal (note: the sum of plant counts for each disposal category below exceeds 467 because some plants use more than 

one type of CCR disposal method): 

o 311 plants with active onsite CCR landfills 

o 158 plants with active onsite CCR surface impoundments 

o 149 plants which offsite dispose (assumed all involve offsite landfills) 

For this RIA, the gbaselineh is defined as existing conditions plus projection of future conditions over the 50-year future period-of-analysis 

2012 to 2061 applied in this RIA (this RIA assumes year 2012 represents the first year when the final rule could take effect, if promulgated). 

Baseline engineering controls were estimated using the following 2-step method which is based on two alternative and complementary sources 

of information: 

x Step 1: If the plant reported controls in the 1995 EPRI Comanagement Survey, 1996 CIBO Survey, or the 1994-2004 DOE-EPA Study, 

the stricter of these controls or state-specified controls are assumed for the baseline. These studies contained control data for 89 plants with 

CCR landfills and 50 plants with CCR impoundments (i.e., 139 of the 495 electric utility plants). State regulations added additional 

controls at 69 of the 89 landfill plants and 43 of the 50 impoundment plants with plant specific information (e.g., the EPRI Survey data may 

have indicated that the unit had a liner only but state regulations required groundwater monitoring and capping so these additional controls 

were added). 

x Step 2: Controls specified under state regulations for 34 states are assumed for all other plants in those 34 states for the baseline if no 

1995 EPRI Comanagement Survey data, 1996 CIBO Survey data, or 1994-2004 DOE-EPA Study data are available for that plant. This

step resulted in assigning state-required controls to 201 plants with CCR landfills and 55 plants with CCR impoundments (i.e., 256 of the 

495 plants). Overall state regulations were added to 270 plants with CCR landfills and 98 plants with CCR impoundments. 

For the 100 plants (i.e., 47 plants with landfills and 53 plants with impoundments) for which there are no data from the three 

studies, and no state-regulatory data on controls from Step 1, no controls are assumed under baseline for on-site landfills and

impoundments; this represents a worst case (i.e., high cost) assumption. 

The associated data sources and findings for each baseline characterization step are described below. 

x Step 1: Baseline Installed CCR Disposal Engineering Controls Identified in Prior Industry Surveys (1995, 1996, 2004) 

The controls identified through the Step 1 prior studies were more stringent than the state government requirements discussed in Step 2 for: 

 

o Landfills: Voluntary controls for 25 plants with landfills (9% of 227 plants landfills) receiving 6.4 million tons per year (i.e., 

9% of total landfill CCR quantity) in 12 states (some are identified as voluntary because state regulations were not reviewed for 

the state): AR, AZ, CA, IA, IN, KS, MD, MN, NE, SD, SI, WV. 
44 

o Impoundments: Voluntary controls for 39 plants with impoundments (25% of 158 plants with impoundments) receiving 5.5 

million tons per year (i.e., 25% of total CCR impoundment quantity) in 14 states (some are identified as voluntary because state 

regulations were not reviewed for the state): AL, FL, IA, IL, IN, LA, MN, MS, NM, OH, SC, TX, UT, WY. 

x Step 2: Baseline State Government CCR Disposal Engineering Control Requirements for Landfills & Impoundments (2008) 

Several states have already established certain CCR disposal unit design and operating requirements that are required to be implemented either 

upon the effective date of the regulation (e.g., groundwater monitoring), upon retirement of the disposal unit (e.g., post-closure monitoring), or 

for newly constructed units only. Appendix E of this RIA provides a summary of the state government requirements for both landfills and 

impoundments. Current CCR disposal regulations have been reviewed for the top 34 states that utilize coal for producing electricity for 

required engineering controls at landfills and impoundments. The plants located in these states account for 99% of the annual quantity of CCR 

managed in company-owned (i.e., onsite) landfills and impoundments. State regulations were reviewed for the following 34 states: AL, AZ, 

CO, FL, GA, IA, IL, IN, KS, KY, LA, MD, MI, MN, MS, MO, MT, NV, NM, NY, NC, ND, OH, OK, PA, SC, TN, TX, UT, VA, WA, WV, 

WI, WY. Below is a synopsis of the baseline state government requirements according to the engineering controls listed above. 

1. Groundwater monitoring requirements: 

x Point-of Compliance: 

Two options for point-of-compliance groundwater monitoring include installing monitoring wells at the unit boundary or within 150 

meters of the unit boundary. Recent changes to state regulations suggest that states typically require unit boundary monitoring. 

x Number of Wells: 

Certain states specify a minimum number of monitoring wells: FL (3 wells for impoundments), IA (1 well for landfill), IL (multiple 

wells for landfills), KY (3 wells for landfills), LA (3 wells for impoundments and landfills), MO (4 wells for impoundments and

landfills), ND (3 wells for impoundments), OK (3 wells for impoundments and 4 wells for landfills), TN (3 wells for landfills), UT (3 

wells for landfills), WV (3 wells for impoundments and 4 wells for landfills). Well spacing design criteria for landfill boundary 

detection wells for FL, IA, and KS were reviewed. FL requires a minimum of one down-gradient detection well every 500 feet placed 

within 50 feet of the unit. Iowa requires a minimum of one detection well every 600 feet placed within 50 feet of the unit. KS 

recommends a minimum of one-down-gradient detection well every 500 feet. 

x Monitoring Parameters: 

Two options for sampling include testing for chemical indicators and testing for RCRA hazardous waste Appendix VIII constituents 

(i.e., 40 CFR 261 Appendix VIII). Of the 34 state regulations reviewed, three states require chemical indicator monitoring for surface 

impoundments [CO, PA, WV] and 11 states require chemical indicator monitoring for landfills [IA, FL, KY, MI, OH, OK, PA, TN, UT, 

WI, WV]. Three states require RCRA Appendix VIII constituent monitoring for impoundments [MO, PA, WV], and 10 states require 

RCRA Appendix VIII constituent monitoring for landfills [GA, FL, IA, IL, MI, MO, OH, TN, UT, WV]. 

x Monitoring Frequency: 

Three options for groundwater sampling frequency include quarterly, semi-annual and annual. Of the 34 state regulations reviewed, 

one state requires quarterly sampling for surface impoundments [CO (depending on the ground-water classification)] and three states 

require quarterly monitoring for landfills [IA (until baseline conditions are established), IL (first 5 years), MI]. Five states require semi-
45 

annual sampling for surface impoundments [LA, MO, ND, PA (chemical indicators), WV] and 12 states require semi-annual 

monitoring for landfills [FL, GA, KY, LA, MO, OH (chemical indicators), OK, PA (indicator parameters), TN (chemical indicators), 

UT, WV, WY]. Three states require annual sampling for surface impoundments [CO (depending on the ground-water classification),

PA (metals and VOCs), WV] and five states require annual sampling for landfills [IA (after baseline established), IL (after 5 years), OH 

(metals, TOC, TDS, chloride, sodium and radionuclides), PA (metals and VOCs), TN (RCRA Appendix VIII constituents)]. 

x Timing of State Regulation Implementation: 

In the baseline, certain states require groundwater monitoring only for newly constructed units. These baseline costs are tracked as 

future baseline cost streams in the cost model. Of the 34 state regulations reviewed, nine states require immediate compliance with 

monitoring requirements for impoundments: LA, MN, MO, ND, NV, NY, OK, SC, UT. Eight states that only require groundwater 

monitoring only at newly constructed surface impoundments: CO, FL, KY, MI, NC, PA, WI, WV. 21 states require immediate 

compliance with monitoring requirements for landfills: AL, CO, GA, IA, IN, KS, KY, MI, MN, MT, NC, ND, NY, OH, PA, SC, TN, 

UT, VA, WA, WY. Ten states require groundwater monitoring only at newly constructed landfills: FL, IL, LA, MS, MO, NV, OK, 

TX, WV, WI. 

2. Bottom liner requirements: 

x Impoundments: 

Of the 34 state regulations reviewed, 10 states require immediate compliance with liner requirements for surface impoundments: FL 

(composite), KS (composite), KY (composite), LA (composite), MO (composite), ND (clay or synthetic), NV (composite), NY 

(composite), OK (composite), and PA (composite). Six states require liners only at newly constructed surface impoundments: CO (clay 

or soil), MI (clay or composite), NC (composite), WI (composite, synthetic or clay), WV (composite), WY (composite). 

x Landfills: 

Of the 34 state regulations reviewed, 19 states require immediate compliance with liner requirements for landfills: AL (composite), CO 

(clay or synthetic), GA (composite), IN (clay), KS (composite), LA (composite), MI (composite), MN (clay), MT (composite), NC 

(composite), ND (clay or synthetic), NY (composite), OH (composite), PA (composite), SC (composite or clay), TN (composite), UT

(composite), VA (composite), and WA (composite). 10 states require liners only at newly constructed landfills: FL (composite or 

double), IL (clay or composite), MS composite), MO (composite), NV (composite), OK (composite), TX (composite), WI (composite),

WV (composite), WY (composite). 

3. Leachate collection/detection system requirements: 

x Impoundments: 

Of the 34 state regulations reviewed, nine states require immediate compliance with leachate collection/detection system requirements 

for surface impoundments: FL, KS, KY, LA, MO, ND, NV, NY, PA. Five states require leachate collection/detection systems only at 

newly constructed surface impoundments: CO, MI, NC, WV, WI. 

x Landfills: 

Of the 34 state regulations reviewed, 18 states require immediate compliance with leachate collection system requirements for landfills: 

AL, CO, GA, IN (karst areas only), KS, MI, MN, MT, NC, ND, NY, OH, PA, SC, TN, UT, VA, WA. 11 states require leachate 

collection systems at newly constructed landfills: FL, IL, LA, MS, MO, NV, OK, TX, WI, WV, WY. 
46 

4. Dust control requirements: (landfills only) 

Of the 34 state regulations reviewed, 16 states require immediate compliance with dust control requirements (wetting and truck covers 

and/or compaction) for landfills: CO, GA (compaction only), IA, IN, KS, MI, MN (includes compaction), ND (includes compaction), NY, 

OH, PA, SC, TN, UT, VA, WA. Nine states require dust controls only at newly constructed landfills: FL, IL (includes compaction), LA, 

MO, NM, OK, WI, WV, WY (includes compaction). 

5. Run-on/run-off control requirements: (landfills only) 

Of the 34 state regulations reviewed, 18 states require immediate compliance with run-on/run-off control requirements for landfills: AL, CO, 

GA, IA, IN, KS, MD, MN, MT, NC, NY, OH, PA, SC, TN, UT, VA, WA. 11 states require run-on/run-off only at newly constructed 

landfills: FL, IL, LA, MS, MO, NV, OK, TX, WI, WV, WY. 

6. Financial assurance for CCR disposal unit closure & post-closure care 

x Impoundments: 

Of the 34 state regulations reviewed, 11 states require immediate compliance with financial assurance requirements for surface 

impoundments: AZ, KY, LA, MN, MO, ND, NM, NV, OK, TN, and UT. Four states require financial assurance requirements only at 

newly constructed surface impoundments: CO, MI, NC, WI. 

x Landfills: 

Of the 34 state regulations reviewed, 22 states require immediate compliance with financial assurance requirements for landfills: CO, 

FL (new construction), GA, IA, IN, KS, KY, MI, MN, MO, MT, NC, ND, NY, OH, SC, TN, UT, TX, VA, WA, WY. Eight states 

require financial assurance requirements only at newly constructed landfills: FL, IL, LA, MS, NV, OK, WI, WV. 

7. Disposal Unit Location Restrictions (6 categories)

State regulations for the top-25 coal usage states (for electricity) were reviewed back in year 2000 for any location restrictions. These 

regulations were not updated as part of this RIA. The following is a synopsis of state government location restrictions on locating CCR 

surface impoundments and landfills, according to six categories of location restrictions (water table, floodplains, wetlands, fault areas, 

seismic zones, unstable karst terrain). 

x 7-1: Below the natural water table: 

o Of the 25 state regulations reviewed, five states have location restrictions below the natural water table for surface impoundments: 

NC (4 feet above seasonal water table), ND (within aquifer), OK (if less than 15 feet above ground-water table), WV (5 feet above 

ground-water table), WY. 

o Of the 25 state regulations reviewed, eight states have location restrictions below the natural water table for landfills: FL, IA (5 feet 

above ground water), MI (4 feet above ground water), MN (5 feet above ground water), NC (4 feet above seasonal water table), ND

(within aquifer), OH (5 feet above water table for wastes with higher leachate concentrations), TN (if less than 5 feet above water 

table). 

x 7-2: Floodplains: 
47 

o Of the 25 state regulations reviewed, eight states have location restrictions in floodplains for surface impoundments: KS (under 

permit), KY, MO (if closed with waste in place), NC, ND, OK (if dike not at least 1 foot above 100-year flood elevation), PA, WV. 

o Of the 25 state regulations reviewed, 20 states have location restrictions in floodplains for landfills: AZ, CO, FL, IL, IN, IA, KS, KY, 

MI, MN, MO, NC, ND, OH, OK, PA, TN, WV, WI, WY. 

x 7-3: Wetlands 

o Of the 25 state regulations reviewed, five states have location restrictions in wetlands for surface impoundments: KY, MO (if closed 

with waste in place), ND, PA, WV. 

o Of the 25 state regulations reviewed, 17 states that have location restrictions in wetlands for landfills include AZ, CO, FL, IL, IN, IA, 

KY, MI, MN, MO, ND, OK, PA, TN, WV, WI, WY. 

x 7-4: Fault areas: 

o Of the 25 state regulations reviewed, two states have location restrictions in fault areas for surface impoundments: MO (if closed with 

waste in place), WV. 

o Of the 25 state regulations reviewed, seven states have location restrictions in fault areas for landfills: AZ, CO, MO, OH, TN, WV 

and WI. 

x 7-5: Seismic zones: 

o Of the 25 state regulations reviewed, two states have location restrictions in seismic impact areas for surface impoundments: include 

MO (if closed with waste in place), WV. 

o Of the 25 state regulations reviewed, eight states have location restrictions in seismic impact areas for landfills: AZ, CO, IL, MO, OK 

(if within 5 miles of epicenter of 4.0 earthquakes), TN, WV, WI. 

x 7-6: Karst areas: 

o Of the 25 state regulations reviewed, five states have location restrictions in unstable areas for surface impoundments: KY, MO (if 

closed with waste in place), ND, PA, WV (1,000 feet away). 

o Of the 25 state regulations reviewed, 12 states have location restrictions in unstable areas for landfills: AZ, CO, IN, IA, KY, MN, 

MO, ND, PA, TN, WV (1,000 feet away), WI. 

8. Closure cap controls 

x Of the 34 state regulations reviewed, nine states require immediate compliance with closure control requirements for surface 

impoundments: AZ (synthetic cap), KY (synthetic cap), LA (clay cap), MO (soil cap), ND (clay or synthetic cap), NM (synthetic 

cap), OK (clay or synthetic cap), PA (clay or synthetic), TN (synthetic cap). Four states require closure controls only at newly 

constructed surface impoundments: CO (clay or synthetic cap), MI (clay or synthetic cap), NC (soil cap), WI (synthetic cap). 

x Of the 34 state regulations reviewed, 23 states require immediate compliance with closure control requirements for landfills: AL 

(synthetic cap), CO (clay cap), GA (soil cap), IA (clay cap), IN (clay cap), KS (soil cap), KY, MD (clay cap), MI (clay or synthetic 

cap), MN (clay cap), MO (soil cap), MT (clay cap), NC (soil cap), ND (clay or synthetic cap), NY (synthetic cap), OH (synthetic

cap), PA (synthetic cap), SC (synthetic cap), TN (clay cap), TX (synthetic cap), UT (soil cap), VA (synthetic cap), and WA (synthetic 

cap). Nine states require closure controls only at newly constructed landfills: FL (synthetic cap), IL (clay or synthetic cap), LA (clay 

cap), MS (soil cap), NV (soil cap), OK (clay cap), WI (clay cap), WV (soil or clay cap), WY (synthetic cap). 
48 

9. Post-closure monitoring requirements 

x Of the 34 state regulations reviewed, 11 states require immediate compliance with post-closure groundwater monitoring requirement for 

surface impoundments: AZ, LA, MO, ND, NM, NV, NY, OK, SC, TN, UT. Seven states require post-closure groundwater monitoring 

only at newly constructed surface impoundments: CO, KY, MI, NC, PA, WI, WV. 

x Of the 34 states reviewed, 22 states require immediate compliance with post-closure groundwater monitoring requirements for landfills: 

AL, CO, GA, IA, KS, KY, MD, MI, MN, MO, MT, ND, NY, OH, PA, SC, TN, TX, UT, VA, WA, WY. Eight states require post-closure 

groundwater monitoring at newly constructed landfills: FL, IL, LA, MS, NV, OK, WI, WV. 

10. Baseline storage tank/container design and operating standards 

The baseline storage tank /container design and operating standards were not evaluated in this RIA because of a lack of data about the baseline 

count and conditions of CCR storage or treatment tanks, containers, and containment buildings at electric utility plants 

x Industry Baseline CCR Disposal Characterization Findings 

Appendix F of this RIA presents on a plant-by-plant basis the baseline engineering controls assumed for each of the 383 of the 495 electric 

utility plants which onsite dispose CCR (84 plants solely dispose CCR offsite; this RIA assumes that all offsite CCR disposal units are landfills, 

and further assumes that all of those offsite landfills currently comply with the engineering controls described in this RIA for the regulatory 

options). Exhibits 3I (for landfills) and Exhibit 3J (for impoundments) below summarize the assignment of baseline conditions in this RIA 

for these 411 plants which dispose CCR onsite. 
49 

Exhibit 3I 

Baseline Compliance with State Government Engineering Control Requirements: CCR Landfills 

A B C D E F G H 

Future new CCR landfills Existing CCR landfills 

Current or State Regulated 

Engineering control 

No. of 

Plants 

Percent of 

311 plants 

with LFs 

Volume of 

CCR diposed 

in landfills 

(tons/year) 

% of 71.8 

million tons 

onsite + offsite 

LF 

No. of 

Plants 

Percent of 

311 plants 

with LFs 

Volume of 

CCR disposed 

in landfills 

(tons/year) 

% of 71.8 million 

tons onsite + 

offsite LF 

1. Groundwater Monitoring 302 97%* 69,706,646 97%* 272 81% 60,623,231 85% 

2. Bottom Liner 302 97%* 69,706,646 97%* 238 71% 52,505,314 73% 

3. Leachate Collection System 273 81% 62,696,310 88% 222 66% 49,213,424 69% 

4. Dust Controls 215 64% 40,634,681 57% 205 61% 42,781,444 60% 

5. Run on/Run off Controls 261 77% 60,342,426 84% 209 62% 46,232,440 65% 

6. Financial Assurance 266 79% 56,861,231 79% 231 69% 49,487,222 69% 

7. Site restrictins 1. Water table 98 29% 18,878,963 26% ND ND ND ND 

 2. Floodplains 232 69% 50,072,235 70% ND ND ND ND 

 3. Wetlands 199 59% 40,227,659 56% ND ND ND ND 

 4. Fault areas 72 21% 18,816,363 26% ND ND ND ND 

 5. Seismic zone 66 20% 13,056,165 18% ND ND ND ND 

 6. Karst areas 152 45% 33,970,045 47% ND ND ND ND 

8. Cap Synthetic or Clay 245 73% 52,234,482 73% 213 63% 46,031,621 64% 

Soil 48 14% 10,990,166 15% 50 15% 12,094,140 17% 

Clay/Soil 13 4% 5,419,918 8% 5 1% 3,022,219 4% 

9. Post Closure Monitoring 271 80% 61,444,140 86% 232 69% 53,249,880 74% 

10. Storage design standards ND ND ND ND ND ND ND ND 

Notes: 

ND = Not determined. Comparisons have not been made comparing the date the state site restriction regulation became effective and the date of existing landfill 

construction for each plant. 

* According to the August 2006 DOE/EPA report gCoal Combustion Waste Management at Landfills and Surface Impoundments, 1994-2004h report nr. DOE/PI0004, 286 pp; http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=2008: 

~ 97% of newly constructed CCR landfills have groundwater monitoring (Table 14, p.35) 

~ 97% of newly constructed CCR landfills have liners (Table 13, p.33) 

These percentages reflect a mix of state government permit requirements for some surveyed electricity plants, plus industry voluntary actions for other plants. 
50 

Exhibit 3J 

Baseline Compliance with State Government Engineering Control Requirements: CCR Surface Impoundments 

A B C D E F G H 

Future new CCR impoundments Existing CCR impoundments 

Current or State Regulated 

Engineering control 

No. of 

Plants 

Percent of 

158 plants 

with SIs 

Volume of CCR 

disposed in 

impoundments 

(tons/year) 

% of 22.4 

million tons 

CCR disposed 

in 

impoundments 

No. of 

Plants 

Percent of 

158 plants 

with SIs 

Volume of 

CCR disposed 

in 

impoundments 

(tons/year) 

% of 22.4 

million tons 

CCR disposed 

in 

impoundments 

1. Groundwater Monitoring 123 78%* 17,472,000 78%* 78 49% 9,216,470 41% 

2. Bottom Liner 158 100%* 22,400,000 100%* 62 39% 6,920,820 31% 

3. Leachate Collection System 61 39% 7,676,710 34% 48 30% 5,338,110 24% 

4. Dust control NA NA NA NA NA NA NA NA 

5. Runon/runoff control NA NA NA NA NA NA NA NA 

6. Financial Assurance 63 40% 7,694,010 34% 58 37% 7,327,410 33% 

7. Site restrictns 1. Water table 28 18% 3,039,860 14% ND ND ND ND 

 2. Floodplains 51 32% 6,902,610 31% ND ND ND ND 

 3. Wetlands 34 22% 5,347,550 24% ND ND ND ND 

 4. Fault areas 15 9% 1,675,350 7% ND ND ND ND 

 5. Seismic zone 15 9% 1,675,350 7% ND ND ND ND 

 6. Karst areas 34 22% 5,347,550 24% ND ND ND ND 

8. Cap Synthetic 38 24% 5,911,760 26% 31 20% 4,298,660 19% 

Soil 27 17% 2,490,050 11% 23 15% 2,293,550 10% 

Clay 3 2% 254,800 1% 3 2% 254,800 1% 

9. Post Closure Monitoring 78 49% 9,520,360 43% 65 41% 7,181,760 32% 

10. Storage design standards ND ND ND ND ND ND ND ND 

Notes: 

NA = Not applicable to surface impoundments. 

ND = Not determined. Comparisons have not been made comparing the date the state site restriction regulation became effective and the date of existing surface 

impoundment construction for each plant. 

* According to the August 2006 DOE/EPA report gCoal Combustion Waste Management at Landfills and Surface Impoundments, 1994-2004h report nr. DOE/PI0004, 286 pages; http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=2008: 

~ 78% of newly constructed CCR impoundments have groundwater monitoring (Table 14, p.35) 

~ 100% of newly constructed CCR impoundments have liners (Table 13, p.33) 

These percentages reflect a mix of state government permit requirements for some surveyed electricity plants, plus industry voluntary actions for other plants. 
51 

x Baseline CCR Disposal Cost Estimation 

This section presents baseline cost estimates for both onsite and offsite CCR disposal units (i.e., landfills and impoundments) for 467 of the 495 

electric utility plants which dispose CCR (CCR from the remainder 28 of the 495 plants is solely beneficially used). 

x Cost Estimation Framework 

x Cost calculations: This RIA contains three types of cost estimates (with decreasing relative degrees of expected accuracy): 

o Data-based estimates: Based on a landfill and impoundment engineering controls cost estimation model using relatively 

robust and recent data inputs (e.g., 2005 or newer) pertaining to CCR quantities and disposal methods for individual 

electric utility plants. The cost model was first developed by EPA in 1988 to support EPA_s 1991 final criteria for 

municipal solid waste RCRA Subtitle D landfills, and EPA_s 1999 proposed rule cement kiln dust landfill requirements.45 

The cost model consists of two software components; Appendix G to this RIA provides additional details about the 

model: 

 1st of 2 cost model components: Unit Cost Component: The first component is a Fortran computer programmed 

cost model which dates back to 1988. This model specifies the various steps and physical units (e.g., square 

footage sizes and associated quantities of labor, equipment and materials for the specified sizes) involved in 

designing, constructing, operating, and closing a landfill or impoundment. Then it combines the physical 

component data inputs, with input data on the prices/ costs/ fees for the physical components to estimate as model 

outputs, the capital and annual O&M costs of specified sizes of landfills and impoundments. The unit prices/ 

costs/fees used as input data include a wide range of items, such as the per-acre cost of land, clearing, excavation, 

equipment, labor, bottom liner materials, and cover materials. For this RIA, the model was run multiple times to 

generate individual cost estimates for a series of five alternatively-sized CCR landfills and impoundments with 

varying types of engineering controls to represent the range of sizes and engineering controls in the population of 

495 electric utility plants. The size categories are defined in tons per day of CCR disposed. Each CCR landfill or 

 

45 The 1988 cost model is documented in the gUser_s Manual for the Subtitle D Municipal Landfill Cost Modelh draft report prepared for EPA_s Office of Solid Waste by 

DPRA Inc, Sept 1988, 129 pages which is available from the Federal docket as document ID nr EPA-HQ-RCRA-2006-0796. 

EPA previously publicly referenced this cost model in the following six publications: (a) gDraft Regulatory Impact Analysis for Proposed Revisions to Subtitle D 

Criteria for Municipal Solid Waste Landfills,h prepared for US EPA Office of Solid Waste by Temple, Barker & Sloane, Inc., ICF Incorporated, Pope-Reid Associates (now 

DPRA Inc.) and American Management Systems, Inc., 05 Aug 1988 (this document includes about a 4-page summary of the cost model); (b) gRegulatory Impact Analysis 

for the Final Criteria for Municipal Solid Waste Landfills,h prepared for US EPA Office of Solid Waste by Temple, Barker & Sloane/Clayton Environmental Consultants, 

ICF Inc, DPRA Inc, and American Management Systems, Inc., Dec 1990 (this document includes about a 4-page summary of the cost model); (c) gAddendum to the 

Regulatory Impact Analysis for the Final Criteria for Municipal Solid Waste Landfills,h prepared for US EPA, Office of Solid Waste by Temple, Barker & Sloane/Clayton 

Environmental Consultants and ICF Inc, August 1991; (d) g40 CFR Parts 257 and 258 Solid Waste Disposal Facility Criteria: Proposed Rule,h Federal Register, Vol.53, 

No.168, pp.33314-33422, 30 Aug 1988; (e) gRevised Criteria for Municipal Solid Waste Landfills,h Federal Register Volume 56, pp. 50978, 09 Oct 1991; (f) gTechnical 

Background Document: Compliance Cost Estimated for the Proposed Land Management Regulation of Cement Kiln Dust,h prepared for the US EPA, Office of Solid 

Waste by DPRA Inc, 10 April 1998.; and (g) g40 CFR Parts 259, 261, 266, and 270 Standards for the Management of Cement Kiln Dust; Proposed Rule,h Federal Register

Vol.64, No.161, pp. 45632-45697, 20 Aug 1999. 
52 

impoundment is assumed to operate 300 days per year (average number of operating days for coal-fired boilers 

based on 2005 DOE EIA 767 database). The size categories are 10,000, 50,000, 200,000, 500,000 and 2,000,000 

tons of CCR per year. Size is the primary determinant of overall cost; however, landfills and impoundments 

exhibit increasing returns to scale: the larger the landfill or impoundment, the lower the cost per ton of CCR 

managed. The cost equations generated by these unit cost model runs are used as inputs in the second component 

of the cost model to compute landfill and impoundment cost curves (equations) based on size for each combination 

of engineering controls, so that a unique cost estimate may be assigned to each of the 495 electric utility plants 

according to each plant_s unique annual CCR disposal tonnage. 

 2nd of 2 cost model components: Plant-by-Plant & Aggregate Cost Component: The second component of the 

model is an Excel spreadsheet with Visual Basic programming used to estimate unique baseline (i.e., current) and 

regulatory option costs for each electric utility plant. The spreadsheet is populated with plant-by-plant data 

including plant location, known disposal and beneficial reuse practices, known or estimated baseline engineering 

controls on CCR disposal units, annual CCR disposal tonnages, and known or estimated CCR landfill and 

impoundment future closure years. The spreadsheet is also populated with the cost equations generated by the first 

component of the model for the various engineering controls (e.g., groundwater monitoring and safety inspections) 

and for off-site landfill disposal costs. The Visual Basic programming is used for this RIA to estimate engineering 

control costs for both the (a) baseline and (b) regulatory options for each plant over a 50-year future period-ofanalysis (i.e., 2012 to 2061). The plant-by-plant estimated costs are then aggregated in this second component of 

the model on an average annualized basis. 

o Assumption-based estimates: These are based on relatively limited data, and/or older data (e.g., older than 2005), or metaanalysis transfer of results from other studies, or data from case studies, or based mostly on professional judgment 

assumptions rather than data, for some of the major factors used in cost calculations. 

o Scenario-based estimates: These are applied in absence of data, case studies, or assumptions for purpose of illustrating 

potential lower- and upper-bound costs (i.e., bounding estimates). EPA defines gscenariosh as qualitative projections of 

possible future conditions based on variations in key drivers of change, including social, technological, economic and 

institutional drivers. Scenario construction is a futures analysis method; as such, scenario-based estimates do not strive to 

predict the future with absolute certainty, but to explore uncertainties, possible consequences, and possible outcomes.46

x 2009 price level: Costs are normalized to beginning-of-year 2009 dollars using inflation factors developed by Engineering NewsRecord (ENR) Construction Cost Index, and using regional cost adjustment factors applied to each plant cost 

estimate involving on-site construction. These regional factors account for the variability between states in site work 

and landscape construction costs. Cost adjustment factors are derived from the Means Building Construction Costs 

Year 2003 city factors. All the cities for each state were averaged together to derive a state average. 

 

46 gSource: EPA Office of Science Policy, gShaping Our Environmental Future: Foresight in the Office of Research & Development,h report nr. EPA 600/R-06/150, 2006 

at: http://www.epa.gov/osp/futures/FuturesHandbook.pdf 
53 

x Before-tax costs: Baseline disposal costs estimated on a before-tax basis to approximate the overall economic cost (i.e., real resource 

allocation for the economy as a whole, rather than on an after-tax basis which would approximate a relatively narrower 

financial cost to the electric utility industry because after-tax costs subtract business expense tax deductions and 

depreciation of capital expenditures for pollution control equipment. 

x 50-year period: A 50-year future time horizon (aka period-of-analysis) was applied because new construction for replacement of all 

CCR disposal units and end of existing lifespan is estimated to have occurred at least once by that time. 

x 7% discount rate: A 7% discount rate was applied for calculating both net present value cost and average annualized cost for the 

engineering control unit costs applied in this RIA. Because both the annualized baseline cost and annualized 

incremental proposed rule costs estimated in this RIA consist of primarily (i.e., >95%) industry cost rather than 

government cost, this RIA applies a 7% discount rate rather than a lower (e.g., 3%, 2%, 1% or 0%) discount rate to 

represent the opportunity cost of business capital investment and business expense financing (i.e., the average rate of 

return to corporate capital). This is consistent with OMB_s 2003 Circular A-447 (page 33) and 1992 Circular A-9448

(page 8) which indicate that a 7% discount rate base-case should be used for regulatory analyses when regulation is 

expected to primarily and directly affect businesses and industries. 

x 0.73% growth: Baseline cost estimates increased 0.73% per year over the 50-year future time horizon to reflect a 0.73% annual

growth in coal consumption at electric utility plants (which is a proxy for future annual growth in the annual tonnage of 

CCR generation needing disposal from those plants). The 0.73% annual growth factor is based on DOE-EIA's January 

2009 "Annual Energy Outlook 2009" forecast change in US coal consumption for electricity generation between year 

2010 (22.91 quadrillion Btus) and 2030 (26.41 quadrillion Btus), available at: 

http://www.eia.doe.gov/oiaf/aeo/index.html

x Beneficial use: If reported in the baseline by any particular plant, beneficial use was assumed to continue in the future by that plant 

under the baseline projection over the 50-year future period-of-analysis. Section 5C in Chapter 5 of this RIA 

evaluates potential changes to this beneficial use baseline under alternative regulatory impact scenarios. 

x Offsite disposal: If reported in baseline by any particular plant, offsite disposal was assumed to continue in the future by that plant. 

Offsite disposal landfill cost estimated under both baseline and regulatory options using the engineering control cost 

model. Truck operating cost estimated separately outside of the model. 

x Existing unit closure: One set of years for the opening and closure of disposal units are assumed for each facility. If data for initial year of 

operation were provided in the 1995 EPRI Comanagement Survey, these data were used. If the plant had more than 

 

47 2003 OMB Circular A-4: http://www.whitehouse.gov/omb/circulars_a004_a-4/ 48 1992 OMB Circular A-94: http://www.whitehouse.gov/omb/circulars_a094/ 
54 

one disposal unit and more than one reported date for initial year of operation, the years were averaged. For example, 

if a facility had three disposal units (2 landfills and 1 impoundment) with installation dates of 1970, 1980, and 1990, 

this RIA assumed the installation date of all the units was 1980. This assumption simplified the cost calculations on a 

per facility basis instead of a per disposal unit basis. If no disposal unit installation data were available, the installation 

year is assumed to be equal to the earliest boiler installation year reported in either the 2007 EIA 860 database for that 

plant or 1998 EIA 767 database, whichever was older. If no disposal unit or boiler installation year data were 

available, an installation year of 1980 was assumed. If the 1995 EPRI Comanagement Survey provided a forecasted 

closure year for a unit, new unit installation is assumed to occur in that year. Otherwise, if no closure forecast year is 

provided, closure is assumed to occur 40 years after the year of installation (assumed average lifespan for CCR landfills 

and impoundments). 

x New unit construction: The timing of when baseline state regulatory requirements for newly constructed units begin to be incurred depends 

on the installation and closure date for the existing disposal units. Baseline state regulatory cost requirements are 

incurred at the closure date of the disposal unit when new unit construction occurs. For example, if a plant_s disposal 

unit is assumed in this RIA to close in 2019; new unit construction costs required under state regulations are incurred 

over its assumed 40-year future lifespan beginning in 2020. 

x New landfills: The most economic of three landfill options v (1) combination landfill with 50% of waste below 

ground and 50% above ground, (2) pile landfill with 5 % of waste below ground and 95% above ground, or (3) 

offsite landfill -- is determined within the cost model. The cost for the most economical approach is assigned to 

that plant unless available data specify otherwise. The choice is dependent upon on estimated engineering 

control costs and annual CCR disposal tonnage. 

x New impoundments: If currently used as a disposal unit, this RIA assumes a landfill will be constructed as the 

future new disposal unit as impoundments reach end of lifespan, because the model calculates that new landfills 

are more economical to construct for two cost reasons: (a) if no pre-existing land depressions for use as a new 

impoundment, the cost for a larger excavation for a new impoundment rather than a smaller excavation for a 

landfill is necessary, and (b) the primary determinant of many of the cost for engineering controls is the footprint 

of the disposal unit such that the same set of engineering controls for a new impoundment would be more 

expensive than for a new landfill. However, the cost model does not estimate the associated capital and annual 

O&M costs for future conversion of existing wet ash and wet scrubber boilers and conversion of wet CCR 

conveyance equipment used for moving CCR to disposal units. These conversion costs are estimated separately 

outside of the cost model in this RIA. 
55 

x Baseline “Engineering Control” Cost Estimates 

1. Baseline ground water monitoring 

Groundwater monitoring costs are based on the Remedial Action Cost Engineering and Requirements (RACER) cost estimating software 

(2002) with costs based on the R.S. Means, Environmental Cost Handling Options and Solutions (ECHOS), Environmental Remediation Cost 

Data (2002). 

 Assumes same groundwater monitoring requirements for both landfills and impoundments 

 Point of compliance: 

Placement at the unit boundary is assumed in the cost estimates. Unit boundary point-of-compliance monitoring complies with the gwithin 

150 meter point-of-complianceh criterion. Plants monitoring at the unit boundary will incur no additional costs under the within 150 meter 

placement criteria. 

 Number of wells: 

EPA_s March 1985 gGround Water Technical Enforcement Guidanceh Document (pages 2-8 to 2-16) recommends a maximum of 150 feet 

spacing between down-gradient wells. EPA_s December 1980 SW-611 gProcedures Manual for Groundwater Monitoring at Solid Waste 

Disposal Facilitiesh (pages 40 to 43) recommends a maximum of 250 feet spacing between down-gradient wells. Assuming the technical 

documents are the most stringent and the state regulation minimums are the least stringent, a middle ground within the range is anticipated 

and used in the cost estimates. This RIA does not evaluate the cost differences between the upper and lower bounds of well spacing. 

Groundwater monitoring well costs in this analysis assume a minimum of 2 down-gradient wells for the first 800 feet of length along two 

sides of the landfill or impoundment unit, which is assumed to be square, plus additional wells spaced every 400 feet. In addition, one upgradient well is assumed. 

 Constituents: 

The cost estimates include monitoring for the following chemical indicators and metals, which represents a reasonable glikely-caseh 

scenario between indicators only and RCRA 40 CFR 261 Appendix VIII constituent monitoring which includes about 500 chemical 

substances: 

o Chemical indicators: Based on EPA_s 1999 cement kiln dust proposed rule parameters (i.e., pH, conductivity, total dissolved solids, 

potassium, chloride, sodium, and sulfate) as a cost proxy. 

o Metals: Metals with primary and secondary Maximum Contaminant Levels (MCLs) (i.e., Al, Cu, Fe, Mn, Ag, Zn, Sb, As, Ba, Be, Cd, 

Cr, Pb, Hg, Se, Tl). 

 Frequency: 

The cost estimates only include semi-annual sampling (most-likely case) analogous to EPA_s 1999 cement kiln dust proposed rule and to 

many current state regulations, even if some states require a quarterly or annual basis. 

 Unitized cost estimate: Dividing the average annual cost estimate result displayed in Exhibit 3L below (row item 1) for baseline ground 

water monitoring, by the count of electric utility plants estimated in Exhibit 3I (row 1, column A) and Exhibit 3J (row 1, column A) above 

to conduct that activity under state government requirements, yields an average annual per-plant (i.e., unitized) cost estimate of $64,000. In 

comparison, EPA_s most recent (2008) Information Collection Request (ICR) No. 0959.13 gGround-Water Monitoring Requirementsh 

(renewal) for the RCRA Subtitle C 40 CFR 264.92 and 265.92 TSDF gground-water protection standardh provides an estimate of $28,130 
56 

per year.49 The $64,000 unitized cost for groundwater monitoring generated by the above assumptions applied in the engineering control 

cost model used for this RIA is 2.3 times larger and more appropriate to this RIA because it reflects a larger number of wells per-plant to 

monitor the groundwater under the larger sized CCR disposal units compared to the average sizes of other types of industrial waste disposal 

units. 

2. Baseline bottom liners 

 Same bottom liner requirements for both new landfills and new impoundments 

 The cost estimates include a composite (2-foot compacted clay-synthetic) liner for the more stringent design and a 2-foot compacted clay 

liner, single-synthetic liner, and a 2-foot compacted ash liner for less stringent baseline designs. 

3. Baseline leachate collection system 

 No leachate collection is assumed from beneath the impoundment liner 

 The cost estimate is comprised of perforated pipes spaced approximately 300 feet apart along the base of the unit. It includes a wet well for 

leachate collection. Leachate is shipped by truck for off-site treatment. 

 Assumes 3-inches of leachate per year collected in landfill leachate collection systems. 

4. Baseline dust controls 

Cost estimate includes CCR compaction equipment, water trucks for spraying CCR during compaction and for spraying unpaved landfill roads, 

and covers for landfill trucks: 

 Compaction Equipment 

Ash is assumed to be compacted in the waste management area by self-propelled rollers for regulatory scenarios including dust controls. A 

model cost assumption is that four passes are made by the roller in 6-inch lifts. With these assumptions, the roller can compact 

approximately 1,300 cy of ash per day. The operating life of purchased compaction equipment is assumed to be five years. The number of 

sheepsfoot rollers required is estimated as follows: 

Rollers = (tons/yr)(2,000 lb/ton)(16.02 kg/m3 / lb/cf)

(1,190 kg/m3)(27 cf/cy)(1,300 cy/day)(300 days/yr) 

The cost of a sheepsfoot roller is assumed to be $75,000 in 1995 dollars. 

Plants will incur annual costs for equipment operation ($0.63/cy) and maintenance. 

Maintenance costs are assumed to be 5% of capital costs. Annual costs for compaction are estimated as follows: 

Annual Cost = (tons/yr)(2,000 lb/ton)(16.02 kg/m3 / lb/cf)($0.63/cy) + $75,000*0.05*Rollers 

(1,190 kg/m3)(27 cf/cy) 

x Water Truck for Compaction: 

Ash is assumed to be wetted in the waste management area by water trucks to facilitate compaction and to control dust. A model assumption is 

that FFC plants currently use water trucks 50% of the operational day to control dust on roads (see Water Spray on Roads). It is reasonable to 

 

49 $28,130 per year per-facility average cost derived for purpose of this RIA by dividing the reported $27.818 million annual cost by the reported 989 TSDFs from the EPA 

ICR 0959.13, Federal Register, Vol.73, No.103, page 30617; 28 May 2008; http://edocket.access.gpo.gov/2008/pdf/E8-11888.pdf 
57 

assume that the same water trucks will be used for the roads and the ash management unit. Therefore, it is assumed that an existing water truck 

is available for compaction 50% of the operational day. Additional water trucks are assumed to be necessary to facilitate compaction for large 

facilities. The cost of tarps, tarp mechanisms, and installation of the mechanisms, as well as the life of each tarp were estimated by ICF in gCost 

Functions for Alternative CKD Control Technologiesh (Draft), 19 July 1996. A model assumption is that a water truck will be necessary for 

compaction 50% of the time required by the compaction equipment. The water truck time for compaction is estimated as follows: 

Water Truck Time for Compaction = (tons/yr)(2,000 lb/ton)(16.02 kg/m3 / lb/cf)(8 hr/day)(0.5)

(1,190 kg/m3)(27 cf/cy)(1,300 cy/day) 

One existing water truck for compaction and water spray on roads is estimated to be sufficient for plants managing less than 391,000 tons per 

year of ash. Facilities managing between 391,000 and 1,173,000 tons per year are assumed to purchase one additional water truck. Facilities 

managing between 1,173,000 and 1,955,000 tons per year are assumed to purchase two additional water trucks. Facilities managing more than 

1,955,000 tons per year to the maximum facility size modeled of 2,000,000 tons per year are assumed to purchase three additional water trucks. 

The cost of a water truck is assumed to be $101,000 in 1995 dollars. The water truck operating life is assumed to be five years. The operating 

costs for water spray for compaction are estimated assuming that the truck travels approximately five miles per day, for each day used, with a 

fuel consumption of five miles per gallon at a fuel cost of $1.15 per gallon. The truck is assumed to operate 50% of the hours required for 

compaction. The daily water volume used is assumed to be 10,000 gallons, at a cost of $2 per 1,000 gallons. The annual cost associated with 

ash management is estimated as follows: 

Annual Cost = (tons/yr)(2,000 lb/MT)(16.02 kg/m3 / lb/cf)(0.5) * [(8hr/day)($31.50/hr) 

(1,190 kg/m3)(27 cf/cy)(1,300 cy/day) 

+ (5 mi/day)($1.15/gal)/(5 mi/gal) + (10,000 gal/day)($2/1,000 gal)] 

x Covers on Trucks: 

Covers on hauling trucks as a fugitive dust control technology is an option for the compliance scenarios. Capital costs for this dust control 

technology include the cost of the roll-on tarp mechanism and the installation of this mechanism. Capital costs for covers on trucks are 

estimated as follows: Capital Cost = [(tons/year) x (2,000 lb/ton) x (16.02 kg/m3 / lb/cf) x (0.65 hr/load)] x ($4,800) 

Water truck capacity, refill time, and spray width were estimated by ICF in gCost Functions for Alternative CKD Control Technologiesh 

(Draft), dated July 19, 1996. 

(1,190 kg/m3)(0.80)(27 cf/cy)(9 cy/load)(2,400 hr/yr) 

Annual costs for this dust control technology include the cost of the tarps and the cost to replace the tarps. Tarps are estimated to be replaced 

every 150 loads. Replacement of a tarp is estimated to require 15 minutes. Annual costs for covers on trucks are estimated as follows: 

Annual Cost = (tons/yr)(2,000 lb/ton)(16.02 kg/m3 / lb/cf)($155/tarp + 0.25hr/tarp*$19/hr)

(1,190 kg/m3)(0.80)(27 cf/cy)(9 cy/load)(150 load/tarp) 

x Water Spray on Roads: 

Water spray on roads is required as a fugitive dust control technology for the compliance scenarios. A model assumption is that FFC plants 

currently have water trucks and use water spray on roads as a baseline management practice. A model assumption is that dust control is 

required for a road length of 1.5 miles (3 miles roundtrip), with a road width of 10 meters. The water truck capacity is assumed to be 5,000 

gallons and requires approximately one hour to fill. The water truck can spray a width of five meters at an assumed speed of 10 miles per hour. 

For the baseline scenario, a model assumption is that the entire water volume (5,000 gallons) will be sprayed on each pass of the truck along 

one side of the road (i.e., 1.5 miles x 5 meters). The resulting water volume per road area, averaged over the 1.25 hours required to spray the 
58 

road and refill the truck, is approximately 2.5 times that of the average hourly daytime evaporation rate. Therefore, water spray on roads will be 

required 3 times per day. The water volume sprayed per road area is estimated as follows: 

Water per Area = (1.5 mi)(5,280 ft/mi)(0.3048 m/ft)(10 m)(5,000 gal)(3.785 L/gal) = 0.784 L/m2 

The time required for the water truck to be filled, spray along both sides of the road, and return for refilling is estimated as follows: 

Time = (1 hour) + (3 miles)/(10 miles/hour) = 1.3 hour 

Therefore, the total time for one pass is assumed to be 1 hour and 15 minutes. The average rate of water spray is estimated as follows: 

Spray Rate = (0.784 L/m2)(1,000 ml/L)(cm3/ml)(1,000 mm/m) = 0.6272 mm/hr 

(100 cm/m)3(1.25 hr) 

The average hourly daytime evaporation rate is approximately 0.25 mm/hr. Therefore, the water spray rate is approximately 2.5 times the 

evaporation rate. Since the total time required for water spray (1.25 hour) times 2.5 is approximately 3, a model assumption is that water spray 

on roads is required approximately every 3 hours. In order to coordinate the water truck use for road spray and ash compaction, it is assumed 

that the truck alternates between these two requirements during the day. Therefore, over a nine-hour day (eight working hours plus one hour for 

lunch), roads are sprayed 3 times, requiring a total of approximately 4 hours, or 50% of the operational day. Because it is assumed that FFC 

facilities currently spray water on roads for dust control, the incremental cost from the baseline to the compliance scenarios is zero. 

5. Baseline rain and surface water run-on/run-off controls (landfills only) 

The cost estimates assume that stormwater run-on/run-off control is comprised of a ditch surrounding active area of landfill and an excavated 

bermed basin for water collection. 

6. Baseline financial assurance for CCR disposal unit closure and post-closure care 

Financial assurance helps assure that the owners and operators of CCR landfills and impoundments have adequately planned for the future cost 

of closure, post-closure care, and corrective action for known releases, and to assure that adequate funds will be available when needed to cover 

these costs if the owner or operator is unwilling or unable to do so. Financial assurance helps protect future generations from paying for 

damages caused by or the prevention of damages potentially created from current waste management activities. Requiring provision of 

financial assurance during operation of landfills and impoundments places the cost burden on the current owner and consumer, and prevents 

costs from being passed from the current generation to future generations. 

 The cost estimate includes the costs for selecting a financial mechanism, establishing a financial test, and establishing a letter of credit. 

The differences between RCRA Subtitle C and Subtitle D financial assurance mechanisms are not assessed. This RIA assumes the same 

requirements for both landfills and impoundments: 

x Capital cost includes selection of financial assurance mechanism, establishment of financial test, and establishment of letter of credit. 

The letter of credit is assumed to be most available to utilities and will be utilized in most circumstances. This is amortized in the annual 

cost. 

x Annual cost includes maintenance of financial test and maintenance of letter of credit. Establishment and annual maintenance of the 

letter of credit is estimated to be 1% to 3% of the nominal value of the letter of credit (i.e., total cost of closure and post closure). This RIA 

applied the 2% midpoint of this range. Implementation costs are estimated on the assumption that an outside consulting firm and legal 

assistance will assist in obtaining and maintaining the letter of credit ($692 per year in 1995 dollars or $1,051 per year inflated to 2009 

dollars). Estimate obtained from Mohammad Iqbal and John Collier, ICF, Inc., gLocal Government Financial Test Economic Analysis,h 
59 

memorandum to George Garland, EPA, 30 April 1995. Additional supporting information obtained from EPA gEstimating Costs for the 

Economic Benefits of RCRA Noncompliance,h September 1997. 

7. Baseline disposal unit location restrictions 

Baseline cost not estimated in this RIA. 

8. Baseline closure capping to cover unit 

The cost estimate for this engineering control does not include the closure plan cost or closure certification costs. Capping costs are a large 

capital expense. So, if a unit is expected to close in one year the total capping cost is assigned to the last year in the life of the unit. However, 

businesses are likely to borrow money from a bank for these large capital costs and annualize them over a set period of time, for example, 10 or 

20 years. Incremental cost estimates in the cost model are overestimated for large capital expenditures applied to existing units that have been 

added over short time periods. In addition, owners are likely to close these units prior to the proposed rule coming into effect if promulgated as 

a final rule. This RIA assumes the same requirements for both landfills and impoundments: 

 Synthetic cap with drainage layer is comprised of a 60 mil HDPE synthetic liner, 1 foot sand, filter fabric, 1.5 foot slope and earth fill, 0.5 

foot topsoil, and vegetation. It includes a perforated pipe for drainage collection. 

 Synthetic cap without drainage layer is comprised of a 60 mil HDPE synthetic liner, 1.5 foot slope and earth fill, 0.5 foot topsoil, and 

vegetation. 

 Clay cap is comprised of 2 feet of off-site clay, 0.5 foot topsoil, and vegetation. Cover costs would be lower if on-site clay is available. 

 Soil/clay cover is comprised of 0.5 foot clay, 0.5 foot earthfill, and 0.5 foot topsoil, and vegetation. Cover costs would be lower if on-site 

clay is available. 

 Soil cap is comprised of a 1.5 foot slope and earth fill, 0.5 foot topsoil, and vegetation. The slope of the cap is assumed to be 0.02:1 (rise:run) 

with a cover toe slope of 4:1 (run:rise). 

9. Baseline post-closure groundwater monitoring requirements 

 Same requirements for both landfills and impoundments 

 Baseline post-closure monitoring is assumed to comprise 30 years of groundwater monitoring and surface water monitoring on a semi-annual 

basis. The physical parameters (i.e., point of compliance, number of wells, sets of chemical indicators and sets of chemical constituents 

monitored, and semi-annual frequency) and unit cost are assumed identical as defined in the baseline groundwater monitoring cost item 1 

above in this section of the RIA. 

 However, post-closure monitoring costs are estimated in this RIA assuming an annual sum is placed in a fund by affected entities (i.e., electric 

utility owners) during the assumed average 40-year operating life of the CCR disposal unit. At the time of closure sufficient monies will be 

available in the fund to cover post-closure monitoring for the next 30 years beyond end-of-lifespan, assuming an annual interest rate of 7%. 

10. Baseline storage tank/container design and operating standards 

Baseline cost not estimated in this RIA 
60 

x Baseline “Ancillary Costs” Estimates 

11. Baseline offsite disposal 

The baseline cost for engineering controls at offsite CCR disposal sites (assumed in this RIA to be commercial Subtitle D landfills) is estimated 

using the same cost model as the engineering controls for onsite disposal units. In addition, the offsite disposal baseline cost includes the cost 

for truck transport from the electric utility plant to the offsite landfill, calculated as follows: 

 Baseline Assumptions: 

o 12% (15 million tons/year) CCR currently trucked offsite to non-haz LFs (2005) 

o 6 miles average one-way trucking distance to offsite LFs50

o $0.10/ton/mile non-haz waste truck operating cost 

o 12 tons CCR per full truckload (source: Gambrills MD case study); (15 million tons/year) / (12 tons/load) = 1.25 million truckloads 

per year 

 Baseline Cost Calculations: 

o Manifest cost: $0 

o Trucking cost: (15 million tons/year) x (6 miles) x ($0.10/ton/mile truck operating cost for non hazmat) = $9.0 million/year 

12. Baseline structural integrity inspections 

Assumptions: 

Baseline assumption is that 82% of CCR disposal units at electric utility plants are inspected (source: page 36 of joint DOE/EPA report gCoal 

Combustion Waste Management at Landfills and Surface Impoundments, 1994-2004h, report nr. DOE/PI-0004, Aug 2006 at: 

http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=2008). Per-plant cost for inspections estimated in Exhibit 3K below. 

Cost Calculation: 

Industry cost: ($10,829/year per facility) x (82% inspected) x (495 plants) = $4.40 million per year 

State government cost: ($599/year per facility) x (82% inspected) x (495 plants) = $0.24 million per year 

Total (industry + state) = $4.64 million per year 

 

50 Source: based on actual distance reported for a MD plant at http://www.rachel.org/en/node/445). Note: a broader range of 2.4 miles to 25 miles in one-way offsite landfill 

distance was reported by an OH plant at http://www.columbusdispatch.com/live/content/local_news/stories/2008/04/14/Powerfills.ART_ART_04-14-

08_B1_FF9TI0U.html?sid=101, and a WI plant, respectively at http://www.lacrossetribune.com/articles/2007/09/21/news/03landfill0921.txt 
61 

Exhibit 3K 

Summary of Industry & State Government Labor Costs for MSHA Surface Impoundment Safety Plan & Annual Inspections 

& Estimate of Annual Costs for Similar Structural Integrity Activities for Electric Utility Plant Surface Impoundments 

Item Paperwork Burden Element* Labor hours Cost (2006) Cost per facility Annualized 

Industry Costs 

1 Impoundment Safety Plan prepared by mining company engineer 

>>> Purpose: To evaluate geotechnical, hydrologic, hydraulic & other 

engineering factors to construct or improve surface impoundment structures to 

avoid structural failures 

1,300 $70.07/hr $91,091 $9,109 

2 Revisions to Impoundment Safety Plan prepared by mining company engineer2 40 $70.07/hr $2,803 $280 

3 Fire Extinguishing Plan prepared by mining company engineer or supervisor 20 $70.07/hr $1,401 $140 

4 Annual Status Report & Annual Certification prepared by company engineer 

>>> Purpose: To determine whether impoundments are operated and maintained 

according to approved engineering safety plan 

2 $70.07/hr $140 $14 

5 Recordkeeping and weekly inspections3 

>>> Purpose: To determine whether any signs of instability have developed 

2.5 hrs per inspectn x 

17 inspect = 42.5 

$30.27/hr $1,286 $1,286 

Subtotal (Industry costs): $10,829 per facility per year 

State Government Costs 

6 Review of Impoundment Safety Plans 160 hrs tech review + 

2 hrs admin review 

$30.57/hr $4,952 $495 

7 Review of revisions to Impoundment Safety Plans 30 hrs tech review + 

2 hrs admin review 

$30.57/hr $978 $98 

8 Review and prepare responses for impoundment abandonment plans 1 $30.57/hr $31 per plan $3 

9 Review of annual inspection Status Reports and Certifications 1 $30.57/hr $31 per report $3 

Subtotal (State government costs): $599 per facility per year 

Total Cost 

Total industry + state government cost: $11,428 per inspection 

Notes: 

* Elements, labor hours, and labor costs are based on the gSupporting Statementh for the March 2008 DOL/MSHA ICR 12-19-0015, gRefuse Piles and Impounding 

Structures, Recordkeeping, and Reporting Requirementsh at: http://www.msha.gov/regs/fedreg/paperwork/2004/04-24046.pdf 

1. Assumes plans are valid for 10-years similar to the length of RCRA permits. 

2. Assumes one revision to the plan will be made during 10-years. 

3. Average labor hours per inspection between inspections at sites with monitoring instruments (3 hours) and at sites without monitoring instruments (2 hours). 
62 

13. Baseline RCRA facility-wide investigations (RFI) 

Baseline cost assumed to be $0 because this RIA assumes that all baseline CCR disposal units used by electric utility plants are not regulated 

under RCRA Subtitle C. 

14. Baseline facility-wide corrective action 

Because CCR is not regulated as Subtitle C hazardous waste, there are no existing facility-wide (i.e., CCR disposal units plus other waste units 

also located at the same plant) corrective action requirements, although some state governments have the following unit-specific corrective 

action requirements affecting CCR disposal units. 

State regulations for the top 25 coal usage states (for electricity) were reviewed for correction action requirements in 2000. These regulations 

were not updated as part of this RIA. Corrective action requirements were identified in 21 of the 25 states. 

x Surface impoundments: 71% of CCR impoundments representing 67% of CCR impoundment annual tonnage have state government baseline

corrective action requirements: 

o AZ, IN, and IA establish a corrective action alert level and response action in site-specific state permits 

o CO requires corrective action for new units 

o 9 states (FL, GA, KY, MI, NC, ND, PA, UT, WI) require corrective action 

o IL, MN, TX, WV, WY do not allow groundwater degradation, but specific enforcement mechanisms are not specified in state 

regulations 

o MO requires corrective action for units closed with waste in place, otherwise, corrective action may be established under a permit 

o NM requires an abatement plan. 

x Landfills: 66% of CCR landfills with 81% of CCR landfill annual tonnage have state government corrective action requirements: 

o AZ establishes corrective action alert level and response action in site-specific state permits 

o 15 states (CO, FL, GA, IL, KY, MI, NC, ND, OH, OK, PA, UT, WV, WI, WY) require corrective action 

o MN, TX do not allow groundwater degradation, but, specific enforcement mechanisms are not specified in state regulations 

o MO, TN require assessment only 

o NM requires an abatement plan 

15. Baseline waste disposal permit cost 

x Assumptions: 

o 93% of CCR landfills have a state government non-hazardous waste disposal permit and 12% of CCR impoundments have such 

permits. Source: page 28, Table 9 of gCoal Combustion Waste Management at Landfills and Surface Impoundments, 1994-2004h, 

August 2006 at http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=2008

x Industry waste disposal permit cost: 

o ($5,000 RCRA Part A permit) + ($50,000 RCRA general facility permit requirements) + ($25,000 average RCRA Part B for 

impoundment or landfill) = $80,000 per Subtitle C permit 

o Assume RCRA Subtitle D (40 CFR 257, 258) waste permitting activities are less burdensome than RCRA Subtitle C waste 

permits. Based on factor of 3.3 times more technical standards listed in RCRA Subtitle C (40 CFR 264/265, 268, 270) compared to

Subtitle D (40 CFR 257, 258), assume Subtitle D permitting costs are lower by the 3.3 factor: 
63 

($80,000 per year average Subtitle C waste disposal permit cost) / (3.3) = $24,300 per non-haz waste disposal permit 

[((93% landfills w/permit) x (337 landfills)) + ((12% impoundments w/permit) x (158 impoundments))] x ($24,300 per permit) = 

$8.1 million 

 Amortized industry cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $0.59 million/year 

x State government waste disposal permit cost: 

o Build estimate based on the following four RCRA Subtitle C permit-related state government activities associated with RCRA 

Subtitle C waste disposal permits:51

(1,215 pre-application activities) + ($27,063 application review) + ($26,846 permit issuance) + ($3,110 permit maintenance) = 

$58,200 average cost per Subtitle C waste disposal permit. 

o Assume RCRA Subtitle D (40 CFR 257, 258) waste permitting activities are less burdensome than RCRA Subtitle C waste 

permits. Based on factor of 3.3 times more technical standards listed in RCRA Subtitle C (40 CFR 264/265, 268, 270) compared to

Subtitle D (40 CFR 257, 258), assume Subtitle D permitting costs are lower by the 3.3 factor: 

($58,200 per year average Subtitle C waste disposal permit cost) / (3.3) = $17,600 per non-haz waste disposal permit 

o State Cost Calculation: 

[((93% landfills w/permit) x (337 landfills)) + ((12% impoundments w/permit) x (158 impoundments))] x ($17,600 per permit) = 

$5.85 million 

Amortized state cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $0.42 million/year 

 Total baseline permit cost (industry + state government) = $1.01 million per year 

16. Baseline enforcement inspection 

Not estimated in this RIA. 

17. Baseline remediation of environmental releases 

Not estimated in this RIA. 

 

51 Source: Based on cost data from page 84 of January 2007 ASTSWMO report gState RCRA Subtitle C Core Hazardous Waste Management Program Implementation 

Costs Final Reporth at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20Core%20Project.pdf 
64 

x Baseline CCR Disposal Cost Estimation Results 

Exhibit 3L below displays the average annualized costs for each of the baseline cost components, as well as on an average per-ton and perplant basis. Appendix H provides plant-by-plant and owner entity-by-entity estimates of baseline costs. 

Exhibit 3L 

Industry Baseline Cost Estimates for CCR Disposal by Electric Utility Plants (Onsite + Offsite) 

($millions per year in 2009$ discounted @7% over 50-year period-of-analysis 2012 to 2061) 

Baseline Cost Element CCR Landfills (311 plants) CCR Impoundments (158 plants) Row totals (467 of 495 plants) 

A. Engineering controls (onsite disposal): 

1. Ground water monitoring $19.2 $8.0 $27.2 0.5% 

2. Bottom liners $2,751 $1,219 $3,970 71.5% 

3. Leachate collection system $105.5 $52.2 $157.7 2.8% 

4. Dust controls $24.2 $2.8 $27.1 0.5% 

5. Water run-on/run-off controls $4.8 $0.7 $5.6 0.10% 

6..Financial assurance $61.2 $17.9 $79.2 1.4% 

7. Disposal location restrictions Not estimated Not estimated Not estimated 

8. Closure capping to cover unit $72.7 $15.7 $88.5 1.6% 

9. Post-closure groundwater monitoring $1.3 $0.5 $1.8 0.03% 

10. Storage design/operating requirements Not estimated Not estimated Not estimated 

Subtotal Engineering Control costs = $3,040 $1,317 $4,357 78% 

B. Ancillary costs for CCR disposal: 

11. Offsite disposal (commercial landfills) $1,193 $0 $1,193 21.5% 

12. Structural integrity inspections $2.46 $2.18 $4.64 0.08% 

13. RCRA facility-wide investigation (RFI) $0 $0 $0 0% 

14. Corrective action Not estimated Not estimated Not estimated NE 

15. Waste disposal permits $0.69 $0.32 $1.01 0.02% 

16. Enforcement inspection Not estimated Not estimated Not estimated NE 

17. Remediation of environmental releases Not estimated Not estimated Not estimated NE 

Subtotal Ancillary costs = $1,196 $2.5 $1,199 22% 

Cost Summary (A+B) 

Column total annualized cost = $4,236 $1,320 $5,556 

(includes $1,193 offsite disposal) 

PV = $76,678 (@7%, 50-years) 

Average annual cost per plant = $13.6 million per plant $8.4 million per plant $11.9 million per plant 

Average cost per CCR ton disposed = $59 per ton 

(71.8 million tons per year) 

$59 per ton 

(22.4 million tons per year) 

$59 per ton 

(94.2 million tons/year disposed) 
65 

x Validity Check of Baseline Cost Estimate (2 Tests): 

o Validity Test #1 of 2: Comparison to ACAA Published Estimate of Average CCR Disposal Cost 

As displayed above in Exhibit 3L the estimated baseline (i.e., current) average annualized cost to the 495 coal-fired electric utility plants for 

disposal of CCR is $5.6 billion per year (2009$). This annualized cost includes amortization of capital investment in construction of disposal 

units and associated equipment (i.e., in-plant equipment for extracting CCR from boilers, CCR storage equipment, CCR conveyance equipment 

such as slurry pipelines for wet CCR or trucks and mechanical conveyor belts for dry CCR, and the disposal units themselves), plus annual 

expenditures for operation, maintenance and replacement/expansion of this equipment and disposal units. On a unitized cost-per-ton basis -- 

calculated by dividing the annualized baseline cost by the estimated 94.2 million tons per year (as of 2005) CCR disposed in (a) onsite landfills 

plus (b) offsite landfills plus (c) impoundments annually v the estimated baseline cost represents an average unitized cost of $59 per-ton. 

In comparison, the American Coal Ash Association (ACAA) estimates that the average unit cost (per-ton) for baseline disposal of CCR by 

coal-fired electric utility plants ranges as low as $3 per-ton to higher than $40 per-ton: 

"As one can see, a variety of factors enter into determining disposal costs. The lowest cost occurs when a disposal site is 

located near the power plant and the material being disposed can be easily handled. If the material can be piped, rather than 

trucked, costs are usually lower. In these types of situations, cost may be as low as $3 to $5 per ton. In other areas, when 

distance is far away and the [CCR] must be handled several times due to its moisture content or volume, costs could range from 

$20 to $40 per ton. In some areas, the costs are even higher. If new sites are required and extensive permitting processes take 

place, the total cost of the facility may be increased, resulting in higher disposal costs over time."

52

The reasons the average annualized and unitized baseline CCR disposal cost of $59 per-ton estimated in this RIA, is higher than the baseline 

cost range of $3 to over $40 per-ton reported by the ACAA, are: 

x Low-end unitized cost: The low-end of ACAA_s reported cost range is $3 to $5 per-ton. Assuming the cheapest operating surface 

impoundment does not include a liner and leachate collection costs as estimated in this RIA for impoundments in states with such 

regulatory requirements, the baseline surface impoundment unitized cost may be as low as $2 per-ton based on the cost elements 

applied in this RIA. This low-end unitized cost may be derived from the impoundment cost column of Exhibit 3L as follows: 

(Column total cost - Row 2 cost - Row 3 cost) / (22.4 million tons per year managed in impoundments) = 

($1,317 million/year - $1,219 million/year - $52.2 million/year) / (22.4 million tons per year) = $2.04 per-ton

x High-end unitized cost: The upper-end of ACAA_s reported cost range is $20 to $40 per ton, which applies to offsite disposal. The 

cost estimation of this RIA incorporates off-site commercial disposal costs on a state-by-state specific basis according to electricity 

 

52 Source: ACAA webpage containing Frequently Asked Question nr. 13 at http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=5#Q13 
66 

power plant location, using commercial landfill tipping fees ($2009) for contaminated soil, which range widely from $11 per-ton to 

$135 per-ton, with a national average of $50 per-ton. For example, commercial landfill tipping fees for contaminated soil for some of 

the high coal usage states are: TN = $11.19/ton, IN = $32.73/ton, OH = $35.48/ton, and PA = $57.96/ton. The baseline cost 

estimation method of this RIA then added a CCR offsite transportation and loading cost of approximately $33 per-ton based on the 

RACER cost estimation tool. For the estimated 15.0 million tons per-year of CCR disposed in offsite landfills, the estimated baseline 

cost is $1,193 million per-year, which is equivalent to $79.53 per-ton over the 50-year time period of the RIA cost analysis which 

assumes increasing coal usage (0.73% per-year) by electric utilities and subsequent offsite landfill disposal over the 50 year time 

period. It is unknown what cost elements are included in the high-end of the ACAA reported cost range (e.g., transportation cost 

and/or landfill tipping fee cost). In addition, electric utility companies likely have annual or multi-year contracts with offsite landfill 

operators that offer lower tipping fees than the state-average off-site contaminated soil tipping fees used in this RIA.

o Validity Test #2 of 2: Comparison to CCR Disposal Costs Contained in the EIA Form 767 Database 

The 2005 Energy Information Administration (EIA) Form 767 database (Schedule 3, Part B) indicates $5,890 million in annual capital and 

O&M cost reported by steam electric plants with nameplate capacity of 100 MW or greater, including (a) $0.314 million per year for water 

pollution controls, (b) $0.193 million per year for solid waste disposal, (c) $0.185 million per year for other pollution controls, (d) $3,627 

million per year capital expense for air pollution abatement, and (e) $1,546 million per year for collection and disposal O&M costs for fly ash, 

bottom ash, and FGD. This last cost element --- $1,546 million per year for CCR disposal --- is only 28% of the $5,556 million per year 

estimate displayed in Exhibit 3L above. However, the 2005 EIA Form 767 cost data are associated with only 179 coal-fired electric utility 

plants, which represent only 36% of the 495 coal-fired electric utility plants addressed by this RIA. Therefore, to facilitate a direct comparison, 

the $1,546 million per year cost from the data in EIA Form 767 may be extrapolated to all 495 plants by multiplying by the factor 2.765 (i.e., 

495 / 179), which produces an estimated extrapolated cost for all 495 plants of $4,275 million per year (i.e., 2.765 x $1,546 million per year). 

This extrapolated cost is 23% lower than the $5,556 million per year baseline cost estimated in this RIA. This comparison suggests the 

baseline cost estimated in this RIA may be an over-estimate, but it is not clear whether the cost data in the EIA Form 767 database include 

baseline costs to the electric utility plants for compliance with existing state government regulations concerning CCR disposal (e.g., the 

annualized cost for obtaining and maintaining state government disposal permits and the annualized cost for impoundment structural integrity 

inspections), as does this RIA. 
67 

Chapter 4 

Estimated Cost for RCRA Regulation of CCR Disposal 

Note: EPA formulated cost estimates in this Chapter based on the October 2009 draft RIA regulatory options. Because the 

high-end cost of those options (i.e., for the Subtitle C ghazardous wasteh option) is larger than the high-end cost for the 2010 

regulatory options (i.e., for the Subtitle C gspecial wasteh option), the costs in this Chapter are proportionately over-estimated. 

However, Section 6B of this RIA applies scaling factors to adjust the costs estimated in this Chapter to the 2010 options. 

4A. EPA’s Prior Cost Estimates for Possible RCRA Regulation of CCR Disposal at Electric Utility Plants 

In prior studies, EPA_s Office of Solid Waste (which EPA renamed as the ORCR effective 18 January 2009), formulated the following industry 

compliance cost estimates for different RCRA-based regulatory approaches to CCR disposal by the electric utility industry: 

1988: OSW's 1988 Report to Congress on CCR estimated $2.4 billion to $4.7 billion per year (1986$) in potential average annualized 

industry cost (514 plants in 1984) for compliance with technical standards contained in 40 CFR 264 RCRA Subtitle C hazardous waste 

regulations. The range reflects different liner assumptions (i.e., single versus double liners) and whether only unlined CCR units close 

or all existing units close requiring construction of new units. This cost includes closure costs but not a cost for corrective action 

excavating and removing CCR to Subtitle C facilities for closure of existing units. This report separately estimated that corrective 

action gat a cost of about $2.0 billion per plant, industry-wide costs would exceed $1.0 trillionh lump-sum cost, which is equivalent to 

$43 billion annualized cost (discounted @3% over 40-years). Source: EPA-OSWER report nr. EPA/530-SW-88-002, Feb 1988. 

1999: OSW_s 1999 Report to Congress focused on the gco-managementh (i.e., low-volume mixed with high-volume) subset of CCR units 

(i.e., 206 units at 353 plants in 1994), constituting 53 million tons (50%) of the 105 million total high-volume electric utility CCR 

generation in 1997. This report estimated a range of $800 million to $900 million per year (1998$) in potential average annualized 

compliance cost to the electric utility industry to comply with technical standards similar to 40 CFR 258 RCRA Subtitle D nonhazardous waste regulations. This cost estimate includes opening new CCR units to replace existing units that do not meet Subtitle D 

standards, including the following itemized costs: land purchase, site development, liner installation, leachate collection, groundwater 

wells & monitoring, closure costs, and post-closure costs. This estimate accounted for state CCR management requirements as of 1997. 

Source: EPA OSWER report nr. EPA 530-R-99-010, March 1999. 

2005: In a November 2005 report, an OSW contractor (DPRA Inc) estimated $304 million to $521 million per year (2005$) in potential 

average annualized cost for the electric utility industry (i.e., 470 units at 452 plants in 2003) to comply with regulatory options 

developed with reference to the gtailored standardsh of EPA_s 1999 cement kiln dust proposed rule which based many elements on 40 

CFR 258 RCRA Subtitle D non-hazardous waste regulations. Cost elements in this report included (a) location standards, (b) operating 

criteria such as cover material, dust control, run-on/run-off control, (c) design criteria such as liner and leachate collection, (d) 

groundwater monitoring, (e) closure and post-closure standards, and (f) financial assurance for closure, post-closure and corrective 
68 

action. This estimate accounted for state CCR management requirements as of 2004, but did not include costs for corrective action. 

Source: EPA-OSWER document ID nr. EPA-HQ-RCRA-2006-0796-0469 at http://www.regulations.gov. 

These three prior RCRA regulatory cost estimates range from $304 million to $4.7 billion per year. Even without updating these prior cost 

estimates to the current 2009 price level, all three prior cost estimates exceed the 1993 Executive Order 12866 Section 3(f)(1) geconomically 

significanth $100 million annual effect threshold for Federal rulemakings. 

4B. Regulatory Cost Estimation Algorithms & Results

This section presents incremental cost estimates for each regulatory option, for both existing active (i.e., operating) and future new CCR 

landfills and impoundments, and by size/type of affected electric utility plant owner entity. Incremental comparison of the estimated cost of 

each regulatory option to the baseline (as estimated in Chapter 3 of this RIA) is consistent with OMB_s 2003 gCircular A-4: Regulatory 

Analysish best practices guidance to Federal agencies: 

gIdentify a baseline. Benefits and costs are defined in comparison with a clearly stated alternative. This normally will be a “no 

action” baseline: what the world will be like if the proposed rule is not adopted.h 

As listed below, this RIA estimates 18 potential regulatory costs and the land disposal restriction (LDR) dewatering treatment standard, based 

on many of the same unit cost data sources and the same framework (i.e., 2009 price level, 50-year period of analysis, etc.), identified in the 

prior chapter of this RIA for baseline cost estimation. According to three methodological groupings, this RIA estimates three categories of 

regulatory costs: 

A. Engineering controls for CCR disposal units v estimated using the cost model described in the prior chapter of this RIA: 

1. Ground water monitoring 

2. Bottom liners v for future new units only 

3. Leachate collection system v for future new units only 

4. Dust controls v applicable to landfills only 

5. Rain and surface water run-on/run-off controls v applicable to landfills only 

6. Financial assurance for disposal unit closure and post-closure 

7. Disposal unit location restrictions (6 types: water tables, floodplains, wetlands, fault areas, seismic zones, karst terrain) 

8. Closure capping to cover unit 

9. Post-closure monitoring requirements 

10. Temporary storage requirements v not estimated in this RIA because do not have information on the baseline counts or physical 

conditions of CCR storage tanks and storage buildings at electric utility plants. 
69 

B. Ancillary costs for CCR disposal v estimated outside of the engineering control cost model: 

11. Offsite disposal (hazmat trucking, RCRA manifesting, offsite RCRA TSDF permits) 

12. Structural integrity inspections v impoundments only 

13. RCRA facility-wide investigation (RFI) 

14. RCRA facility-wide corrective action 

15. RCRA TSDF hazardous waste disposal permits for onsite disposal 

16. RCRA enforcement inspection 

17. Cleanup remediation of future CCR impoundment failures as RCRA hazardous waste 

18. EPA administrative reporting & recordkeeping 

C. LDR cost for land disposal restriction dewatering treatment v Sections 3004(d) and (m) of the RCRA statute require treatment prior to 

land disposal for Subtitle C hazardous waste listings, but not for Subtitle D non-hazardous waste regulation. The purpose of the treatment 

is to gsubstantially diminish the toxicity of the waste or substantially reduce the likelihood of migration of hazardous constituents from the 

waste so that short-term and long-term threats to human health and the environment are minimizedh (source: section 3004(m)): 

o Dry CCR disposal (landfills): Moisture conditioning and compaction included in engineering control cost item 4. 

o Wet CCR disposal (impoundments): Estimated outside and separately of the engineering controls cost model in this RIA. 

This RIA does not include either qualitative or quantitative estimation of the potential effects of the proposed rule on economic productivity, 

economic growth, employment, job creation, or international economic competitiveness. These potential effects are identified as factors in 

both the 1993 Executive Order gRegulatory Planning and Reviewh (section 3(f)(1)) and in the 1995 Unfunded Mandates Reform Act (section 

202(a)(4)). These other potential economic effects are excluded from this RIA because the upper-end of the range in average annualized 

regulatory cost across all regulatory options as estimated in this chapter below, does not exceed the 0.25% to 0.5% of Gross Domestic Product 

(GDP) threshold identified in OMB_s 1995 guidance53 for attempting to measure such other economic effects for purpose of UMRA economic 

analysis compliance. Based on the 2008 US GDP of $14.42 trillion,54 the 0.25% to 0.5% threshold is equal to $36 billion to $72 billion. 

 4B.1 Regulatory Cost to Industry for RCRA “Engineering Controls” 

This RIA assumes that that same set of RCRA 3004(x) custom-tailored engineering controls is required under each of the regulatory options, so 

the costs for engineering controls for all regulatory options are mostly, but not entirely, based on the same cost estimation formulae described 

above in Chapter 3 for estimation of baseline engineering control costs. Furthermore, this RIA assumes that the engineering control costs are 

 

53 Source: Section 4.B(3) of OMB_s 31 March 1995 guidance for implementing the UMRA state that gWe would note that such macro-economic effects tend to be 

measurable, in nation-wide econometric models, only if the economic impact of the regulation reaches 0.25 percent to 0.5 percent of Gross Domestic Product. A regulation 

with a smaller aggregate effect is highly unlikely to have any measurable impact in macro-economic terms unless it is highly focuses on a particular geographic region or 

economic sector.h 54 Source: 2008 3rd quarter estimate of 2008 US GDP as reported in gTABLE Bv8.ÄGross domestic product by major type of product, 1959v2008h of the 2009 Economic 

Report of the President at http://www.gpoaccess.gov/eop/tables09.html 
70 

similarly specified in EPA_s cement kiln dust 20 August 1999 proposed rule.55 This assumption was required to launch this RIA in April 2009 

prior to the initial draft of the CCR proposed rule and its regulatory options. This RIA assumes that liners and leachate collection systems 

requirements apply only to future new CCR landfills and impoundments. Offsite disposal costs are assumed unaffected under all regulatory 

options because offsite CCR disposal units are assumed to be commercially-owned units (i.e., owned by the waste management industry) and 

assumed currently in compliance with the custom-tailored engineering controls. For engineering controls added to existing units the costs are 

added to the remaining years of the lifespan of the landfill or impoundment. 

1. Regulatory groundwater monitoring cost 

Same cost estimation formula applied above in Chapter 3 for baseline cost estimation. 

2. Regulatory bottom liner cost 

Same cost estimation formula applied above in Chapter 3 for baseline cost estimation. 

3. Regulatory leachate collection cost 

Same cost estimation formula applied above in Chapter 3 for baseline cost estimation. 

4. Regulatory fugitive dust control cost 

Same cost estimation formula applied above in Chapter 3 for baseline cost estimation. 

5. Regulatory financial assurance cost 

Same cost estimation formula applied above in Chapter 3 for baseline cost estimation. 

6. Regulatory closure costs 

Same cost estimation formula applied above in Chapter 3 for baseline cost estimation. 

7. Regulatory disposal unit location restriction costs 

This cost element is estimated outside of the engineering controls cost model, using the factors, data and calculations below. 

x Count of Existing Electric Plants Which May be Affected by Location Restrictions 

To estimate the potential cost of location restrictions, this RIA conducted a GIS analysis to determine which facilities may be affected by 

location restrictions. As summarized below, the GIS analysis was conducted for three of the six possible site restrictions (i.e., using three GISbased datasets pertaining to fault areas, seismic zones, and karst zones readily available to EPA-ORCR at the 2009 launch of this RIA). This 

limitation potentially results in under-estimation in this RIA of the number or electric utility plants which may be affected and thus underestimation of regulatory location restriction costs. On the other hand, the average per-plant cost of $4.1 million applied below for estimating 

the potential cost of this regulatory element is over five-times higher than the $0.75 million56 cost per-plant cost estimated by another study for 

 

55 Federal Register, Vol.64, No.161, 20 Aug 1999, pp.45632-45697. 56 Source: $0.75 million disposal unit location restriction mitigation cost for a single electric utility plant is from page 10 (slide number TVA-00007496) of gKingston Fossil 

Plant Decision Matrix: Pond or Peninsula?,h 27 Jan 2005 Plant Managers Conference Room at http://www.tva.gov/kingston/tdec/pdf/TVA-00007487.pdf 
71 

location restriction mitigation involving karst mitigation and floodplain/wetland mitigation; this probably overly offsets the possible cost 

underestimation in this RIA for this regulatory element. 

The GIS was based on the DOE-EIA eGRID database to identify the geographic coordinates for 491 of the 495 electric utility plants 

(disregarding four plants not present in the eGRID database). Appendix I of this RIA presents site location data for each electric utility plant 

used in the GIS analysis. In order to geographically capture both the facilities and their waste units, and to compensate for the fact that there 

exists uncertainty as to the exact facility location versus the reported geographic coordinates (i.e., depending on whether location was measured 

by plant centroid, street address, smokestack, etc.), this GIS analysis used both a 1-mile and a 3-mile buffer around the reported facility 

coordinates. This RIA presumes these buffers are likely to ensure inclusion of the facility's onsite CCR disposal units, and account for 

uncertainty in the location data. The 1-mile buffer should capture all impoundments; the 3-mile buffer represents an upper-bound to capture all 

landfills that could reasonably be considered on-site. 

1. Water table restrictions: GIS analysis not conducted for this site restriction 

2. Floodplain restrictions: GIS analysis not conducted for this site restriction 

3. Wetlands restrictions: GIS analysis not conducted for this site restriction 

4. Fault area restrictions 

To identify fault zones, used the USGS database, gQuarternary Fault and Fold Database for the United States,h which contains national scale 

location data on faults and associated folds.57 This analysis identified plants including their buffers which fall within 200 feet of fault lines that 

have exhibited movement in the Holocene era. The USGS dataset includes fault lines that are believed to have been a source of earthquakes 

greater than magnitude 6 during the Quarternary (the past 1,600,000 years) and it defines gHoloceneh as the past 15 thousand years.58,59

x 1-mile buffer: 1 plant falls within 200 feet of a fault line. 

x 3-mile buffer: 3 plants fall within 200 feet of a fault line. (these three plants are located in NV and UT). 

It is important to note that this preliminary analysis has certain limitations and may not capture facilities in other areas of seismic risk. 

According to the USGS fault line database, no relevant faults are located in the central and eastern US. The USGS states in its database 

description that this absence of identified faults with movement in the central and eastern US is partly a real phenomena, because the western 

US has more tectonic activity, but that it is partly a detection problem caused by geological characteristics present in the central and eastern 

US, such as glacial sediments, that conceal evidence of movement along faults. For this reason, the analysis of seismic zones below, which 

are defined based on the likelihood of future seismic activity, may represent a more reliable estimate of the number of facilities potentially 

affected by fault area restrictions.60

 

57 US Geological Survey, 2006, gQuarternary Fault and Fold Database for the United Statesh at: http//earthquakes.usgs.gov/regional/qfaults. File used: fitarc.shp 

58 RCRA defines gHoloceneh as gthe most recent epoch of the Quarternary period, extending from the end of the Pleistocene to the presenth (40 CFR 264.18(a)(2)(iii)). 59 Faults designated by the dataset as showing movement during the Holocene are not necessarily believed to have produced an earthquake of magnitude 6 or greater during 

the Holocene. Rather, they are believed to have produced an earthquake of magnitude 6 or greater during the Quarternary, but their most recent suspected movement of any 

degree was during the Holocene. 

60 The USGS data layer used for this analysis indicates that faults with Holocene movement are located only in states in the West and Southwest regions of the US. This 

appears generally consistent with a separate analysis in the RCRA Practice Manual (Garrett, Theodore L., 2004, published by American Bar Association), and the small 

number of plants affected is not unexpected given the relatively small number of plants in these regions. However, the RCRA Practice Manual also notes that virtually all 

plants in CA and NV, and in parts of AK, AZ, CO, HI, ID, MT, NM, UT, WA, WY would be located within 200 feet of relevant faults. This suggests an upper bound of 54 

plants (out of the 491 plants analyzed), if all facilities in the identified states may be affected by fault area restrictions.
72 

5. Seismic zone restrictions: 

To identify seismic zones, USGS National Seismic Hazard Maps provide peak horizontal acceleration at different probabilities of exceedance 

in 50 years.61 Identified those facilities, including their buffers, which overlap with the seismic impact zones that have a 10% or greater 

probability of exceeding a maximum horizontal acceleration of 10% the force of gravity (i.e., 0.10 g) in 250 years.62 The USGS data gives 

probabilities of exceedance over 50 years; thus used a data layer presenting 2% probability of exceedance, and assumed that this equates to a 

10% probability of exceedance in 250 years. 

x 1-mile buffer: 151 plants fall within seismic zones 

x 3-mile buffer: 152 plants fall within seismic zones 

6. Karst zone restrictions: 

This analysis used two databases: (1) DOE-EIA_s eGRID database to identify the geographic coordinates of 491 of the 495 plants analyzed 

(disregarding four plants that were not present in the eGRID database), and (2) the USGS's GIS database "Engineering Aspects of Karst," 

which provides national-scale data on karst coverage.63 Four types of karst areas are identified in the dataset: (a) long karst features (fissures, 

tubes, and caves over 1000 feet long and 250 feet deep); (b) short karst (fissures, tubes, and caves less than 1000 feet long and 50 feet deep), 

(c) areas where karst features are generally absent but present in small isolated areas, and (d) pseudo-karst areas, which have features 

analogous to karst. 

x 1-mile buffer: 138 plants fall within karst zones 

x 3-mile buffer: 177 plants fall within karst zones 

These counts do not distinguish between the four different types of karst terrain identified in the data set; this analysis represents an initial 

upper bound of potentially affected facilities. 

x Potential Cost for Existing & New Electric Plants to Meet Disposal Unit Location Restrictions 

According to the above findings for the three location criteria evaluated in this RIA (i.e., fault areas, seismic zones, karst zones), a maximum 

count of 177 plants could be affected (this is the upper-end of the affected plant counts across the three location evaluations). The potential 

cost to these plants of the location restrictions is estimated in this RIA using the cost to retro-fit existing CCR disposal units and to protect 

new CCR disposal units with a berm (aka levee). A berm is a type of engineering measure which may serve to demonstrate that engineering 

measures have been incorporated into disposal unit design to mitigate the potential adverse impacts disposal units may have on, or be caused 

by, these six location considerations. 

The cost to construct a berm is based on the cost to construct a 10-foot tall flood berm using US Army Corps of Engineers_ publication 

gFlood Proofing v How to Evaluate Your Options,” (July 1993), which provides unit costs in 1993 dollars to construct clay core flood control 

levees that are two, four, and six-feet high. This RIA inflated these unit costs to 2009 dollars using the ENR Construction Cost Index, and 

conducted a regression analysis on the unit costs (i.e., extrapolated the cost based on the implied cost curve of the smaller berms) to estimate 

the cost to construct a 10-foot tall berm. The estimated cost per linear foot to construct a 10-foot tall berm is $375. It is assumed that this unit 

cost could apply to both existing and new units, and that the berm would be constructed physically separate from the disposal unit, not 

integral as gfreeboardh to the disposal unit_s structure. 

 

61 U.S. Geological Survey, 2008, gNational Seismic Hazard Maps,h from USGS website: http://gldims.cr.usgs.gov/nshmp2008/viewer.htm. Data file used: pga2pct_p.shp. 62 This threshold for seismic impact zones is consistent with RCRA_s municipal solid waste landfill location restrictions (40 CFR 258.14(a)(b)(1)). 63 U.S. Geological Survey, 1984, gEngineering aspects of karst,h from USGS website: http://pubs.usgs.gov/of/2004/1352. File used: karst.shp. 
73 

o Impoundment berms: The average surface impoundment size for existing units in the cost model is 343 acres. Assuming a 

square impoundment and that the berm would be constructed on three sides of the impoundment the average berm length is 11,594 

feet. Therefore, the cost to construct a berm around an average-size impoundment is $4.3 million.64

o Landfill berms: Similarly, the average landfill size for existing units in the cost model is 278 acres. Assuming a square landfill 

and that the berm would be constructed on three sides of the landfill (leaving one side open for truck access), the average berm 

length is 10,447 feet, and the cost to construct a berm surrounding an average-size landfill is $3.9 million. 

Using the 3-mile buffer karst zone finding of 177 plants, the potential cost for constructing berms at those plants plus future plants is: 

o Existing units: ($4.1 million average berm cost) x (177 disposal units) = $726 million total cost 

Amortized with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $53 million/year equivalent 

o New units: Apply 0.73% average annual growth rate in future CCR generation (cited elsewhere in this RIA) to estimate the count

of future new or expanded disposal units over 50-years, and assume 36% (i.e., 177/495) will need berms: 

(495 existing disposal units) x (1.0073% growth rate)^(50 years) = 712 existing plus new units over 50-years 

(712 units over 50-years) v (495 existing units) = 217 future new disposal units 

(217 future new units) x (36% needing berms) x ($4.1 million average berm cost) = $318 million total cost 

Amortized with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $23 million/year equivalent 

 Average annualized berm cost for existing + new units = $76 million/year equivalent 

8. Regulatory closure cost 

Same cost estimation formula applied above in Chapter 3 for baseline cost estimation. 

9. Regulatory post-closure monitoring cost 

Same cost estimation formula applied above in Chapter 3 for baseline cost estimation. 

10. Storage design and operating standards for tanks, containers, and containment buildings 

Not estimated in this RIA due to lack of baseline information about the count and condition of these units at electric utility plants 

4B.2 Ancillary Regulatory Requirement Costs 

For estimating most of the gOther Ancillary Costsh in this section, this RIA distinguishes between RCRA Subtitle C and RCRA Subtitle D 

requirements according to the respective basis of each regulatory option, as well as between costs to electric utility plants and costs to state 

government RCRA-authorized regulatory programs. 

 

64 For purpose of comparison to the $4.3 million (per impoundment) and $3.9 million (per landfill) location restriction mitigation cost estimates above, in 2005 the TVA 

estimated an gassumedh cost of $500,000 for karst mitigation and $250,000 for floodplain mitigation for a potential new CCR disposal site involving 1,300 linear feet for 

mitigation. Extrapolation of TVA_s $750,000 cost estimate to 11,594 feet (impoundment) yields $6.7 million (i.e., (11,594 feet / 1,300 feet) x ($750,000)), and to 10,447 

feet (landfill) yields $6.0 million (i.e., 10,447 feet / 1,300 feet) x ($750,000)). Source for TVA cost estimate: page 10 of gKingston Fossil Plant Decision Matrix: Pond or 

Peninsula?h, 27 January 2005 Plant Managers Conference, http://www.tva.gov/kingston/tdec/pdf/TVA-00007487.pdf 
74 

11. Regulatory offsite disposal costs (hazmat trucking, RCRA manifests, RCRA TSDF permits for offsite) 

EPA assumed that Subtitle C options add extra cost to (a) truck hauling to offsite disposal, and (b) all offsite landfills must become RCRA 

Subtitle C permitted. This cost estimate does not include taxes/trans-state government fees associated with off-site disposal.

11a & 11b. Added truck hauling cost (Subtitle C options) 

Assumptions: 

x Affects the 12% (15 million tons per year) annual CCR generation currently trucked offsite to non-haz LFs (2005) 

x 6 miles average one-way trucking distance to offsite LFs65

x $0.19/ton/mile hazardous waste truck operating cost 

x 12 tons CCR per full truckload (source: Gambrills MD case study); (15 million tons/year) / (12 tons/load) = 1.25 million 

truckloads per year 

Cost Calculations: 

x 11a. RCRA manifest cost: (1.25 million truckloads) x ($53 per manifest per load average cost from EPA 2007 ICR 801.15) = 

$66 million per year 

x 11b. Trucking cost (distance + operating cost): (15 million tons/year) x (6 miles) x ($0.09/ton/mile added truck operating cost

for hazardous waste loads) = $8.1 million per year 

x Subtotal (11a manifest + 11b trucking): $74.1 million per year 

11c. Added cost for RCRA Subtitle C permits for all offsite CCR landfills under Subtitle C 

Assumptions: 

x Added operating cost to offsite CCR landfills for meeting engineering control requirements under each of the regulatory options

evaluated in this RIA are included in the gEngineering Control Costsh section above, so are not again calculated here to avoid 

double-counting. Only the paperwork burden cost for obtaining a RCRA permit is estimated here. 

x Industry average cost per waste disposal permit: 

($44066 average RCRA Part A permit application cost per-plant per-year) + ($68,96067 average RCRA Part B application cost 

per-facility per-year) = $69,400 per Subtitle C permit per year 

($69,400 per permit per year) x (3 years ICR annualization period) = $208,200 per permit 

(149 offsite CCR landfills) x ($208,200 per permit) = $31.02 million 

 Amortized industry cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $2.25 million/year 

 

65 Source: based on actual distance reported for a MD plant at http://www.rachel.org/en/node/445). Note: a broader range of 2.4 miles to 25 miles in one-way offsite landfill 

distance was reported by an OH plant at http://www.columbusdispatch.com/live/content/local_news/stories/2008/04/14/Powerfills.ART_ART_04-14-

08_B1_FF9TI0U.html?sid=101, and a WI plant, respectively at http://www.lacrossetribune.com/articles/2007/09/21/news/03landfill0921.txt 66 $440 unitized cost derived for this RIA from EPA Information Collection Request (ICR) No. 0262.12 gRCRA Hazardous Waste Permit Application and Modification 

Part Ah, Federal Register, Vol.74, No.17, 28 Jan 2009, page 4958; http://edocket.access.gpo.gov/2009/pdf/E9-1804.pdf 67 $68,960 unitized cost derived for this RIA from EPA Information Collection Request (ICR) No. 1573.12 gPart B Permit Applicationh, Federal Register, Vol.74, No.100, 

page 25237, 27 May 2009; http://edocket.access.gpo.gov/2009/pdf/E9-12285.pdf 
75 

x State government average cost per waste disposal permit: 

Average cost for state government review of RCRA Subtitle C permits consists of four activities:68

(1,215 pre-application activities) + ($27,063 application review) + ($26,846 permit issuance) + ($3,110 permit maintenance) = 

$58,200 per permit 

 (149 offsite CCR landfills) x ($58,200 per Subtitle C permit) = $8.67 million 

 Amortized state cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $0.63 million/year 

x Total Subtitle C permit cost (industry + state government) = $2.9 million per year 

Total cost for item 11 (11a + 11b + 11c): 

x Industry share of cost = $76.35 million per year 

x State government share of cost = $0.63 million per year 

x Total (industry + states) = $76.98 million per year 

12. Regulatory structural integrity inspection cost 

x Assumptions: 

EPA assumed that the residual 18% of the non-inspected plants require inspection over the 82% baseline inspection coverage. 

The per-plant cost for inspections is estimated in the Chapter 3 baseline above. 

x Cost Calculation: 

Industry cost: ($10,829/year per facility) x (18% not inspected) x (495 plants) = $0.96 million per year 

State government cost: ($599/year per facility) x (18% not inspected) x (495 plants) = $0.054 million per year 

Total (industry + state) = $1.01 million per year 

13. Regulatory RCRA facility-wide investigation (RFI) cost 

x Industry RFI cost: 

x As of 2008, state government corrective action covers 64% of electric utility industry impoundments and 78% of landfills. Thus, 

assume that 57 plants with impoundments (i.e., 36% x 158 plants with impoundments) plus 74 plants with landfills (i.e., 22% x 337 plants 

with landfills) may require RFIs, for a total of 131 RFIs. 

x The purpose of an RFI is to obtain information to fully characterize the nature, extent and rate of migration of releases of hazardous 

waste or constituents to determine whether interim corrective measures and/or a Corrective Measures Study may be necessary for other 

waste units at the facility (source: EPA 530/SW-89-031, May 1989, Vol.I). RFIs may include: rapid field screening using portable field 

instruments, drilling in soils, excavating test pits, ground-water monitoring, waste testing, biomonitoring, and site surveying, site 

photography, site mapping. 

x RFI average cost: 

$0.75 million average cost for RFIs involving captive industrial landfills 

 

68 Source: Based on cost data from page 84 of January 2007 ASTSWMO report gState RCRA Subtitle C Core Hazardous Waste Management Program Implementation 

Costs Final Reporth at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20Core%20Project.pdf 
76 

 $0.69 million average cost for RFIs involving captive industrial waste management (assume applies to impoundments) 

Source: EPA OSRE memorandum gTransmittal of Average Cost of Investigation Derived from Fund-Lead Superfund Costs, Interim 

Measures Cost Compendium, and Compendium of Related Guidance Documentsh, 01 Nov 2004. This memo indicates that Superfund 

remedial investigation costs can be used as a proxy for RCRA RFI costs. 

Industry RFI cost calculations: 

x Landfills: (74 landfills) x ($0.75 million average cost per RFI) = $55.5 million total cost 

x Impoundments: (57 impoundments) x ($0.69 million average cost per RFI) = $39.3 million total cost 

Total = $94.8 million total cost to industry 

Amortized industry RFI cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $6.9 million/year equivalent 

x State government RFI cost: 

State government RFI review, approval, oversight average cost per RFI = $76,00069

(131 RFIs) x ($76,000 review, approval, oversight average cost per RFI to state governments) = $10 million total cost 

Amortized state government RFI cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $0.7 million/year 

equivalent 

x RFI total cost (industry + state governments) = $7.6 million per year 

14. Regulatory RCRA facility-wide corrective action cost 

Average annualized future potential cost was not estimated in this RIA because of a high degree of uncertainty. Through a process called 

corrective action, RCRA Subtitle C requires RCRA-regulated facilities to investigate and clean-up releases of hazardous wastes or constituents 

to the environment identified in the RCRA facility-wide investigation (RFI). After the RFI, if the need for cleanup is discovered, the RCRAregulated facility must perform a gCorrective Measures Studyh (CMS) which may range in cost from $100,000 to $800,000 for such a study.70 

State government cost for corrective measures study & corrective action review, approval, oversight is $117,300 per case.71 The purpose of a 

CMS is to develop and evaluate the corrective action alternative(s) and to recommend the corrective measure(s) be taken at the facility.72

As of 2008 the RCRA corrective action universe is about 3,800 sites nationwide.73 Relative to the RCRA-regulated universe of 

217,500 facilities (consisting of about 16,000 hazardous waste LQG glarge quantity generatorsh plus about 200,000 hazardous waste SQG 

gsmall quantity generatorsh plus about 1,500 hazardous waste TSDF gtreatment, storage, disposal facilitiesh as of 2008), the 3,800 corrective 

action universe implies a 1.75% relative incidence of occurrence (i.e., 3,800 / 217,500 = 1.75%). Corrective action costs vary from facility-tofacility depending on the number and types of waste management units and other industrial equipment/processes and wastes involved. The 

 

69 Source: Divided the $2,200,600 annual RFI cost to 10 state governments by the 29 annual RFIs from page 82 of the January 2007 ASTSWMO report gState RCRA 

Subtitle C Core Hazardous Waste Management Program Implementation Costs Final Reporth at: 

http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20Core%20Project.pdf 70 Source: RACER unit cost reported on p.38 of EPA_s 2000 gUnit Cost Compendiumh , document ID nr. EPA-HQ-RCRA-2002-0031-0429 at : http://www.regulations.gov 71 Source: derived from cost data contained on page 83 of the ASTSWMO gState RCRA Subtitle C Core Hazardous Waste Management Program Implementation Costs 

Final Reporth, January 2007 at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20Core%20Project.pdf 72 Source: gCorrective Measures Study Scope of Workh, EPA Region 3 at: http://www.epa.gov/reg3wcmd/ca/pdf/CMSATTC.pdf 73 Source: 3,800 corrective action cases represents EPA_s g2020 Corrective Action Universeh as identified on EPA Hazardous Waste Corrective Action Facility Information 

website at: http://www.epa.gov/waste/hazard/correctiveaction/facility/index.htm#2020 
77 

corrective action remedies usually involve mitigating damages to surface water and groundwater. The General Accountability Office (GAO) 

reported74 that RCRA corrective action could cost 3,698 non-Federal hazardous waste treatment, storage, or disposal facilities a total of about 

$16 billion (1996$) to clean up their properties contaminated by hazardous substances, representing an average $4.327 million corrective action 

cost per-facility. Updated75 to 2009$ implies an average of $5.365 million RCRA corrective action cost per facility.

15. Regulatory RCRA TSDF waste disposal permit cost for onsite disposal 

RCRA Subtitle C hazardous waste regulations require hazardous waste treatment, storage, disposal facilities (TSDFs) to obtain RCRA permits 

as described in 40 CFR 270 consisting of a two-part (i.e., Part A and Part B) application process. The paperwork burden cost of this 

requirement is estimated below. Furthermore, but not included in the cost estimate below, are separate, additional RCRA regulations 

containing gtechnical requirementsh used by permit issuing authorities (e.g., RCRA-authorized state government waste programs or EPA 

Regional offices) to determine what technical requirements must be placed in permits. The separate cost of technical requirements is estimated 

in the gEngineering Controlsh regulatory cost section of this RIA above. 

x Assumptions: 

o Although 93% of CCR landfills have a state government non-hazardous waste disposal permit and 12% of CCR impoundments 

have such state permits, assume CCR disposal units will need new RCRA disposal permits under Subtitle C options. 

o 383 of the 495 total electric utility plants currently dispose onsite (i.e., 84 of the 495 plants solely dispose CCR offsite, plus 28 

plants solely supply CCR for beneficial uses). 

x Industry average cost per waste disposal permit: 

o ($44076 average RCRA Part A permit application cost per-plant per-year) + ($68,96077 average RCRA Part B application cost 

per-facility per-year) = $69,400 per Subtitle C permit per year 

($69,400 per permit per year) x (3 years ICR annualization period) = $208,200 per permit 

(383 plants) x ($208,200 per permit) = $79.74 million 

 Amortized industry cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $5.8 million/year 

x State government average cost per waste disposal permit: 

o Build estimate based on the following four RCRA Subtitle C permit-related state government activities associated with RCRA 

Subtitle C waste disposal permits:78

(1,215 pre-application activities) + ($27,063 application review) + ($26,846 permit issuance) + ($3,110 permit maintenance) = 

$58,200 average cost per Subtitle C waste disposal permit per year. 

 

74 Source: page 1 of US General Accountability Office (GAO), gHazardous Waste: Progress Under the Corrective Action Program is Limited, But New Initiatives May 

Accelerate Cleanups,h report nr. GAO/RCED-98-3, October 1997; http://www.gao.gov/archive/1998/rc98003.pdf 75 Updated from 1996$ to 2009$ using the NASA gGross Domestic Product Deflator Inflation Calculatorh at http://cost.jsc.nasa.gov/inflateGDP.html 76 $440 unitized cost derived for this RIA from EPA Information Collection Request (ICR) No. 0262.12 gRCRA Hazardous Waste Permit Application and Modification 

Part Ah, Federal Register, Vol.74, No.17, 28 Jan 2009, page 4958; http://edocket.access.gpo.gov/2009/pdf/E9-1804.pdf 77 $68,960 unitized cost derived for this RIA from EPA Information Collection Request (ICR) No. 1573.12 gPart B Permit Applicationh, Federal Register, Vol.74, No.100, 

page 25237, 27 May 2009; http://edocket.access.gpo.gov/2009/pdf/E9-12285.pdf 78 Source: Based on cost data from page 84 of January 2007 ASTSWMO report gState RCRA Subtitle C Core Hazardous Waste Management Program Implementation 

Costs Final Reporth at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20Core%20Project.pdf 
78 

o State Cost Calculation: 

 (383 electricity plants dispose CCR onsite) x ($58,200 per Subtitle C permit per year) = $22.3 million per year 

x Total Subtitle C permit cost (industry + state government) = $28.1 million per year 

16. Regulatory RCRA enforcement inspection cost 

x Assumptions: 

o State government average cost = $7,900 per Subtitle C inspection (source: hazardous waste LQG large quantity generator 

average calculated by dividing the $1,517,357 annual enforcement inspection cost to 10 surveyed state governments by 192 

annual enforcement cases, from page 87 of the January 2007 ASTSWMO report gState RCRA Subtitle C Core Hazardous Waste 

Management Program Implementation Costs Final Reporth 

o 1.6% average annual enforcement inspection frequency based on dividing the 11,965 LQG glarge quantity generatorh universe 

reported by 10 survey states by the 192 hazardous waste LQG enforcement cases reported in the January 2007 ASTSWMO 

report gState RCRA Subtitle C Core Hazardous Waste Management Program Implementation Costs Final Reporth 

x Cost calculation: 

($7,900 per LQG enforcement) x (495 electric utility plants) x (1.6% LQG enforcements annually) = $0.063 million per year 

17. Regulatory future remediation added cost 

Potential $18.5 million to $376 million per case in added cleanup cost for future surface impoundment failures, if regulated under RCRA 

Subtitle C rather than Subtitle D, is based on the two example case studies summarized in Exhibit 4A below. 
79 

Exhibit 4A 

Two Case Studies: 

Possible Added Cost Under RCRA Subtitle C Regulation of CCR Cleanup at Electricity Plants from CCR Impoundment Failures 

(Note: Assumptions or numerical factors unique to each case study are applied in the cost calculations below 

rather than the national average assumptions and numerical factors applied elsewhere in this RIA)

Case Study #1: 

TVA Kingston TN (2008) 

Case Study #2: 

Constellation Energy Gambrills MD (2008)

If cleanup as non-hazardous waste: 

Baseline Assumptions: 

x 3.32 million tons released 

x $0.10/ton/mile truck operating cost (source: OSW-EMRAD) 

x 45 miles to Subtitle D LF (source: OSW-EMRAD) 

x $35/ton tipping fee (source: 2005 Chartwell) 

x 154,000 truckloads (source: TVA assumes 21.6 tons ash per load) 

Baseline Cost Calculations: 

x Trucking cost: (3.32 million tons) x (45 miles) x ($0.10/ton /mile) = 

$15 million 

x LF tipping fee: ($35/ton) x (3.32 million tons) = $116 million 

x Manifest: $0 

x Case #1 total = $131 million for event 

If cleanup as non-hazardous waste: 

Baseline Assumptions: 

x 0.25 million tons released 

x $0.10/ton/mile truck operating cost (source: OSW-EMRAD) 

x 193 miles to Subtitle D LF (Constellation Energy_s mileage estimate 

to existing VA fly ash LF) 

x $35/ton tipping fee (source: 2005 Chartwell) 

x 20,833 truckloads (source: Constellation Energy assumes 12 tons ash 

per load) 

 Baseline Cost Calculations: 

x Trucking cost: (0.25 million tons released) x (193 miles) x ($0.10/ton 

/mile) = $5 million 

x LF tipping fee: ($35/ton) x (0.25 million.tons) = $9 million 

x Manifest: $0 

Case #2 total = $14 million for event 

If cleanup as RCRA Subtitle C hazardous waste 

Assumptions: 

x 3.32 million tons released 

x $0.19/ton/mile truck operating cost (source: TVA) 

x 370 miles to Subtitle C LF (source: TVA) 

x $80/ton Subtitle C tipping fee (source: TVA) 

x 154,000 truckloads (source: TVA assumes 21.6 tons ash per load) 

Cost Calculations: 

x Trucking cost: (3.32 million tons) x (370 miles) x ($0.19/ton/mile 

truck operating cost) = $233 million 

x LF tipping fee: ($80/ton) x (3.32 million tons) = $266 million 

x Manifest: (154,000 truckloads) x ($53 manifest cost per load) = $8 

million 

x Case #1 total = $507 million for event 

If cleanup as RCRA Subtitle C hazardous waste 

Assumptions: 

x 0.25 million tons released 

x $0.19/ton/mile truck operating cost (from TVA) 

x 179 miles to Subtitle C LF (closest is Envirosafe OH with 0.9 million 

tons permitted capacity) 

x $90/ton tipping fee (2004 ETC national median fee) 

x 20,833 truckloads (source: Constellation Energy assumes 12 tons ash 

per load) 

Cost Calculations: 

x Trucking cost: (0.25 million tons) x (179 miles) x ($0.19/ton/mile 

truck operating cost) = $8.5 million 

x LF tipping fee: ($90/ton) x (0.25 million tons) = $23 million 

x Manifest: (20,833 truckloads) x ($53 manifest cost per load) = $1 

million 

x Case #2 total = $32.5 million for event 

Case #1 incremental cost over non-hazardous: 

$376 million for cleanup event 

Case #2 incremental cost over non-hazardous: 

$18.5 million for cleanup event 
80 

18. EPA administrative reporting and recordkeeping costs 

Three of the regulatory costs itemized above -- item 11 offsite disposal truck manifesting and offsite disposal hazardous waste permits, item 12 

structural integrity inspections, and item 13 RCRA facility-wide investigation (RFI) v include the cost of paperwork burden for those items. In 

addition, certain features of the Subtitle C options of the proposed rule require four other paperwork burden activities: 

18a. Notice of Regulated Waste Activity & EPA ID Number 

RCRA Subtitle C regulations for hazardous waste ggeneratorsh require generators to notify their facilities as such and obtain EPA identification 

numbers (40 CFR 262.12). According to EPA_s most recent (2009) estimate, the average per-facility response burden is $162 per facility.79 

Applied to the 495 electric utility plants yields an estimated one-time notification cost of $80,190 (i.e., (495 electric utility plants) x ($162 per 

notification)). Amortized with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $5,800 per year average annual 

equivalent. 

o Industry share of cost: (86%) x ($5,800/year) = $5,000/year 

o State government share of cost: (14%) x ($5,800/year) = $800/year 

18b. General Facility Standards for Hazardous Waste TSDFs 

This cost item represents a set of paperwork burden activities grouped under 40 CFR 264/265 Subpart B (i.e., 264.10 to 264.19 and 265.10 to 

265.19) and includes (1) maintaining records for hazardous waste that is stored, treated, and/or disposed onsite, (2) descriptions of location, 

design, construction, operating methods, techniques, and practices for onsite hazardous waste storage, treatment, and/or disposal, (3) 

contingency plans for unanticipated damages from hazardous waste onsite storage, treatment and/or disposal, (4) maintaining qualifications of 

facility ownership, (5) maintaining continuity and financial responsibility of facility operation, and (6) employee hazardous waste training. 

According to EPA_s most recent (2009) estimate the average per-facility paperwork burden is $27,350 per facility per year.80 Applied to the 

383 electric utility plants which currently dispose onsite (i.e., 84 of the 495 plants solely dispose CCR offsite with other companies, plus 28 

plants solely provide CCR for beneficial uses) yields an estimated cost of ($27,350 per facility pre year) x (383 plants which dispose CCR) = 

$10.48 million/year: 

o Industry share of cost: (86%) x ($10.48 million/year) = $9.01 million/year 

o State government share of cost: (14%) x ($10.48 million/year) = $1.47 million/year 

18c. RCRA Hazardous Waste Biennial Report 

RCRA Subtitle C requires hazardous waste LQG large quantity generators (40 CFR 262.41) and hazardous waste TSDF treatment, storage, and 

disposal facilities (40 CFR 264.75 and 265.75) to submit gHazardous Waste Reporth information on a 2-year repeating cycle (aka gRCRA 

 

79 $162 per year notification cost derived from EPA Information Collection Request (ICR) No. 0261.16 gNotification of Regulated Waste Activity (Renewal)h, Federal 

Register, Vol.74, No.123, pages 31028-31029, 29 June 2009; http://edocket.access.gpo.gov/2009/pdf/E9-15310.pdf 80 $27,350 per facility per year average cost derived from EPA Information Collection Request (ICR) No. 1571.09 gGeneral Hazardous Waste Facility Standardsh, Federal 

Register, Vol.74, No.23, pages 6152-6154, 05 Feb 2009. 
81 

Biennial Reporth). According to EPA_s most recent (2009) estimate, the average annualized per-facility response burden is $3,410 per year.81 

Extrapolated to 495 electric utility plants produces a cost estimate of $1.69 million per year. 

o Industry share of cost: (86%) x ($1.69 million/year) = $1.45 million/year 

o State government share of cost: (14%) x ($1.69 million/year) = $0.24 million/year 

18d. CERCLA Reportable Quantity (RQ) Spill/Leak Reporting 

Section 103(a) of CERCLA requires facilities and vessels to immediately notify the National Response Center (NRC) of a hazardous substance 

release (e.g., spill, leak) into the environment if the amount of the release equals or exceeds the substance_s reportable quantity (RQ) limit. In 

general there are five RQ categories (1, 10, 100, 1,000 or 5,000 pounds). Subtitle C options may add CCR to the CERCLA list of hazardous 

substances and assign an RQ of one-pound, as well as allowing the use of concentrations to determine RQ thus resulting in a range of 1,294 

pounds to 10,000,000 pounds for 12 chemicals. Using the total count of facilities (i.e., establishments) in the US manufacturing sector (NAICS 

31, 32, 33) plus the US waste management sector (NAICS 562) as rough indicators, there are 315,000 industrial facilities in the US which may 

handle RQ-listed hazardous substances.82 According to EPA_s most recent (2007) estimate, the average per-facility response burden is $122 

(i.e., 4.1 burden hours) per facility per response, based on an average annual 25,861 facilities at an annual paperwork burden cost of $3.161 

million.83 Relative to this 300,000 industrial facility universe, this annual count of RQ-reporting facilities represents an 8% fraction. 

Extrapolated to the 495 electric utility plants yields a rough estimate of 40 possible RQ reports per year, at a cost of $4,900 per year (i.e., (495 

electric utility plants) x (8% RQ reports per year) x ($122 per RQ report)). 

o Industry share of cost: (86%) x ($4,900/year) = $4,200/year 

o State government share of cost: (14%) x ($4,900/year) = $700/year 

Sub-total cost item 17 (17a + 17b + 17c + 17d) = $12.94 million per year. 

o Industry share of cost: (86%) x ($12.94 million/year) = $11.13 million/year 

o State government share of cost: (14%) x ($12.94 million/year) = $1.81 million/year 

Exhibit 4B below presents a summary of these gAncillary Costh elements numbered from 11 to 18. 

 

81 $3,410 per facility per year average cost derived from EPA Information Collection Request (ICR) No. 0976.14 g2009 Hazardous Waste Reporth, Federal Register, 

Vol.74, No.93, pages 22922-22924, 15 May 2009; http://edocket.access.gpo.gov/2009/pdf/E9-11410.pdf 

82 315,000 industrial facilities based on gNumber of Establishmentsh published for NAICS codes 31-33 Manufacturing (293,919 establishments) plus NAICS code 562 

Waste management and remediation services (21,254 establishments) from the US Census Bureau in its g2007 Economic Census.h Not all manufacturing or waste 

management facilities necessarily handle hazardous substances so this is an over-estimate, but there are also other economic sectors (e.g., mining, construction, utilities, 

transporters, and wholesalers), which handle hazardous substances not included in this facility count which offsets this over-estimate. 83 $122 per facility average cost derived from EPA Information Collection Request (ICR) No. 1049.11 gNotification of Episodic Releases of Oil and Hazardous Substances 

(Renewal); Federal Register, Vol.72, No.205, 24 Oct 2007, pp.60357-60358; http://edocket.access.gpo.gov/2007/pdf/E7-20934.pdf 
82 

Exhibit 4B 

Summary of “Ancillary Cost” Estimates Associated with RCRA Regulation of CCR Disposal 

($millions average annualized; 2009$) 

Ancillary Cost Element 

Applicability to 

CCR Regulatory Options 

Electric Utility 

Industry Cost 

State Government 

RCRA-Authorized 

Program Cost 

Row Total 

Cost 

11. Ancillary offsite disposal costs Subtitle C $76.35 $0.63 $76.98 

12. Impoundment structural integrity inspections Subtitle C and Subtitle D $0.96 $0.054 $1.01 

13. RCRA facility-wide investigations (RFIs) Subtitle C $6.9 $0.7 $7.6 

14. RCRA facility-wide corrective action Subtitle C Not estimated v 

historical 

average cost = 

$5.4 million per 

facility 

Not estimated Not est. 

15. RCRA TSDF waste disposal permits Subtitle C $5.8 $22.3 $28.1 

16. RCRA enforcement inspections Subtitle C $0 $0.063 $0.063 

17. Future disposal unit failure cleanup 

remediation as RCRA hazardous waste 

Subtitle C Not est. v case 

study example 

Not est. v case 

study example 

Not est. 

18. EPA administrative reporting & recordkeeping 

18a. EPA regulated waste notification 

18b. RCRA TSDF general facility standards 

18c. RCRA haz waste biennial report 

18d. CERCLA RQ reporting 

Subtitle C Subtotal= $11.13 

$0.005 

$9.01 

$1.45 

$0.0042 

Subtotal= $1.81 

$0.0008 

$1.47 

$0.24 

$0.0007 

$12.94 

$0.0058 

$10.48 

$1.69 

$0.0049 

Column Totals for the three options of the October 2009 draft RIA : 

 Subtitle C hazardous waste $100.4 $25.6 $126.7 

 Subtitle D (version 1) $0.96 $0.05 $1.0 

 Hybrid C&D* $7.9 $7.7 $15.6 

* Hybrid C&D costs for ancillary cost items 13, 14, 15, 16, 17, 18 are proportioned only to the 158 plants with impoundments that would be 

regulated under Subtitle C for this option, by the proportionate multiplier: (158 plants w/impoundments) / (495 total plants) = 0.319 
83 

4B.3 Land Disposal Restriction Cost (for dewatering treatment of CCR) 

This element consists of two components: 

x Dry CCR disposal (landfills): Moisture conditioning and compaction to 95% maximum dry density value according to ASTM D 698 or 

ASTM D 1557 test methods prior to disposal in landfills. 

x Wet CCR disposal (impoundments): Dewatering to remove solids prior to disposal in impoundments within 5-years of rule_s effective date. 

The potential cost for this treatment standard is estimated below. 

However, only the potential cost for the wet CCR disposal dewatering treatment standard is estimated in this section of the RIA because the 

potential cost for meeting the dry CCR moisture conditioning and compaction requirements are already estimated in item 4 of the gengineering 

controlsh in this chapter above: 

x Examples of CCR Dewatering Methods 

Based on the following recent (1997-2009) example descriptions of dry CCR disposal practices at existing or planned coal-fired electric utility 

plants, dry CCR disposal may involve different methods for any given plant: 

1. Tanks & chain drag: As described in March 2009 by the Basin Electric Power Cooperative.84 Bottom ash will be dewatered in tanks 

and the water will be re-circulated to transport additional bottom ash. Bottom ash will be removed using a chain drag. The ash will 

then be hauled by truck to a lined landfill offsite. The fly ash will be conveyed in a dry state. Both ashes will be disposed in a landfill 

close to the plant site. 

2. Pressure squeeze conveyor: Another tank-based example apparently similar to the Basin Cooperative method is reported for dry 

disposal conversion by the coal mining industry, involving the Phoenix Process Equipment company supplier of alternative slurry

processing equipment. This second example involves a thickening tank, porous conveyor belt and pressure to squeeze water out of the 

coal washings, producing a semi-solid, 75% dewatered cake which is scraped off the conveyor belt and stacked like a pile of sand. The 

cost for this process is reported at $0.50 per ton of coal waste processed.85

3. Horizontal belt filters: According to a May 2009 technical paper86, dewatering gypsum using horizontal belt filters is common in the 

electric utility industry, and a new modified horizontal belt filter method involving two feedboxes allows fly ash and FGD (gypsum) to 

be dewatered simultaneously. 

4. Storage silos & rail system: As described June 200987 for a $10 million conversion project located at Detroit Edison_s Monroe 

Michigan Power Plant -- a four boiler unit, 3,200-megawatt power station originally constructed in 1974. Installation of equipment to 

collect the coal ash in a dry state, plus dry ash storage facilities (storage silos), and truck/rail loading equipment for distribution of the 

dry ash to concrete producers in the Midwest United States and Eastern Canada. 

 

84 Source: March 2009 Basin Electric Power Cooperative examples at http://www.basinelectric.com/News_Center/Feature_Articles/Coal_ash_handling.html 85 Source: Dave Cooper, gBetter, Safer Ways to Handle Coal Slurry Do Existh, page 14 of the Nov 2001 gEh-Notes Newsletter of the Ohio Valley Environmental Coalition 

at http://www.ohvec.org/newsletters/enotes_97-01_pdf/enotes_2001_11.pdf 86 Source: May 2009 horizontal belt filter technical paper by Alex Hohne at http://www.flyash.info/2009/036-hohne2009.pdf 87 Source: June 2009 Detroit Edison Monroe Power Plant example at http://www.headwaters.com/data/upimages/press/6.30.09MonroeAshRelease.pdf 
84 

5. Integrated silo system: Integrated with precipitators, vacuum pumps and bag filter/receivers, as described in an engineering report88

about the 1997 dry fly ash system conversion of Northern Indiana Public Service Company_s Michigan City Plant. 

For this RIA, EPA ORCR identified four alternative existing studies with cost estimates (dated 1981, 1985, 2005, and 2009) comparing dry and 

wet CCR disposal at coal-fired electric utility plants. The first three studies provided cost estimates on a per-plant basis, whereas the 2009 

study provided an extrapolated nationwide cost estimate. However, only the 2005 study is used in this RIA as a basis for deriving a cost 

estimate for the wet CCR dewatering land disposal treatment, because the first two studies are over 25-years old (1981 and 1985), and the 2009 

study does not provide sufficient details for verification of data and calculations. These three other studies are summarized below in this 

chapter to illustrate the magnitude of cost estimation uncertainty implied by the other studies, compared to the estimate derived below in this 

section of the RIA. 

x Summary of 2005 TVA CCR Dry Disposal Cost Study 

x In August 2009 TVA announced a proposed plan to convert its wet CCR disposal to dry disposal. TVA_s CEO Tom Kilgore said before a 

28 July 2009 US Congressional subcommittee hearing that TVA has developed a 5-year plan to shift CCR disposal from wet 

impoundments to dry landfills. TVA estimated it will cost between $1.5 billion to $2 billion over 8 to 10 years for its 11 coal-fired electric 

utility plants.89 Detailed or semi-detailed calculations of TVA_s 2009 cost estimate are not available for this RIA to use for extrapolation 

nationwide. 

x However, a 2005 TVA cost estimate titled gKingston Fossil Plant Decision Matrix: Pond or Peninsula?h provides detailed cost estimates for 

dry conversion of the TVA Kingston TN plant.90 The TVA cost study involves conversion of an existing impoundment currently used to 

dispose wet fly ash and wet bottom ash at the TVA Kingston TN electric utility plant, for future dry fly ash and dry bottom ash disposal. 

The FGD stream remains wet-sluiced before and after this hypothetical conversion in the cost study. In addition to the cost of converting 

the electric plant boilers and the impoundment for dry ash disposal, the cost study also includes the cost for construction of a new storm 

water runoff management pond (Source: row item 68 of TVA_s gAppendix C Detailed Cost Sheetsh, slide nr. TVA-00007403). 

x TVA cost study involves conversion of 475,600 cubic yards of fly ash plus bottom ash per year; this RIA estimates this quantity is 

equivalent to 880,000 tons per year, assuming 1.85 tons per cubic yard multiplier.91

 

88 Source: Dec 1997 NIPSC conversion report at http://www.babcockpower.com/pdf/rst-145.pdf 89 Source: TVA news release gTVA Coal Combustion Products Remediation Plan Proposedh, 20 Aug 2009 http://www.tva.gov/news/releases/julsep09/ccprp_other.htm 90 Source: TVA 27 January 2005 plant managers conference slide presentation (25 pages).. Wet disposal is presented as gOption 1h and dry disposal is presented as gOption 

2h in the TVA cost presentation. Additional details for the TVA cost estimates are available at http://www.tva.gov/kingston/tdec/pdf/TVA-00007402.pdf 91 "Source: 1.85 tons per cubic yard multiplier represents the midpoint from the following 1.2 to 2.5 range: According to EPA_s 1988 Report to Congress (gWastes from the 

Combustion of Coal by Electric Utility Power Plants,h page 3-14), the dry density of fly ash is 80-90 lbs/cubic ft which translates to a specific density of 1.4. The Federal 

Highway Administration studied fly ash for use in highway construction and reported its specific gravity may be as low as 1.7 to as high as 3.0. Conversion of this implied 

1.4 to 3.0 range in fly ash specific gravities to tons-per-cubic-yard as follows: 

o Low-end: (1.4 g/cm3) / (0.000001 m3/cm3) x (0.764 m3/yd3) / (1000 g/kg) x (2.204 lbs/kg) / (2000 lbs/short ton) = 1.2 short tons per cubic yard. 

o High-end: (3.0 g/cm3) / (0.000001 m3/cm3) x (0.764 m3/yd3) / (1000 g/kg) x (2.204 lbs/kg) / (2000 lbs/short ton) = 2.5 short tons per cubic yard. 
85 

x The TVA cost study did not estimate the cost for dewatering FGD (gypsum) because FGD is already dewatered by most electric utility 

plants for beneficial uses, thus only four of the 495 electric utility plants (i.e., TVA Widows Creek plant, TVA Paradise plant, Louisville 

Gas & Electric Co Trimble County plant, and Northern Indiana Public Service Company R.M. Schafer plant) wet dispose 1.9 million tons 

FGD per year in impoundments as of 2005 (source: column B of Exhibit 3G of this RIA). 

x Unit cost (i.e., average cost per ton) of conversion from wet to dry disposal estimated from the 2005 TVA cost analysis which provides cost 

estimates for converting from wet ash disposal to dry ash disposal: 

TVA wet disposal TVA dry disposal Added cost for dry Unitized dry cost

o Capital cost $13.12 million PV $38.45 million PV Cost not incremental $43.7/ton per year (@20 years) 

o Annual O&M cost $10.63 million PV $17.51 million PV $6.88 million PV $0.60/ton (@13 years) 

(Note: PV = present value for TVA_s 25-year period of analysis 2005-2029; TVA costs are in 2005$ prices) 

x Cost estimate calculation under conversion to dry disposal scenario, calculated based on TVA_s per-ton cost extrapolation to 22.4 million 

tons per year baseline wet CCR (i.e., wet fly ash, wet bottom ash, wet FGD, wet gypsum, wet other CCR) disposal in impoundments at 158 

of the 495 electric utility plants: 

o Capital cost: (22.4 million tons per year wet CCR disposal for conversion at 158 plants) x ($43.7/ton per year conversion capital 

cost) x (20 years capitalization period) x (1.174 price update multiplier92 to 2009$ price level) = $22,984 million undiscounted 

capital cost 

Annual equivalent capital: ($22,984 million) x (0.07246 capital recovery factor @7% & 50-years) = $1,665 million per year 

o O&M cost: ($0.60/ton conversion O&M cost) x (22.4 million tons/year wet CCR disposal for conversion at 158 plants) x (45 

years future operational period 2017-2061 which assumed to begin 5 years after 2012 final rule promulgation) x (1.174 price 

update multiplier to 2009$ price level) = $710 million undiscounted total O&M 

PV present value discounted @7% over 50-years = $153 million PV present value O&M 

Annual equivalent O&M: ($153 million) x (0.07246 capital recovery factor @7% & 50-years) = $11 million per year 

o Total annualized cost (capital + O&M) = ($1,665 million/year capital) + ($11 million/year O&M) = $1,676 million/year 

x Uncertainty in Land Disposal Treatment Cost Estimate 

In addition to the 2005 Tennessee Valley Authority (TVA) cost study referenced above, there are three other related cost studies (1981, 1985, 

and 2009) which are summarized below. The first two studies provide cost estimates on a per-plant basis for a few plant sizes, and the 2009 

study provides a nationwide cost estimate. This RIA did not apply these other studies because the first two are over 25-years old (i.e., 1981 and 

1985) and the third study does not provide sufficient details for verification of data and calculations. These studies are summarized below and 

used as a basis for formulating alternative nationwide cost estimates for land disposal treatment, for the purpose of illustrating the potential 

magnitude of uncertainty in this RIA_s cost estimate in relation to these other studies. 

 

92 1.174 price update multiplier represents 2009:to:2005 ratio in the Engineering-News Record Construction Cost Index: (8566 CCI for July 2009) / (7297 CCI for 2005). 
86 

x Study #1 of 3: 1981 TVA/EPA 

x In January 1981, TVA_s Energy Demonstrations and Technology Office (Chattanooga TN) co-authored with EPA_s Industrial 

Environmental Research Laboratory (Research Triangle Park NC) a study titled gEconomic Analysis of Wet Versus Dry Ash Disposal 

Systems,h Interagency Energy/Environment R&D Program Report, report no. TVA/OP/EDT-81/30 and EPA-600-7-81-013, 126 pages.93

x The study compares the relative costs of wet and dry methods of coal ash disposal for five electric plant power size categories (300 MW, 600 

MW, 900 MW, 1,300 MW, 2,600 MW) with annual coal ash generation ranging from 0.2 million to 1.7 million per year per plant. 

x Per-plant capital and O&M costs estimated based on 35-year assumed plant lifespan in 1980$. Capital costs for (a) in-plant coal ash 

handling systems, (b) conveyance/transport, and disposal units, were obtained from equipment suppliers. 

x The study found (page 67) there is not a significant difference in ash system economics based on the method of analysis. Present worth 

analysis gindicates that wet disposal is typically the least cost alternative. However, various dry disposal options are within a 15 percent 

range of those costs. The costs are, in fact, sensitive to spreading the dry disposal area capital costs over the life of the power station and 

the in-plant handling system cost. Use of either the lower dilute phase transport system cost or the dense phase collection system cost results 

in the dry disposal system alternative become the least cost alternative.h 

x The study also noted that staged construction may provide 30% saving in system total cost: g[T]he above analyses assumed construction of 

all the required facilities upon start-up. In the case of dry disposal, this is a reasonable assumption although site preparation costs would 

proceed during the development of the site. In the case of wet disposal, it may be economically sound to construct the embankment in stages, 

even if the amount of material to be placed or the engineering estimate is higher for staged construction. This is due to the high cost of the 

dam or levee and the cost of money over the life of the project. As an example... wet disposal area was analyzed for all construction 

occurring in 1980 and by a staged construction sequence (3 stages). In this case, staged construction provided a 30 percent savings in the 

total cost of the system.h 

x The 1981 study used two cost methods. The gPresent Worthh (aka present value PV) cost method findings (page 62) indicated the following 

comparative ranges in wet dry versus wet disposal costs: 

Disposal method 1980$ cost ($/ton) 2009$ update ($/ton)94

Dry disposal $2.19 to $4.50 $4.81 to $9.87 

Wet disposal $1.86 to $5.68 $4.08 to $12.46 

 

93 Source: 1981 TVA/EPA report at 

http://nepis.epa.gov/Exe/ZyNET.exe/20006ORT.TXT?ZyActionD=ZyDocument&Client=EPA&Index=1981+Thru+1985&Docs=&Query=tva+wet+dry+disposal&Time=

&EndTime=&SearchMethod=3&TocRestrict=n&Toc=&TocEntry=&QField=pubnumber%5E%22600781013%22&QFieldYear=&QFieldMonth=&QFieldDay=&UseQFie

ld=pubnumber&IntQFieldOp=1&ExtQFieldOp=1&XmlQuery=&File=D%3A%5Czyfiles%5CIndex%20Data%5C81thru85%5CTxt%5C00000000%5C20006ORT.txt&Us

er=ANONYMOUS&Password=anonymous&SortMethod=h%7C-

&MaximumDocuments=10&FuzzyDegree=0&ImageQuality=r75g8/r75g8/x150y150g16/i425&Display=p%7Cf&DefSeekPage=x&SearchBack=ZyActionL&Back=ZyAct

ionS&BackDesc=Results%20page&MaximumPages=1&ZyEntry=1&SeekPage=x 

94 1980$ costs from the 1981 TVA/EPA study updated by EPA ORCR to 2009$ using the GDP calculator at http://cost.jsc.nasa.gov/inflateGDP.html 
87 

x Using the EPA ORCR 2009$ updated unit cost midpoints displayed above yields the following rough cost estimate for the 158 electric 

utility plants with CCR impoundments: 

o Capital cost: (22.4 million tons per year wet CCR disposal for conversion at 158 plants) x ($4.81 to $9.87 per ton dry disposal 

unitized present value cost) x (40.6% capital cost fraction) x (50 years period-of-analysis for this RIA) = $2,187 million to 

$4,488 million present value capital cost 

Annualized capital cost: ($2,187 million to $4,488 million) x (0.07246 capital recovery factor @7% & 50-years) = $158.5 

million to $325.2 million per year 

o O&M cost95: (22.4 million tons per year wet CCR disposal for conversion at 158 plants) x [(($4.81 to $9.87 per ton dry disposal 

unitized present value cost) x (59.4% dry O&M fraction)) v (($4.08 to $12.46 per ton wet disposal unitized present value cost) x 

(31.6% wet O&M fraction))] x (45 years dry disposal operational period 2017-2061 which assumed to begin 5 years after 2012 

final rule promulgation) = $1,580.5 million to $1,941.4 million present value O&M 

Annualized O&M cost: ($1,580.5 million to $1,941.4 million) x (0.07246 capital recovery factor @7% & 50-years) = $114.5 

million to $140.7 million per year 

o Total annualized cost (capital + O&M) = ($158.5 million to $325.2 million per year capital) + ($114.5 million to $140.7 million 

per year O&M) = $273 million to $466 million per year 

x Study #2 of 3: 1985 EPA 

x EPA_s Air and Energy Engineering Research Laboratory (Research Triangle Park NC) published cost estimates for both wet and dry CCR 

disposal at coal-fired electric utility plants in the report gFull-Scale Field Evaluation of Waste Disposal from Coal-Fired Electric Generating 

Plantsh, document nr. EPA/600/S7-85/028, August 1985, 12 pages.96

x This is a 3-year study of waste characterization, environmental data, engineering, and cost evaluations associated with disposal of coal ash 

and FGD waste by six coal-fired electricity plants ranging in nameplate capacity between 310 to 1,786 megawatts and located in FL, IL, MN, 

NC, PA, and WY. EPA used this study to assist preparation of EPA_s 1988 gReport to Congress on Wastes from the Combustion of Coal by 

Electric Utility Power Plantsh (report no. EPA530-SW-88-002, Feb 1988). 

x This study developed ggenerich capital and annual O&M costs for both wet CCR pond disposal and dry CCR landfill disposal methods 

involving fly ash, bottom ash, and FGD, based on specific costs for the six sites combined with cost estimates from other studies by TVA, 

 

95 O&M cost extrapolation calculation in this RIA for the 1981 study applies two different O&M cost percentages based on the study_s 59.4% dry disposal O&M cost 

percentage derived from page B-10, and on the study_s 31.6% wet disposal O&M cost percentage derived from page C-11. 96 Source: 1985 EPA AEERL report at 

http://nepis.epa.gov/Exe/ZyNET.exe/2000TNFC.TXT?ZyActionD=ZyDocument&Client=EPA&Index=1981+Thru+1985&Docs=&Query=&Time=&EndTime=&SearchM

ethod=1&TocRestrict=n&Toc=&TocEntry=&QField=pubnumber%5E%22600S785028%22&QFieldYear=&QFieldMonth=&QFieldDay=&UseQField=pubnumber&IntQ

FieldOp=1&ExtQFieldOp=1&XmlQuery=&File=D%3A%5Czyfiles%5CIndex%20Data%5C81thru85%5CTxt%5C00000010%5C2000TNFC.txt&User=ANONYMOUS&

Password=anonymous&SortMethod=h%7C-

&MaximumDocuments=10&FuzzyDegree=0&ImageQuality=r75g8/r75g8/x150y150g16/i425&Display=p%7Cf&DefSeekPage=x&SearchBack=ZyActionL&Back=ZyAct

ionS&BackDesc=Results%20page&MaximumPages=1&ZyEntry=1&SeekPage=x 
88 

EPRI, and other organizations. Exhibit 4C below displays the unitized capital costs and Exhibit 4D below displays the unitized O&M costs 

from the study updated for this RIA to 2009 price level. 

x Using the 2009-updated mean unit capital and O&M cost estimates displayed in Exhibit 4C and Exhibit 4D, provides the following cost 

estimates for conversion to dry disposal, based on extrapolation to 22.4 million tons per year baseline wet CCR (i.e., wet fly ash, wet bottom 

ash, wet FGD, wet gypsum, wet other CCR) disposal in impoundments at 158 of the 495 electric utility plants which have a subtotal of 

180,901 MW nameplate total capacity: 

o Capital cost: (180,901,000 kilowatt capacity for 158 electric utility plants with surface impoundments) x ($37.60 dry conversion 

capital cost per kilowatt capacity from Exhibit 4C) = $6,810 million capital cost 

Annual equivalent cost: ($6,810 million) x (0.07246 capital recovery factor @7% & 50-years) = $494 million/year 

o O&M cost: (22.4 million tons per year wet CCR disposed in impoundments) x (-$17.40 cost savings per ton to manage for dry 

disposal from Exhibit 4D) = -$389 million per year O&M cost savings. 

o Total average annualized cost (capital + O&M) = ($494 million/year capital cost) v ($389 million/year O&M cost savings) = 

$105 million per year dry conversion cost. 

Exhibit 4C 

Comparison of Unitized Capital Costs for Wet and Dry CCR Disposal (Source: 1985 EPA Study; $/kW) 

Plant Size Categories (MW = megawatts) 

250 500 1000 2000 

Row Summary 

Across Four Size Categories 

Item Disposal Operation 

Wet or Dry 

CCR Min Max Min Max Min Max Min Max Min Max Midpnt Mean 

1A Fly ash handling/processing Wet $2.3 $6.8 $1.9 $5.5 $1.5 $6.4 $1.3 $3.6 $1.3 $6.8 $4.1 $3.7 

1B Dry $2.2 $4.1 $1.8 $3.3 $1.4 $2.7 $1.2 $2.2 $1.2 $4.1 $2.7 $2.4 

2 Fly ash storage Dry $4.7 $8.8 $4.2 $7.7 $3.7 $6.8 $3.2 $5.9 $3.2 $8.8 $6.0 $5.6 

3A Fly ash transport Wet $3.5 $6.4 $2.7 $5.1 $2.2 $4.0 $1.7 $3.2 $1.7 $6.4 $4.1 $3.6 

3B Dry $0.3 $0.5 $0.3 $0.6 $0.3 $0.5 $0.2 $0.5 $0.2 $0.6 $0.4 $0.4 

4A Fly ash placement/disposal Wet $15.1 $27.8 $12.9 $23.9 $11.0 $20.5 $9.4 $17.5 $9.4 $27.8 $18.6 $17.3 

4B Dry $4.3 $8.1 $3.3 $6.1 $2.5 $4.7 $1.9 $3.6 $1.9 $8.1 $5.0 $4.3 

5 Bottom ash 

handling/processing 

Wet/Dry $2.2 $4.6 $1.7 $3.7 $1.3 $3.0 $1.0 $2.4 $1.0 $4.6 $2.8 $2.5 

6A Bottom ash transport Wet $3.0 $5.6 $2.4 $4.5 $1.9 $3.6 $1.5 $2.8 $1.5 $5.6 $3.6 $3.2 

6B Dry $0.2 $0.4 $0.2 $0.3 $0.1 $0.2 $0.1 $0.2 $0.1 $0.4 $0.3 $0.2 

7A Bottom ash 

placement/disposal 

Wet $6.4 $11.8 $5.1 $9.6 $4.2 $7.7 $3.4 $6.2 $3.4 $11.8 $7.6 $6.8 

7B Dry $1.3 $2.4 $1.1 $2.0 $0.9 $1.6 $0.7 $1.3 $0.7 $2.4 $1.6 $1.4 

Summary: 

Wet Subtotal (1A+3A+4A+5+6A+7A) Wet (1982$) $32.5 $63.0 $26.7 $52.3 $22.1 $45.2 $18.3 $35.7 $18.3 $63.0 $40.7 $37.0 

Dry Subtotal (1B+2+3B+4B+6B) Dry (1982$) $15.2 $28.9 $12.6 $23.7 $10.2 $19.5 $8.3 $16.1 $8.3 $29.0 $18.7 $16.8 

2009 Updated Wet Subtotal* Wet (2009$) $72.8 $141.1 $59.8 $117.1 $49.5 $101.2 $41.0 $79.9 $41.0 $141.1 $91.0 $82.8 

2009 Updated Dry Subtotal* Dry (2009$) $34.0 $64.7 $28.2 $53.1 $22.8 $43.7 $18.6 $36.0 $18.6 $64.9 $41.8 $37.6 

* Note: 2009 price update multiplier (source: ENR Construction Cost Index ratio 2009:to:1982 = 8564/3825) = 2.239 
89 

Exhibit 4D 

Comparison of Annual O&M Costs for Wet and Dry CCR Disposal (Source: 1985 EPA Study; $/dry metric ton)

Plant Size Categories (MW = megawatts) 

250 500 1000 2000 

Row Summary 

Across Four Size Categories 

Item Disposal Operation 

Wet or Dry 

CCR Min Max Min Max Min Max Min Max Min Max Midpnt Mean 

Fly Ash: 

1A Fly ash handling/processing Wet $2.5 $6.8 $1.0 $5.4 $1.6 $4.3 $1.3 $3.6 $1.0 $6.8 $3.9 $3.3 

1B Dry $2.5 $4.7 $2.1 $3.9 $1.7 $3.2 $1.5 $2.7 $1.5 $4.7 $3.1 $2.8 

2 Fly ash storage Dry $3.3 $6.1 $3.0 $5.6 $2.8 $5.2 $2.5 $4.7 $2.5 $6.1 $4.3 $4.2 

3A Fly ash transport Wet $4.2 $7.6 $3.2 $5.9 $2.5 $4.7 $2.0 $3.7 $2.0 $7.6 $4.8 $4.2 

3B Dry $1.7 $3.1 $1.5 $2.8 $1.3 $2.5 $1.2 $2.2 $1.2 $3.1 $2.2 $2.0 

4A Fly ash placement/disposal Wet $11.5 $21.3 $9.1 $16.8 $7.2 $13.5 $5.7 $10.5 $5.7 $21.3 $13.5 $12.0 

4B Dry $7.0 $13.0 $5.6 $10.5 $4.6 $8.5 $3.7 $6.9 $3.7 $13.0 $8.4 $7.5 

 Subtotal fly ash Wet (1982$) $18.2 $35.7 $13.3 $28.1 $11.3 $22.5 $9.0 $17.8 $8.7 $35.7 $22.2 $19.5 

 Dry (1982$) $11.2 $20.8 $9.2 $17.2 $7.6 $14.2 $6.4 $11.8 $6.4 $20.8 $13.6 $12.3 

Bottom Ash: 

5 Bottom ash 

handling/processing 

Wet/Dry $11.3 $22.8 $9.0 $19.1 $6.9 $15.7 $5.3 $12.8 $5.3 $22.8 $14.1 $12.9 

6A Bottom ash transport Wet $9.2 $17.1 $7.3 $13.5 $5.6 $10.3 $4.3 $7.9 $4.3 $17.1 $10.7 $9.4 

6B Dry $3.4 $6.3 $2.8 $5.2 $2.2 $4.1 $1.8 $3.3 $1.8 $6.3 $4.1 $3.6 

7A Bottom ash 

placement/disposal 

Wet $9.2 $17.1 $7.9 $14.6 $6.5 $12.1 $5.4 $10.0 $5.4 $17.1 $11.3 $10.4 

7B Dry $5.4 $10.0 $4.7 $8.8 $4.1 $7.6 $3.5 $6.5 $3.5 $10.0 $6.8 $6.3 

 Subtotal bottom ash Wet (1982$) $29.7 $57.0 $24.2 $47.2 $19.0 $38.1 $15.0 $30.7 $15.0 $57.0 $36.0 $32.6 

 Dry (1982$) $20.1 $39.1 $16.5 $33.1 $13.2 $27.4 $10.6 $22.6 $10.6 $39.1 $24.9 $22.8 

Summary (Fly Ash & Bottom Ash): 

Weighted average* Wet (1982$) $20.7 $40.4 $15.7 $32.3 $13.0 $25.9 $10.3 $20.6 $10.1 $40.4 $25.2 $22.4 

 Dry (1982$) $13.2 $24.8 $10.8 $20.7 $8.8 $17.1 $7.3 $14.2 $7.3 $24.8 $16.1 $14.6 

2009 updated weighted average** Wet (2009$) $46.4 $90.4 $35.2 $72.3 $29.1 $58.1 $23.1 $46.2 $22.6 $90.4 $56.5 $50.1 

 Dry (2009$) $29.5 $55.6 $24.2 $46.4 $19.8 $38.3 $16.4 $31.8 $16.4 $55.6 $36.0 $32.7 

Incremental cost from conversion to dry disposal = -$17.4 

Notes: 

* Fly:to:ash weighted average based on 2005 relative annual tonnages evaluated in the RIA: Fly ash tons/year = 15,200,000; Bottom ash tons/year = 4,300,000 

** 2009 price update multiplier (source: ENR Construction Cost Index ratio 2009:to:1982 = 8564/3825) = 2.239 
90 

x Study #3 of 3: 2009 USWAG 

x On 11 June 2009 the Utility Solid Waste Action Group (Jim Roewer, Executive Director) provided to EPA a 14-page cost study USWAG 

sponsored by the EOP Group Inc., containing an estimate of $39,000 million present value (PV) for conversion to dry disposal: gCost 

Estimates for Closure of Ash Ponds at Fossil Fuel Power Generation Facilitiesh, prepared in 2009 by EOP Group Inc. USWAG/EOP_s

$39,000 million PV estimate uses a 3% discount rate over 20 years with a 10-year implementation period, and consists of:

o $12,900 million PV (33%) for fly ash and bottom ash conversion to dry disposal

o $2,500 million PV (6%) for foregone sunk cost in ponds

o $23,700 million PV (61%) for construction of new wastewater plants for other non-ash ancillary wastewaters (e.g., stormwater) 

which are currently co-mingled with the wet ash.

x For purpose of comparing this estimate with the other two cost studies above, the following rough calculations extend the O&M costs from 

the 20-year period from the USWAG/EOP study, to the 50-year period applied in this RIA:

o Dry management O&M cost = ($2.00 per ton higher cost than wet management) x (20.6 million tons per year in 

impoundments) x (40-years after 10-year impoundment phase-out) = $1,648 million (undiscounted). 

PV discounted @7% over 50-years = $279 million PV present value 

o Waste water treatment plant (WWTP) O&M cost = ($525 million per year) x (40-years after 10-year impoundment phase-out) 

= $21,000 million (undiscounted). 

PV discounted @7% over 50-years = $3,558 million PV present value 

x Substituting these 50-year based PV O&M cost estimates for the 20-year based PV O&M cost estimates into the USWAG/EOP 

$39,000 million 20-year PV total cost estimate produces the following 50-year based average annualized cost: 

o Capital cost:($39,000 million PV total cost) v ($400 million 20-year PV dry management O&M) v ($5,200 million 20-year PV 

WWTP O&M) = $33,400 million PV capital cost 

Annual equivalent capital cost: ($33,400 million PV) x (0.07246 capital recovery factor @7% & 50-years) = $2,420 million per 

year annualized capital cost 

o O&M cost: ($279 million 50-year PV dry management O&M) + ($3,558 million 50-year PV WWTP O&M) = $3,837 million 

PV present value O&M 

Annualized O&M cost: ($3,837 million PV) x (0.07246 capital recovery factor @7% & 50-years) = $278 million per year O&M 

o Total annualized cost (capital + O&M) = $2,698 million per year 

Exhibit 4E below presents a summary of the extrapolated cost estimates based on the per-plant cost findings from these three alternative cost 

studies, compared to the cost estimate based on the 2005 TVA cost study applied in this RIA. 
91 

Exhibit 4E 

Summary of Wet Conversion Cost Estimates Based on Four Alternative Studies 1981, 1985, 2005, 2009 

($millions updated to 2009$) 

A B C D E (A to D) 

Type of Dry Conversion 

Cost Element 

Cost Study #1 

EPA 1981 

Cost Study #2 

EPA 1985 

Selected for Basis 

of the Estimate 

Applied in this 

RIA 

Cost Study #3 

TVA 2005 

Cost Study #4 

USWAG/EOP 2009 Implied Range 

1. Capital cost: 

1a. Present value (PV) = $2,187 to $4,488 $6,810 $22,984 $33,400 $2,187 to $33,400 

1b. Annualized equivalent* = $158 to $325 $494 $1,665 $2,420 $158 to $2,420 

2. Average annual O&M cost $115 to $141 -$389 savings $11 $278 -$389 savings to $278 

3. Total annualized cost (1b+2) $273 to $466 $105 $1,676 

(PV** = $23,137) 

$2,698 $105 to $2,698 

Row 3 implied uncertainty range compared to estimate based on 2005 TVA study = -94% to +61% 

Notes: 

* Annualized over a 50-year period @7% discount rate. 

** Present value computed by multiplying the annualized value by a 13.801 present value multiplier, which represents 7% discount over 50-years. 

x Update of Cost Estimate for Converting from Wet to Dry CCR Disposal 

o Purpose of Dry Conversion Cost Estimate Update 

The purpose of this section is to update the initial estimate above in this RIA, of the cost of converting CCR disposal impoundments to dry 

disposal (i.e., landfills). The initial $23.137 billion estimate (present value discounted at 7% over 50-years) presented in above in this section 

of the RIA is based on the 2005 universe of 158 coal-fired electric utility plants (classified in NAICS code 22) with active CCR impoundments 

addressed in EPA_s October 2009 draft RIA for the proposed rule. Exhibit 4F below provides a summary of this initial cost estimate.97 As of 

February 2010, the 2005 universe is the latest available data from the U.S. Department of Energy_s Energy Information Administration (EIA) 

Form 767 database, because the EIA temporarily suspended its electric utility industry data collection survey questionnaire to revise it. 

 

97 EPA_s 2009 draft RIA cost estimate was based on an extrapolation of a cost estimate developed in 2005 by the Tennessee Valley Authority (TVA) for converting its 

Kingston TN coal-fired electric plant to dry disposal of fly ash and bottom ash. In the RIA, EPA (a) unitized TVA_s cost estimate on a cost-per-ton basis for both the 

capital cost and annual O&M cost components, and then (b) extrapolated the unit costs to the 2005 national universe of 22.4 million tons wet disposed CCR associated with 

the 158 electric utility plants with active CCR impoundments as of 2005. Exhibit 4F below displays how the draft RIA timed the capital and O&M costs over the 50-year 

period of analysis applied in the RIA (2012 to 2061), and the result of discounting the 50-year cost stream at a 7% annual rate. 
92 

Exhibit 4F 

PR O P O SE D R U L E OC T 200 9 R IA "O P T IO N 1" (R C R A S u b tile C 30 04x )

Al l Im p o u n d m e n ts M u s t C o n v e rt to D ry A s h S y s te m in 5 -Y e a rs

C a p it a l co st fo r c o n ve rs io n to d r y (n o n -d is c o u n t e d lu m p -s u m ) = $ 2 2 ,9 8 4 , 0 0 0 ,0 0 0

A d d e d a n n u a l O & M f o r d r y co m p a re d to w e t (n o n -d i sc o u n te d ) = $ 1 5 , 8 0 0 , 0 0 0

A B

5- Year pha se -out

C o u n t o f e x is ti n g 0 8 O c t 2 0 0 9 d ra ft R I A

e le c t ric u tilit y s im p le e s t im a t e if

p la n t s w it h lu m p -s u m c a p i ta l c o s t

R o w Y e a r im p o u n d m e n t s i n 1 st ye a r o f f in a l ru le

1 201 2 1 5 8 $ 2 2 , 9 8 4 ,0 0 0 , 0 0 0

2 201 3 158 $0

3 201 4 158 $0

4 201 5 158 $0

5 201 6 158 $0

6 2 0 1 7 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

7 2 0 1 8 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

8 2 0 1 9 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

9 2 0 2 0 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

1 0 2 0 2 1 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

1 1 2 0 2 2 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

1 2 2 0 2 3 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

1 3 2 0 2 4 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

1 4 2 0 2 5 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

1 5 2 0 2 6 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

1 6 2 0 2 7 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

1 7 2 0 2 8 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

1 8 2 0 2 9 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

1 9 2 0 3 0 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

2 0 2 0 3 1 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

2 1 2 0 3 2 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

2 2 2 0 3 3 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

2 3 2 0 3 4 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

2 4 2 0 3 5 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

2 5 2 0 3 6 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

2 6 2 0 3 7 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

2 7 2 0 3 8 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

2 8 2 0 3 9 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

2 9 2 0 4 0 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

3 0 2 0 4 1 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

3 1 2 0 4 2 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

3 2 2 0 4 3 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

3 3 2 0 4 4 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

3 4 2 0 4 5 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

3 5 2 0 4 6 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

3 6 2 0 4 7 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

3 7 2 0 4 8 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

3 8 2 0 4 9 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

3 9 2 0 5 0 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

4 0 2 0 5 1 1 5 8 $ 2 2 , 9 8 4 ,0 0 0 , 0 0 0

4 1 2 0 5 2 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

4 2 2 0 5 3 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

4 3 2 0 5 4 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

4 4 2 0 5 5 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

4 5 2 0 5 6 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

4 6 2 0 5 7 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

4 7 2 0 5 8 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

4 8 2 0 5 9 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

4 9 2 0 6 0 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

5 0 2 0 6 1 1 5 8 $ 1 5 ,8 0 0 , 0 0 0

N o n -d is c o u n t e d t o ta l c o s t = $ 4 6 , 6 6 3 ,0 0 0 , 0 0 0

N o n -d is co u n t e d a v e ra g e c o s t = $ 9 3 3 ,0 0 0 , 0 0 0

P re s e n t va lu e c o s t (@ 7 % d is c .r a te ) = $ 2 3 , 1 6 7 ,0 0 0 , 0 0 0

A v e r a g e a n n u a liz e d c o s t (@ 7 % d is c .r a te ) = $ 1 ,6 7 9 , 0 0 0 , 0 0 0

Dis c o u n t ra t e = 7 %

A n n u a l e n g in e e ri n g + a n c illa r y co st s f o r R I A " O p t io n 1 " S u b t itle C = $ 5 9 5 ,0 0 0 , 0 0 0

T o t a l a n n u a lize d c o s t f o r R I A " O p t io n 1 " S u b t itle C = $ 2 ,2 7 4 ,0 0 0 ,0 0 0

P re se n t v a lu e c o s t (@ 7 % d is c . ra t e ) = $ 3 1 , 3 8 3 ,0 0 0 , 0 0 0

PR O P O SE D R U L E OC T 200 9 R IA "O P T IO N 1" (R C R A S u b tile C 30 04x )

Al l Im p o u n d m e n ts M u st C o n vert to D ry A sh S ys te m in 5 -Y e a rs

C a p it a l co st fo r c o n ve rs io n to d r y (n o n -d is c o u n t e d lu m p -s u m ) = $ 2 2 ,9 8 4 , 0 0 0 ,0 0 0

A d d e d a n n u a l O & M f o r d r y co m p a re d to w e t (n o n -d i sc o u n te d ) = $ 1 5 , 8 0 0 , 0 0 0

A B

5- Year pha se -out

Co u n t o f e x is ti n g 0 8 O c t 2 0 0 9 d ra ft RI A

e le c tric u tilit y s im p le e s tim a t e if

p la n t s w ith lu m p -s u m c a p i ta l c o s t

R o w Y e a r im p o u n d m e n t s i n 1 st ye a r o f f in a l ru le

1 201 2 1 5 8 $ 2 2 , 9 8 4 ,0 0 0 ,0 0 0

2 201 3 158 $0

3 201 4 158 $0

4 201 5 158 $0

5 201 6 158 $0

6 2 0 1 7 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

7 2 0 1 8 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

8 2 0 1 9 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

9 2 0 2 0 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

1 0 2 0 2 1 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

1 1 2 0 2 2 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

1 2 2 0 2 3 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

1 3 2 0 2 4 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

1 4 2 0 2 5 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

1 5 2 0 2 6 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

1 6 2 0 2 7 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

1 7 2 0 2 8 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

1 8 2 0 2 9 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

1 9 2 0 3 0 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

2 0 2 0 3 1 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

2 1 2 0 3 2 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

2 2 2 0 3 3 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

2 3 2 0 3 4 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

2 4 2 0 3 5 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

2 5 2 0 3 6 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

2 6 2 0 3 7 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

2 7 2 0 3 8 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

2 8 2 0 3 9 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

2 9 2 0 4 0 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

3 0 2 0 4 1 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

3 1 2 0 4 2 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

3 2 2 0 4 3 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

3 3 2 0 4 4 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

3 4 2 0 4 5 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

3 5 2 0 4 6 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

3 6 2 0 4 7 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

3 7 2 0 4 8 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

3 8 2 0 4 9 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

3 9 2 0 5 0 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

4 0 2 0 5 1 1 5 8 $ 2 2 , 9 8 4 ,0 0 0 ,0 0 0

4 1 2 0 5 2 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

4 2 2 0 5 3 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

4 3 2 0 5 4 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

4 4 2 0 5 5 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

4 5 2 0 5 6 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

4 6 2 0 5 7 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

4 7 2 0 5 8 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

4 8 2 0 5 9 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

4 9 2 0 6 0 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

5 0 2 0 6 1 1 5 8 $ 1 5 ,8 0 0 ,0 0 0

N o n -d is c o u n t e d t o ta l c o s t = $ 4 6 , 6 6 3 ,0 0 0 ,0 0 0

N o n -d is co u n t e d a v e ra g e c o s t = $ 9 3 3 ,0 0 0 ,0 0 0

P re s e n t va lu e c o s t (@ 7 % d is c .r a te ) = $ 2 3 ,1 6 7 ,0 0 0 , 0 0 0

A v e r a g e a n n u a liz e d c o s t (@ 7 % d is c .r a te ) = $ 1 ,6 7 9 ,0 0 0 , 0 0 0

Dis c o u n t ra t e = 7 %

A n n u a l e n g in e e ri n g + a n c illa r y co sts fo r R I A " O p tio n 1 " S u b t itle C = $ 5 9 5 ,0 0 0 ,0 0 0

T o t a l a n n u a lize d c o s t fo r R I A " O p tio n 1 " S u b t itle C = $ 2 ,2 7 4 ,0 0 0 , 0 0 0

P re se n t v a lu e c o s t (@ 7 % d is c . ra t e ) = $ 3 1 ,3 8 3 ,0 0 0 , 0 0 0
93 

o Recent Trend in CCR Impoundment Phase-Outs 

Since formulating the initial cost estimate above, EPA obtained new information which indicates that many electric utility plants have already 

closed or are planning to close CCR impoundments and convert to dry disposal (i.e., landfill disposal and/or sell and transport dry CCR offsite 

for beneficial use by other industries) for reasons independent of the CCR proposed rule. As displayed below in Exhibit 4G, EIA_s historical 

data98 for the electric utility industry indicate that between 1996 and 2005, the tonnage of CCR disposed in impoundments has decreased by 

10% from 25.2 to 22.5 million tons despite total CCR generation at electric utility plants increasing 24% over that same period from 102.0 

million tons (1996) to 126.3 million tons (2005). This represents an average annual CCR impoundment phase-out rate of 1.1% per year. 

 1996 2005 10-year decrease

Tonnage wet disposal 25.188 million 22.537 million 10% 

Percentage of generation 25% of CCR 18% of CCR 7% 

Exhibit 4G 

Documentation of Recent Trend (1996-2005) In Switching From Wet to Dry CCR Disposal in the US Electric Utility Industry 

Coal Ash, FGD Waste - EIA Data

Thousand Short Tons

Utility 

Landfill 

(Dry)

Utility 

Disposal 

Ponds 

(Wet)

On Site 

Use and 

Storage Sold

Off Site 

Disposal Total %

Utility 

Landfill 

(Dry)

Utility 

Disposal 

Ponds 

(Wet)

On Site 

Use and 

Storage Sold

Off Site 

Disposal Total %

Fly Ash 21,450 15,710 2,446 12,091 8,110 59,806 59% 22,557 15,322 4,645 21,211 10,626 74,360 59%

Bottom Ash 5,340 4,973 1,968 4,322 2,537 19,140 19% 6,109 4,374 3,553 5,767 2,177 21,981 17%

Sludge 12,938 3,484 1,011 236 987 18,655 18% 9,592 1,886 467 409 2,507 14,861 12%

Gypsum 502 987 379 1,190 88 3,146 3% 55 872 372 8,513 783 10,595 8%

Other 171 35 0 691 305 1,202 1% 227 83 116 3,749 315 4,490 4%

Total 40,401 25,188 5,804 18,529 12,028 101,950 100% 38,539 22,537 9,153 39,650 16,407 126,286 100%

% Share of Total

Utility 

Landfill 

(Dry)

Utility 

Disposal 

Ponds 

(Wet)

On Site 

Use and 

Storage Sold

Off Site 

Disposal Total

Utility 

Landfill 

(Dry)

Utility 

Disposal 

Ponds 

(Wet)

On Site 

Use and 

Storage Sold

Off Site 

Disposal Total

Fly Ash 36% 26% 4% 20% 14% 100% 30% 21% 6% 29% 14% 100%

Bottom Ash 28% 26% 10% 23% 13% 100% 28% 20% 16% 26% 10% 100%

Sludge 69% 19% 5% 1% 5% 100% 65% 13% 3% 3% 17% 100%

Gypsum 16% 31% 12% 38% 3% 100% 1% 8% 4% 80% 7% 100%

Other 14% 3% 0% 57% 25% 100% 5% 2% 3% 84% 7% 100%

Total 40% 25% 6% 18% 12% 100% 31% 18% 7% 31% 13% 100%

1996 2005

1996 2005

 

98 Source: US Department of Energy EIA F767_PLANT database at: http://www.eia.doe.gov/cneaf/electricity/page/eia767.html 
94 

One important reason for this change is that dry systems allow plants more flexibility in the type of coal they use as fuel. For example, as 

plants switched from bituminous to sub-bituminous coal, they also converted to dry fly ash handling systems because the ash from some subbituminous coals has cementitious properties that can cause plugging and high maintenance costs for some wet ash disposal systems, thus 

necessitating dry ash systems. Also, some types of sub-bituminous coal fly ash are in economic demand by the cement industry because of 

their low carbon content and need to be stored dry for transport. EIA_s historical data for coal-fired electric plant fly ash disposal confirms this 

same trend away from wet disposal to dry disposal (and to beneficial reuse). In 1996, 26% of fly ash was disposed of in ponds (aka 

gimpoundmentsh). This fly ash disposal method dropped to 21% in 2005. 

x Possible Factors Behind this CCR Dry Disposal Conversion Trend 

In the next few years, there will be a number of factors that may affect the way coal-fired plants in the electric utility industry operate 

that may further encourage CCR dry disposal rather than wet disposal. Five example factors are: 

1. Federal regulations: EPA plans to issue a number of regulations that will affect electric utility plants under the Clean Air Act 

and the Clean Water Act. For example anticipated Clean Air Act regulations will likely lead to increased use of SO2 

controls on existing electric utility plants that will increase the tonnage of flue gas desulfurization (FGD) solids that must be 

processed (i.e., beneficially used or disposed) and is some cases add calcium derivatives to the existing fly ash (through use 

of dry scrubbers). While the incremental costs of handling such additional materials are site specific, there are a number of 

factors that are likely to drive electric utility companies to give more consideration to dry CCR disposal. While wet disposal

was common on earlier generations of wet scrubbers, in recent cases, some electric utility companies have focused much 

more strongly on options to reduce costs by finding beneficial uses for CCR. Furthermore, given the magnitude of the 

upcoming projects and growing public interest in how CCR are handled and disposed, expediting approval of the project 

may also drive towards consideration of dry disposal methods. 

2. State regulations: A number of state governments are considering programs that may affect their respective state-wide 

economic demand for electricity. 

3. Technology: New technologies for generation, transmission, and use of electricity are being introduced into the market. 

4. Fuel cost: Spot markets for coal make it easy for plants to fuel switch or mix coal fuel types. This means, among other 

things that wet CCR disposal systems, because they limit the types of coal that these plants can use, are likely to be further 

reduced. 

5. Plant property: As land availability constraints becomes more important to electric utility plants (e.g., some electric utility 

plants are located in riparian settings), on-site wet disposal areas become less important in favor of smaller footprint on-site 

dry disposal landfills and sending CCR off-site for disposal or beneficial use. 

As electric utility companies face this myriad of changes, they are likely to be reconsidering at a very detailed level how they are 

operating their plants. In fact, this is evident in the fact that some electric utility companies have already announced actual or planned 

closures of a number of coal-fired electric generator units, while other companies have announced plans to switch some units or plants 
95 

from coal to other fuels such as natural gas. This consideration of the way electric utility plants will operate is likely to include a 

reconsideration of how the plants will handle and disposal CCR. Furthermore, since future air pollution regulations are likely to cause 

more reassessment at electricity plants with older and less efficient air emission particulate control devices and air pollution scrubbers, 

air regulations themselves are likely to provide further inducement to reconsider CCR disposal practices at plants that are currently 

using wet disposal. These actions in the near future also mean that the market and regulatory environment in which these plants operate 

will continue to be in flux and the ability to operate in a way that will make them able to respond quickly to changes will be important. 

Corroborating continuation of this historical phase-out trend are recent (2009) announcements by five electric utility companies (i.e., Tennessee 

Valley Authority (TVA), Duke Energy Company, Hoosier Energy REC Inc, Vectren Southern Indiana Gas & Electric Company, and Westar 

Energy Company)99 that they plan to convert all or a significant portion of their CCR impoundments to dry management within the next 10 

years corroborates continuation of this recent impoundment phase-out trend. These 18 plants alone comprise 17% of the annual 22.4 million 

tons CCR disposed annually in impoundments (as of 2005). In addition, three companies have announced planned coal-fired electricity plant 

closures or planned switching from coal to other fuels. These three plants comprise 3% of the annual CCR impoundment disposal tonnage. 

See Exhibit 4H below for a list of these companies, their plant names, and associated CCR impoundment disposal annual tonnages. Future 

developments in the electric utility industry, including compliance with upcoming Clean Air Act and Clean Water Act regulations under 

development at EPA, will increase the dry disposal conversion trend. It is inappropriate to assign the costs of these conversions to the CCR 

proposed rule, because they would happen anyway, in absence of the rule. 

 

99 TVA_s 20 August 2009 news release gTVA Coal Combustion Products Remediation Plan Proposedh announced that TVA plans gto convert all TVA wet ash and gypsum 

storage to dry{over eight to 10 years.h . Recent plans to convert from wet CCR impoundment disposal to dry landfill disposal for electric utility plants operated by the 

Duke Energy Company, the Hoosier Electric Cooperative, and Vectren Southern Indiana Gas & Electric Company were reported 24 October 2009 by Mark Wilson of the 

Courier Press gCoal Ash Disposal Varies From Company to Companyh at http://btop.courierpress.com/news/2009/oct/24/coal-ash-disposal-varies-from-company-tocompany/?print=1 

Westar Energy apparently converted to dry fly ash management by December 2006 according to gCoal Plant O&M: Retrofit Flyash-Handling System Pays Dividends,h 

Douglas J. Smith, Contributing Editor, Coal Power magazine, 01 Nov 2007: http://www.coalpowermag.com/transportation/Coal-Plant-O-and-M-Retrofit-Flyash-HandlingSystem-Pays-Dividends_79.html 
96 

Exhibit 4H 

Lists of Coal-Fired Electric Utility Plants With Active CCR Impoundments (as of 2005) 

Which are Either Voluntarily Planning to Convert to Dry Disposal 

or Voluntarily Planning to Close or Switch Away from Coal to Another Fuel Source (e.g., Natural Gas) 

Plants With CCR Impoundments Soon Converting to Dry Disposal* 

Coal-Fired Electric Utility Plants Closing 

or Switching Away From Coal Fuel with CCR Impoundments** 

A B C D E F G H 

Company Name Plant Name State 2005 CCR 

Pond Tons 

(1,000s)**

* 

Company Name Plant Name State 2005 CCR 

Pond Tons 

(1,000s)***

1. PSI Energy Inc (Duke Energy) Cayuga IN 210.9 1. Progress Energy Cape Fear NC 101.3 

2. PSI Energy Inc (Duke Energy) Edwardsport IN 11.5 2. Progress Energy Lee NC 106.1 

3. PSI Energy Inc (Duke Energy) R Gallagher IN 125.6 3. Progress Energy L V Sutton NC 166.0 

4. PSI Energy Inc (Duke Energy) Wabash River IN 192.1 4. Progress Energy W H Weatherspoon NC 47.0 

5. PSI Energy Inc (Duke Energy) Gibson IN 897.8 5. Duke Energy Company Buck NC 121.9 

6. Tennessee Valley Authority Colbert TN 29.2 6. Duke Energy Company Dan River NC 28.5 

7. Tennessee Valley Authority Widows Creek TN 852.8 7. Northern States (Xcel Energy) High Bridge MN 0.01 

8. Tennessee Valley Authority Paradise TN 517.9 8. Northern States (Xcel Energy) Riverside MN 6.7 

9. Tennessee Valley Authority Shawnee TN 61.1 

10. Tennessee Valley Authority Bull Run TN 22.4 

11. Tennessee Valley Authority Gallatin TN 180.5 

12. Tennessee Valley Authority John Sevier TN 10.0 

13. Tennessee Valley Authority Johnsonville TN 53.7 

14. Tennessee Valley Authority Kingston TN 325.9 

15. Southern Indiana Gas & 

Electric Company (Vectren) 

F B Culley IN 35.6 

16. Southern Indiana Gas & 

Electric Company (Vectren) 

A B Brown IN 165.8 

17. Hoosier Energy R E C Inc Frank E Ratts IN 39.8 

18. Westar Energy Jeffrey Energy 

Center 

KS 184.1 

Subtotal impoundment tons for 18 plants listed above = 3,916.7 Subtotal for 8 plants listed above = 577.51 

% of 22.4 million tons 2005 wet disposal tonnage by 158 plants = 17% % of 22.4 million tons 2005 wet disposal tonnage by 158 plants = 3% 

Notes: 

* EPA-ORCR identified the 18 plants with recent plans to convert from wet to dry CCR landfill disposal for electric utility plants operated by the Duke Energy 

Company, the Vectren Company, and the Hoosier Electric Cooperative, from the 24 October 2009 news report by Mark Wilson of the Courier Press gCoal Ash Disposal 

Varies From Company to Company.h . The Westar Energy plant was identified by an EPA-ORCR staff person based on knowledge of that specific plant or company. 

** EPA identified the 8 plants switching from coal from SourceWatch websites: http://www.sourcewatch.org/index.php?title=Coal_plant_conversion_projects

and http://www.sourcewatch.org/index.php?title=Existing_U.S._Coal_Plants 

*** Source: Based on the 2005 DOE-EIA data. 
97 

o Result of Dry Conversion Cost Update 

The result of this dry conversion cost update is displayed below in comparison to the initial conversion cost estimate. The adjusted cost 

incorporates the average annual 1.1% decrease in CCR impoundment disposal tonnage calculated based on the 1996-2005 EIA data trend as 

presented in Exhibit 4G above, relative to the 2005 base year impoundment disposal tonnage of 22.4 million tons over the same 50-year period 

(i.e., 2012 to 2061) applied in the RIA. This adjustment provides a declining future CCR impoundment tonnage trend which would be 

impacted by the CCR proposed rule when it is implemented, rather than simply assigning to the rule a dry conversion cost for the entire 2005 

impoundment tonnage (i.e., 22.4 million tons) as was done in the initial cost estimate. The cost adjustment using this trend involved two steps: 

Step 1: Assign a dry conversion cost to the extrapolation phase-out trend (i.e., 2006 to 2061) representing what the electric utility 

industry could be expected to incur in the future in absence of the CCR rule. The results of this 1st step are displayed in columns A1 to 

A4 of Exhibit 4I below. 

Step 2: Re-estimate the phase-out cost under this same industry trend but by adding the requirement under the CCR rule that all 

remaining CCR impoundment tonnage that is not projected to be voluntarily phased-out within 5-years of the final rule_s adoption must 

be phased-out. This step incorporates three assumptions: (a) EPA promulgates the final rule at the start of 2012, (b) state governments 

adopt the final rule 2-years later at end of 2013, and (c) the final rule allows a 5-year phase-out period which spans 2014 to 2018. The 

results of this 2nd step are displayed in columns B1 to B4 of Exhibit 4I below. 
98 

Exhibit 4I 

Adjustment of Dry Conversion Cost Estimate to Account for Utility Industry's Voluntary Impoundment Phase-Out Trend A1 A2 A3 A4 B1 B2 B3 B4

A. Cost of Dry Conversion Trend Without CCR Rule B. Dry Conversion Cost if Mandated by CCR Rule

Incremental added Incremental added

cost year-by-year ---- Mandatory cost year-by-year ----

Projected Year-by-year regression trendline Regression trendline year-by-year mandatory Mandatory

trendline RIA 50-year End Regression trendline incremental dry conversion dry conversion Mandatory wet incremental dry conversion dry conversion

year period of of wet disposal phaseout conversion to dry cost projection cumulative cost phaseout within conversion to dry cost projection cumulative cost

count analysis year (million tons/year) (million tons/year) without CCR rule without CCR rule 5-years of rule (million tons/year) with CCR rule with CCR rule

1 2005 22.5 Base year Base year Base year 22.5 Base year Base year Base year

2 2006 22.2 0.3 $22,122,377 $22,122,377 22.2 0.3 $22,122,377 $22,122,377

3 2007 21.9 0.3 $22,122,377 $44,244,754 21.9 0.3 $22,122,377 $44,244,754

4 2008 21.7 0.3 $22,122,377 $66,367,131 21.7 0.3 $22,122,377 $66,367,131

5 2009 21.4 0.3 $22,122,377 $88,489,508 21.4 0.3 $22,122,377 $88,489,508

6 2010 21.1 0.3 $22,122,377 $110,611,885 21.1 0.3 $22,122,377 $110,611,885

7 2011 20.8 0.3 $22,122,377 $132,734,262 20.8 0.3 $22,122,377 $132,734,262

8 1 2012 20.5 0.3 $22,122,377 $154,856,640 20.5 0.3 $22,122,377 $154,856,640

9 2 2013 20.2 0.3 $22,122,377 $176,979,017 20.2 0.3 $22,122,377 $176,979,017

10 3 2014 19.9 0.3 $22,122,377 $199,101,394 19.9 4.0 $298,704,663 $475,683,680

11 4 2015 19.6 0.3 $22,122,377 $221,223,771 19.6 4.0 $298,704,663 $774,388,344

12 5 2016 19.3 0.3 $22,122,377 $243,346,148 19.3 4.0 $298,704,663 $1,073,093,007

13 6 2017 19.0 0.3 $22,122,377 $265,468,525 19.0 4.0 $298,704,663 $1,371,797,671

14 7 2018 18.7 0.3 $22,122,377 $287,590,902 18.7 4.0 $298,704,663 $1,670,502,334

15 8 2019 18.4 0.3 $22,122,377 $309,713,279 0 0 $0 $1,670,502,334

16 9 2020 18.1 0.3 $22,122,377 $331,835,656 0 0 $0 $1,670,502,334

17 10 2021 17.8 0.3 $22,122,377 $353,958,033 0 0 $0 $1,670,502,334

18 11 2022 17.5 0.3 $22,122,377 $376,080,410 0 0 $0 $1,670,502,334

19 12 2023 17.2 0.3 $22,122,377 $398,202,787 0 0 $0 $1,670,502,334

20 13 2024 16.9 0.3 $22,122,377 $420,325,164 0 0 $0 $1,670,502,334

21 14 2025 16.6 0.3 $22,122,377 $442,447,541 0 0 $0 $1,670,502,334

22 15 2026 16.4 0.3 $22,122,377 $464,569,919 0 0 $0 $1,670,502,334

23 16 2027 16.1 0.3 $22,122,377 $486,692,296 0 0 $0 $1,670,502,334

24 17 2028 15.8 0.3 $22,122,377 $508,814,673 0 0 $0 $1,670,502,334

25 18 2029 15.5 0.3 $22,122,377 $530,937,050 0 0 $0 $1,670,502,334

26 19 2030 15.2 0.3 $22,122,377 $553,059,427 0 0 $0 $1,670,502,334

27 20 2031 14.9 0.3 $22,122,377 $575,181,804 0 0 $0 $1,670,502,334

28 21 2032 14.6 0.3 $22,122,377 $597,304,181 0 0 $0 $1,670,502,334

29 22 2033 14.3 0.3 $22,122,377 $619,426,558 0 0 $0 $1,670,502,334

30 23 2034 14.0 0.3 $22,122,377 $641,548,935 0 0 $0 $1,670,502,334

31 24 2035 13.7 0.3 $22,122,377 $663,671,312 0 0 $0 $1,670,502,334

32 25 2036 13.4 0.3 $22,122,377 $685,793,689 0 0 $0 $1,670,502,334

33 26 2037 13.1 0.3 $22,122,377 $707,916,066 0 0 $0 $1,670,502,334

34 27 2038 12.8 0.3 $22,122,377 $730,038,443 0 0 $0 $1,670,502,334

35 28 2039 12.5 0.3 $22,122,377 $752,160,821 0 0 $0 $1,670,502,334

36 29 2040 12.2 0.3 $22,122,377 $774,283,198 0 0 $0 $1,670,502,334

37 30 2041 11.9 0.3 $22,122,377 $796,405,575 0 0 $0 $1,670,502,334

38 31 2042 11.6 0.3 $22,122,377 $818,527,952 0 0 $0 $1,670,502,334

39 32 2043 11.3 0.3 $22,122,377 $840,650,329 0 0 $0 $1,670,502,334

40 33 2044 11.0 0.3 $22,122,377 $862,772,706 0 0 $0 $1,670,502,334

41 34 2045 10.8 0.3 $22,122,377 $884,895,083 0 0 $0 $1,670,502,334

42 35 2046 10.5 0.3 $22,122,377 $907,017,460 0 0 $0 $1,670,502,334

43 36 2047 10.2 0.3 $22,122,377 $929,139,837 0 0 $0 $1,670,502,334

44 37 2048 9.9 0.3 $22,122,377 $951,262,214 0 0 $0 $1,670,502,334

45 38 2049 9.6 0.3 $22,122,377 $973,384,591 0 0 $0 $1,670,502,334

46 39 2050 9.3 0.3 $22,122,377 $995,506,968 0 0 $0 $1,670,502,334

47 40 2051 9.0 0.3 $22,122,377 $1,017,629,345 0 0 $0 $1,670,502,334

48 41 2052 8.7 0.3 $22,122,377 $1,039,751,722 0 0 $0 $1,670,502,334

49 42 2053 8.4 0.3 $22,122,377 $1,061,874,100 0 0 $0 $1,670,502,334

50 43 2054 8.1 0.3 $22,122,377 $1,083,996,477 0 0 $0 $1,670,502,334

51 44 2055 7.8 0.3 $22,122,377 $1,106,118,854 0 0 $0 $1,670,502,334

52 45 2056 7.5 0.3 $22,122,377 $1,128,241,231 0 0 $0 $1,670,502,334

53 46 2057 7.2 0.3 $22,122,377 $1,150,363,608 0 0 $0 $1,670,502,334

54 47 2058 6.9 0.3 $22,122,377 $1,172,485,985 0 0 $0 $1,670,502,334

55 48 2059 6.6 0.3 $22,122,377 $1,194,608,362 0 0 $0 $1,670,502,334

56 49 2060 6.3 0.3 $22,122,377 $1,216,730,739 0 0 $0 $1,670,502,334

57 50 2061 6.0 0.3 $22,122,377 $1,238,853,116 0 0 $0 $1,670,502,334

Summary Relative to 2005 Column total = 16.5 $1,238,853,116 $35,307,313,810 22.2 $1,670,502,334 $77,993,470,971

(56 years after base year) Average annual = $630,487,747 $1,392,740,553

Present value (PV) = $4,321,186,852 $12,375,281,254

Annualized PV value = $309,483,860 $886,318,954

Summary Relative to 2010 Column total = 15.3 $1,150,363,608 $35,086,090,039 21.1 $1,582,012,826 $77,772,247,201

(52 years after update) Average annual = $674,732,501 $1,495,620,138

Present value (PV) = $5,426,935,463 $15,984,210,270

Annualized PV value = $391,493,777 $1,153,085,179

Summary Relative to 2012 Column total = 14.7 $1,106,118,854 $34,842,743,891 20.5 $1,537,768,072 $77,528,901,053

(50 years same as RIA) Average annual = $696,854,878 $1,550,578,021

Present value (PV) = $5,962,000,000 $18,049,000,000

Annualized PV value = $432,005,623 $1,307,827,824

Discount rate = 7% Added Cost for Conversion to Dry Disposal Under the CCR Proposed Rule Compared to Conversion Trend Without Rule:

Present value (PV) = $12,087,000,000

Annualized PV value = $875,822,201

Percent reduction compared to October 2009 draft RIA dry conversion cost estimate:

October 2009 draft RIA cost estimate = $23,200,000,000

Reduction in cost estimate compared to RIA = -48%
99 

As summarized below in comparison to the initial cost estimate, the updated conversion cost is the difference in the step-1 cost to the electric 

utility industry for continuation of the phase-out trend without the CCR rule, compared to the step-2 cost for mandatory phase-out with the rule. 

Dry conversion cost: Initial cost estimate Updated cost estimate

Average annualized cost $1.676 billion/year $0.876 billion/year (48% reduction) 

Present value (PV) cost $23.2 billion PV $12.1 billion PV (48% reduction) 

The updated cost is also presented below after integrating the updated dry conversion cost back into the overall cost of the CCR proposed rule 

which contains two other cost categories as estimated for the Subtitle C option (i.e., $491 million/year for engineering control costs + $107 

million/year for ancillary regulatory costs). 

Rule total cost: (i.e., updated dry conversion cost + engineering control cost + ancillary cost) 

 Initial cost estimate Updated estimate

Average annualized cost $2.27 billion/year $1.47 billion/year (35% reduction) 

Present value (PV) cost $31.4 billion PV $20.3 billion PV (35% reduction) 

As shown above, the composite effect of the two cost update factors is they reduce the initial dry conversion cost estimate by 48%, and reduce 

by 35% the overall compliance cost estimate (i.e., dry conversion cost plus engineering control costs plus ancillary costs). 

o Factors Which May Accelerate the CCR Impoundment Phase-Out Trend 

For the reasons described above, it is clear that there is a significant past and continuing trend toward CCR impoundment phase-out at electric 

utility plants, regardless of the CCR rule, and that this trend will continue. Described below, EPA has identified seven factors which 

corroborate continuation of this impoundment phase-out trend, some of which have been quantified in the cost adjustment: 

1. Industry conversions to dry CCR disposal: This factor corroborates the phase-out trend applied in the cost update. As discussed 

above, there is a documented over two-decade long trend 1996 to 2019 away from wet CCR disposal in the electric utility industry. 

This trend consists of two parts: (a) the 1996-2005 historical data period, plus (b) the more recent (2009) announcements of actual 

conversions which occurred between 2005 and 2009, and planned conversions to occur within the next 10 years (i.e., by 2019). 

According to one company (United Conveyor Corporation) who has been supplying dry disposal equipment and conversion services to

the electric utility industry, the main historical drivers for this voluntary shift have been (1) generating dry fly ash as a saleable coproduct to other industries for beneficial uses, and (2) decreasing the volume of fly ash going to impoundments to provide greater 

capacity for bottom ash. Since then, concern over possible future environmental release liabilities associated with CCR impoundments, 

and pressure from individual state governments, has led electric utility companies to consider dry conversion. TVA is the most

prominent example of this trend which publicly announced100 in 2009 it plans to convert its wet fly ash and wet bottom ash systems to 

 

100 TVA_s 20 August 2009 news release is at http://www.tva.gov/news/releases/julsep09/ccprp_other.htm 
100 

dry disposal within the next eight to 10 years (i.e. by 2019). Conversions of this sort are a current trend, and they will definitely 

continue, even in the absence of the CCR proposed rule. As summarized in Exhibit 4H above (columns A to D), EPA identified 18 

such plants constituting 17% of the industry-wide wet CCR disposal tonnage as of 2005. It is inappropriate to attribute the wet disposal 

phase-out cost of the CCR proposed rule to plants independently moving to dry CCR disposal. At this point, EPA expects that most 

plants will choose to move to dry disposal given the additional factors presented below. 

2. Plants switching to other fuels: EPA assumes this factor is reflected in the phase-out trend applied to the cost update. Some coalfired electricity plants have since 2005 switched, or are planning to switch, some or all of their coal-fired boilers at certain plants, from 

coal to other fuels (e.g. natural gas) for reasons unrelated to the CCR proposed rule. In such cases, the cost of closure of their CCR 

disposal impoundments should not be attributed to the cost of the proposed rule. This factor decreases the estimated cost of the rule, 

and particularly EPA_s estimated future cost of phasing-out wet disposal attributable to the proposed rule. For example, based on 

EPA_s recent internet search, as also displayed in Exhibit 4H above (columns E to H), EPA identified 8 coal-fired electric utility plants 

using impoundments (as of 2005) representing 3% of wet CCR disposal by the 158 plants, which have or plan to switch fuels at one or 

more of their coal-fired electricity generation boilers within one or more plants, or to close one or more of their coal-fired boilers or 

entire coal-fired plants. 

3. Lifespan expiration of existing CCR impoundments: This factor suggests a faster future phase-out trend than applied in the cost 

update, but is not applied in the cost update. Another factor which corroborates the future continuation of the electric utility industry_s 

voluntary phase-out of CCR impoundments, is the fact that existing (i.e., active, operational) CCR impoundments have distinct 

operational lifespans. When an impoundment reaches its end-of-lifespan, the electric utility plant must in that future year either add 

new impoundment capacity by installing another impoundment, or convert to dry disposal by installing a landfill (or providing their 

annual CCR for beneficial uses). For purpose of estimating the gengineering costh component (in Chapter 4 of this RIA), EPA 

assigned impoundment lifespan start years (i.e., year in which impoundment construction was completed and began receiving CCR),

and future expected impoundment operational lifespan closure years, to each of the 158 coal-fired plants with operational CCR 

impoundments (as of 2005) identified in this RIA. For the most part, the impoundment start years were based on actual industryreported data from the references cited in this RIA. However, expected closure years were provided by industry for 78 of the 158 

plants; thus, EPA assigned expected closure years to the remainder 80 plants assuming a 40-year lifespan. Exhibit 4J below presents a 

summary of the expected future closure years in relation to the remaining lifespan years and associated impoundment tonnages which 

are expected to reach end of operational lifespan in absence of the CCR rule. This summary indicates that all existing CCR 

impoundments could be expected to reach end-of-lifespan by year 2051, and that 20% of impoundments will have reached end-oflifespan by year 2018. According to the cost update assumptions discussed in the 2nd update steps of prior section above, year 2018 

represents the 5th year of the CCR final rule_s assumed 5-year phase-out period spanning 2014 to 2018, which also assumes the CCR 

final rule is promulgated by EPA at the start of 2012 and that state governments will adopt the rule 2-years later by the end of 2013. 

This lifespan expiration trend corroborates the assumed continuation of the phase-out trend depicted in Exhibit 4I (column A1) which 

indicates that 17% of CCR impoundment tonnage may be expected to have phased-out by year 2018 (i.e., 18.7 million tons remaining 

by 2018 compared to 22.5 million tons in the analysis base year 2005) in absence of the CCR rule. In fact, given that end-of-lifespan 

provides companies with a low-cost opportunity to convert to dry disposal, the higher 20% end-of-lifespan percentage compared to the 
101 

17% phase-out trend suggest the future phase-out trend may be accelerated compared to the 1.1% annual phase-out assumed based on 

the 1996-2005 trend. For example, this result suggests that by 2018 the annual phase-out rate in that year could be 1.3% (i.e., 

(20%/17%) x 1.1%)). 

4. EPA’s Clean Air Act emissions standards: This factor is not quantified in the cost update. Where existing coal-fired electric 

utility plants put in new air emission scrubbing systems, EPA believes they will overwhelmingly rely on CCR management systems that 

do not require wet disposal impoundments. Two of EPA_s upcoming Clean Air Act (CAA) air pollution regulations may lead some coal 

plants to begin using large amounts of reagent to capture SO2 from boiler flue gas: 

x EPA_s Clean Air Mercury Rule (CAMR) which was vacated by the DC Circuit Court in 2007 compels EPA under the CAA Section 

112 to issue maximum achievable control technology (MACT) regulations for coal- and oil-fired electric utility units: 

http://www.epa.gov/ttn/atw/utility/utilitypg.html

x EPA_s remanded Clean Air Interstate Rule (CAIR) was also vacated by the DC Circuit Court in 2007 but was later reinstated and 

remanded back to the Agency for further review/clarification: http://www.epa.gov/cair 

Such plants would likely experience a significant increase in the amount of fly ash or wet FGD waste tonnage to be disposed, because 

the reactants are either captured with the fly ash or with the wet FGD waste. If these plants currently dispose of bottom ash, fly ash, or 

wet FGD waste in wet impoundments, the likelihood of significantly increased future disposal tonnages may prompt them to consider a 

switch to dry disposal. Therefore, new CCR generated as a result of new Clean Air Act emissions requirements are very likely to cause 

plants to switch away from wet disposal independent from the CCR proposed rule. EPA has not quantified this factor for purpose of 

updating the 2009 RIA regulatory cost estimate in this RIA. 

5. EPA’s Clean Water Act effluent standards: This factor is not quantified in the cost update. EPA is currently developing new 

industrial wastewater effluent regulations for coal-fired electricity plants. These new regulations are likely to tighten significantly 

existing effluent limits. These new regulations will be one more factor likely to influence plants to switch to dry disposal systems. 

6. State government implementation of rule: This factor is quantified in the cost update. It recognizes that states require two years 

for their state legislatures or environmental regulatory programs to adopt new RCRA regulations such as the CCR final rule, which is 

necessary for the rule to become federally enforceable. In the initial cost estimate, EPA assumed that the CCR final rule would become 

effective (i.e., adopted by states) in year 2012 and that dry conversion capital costs would all be incurred in that single year. In contrast 

to that simple cost estimation framework, this cost update factor pushes the dry conversion cost 2-years out into the future beginning in 

2014. The 5-year allowed dry conversion (i.e., impoundment phase-out) period is thus 2014 to 2018. In reality, there is a further 

distinction to be made. For states which operate EPA-authorized RCRA regulatory programs (as of 2005, EPA-authorized states 

comprise 97% of the 22.4 million tons annual CCR impoundment disposal tonnage), they could have 2-years adoption period. However, 

in non-authorized states (i.e., AK, IA), territories, and Indian country, the CCR rule becomes effective in 2012 by fact that EPA will 

implement it directly. According to the 2005 EIA data, in this 2nd group there are four plants with impoundments in IA plus one plant 
102 

with impoundment(s) on tribal land totaling 3% of the 22.4 million tons impoundment disposal in 2005.101 Because this 2nd group only 

comprises a very small 3% fraction of the annual CCR impoundment disposal tonnage, and to avoid adding another layer of complexity 

to the cost update which would only result in a very small (i.e., <5%) difference in updated estimate, the cost update does not separately 

calculate costs for both groups addressing under this factor, but applies implementation year to the entire 22.4 million tonnage. This 2-

year final rule adoption cost-timing adjustment factor is highlighted in Exhibit 4I above. 

7. 5-year impoundment phase-out period: This factor is quantified in the cost update. It recognizes that electric utility plants are 

likely to incur dry conversion capital costs spread across each of the years in the CCR rule_s 5-year mandated phase-out period, rather 

than incurring all dry conversion capital cost in one year as was simply assumed in the initial cost estimate. This cost-timing adjustment 

factor is highlighted in Exhibit 4I above. 

 

101 As of 2005, the four IA plants are the George Neal North plant (50,200 tons/year CCR impoundment disposal), the Lansing plant (24,000 tons/year), the Louisa plant 

(23,000 tons/year), and the Walter Scott Jr Energy Center plant (104,000 tons/year). The one plant located on tribal land is the Four Corners plant in NM (501,400 

tons/year). 
103 

Exhibit 4J 

RIA 50-

year 

period

Actual company 

planned or EPA 

estimated pond 

closure year

CCR pond end 

of lifespan 

(tons/year)

Cumulative pond 

lifespan end 

(tons/year)

% pond 

tonnage 

phaseout

2009 Total 0 0 0%

2010 Total 0 0 0%

2011 Total 0 0 0%

1 2012 Total 481,300 481,300 2.1%

2 2013 Total 40,400 521,700 2.3%

3 2014 Total 634,700 1,156,400 5.2%

4 2015 Total 599,450 1,755,850 7.8%

5 2016 Total 2,021,700 3,777,550 16.9%

6 2017 Total 189,300 3,966,850 17.7%

7 2018 Total 4,480,250 513,400 20%

8 2019 Total 838,400 5,318,650 23.7%

9 2020 Total 1,969,160 7,287,810 32.5%

10 2021 Total 183,100 7,470,910 33.4%

11 2022 Total 661,700 8,132,610 36.3%

12 2023 Total 410,800 8,543,410 38.1%

13 2024 Total 39,000 8,582,410 38.3%

14 2025 Total 477,700 9,060,110 40.4%

15 2026 Total 280,900 9,341,010 41.7%

16 2027 Total 27,600 9,368,610 41.8%

17 2028 Total 134,000 9,502,610 42.4%

18 2029 Total 36,200 9,538,810 42.6%

19 2030 Total 527,100 10,065,910 44.9%

20 2031 Total 170,350 10,236,260 45.7%

21 2032 Total 327,400 10,563,660 47.2%

22 2033 Total 746,500 11,310,160 50.5%

23 2034 Total 594,100 11,904,260 53.1%

24 2035 Total 473,000 12,377,260 55.3%

25 2036 Total 322,000 12,699,260 56.7%

26 2037 Total 742,800 13,442,060 60.0%

27 2038 Total 476,100 13,918,160 62.1%

28 2039 Total 825,900 14,744,060 65.8%

29 2040 Total 642,050 15,386,110 68.7%

30 2041 Total 1,009,100 16,395,210 73.2%

31 2042 Total 141,600 16,536,810 73.8%

32 2043 Total 992,010 17,528,820 78.3%

33 2044 Total 505,700 18,034,520 80.5%

34 2045 Total 104,400 18,138,920 81.0%

35 2046 Total 338,000 18,476,920 82.5%

36 2047 Total 326,800 18,803,720 83.9%

37 2048 Total 575,800 19,379,520 86.5%

38 2049 Total 788,300 20,167,820 90.0%

39 2050 Total 2,075,700 22,243,520 99.3%

40 2051 Total 121,900 22,400,000 100.0%

Column total (2005 base) = 22,400,000

Projection of Future CCR Pond Lifespan Closure Tonnage

-

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

2012 Total

2014 Total

2016 Total2018 Total2020 Total

2022 Total

2024 Total

2026 Total

2028 Total2030 Total

2032 Total2034 Total2036 Total2038 Total2040 Total

2042 Total

2044 Total2046 Total2048 Total2050 Total

Projection of Future Percentage of 2005 CCR Pond Disposal Lifespan 

Closure

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2012 Total

2014 Total

2016 Total

2018 Total2020 Total2022 Total

2024 Total

2026 Total2028 Total2030 Total

2032 Total2034 Total2036 Total2038 Total2040 Total2042 Total2044 Total2046 Total

2048 Total2050 Total
104 

Exhibit 4K below summarizes the above regulatory cost estimates on an incremental basis (i.e., without including the gBaseline Costsh 

estimated in Chapter 3 of this RIA). Appendix J presents regulatory costs estimates for each of the 495 electric utility plants. 

Exhibit 4K 

Summary of Cost Estimates for the October 2009 Draft RIA Regulatory Options 

($millions in 2009 price level; average annual amortized @7% discount rate over 50-year period 2012 to 2061) 

RCRA Regulatory Cost Element 

Subtitle C 

Hazardous waste 

Subtitle D 

(version 1) 

Hybrid C&D 

A. Engineering Controls (onsite): $491 $491 $491 

1. Groundwater monitoring $13 $13 $13 

2. Bottom liners $95 $95 $95 

3. Leachate collection $8 $8 $8 

4. Fugitive dust controls $5 $5 $5 

5. Water runon/runoff controls $2 $2 $2 

6. Financial assurance $30 $30 $30 

7. Disposal unit location restrictions $76 $76 $76 

8. Closure capping to cover unit $255 $255 $255 

9. Post-closure groundwater monitoring $2 $2 $2 

10. Storage design & operating standards Not estimated in this RIA Not estimated in this RIA Not estimated in this RIA 

B. Other Ancillary Costs: $107 $1 $9 

11. For offsite disposal (11a+11b+11c) = 

 11a. RCRA manifest cost 

 11b. Added operation for hazmat truck 

 11c. Offsite LF RCRA Subtitle C permit 

$77 

$66 

$8 

$3 

$0 

Not relevant 

Not relevant 

Not relevant 

$0 

(offsite applies only to LFs 

so no incremental cost over 

baseline) 

12. Structural integrity inspections $1 $1 $1 

13. RCRA facility-wide investigation $7.6 Not relevant $2.4 

14. RCRA facility-wide corrective action Not estimated in this RIA; 

historical average = 

$5.4 million per case 

Not relevant Not estimated in this RIA; 

historical average = 

$5.4 million per case 

15. RCRA TSDF haz waste disposal permit $7 Not relevant $2 

16. RCRA enforcement inspection $0.06 $0 $0.02 

17. Future added cleanup cost as ghazardous wasteh Not estimated in this RIA: 

case studies indicate possible 

$18 to $376 million per case 

Not relevant Not estimated in this RIA; 

case studies indicate possible 

$18 to $376 million per case 

18. EPA paperwork reporting/recordkeeping $13 Not relevant $4 

C. Land Disposal Restriction Dewatering Treatment $876 (updated) $876 (updated) $876 (updated) 

TOTAL ANNUALIZED COSTS (A+B+C) =

Average cost per-ton (94.2 million tons disposed) = 

Average cost per-plant (467 disposing plants) =

$1,474 per year (updated) 

($15.65 per ton) 

($3.16 million per plant)

$1,368 per year (updated) 

($14.52 per ton) 

($2.93 million per plant)

$1,376 per year (updated) 

($14.61 per ton) 

($2.95 million per plant)

Note: Chapter 6 of this RIA scales these cost estimates based on the October 2009 draft RIA options, to the 2010 regulatory options.
105 

4C. State-by-State Distribution of Incremental CCR Regulatory Costs 

Exhibit 4L below summarizes the distribution of estimated regulatory costs on a state-by-state basis and by option. This state-by-state 

summary is based on apportionment of nationwide average annualized cost estimated for each regulatory option, according to state-by-state 

annual CCR tonnage generated by the 495 coal-fired electric utility plants. 

Exhibit 4L 

State-by-State Distribution of Estimated Incremental Costs for the October 2009 Draft RIA Regulatory Options 

($million average annualized cost in 2009$ over 50-year period of analysis 2012 to 2061) 

A B C D E F G H 

Item State 

# of coalfired 

electricity 

plants 

2005 CCR 

generation by 

coal-fired electric 

utility plants 

(tons/year) 

State % of 

nationwide CCR 

generation 

(based on 

Column D) 

Subtitle C 

Hazardous waste 

Subtitle D 

(version 1) 

Hybrid C&D: 

Subtitle C impoundments 

Subtitle D landfills 

1 AK 2 46,179 0.03% $0.4 $0.4 $0.4 

2 AL 16 3,210,337 2.27% $33.5 $31.1 $31.2 

3 AR 4 744,267 0.53% $7.8 $7.3 $7.3 

4 AZ 8 3,334,030 2.36% $34.8 $32.3 $32.5 

5 CA 6 159,927 0.11% $1.6 $1.5 $1.5 

6 CO 12 1,704,433 1.21% $17.8 $16.6 $16.6 

7 CT 0 172,280 0.12% $1.8 $1.6 $1.7 

8 DC 0 0 0.00% $0.0 $0.0 $0.0 

9 DE 2 251,205 0.18% $2.7 $2.5 $2.5 

10 FL 15 6,132,345 4.34% $64.0 $59.4 $59.7 

11 GA 13 6,077,700 4.30% $63.4 $58.9 $59.2 

12 HI 1 58,968 0.04% $0.6 $0.5 $0.6 

13 IA 15 1,136,289 0.80% $11.8 $11.0 $11.0 

14 ID 0 0 0.00% $0.0 $0.0 $0.0 

15 IL 17 3,856,748 2.73% $40.2 $37.4 $37.6 

16 IN 33 8,798,845 6.23% $91.8 $85.3 $85.7 

17 KS 8 1,495,099 1.06% $15.6 $14.5 $14.6 

18 KY 31 9,197,567 6.51% $96.0 $89.1 $89.6 

19 LA 3 1,614,800 1.14% $16.8 $15.6 $15.7 

20 MA 0 363,150 0.26% $3.8 $3.6 $3.6 

21 MD 4 1,932,740 1.37% $20.2 $18.8 $18.9 

22 ME 1 48,000 0.03% $0.4 $0.4 $0.4 

23 MI 24 2,369,673 1.68% $24.8 $23.0 $23.1 

24 MN 20 1,525,979 1.08% $15.9 $14.8 $14.9 

25 MO 20 2,679,742 1.90% $28.0 $26.0 $26.1 

26 MS 6 1,229,400 0.87% $12.8 $11.9 $12.0 
106 

Exhibit 4L 

State-by-State Distribution of Estimated Incremental Costs for the October 2009 Draft RIA Regulatory Options 

($million average annualized cost in 2009$ over 50-year period of analysis 2012 to 2061) 

A B C D E F G H 

Item State 

# of coalfired 

electricity 

plants 

2005 CCR 

generation by 

coal-fired electric 

utility plants 

(tons/year) 

State % of 

nationwide CCR 

generation 

(based on 

Column D) 

Subtitle C 

Hazardous waste 

Subtitle D 

(version 1) 

Hybrid C&D: 

Subtitle C impoundments 

Subtitle D landfills 

27 MT 5 1,830,624 1.30% $19.2 $17.8 $17.9 

28 NC 27 5,504,531 3.90% $57.5 $53.4 $53.7 

29 ND 9 3,038,100 2.15% $31.7 $29.4 $29.6 

30 NE 6 614,473 0.44% $6.5 $6.0 $6.1 

31 NH 1 176,900 0.13% $1.9 $1.8 $1.8 

32 NJ 2 735,214 0.52% $7.7 $7.1 $7.2 

33 NM 4 3,983,300 2.82% $41.6 $38.6 $38.8 

34 NV 2 391,500 0.28% $4.1 $3.8 $3.9 

35 NY 11 1,479,792 1.05% $15.5 $14.4 $14.4 

36 OH 24 10,429,446 7.39% $108.9 $101.2 $101.7 

37 OK 3 1,490,800 1.06% $15.6 $14.5 $14.6 

38 OR 1 99,900 0.07% $1.0 $1.0 $1.0 

39 PA 28 15,359,680 10.88% $160.4 $148.9 $149.7 

40 RI 0 0 0.00% $0.0 $0.0 $0.0 

41 SC 14 2,178,360 1.54% $22.7 $21.1 $21.2 

42 SD 2 103,753 0.07% $1.0 $1.0 $1.0 

43 TN 12 3,240,120 2.29% $33.8 $31.4 $31.5 

44 TX 18 13,165,728 9.32% $137.4 $127.6 $128.2 

45 UT 7 2,582,144 1.83% $27.0 $25.1 $25.2 

46 VA 13 2,388,526 1.69% $24.9 $23.1 $23.3 

47 VT 0 0 0.00% $0.0 $0.0 $0.0 

48 WA 1 1,405,220 1.00% $14.7 $13.7 $13.8 

49 WI 12 1,412,534 1.00% $14.7 $13.7 $13.8 

50 WV 20 9,231,718 6.54% $96.4 $89.5 $90.0 

51 WY 12 2,224,848 1.58% $23.3 $21.6 $21.7 

Totals = 495 141.2 million 100% $1,474/year $1,368/year $1,376/year 
107 

4D. Cost Estimation Uncertainty 

This section addresses OMB_s 2003 Circular A-4 gRegulatory Analysish guidance (page 40) requirement for RIAs involving rules with 

expected annual economic effects of $1 billion or more, to present a formal quantitative analysis of the uncertainties about benefit and cost 

estimates. This section only addresses uncertainties with respect to cost estimates for both baseline cost and incremental costs for the 

regulatory options. This section first presents three specific examples of data quality uncertainty factors in this RIA, followed by an overall 

uncertainty factor to represent all such specific data quality uncertainty factors combined (the three factors below are not additive across their 

low- and high-end percentage range endpoints because such simple addition would represent unlikely compounding of these factors): 

x Specific Examples of Data Quality Uncertainty Factors in This RIA 

1. CCR tonnage data:The baseline and regulatory cost estimates in this RIA are based on the annual CCR disposal and beneficial use

tonnages reported by electric utility plants to the 2005 DOE-EIA Form 767 database. However, the DOE-EIA 767 

data reporting form102 does not provide respondents with a definition for the gtonsh collected in Schedule 3 of the 

data reporting form. Because there are three numerical definitions of gtonh commonly used in the US (i.e., short-ton 

= 2,000 pounds, long-ton = 2,200 pounds; and metric ton = 2,205 pounds), this factor potentially introduces -20% to 

+20% uncertainty range. For purpose of consistency with the use of short-tons in most EPA RCRA program 

reports,103 this RIA interprets CCR gtonsh as short-tons. 

2. Data sources: Also with respect to CCR tonnage data, this RIA cites multiple possible sources of data based on different published 

sources. For example, as displayed in Exhibit 4D of this RIA, one source (American Coal Ash Association) 

provides an industry survey-based estimate of CCR generation by electric utility plants in 2005 of 123.1 million tons. 

Whereas this RIA estimates 141.2 million tons CCR generation in 2005 based on data from the 2005 DOE-EIA Form 

767 database for plants >100 MW in size and based on supplemental estimates made in this RIA for <100 MW size 

plants. This data source inconsistency factor represents -13% to +15% uncertainty range. 

3. Data years: Information and data used to evaluate and estimate the cost of baseline CCR disposal practices are from various 

published sources dated 1995, 1996, and 2006. Furthermore, unit costs for CCR disposal unit engineering controls 

applied in this RIA are from different published data years such as 2000, 2004, and 2007. This RIA updated 

historical data to 2009 price levels using various indexes, some of which were specific to a particular type of unit 

cost, and other indexes were general (e.g., GDP Price Deflator). The uncertainty in accuracy of unit costs introduced 

by use of historical data is not quantified. 

x Overall Data Quality Uncertainty Range 

 

102 Instructions to the 2005 DOE-EIA Form 767 data reporting questionnaire (24 pages) are available at 

http://www.eia.doe.gov/cneaf/electricity/forms/eia767/eia767instr.pdf

A copy of the 2005 DOE-EIA 767 data reporting questionnaire (16 pages) is available at http://www.eia.doe.gov/cneaf/electricity/forms/eia767/eia767.pdf 103 One example of the standardized use of gshort-tonsh in EPA RCRA program reports is the RCRA Biennial Hazardous Waste Reports which are archived at 

http://www.epa.gov/waste/inforesources/data/biennialreport/index.htm 
108 

The method applied to characterize the overall level of quantitative uncertainty in the cost estimates of this RIA, is based on the 02 February 

2005 gRecommended Practice No. 18R-97: Cost Estimate Classification System as Applied in Engineering, Procurement, and Construction for 

the Process Industriesh104. This method is specifically applicable to cost estimates developed for mechanical and chemical process equipment 

used for engineering, procurement and construction across a wide variety of industries including the electric utility industry sector (i.e., NAICS 

code 22). As summarized in Exhibit 4M below, this cost estimate classification system involves five estimation categories (i.e., Class 1, Class 

2, Class 3, Class 4, Class 5) reflecting different relative (a) levels of cost definition, (b) purposes and uses of cost estimates, (c) cost estimation 

methodologies, (d) expected accuracy ranges, and (e) degrees of cost estimate preparation effort. 

Exhibit 4M 

Summary of Cost Estimation Classification System for Characterizing Data Quality Uncertainty in this RIA 

Estimate 

Category 

Level of Detail 

(Quantity of Input Information & Data) 

Level of Effort 

(Time Required to Complete the Cost Estimate) 

Expected Accuracy 

Range 

Class 5 Very limited information (e.g., little more than proposed project 

type, location, and capacity). 

Very limited amount of time and with little effort, sometimes 

requiring less than one hour FTE to prepare the cost estimate. -50% to +100% 

Class 4 

1% to 5% complete, limited information (e.g., preliminary 

engineered process and equipment lists) for purpose of alternatives 

analysis, screening analysis, or demonstration of economic 

feasibility. 

Sometimes requiring up to two months FTE for preparing the 

cost estimate. -30% to +50% 

Data quality uncertainty range applied in this RIA (i.e., between Class 3 and Class 4) = -25% to +40% 

Class 3 

10% to 40% complete, semi-detailed information (e.g., process 

flow diagrams, equipment diagrams, layout drawings, engineered 

process and equipment lists). 

May require up to nine months FTE to prepare the cost 

estimate. -20% to +30% 

Class 2 30% to 70% complete, detailed information May require up to 1.5 years FTE to prepare the cost estimate. -15% to +20% 

Class 1 50% to 100% complete and full project definition (e.g., virtually all 

engineering and design documentation/plans) 

May require up to or over three years FTE to prepare the cost 

estimate. -10% to +15% 

Because the bulk of the data collection and analysis presented in this RIA was executed in a relatively short time (i.e., five months) using semidetailed information for baseline CCR disposal conditions, disposal unit costs, and engineering control and ancillary costs for the regulatory 

options, the level of numerical uncertainty for the baseline cost and incremental costs for each of the regulatory options estimated in this RIA 

may be classified between a Class 3 and Class 4 type of estimate (i.e., -25% to +40%), as displayed below in Exhibit 4N. These uncertainty 

ranges represent a probability distribution about the cost estimates, and may be interpreted as the expected values (i.e., best estimates) and lowend and high-end ranges about each cost estimate. Such quantitative indicators of uncertainty are identified in OMB_s Circular A-4 (pages 40, 

41) as acceptable for characterizing probability distributions for cost estimates involving major rules with possible annual economic effects of 

$1 billion or more for one or more regulatory options. 

 

104 Recommended Practice No. 18R-97 (10 pages) published by the Association for the Advancement of Cost Engineering at: http://www.aacei.org/technical/rps/18r-97.pdf 
109 

Exhibit 4N 

Cost Estimation Uncertainty with Overall Data Quality Uncertainty Factor Applied to the October 2009 Draft RIA Options 

($millions in 2009$) 

Cost Estimate Uncertainty Indicator 

Subtitle C 

Hazardous waste

Subtitle D 

(version 1)

Hybrid C&D: 

Subtitle C for impoundments

Subtitle D for landfills 

Best estimate (w/updated LDR cost): $1,474/year (updated) 

$20,343 PV 

$1,368/year (updated) 

$18,880 PV 

$1,376/year (updated) 

$18,990 PV 

-25% uncertainty low-end $1,106/year 

$15,264 PV 

$1,026/year 

$14,160 PV 

$1,032/year 

$14,243 PV 

+40% uncertainty high-end $2,064/year 

$28,485 PV 

$1,915/year 

$26,429 PV 

$1,926/year 

$26,581 PV 

Note: 

PV = present value of average annualized cost over 50-years @7% discount rate, calculated by multiplying the average annualized cost by the 

present value factor = 13.801. 

Note: Chapter 6 of this RIA scales these estimated costs based on the October 2009 draft RIA, to the 2010 regulatory options.
110 

Chapter 5 

Potential Benefits of RCRA Regulation of CCR Disposal in the Electric Utility Industry 

Exhibit 5A below displays social benefits associated with EPA_s RCRA regulatory program, a few or many of which may be associated with 

any particular RCRA regulation. To a lesser or greater degree, a range of these benefit elements may be associated with future benefits from 

RCRA regulation of CCR disposal, according to the unique physical and environmental attributes at any particular CCR disposal site. 

Exhibit 5A 

Human Health, Environmental, & Economic Benefits of the EPA RCRA Regulatory Program* 

Benefit Category (n = 6) Benefit Sub-Element Examples (n = 36) 

1. Human Health Protection 

Benefits 

1A. Mortality Reduction-Examples 

1) Reduced risk of cancer fatality 

2) Reduced risk of acute fatality 

1B. Morbidity reduction-Examples 

1) Reduced risk of cancer 

2) Reduced risk of morbidity (e.g., asthma, nausea) 

2A. Market Ecological Values: 

1) Commercial fisheries 

2) Market recreational benefits (e.g., involving fees) 

3) Food 

4) Fuel 

5) Fiber 

6) Timber 

7) Fur/leather 

2. Ecological Protection Benefits 

2B. Non-Market Ecological Values & Amenities (examples): 

1) Non-market recreational benefits (e.g., w/out fees) 

2) Non-use values: existence, bequest, and quasi-option 

values 

3. Indirect Ecosystem & 

Resource Conservation Benefits 

1) Climate moderation 

2) Flood moderation 

3) Groundwater recharge 

4) Sediment trapping 

5) Soil retention 

6) Nutrient cycling 

7) Pollination by wild species 

8) Biodiversity 

9) Water filtration 

10) Soil fertilization 

11) Pest control 

12) Reduced pressure on endangered species 

13) Avoided habitat destruction 

4. Avoided Economic Costs 1) Avoided costs of providing government mandated 

alternate drinking water supplies 

2) Avoided costs associated with government mandated 

cleanups of industrial waste accidents or spills 

5. Avoided Materials Damages, 

Improved Aesthetics, & 

Historical Preservation 

1) Aesthetic pleasure 

2) Improved taste, order, visibility 

3) Protection of resources with cultural and historic value 

4) Protection of constructed resources (e.g., buildings, 

infrastructure) 

6. Potential Long-Term Benefits 

(Sustainability) 

1) Avoided increases in damages related to changes in 

affected populations 

2) Benefits associated with resource conservation 

3) Benefits associated with the precautionary principle, 

protection from unforeseen issues 

4) Benefits from long-term increases in the value of 

environmental quality 

* Source: Exhibit 1-1 of EPA Office of Solid Waste, gApproaches to Assessing the Benefits, Costs, and Impacts of the RCRA Subtitle C Program,h prepared by 

Industrial Economics Inc., October 2000, 
111 

In contrast to the Exhibit 5A list of RCRA regulatory program benefits, because of time, data, and methodological limitations, the regulatory 

benefits estimated in this RIA do not represent a complete list of expected benefits of the CCR proposed rule. For example, the benefits 

analysis in this Chapter of the RIA does not estimate benefits of (a) reducing cancer risks associated with preventing direct effluent discharges 

of CCR to surface waters, (b) ecological and ecosystem benefits, (c) off-site CCR disposal regulatory benefits, or (d) non-cancer human health 

protection benefits. In contrast to this large number of possible benefit elements, this RIA monetizes only three benefit categories consisting of 

five sub-elements. 

1. Groundwater Protection Benefits at CCR Disposal Sites 

a. Human health protection benefits (i.e., benefit of preventing cancer from arsenic exposure) 

b. Groundwater remediation costs avoided 

2. CCR Impoundment Catastrophic Failure Benefits 

a. Future cleanup costs avoided 

3. Benefits from Increase in Future CCR Beneficial Uses 

a. Direct market benefits (economic benefits) 

b. Lifecycle social benefits (economic + environmental benefits) 

These monetized benefits are based on EPA_s initial analysis using existing information and analytical techniques. EPA requests public 

comment on all data sources and analytical approaches used in estimating the benefits presented in this Chapter. 

5A. Groundwater Protection Benefits (Avoided Future Cancer Risks & Groundwater Remediation Costs) 

This section estimates the potential future benefits of reduced human cancer risks and avoided groundwater contamination remediation costs 

associated with controlling arsenic from onsite CCR landfills and surface impoundments. The estimates are based on EPA_s risk assessment, 

which predicts leaching behavior using SPLP and TCLP data. Recent research and damage cases indicate that these leaching tests underestimate risks from dry disposal.105 Human cancer risks avoided are based on the individual gexcessh lifetime cancer probabilities estimated 

below. This estimation follows an 8-step method which begins by characterizing the cancer risks and expected number of future cancer risks 

from arsenic releases to groundwater from CCR landfills and surface impoundments in the absence of EPA or state action. It then proceeds to 

monetize these cancers using accepted economic practices. Next, a baseline is established for the operation of state regulatory and remedial 

 

105 Recent EPA research demonstrates that CCR can leach significantly more aggressively under different pH conditions potentially present in disposal units. In a 2009 

EPA study of 34 electric utility plants, CCR from 19 facilities exceeded at least one of the 40 CFR Toxicity Characteristic regulatory values for at least one type of CCR

(e.g., fly ash or FGD residue) at the self-generated pH of the material (source: EPA Office of Research & Development, gCharacterization of Coal Combustion Residues 

from Electric Utilities v Leaching and Characterization Data,h EPA-600/R-09/151. Office of Research and Development, Air Pollution Control Division. Research Triangle 

Park, NC. December 2009). This behavior likely explains the rapid migration of chemical constituents from CCR disposal sites like Chesapeake, VA and Gambrills, MD. 

See also EPA gCharacterization of Mercury-Enriched Coal Combustion Residues from Electric Utilities Using Enhanced Sorbents for Mercury Control,h EPA 600/R06/008. Office of Research and Development. Research Triangle Park, NC. January 2006; and EPA gCharacterization of Coal Combustion Residues from Electric Utilities 

Using Wet Scrubbers for Multi-Pollutant Control,h EPA/600/R-08/077. Office of Research and Development, Air Pollution Control Division. Research Triangle Park, NC. 

July 2008. 
112 

programs. Groundwater remediation costs and cancer costs under the baseline and each regulatory option are then estimated. Finally, the 

aggregate benefits from each regulatory option (incremental to the baseline) are estimated. 

Step 1. Categorize CCR Disposal Units by Type 

This step begins with the baseline data on CCR disposal (i.e., disposal unit liner types, annual CCR disposal tonnages) contained in Appendix 

F of this RIA for the 495 coal-fired electric utility plants. A subtotal 84 of the 495 plants dispose CCR offsite only, and thus, no liner type is 

assigned to these facilities in this benefits analysis.106 Some of the plants have multiple data entries because they were known to have multiple 

CCR disposal units on-site. This estimation step assigned only the riskiest disposal unit type and liner type combinations of those listed for 

each such plant, which resulted in the six combinations displayed below in Exhibit 5A-1.

107 This hierarchy was based on the 90th percentile, 

trivalent arsenic cancer risks in the EPA-ORCR 2009 CCR risk report as follows, with those units posing the greatest risk appearing first. 

Appendix K1 presents further information on CCR disposal unit liner types and associated data. 

These plants were then further divided by the type of waste disposed in the units; CCR only or co-managed wastes. The ratio of facilities that 

only dispose CCR compared to facilities that co-manage CCR with coal refuse is displayed below in Exhibit 5A-1. These ratios allowed EPA 

to model a single number of potential cancer cases as a best estimate. The data used in the 2009 risk assessment108 were from a 1995 EPRI 

survey. Thus, there is some uncertainty regarding the current accuracy of these ratios. To account for this uncertainty, EPA also calculated a 

bounding range of cancers based on the assumption that all facilities would dispose of CCR only, and that all facilities would co-manage CCR 

with coal refuse only. 

Exhibit 5A-1 

Categorization of CCR Disposal Unit Types 

CCR Disposal Unit Type CCR Only Co-managed 

1. Unlined Landfill 66% 34% 

2. Clay-Lined Landfill 74% 26% 

3. Composite-Lined Landfill 53% 47% 

4. Unlined Surface Impoundment 32% 68% 

5. Clay-Lined Surface Impoundment 48% 52% 

6. Composite-Lined Surface Impoundment 71% 29% 

 

106 Note: 83 facilities in Exhibits E2 and E4 of the 2009 risk assessment are not assigned WMUs or liner types, 5 fewer than indicated in this RIA. 107 Multiple CCR disposal units at a single industrial facility will all affect the same surrounding population. To avoid duplication of population risks, the analysis used the 

simplifying assumption that the human health risks will be driven by the riskiest single WMU, when multiple waste management units are present, but populations around 

all WMUs are accounted for in Appendix K2 of this RIA. 108 Source: EPA gHuman and Ecological Risk Assessment of Coal Combustion Wastes,h Office of Resource Conservation and Recovery, December 7, 2009. 
113 

Step 2. Determine Potentially Affected Populations of Groundwater Drinkers 

With information on the universe of facilities, WMUs, and liners nearby groundwater-drinking populations were assigned. To accomplish this, 

EPA first assigned latitude and longitude coordinates to the 495 sites based on its 2007 eGRID database. Only a few sites were not in eGRID, 

and it is assumed that these sites were constructed since the 2007 eGRID data collection. Once latitude and longitude data were assigned, EPA 

used GIS data to ascertain the location of private groundwater wells within a one-mile radius from the latitude and longitude coordinates, and 

then the number of individuals drinking from those wells.109,110 The data divide populations into adults (18 and older) and children, the same 

two populations examined in the 2009 risk assessment. Once these data were attached to specific sites, they were aggregated based on the 

liner/WMU categories above. 

Aggregated data were then scaled to account for the missing population information and population growth. First, the data was scaled up to 

account for the missing population data in the sites not identified in eGRID. There were 5 unlined landfills, 1 clay-lined landfill, and 7 

composite-lined landfills that had onsite disposal but no eGRID data from which to determine the population. All surface impoundments had 

the necessary eGRID data. To account for these individuals, EPA made the assumption that these plants had populations similar to the plants 

EPA had data for, since EPA had no data to suggest otherwise.111 Thus, the population was scaled up by a scaling factor equal to the total 

number of plants divided by the number of plants for which EPA had population data as follows: 

1) Unlined Landfills = 76/71 (~1.07) 

2) Clay-Lined Landfills = 28/27 (~1.04) 

3) Composite-Lined Landfills = 150/143 (~1.05) 

The populations were then scaled up to current population levels based on Census data, resulting in a scaling factor of 1.093. 

Once these preliminary population estimates were produced, it was also necessary to account for the size of the waste management unit. In the 

2009 risk assessment, WMUs were assumed to be square as a requirement of the model. Using the same assumption here, the actual 1-mile 

radius around the square area of a WMU could be estimated by scaling the population density of the original 1-mile radius up to the area 1-mile 

around a square WMU of average size. This led to scaling factors of 1.81 and 2.56 for landfills and surface impoundments, respectively. 

Further discussion of this area-based scaling can be found in Appendix K2. 

In addition to accounting for the increased area in the 1-mile radius, EPA assumed that half of the receptors would be up-gradient and half 

would be down-gradient of the WMU. For the purposes of this assessment, populations were assumed to be equally distributed within the 

 

109 This data was developed through the use of the 2000 census block data in combination with the 1990 census drinking water source data. For a further discussion of 

population development, see Appendix K3 of this RIA. 110 Municipal water systems using groundwater often rely on deeper aquifers, in which case they would be less susceptible to contamination from CCR releases. Therefore, 

these systems were not included in the 2009 Risk Assessment or in this analysis. However, exposure through this pathway is possible, which means that these population 

estimates could underestimate the population that is exposed to these wastes. 

111 EPA does not account for CCR disposed off-site as in the Gambrills MD and Chesapeake VA damage cases. 
114 

square whose center was the facility WMU. This is illustrated in Exhibit 5A-2 below. It was also assumed that only down-gradient 

populations would be affected (red rectangle), and no up-gradient populations would be affected. This was accounted for by dividing the onemile population by two. The issue of surface waterbodies is addressed below. Appendix K3 provides a detailed explanation of the derivation 

of the exposed population by plant. Overall, 715,855 individuals are potentially exposed to CCR. Of this total, 34,533 use private drinking 

water wells. 

W M U

Groundwater Flow Potentially 

Exposed 

Population Unexposed 

Population 

Exhibit 5A-2 

Conceptual Model for Exposed Well-Drinking Population 

1-mile

Surface 

Waterbody 

Contaminant 

Plume 
115 

Step 3. Apply EPA-ORCR 2009 Arsenic Groundwater Risk Results 

This step involved determining the most appropriate individual risk factors for use in estimating arsenic cancer population risk for the estimated 

populations residing near the CCR disposal sites. There are two sources of information on individual risks associated with arsenic exposure: 

IRIS 1998: Based on skin cancer incidence, as data on skin cancer risks were available prior to the availability of quantitative data for 

internal cancers. Skin cancer is a health endpoint associated with lower fatality risk than the internal cancers induced by 

arsenic. The skin cancer based risk assessments no longer represent the current state of the science for health risk 

assessment for arsenic. This RIA presents these estimates below for informational purposes only. This source describes a 

distribution of risks to a hypothetical individual who drinks water from a well located at a randomly selected point one mile 

down-gradient from the waste management unit edge. The probabilistic risk estimates were gsite-basedh (that is, not sitespecific, but based roughly on 181 actual coal-fired power plants that were operating in 1995). EPA has only the gpeakh 

risks (i.e., those corresponding generally to the highest groundwater concentrations that are modeled to occur) available for 

analysis because computer modeling of peak risks contain gigabytes worth of information, and while EPA attempted to 

keep track of risks up to 10,000 years of the computer model run, the data in these large files became corrupted and are now 

unusable. However, below in this RIA EPA does extrapolate population risks in other years. These other years are the 

years between the cessation of operation of the landfill, or the years after the beginning of operation of the surface 

impoundment, leading up to the years in which the gpeakh risks occur at half of the modeled facilities. 

NRC 2001: The latest science on health risks associated with arsenic exposure is from the National Research Council (NRC) report 

gArsenic in Drinking Water: 2001 Updateh112 which reviewed the available toxicological, epidemiological, and risk 

assessment literature on the health effects of inorganic arsenic, building upon the NRC_s prior report, gArsenic in Drinking 

Waterh (1999). The 2001 report, developed by an eminent committee of scientists with expertise in arsenic toxicology and 

risk assessment provides a scientifically sound and transparent assessment of cancer risks from inorganic arsenic. EPA_s 

Science Advisory Board endorses these estimates and the IRIS estimates are currently being updated to reflect this latest 

science. Therefore, while IRIS estimates exist, because the more recent NRC scientific information is available, this RIA 

relies on the NRC information for analysis of the cancer risks associated with CCR. Appendix K4 provides more detailed 

information on how this NRC research was used. 

For the purposes of initially estimating the expected number of cancers (i.e., cancer risks) in Steps 3 and 4, this RIA applied risk results 

obtained with the latest (i.e., 1998) IRIS value. However, in Step 5 below, the 2001 NRC research was used to update these cancer estimates. 

It should be noted that the 1998 IRIS skin cancer value does not examine bladder and lung cancer incidence, and therefore is not a substitute for 

the 2001 NRC cancer risk research in this area. To the extent that the skin cancers estimated by the IRIS value are not accounted for, this RIA 

may underestimate total cancer incidence.

 

112 National Research Council, Arsenic in Drinking Water: 2001 Update, National Academy Press, 2001 at http://www.nap.edu/openbook.php?isbn=0309076293 
116 

This RIA extracted only those results from the EPA 2009 risk assessment to either represent (a) conventional CCR (i.e., fly ash, bottom ash, 

boiler slag, and flue gas desulphurization waste managed in the landfill or impoundment without mixing with other materials), or (b) CCR comanaged with coal refuse.113 Of these results, only those for trivalent arsenic were used.114 For the primary analysis, it was assumed that all 

arsenic was speciated in this manner. As noted in the EPA source data, arsenic III and arsenic V cancer risk results for unlined surface 

impoundments that co-dispose CCR with coal refuse were not statistically different at the 90th percentile, and these risks are likely to drive the 

population risk estimates. A sensitivity analysis was conducted where all arsenic was assumed to be speciated in the arsenic V state. This 

analysis is presented in Appendix K5. Finally, risks for both adult and child receptors were included so that each group would be accurately 

represented. Once all of these data were collected they were sorted by CCR disposal unit and liner type. 

This analysis reflects possible groundwater and surface water interactions that could affect the population risk estimates. In situations in which 

the modeled distance to a surface water body was less than the modeled distance to a drinking water well EPA assumed that the groundwater 

plume is fully intercepted by a surface waterbody.115 To this end, EPA extracted the model inputs for the distance to groundwater wells and the 

distance to surface waterbodies used in the EPA source, randomly selected from input distributions.116 These two were then compared using a 

logical test in Microsoft Excel. This test returned a 0 if the surface waterbody was closer than the drinking water well and 1 if it was not. 

Thus, a 1 was a positive indication that the contaminant plume in that model run reached the groundwater well. 

Finally, EPA extracted the exposure durations used in each model run from the EPA-ORCR 2009 CCR risk report to capture the fraction of the 

individual_s lifetime risk that was experienced in a one-year period. EPA accomplished this by matching the probabilistic exposure duration 

inputs, to their corresponding age category. Then, each probabilistic run was sorted to return the exposure duration of the adult and child age 

category. These Monte Carlo data constituted a weighted approach for estimating individual human cancer risks. Population risk is typically 

calculated by multiplying risk results by the affected population. Since there were thousands of equally valid model iterations, this RIA 

assigned each of these risks an equal weight in its final population risks by using the average of these individual risks. 

Individual risk estimation took into account the fact that the contaminant plumes might be intercepted by surface waterbodies by multiplying by 

either 0 or 1 as identified above. Each of these risks was then divided by exposure duration to estimate the yearly cancer risk.

117 Once all of 

these risks were calculated for a given WMU/liner type they were summed and divided by the number of iterations to give the average one year 

increment of risk for that WMU/liner type at the peak risk. Thus, the final equation that was used for calculating average risks can be stated as: 

 

113 Fluidized Bed Combustion waste results were not deemed appropriate for use for the reasons discussed in EPA gHuman and Ecological Risk Assessment of Coal 

Combustion Wastes,h Office of Resource Conservation & Recovery, August 2009. 

114 A 1981 Oak Ridge National Laboratory study states gAs (III) is likely to be the predominant arsenic species in ash pore water and groundwater.h Source: Turner, Ralph 

R. gOxidation State of Arsenic in Coal Ash Leachate,h Environmental Science & Technology, Vol.15, Number 9, September 2001. 115 Full interception will not occur in instances where the waterbody is shallow, the waterbody is man-made, or the facility is oriented perpendicular to the waterbody. This 

simplifying assumption serves to minimize the influence of the model runs in which interception may have occurred, but was not reflected in EPA gHuman and Ecological 

Risk Assessment of Coal Combustion Wastes,h Office of Resource Conservation & Recovery, August 2009. 

116 For further discussion of how these distributions were developed, see Appendix C of EPA gHuman and Ecological Risk Assessment of Coal Combustion Wastesg Office 

of Resource Conservation and Recovery, Washington, DC, August 2009. 

117 For further discussion of cancer risks and exposure durations, see Appendix K4 of this RIA. 
117 

N

EDn

RISKn WELLREACH

iRISK

¦ u

 

Where: 

iRISK = Average increment of lifetime cancer risk from a 1-year exposure 

RISKn = Risk result for the nth model run 

WELLREACH = 0 if plume is intercepted by a surface water body, 1 otherwise 

EDn = Exposure duration for the nth model run 

n = Iteration number 

N = Number of iterations 

The results are presented in Exhibit 5A-3 below. For each, the results are presented for both adults and children under each of the WMU/liner 

scenarios. For full distributions of individual risks before averaging, see Appendix K6 v Distributions. 

Exhibit 5A-3 

Peak One Year Risks For CCR Cancer 

Conventional CCR CCR Co-managed With Coal Refuse 

Liner - Receptor Landfills Impoundments Landfills Impoundments 

Unlined - Adult 6E-06 4E-05 5E-06 2E-04 

Unlined - Child 1E-05 1E-04 1E-05 4E-04 

Clay-Lined - Adult 3E-06 3E-05 2E-06 1E-04 

Clay-Lined - Child 7E-06 6E-05 4E-06 2E-04 

Step 4. Extrapolate Annual Cancer Risks from Peak Cancer Risks 

The peak risks that were calculated occur well after cancers can first materialize. Thus, constraining the benefits to only the peak population 

risks significantly underestimates total cancers avoided. To compensate for this shortfall, this RIA formulated an approach illustrated in 

Exhibit 5A-4 below. The blue parabolic curve for population risk is based on the well concentrations over time in the results. While EPA 

cannot reconstruct the exact curve due to data availability issues, a parabolic curve represents groundwater contamination. From this shape it is 

clear that the peak population risks only capture a fraction of total population risks. Using an assumption of linear increases to the peak and 

linear decreases from the peak, produced the simplified risk profile seen as a red line in Exhibit 5A-4. 
118

t = time to peak risk 

Exhibit 5A-4 – Population Risk Method 

t Time (years) 

t0 = WMU built 

t0 t 

Rt 

Rt = peak population risk 

 = Actual Risk Profile 

 = Simplified Risk Profile 

Population Risks At Peak One 

Year Exposure Only 
119 

The constant slope allowed estimation of the population risks from each year_s exposure by assembling the model iteration times to peak.118 

Dividing peak risks (y-value) by the time to peak (x-value), the slope of the time line was determined for each WMU/liner type as displayed in 

Exhibit 5A-5 below. 

Exhibit 5A-5 

Human Cancer Time Slope Factors For CCR 

Slopes For Conventional CCR Slopes For CCR Co-managed With Coal Refuse 

Liner - Receptor Landfills Impoundments Landfills Impoundments 

Unlined - Adult 1E-08 6E-07 8E-09 3E-06 

Unlined - Child 2E-08 1E-06 2E-08 6E-06 

Clay-Lined - Adult 5E-09 4E-07 3E-09 1E-06 

Clay-Lined - Child 1E-08 7E-07 6E-09 3E-06 

Multiplying this slope by the number of years elapsed yields the yearly increment of individual risk for that year. Multiplying this average 

incremental individual risk by the population exposed in each year119 EPA estimated the number of cancers in each year. While this underestimates cancer incidence by the difference between the blue and red profiles it is the best estimate based on currently available data. 

As displayed in Exhibit 5A-6 below, this approach results in an estimate between 45 and 196 potential cancer cases over 75 years120 as a result 

of arsenic consumed through contaminated groundwater using EPA_s 1995 cancer slope factor (1.5 mg/kg/d-1) for arsenic based on skin 

cancers. Using the ratios of conventional CCR co-managed with coal refuse a best estimate within this range is 145 cancers. 

 

118 Since these iterations were performed in later model runs they could not be tied to the specific model iterations used above. 67% of the model runs had the nearest 

groundwater well occurring beyond the nearest surface waterbody. Since the longer arrival times occur with longer travel distances, and these iterations tended to be the 

iterations that were intercepted, assumed that the 33% of model runs that were not intercepted are also the 33% of model runs with the shortest arrival times (i.e., shortest 

distances). Taking the midpoint of these arrival times yielded the 16.5th percentile. 119 This RIA inflated the future population each year based on the future projections made by the US Census Bureau. From that point on, this RIA assumed a constant 

annual growth rate equal to the growth rate in year 2050. 

120 Seventy-five years were used for the analysis based on the 78 year time to peak period, less two years states are allowed to adopt the rule_s provisions, and less an 

additional year for installing groundwater monitoring. Seventy-eight years are the time at which the risks for typical unlined and clay-lined surface impoundments that are 

not intercepted by surface water will peak. Cancers occurring after year 78, though potentially significant, are unlikely to play a significant role when monetized because 

under a 3% discount rate, benefits fall to ten percent of their value at year 78, and at a 7% discount rate, benefits fall to 0.5% of their value at year 78. These future cancers 

will be further reduced by state regulations, detection of contamination, and a general trend away from wet handling. 
120 

Exhibit 5A-6 

Potential Future Human Cancer Cases from the Disposal of CCR Based on Arsenic Cancer-Slope Factor from EPA/IRIS 

Disposal of Conventional CCR Disposal of CCR 

Co-Managed with Coal Refuse 

WMU Adult Child Totals Adult Child Totals 

Unlined Landfills 0.1 0.1 0.2 0.1 0.1 0.2 

Clay-Lined Landfills 0.1 0.1 0.2 0.0 0.0 0.0 

Unlined Surface Impoundments 20.1 16.3 36.4 98.1 67.6 166.7 

Clay-Lined Surface Impoundments 4.8 3.5 8.3 17.6 12.6 309.2 

Totals 25.1 20.0 45 115.8 80.3 196 

Step 5. Estimate Arsenic Cancer Risks Using Recent NRC Science for Arsenic 

Based on the NRC data source, lifetime exposure to 10 ug/L arsenic in drinking water would lead to 23 excess male bladder cancers and 14 

excess male lung cancers per 10,000 people. Under the exposure factor assumptions used by the NRC the equivalent cancer slope factor (CSF) 

is 26 mg/kg/d-1. For details of how this cancer slope factor was calculated, see Appendix K4 v Cancer Calculations.121 Exhibit 5A-7 below 

displays the population risk estimates for CCR disposal base on the NRC source.122 Using the NRC (2001) cancer slope factor one would 

expect between approximately 778 and 3,392 cancer cases over 75 years as a result of arsenic consumed through contaminated groundwater. 

Using the ratios of conventional CCR co-managed with coal refuse produces a best estimate within this range of 2,509 cancers. 

Exhibit 5A-7 

Potential Future Human Cancer Cases from CCR Disposal Based on Arsenic Cancer-Slope Factor from NRC 

Disposal of Conventional CCR Disposal of CCR 

Co-Managed with Coal Refuse 

WMU Adult Child Totals Adult Child Totals 

Unlined Landfills 2 2 4 1 1 2 

Clay-Lined Landfills 1 1 2 1 1 2 

Unlined Surface Impoundments 348 281 629 1,696 1,169 2,865 

Clay-Lined Surface Impoundments 82 61 144 305 218 523 

Totals 433 345 778 2,003 1,389 3,392 

 

121 EPA is currently in the process of revising the arsenic cancer slope factor in EPA_s Integrated Risk Information System (IRIS). 122 EPA also conducted a sensitivity analysis assuming the female cancer slope factor in Appendix K5 of this RIA. 
121 

Step 6. Monetize Future Avoided Cancer Risk Benefits 

Reflecting the best science available, EPA used a point estimate of cancer cases avoided to monetize cancer risks. Appendix K4 provides 

further explanation as to why the NRC science is considered more appropriate than the older skin cancer research that the current IRIS value 

was derived from. Because EPA has greater confidence in the NRC estimates, it chose to use the 2,509 cancers calculated above as the best 

estimate. EPA also used the NRC ratio of 23 male bladder cancers to 14 male lung cancers to estimate how many of each type were likely to 

occur in each year. That is, 62%, or 1,556 cancers, are assumed to be bladder cancers and 38% or 953 are assumed to be lung cancers. 

Appendix K7 shows the best estimate number of lung and bladder cancers in each year that was used in the remaining portions of this analysis. 

Since cancers are not all fatal, the next step was to estimate the number of cancers that are fatal and non-fatal. This was done separately for 

each type of cancer using 5-year survival rates from the EPA-ORCR 2009 CCR risk report. The 5-year survival rate used for bladder cancer is 

82% and the 5-year survival rate used for lung cancer is 14%. Thus, 1,276 (82%) of bladder cancers are non-fatal and 280 (18%) are fatal. For 

lung cancer, 133 (14%) are non-fatal and 820 (86%) are fatal. Again, these cancers are spread over the 75 years of the analysis. In order to 

monetize avoided cancer risks, this RIA applied the value of a statistical life (VSL) plus the cost of terminal cancer treatments displayed in 

Exhibit 5A-8 below. To monetize avoided non-fatal cancer risks, this RIA used an estimate from Magat et al. (1996).123 This study shows that 

a typical individual_s assessment of a non-fatal lymphoma risk reduction was the equivalent of 58.3% of a fatal lymphoma risk reduction.124 

Therefore, this RIA assumed individuals value non-fatal bladder and lung cancer risk reduction in a similar manner. 

Exhibit 5A-8 

Unitized Monetary Values for Human Cancer Risks Applied in this RIA 

Monetized Value 2008$ 

Fatal cancers: value of statistical life (VSL)* $8,800,000 

Non-fatal cancers: 58.3% of VSL* $5,130,400 

Medical costs associated with fatal bladder cancer** $149,863 

Medical costs associated with fatal lung cancer** $87,703 

Notes: 

*Median VSL of $4.65 million (1997$) from Exhibit 7-3 (page 89) of EPA gGuidelines for Preparing Economic Analyses,h EPA 240-

R-00-003, Sept 2000; converted for this RIA to 2008 dollars using the Consumer Price Index. In addition, projections of benefits in 

future years are subject to income elasticity adjustments. These represent changes in valuation in relation to changes in real income. 

For example, if, for every 1% increase in real income, a particular consumer_s willingness-to-pay for a particular item increases by 1%, 

this would be represented by an income elasticity of 1.0. For most items, income elasticity values are actually less than 1, indicating 

that valuation of most items does not increase as fast as real income levels. To do so, applied the change in Gross Domestic Product 

per-capita between the original dollar year of the estimates and 2008, and an income elasticity of 0.5 based on estimates from Viscusi, 

W. K. and Aldy, J. E. gThe Value of a Statistical Life: A Critical Review of Market Estimates throughout the World,h Journal of Risk 

and Uncertainty, Vol.27, 2003, pp. 15v76. 

** These costs reflect the inpatient hospital stays, skilled nursing facility stays, home health agency charges, physicians' services, and 

outpatient and other medical services - in other words the treatment and maintenance costs. Costs are assumed to occur during initial 

 

123 Magat, Wesley A., V. Kip Viscusi and Joel Huber "A Reference Lottery Metric for Valuing Health," Management Science, Vol.42, Issue 8, 1996, pp.1118 - 1130. 124 EPA acknowledges that alternative approaches to valuing non-fatal cancers are available. One such alternative is presented in Appendix K5 of this RIA. 
122 

Exhibit 5A-8 

Unitized Monetary Values for Human Cancer Risks Applied in this RIA 

treatment, maintenance care between initial and terminal treatment and terminal treatment during the final six months prior to death: 

x Bladder cancer costs are based on survival and death rates each year for 20 years which captures most deaths from 

bladder cancer among those who are diagnosed with the disease. 

x Lung cancer costs are based on a 10 year time horizon during which most deaths are assumed to occur. 

The original figures in the 2001 EPA report are in 1996 dollars (source: EPA gThe Cost of Illness Handbook,h Office of Pollution 

Prevention & Toxics, October 2001). These costs are updated for this RIA to 2008 dollars using the Medical Care Component of the 

Consumer Price Index. 

These values are further adjusted for cessation lag and income as described in Appendix K8. EPA used the cessation data of bladder cancers 

from arsenic in Chen and Gibb (2003)125 to construct a Weibull curve approximating the lag time between reduced arsenic exposure and 

reduced cancer outcomes. Because this lag will reduce willingness to pay compared to an immediate risk reduction, the value of reduced 

statistical cancers are 83% and 67% of what they would be using an unadjusted VSL (at a 3% and 7% discount rate, respectively.) This is 

described in more detail in Appendix K8. For income, EPA projected per capita GDP, and used this combined with an income elasticity of 0.5 

income elasticity of 0.5 from Viscusi and Aldy (2003) to estimate the growth in VSL until the exposure year. There has been economic debate 

over whether VSL should be adjusted to the year of exposure or the year of the cancer. However, typically, it is not possible to know when the 

exposure occurred. Because of the model used here, this RIA applied the VSL adjustment at the time of exposure. The full table of VSL 

adjustment factors, as well as their derivation, is presented in more detail in Appendix K8. 

Applying these nominal dollar values to the number of fatal and non-fatal bladder and lung cancers in each year, a current year value for 

avoiding cancer risk was calculated for each of the 75 years. These values can be seen in Appendix K7. The present value (PV) of these 

values is approximately $4,696 million at a 3% discount rate and $885 million at a 7% discount rate. This would reflect the value of avoiding 

future cancer risks assuming that no steps were taken to prevent contamination and the resulting cancers. However, as discussed below, this is 

not realistic under baseline state regulatory controls. 

Step 7. Account for Groundwater Remediation under the Baseline and Regulatory Options 

The results above assume that arsenic is released from existing impoundments and landfills, without any controls (beyond the liners taken into 

account in the model). The benefits of regulatory options would be reflected by lower rates of cancer, resulting from the rule_s controls 

(including ground-water monitoring, permitting, corrective action, phase-out of surface impoundments, financial assurance, etc.).126 The rule 

will also have the benefits of reducing or eliminating groundwater remediation cost, because groundwater releases are eliminated through 

 

125 Source: Chen, C.W. & Gibb, H. gProcedures for Calculating Cessation Lag.h Regulatory Toxicology and Pharmacology,h Vol.38, Issue 2, 2003, pp.:157-65. 126 The two Subtitle D Options evaluated were: (1) Subtitle D Ä regulation of landfills and surface impoundments, with liners required for existing and new surface 

impoundments, and new landfills and (2) Subtitle gD Primeh Ä regulation of landfills and surface impoundments, with liners required only for new surface impoundments 

and landfills. 
123 

controls like surface-impoundment phase-out, or reduced because releases are caught earlier. These benefits, and how they relate, are described 

in the section below. 

First, even in the absence of federal regulations, CCR disposal units will not leach and cause cancers in all cases estimated through the 

evaluation above. Even without federal regulation, there will be facilities that discover contamination and clean the contamination up before 

cancers occur, either due to state regulations or good practice. Where exposures are identified, this RIA assumed that the pathway will be cut 

off (e.g., through provision of alternative water sources). Even facilities that fail to prevent contamination may detect that contamination and 

clean it up at a later time, although after exposure has occurred. This Step of the estimation attempted to account for these practices. 

To estimate the different speed and cost of groundwater remediation likely under the baseline and under the three regulatory scenarios (i.e., 

Subtitle C, Subtitle D and Subtitle D Prime), this RIA began by examining the differences across states in groundwater monitoring 

requirements pertaining to CCR disposal units, and focused on groundwater monitoring requirements because adequate monitoring is needed to 

determine whether a release has occurred. This RIA assumes that, where releases of concern have been identified, and particularly where 

people may be at risk, drinking water pathways will be cut off and alternative drinking water will be provided. Then calculated the percentage 

of CCR disposed by each state, and noted which of three levels of groundwater monitoring were required: 

1. No monitoring requirements 

2. Monitoring requirements for only future newly constructed CCR disposal units 

3. Monitoring requirements for both future new and existing CCR disposal units 

Then EPA tracked the percentage of total waste that was discarded by facilities in states requiring each of these three monitoring scenarios. 

Exhibit 5A-9 below presents these percentages for states requiring at least some monitoring (categories 2 and 3 above) and states requiring 

monitoring at exiting facilities (category 3 above). The first value in the table, 91%, is the percentage of CCR discarded in landfills that impose 

some form of monitoring requirements, whether for new landfills only, or for both new and existing landfills. 62% is the percent of CCR 

discarded in landfills that impose monitoring requirements on both new and existing CCR disposal units (a subset of the 91%).127 Percentages 

are also provided for CCR that are managed in surface impoundments. Appendix K9 provides these data for each individual state. 

 

127 Some states may require monitoring only for off-site units; however, in the absence of a specific breakdown, EPA made the assumption that on-site units would be 

monitored in all states that require monitoring. 
124 

Exhibit 5A-9 

State Government Groundwater Monitoring Requirements Assumed in this RIA 

Landfills Surface Impoundments 

Any Monitoring 

Requirements 

(categories 2&3) 

Required at New and 

Existing Units 

(category 3) 

Any Monitoring 

Requirements 

(categories 2&3) 

Required at New and 

Existing Units 

(category 3) 

Percent of Facilities 91% 62% 48% 12% 

These percentages helped to determine when releases will be identified, and the likely cost of cleanups or other remedies, when releases are 

identified, under the baseline and three regulatory scenarios. Since all but 4 of the 2,509 cancers projected above result from surface 

impoundments, only surface impoundment monitoring data were used in the calculations.128 For the baseline scenario, it was assumed that 

states with the highest level of monitoring requirements (those requiring groundwater monitoring at both new and existing units) would 

generally find groundwater contamination relatively early and would require preventive measures that would avoid cancers (e.g., intercept the 

plume and/or put residents on municipal or bottled water). Thus, 12% of contamination that could occur would have already been detected, 

and the resulting cancers prevented. To the extent that cleanups and/or alternative water are required, that was considered part of the baseline. 

To model the Subtitle D option, EPA assumed that states with groundwater monitoring requirements at new units, or with some coverage of the 

units in question, would upgrade their existing programs to provide fuller coverage v because they already have a regulatory infrastructure v 

but other states with no program would not. While states that do not currently regulate units would not change their practices simply because 

EPA issued national rules, EPA recognizes that facilities in these latter states will to a certain extent comply, to avoid citizens_ suits. However, 

EPA_s and states_ experience in implementing the RCRA program demonstrates that self-implementing ground-water monitoring programs are 

of limited reliability. Given these factors, the percentage of waste disposed of in states with some level of groundwater monitoring programs is 

a reasonable estimate of benefits for the subtitle D approach. Under these assumptions, contamination in states with monitoring requirements 

for only new units, as well as contamination in states with monitoring requirements for new and existing units would be detected promptly. 

This leads to 48% of surface impoundment groundwater contamination being detected before extensive damage has occurred, and therefore 

48% of cancers being prevented. 

Since the Subtitle gD Primeh option does not require the retrofitting of existing units, unlined surface impoundments would remain a 

continuing source of release. However, the presence of a new national rule accompanied by EPA support would lead at least some states to 

make such updates. Since the potential risks will fall somewhere between the Subtitle D option and the baseline, the midpoint between 

baseline and the Subtitle D option (30%) was chosen as a best estimate. This leads to 30% of contamination being immediately detected, and 

thus 30% of cancers being prevented. 

 

128 Note, however, that considerable evidence indicates that releases from dry disposal can present significant risk as well, as demonstrated by EPA research on CCR leach 

rates at different pHs and the damage cases. 
125 

Finally, for Subtitle C, there would be federal oversight of the groundwater monitoring requirement, and therefore this RIA assumes 100% of 

facilities would have contamination detected early. Looking forward, this would effectively prevent all cancers.129 In addition, the technical 

standards of the subtitle C rule would largely prevent future releases because surface impoundments would be phased-out, and because new 

landfills would require composite liners. Similarly, closure requirements would largely prevent releases after closure of both types of units. 

Where releases of arsenic from disposal units occur in the future, they will be detected promptly after they occur under the proposed option, as 

well as under the other options where good monitoring programs are in place. In these cases, there may be response costs, but no cancer risks. 

On the other hand, if facilities do not have adequate detection systems in place (and other adequate controls, e.g., liners, adequate closure, etc.), 

then detection will be delayed. This RIA assumes that releases will eventually be discovered, but that detection may be on a delayed basis. To 

quantify this assumed that contamination would be discovered consistently until it was all discovered. Since the rate of discovery is 

unpredictable, further assumed detection would be at a constant rate, reaching 100% detection by the final year of the analysis.

130 These 

discoveries were assumed not to start for six years because the first percentile of time duration until peak risks for unlined surface 

impoundments occurred. Restated, this profile assumes that facilities in states that require groundwater monitoring for existing units would 

generally find contamination in the future soon after it occurred, reducing response costs, and preventing cancer risks. But where monitoring 

and other controls were not adequate, releases would potentially go undetected for lengthy periods, causing cancers until the contamination was 

eventually detected and those residents switched to municipal or bottled drinking water. In addition, response costs would be significantly 

increased. The present value of avoiding all of the risks in the baseline case is the upper-bound on benefits, and this upper bound is reduced by 

detection and groundwater remediation as described in this section. The risk reduction benefit for each regulatory option is the difference 

between baseline risks and remaining risks under that option. These benefits, accounting for the detection and remediation, are presented in 

Exhibit 5A-10 below. Baseline expected cancer risks are accounting for detection and remediation, compared to without taking these factor 

into account. Further discussion of the cancer profile can be found in Appendix K7. 

This RIA projects a trend towards decreased management of CCR in surface impoundments. Facilities with surface impoundments have been 

slowly moving from wet handling in impoundments to dry handling in landfills or to beneficial uses. While this trend could affect the profile 

discussed above, it is unlikely to have a significant effect on risks for two reasons. First, surface impoundments, to the extent they are closed, 

are typically closed with waste in place. Thus, they are likely to continue to leach beyond the 75-year period modeled in the 2009 risk 

assessment; this is particularly true in situations where they are not lined (which are overwhelmingly the case) and where they are located in 

states without strong regulation. In the latter case, closures are likely to be inadequate, leading to continued infiltration. Second, the releases 

that occurred before the surface impoundments are closed will continue to migrate until they reach the groundwater wells or until they are 

intercepted by a surface waterbody (again particularly in states without strong programs). Given the relatively very large size of the CCR 

impoundments, and the presence of a hydraulic head at least before closure, these historic releases have the potential to be significant. Given 

these considerations, the closure of surface impoundments in states without regulations (e.g., corrective action, groundwater monitoring, etc.) 

would behave very similarly to active surface impoundments in terms of their risks to human health and the environment. For this reason, the 

regulatory oversight in the options above was not modified for closed CCR disposal units. 

 

129 Cancers from historic releases would not be affected, but the releases would be promptly identified and future exposures avoided. 130 Some releases are likely to go entirely undetected in the absence of groundwater monitoring and other controls. However, to put a reasonable limit around the analysis, 

this RIA assumed 100% detection. 
126 

Exhibit 5A-10 

Present Value of Avoided Human Cancer Risks Associated with CCR Disposal 

($millions present value over 50-years) 

Discount rate Subtitle C Subtitle D Subtitle D_ 

@ 3% $1,825 $750 $375 

@ 7% $504 $207 $104 

The other major cost associated with groundwater contamination is that of remediation or other response. To estimate that cost, EPA began by 

estimating the number of coal-fired electric utility plants that would require responses under various state environmental programs, based on 

the 2009 risk assessment. In any particular situation, a state could require remediation of a site involving potential drinking water to 10-4, 10-5, 

or 10-6 levels. In addition, states may choose to require groundwater remediation for groundwater that is not a likely drinking water source, 

because of ecological concerns. Exhibit 5A-11 below shows the number of facilities potentially requiring cleanup. Since each estimate is 

equally acceptable under current state programs, the average is believed to be a best estimate for how many electric utility plants will ultimately 

need groundwater remediation so as not to overestimate the number of remediation events. 

Exhibit 5A-11 

Proportion of CCR Sites Requiring Remediation Based on State Cleanup Levels 

State Clean All Groundwater Clean Only Drinkable Groundwater 

Cleanup 

Levels 10-4 10-5 10-6 10-4 10-5 10-6 Average 

Total LF 22 50 72 7 16 24 32 

Total SI 93 132 150 31 44 50 83 

These plant counts are based on the probabilistic model iterations from the 2009 risk assessment which were used to estimate what fraction of 

sites would leach at above various clean up levels. Typically, solid waste cleanups can be conducted at either 10-4, 10-5, or 10-6 individual 

cancer risk levels. Exhibit 5A-12 uses the PERCENTRANK function in Excel to estimate what percent of risk results fall at or below each 

clean up level. For example, in the first cell of Exhibit 5A-12, the 78% means that 10-4 is higher than 78% of the probabilistic results for 

unlined landfills with conventional ash. 

UL = Unlined 

CL = Clay-Lined 

A = Conventionally Managed Ash 

C = Co-managed Ash 

LF = Landfill 

SI = Surface Impoundment 
127 

Exhibit 5A-12 

Percentile of Cleanup Levels in the EPA-ORCR 2009 CCR Risk Study 

Clean Up Level 

UL A 

LF 

CL A 

LF 

UL C 

LF 

CL C 

LF 

UL A 

SI 

CL A 

SI 

UL C 

SI 

CL C 

SI 

1.00E-04 78% 83% 74% 85% 46% 59% 30% 43% 

1.00E-05 55% 59% 42% 57% 15% 24% 12% 21% 

1.00E-06 36% 35% 18% 28% 5% 7% 3% 8% 

Model results equal to or above these percentiles would require a state or federal cleanup. In other words, the percentage of sites above the 

cleanup level displayed in Exhibit 5A-13 can be derived by subtracting the percents in Exhibit 5A-12 above from 100%. However, while 

states may require remediation of all groundwater, whether or not it is potable, they may also choose not to on a site by site basis. As discussed 

in the EPA-ORCR 2009 CCR risk report, it is estimated that two-thirds of sites are located closer to a surface waterbody than to the nearest 

groundwater well. Therefore, sites located on surface waterbodies may not be cleaned in some states. This 2/3 decrease is accounted for in the 

second set of values in Exhibit 5A-13. 

Exhibit 5A-13 

Percent of Electric Utility Plants Requiring Future Groundwater Remediation 

Clean Up Level 

UL A 

LF 

CL A 

LF 

UL C 

LF 

CL C 

LF 

UL A 

SI 

CL A 

SI 

UL C 

SI 

CL C 

SI 

Assuming All Groundwater is Remediated 

1.00E-04 22% 17% 26% 15% 54% 41% 70% 58% 

1.00E-05 45% 41% 58% 43% 85% 76% 89% 79% 

1.00E-06 65% 65% 82% 72% 96% 93% 97% 93% 

Assuming Only Potable Groundwater is Remediated 

1.00E-04 7% 6% 8% 5% 18% 13% 23% 19% 

1.00E-05 15% 14% 19% 14% 28% 25% 29% 26% 

1.00E-06 21% 21% 27% 24% 32% 31% 32% 31% 

The number of utility plants with each type of CCR disposal, liner type, and management combination was calculated by taking the Appendix 

F plant data from this RIA and combining it with the conventional versus co-managed rates. 
128 

Exhibit 5A-14 

Estimated Number of Electric Utility Plants by CCR Disposal Unit Type 

UL A 

LF 

CL A 

LF 

UL C 

LF 

CL C 

LF 

UL A 

SI 

CL A 

SI 

UL C 

SI 

CL C 

SI 

50 21 26 7 31 28 68 31 

Multiplying the number of facilities in each category from Exhibit 5A-14 above by the percent of facilities requiring remediation in Exhibit 

5A-13 above yields the estimated number of facilities that would lead to state or federal clean ups in Exhibit 5A-15 below. These estimates of 

the number of facilities requiring cleanup does not account for any cleanups resulting from other constituents exceeding a hazard quotient of 1. 

Thus, this estimate may under-estimate the total number of cleanups. 

Exhibit 5A-15 

Number of Electric Utility Plants Requiring Future Groundwater Remediation 

Clean Up Level 

UL A 

LF 

CL A 

LF 

UL C 

LF 

CL C 

LF 

UL A 

SI 

CL A 

SI 

UL C 

SI 

CL C 

SI 

Assuming All Groundwater Is Remediated 

1.00E-04 11 4 7 1 17 11 47 18 

1.00E-05 23 9 15 3 26 21 60 24 

1.00E-06 32 14 21 5 30 26 66 29 

Assuming Only Potable Groundwater Is Remediated 

1.00E-04 4 1 2 0 6 4 16 6 

1.00E-05 7 3 5 1 9 7 20 8 

1.00E-06 11 5 7 2 10 9 22 9 

With the number of units requiring remediation, EPA estimated the cost of groundwater remediation under the baseline and each regulatory 

option presented above. Groundwater remediation costs were estimated in two steps. First, EPA assumed contamination that might occur at 

sites in states with more stringent monitoring requirements, would be discovered promptly. This suggests that there is likely to be less 

remediation required than at the typical site. Thus, EPA assigned these sites the 25th percentile remediation costs displayed in Exhibit 5A-16

below as the midpoint of the bottom half of costs. These future remediation events were spread evenly across all 75 years of the analysis. 
129 

Exhibit 5A-16 

Per-Site Groundwater Contamination Remediation Costs* 

Cost element category 25th percentile gearly costsh 75th percentile glater costsh 

Capital Costs $6,075,900 $21,195,000 

Annual O&M $98,910 $1,413,000 

O&M at 3% discount rate** $1,978,242 $28,260,605 

O&M at 7% discount rate** $1,239,522 $17,707,453 

Total cost at 3% $8,054,142 $49,455,605 

Total cost at 7% $7,315,422 $38,902,453 

Notes: 

*Cost data from Exhibits 3 and 4 in EPA gCost Analyses for Selected Groundwater Cleanup 

Projects: Pump and Treat Systems and Permeable Reactive Barriers,h Office of Solid Waste & 

Emergency Response, EPA-542-R-00-013. February 2001 at: 

http://www.epa.gov/tio/download/remed/542r00013.pdf 

**O&M costs were capitalized over 30 years at both a 3% and 7% discount rate for use in the 

two estimates. This was done to simplify spreadsheet calculations. 

For the remaining sites expected to require remediation, but lacking groundwater monitoring requirements, EPA assumed discovery of 

contamination would take longer. That is, CCR contamination would have migrated for some number of years, resulting in a larger 

groundwater plume to remediate, or more extensive remediation. EPA assigned these sites the 75th percentile remediation costs as the midpoint 

of the top half of costs. Since the first percentile time to peak results for unlined surface impoundments is six years, it is assumed that no 

discoveries and cleanups will be made in the first six years for these sites (three years once the two years for state adoption and one year for 

groundwater monitoring are considered). The costs are thus spread evenly over the remaining 72 years. The present value of these 

remediations, accounting for the slow, but continued discovery of contaminated sites, is presented in Exhibit 5A-17 below. Further discussion 

of the discounted remediation costs for each year is presented in Appendix K10. 

Exhibit 5A-17 

Present Value of Future Groundwater Remediation Costs from CCR Contamination 

($ millions present value over 50-years) 

Discount Rate Subtitle C Subtitle D Subtitle D_ Baseline 

@ 3% $96 $1,016 $1,302 $1,587 

@ 7% $39 $336 $420 $504 
130 

Aggregate benefits from cancer risk reductions and avoided remediation costs are summarized in Exhibit 5A-18 below. These benefits are 

calculated by subtracting the costs resulting under that option from the costs resulting under the baseline (i.e., cost avoided). 

Exhibit 5A-18 

Present Value of Future Avoided Human Cancer Risks 

& Avoided Groundwater Remediation Cost Benefits 

($millions present value over 50-years) 

Subtitle C Subtitle D Subtitle D_ 

@ 3% discount 

Groundwater Remediation Costs Avoided* $1,491 $571 $286 

Human Cancer Risks Avoided $1,825 $750 $375 

Total $3,316 $1,321 $661 

@ 7% discount

Groundwater Remediation Costs Avoided* $466 $168 $84 

Human Cancer Risks Avoided $504 $207 $104 

Total $970 $375 $188 

Note: 

* Calculated by subtracting the present value future groundwater remediation cost estimated in Exhibit 

5A-17 for each regulatory option, from the estimated baseline present value in that same Exhibit. 

Step 8. Characterize Cancer Risk Estimation Uncertainties 

There are a number of uncertainties associated with the annualized cancer estimates calculated in this RIA which are likely to under-estimate 

groundwater protection benefits: 

x Estimates do not account for historic releases at operating plants. These releases could lead to further migration and future cancer risks 

without proper regulatory actions like groundwater monitoring. 

x A linear slope for individual cancer risk was used to approximate the increase in cancer risks instead of the parabolic curve. 

x Approximately 18% of plants dispose of CCR off-site only. Since these facilities were not accounted for, additional populations would be 

exposed to arsenic cancer risks from disposal as recently illustrated by the Gambrills, MD and Chesapeake, VA damage cases. 

x Three new research studies131 (2006, 2008, 2009) from EPA_s Office of Research and Development, indicates that landfills may leach toxic 

metals much faster than originally believed. The damage cases at Gambrills MD and Chesapeake VA resulted in groundwater 

contamination much more quickly than would be expected, and are therefore consistent with this research. 

 

131 The three new EPA studies are: 

1. gCharacterization of Mercury-Enriched Coal Combustion Residues from Electric Utilities Using Enhanced Sorbents for Mercury Control,h EPA 600/R-06/008. 

Office of Research and Development. Research Triangle Park, NC. January 2006. 
131 

x Multiple CCR disposal units at a single electric utility plant will all affect the same population. The risk estimates do not account for any 

additive risks from multiple units. However, the populations around these units are accounted for as described in Appendix K2. 

x Multiple landfills could exist at some facilities. While the area of multiple surface impoundments was considered, the area of multiple 

landfills was not considered because EPA did not have survey results for dry handling even though some facilities are known to have more 

than one CCR landfill onsite. 

x Residents on municipal water systems were not included in the 2009 risk assessment or in this analysis. However, exposure through this 

pathway is possible, which means this RIA likely under-estimated the human population that may be exposed to CCR. 

x Populations that are farther than 1-mile that may be within the plume were not included. 

x Some surface water bodies that this analysis assumes fully intercept the groundwater plume may in fact only partially intercept the plume, 

or not intercept it at all. This situation would be more likely to occur when surface water bodies are small or shallow with low flow rates, 

relative to the size of the aquifer underneath the CCR disposal unit, or are oriented such that they would not likely intercept the 

groundwater plume. 

x Potential cancer cases resulting from consumption of recreationally-caught fish (contaminated by direct surface impoundment discharges 

and leaching from groundwater to surface water) are not included in the calculations. 

x According to the EPA-ORCR 2009 CCR risk study, cancers can continue well after the analysis ends, but these cancers were not calculated 

in the population risk estimates. 

x The use of a 5-year survival rate does not take into account those who may die from the cancer after year 5. Since some of the projected 5-

year cancer survivors would have died in later years, they are undervalued in this assessment. 

x The estimated number of cleanups is based only on modeled arsenic contamination. It does not account for cleanups based on hazard 

quotients over 1 for toxic constituents with non-cancer endpoints. 

The following are some uncertainties that are likely to cause over-estimation of groundwater protection benefits: 

x Cancer risk estimates might include some individuals who are down-gradient, but are outside the plume. 

x All arsenic was assumed to be present in the arsenic III state. Appendix K5 contains an analysis in which all arsenic was assumed to be 

speciated in the arsenic V state, and EPA concluded that even if some portion of arsenic was speciated in the arsenic V state, the final 

results would not significantly change. 

x The male CSF estimate from NRC (2001) was used instead of the female CSF. Appendix K5 contains an analysis in which this female 

CSF was applied. 

x It is possible that some states would choose not to remediate CCR contamination above cleanup levels once local residents were placed on 

municipal or bottled water. 

 2. gCharacterization of Coal Combustion Residues from Electric Utilities Using Wet Scrubbers for Multi-Pollutant Control,h EPA/600/R-08/077. Office of 

Research and Development, Air Pollution Control Division. Research Triangle Park, NC. July 2008. 

3. gCharacterization of Coal Combustion Residues from Electric Utilities v Leaching and Characterization Data,h EPA-600/R-09/151. Office of Research and 

Development, Air Pollution Control Division. Research Triangle Park, NC. December 2009. 
132 

x Willingness to pay estimates for non-fatal cancers has been assigned lower values in some research. An alternative valuation for these 

cancers is presented in Appendix K5. 

x Medical treatment costs for those dying of cancer would not occur until the cancer was first discovered. 

The following are some uncertainties that have an unknown effect on the benefits: 

x This RIA assumed an evenly distributed population for establishing up-gradient and down-gradient populations, as well as for adjusting 

population for the WMU area. 

x The latitude and longitude data of the WMU are uncertain. 

x State programs serve as a proxy for units managed well and units managed poorly. However, there could be some WMUs managed well in 

states without any program. Conversely, there could be some WMUs managed poorly in states with an existing program. 

x State regulatory programs affecting CCR disposal may be different than summarized in Appendix E of this RIA. 

x Remediation costs are very site-specific, and the 25th and 75th percentile costs used here may overestimate or underestimate the true 

remediation costs of any particular cleanup. For example, the cost of responses to new releases caught early will sometimes be below the 

estimated costs. In other cases, even if contamination is identified early, those costs can exceed the 75th percentile estimates above. 

Responses at Gambrills MD and Chesapeake VA, two sites where CCR contamination was identified relatively early, are examples of sites 

where actual groundwater remediation responses will far exceed the cost estimates. 

x This RIA assumed that discovery of CCR groundwater contamination and the resulting remediation costs would be incurred evenly over the 

75 year period for regulated facilities and evenly over the 72 years for unregulated facilities. However, experience under the municipal 

solid waste program indicates that the incorporation of lined units could reduce contamination over time. 
133 

5B. Benefit of Preventing Future CCR Impoundment Structural Failures (Avoided Cleanup Costs) 

In December 2008, a failure of a CCR impoundment at the Tennessee Valley Authority (TVA) Kingston Fossil Fuel Plant TN resulted in the 

environmental release of 5.4 million cubic yards of CCR. This impoundment failure event illustrated the potential environmental damage 

severity of structural failures involving CCR impoundments. This section of the RIA estimates future avoided impoundment failure cleanup 

costs as a potential benefit of the CCR proposed rule, according to the following 5-step method. 

Step 1. Characterize CCR Impoundment Release Data 

EPA began by examining the CCR impoundment survey data collected in March and April 2009 by EPA under the authority of Section 104(e) 

of the Comprehensive Emergency Response, Compensation and Liability Act (CERCLA), from 162 individual electric utility plants and from 

61 electric utility corporate headquarters offices. EPA obtained its list of facilities from a 2005 Department of Energy (DOE) Survey of coal 

burning electric utility facilities. EPA used DOE_s 2005 Energy Information Agency F767 database, which provides information on the 

disposition of coal ash from coal burning electricity producers. The database included "steam-electric plants with a generator nameplate rating 

of 10 or more megawatts." The term ggenerator,h means the actual electric generator, not the whole plant. A plant typically will have one or 

more generators. EPA also sent the letters to corporate offices of the electric utilities to make sure that all of their facilities were accounted for 

due to limitations in the DOE survey. Based on information received in response to the initial letter to the utility corporate headquarters 

offices, on April 27, 2009, EPA sent information request letters to an additional 48 plants that had been identified by the corporate offices. 

Based EPA_s initial collation of the mail survey data, 42 CCR releases from impoundments were reported, all of which occurred within the last 

15 years (1995-2009), in response to Question 8 of the survey questionnaire which asked for electric power plants to report all CCR 

impoundment releases which occurred within the last 10 years (i.e., 1999 to 2008). Exhibit 5B-1 below presents a summary of these 42 CCR 

impoundments release cases. Appendix K11 provides additional information about these 42 release cases. 
134 

Exhibit 5B-1 

2009 EPA Mail Survey Data for 42 Historical Release Events Involving CCR Impoundments at Coal-Fired Electric Utility Plants 

Item Owner Company Name of Coal-Fired Electric Plant Name of CCR Impoundment 

Capacity 

(acre feet) 

Height 

(feet) 

Year 

Installed 

CCR Release 

(gallons) 

Release 

year 

Age at 

release 

1 Allete Inc Clay Boswell Power Station Coal Pile Sump 1 20 1972 Unknown 2008 36 

2 Ameren Energy Generating Co Meredosia Power Station Fly Ash Pond 650 24 1968 500 2006 38 

3 American Electric Power Cardinal Power Station Fly Ash Reservoir 2 11350 237 1987 Unknown 2004 17 

4 City of Springfield Lakeside Metal Cleaning Waste Basin 4 1982 Unknown 1998 16 

5 City of Springfield Lakeside Metal Cleaning Waste Basin 4 1982 Unknown 2009 27 

6 Dominion Chesterfield Power Station Lower (Old) Ash Pond 740 19 1964 Unknown 2005 41 

7 Duke Energy Corp Walter C. Beckjord Power Station Ash Pond C 1400 50 1966 Unknown 1999 33 

8 East Kentucky Power Coop Inc Dale Power Station Dale Ash Pond #4 112 26 1977 Unknown 2008 31 

9 First Energy Generation Corp Bruce Mansfield Power Station Lakeside Ash Pond 20 1957 Unknown 

10 Georgia Power Co Harllee Branch Power Station C 1240 83 1971 Unknown 2000 29 

11 Georgia Power Co Bowen Power Station Ash Pond 3719 45 1968 Unknown 2002 34 

12 Georgia Power Co Bowen Power Station Ash Pond 3719 45 1968 Unknown 2008 40 

13 Indianapolis Power & Light Co Eagle Valley Generating Station A/B/C Pond 1949 30,000,000 2007 58 

14 Indianapolis Power & Light Co Eagle Valley Generating Station A/B/C Pond 1949 30,000,000 2008 59 

15 Kansas City Power & Light Co LaCygne Generating Station Scrubber Sludge Ponds 6818 45 1971 Unknown 2007 36 

16 Kansas City Power & Light Co LaCygne Generating Station Scrubber Sludge Ponds 6818 45 1971 Unknown 2007 36 

17 Kansas City Power & Light Co LaCygne Generating Station Scrubber Sludge Ponds 6818 45 1971 Unknown 2009 38 

18 MidAmerican Energy Co Riverside Generating Station South Surface Impoundment 109 10 1967 Unknown 2002 35 

19 Northern Indiana Pub Serv Co R. M. Schahfer Power Station Little Blue Run Dam 84300 388 1975 Unknown 

20 Northern States Power Co Sherburne County Power Station Pond No. 2 57 1984 600 2007 23 

21 PacifiCorp Naughton Power Station FGD Pond #2 382 25 1999 Unknown 2006 7 

22 PacifiCorp Naughton Power Station North Ash Pond 2100 61 1973 11,100,000 2007 34 

23 PacifiCorp Dave Johnston Power Station Blowdown Canal 1 0 1972 14,400 2009 37 

24 PacifiCorp Jim Bridger Power Station FGD Pond #1 1340 32 1979 Unknown 

25 PacifiCorp Jim Bridger Power Station FGD Pond #2 11534 42 1990 Unknown 

26 PPL Generation, LLC PPL Montour Power Station Detention Basin 53 8 1968 Unknown 2004 36 

27 PPL Generation, LLC PPL Martins Creek Power Station Ash Basin 4 40 43 1989 100,000,000 2005 16 

28 PPL Generation, LLC PPL Montour Power Station Ash Basin No. 1 40 1968 Unknown 2007 39 

29 PPL Montana LLC Colstrip Steam Electric Station Units 1 & 2 Stage Evaporation Ponds 4370 88 1992 100 1995 3 

30 PPL Montana LLC Colstrip Steam Electric Station Units 3 & 4 Effluent Holding Pond 17000 138 1983 Unknown 1999 16 

31 PPL Montana LLC Colstrip Steam Electric Station Units 1 & 2 Stage Evaporation Ponds 4370 88 1992 50 2000 8 

32 PPL Montana LLC Colstrip Steam Electric Station Units 1 & 2 A Pond 245 25 1975 2,700 2003 28 

33 PPL Montana LLC Colstrip Steam Electric Station Units 3 & 4 Effluent Holding Pond 17000 138 1983 Unknown 2004 21 

34 PPL Montana LLC Colstrip Steam Electric Station Units 3 & 4 Effluent Holding Pond 17000 138 1983 Unknown 2005 22 

35 PPL Montana LLC Colstrip Steam Electric Station Units 1 & 2 Stage Evaporation Ponds 4370 88 1992 2,000 2006 14 

36 Progress Energy Carolinas Inc W. H. Weatherspoon Power Station 1979 Pond 28 1979 Unknown 2001 22 

37 Progress Energy Carolinas Inc Roxboro Power Station FGD Flush Pond 33 2008 Unknown 2008 0 

38 Santee Cooper Winyah Power Station Unit 3 & 4 Slurry Pond 1190 30 1980 Unknown 2008 28 

39 Tennessee Valley Authority Kingston Power Station Dredge Pond 1955 1,100,000,000 2008 53 

40 Tennessee Valley Authority Widows Creek Power Station Gypsum Stack (Wet Stacking Area) 11157 75 1986 6,100,000 2009 23 

41 Xcel Energy PSCo Comanche Station Polishing Pond (#4) 12 0 1972 3,000 2007 35 

42 Xcel Energy PSCo Valmont Station West Ash Settling Pond 16 0 1964 5,050 2008 44 

 Minimum = 1 0 1949 50 1995 0 

 Maximum = 84,300 388 2008 1,100,000,000 2009 59 

 Mean (average) = 6,874 59 1976 85,148,560 2005 29 

 Median = 1,750 42 1974 5,050 2007 32 

 Column total (based on gallons released data for 15 of the 42 events) = 1.277 billion 
135 

As displayed below in Exhibit 5B-2, EPA was able to collect cost data on three of the most significant and recent release cases (i.e., cases 

resulting in the most gallons released): 

Exhibit 5B-2 

Cleanup Costs for Three Recent Environmental Releases Involving CCR Impoundments 

Item Owner company name 

Coal-fired electric utility 

Plant name & location 

Impoundment 

release year 

Release volume 

(gallons) 

EPA-assigned cost 

for this RIA* 

1 PPL Generation LLC PPL Martins Creek Power Station PA 

(gAsh basin 4h) 

2005 100 million $37 million 

2 Tennessee Valley Authority (TVA) Kingston TN 

(gDredge cell dikeh) 

2008 1.1 billion 

(5.4 million cubic yards) 

$3.0 billion 

3 Tennessee Valley Authority (TVA) Widows Creek Power Station TN 

(gGypsum stackh) 

2009 6.1 million $9.2 million 

Column totals = 1.2061 billion $3.0462 billion 

* Data sources: 

x Item 1: Page 29 of gPublic Health Issues Surrounding Coal as an Energy Source,h Brian Schwartz, MD, MS, Department of Environmental Health Sciences, February 

2009 at http://www.jhsph.edu/bin/g/f/Coal_and_public_health_Mar_2009.pdf 

x Item 2: $3.0 billion is EPA_s initial gsocial costh estimate assigned in this RIA to the December 2008 TVA Kingston TN impoundment release event. Social cost 

represents the opportunity costs incurred by society, not just the monetary costs for cleanup. OMB's 2003 "Circular A-4: Regulatory Analysis" (page 18) instructs 

Federal agencies to estimate "opportunity costs" for purpose of valuing benefits and costs in RIAs. This $3.0 billion social cost estimate is larger than TVA_s $933 

million to $1.2 billion cleanup cost estimate (i.e., TVA_s estimate as of 03 Feb 2010), because EPA_s social cost estimate consists of three other social cost elements 

in addition to TVA_s cleanup cost estimate: (a) TVA cleanup cost, (b) response, oversight and ancillary costs associated with local, state, and other Federal agencies, 

(c) ecological damages, and (d) local (community) socio-economic damages. Appendix Q to this RIA provides EPA's documentation and calculation of these four 

cost elements, which total $3.0 billion in social cost. Appendix Q to this RIA also provides an alternative, lower estimate of social costs, based on different 

modeling assumptions for capturing such costs. This alternative analysis suggests that TVA_s cleanup costs alone may be close to the social costs associated with the 

Kingston impoundment failure. EPA specifically requests comment on this social cost estimate, and will continue to develop this estimate for the final rule. 

x Item 3: 25 January 2010 e-mail entitled gTVA Widow_s Creek Clean Up Infoh from Anda Ray, Sr. Vice President of TVA Environment & Technology and TVA 

Sustainablity Officer, to Jim Kohler, EPA-ORCR Environmental Engineer. 
136 

Given this limited data, this RIA attempted to quantify the likelihood and costs of future releases using a historical methodology. First, 

distinguished between three types of historical CCR impoundment structural failures (i.e., releases): 

1. Catastrophic failures: Involving a billion gallons or more. These releases would have the potential to cause as much or more damage 

than occurred in December 2008 at TVA_s Kingston TN plant. 

2. Significant failures: Involving between a million and a billion gallons. These would be less than a complete failure, but still costly. 

TVA Widow_s Creek (6,100,000 gallons) and PPL Martin_s Creek (100,000,000 gallons) are the lowest and highest known releases in

this category, respectively. As an approximation, EPA assumes their costs should also bracket the costs of other significant 

releases.132 Thus, EPA estimates that the typical costs of a significant failure will be $23.1 million (the average of TVA Widow_s 

Creek and PPL Martin_s Creek). 

3. Seepage failures: Involving releases below one million gallons. While these releases can still be significant and present risks to 

human health and the environment, this RIA does not include these in this analysis, which under-estimates total costs using this 

historical methodology. These smaller seeps are common to earthen dams and are not necessarily a problem unless the seepage 

volume is increasing or the seepage becomes cloudy - indicating the possible transport of CCR through the embankment. 

Step 2. Fit a Distribution of Future Releases. 

For the two categories consisting of catastrophic and significant releases, this RIA estimates not only the cleanup costs of these events, but also 

their frequency. Since relatively little data are available, this RIA applies a Poisson distribution. The Poisson distribution is used when rare 

discrete events, and not continuous functions, are being modeled. To be a Poisson process, the arrival of events must satisfy stationarity, nonmultiplicity, and independence. Here, the events (releases) satisfy non-multiplicity because the probability of two or more events in a short 

period of time is very small. They also satisfy independence because releases occurring in one time period are independent of releases in any 

other time period. However, as these impoundments increase in age, it is quite likely that releases might increase over time, which would 

violate the stationarity requirement. This potential problem is dealt with in Step 4 below. For the present, it will be assumed that releases occur 

at a constant rate in the future. In general, a Poisson distribution can be represented by the equation: 

!

( ) ( )

k

t ek Ot O 

 

132 This is a valid assumption if cleanup costs are closely correlated to tonnage released. Since cost modeling software typically requires an input of gallons released, the 

correlation is likely strong. 
137 

Where: 

Ȝ = Observed arrival rate (0.067 for catastrophic, 0.333 for significant);133

t = Time period being projected (50 years) 

e = Constant (2.71828183) 

k = Number of impoundment release events projected 

The probabilities of a specific number of future CCR impoundment catastrophic or significant releases are illustrated in Exhibit 5B-2 and 

Exhibit 5B-3 (cumulative distribution) below. 

Exhibit 5B-2 

Poisson Distribution (Lamda=0.067, T=50) (Lamda=0.333, T=50)

0.0%

2.5%

5.0%

7.5%

10.0%

12.5%

15.0%

17.5%

20.0%

22.5%

0 5 10 15 20 25 30 35

Events (K)

Probability

Catastrophic Significant

 

133 Ȝ was calculated by dividing the number of events observed between 1995 and 2009 by the 15-year time period. 
138 

Exhibit 5B-3 

Cumulative Distribution

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

40.0%

45.0%

50.0%

55.0%

60.0%

65.0%

70.0%

75.0%

80.0%

85.0%

90.0%

95.0%

100.0%

0 5 10 15 20 25 30 35

Events

Probability

Catastrophic Significant
139 

Step 3. Calculate Future Impoundment Failure Avoided Cleanup Cost Benefits 

After fitting a distribution of the number of releases likely to occur, EPA proceeded to combine these with the cost data presented in Step 1 

above. This was done for the average case and three high-end cases (90th, 95th, and 99th percentiles). For each case, the number of expected 

releases seen in Exhibit 5B-4 below was divided by 50 to get the expected number of releases per year. These events were then multiplied by 

their respective costs, and the catastrophic and significant release values were summed in each year. 

Exhibit 5B-4 

Projected Future CCR Impoundment Releases 

Based on 15-Year (1995-2009) Period of Historical CCR Impoundment Structural Failure Cases 

Type of CCR Expected Number of Release Events 

Impoundment Release 99th %-ile 95th %-ile 90th %-ile Average 

Assigned Cost 

Per Failure Event 

Catastrophic 8 7 6 3 $3.0 billion* 

Significant 27 24 22 17 $23.1 million 

* Note: $3.0 billion is EPA_s initial gsocial costh estimate assigned in this RIA to the December 2008 TVA Kingston 

TN impoundment release event. Social cost represents the opportunity costs incurred by society, not just the monetary 

costs for cleanup. OMB's 2003 "Circular A-4: Regulatory Analysis" (page 18) instructs Federal agencies to estimate 

"opportunity costs" for purpose of valuing benefits and costs in RIAs. This $3.0 billion social cost estimate is larger 

than TVA_s $933 million to $1.2 billion cleanup cost estimate (i.e., TVA_s estimate as of 03 Feb 2010), because 

EPA_s social cost estimate consists of three other social cost elements in addition to TVA_s cleanup cost estimate: (a) 

TVA cleanup cost, (b) response, oversight and ancillary costs associated with local, state, and other Federal agencies, 

(c) ecological damages, and (d) local (community) socio-economic damages. Appendix Q to this RIA provides 

EPA's documentation and calculation of these four cost elements, which total $3.0 billion in social cost. Appendix Q

to this RIA also provides an alternative, lower estimate of social costs, based on different modeling assumptions for 

capturing such costs. This alternative analysis suggests that TVA_s cleanup costs alone may be close to the social costs 

associated with the Kingston impoundment failure. EPA specifically requests comment on this social cost estimate, 

and will continue to develop this estimate for the final rule. 

However, EIA data indicate that there is a current trend among coal-fired power plants to switch from wet handling to dry handling. As seen 

below in Exhibit 5B-5, this will lead to a decrease of approximately 300,000 tons being disposed of in surface impoundments per year, or 

approximately 1.3% of the initial 22.5 million tons in 2005. Since the tons disposed of (and similarly, the number of surface impoundments) 

likely relate to the number of releases, these decreases are accounted for by using 2005 wet tonnage as a benchmark and assuming the quantity 

of wet tonnage declines 300,000 tons per year. The cost for each year is multiplied by the remaining percent still handled wet. 
140 

Exhibit 5B-5 

Decreasing CCR Wet Disposal Trend 

Year % CCR Still 

Disposed Wet Year % CCR Still Disposed Wet Year % CCR Still Disposed Wet 

2005 100.0% 2024 75.2% 2043 50.3% 

2006 98.7% 2025 73.9% 2044 49.0% 

2007 97.4% 2026 72.6% 2045 47.7% 

2008 96.1% 2027 71.2% 2046 46.4% 

2009 94.8% 2028 69.9% 2047 45.1% 

2010 93.5% 2029 68.6% 2048 43.8% 

2011 92.2% 2030 67.3% 2049 42.5% 

2012 90.9% 2031 66.0% 2050 41.2% 

2013 89.5% 2032 64.7% 2051 39.9% 

2014 88.2% 2033 63.4% 2052 38.6% 

2015 86.9% 2034 62.1% 2053 37.3% 

2016 85.6% 2035 60.8% 2054 36.0% 

2017 84.3% 2036 59.5% 2055 34.7% 

2018 83.0% 2037 58.2% 2056 33.3% 

2019 81.7% 2038 56.9% 2057 32.0% 

2020 80.4% 2039 55.6% 2058 30.7% 

2021 79.1% 2040 54.3% 2059 29.4% 

2022 77.8% 2041 52.9% 2060 28.1% 

2023 76.5% 2042 51.6% 2061 26.8% 

The final step in the calculation was to take the adjusted costs in each year and discount them by 3% and 7% to calculate the present value (PV) 

as displayed in Exhibit 5B-6 below. A full table of year-by-year costs can be found in Appendix K11. Approximately 97% of these costs 

result from catastrophic releases, and the remaining 3% result from significant releases. It is important to note that no costs are attributed to 

2012-2014 as the rule will not be adopted and implemented until 2015. However, all costs beginning in 2015 are assumed to be avoided under 

subtitle C. Although facilities are given 5 years to phase out CCR impoundments under one of the proposed regulatory options, the other 

options require regular inspections of CCR impoundments to prevent catastrophic or significant releases. 

For a subtitle D approach, expect delayed compliance with the requirement that surface impoundments be lined and that existing unlined 

surface impoundments be closed if they aren_t lined when compared to compliance with the surface impoundment phaseout under subtitle C. 

Compliance will largely depend on the uncertainties of state regulations, the implementation of those regulations, and citizen suits. Also, since 

some facilities will line their surface impoundments instead of converting to dry handling, these facilities will continue to pose risks for 

catastrophic failure even though they may no longer require cleanup costs for groundwater contamination. The percent of states with at least 
141 

some surface impoundment regulations, 48% as described in Appendix K9, is used as a proxy for the phase-out of existing impoundments. 

However, the 5.5% of those 48% that would retrofit with composite liners could still pose release risks. This results in 45% of the subtitle C 

benefits being realized in subtitle D. 

For the subtitle D prime approach, existing impoundments will not need to be lined, but can continue to operate until they close. Third-party 

inspections of surface impoundments would be required under this option, but it is difficult to predict the extent to which these inspections 

would actually occur and would decrease catastrophic failures. In any case, the benefits of subtitle D prime would be less than those of subtitle 

D and greater than the baseline in terms of costs of catastrophic failures avoided. Thus, EPA used the midpoint as a best-estimate of the 

effectiveness that these inspections would have, which results in 23% of the subtitle C benefits being realized in a subtitle D prime approach. 

Exhibit 5B-6 

Estimate of Future CCR Impoundment Structural Failure Cleanup Costs Avoided 

As Benefits Under Three RCRA Regulatory Options 

(present value in $millions) 

Discount Rate 99th %-ile 95th %-ile 90th %-ile Average 

Subtitle C special waste 

3% $7,407 $6,483 $5,567 $3,124 

7% $4,177 $3,656 $3,140 $1,762 

Subtitle D (version 2) 

3% $3,333 $2,917 $2,505 $1,406 

7% $1,880 $1,645 $1,413 $793 

Subtitle gD Primeh 

3% $1,704 $1,491 $1,280 $719 

7% $961 $841 $722 $405 

Step 4. Account for Increasing CCR Impoundment Release Trend 

In Step 2 above, it was noted that the arrival rate of releases might violate the stationarity requirement for Poisson distributions. This is due to 

the trend of increasing release frequency based on the aging structure of the earthen impoundments. EPA attempted to discern whether a time 

trend was likely between releases and the average age of the surface impoundments. First, EPA limited the universe to the 38 releases that had 

reported release dates within the past 15 years. Next, the number of releases in 2009 was scaled up to account for the fact that the EPA mail 

survey questionnaires were returned by June of 2009. Thus, the four releases in 2009 were scaled up by 12 months/6 months, or a factor of 2. 

Using commission age and only those releases for which a release year was known, EPA constructed the profile of releases in the years ranging 

from 1995 to 2009 displayed in Exhibit 5B-7 below. 
142 

Exhibit 5B-7 

Summary of 15-Year (1995-2009) Period of 

Historical CCR Impoundment Structural Failures 

Year CCR impoundment 

average age 

Count of 

impoundment 

release events 

% of all CCR 

impoundments 

releasing 

1995 21.1 1 0.20% 

1996 21.5 0 0.00% 

1997 22.5 0 0.00% 

1998 23.5 1 0.19% 

1999 24.5 2 0.38% 

2000 25.3 2 0.38% 

2001 26.1 1 0.19% 

2002 27.0 2 0.37% 

2003 27.9 1 0.19% 

2004 28.7 3 0.55% 

2005 29.7 3 0.55% 

2006 30.5 3 0.55% 

2007 31.3 7 1.27% 

2008 32.3 8 1.45% 

2009 33.0 8 1.44% 

As can be seen in the table above, both the absolute number of releases and the percent of units with releases have increased over the past 15 

years. All five significant releases and the catastrophic release at TVA Kingston TN have happened since 2005. To account for this potential 

lack of stationarity, EPA conducted a sensitivity analysis with alternate values of Ȝ. Instead of looking at the last 15 years, EPA assumed that 

the previous 5-year period best reflects impoundment releases. Thus, in place of the earlier calculated lambda values (0.067 and 0.333) derived 

by dividing the number of catastrophic and significant failures between 1995 and 2009 by 15, EPA calculated higher lambdas (0.2 and 1) by 

dividing the catastrophic and significant failures between 2005 and 2009 by 5. Using these new lambda values, but keeping the same 50-year 

forecast period, EPA derived the Poisson distribution seen in the two figures below. The probability of a specific number of catastrophic or 

significant releases is illustrated in Exhibit 5B-8 and Exhibit 5B-9 (cumulative distribution) below. 
143 

Exhibit 5B-8 

Poisson Distribution (Lamda=0.20, T=50) (Lamda=1.00, T=50)

0.0%

1.5%

3.0%

4.5%

6.0%

7.5%

9.0%

10.5%

12.0%

13.5%

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80

Events (K)

Probability

Catastrophic Significant
144 

Exhibit 5B-9 

Cumulative Distribution

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

40.0%

45.0%

50.0%

55.0%

60.0%

65.0%

70.0%

75.0%

80.0%

85.0%

90.0%

95.0%

100.0%

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80

Events

Probability

Catastrophic Significant
145 

With these new distributions, EPA performed the same calculations as described in Step 3. The expected number of releases in Exhibit 5B-10

below was divided by 50 to get releases per year; these releases were multiplied by the cost per release; an adjustment was made to account for 

voluntary switching to dry handling; and yearly values were discounted. A full exhibit of year-by-year costs can be found in Appendix K11. 

Exhibit 5B-10 

Projection of Future CCR Impoundment Releases 

Based on 5-Year (2005-2009) Historical CCR Impoundment Release Cases 

Type of CCR Expected Number of Release Events 

impoundment release 

event 99th %-ile 95th %-ile 90th %-ile Average 

Cost per CCR 

impoundment release 

event 

Catastrophic 18 15 14 10 $3.0 billion* 

Significant 67 62 59 50 $23.1 million 

* Note: $3.0 billion is EPA_s initial gsocial costh estimate assigned in this RIA to the December 2008 TVA Kingston 

TN impoundment release event. Social cost represents the opportunity costs incurred by society, not just the 

monetary costs for cleanup. OMB's 2003 "Circular A-4: Regulatory Analysis" (page 18) instructs Federal agencies 

to estimate "opportunity costs" for purpose of valuing benefits and costs in RIAs. This $3.0 billion social cost 

estimate is larger than TVA_s $933 million to $1.2 billion cleanup cost estimate (i.e., TVA_s estimate as of 03 Feb 

2010), because EPA_s social cost estimate consists of three other social cost elements in addition to TVA_s cleanup 

cost estimate: (a) TVA cleanup cost, (b) response, oversight and ancillary costs associated with local, state, and other 

Federal agencies, (c) ecological damages, and (d) local (community) socio-economic damages. Appendix Q to this 

RIA provides EPA's documentation and calculation of these four cost elements, which total $3.0 billion in social 

cost. Appendix Q to this RIA also provides an alternative, lower estimate of social costs, based on different 

modeling assumptions for capturing such costs. This alternative analysis suggests that TVA_s cleanup costs alone 

may be close to the social costs associated with the Kingston impoundment failure. EPA specifically requests 

comment on this social cost estimate, and will continue to develop this estimate for the final rule. 

EPA estimated subtitle C (special waste) costs avoided that were between two and three times the costs predicted in Step 3. This difference 

helps to explain how significant the assumption of lambda, and the potential non-stationarity of the data, can have on the final results. 

Sensitivity results were also calculated for subtitle D (version 2) and subtitle gD primeh approaches. As assumed above for the subtitle D 

(version 2) option, EPA expects delayed compliance with the requirement that surface impoundments be lined and that existing unlined surface 

impoundments be closed if they are not lined when compared to compliance with the surface impoundment phaseout under subtitle C. 

Compliance will largely depend on the uncertainties of state regulations, the implementation of those regulations, and citizen suits. Also, since 

some facilities will line their surface impoundments instead of converting to dry handling, these facilities will continue to pose risks for 

catastrophic failure even though they may no longer require cleanup costs for groundwater contamination. The percent of states with at least 

some surface impoundment regulations, 48% as described in Appendix K9, is used as a proxy for the phase-out of existing impoundments. 

However, the 5.5% of those 48% that would retrofit with composite liners could still pose release risks. This results in 45% of the subtitle C 

(special waste) benefits being realized in Subtitle D (version 2). 
146 

For the subtitle gD primeh approach, existing impoundments will not need to be lined, but can continue to operate until they close. Third-party 

inspections of surface impoundments would be required under this option, but it is difficult to predict the extent to which these inspections 

would actually occur and would decrease catastrophic failures. In any case, the benefits of subtitle gD primeh would be less than those of 

subtitle D (version 2) and greater than the baseline in terms of costs of catastrophic failures avoided. Thus, this RIA used the midpoint as a 

best-estimate of the effectiveness that these inspections would have. This results in 23% of the subtitle C (special waste) benefits being 

realized in a subtitle gD primeh approach. Exhibit 5B-11 below presents the avoided cleanup cost estimates for the three regulatory options 

(i.e., Subtitle C special waste, Subtitle D version 2, and Subtitle gD primeh). 

Exhibit 5B-11 

Future CCR Impoundment Structural Failure Cleanup Costs Avoided 

($millions present value over 50-years) 

Discount Rate 99th %-ile 95th %-ile 90th %-ile Average 

Subtitle C (special waste) 

3% $16,708 $13,966 $13,043 $9,371 

7% $9,423 $7,876 $7,356 $5,285 

Subtitle D (version 2) 

3% $7,519 $6,285 $5,869 $4,217 

7% $4,240 $3,544 $3,310 $2,378 

Subtitle gD Primeh 

3% $3,843 $3,212 $3,000 $2,155 

7% $2,167 $1,811 $1,692 $1,216 

Step 5. Estimate Future Avoided Cleanup Costs for Two Alternative Impoundment Failure Scenarios (Scenario #2 & #3) 

Not all of these releases are likely to pose the type of catastrophic risks that were seen at TVA_s Kingston, TN plant. Catastrophic releases are 

more likely where there is a high potential for impoundment materials to disperse over large areas. This is most likely to occur at tall 

impoundments. Thus, this RIA presents an alternative assumption that the Kinston-like catastrophic releases would only occur at these tall 

impoundments. In addition, as age appears to be a driving factor in releases, this analysis also assumed that Kingston-like catastrophic releases 

would occur at older impoundments. Particularly, 96 impoundments of the 584 covered in the 2009 EPA mail survey were at least 40 feet tall 

and at least 25 years old. The analysis below assumes that 10% - 20% of these impoundments could fail within the next 20 years. This is 

equivalent to the upper percentiles of failures predicted in Steps 3 and 4 above; however it moves the costs forward in time, to show the 

sensitivity of the benefits with respect to time. 
147 

Exhibit 5B-12 

Scenario #2: Cleanup Cost Estimates for CCR Impoundment Catastrophic Failures @ 10% Failures 

% of Tons 

Baseline Year Costs @3% (in millions) 

Costs @7% 

(in millions) 

% of Tons 

Subtitle C 

Costs @3% 

(in millions) 

Costs @7% 

(in millions) 

88.2% 2014 - - 88.2% - - 

86.9% 2015 $1,146 $1,022 70.6% $930 $830 

85.6% 2016 $1,095 $941 52.9% $677 $582 

84.3% 2017 $1,047 $866 35.3% $438 $362 

83.0% 2018 $1,001 $797 17.6% $213 $169 

81.7% 2019 $956 $733 0.0% $0 $0 

80.4% 2020 $914 $674 

79.1% 2021 $873 $619 

77.8% 2022 $833 $569 

76.5% 2023 $796 $523 

75.2% 2024 $759 $481 

73.9% 2025 $724 $441 

72.6% 2026 $691 $405 

71.2% 2027 $659 $372 

69.9% 2028 $628 $341 

68.6% 2029 $598 $313 

67.3% 2030 $569 $287 

66.0% 2031 $542 $263 

64.7% 2032 $516 $241 

63.4% 2033 $491 $221 

62.1% 2034 $467 $202 

Baseline Total $15,305 $10,309 C Total $2,259 $1,943 

Given the costs above, the total benefits of a Subtitle C phase out over 5 years would be the difference between the potential catastrophic 

failure costs under C and the catastrophic failure costs under the baseline. For the 20% gScenario #3h, this figure is double, as displayed below 

in Exhibit 5B-13. For Subtitle D, it is assumed that the 48% of states (by tonnage, as described in Appendix K9) that have at least some 

regulatory oversight currently, would enforce the retrofitting requirement. However, since 5.5% of impoundments already have composite 

liners, these units would not be expected to close. Thus 94.5% times 48% leads to an approximately 45% of the Subtitle C benefits. For 

Subtitle D prime, the requirement of dam safety inspections would be likely to result in some amount catastrophic failure reduction between the 

baseline and the Subtitle D approach. This RIA uses the midpoint, a 23% reduction, as a best estimate. While these estimates are likely much 

higher than the actual benefits from preventing catastrophic failures, they do help to define the upper bound of what is possible under current 

practices of mismanagement. 
148 

Exhibit 5B-13 

Avoided Future CCR Impoundment Catastrophic Failure Cleanup Costs 

($millions present value) 

Scenarios Subtitle C 

Special waste 

Subtitle D 

(version 2) Subtitle gD Primeh 

Scenario #2: Assuming 10% of the 96 Impoundments Fail 

at 3% $13,046 $5,918 $2,959 

at 7% $8,366 $3,795 $1,897 

Scenario #3: Assuming 20% of the 96 Impoundments Fail 

at 3% $26,092 $11,836 $5,918 

at 7% $16,732 $7,590 $3,795 

Note: 

These future CCR impoundment failure cleanup costs avoided do not account for 

avoided costs from releases that are less than gcatastrophic.h 
149 

5C. Induced Effect of RCRA Regulation on CCR Beneficial Use 

This section assesses the potential effects of the different regulatory options for disposal of CCR on the future annual quantities of CCR 

beneficially used. It also estimates the values of social and economic impacts associated with baseline and different levels of beneficial use. It 

estimates the expected increase in beneficial use from increased cost of disposal of CCR and evaluates future changes in the beneficial use of 

coal combustion residuals (CCR) as a result of a potential gstigmah effect. 

5C1. Baseline Environmental & Economic Benefits of CCR Beneficial Use by Other Industries

According to CCR beneficial use market data compiled for year 2005 as displayed below in Exhibit 5C-1, and extrapolated in this RIA to 2009 

as displayed in Exhibit 5C-2 below, 62 million tons of annual CCR generated by 272 of the 495 electric utility plants is not disposed, but is 

beneficially used as material substitutes in at least 14 industrial applications. The purpose of this section is to provide estimates of two 

categories of baseline benefits associated with baseline CCR beneficial use, consisting of five sub-elements (i.e., 1a, 1b, 2a, 2b, 2c): 

1. Economic benefits: Economic benefits estimated in this section are based on recent market prices and include: 

a. Annual cost savings to over 14 CCR beneficial use industries in the form of reduced industrial raw and 

intermediate materials purchase prices relative to purchasing higher-priced substitute materials, compared 

to paying electric utility plants lower prices for buying and using CCR as an industrial material. 

b. Cost savings to electric utility plants for avoiding the cost of disposing CCR which is beneficially used. 

2. Lifecycle benefits: Lifecycle benefits as quantified in this RIA are based on market or social values assigned to the relative 

physical consequences of using CCR compared to substitute industrial materials, through the entire gmaterials 

flowh chain of the national economy which consists of five basic stages (1. raw materials extraction, 2. 

materials processing, 3. industrial manufacturing, 4. product use, 5. product end-of-lifespan 

disposal/recycling). Three lifecycle physical consequences are quantified in this RIA but not all monetized: 

a. Lifecycle resource consumption savings (water & energy consumption) 

b. Lifecycle air pollution emissions (GHG, CO, NOx, SOx, PM, Hg, Pb) 

c. Lifecycle wastes (wastewaters and solid wastes) 

Lifecycle benefits in this RIA are only based on three categories of CCR beneficial uses (i.e., concrete, 

cement, and wallboard representing a sub-total of 58% of all CCR beneficial uses) which were addressed in 

the prior 2008 study134 used as a reference for this section of the RIA. 

 

134 Source: EPA Office of Solid Waste gWaste and Materials-Flow Benchmark Sector Report: Beneficial Use of Secondary Materials v Coal Combustion Products,h Final 

Report, EPA report nr. 530-R-08-003, prepared by Industrial Economics Inc., 95 pages, 12 Feb 2008 at: http://www.epa.gov/osw/partnerships/c2p2/pubs/benuse07.pdf. 

The beneficial use market data cited in this source is summarized from the American Coal Ash Association (ACAA) 2005 national survey of the electric utility industry. 
150 

Lifecycle benefits encompass economic benefits so these two categories are not additive but duplicative. Lifecycle benefits in this RIA are 

based on glifecycle analysish (LCA), a method which involves estimating both internalized (e.g., market priced) and externalized (e.g., costs 

not captured in market prices) material flow consequences: 

gLife cycle analysis depicts the production of materials in a system of complex physical outcomes, and can predict the 

incremental physical consequences of a change in material inputs, technology, waste management practices, or price incentives. 

In LCA, as in reality, one change in the physical system, such as the substitution of fly ash for virgin Portland cement, leads to a 

corresponding cascade of economy-wide impacts and shifts. As inputs are substituted, technologies, physical outputs, and 

exposure pathways change. Using a range of modeling platforms and life cycle inventories to calculate the outputs associated 

with each incremental change, LCA calculates the net result of all of these interactions, capturing the total incremental effect of 

a change in operations on physical environmental impacts such as air emissions, and energy and water use.h 

x Economic Benefits of CCR Beneficial Use 

As estimated in Exhibit 5C-1 below (Column F), CCR used for beneficial use applications has an estimated annual US market value of $177 

million per-year based on annual CCR sales revenue data supplied by 233 electric utility plants to the 2005 EIA-767 database, updated in this 

RIA to 2009. Based on comparison with the average higher prices for substitute industrial materials, using lower-priced CCR provides the US 

national economy with $2,300 million in annual net cost savings compared to the higher $2,477 million annual cost of substitute materials in 

these 14 industrial applications (see Column I of Exhibit 5C-1). 
151 

Exhibit 5C-1 

Estimate of Annual Materials Cost Savings Benefit of CCR Generated by the Electric Utility Industry for Beneficial Use in Industrial Applications 

A B C D E F (C x E) G H (C x G) I (H v F) 

Item Industry Application 2005 CCR 

beneficial use 

(million tons) 

% of CCR 

beneficial use 

market 

2005 average 

market price paid 

electric plants* 

($/ton) 

Implied annual CCR 

sales revenues to 

electric utility plants 

2005 avg price 

for substitute 

material 

($/ton) 

2005 implied 

annual 

alternative 

materials cost 

Implied annual 

US national cost 

savings w/CCR 

beneficial uses 

1 Construction concrete ingredient 

NAICS code 3273 

See 1A + 1B See 1A + 1B See 1A + 1B See 1A + 1B See 1A + 1B See 1A + 1B See 1A + 1B 

1A Direct ingredient: substitute for portion 

of Portland cement ingredient in 

concrete mfg 

NAICS code 3273 

16.35 33.0% $0 to $45 $0 to $735.8 million $80 $1,308 million $572.2 to $1,308 

million 

1B Indirect ingredient: raw feed blended 

with limestone or shale to make 

cement clinker to be ground into 

cement for concrete mfg 

NAICS code 3273 

4.22 8.5% $0 to $45 $0 to $189.9 million $80 $337.6 million $147.7 to $337.6 

million 

2 Construction structural fill for building 

foundations and embankments 

NAICS code 238910 

8.35 16.8% $1 $8.35 million $3 $25.05 million $16.7 million 

3 Construction wall board 

NAICS code 327420 

8.18 16.5% $0 to $8 $0 to $65.4 million $4.5 to $12 $36.8 to $98.2 

million 

$32.8 to $36.8 

million 

4 Waste stabilization (substitute for lime) 

NAICS code 5622 

2.84 5.7% $15 to $25 $42.6 to $71.0 million $66 $187.4 million $116.4 to $144.8 

million 

5 Blasting grit 

NAICS code 212322 

1.63 3.3% Not reported Not reported Not reported Not estimated Not estimated 

6 Roofing granules 

NAICS code 324122 

Included with 

grit (row 5) 

Included with 

grit (row 5) 

Not reported Not estimated Not reported Not estimated Not estimated 

7 Minor uses (n=7)** 8.04 16.2% $3 to $20 $24.1 to $160.8 

million 

$5 to $83 $40.2 to $667.3 

million 

$16.1 to $506.5 

million 

Column totals (2005) = 49.61 100% 

Implied 

average (F/C) 

= $3 

$75 to $1,231 million 

(best estimate  = 

$149 million) 

Implied 

average (H/C) 

= $40 

$1,935 to 

$2,624 million 

(best est.** ** = 

$1,979 million) 

$1,830 

2008 updated estimates = 62*** $177 million $2,477 million $2,300 million 

($37 per ton) 

Explanatory notes: 

Source: Data in columns C, E, and G are from gWaste and Materials-Flow Benchmark Sector Report: Beneficial Use of Secondary Materials v Coal Combustion Products,h 

EPA report nr. 530-R-08-003, prepared by Industrial Economics Inc., 95 pages, 12 Feb 2008 at http://www.epa.gov/osw/partnerships/c2p2/pubs/benuse07.pdf 

* Average price includes gfree on boardh (FOB) shipping and insurance costs paid by the supplier from the point of manufacture to a specified destination. 

** Minor uses include: (1) agricultural soil amendment for flue gas desulfurization gypsum, (2) road base foundation layer underlying pavements for bottom ash, (3) mine 

reclamation material as substitute for soil, (4) mineral filler in asphalt, (5) soil stabilizer, (6) snow and ice control substitute for sand, and (7) mining. 

*** 2009 update estimated tonnage (Column C above) derived in Exhibit 5C-2 of this RIA; 2009:to2005 multiplier = 62.09/49.61 = 1.25. 

**** gBest estimateh in Column F based on sum of coal-fired electric plant CCR gbyproduct sales revenuesh from the DOE-EIA F767_PLANT database for 233 plants. 

 gBest estimateh in Columns H and I derived by numerical interpolation of the ranges displayed based on the proportionate best estimate and range of Column F. 
152 

Exhibit 5C-2 

2001-2008 Historical Trend in CCR Beneficial Use Quantity (Short Tons*) 

A. Actual Data: Year CCR Beneficial Use** 

(tons per year) 

% change % Use Linear Regression Output 

Actual = 2001 37,119,321 R-Squared 0.943 

Actual = 2002 45,523,256 +22.6% 35% Standard Error 1,859,123 

Actual = 2003 46,384,405 +1.9% 38% Observations 8 

Actual = 2004 49,089,818 +5.8% 40% Coefficients 

Actual = 2005 49,612,541 +1.1% 40% Intercept 39,784,058 

Actual = 2006 54,203,170 +9.3% 43% X Variable 2,867,597 

Actual = 2007 56,039,005 +3.4% 43% 

Actual = 2008 60,593,660 +8.1% 46% 

Notes: 

* Tons source: Amer. Coal Ash Assoc http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=3

** gBeneficial useh data in this Exhibit correspond to the 15 categories defined in the ACAA dataset which do not match the 

definition (examples) of CCR beneficial uses in EPA-ORCR_s CCR proposed rule. 

B. Trendline: Year Regression best fit % change 

Trendline = 2001 39,784,100 

Trendline = 2002 42,651,700 7.2% 

Trendline = 2003 45,519,300 6.7% 

Trendline = 2004 48,386,800 6.3% 

Trendline = 2005 51,254,400 5.9% 

Trendline = 2006 54,122,000 5.6% 

Trendline = 2007 56,989,600 5.3% 

Trendline = 2008 59,857,200 5.0% 

Projection = 2009 62,724,800 4.8% 

Annual average growth rate = 5.2% 

Annual CCR Beneficial Use Tons 

30,000,000

35,000,000

40,000,000

45,000,000

50,000,000

55,000,000

60,000,000

65,000,000

2001 2002 2003 2004 2005 2006 2007 2008 2009

Year

ACAA actual data Trendline
153 

Exhibit 5C-3 below presents a 2004 state-by-state summary of annual quantity of CCR beneficially used. 

Exhibit 5C-3 

State-by-State Summary of CCR Beneficial Use (2004*) 

A B C D E 

Item State 

2004 CCR 

generation 

(short tons) 

2004 CCR 

beneficial use 

(short tons) 

% CCR 

used 

beneficially 

1 AK 43,000 Not reported NR 

2 AL 3,408,000 663,000 19% 

3 AR 688,000 324,000 47% 

4 AZ 2,764,000 1,161,000 42% 

5 CA 50,000 0 0% 

6 CO 1,548,000 252,000 16% 

7 CT 181,000 0 0% 

8 DC 0 0 NA 

9 DE 121,000 24,000 20% 

10 FL 5,092,000 3,171,000 62% 

11 GA 3,141,000 1,022,000 33% 

12 HI 48,000 0 0% 

13 IA 1,260,000 750,000 60% 

14 1D 0 0 0% 

15 IL 4,419,000 1,968,000 45% 

16 IN 9,549,000 3,023,000 32% 

17 KS 1,399,000 575,000 41% 

18 KY 14,537,000 2,521,000 17% 

19 LA 1,588,000 716,000 45% 

20 MA 310,000 130,000 42% 

21 MD 1,983,000 646,000 33% 

22 ME 36,000 0 0% 

23 MI 2,145,000 614,000 29% 

24 MN 1,561,000 387,000 25% 

25 MO 2,348,000 1,070,000 46% 

26 MS 1,758,000 681,000 39% 

27 MT 952,000 51,000 5% 

28 NC 3,545,000 1,641,000 46% 

29 ND 2,757,000 731,000 27% 

30 NE 469,000 299,000 64% 

A B C D E 

Item State 

2004 CCR 

generation 

(short tons) 

2004 CCR 

beneficial use 

(short tons) 

% CCR 

used 

beneficially 

31 NH 141,000 57,000 40% 

32 NJ 600,000 112,000 19% 

33 NM 3,668,000 864,000 24% 

34 NV 825,000 314,000 38% 

35 NY 1,379,000 368,000 27% 

36 OH 6,980,000 2,290,000 33% 

37 OK 1,277,000 625,000 49% 

38 OR 95,000 81,000 85% 

39 PA 9,545,000 2,941,000 31% 

40 RI 0 0 NA 

41 SC 2,172,000 1,169,000 54% 

42 SD 105,000 28,000 27% 

43 TN 3,803,000 2,163,000 57% 

44 TX 12,943,000 4,395,000 34% 

45 UT 2,341,000 812,000 35% 

46 VA 2,442,000 203,000 8% 

47 VT 0 0 NA 

48 WA 2,301,000 1,683,000 73% 

49 WI 1,437,000 1,219,000 85% 

50 WV 7,220,000 2,401,000 33% 

51 WY 2,106,000 508,000 24% 

 Totals = 129,001,000 44,653,000 35% 

Notes: 

* Source: DOE & EPA, gCoal Combustion Waste Management at 

Landfills and Surface Impoundments 1994-2004,h DOE/PI-0004, Aug 

2006, page 5 (Table 1) at: 

http://www.ead.anl.gov/pub/doc/coal_waste_report.pdf

In comparison, the ACAA reports that a 5% smaller amount of 

122,465,119 tons CCR was generated in 2004 
154 

x Lifecycle Benefits Associated with CCR Beneficial Use 

The baseline (2005) material cost savings estimate displayed in Exhibit 5C-1 above is adjusted below to exclude the mining applications use, 

because mine-filling is not covered in the proposed rule.135 As displayed in Exhibit 5C-4 below, subtracting 2.3% of the mining applications 

beneficial use category decreased the baseline CCR beneficial use from 49.6 million tons to 48.5 million tons (relative to 2005). 

Exhibit 5C-4 

Subtraction of Mining Application Minor Use from the Minor Use Category 

of the Material Cost Savings for CCR Beneficial Use 

CCR Beneficial Use Category 

(Minor Uses) 

CCR beneficial 

use tons (2005) 

% of all 

CCR uses 

Materials price 

cost savings 

(million 2009$) 

1. Flowable fill 259,907 0.5% $10.7 

2. Road base/sub-base 1,461,992 2.9% $60.0 

3. Soil modification/stabilization 1,139,640 2.3% $46.8 

4. Mineral filler in asphalt 140,838 0.3% $5.8 

5. Snow & ice control 547,541 1.1% $22.5 

6. Mining applications 1,132,945 2.3% $46.5 

7. Agriculture 415,741 0.8% $17.1 

8. Aggregate 872,776 1.8% $35.8 

9. Miscellaneous minor uses 2,071,157 4.2% $85.1 

Sub-total Minor Uses = 8,042,537 16.2% $330.3 

Total All Uses (Major + Minor) = 49,612,541 100.0% $1,830 

Total Excluding Mining = 48,479,596 97.7% $1,783.5 

($37 per ton) 

From a materials lifecycle analysis perspective, CCR beneficial use generates net environmental benefits. Based on a 2008 life cycle study136

of two of the 14 CCR beneficial use industrial applications (i.e., concrete and wallboard) there are 12 environmental benefit categories with the 

annual magnitudes estimated below in Exhibit 5C-5. This estimate of environmental benefits is based on only 47% (i.e., 23.2 million tons) of 

the 49.62 million tons for the 2005 CCR beneficial use market as reported in that 2008 study. Thus, these estimates may understate annual 

environmental benefits of CCR beneficial uses. These net benefits are not additive to the economic benefits, but encompass them. 

 

135 As noted in the Federal Register notice of EPA_s proposed CCR rule, minefilling will be addressed in an alternate rulemaking. 136 Source: Exhibit 5-3 of gWaste and Materials-Flow Benchmark Sector Report: Beneficial Use of Secondary Materials v Coal Combustion Products,h prepared by 

Industrial Economics Inc for the EPA Office of Solid Waste, 12 Feb 2008, 95 pages at http://www.epa.gov/osw/partnerships/c2p2/pubs/benuse07.pdf 
155 

To avoid double-counting of economic and social benefits, EPA evaluated the monetization of the energy, water, and air pollution-related 

impacts for any such double counting. Based on this evaluation, this RIA concludes that each of the individual monetized estimates for these 

impacts are fully additive and do not double count benefits, with one exception regarding partial overlap between energy cost savings and the 

value of avoided SOx air emissions. For SOx, where there exists a cap and trade permit program, firms must pay to emit SOx. A portion of the 

SOx emissions avoided from beneficially using CCR is from the energy sector. Under the presumption that the marginal costs of abatement 

equal the value of marginal damages, the value of the portion of SOx emissions from the energy sector will be reflected in the energy cost 

savings. The portion of avoided SOx emissions that comes from sectors other than energy is not reflected in energy cost savings and thus 

should be retained. However, separately adding a value for reduced SOx emissions likely represents some amount of double counting. 

Unlike the SOx permit program, most regulation of NOx and particulate matter (PM) does not require firms to purchase permits to pollute. 

Thus there is little to no overlap between the external costs of these air pollutants and energy costs. In addition, aside from limited state 

programs, GHG damages are not currently regulated and would not be reflected in the market price for energy. Thus, the benefits from NOx, 

particulates and GHG reductions are fully additive to private energy cost savings. Furthermore, for water use, the only benefits included are 

the direct cost savings, and because the water savings in these cases are not associated with energy production, these savings are not being 

captured elsewhere. Reduced water use in the production process is a real cost savings that should be a component of total benefits. 

Therefore, this RIA concludes that there is only a partial double counting between energy cost savings and the savings associated with reduced 

SOx emissions. No other beneficial use benefits categories are affected by this double counting issue. Thus, Exhibit 5C-5 below has 

subtracted the $1,491 million benefits attributable to SOx reductions from the environmental benefits estimate, resulting in an environmental 

estimate of $22,980 million per year, or $474 per ton average lifecycle benefit, assigning zero values to tonnage other than concrete and 

wallboard. In addition to baseline lifecycle benefits, there are an estimated $2,927 million per year in baseline avoided disposal cost benefits 

to the electric utility industry (i.e., (49.61 million tons CCR beneficial use in 2005) x ($59 per ton average baseline disposal cost estimated in 

Exhibit 3L of this RIA)), which constitutes a total of $25,907 million per year (relative to 2005 CCR beneficial use tonnage), which is an 

average of $533 per ton nationwide baseline social benefits from CCR beneficial use. 

Exhibit 5C-5 

Estimate of Annual Baseline Lifecycle Benefits from CCR Beneficial Use 

(Based on 2005 CCR beneficial use tonnage) 

Benefit category Physical quantity of environmental benefits for 

48.5 million tons annual CCR beneficial use w/out mining application* 

Unit monetization 

values (2009$)** 

Estimated benefits 

($millions per year) 

A. Resource Consumption Savings 

1. Energy consumption 158 trillion BTU energy savings $0.00003093 per BTU $4,888 

2. Water consumption 32.1 billion gallons water savings $0.0025259 per gallon $81 

 Subtotal (1+2) = $4,969 

B. Air Pollution Savings 

3. GHG - greenhouse gases 11.5 million metric tons CO2 equivalent emissions avoided $20.76 per metric ton $239 

4. CO v carbon monoxide 9,200 metric tons emissions avoided Not estimated Not estimated 

5. NOx v nitrous oxides 30,400 metric tons emissions avoided $10,255 per metric ton $312 
156 

Exhibit 5C-5 

Estimate of Annual Baseline Lifecycle Benefits from CCR Beneficial Use 

(Based on 2005 CCR beneficial use tonnage) 

Benefit category Physical quantity of environmental benefits for 

48.5 million tons annual CCR beneficial use w/out mining application* 

Unit monetization 

values (2009$)** 

Estimated benefits 

($millions per year) 

6. SOx – sulfur oxides 23,900 metric tons emissions avoided $62,375 per metric ton $1,491 

7. PM v particulate matter 9,704 metric tons emissions avoided $486,312 per metric ton $4,719 

8. Particles non-specified 26,200 metric tons emissions avoided $486,312 per metric ton $12,741 

9. Hg - mercury 0.584 metric tons emissions avoided Not estimated Not estimated 

10. Pb - lead 0.656 metric tons emissions avoided Not estimated Not estimated 

Subtotal (3 to 10) = $19,502 

Subtotal air pollution savings excluding SOx & excluding mine-filling use = $18,011 

C. Other Environmental Savings 

11. Waterborne wastes 2,446 short tons waste generation avoided 

(SM + BOD + COD + Cu + Hg + Pb + Se) Not estimated Not estimated 

12. Solid waste 27,991 short tons waste generation avoided Not estimated Not estimated 

Total (1 to 12) = $24,471 

Total annual lifecycle benefits (excluding SOx & excluding mine-filling use) = $22,980 

($474/ton) 

Notes: 

* Physical quantity of environmental benefits are based on only two of the 14 beneficial use industrial applications (i.e., 15.0 million tons per year fly ash CCR used in 

concrete, plus 8.2 million tons per year FGD CCR used in wallboard). These estimates are from Exhibit 5-3 (page 5-6) of gWaste and Materials-Flow Benchmark 

Sector Report: Beneficial Use of Secondary Materials v Coal Combustion Products,h prepared by Industrial Economics Inc for the EPA Office of Solid Waste, 12 Feb 

2008; available at http://www.epa.gov/osw/partnerships/c2p2/pubs/benuse07.pdf. This 2008 reference report does not provide environmental impact estimates for the 

other 12 beneficial use industrial applications. 

** Unit monetary values applied for monetization are from the following sources: 

x Row 1 & Row 2: 2007 values from Exhibit 5-3 (page 5-6) of the Industrial Economics Inc reference report. Unit values updated for this RIA from 2007 to 2009 

using NASA_s Gross Domestic Product Deflator Inflation Calculator at http://cost.jsc.nasa.gov/inflateGDP.html

x Row 3: Based on the September 2009 interim social cost of carbon (i.e., interim SCC) from Table III.H.6-3, page 29617 of the joint EPA and DOT-NHTSA 

gProposed Rulemaking to Establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards,h Federal Register, 

Volume 74, No. 186, 28 Sept 2009. The value applied in this RIA is the $19.50 per ton median value from the $5 to $56 per ton range displayed in the 2007 

column in that source. Furthermore, this RIA updated the 2007$ median value from 2007 to 2009 dollars using the NASA Gross Domestic Product Deflator 

Inflation Calculator at http://cost.jsc.nasa.gov/inflateGDP.html. EPA is aware that final SCC values were published on March 9, 2010 in conjunction with a 

Department of Energy final rule. EPA intends to use the final SCC values for the CCR final rule RIA. The final SCC values are published in the Department of 

Energy, Energy Efficiency & Renewable Energy Building Technologies Program, "Small Electric Motors Final Rule Technical Support Document: Chapter 16 - 

Regulatory Impact Analysis", March 9, 2010 at http://www1.eere.energy.gov/buildings/appliance_standards/commercial/sem_finalrule_tsd.html). 

x Rows 4-10: Unit values from the report gThe Influence of Location, Source, and Emission Type in Estimates of the Human Health Benefits of Reducing a Ton of 

Air Pollutionh by Neal Fann, Charles Fulcher and Bryan Hubbell, in Air Quality, Atmosphere & Health, Volume 2, No.3, Sept 2009, pages 169-176. The dollar 

values from this report were updated from 2006 to 2009 using NASA_s Gross Domestic Product Deflator Inflation Calculator at 

http://cost.jsc.nasa.gov/inflateGDP.html 

x Rows 12-13: Waterborne waste and solid waste generation avoided benefits were not monetized in the 2008 Industrial Economics Inc. reference study cited above. 
157 

5C2. Potential Effect of RCRA Regulation of CCR Disposal on CCR Beneficial Use 

Under the proposed regulation, the Bevill exemption still applies to quantities of CCR directed to certain beneficial uses so that these quantities 

do not face increased disposal costs associated with Subtitle C or D regulation of disposed CCR. The increased costs of disposal of CCR as a 

result of their regulation under RCRA subtitle C will create a strong economic and regulatory incentive for increased beneficial uses of CCR. 

In fact, EPA concludes that the increased costs of disposal of CCR under subtitle C of RCRA, but not the beneficial use of CCR, will actually 

increase their usage in non-regulated beneficial uses, simply as a result of the economics of supply and demand. The economic driver - 

availability of a low-cost, functionally equivalent or often superior substitute for other raw materials - will continue to make CCR an 

increasingly desirable product. Furthermore, it has been EPA_s experience in the RCRA hazardous waste regulations and elsewhere that 

material inevitably flows to less regulated applications. 

On the other hand, industry and state government stakeholders have asserted in letters to EPA, that regulation of CCR as a RCRA ghazardous 

wasteh will impose a gstigmah on CCR beneficial use which will significantly curtail these uses. In their view, even an action that regulates 

only the disposal of CCR in landfills or surface impoundments as hazardous waste, but retains the Bevill exemption for beneficial uses, would 

have this effect. Also, the states particularly have argued that, by operation of state law, the beneficial use of CCR would be prohibited under 

many states_ beneficial use programs, if EPA were to designate CCR as a hazardous waste when disposed. 

The purpose of this section of the RIA is to quantify both possibilities v i.e., an induced increase (Scenario #1) and an induced decrease 

(Scenario #2) -- in future CCR beneficial use, and to explain the basis for this RIA selecting the former (Scenario #1) as the gbase case.h 

x Examples of Hazardous Waste Recycling Success Not “Stigma” 

EPA_s past experiences with the impacts of RCRA regulation, and with how RCRA industrial hazardous wastes and other hazardous materials 

are used and recycled, suggests that a ghazardous wasteh designation of industrial secondary materials and wastes, does not impose a 

significant barrier to its beneficial use (e.g., recycling), and that non-regulated uses generally increase as the costs of regulated disposal 

increase. As summarized below, EPA_s experience has shown that the economic incentive of a high disposal cost has outweighed any 

hypothetical stigma effect in case after case of hazardous waste recycling. Six examples listed below illustrate the point that a RCRA 

ghazardous wasteh designation does not stand in the way of a material_s (or waste_s) subsequent industrial recycling or reuse as a raw or 

intermediate material: 

1. Electric arc furnace dust: RCRA hazardous waste (waste code = K061), and yet it is a highly recycled material. Specifically, between 

2001 and 2007, approximately 42% to 51% of K061 was recycled as evidenced by Biennial Reporting System (BRS) data. Both 

currently and historically, K061 has been used as an ingredient in fertilizer, an input in making steel, and in the production of zinc 

products, including pharmaceutical materials. Slag from the smelting of K061 is in high demand for use in road construction. The use 

of slag is regulated under Pennsylvania_s beneficial use program, despite the fact that it is derived from a listed hazardous waste. In 

fact, there is little doubt that, without its regulation as a hazardous waste, a significantly greater amount of K061 would be diverted 

from recycling to disposal in non-hazardous landfills. 
158 

2. Electroplating wastewater sludge: Listed hazardous waste (F006) that is recycled for its copper, zinc, and nickel content for use in the 

commercial market. In 2007, approximately 35% of F006 material was recycled according to BRS data. These materials are clearly in 

no way stigmatized in the marketplace. 

3. Chat: Superfund cleanup waste with lead contamination is used in road construction in Oklahoma and the surrounding areas. In this 

case, the very waste that has triggered an expensive Superfund cleanup is successfully offered in the marketplace as a raw material in 

road building. The alternative costs of disposal in this case are a significant driver in the beneficial use of this material, and the 

Superfund origin of the material has not prevented its use. 

4. Used oil: Frequently a hazardous waste if disposed of, and is regulated under the RCRA subtitle C standards. While used oil that is 

recycled is subject to a separate set of standards under subtitle C (and is not identified as a hazardous waste), gstigmah does not prevent 

home do-it-yourselfers from collecting used oil, or automotive shops from accepting it and sending it on for recovery. Collected used 

oil may be re-refined, reused, or used as a fuel in boilers, often at the site where it is collected. One large commercial used oil handler 

reports managing 500 million gallons of used oil a year. 

5. Spent etchants: Directly used as ingredients in the production of a copper micronutrient for livestock. 

6. Spent solvents: Generated from metals parts washing are directly used in the production of roofing shingles. 

And in all such cases, these materials are generally RCRA hazardous wastes before reclamation. Many materials widely used in homes today 

can be classified as ghazardoush materials, and many come with warning labels. For example, motor oil comes with warning labels. Gasoline 

would be a characteristic hazardous waste if disposed of, as would many common drain cleaners and household cleaners. Cathode ray tube 

monitors for TVs and computers, as well as many fluorescent lamps are all hazardous wastes if disposed of. Fluorescent lamps (and CFLs) are 

potentially hazardous when disposed of because of mercury. Mercury is an indispensable resource, and virtually all of the mercury used for 

lamps and other uses in the U.S. is derived from discarded mercury or mercury products v that is, from hazardous waste. Even products as 

unlikely as nicotine gum or dental amalgam would be a hazardous waste when disposed of. Consumers are generally comfortable with these 

products, and their regulatory status does not discourage their use. 

x Differing Views About Prospect of Future “Stigma” 

Stakeholders have also expressed the concern that standards-setting organizations might prohibit the use of CCR in specific products or 

materials in their voluntary standards. Recently, the American Standards and Testing Materials (ASTM) International Committee C09, and its 

subcommittee, C09.24, in a December 23, 2009 letter to EPA indicated that ASTM would remove fly ash from the project specifications in its 

concrete standard if EPA determined that CCR were a hazardous waste. However, ASTM standards are developed through an open consensus 

process, and current standards cover the use of numerous hazardous materials in construction and other activities. For example, ASTM 

provides specifications for the reuse of solvents and thus, by implication, does not appear to take issue with the use of these recycled wastes, 

despite their classification as hazardous wastes.137

 

137 For example, see ASTM Volume 15.05, Engine Coolants, Halogenated Organic Solvents and Fire Extinguishing Agents; Industrial and Specialty Chemicals, at or 

ASTM D5396 - 04 Standard Specification for Reclaimed Perchloroethylene. 
159 

Others take a different view on how standard-setting organizations will react. Most notably, a US Green Building Council representative has 

been quoted in the New York Times as saying that LEED incentives for using fly ash in concrete would remain in place, even under an EPA 

hazardous determination. If the Green Building Council (along with EPA) continues to recognize fly ash as an environmentally beneficial 

substitute for Portland cement, EPA believes that the use of this material is unlikely to decrease solely because of gstigmah concerns. 

In addition, Congress directed government agencies to increase their purchase of recycled-content products. Specifically, section 6002 of 

RCRA requires EPA to designate products that can be made with recovered materials and to recommend practices for buying these products. 

Once a product is designated, gprocuring agenciesh 138 are required to purchase it with the highest recovered material content level practicable 

if they spend more than $10,000 a year on that item. EPA_s federal Comprehensive Procurement Guidelines (CPG), requiring the use of fly ash 

in cement for federally funded projects, would remain in place. Thus, any federal, state, or local agency carrying out federally funded 

construction projects would continue to be required to give a preference to fly ash as a Portland cement replacement. 

Finally, many state governments have argued that their statutes or regulations prohibit the use of hazardous wastes in their state beneficial use 

programs, and therefore that, if EPA lists CCR as a hazardous waste (even if only for disposal), their use would be precluded in those states. 

EPA has reviewed the regulations of 10 states with the highest consumption of fly ash and/or cement and concluded that while these states do 

not allow the use of hazardous waste in their beneficial use programs, CCR that are beneficially reused will remain Bevill-exempt solid wastes, 

or in some cases, would not be considered wastes at all and thus, the continued use of CCR under these programs should not be affected by the 

proposed CCR rule. For EPA_s summary of 10 state government CCR beneficial use regulations, see Appendix K12. For the above reasons, 

this RIA presents the increased future CCR beneficial use (Scenario #1) as the gbase case.h However, this RIA monetizes both scenarios (i.e., 

induced increase and induced gstigmah decrease) using the following 10-step method. 

Step 1. Project Future Annual Tonnage CCR Generation 

To estimate the levels of CCR beneficial use, the first task was to project the future annual tonnage of CCR generated by the electric utility 

industry. The amount of CCR is likely to increase proportionally, as utilities comply with new Clean Air Act requirements. Not reflecting this 

proportional increase, this RIA relied on the EIA future forecast for coal burned by the electric utility industry.139 As displayed in Exhibit 5C6 below, the EIA data extends out to the year 2035. However, to remain consistent with the other cost and benefit estimates, this RIA extended 

this trend out to the year 2061 based on regression-fit extrapolation using the following first-order regression of coal burned as dependent 

variable against year as independent variable: 

 

138 Procuring agencies include all federal agencies, and any state or local agency or government contractor that uses appropriated federal funds. 139 Source: Based on 2007 to 2035 annual short tons coal consumption by electric power sector forecast data from the Energy Information Administration (EIA), gYear-byYear Reference Case Tables (2008-2035): Table 15 Coal Supply, Disposition, and Pricesh from the report gAnnual Energy Outlook 2010 Early Release,h December 14, 

2009 at http://www.eia.doe.gov/oiaf/aeo. The EIA report presents a midterm projection and analysis of US energy supply, demand, and prices through 2035, based on the

EIA_s National Energy Modeling System. Further information on the EIA_s projections is available at 
160 

y x E 0  E1

Where: 

y = Tons coal burned at time = x 

ȕ0 = Tons coal burned at time = 0 

ȕ1 = Additional tons coal burned each year, on average 

x = Time elapsed (years) 

Running the regression, calculated a ȕ0 (or intercept) of 1,001,902,312; a ȕ1 (or slope) of 6,082,277; and an R-squared (or fit) of 87%. This 

regression was used to extrapolate the EIA projection out to the year 2061 as displayed in Exhibit 5C-7 and as graphed in Exhibit 5C-8 below. 

Table 5C-6 

Coal Burned Forecast Data From EIA

Year X = Time 

Elapsed 

Y = 

EIA Projection 

(Tons Coal Burned) 

2007 0 1,045,140,137 

2008 1 1,041,599,976 

2009 2 951,846,252 

2010 3 970,887,207 

2011 4 1,025,782,227 

2012 5 1,049,056,519 

2013 6 1,057,912,842 

2014 7 1,069,233,154 

2015 8 1,044,051,880 

2016 9 1,053,579,224 

2017 10 1,052,420,654 

2018 11 1,062,561,646 

2019 12 1,071,914,062 

2020 13 1,073,440,308 

2021 14 1,090,903,931 

2022 15 1,098,539,673 

2023 16 1,102,742,065 

2024 17 1,096,057,129 

2025 18 1,115,724,243 

2026 19 1,111,202,026 

2027 20 1,121,313,477 

2028 21 1,131,518,677 

2029 22 1,128,823,120 

2030 23 1,146,826,782 

2031 24 1,149,894,043 

2032 25 1,160,750,977 

2033 26 1,156,721,802 

2034 27 1,161,479,736 

2035 28 1,182,647,705 
161 

Exhibit 5C-7 

EPA Extrapolation of EIA Projection to 2061 

Year Tons Burned Year Tons Burned 

2007 1,001,902,312 2035 1,172,206,065 

2008 1,007,984,589 2036 1,178,288,342 

2009 1,014,066,866 2037 1,184,370,619 

2010 1,020,149,143 2038 1,190,452,896 

2011 1,026,231,420 2039 1,196,535,173 

2012 1,032,313,697 2040 1,202,617,450 

2013 1,038,395,974 2041 1,208,699,727 

2014 1,044,478,251 2042 1,214,782,003 

2015 1,050,560,527 2043 1,220,864,280 

2016 1,056,642,804 2044 1,226,946,557 

2017 1,062,725,081 2045 1,233,028,834 

2018 1,068,807,358 2046 1,239,111,111 

2019 1,074,889,635 2047 1,245,193,388 

2020 1,080,971,912 2048 1,251,275,665 

Exhibit 5C-7 

EPA Extrapolation of EIA Projection to 2061 

Year Tons Burned Year Tons Burned 

2021 1,087,054,189 2049 1,257,357,942 

2022 1,093,136,466 2050 1,263,440,219 

2023 1,099,218,743 2051 1,269,522,495 

2024 1,105,301,019 2052 1,275,604,772 

2025 1,111,383,296 2053 1,281,687,049 

2026 1,117,465,573 2054 1,287,769,326 

2027 1,123,547,850 2055 1,293,851,603 

2028 1,129,630,127 2056 1,299,933,880 

2029 1,135,712,404 2057 1,306,016,157 

2030 1,141,794,681 2058 1,312,098,434 

2031 1,147,876,958 2059 1,318,180,710 

2032 1,153,959,235 2060 1,324,262,987 

2033 1,160,041,511 2061 1,330,345,264 

2034 1,166,123,788 Total 64,136,808,356 
162 

Exhibit 5C-8 

Extending EIA Projections

900,000,000

950,000,000

1,000,000,000

1,050,000,000

1,100,000,000

1,150,000,000

1,200,000,000

1,250,000,000

1,300,000,000

1,350,000,000

1,400,000,000

2007 2012 2017 2022 2027 2032 2037 2042 2047 2052 2057

Year

Coal Burned (Tons)

EIA Projection EPA Regression
163 

Based on the most recent CCR beneficial use data from ACAA, EPA estimated the average tons of CCR generated for every ton of coal burned 

by electric utility plants. For this calculation, this RIA only used the most recent data year (2008) to estimate a conversion rate because over 

time, the quantities of CCR generated per ton of coal combusted has steadily increased. Thus an average of recent years would not reflect this 

trend. The steady increase over time is due to tightening of industrial air pollution regulations. This trend would likely continue in the future 

as further facilities undergo new source review, or implement new Clean Air Act requirements under upcoming EPA rules like the Clean Air 

Interstate Rule (CAIR) and the Clean Air Mercury Rule (CAMR). Thus, the future annual tonnages of CCR estimated in this RIA are likely 

under-estimates. Dividing the 2008 tons of CCR generated (136 million tons) by the 2008 tons of coal burned by the electric power sector 

(1,042 million tons), EPA produced a CCR-to-coal relationship factor of 0.131. Applying this factor to the extrapolated coal consumption 

projection produced the future CCR generation scenario displayed below in Exhibit 5C-9. 

Exhibit 5C-9 

Projected Future Annual CCR Generation by the Electric Utility Industry: 

Scenario Based on Extrapolation of EIA’s Projection of Electric Power Sector Coal Burned 2007-2035 

(Short Tons) 

Year CCR Year CCR Year CCR Year CCR 

2012 134,764,862 2025 145,087,115 2038 155,409,369 2051 165,731,622 

2013 135,558,881 2026 145,881,135 2039 156,203,388 2052 166,525,642 

2014 136,352,901 2027 146,675,154 2040 156,997,408 2053 167,319,661 

2015 137,146,920 2028 147,469,174 2041 157,791,427 2054 168,113,681 

2016 137,940,940 2029 148,263,193 2042 158,585,447 2055 168,907,700 

2017 138,734,959 2030 149,057,213 2043 159,379,466 2056 169,701,720 

2018 139,528,979 2031 149,851,232 2044 160,173,486 2057 170,495,739 

2019 140,322,998 2032 150,645,252 2045 160,967,505 2058 171,289,759 

2020 141,117,018 2033 151,439,271 2046 161,761,525 2059 172,083,778 

2021 141,911,037 2034 152,233,291 2047 162,555,544 2060 172,877,798 

2022 142,705,057 2035 153,027,310 2048 163,349,564 2061 173,671,817 

2023 143,499,076 2036 153,821,330 2049 164,143,583 

2024 144,293,096 2037 154,615,349 2050 164,937,603 

Appendix K5 to this RIA presents alternative estimates of future CCR generation. These estimates take into account the recent increasing 

trend in the ratio of tons CCR generated to the tons coal combustion. For example, in year 2035 the constant ratio projection above yields a 

value of 153 million tons CCR generated whereas the increasing ratio projection in Appendix K5 yields a value of 191 million tons of CCR 

generated. While the exact magnitude of such an increase is uncertain, there would be at least some increase as a result of increased air 

pollution controls. These include future changes due to EPA_s New Source Review (NSR), EPA_s Clean Air Interstate Rule (CAIR), and 

EPA_s Clean Air Mercury Rule (CAMR).
164 

Step 2. Project Future Baseline Annual Tonnage CCR Beneficial Use (Without RCRA Regulation) 

This step involves projecting the extent to which CCR would be beneficially used in the absence of the proposed RCRA regulation of CCR 

disposal (i.e., future baseline CCR beneficial use). Exhibit 5C-10 below displays the recent (i.e., 2001 to 2008) trend in annual tonnage of 

CCR beneficial use, and as a percentage relative to annual CCR generation by the electric utility industry. 

Exhibit 5C-10 

Recent CCR Beneficial Use Trend (2001-2008) 

Year CCR Generation 

(short tons) 

CCR Beneficial Use 

(short tons) Fraction 

2001 117,930,542 37,119,321 31.5% 

2002 128,703,572 45,523,256 35.4% 

2003 121,744,571 46,384,405 38.1% 

2004 122,465,119 49,089,818 40.1% 

2005 123,126,093 49,612,541 40.3% 

2006 124,795,124 54,203,170 43.4% 

2007 131,127,693 56,039,005 42.7% 

2008 136,073,107 60,593,660 44.5% 

Source: American Coal Ash Association (ACAA) at 

http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=3 

If the recent trends in CCR generation and CCR beneficial use continued in a linear fashion, more than 100% of CCR would be beneficially 

used before year 2061. Furthermore, a linear extrapolation for beneficial use would not be appropriate because as more and more CCR is used, 

it would likely become increasingly difficult to use the remaining CCR due to saturation of local markets, competition between CCR 

generators, and other factors, depending on overall macro-economic factors. Thus, for purpose of extrapolation to the 50-year period-ofanalysis (2012 to 2061), this RIA instead modeled the recent trend data as an asymptotic, exponential function of the form: 

*( )

1 1 C X D B

Y  

Where: 

Y = Percent of CCR beneficially used 

X = Time elapsed relative to 2001 

B = 1.021 

C = 1.369 

D = 13.99 
165 

Beneficial uses of CCR have been consistently growing in the recent past. Since the percent of CCR beneficially used has been growing, EPA 

sought to characterize that trend so that the future percent beneficially used could be applied to the future tons of CCR. The ACAA data from 

2001 to 2008 indicate that this trend was increasing. After running several regressions, EPA disposed of the typical trend fits for various 

reasons. A first-order (linear) trend line was abandoned because it would have led to beneficial use above 100% well within the time-frame of 

the analysis. Higher order regressions led to oddities where beneficial use would trend away from 100% at some point in time. Once typical 

fits were ruled out, EPA assumed that CCR beneficial use would not exceed 100% of CCR generated.140 Instead, it would potentially become 

more and more difficult to use CCR as a higher percent went to beneficial uses, because of market limitations. Thus, it made sense to use an 

exponential curve that approached, but never crossed an asymptote of 100% beneficial use. 

To fit an exponential curve to the 2001 to 2008 CCR beneficial use data, a spreadsheet calculation solver was programmed to minimize the 

residual sum of squares between the actual and projected percent of CCR beneficial use by changing the regression equation variables B, C, 

and D. From solver result, B was set to 1.021, C was set to 1.369, and D was set to 13.99. Using these values, the future CCR beneficial use 

projection as measured on a percentage basis relative to CCR generation were estimated, as displayed in Exhibit 5C-11 and Exhibit 5C-12

below. The percentage of CCR beneficially used under the baseline (i.e., without RCRA regulation) is expected to gradually approach, but 

never reach 100% of CCR generation. By 2061 at the end of the 50-year period-of-analysis, 88% of CCR would be beneficially used under this 

projection. While this is a relatively high number, current experiences in at least one US state and in at least 16 other countries (i.e., 15 

European countries + Japan), already demonstrate that very high CCR beneficial use rates of 90% and above are achievable: 

1. Wisconsin: Several companies are developing technologies to convert CCR into bricks used in construction, and one such technology 

was recently commercialized in Wisconsin.141 Some of these technologies have the potential for using 100% CCR (fly ash) in brick 

production, as opposed to the conventional 30%-50% limit for replacing Portland cement in concrete. 

2. Europe: As of 2007, 15 European countries reported a CCR beneficial use rate of 89% (i.e., 55.449 million metric tons beneficially 

used in 2007 in 24 industrial applications, out of the 62.094 million metric tons generated in 2007).142

3. Japan: As of 2006, Japan reported a CCR beneficial use rate of 97% (i.e., 10.657 million tons used in Japan in 2006 for 3 cement 

applications, 6 civil engineering applications, 3 construction applications, 2 agriculture/forestry/fisheries applications, and at least three 

other miscellaneous applications, out of the 10.969 million tons CCR generated in Japan in 2006).143

 

140 The fact that some electric utility plants currently excavate previously disposed CCR for supplying to beneficial use markets suggests this may be a limiting assumption 

which could underestimate future potential growth of CCR beneficial use. For example, one electric utility company reported a 106% CCR beneficial use rate in 2006 for 

its four electricity plants because it recovered CCR that it had previously disposed. 141 Source: gCalStar Gives Sneak Peek of Low-Carbon Brick Factory,h Cleantech Group, 27 Oct 2009 at http://cleantech.com/news/5217/calstar-flyash-low-carbon-brick 142 Source: Europe_s 2007 CCR beneficial use rate is reported by ECOBA (European Coal Combustion Products Association) which was founded in 1990 by European 

energy producers to deal with matters related to the usage of construction raw materials from coal. As of 2009, membership in ECOBA consists of 24 companies and 

associations from 15 countries in Europe, all generators of electricity and heat. ECOBA members represent over 86 % of total CCR generation by the 27 total European 

countries. ECOBA_s 15 member countries are Belgium, Denmark, Finland, France, Germany, Greece, Ireland, Italy, Netherlands, Poland, Portugal, Romania, Russia, 

Spain, and United Kingdom. ECOBA_s 2007 CCR beneficial use rate is reported in gProduction and Utilisation of CCPs in 2007 in Europe (EU 15)h at: 

http://www.ecoba.com/evjm,media/statistics/ECOBA_Stat_2007_EU15.pdf 143 Source: Japan_s 2006 CCR beneficial use rate is reported by the Japan Coal Energy Center (JCOAL) in Table 3-1 of gStatus of Coal Ash Productionh at: 

http://www.jcoal.or.jp/coaltech_en/coalash/ash01e.html
166 

Exhibit 5C-11 

Projected Future Baseline CCR Beneficial Use Measured as Percentage of CCR Generation 

Year % Beneficial Use Year % Beneficial Use Year % Beneficial Use Year % Beneficial Use 

2001 33.22% 2016 56.67% 2031 71.89% 2046 81.76% 

2002 35.11% 2017 57.91% 2032 72.69% 2047 82.28% 

2003 36.96% 2018 59.10% 2033 73.47% 2048 82.79% 

2004 38.75% 2019 60.27% 2034 74.22% 2049 83.28% 

2005 40.49% 2020 61.39% 2035 74.95% 2050 83.75% 

2006 42.19% 2021 62.49% 2036 75.67% 2051 84.21% 

2007 43.83% 2022 63.56% 2037 76.36% 2052 84.66% 

2008 45.43% 2023 64.60% 2038 77.03% 2053 85.10% 

2009 46.98% 2024 65.60% 2039 77.68% 2054 85.52% 

2010 48.49% 2025 66.58% 2040 78.32% 2055 85.93% 

2011 49.95% 2026 67.53% 2041 78.94% 2056 86.33% 

2012 51.37% 2027 68.45% 2042 79.53% 2057 86.72% 

2013 52.76% 2028 69.35% 2043 80.12% 2058 87.10% 

2014 54.10% 2029 70.22% 2044 80.68% 2059 87.47% 

2015 55.41% 2030 71.07% 2045 81.23% 2060 87.82% 

 2061 88.17% 

 Japan_s 17 types of CCR beneficial use applications are listed for year 2003 in Table 1 gBreakdown of Fields for the Effective Use of Coal Ashh from gPart 2 CCT 

Overview Environmental Protection Technologies (Technologies to Effectively Use Coal Ash): 5C1. Coal Ash Generation Process and Application Fieldsh at 

http://www.brain-c-jcoal.info/cctinjapan-files/english/2_5C1.pdf 
167 

Exhibit 5C-12 

Beneficial Use Trend

0.00%

10.00%

20.00%

30.00%

40.00%

50.00%

60.00%

70.00%

80.00%

90.00%

100.00%

2001 2006 2011 2016 2021 2026 2031 2036 2041 2046 2051 2056 2061

Year

Beneficial Use (%)

Actual Projected
168 

Applying the percent of CCR beneficially used in each year to the quantities of CCR shown above, the following future annual tons of 

beneficially used CCR may be expected as displayed below in Exhibit 5C-13. The monetized value of this future baseline projection is: 

PV @3% discount PV @7% discount

Economic value: $102,290 million PV $51,170 million PV 

Lifecycle social value: $1,554,323 million PV $777,541 million PV 

Exhibit 5C-13 

Baseline Projected Future CCR Beneficial Use 

(Short Tons) 

Year CCR Beneficial Use Year CCR Beneficial Use Year CCR Beneficial Use Year CCR Beneficial Use 

2012 69,234,181 2025 96,599,301 2038 119,713,602 2051 139,569,037 

2013 71,516,427 2026 98,514,244 2039 121,345,430 2052 140,985,202 

2014 73,767,022 2027 100,404,645 2040 122,958,473 2053 142,387,139 

2015 75,986,563 2028 102,270,993 2041 124,553,122 2054 143,775,155 

2016 78,175,638 2029 104,113,770 2042 126,129,762 2055 145,149,549 

2017 80,334,827 2030 105,933,448 2043 127,688,769 2056 146,510,616 

2018 82,464,703 2031 107,730,494 2044 129,230,513 2057 147,858,644 

2019 84,565,827 2032 109,505,366 2045 130,755,358 2058 149,193,918 

2020 86,638,755 2033 111,258,513 2046 132,263,659 2059 150,516,713 

2021 88,684,034 2034 112,990,378 2047 133,755,767 2060 151,827,302 

2022 90,702,202 2035 114,701,396 2048 135,232,025 2061 153,125,952 

2023 92,693,789 2036 116,391,994 2049 136,692,770 

2024 94,659,318 2037 118,062,592 2050 138,138,332 

Step 3. Estimate Potential Induced Effect of RCRA Regulation on CCR Beneficial Use 

After establishing a future baseline of CCR beneficial use annual tonnage, this step involved formulating three alternative scenarios whereby 

future CCR beneficial use under RCRA regulation of CCR disposal could either: 

o Scenario #1: Increase in beneficial use 

o Scenario #2: Decrease 

o Scenario #3: Remain unchanged from baseline 
169 

Increases due to increased disposal costs were estimated first and constitute the gbase caseh of this RIA. By increasing disposal costs, electric 

utility plants face an gavoided disposal cost incentiveh to ship their CCR farther for beneficial uses by other industries; that is, utilities would be 

willing to pay more transportation costs to avoid the higher disposal costs. Thus, RCRA regulation of CCR disposal would likely open new 

markets at farther transport distances, or increase purchases by existing markets. The effect of this stimulus would be to increase CCR 

beneficial use. The concept of gavoided disposal cost incentiveh is recognized and defined by the American Coal Ash Association (ACAA) on 

its website as follows: 

gIf a [coal-fired electric utility] plant markets its [CCR] into commercial applications, then disposal of this [CCR] is not 

required. Not only is a revenue stream created for the [coal-fired electricity plant] but also the need to dispose of the [CCR] is 

avoided. As discussed above, disposal is not just the transportation and placement of [CCR] in a disposal site. The need for 

future space is a concern. If [CCR is] marketed, then the need to develop future [CCR disposal] sites (including land 

acquisition, permitting, design and construction costs) is avoided .... It is not uncommon for a company to help offset the costs 

of transportation or placement at construction sites by providing the contractor or trucking firm a payment of some sort. For 

example, if the cost of disposal at a plant is normally four dollars a ton, then the company may arrange a payment of four 

dollars or less to the contractors to cover transportation and placement costs. The difference between the amount of this 

payment and the cost of disposal is also referred to as “avoided disposal costs.h Source: ACAA Frequently Asked Question nr. 

14 webpage at: http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=5#Q14 

On the other hand, some stakeholders have claimed that a Subtitle C ghazardous wasteh approach would have a gstigmah effect on CCR, 

reducing their use. That is, due to the label of ghazardous waste,h some purchasers of CCR might opt to turn down the CCR for more 

expensive substitutes in fear that the CCR might either harm their sales or create liability, and generators might be reluctant to provide the 

material to users because of liability concerns. The final alternative, that beneficial use quantities remain the same, results in no net costs or 

benefits for the Subtitle C approach because it is assumed that the baseline trend plays out the same as it would absent a rule. Thus, no further 

analysis of this option was necessary. 

The two alternative Scenario analyses (i.e., Scenario #1, Scenario #2) in this section build upon the ACAA_s historical CCR beneficial use 

data.144 ACAA data on the beneficial use was modified to remove the use of CCR in minefilling applications because the proposed rule does 

not address minefilling operations. Excluding 100% of the ACAA reported quantity of CCR used in minefilling results in a reduction of 1.13 

million tons per year in the amount beneficially used. As a result, the 2005 quantity of beneficial use relied upon for our analyses is 48.5 

million tons per year of CCR, rather than the original 49.6 million tons per year reported by ACAA. 

 

144 Source: Historical CCR beneficial use data from the American Coal Ash Association (ACAA) gCoal Combustion Products -- Production & Use Statisticsh webpage at: 

http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=3 
170 

Step 4: Estimate Potential Induced Increase in Future CCR Beneficial Use (Scenario #1) 

Under the assumptions and numerical framework described below, this RIA estimates that the Subtitle C option would initially induce an 

increase of 28% in CCR beneficial uses. This growth estimate is a generalized, aggregate estimate across all 15 existing CCR beneficial use 

markets. Due to a lack of available data (i.e., market location, elasticity, cross-elasticity, etc.), this estimate does not take into account unique 

economic supply or economic demand conditions in any single market or for any particular beneficial use, relative to the generalized aggregate 

estimate. However, key uses, such as use of fly ash as a Portland cement replacement, have great opportunity for increased use, far above 28% 

in the initial year. For example, if fly ash use in concrete increased to a 30% replacement rate for Portland cement (a very reasonable 

replacement rate, consistent with current specifications), fly ash usage could increase by more than 100% from the 14 million tons used 

annually at current replacement rates of 10% to 12%. One of the main barriers to this increase usage is transportation costs. Because EPA did 

not have specific data on this market, this RIA does not specifically quantify it; however, it is exactly the type of use that increased disposal 

costs could foster. 

The method presented below may be characterized as a "Raw Material Cost Method" which represents the 1st stage of the generalized 4-stage 

materials flow lifecycle (MFL) through the economy. This 4-stage MFL conceptual framework has been integrated into existing cost modeling 

software systems145 used by government agencies and the private sector, and consists of the following four material flow cradle-to-grave or 

cradle-to-cradle stages: 

1st MFL stage: Raw materials acquisition 

2nd MFL stage: Product manufacturing 

3rd MFL stage: Product use, re-use, maintenance 

4th MFL stage: Recycling, waste management 

This method evaluates the difference in raw material acquisition cost under two alternative conditions. The first condition (Baseline) represents 

current conditions without RCRA regulation of CCR disposal. The second condition (Subtitle C) represents future conditions with RCRA 

regulation for CCR disposed by electric utilities. 

The economic mechanism in this estimation method, which affects different raw material acquisition costs under the two alternative conditions, 

is the gavoided disposal cost incentiveh described above. In other words, it is the avoided disposal cost under RCRA regulation compared to 

the industry_s baseline disposal cost. This difference in cost is an incremental cost relative to baseline. From an economic standpoint, this 

represents an incremental economic incentive to electric utility plants to reduce or eliminate CCR disposal, thereby reducing or avoiding new 

regulatory compliance costs by increasing their future annual supply of CCR to beneficial use markets. This gavoided disposal cost incentiveh 

induced by RCRA regulation has already been anticipated in 2009 by at least one CCR beneficial use industry (bold face added for emphasis): 

 

145 Example cost modeling/estimation software systems using this 4-stage framework are 1. FAST, 2. EE Energy/ Environment Life-Cycle Assessments, 3. EPA Enviro 

Accounting Method, and 4. TEAM (Tools for Environmental Analysis and Mangement); source: gTable 3-1. Overview of Life-Cycle Stages and Costs Considered by 

Software Systems and Toolsh at http://www.p2pays.org/ref/01/00047/00047e.htm 
171 

gUsing [coal] fly ash in building materials is nothing new, as it’s already incorporated in products including Portland cement 

and asphalt concrete. However, it’s estimated that 65 percent of fly ash from coal-fired power plants worldwide goes to 

landfills, with the U.S. reporting a slightly lower 57 percent, according to the American Coal Ash Association. Kane said the 

key to CalStar’s products is that they offer the same performance as aesthetics as traditional bricks, but without the energy use. 

Currently, the cost to buy a ton of fly ash in the U.S. ranges from about $5 to $30, but that could change as fly ash disposal 

faces tighter government restrictions, he said. “The cost to send fly ash to landfills will go up, and utilities will be faced with 

finding the most beneficial use,” Kane said.h146

The baseline average graw material acquisition costh is $94.50/ton, consisting of CCR price, CCR disposal cost, and CCR transportation cost: 

1. CCR price: Price paid to electric utility plants by beneficial use industries for the purchase of CCR. ACAA identifies 15 industrial 

beneficial use markets involving the beneficial use of CCR, many of which involve the construction industry.147 The average price paid 

by these industries to electric utility plants is $3.00 per ton, across a reported range of $0 to $45 per ton.148

2. CCR disposal cost: Cost to the electric utility industry for disposing CCR. This factor also represents the gavoided disposal cost 

incentiveh in the sense that this is an gavoided costh to the electric utility industry for CCR tonnages beneficially used by other 

industries. A unitized gtotal costh ($ per ton) for CCR disposal consisting of both a 50-year amortized capital cost for CCR disposal 

units plus a 50-year amortized O&M costs for CCR disposal is used to monetize this cost factor.149 The average baseline CCR disposal 

cost is $59/ton (source: Exhibit 3L). This is additive to the gCCR priceh element because it represents a subsidy by electricity plants. 

3. CCR transport cost: Average one-way CCR transport distance between electric utility plants and their CCR beneficial use customer 

industries. This method does not explicitly distinguish whether the transport cost is paid by the electric utility plants or by the 

beneficial use industries.150 Average CCR transport cost from electric utility plants to beneficial use sites is estimated at 

($0.26/mile/ton)151 x (125 miles)152 = $32.50/ton. 

 

146 Source: Cleantech Group, gCalStar Gives Sneak Peek of Low-Carbon Brick Factory,h 29 Oct 2009 at http://cleantech.com/news/5217/calstar-flyash-low-carbon-brick 147 ACAA lists 15 beneficial use markets: concrete, cement, flowable fill, structural fill/embankments, road base/sub-base, soil modification, mineral filler in asphalt, 

snow/ice control, blasting grit/roofing granules, mining applications, gypsum panel products, waste stabilization/solidification, agriculture, construction aggregate, and 

miscellaneous uses. 

148 $3 per-ton CCR price is from Column E of Exhibit 5C-1; this price represents the tonnage-weighted average across a reported price range of $0 to $45 per ton CCR. 149 Although in the short-run (< 3 years), marginal business decisions may be made relative to short-term O&M costs, long-term (> 3 years) business decisions usually 

consider both amortized capital costs and O&M costs. 150 The CCR price data used to monetize the CCR price factor above are reportedly based on gFOBh prices which may include some portion of transport cost (e.g., transport 

vehicle loading to a trans-shipment location). 151 $0.26 per-ton-per-mile is the midpoint of the $0.15 to $0.37 per-ton-per-mile range reported in gEstimation of the Marginal Greenhouse Gas Abatement Curve for the 

Beneficial Use of Fly Ash as a Substitute for Portland Cement in Ready-Mix Concrete Production,h EPA Office of Resource Conservation and Recovery (ORCR), 19 June 

2009, page 11. 

152 125 miles is the midpoint of the 100 to 150 mile range reported in footnote 74 on page 4-8 of EPA_s 03 June 2008 gReport to Congress: Study on Increasing the Usage 

of Recovered Mineral Components in Federal Funded Projects Involving Procurement of Cement or Concrete to Address the Safe, Accountable, Flexible, Efficient 

Transportation, Equity Act: A Legacy for Uses by the EPA, the Department of Transportation (DOT) and the Department of Energy (DOE),h report nr. EPA530-R-08-007, 

available at http://www.epa.gov/waste/conserve/tools/cpg/products/cement2.htm. 
172 

In comparison to these baseline graw materials acquisition costh elements, CCR disposal costs are estimated to be $83/ton for the Subtitle C 

option (source: Exhibit 4K). While this represents a 44% increase ($26/ton) over the baseline disposal cost of $59/ton, this ignores the CCR 

price and the transportation cost elements. Factoring these components in, the $26/ton increase represents a 28% increase above the total 

baseline raw material cost of $94.50/ton. This RIA applies this 28% growth factor to represent demand elasticity153 assumptions of: 

+0.64 with respect to the CCR gavoided disposal cost incentiveh factor (i.e., +28%/+44%). 

+1.00 with respect to total graw material acquisition costh consisting of all three cost factors included (i.e., +28%/+28%). 

This RIA applies the elasticity estimate of 1.0 in reference to the graw material acquisition costh to represent the potential increase in CCR 

beneficial use by 28% over the baseline under the Subtitle C option. The other regulatory options are proportionately adjusted below. In 

comparison to historical annual percentage changes in CCR beneficial use tonnages, this 28% increase is a reasonable assumption as it falls 

between the -22.6% decrease and +55.2% increase min-max range (annual mean = +8.2% increase) over the 43 year period 1966 to 2008,154 as 

displayed in Exhibit 5C-14 below. 

Exhibit 5C-14 

Historical Annual Percentage Change in CCR Beneficial Use (1966-2008) 

A B C D E F (E/C) G 

Item Year 

CCR generation 

(tons) 

CCR disposal 

(tons) 

CCR beneficial 

use (tons) 

Percent CCR 

beneficial use 

Annual % change in 

CCR beneficial use tons 

1 1966 26,000,000 22,000,000 4,000,000 15% 

2 1967 28,000,000 23,000,000 5,000,000 18% 25.0% 

3 1968 30,000,000 24,000,000 6,000,000 20% 20.0% 

4 1969 31,500,000 26,000,000 5,500,000 17% -8.3% 

5 1970 39,000,000 33,200,000 5,800,000 15% 5.5% 

6 1971 41,500,000 32,500,000 9,000,000 22% 55.2% 

7 1972 46,000,000 38,000,000 8,000,000 17% -11.1% 

8 1973 50,000,000 41,500,000 8,500,000 17% 6.3% 

9 1974 59,000,000 50,000,000 9,000,000 15% 5.9% 

10 1975 60,000,000 50,000,000 10,000,000 17% 11.1% 

11 1976 62,000,000 50,000,000 12,000,000 19% 20.0% 

12 1977 67,000,000 53,000,000 14,000,000 21% 16.7% 

13 1978 68,000,000 52,000,000 16,000,000 24% 14.3% 

14 1979 75,500,000 60,000,000 15,500,000 21% -3.1% 

15 1980 66,000,000 54,000,000 12,000,000 18% -22.6% 

16 1981 68,000,000 51,500,000 16,500,000 24% 37.5% 

 

153 In economics, the elasticity of supply indicates the responsiveness of the quantity of a product or service supplied to the market relative to a change in its price (i.e., (% 

change in quantity supplied) / (% change in its price)). Similarly, the elasticity of demand indicates the responsiveness of the quantity of market demand for a product or 

service relative to a change in its price (i.e., (% change in quantity demanded) / (% change in its price)). 154 Historical CCR beneficial use data for 1966-2008 from ACAA at http://www.acaa-usa.org/associations/8003/files/Revised_1966_2007_CCP_Prod_v_Use_Chart.pdf 
173 

Exhibit 5C-14 

Historical Annual Percentage Change in CCR Beneficial Use (1966-2008) 

A B C D E F (E/C) G 

Item Year 

CCR generation 

(tons) 

CCR disposal 

(tons) 

CCR beneficial 

use (tons) 

Percent CCR 

beneficial use 

Annual % change in 

CCR beneficial use tons 

17 1982 65,000,000 51,000,000 14,000,000 22% -15.2% 

18 1983 64,000,000 51,000,000 13,000,000 20% -7.1% 

19 1984 69,000,000 53,000,000 16,000,000 23% 23.1% 

20 1985 66,000,000 48,000,000 18,000,000 27% 12.5% 

21 1986 67,500,000 53,000,000 14,500,000 21% -19.4% 

22 1987 82,000,000 63,000,000 19,000,000 23% 31.0% 

23 1988 83,000,000 62,500,000 20,500,000 25% 7.9% 

24 1989 87,000,000 69,500,000 17,500,000 20% -14.6% 

25 1990 86,000,000 64,000,000 22,000,000 26% 25.7% 

26 1991 88,000,000 65,500,000 22,500,000 26% 2.3% 

27 1992 82,000,000 62,000,000 20,000,000 24% -11.1% 

28 1993 88,000,000 69,000,000 19,000,000 22% -5.0% 

29 1994 89,000,000 66,000,000 23,000,000 26% 21.1% 

30 1995 92,000,000 68,000,000 24,000,000 26% 4.3% 

31 1996 102,000,000 76,000,000 26,000,000 25% 8.3% 

32 1997 104,000,000 74,500,000 29,500,000 28% 13.5% 

33 1998 108,000,000 77,000,000 31,000,000 29% 5.1% 

34 1999 107,000,000 74,000,000 33,000,000 31% 6.5% 

35 2000 108,500,000 76,500,000 32,000,000 29% -3.0% 

36 2001 117,930,542 80,811,221 37,119,321 31% 16.0% 

37 2002 128,703,572 83,180,316 45,523,256 35% 22.6% 

38 2003 121,744,571 75,360,166 46,384,405 38% 1.9% 

39 2004 122,465,119 73,375,301 49,089,818 40% 5.8% 

40 2005 123,126,093 73,513,552 49,612,541 40% 1.1% 

41 2006 124,795,124 70,591,954 54,203,170 43% 9.3% 

42 2007 131,127,693 75,088,688 56,039,005 43% 3.4% 

43 2008 136,073,107 75,479,447 60,593,660 45% 8.1% 

 Minimum annual %= -22.6% 

 Maximum annual % = 55.2% 

 Median annual % = 6.4% 

Mean annual % = 8.2% 

Overall percent growth = 1414.8% 

Average annual compound growth = 6.5% 
174 

This is a limiting analysis because it does not include other developments that may be expected increasingly to push CCR to beneficial use: 

1. Aspects of the proposed CCR rule: This analysis does not take into account that some RCRA regulatory options for CCR disposal 

require electricity plants to move to dry management of CCR, either through changes to air pollution control strategies or through 

drying of CCR after they have been generated. This will make the material more amenable to beneficial uses. 

2. The analysis is based on current market conditions: It does not take into account new technologies and products now being developed, 

for example, involving the use of CCR in brick construction.155 An increased gavoided disposal cost incentiveh could be a great boon 

to such new beneficial use technologies, applications, and products. 

x Comparison of “Raw Materials Acquisition Cost Method” to “Travel Cost Method” 

The method applied above involved three cost components of the graw material acquisition cost,h not just in relation to the transportation cost 

component, which is relatively narrower approach that can be called a gTransportation Cost Method.h Compared to this other method, the raw 

material acquisition cost method provides a smaller estimate of effect because the incremental cost is evaluated relative to a broader set of costs 

thereby translating numerically into a smaller percentage change, rather than relative to only one cost factor which would translate into a 

relatively larger percentage change. This methodological difference may be illustrated by using the calculation numbers applied above, to only 

the transportation cost factor. Using a simplistic transportation distance model which uses the CCR disposal unit cost ($ per ton) to determine 

the average circular radius of a CCR transportation market between electricity utility plant suppliers of CCR and their beneficial users 

customers, the increase in transport distance would be calculated as follows (relative to the 2005 49.6 million tons CCR beneficially used as 

reported by the ACAA): 

x Baseline transportation cost (without CCR rule) 

($0.26/mile/ton) x (125 miles one-way average CCR transport distance) x (49.6 million tons/year beneficial use in 2005) = $1,612 

million/year transport cost 

x Hypothetical new transportation cost (with rule) 

Transport subsidy equivalency = ($85/ton avoided disposal cost under rule) v ($59/ton avoided disposal cost without rule) = $26/ton 

subsidy equivalency 

(49.6 million tons/year beneficial use) x ($26/ton subsidy equivalency) = $1,290 million per year subsidy equivalency 

x Hypothetical new transport distance: 

[($1,612 million/year) + ($1,290 million/year)] / (49.6 million tons per year beneficial use) / ($0.26/mile/ton) = 225 miles 

Percentage increase in transport distance: 

[(225 miles) v (125 miles)] / (125 miles) = 80% increase in radial transport distance 

 

155 Several companies are developing technologies to convert CCR into bricks used in construction, and one such technology was recently commercialized at a power plant 

in Wisconsin. Some of these technologies have the potential for using 100% CCR (fly ash) in brick production, as opposed to the conventional 30%-50% limit for 

replacing Portland cement in concrete. 
175 

x Hypothetical expansion of CCR customer delivery area: 

Baseline customer area @125 miles radial transport distance = (3.1415 x (125 miles)^2) = 49,100 square miles 

Expanded customer area @225 miles radial transport distance = (3.1415 x (225 miles)^2) = 159,000 square miles 

Incremental increase in customer area = (159,000 v 49,100 sq. miles) / (49,100 sq.miles) = 124% increase in delivery area 

Step 5: Estimate Hypothetical “Stigma” Decrease in Future CCR Beneficial Use (Scenario #2) 

A number of industry and state government stakeholders have asserted to the EPA, that designating CCR as a hazardous waste (even if the 

designation is only applicable to those CCR that are disposed of) would create a gstigmah that would reduce or curtail or eliminate the 

beneficial use of CCR. This RIA presents an alternative stigma effect scenario in an effort to evaluate what countervailing impact that 

gstigmah may have on the increased beneficial use of CCR estimated in this RIA above. This potential reduction scenario assumes different 

potential impacts in three categories of beneficial CCR usage (uses covered in the CPGs, consolidated uses, and unconsolidated uses). For 

documentation of the calculations discussed in this section, see Appendix K13. 

x “Stigma” on CCR in Consolidated Uses Specified in Comprehensive Procurement Guidelines 

First, some uses for CCR involve the production of specific products that are expressly covered by the federal Comprehensive Procurement 

Guidelines (CPGs), which require procuring agencies that spend more than $10,000 a year on an item to buy products containing recovered 

materials. Procuring agencies are federal, state, and local agencies, and their contractors, that use appropriated federal funds. For example, if a 

county agency spends more than $10,000 a year on an EPA-designated item and part of that money is from appropriated federal funds, then the 

agency must purchase that item made from recovered materials.156 As such, if there were any impacts due to stigma, EPA believes that the 

markets for these uses are less likely to be affected by a hazardous waste label for CCR. CCR categories currently covered under the CPGs 

include concrete/concrete products/grout, flowable fill, and blasting grit/roofing granules. 

According to U.S. Census data, the public portion of total construction spending equaled 20.7% in 2005, 21.4% in 2006, 24.6% in 2007, and 

had swelled to 35.4% by Nov. 2009 (likely in direct relationship to the current state of the economy and current federal stimulus spending). 

Similarly, U.S. EPA (2008d) estimates that for concrete projects, the cement demand attributable to federal concrete projects reflects 

approximately 20% of the annual total demand. EPA then apportioned the amounts of CCR usage into a public construction vs. a private 

construction split. Based on the Census Bureau and EPA data,157 EPA established a 25% / 75% split of the totals for these products, such that 

25% of the total usage is recognized as accruing to public construction and 75 % to private construction. 

 

156 Agencies may elect not to purchase designated items when the cost is unreasonable; inadequate competition exists; items are not available within a reasonable period of 

time; or items do not meet the agency's reasonable performance specifications. 157 Source: EPA gReport to Congress: Study on Increasing the Usage of Recovered Mineral Components in Federal Funded Projects Involving Procurement of Cement or 

Concrete to Address the Safe, Accountable, Flexible, Efficient Transportation, Equity Act: A Legacy for Uses by the EPA, the Department of Transportation (DOT) and the 

Department of Energy (DOE),h EPA530-R-08-007, June 3, 2008 at: http://www.epa.gov/waste/conserve/tools/cpg/products/cement2.htm
176 

Given that the public procurement of these products should continue because of their CPG designation, this RIA assumed that there will be no 

negative impact on the public portion of CCR usage. That is, the demand for CPG products made from CCR will be the same as it currently is 

for the public portion of the construction market. However, this RIA assumes a 50% reduction of total private uses.158 This results in an 

estimated 6.8 million tons per year reduction in CCR use for this category of beneficial uses. 

x “Stigma” for CCR in Other Consolidated Uses 

Not all consolidated uses of CCR are covered under federal CPGs. Thus, this scenario also estimated the potential impacts on the use of CCR 

in non-CPG, consolidated uses. These CCR categories include blended cement/raw feed for clinker, mineral filler in asphalt, gypsum panel 

products, waste stabilization/solidification, and miscellaneous/other. In the case of CCR used in blended cement, mineral filler v asphalt, 

gypsum for wallboard, and miscellaneous/other applications, this RIA assumed that 50% of these uses will be reduced. Thus, the potential 

reductions in this category will total 6.8 million tons per year. 

For the use of CCR in waste stabilization/solidification applications, this RIA assumed that stigma will not have a negative impact. For this 

use, the CCR are already being used in a waste management context. The CCR are used in secure landfills to immobilize wastes typically more 

hazardous than the CCR themselves. Therefore, this RIA projects no reduction in the future annual tonnage of CCR used for this purpose. 

x “Stigma” for Unconsolidated Uses 

In addition to the consolidated uses of CCR discussed above, CCR can be employed in unconsolidated uses. For some of these uses, the CCR 

products may be more similar to the disposed material proposed to be regulated. In addition, they have typically not been chemically fixed 

within a product. As a result, stigma concerns may be more plausible. Markets that involve unconsolidated uses of CCR include structural 

fill/embankments, road base/sub-base, soil modification/stabilization, snow/ice control, aggregate, agriculture, and miscellaneous/other. For 

purpose of the sensitivity analysis, this RIA assumed a potential reduction of 80%.159 This results in an additional 11.1 million tons per year 

reduction of beneficially used CCR. By adding the 6.8 million tons from CPG consolidated uses, to the 6.8 million tons from non-CPG 

consolidated uses, plus the 11.1 million tons from unconsolidated uses, this RIA estimates that a severe stigma effect would lead to a 51% 

reduction of beneficial use. 

 

158 The 50% reduction is considered a worst-case assumption because these materials provide significant value at competitive costs v for example, concrete that includes fly 

ash typically performs better than non-CCR concrete, and is likely to retain favorable treatment under Leadership in Energy and Environmental Design (LEED). In 

addition, academic studies of gstigmah associated with products rarely leads to decreased usage to this extent. 159 EPA has assumed this high gstigmah effect because a number of the uses may appear close to the disposal scenario, e.g., structural fills. Also, it is widely recognized 

that CCR in unconsolidated uses may present risks, if used in the wrong conditions. (Indeed, EPA takes comment on unconsolidated uses in the preamble to the CCR 

proposed rule due to the increased potential for risks.) Some of these uses are likely to be particularly sensitive to public concerns and liability concerns. These include 

agricultural uses and dispersive uses, like use of bottom ash or boiler slag for ice and snow control. Therefore, if stigma does have a role to play, EPA believes it is 

reasonable to assume it will be significant for unconsolidated uses. Even for the purposes of a worst-case sensitivity analysis, however, EPA believes that, given the 

success of many of these uses in states with rigorous beneficial use programs, gstigmah will not completely eliminate such uses; therefore, it has estimated a decrease of 

80%. 
177 

Step 6: Apply Estimated Induced Effect Scenarios to Baseline CCR Beneficial Use 

Applying the first effect (increase in the sale of CCR due to a decrease in price), EPA noted that a 28% increase with an elasticity of 1.0 would 

makes sense when there is ample room for growth. But as the market becomes more and more saturated, it is less and less likely that unit 

elasticity would apply. Instead, the elasticity is likely to decrease with increasing saturation. To account for this, the beneficial use increase 

was set to 28% of either the existing beneficial use tonnage, or to 28% of the remaining CCR tonnage, whichever was less. In other words, 

once beneficial use was greater than 50% of total CCR, the increase would be constrained to 28% of what was left over after beneficial use was 

accounted for. EPA also accounted for the fact that the price change would not fully affect the market until the rule (and therefore the costs) 

had been phased in. Full implementation was assumed to occur by 2019. However, industry would undoubtedly likely attempt to prepare for 

these increased costs as soon as a final rule was passed, and therefore the beneficial use increases were assumed to linearly approach 28% by 

2019. The projected tons of beneficial use under Subtitle C are shown in Exhibit 28 below. 

As seen below, subtitle C in EPA_s analysis would drive more CCR toward beneficial use due to the increased costs of disposal. However, as 

discussed in Step 4 above, there is also the possibility that there would be a stigma associated with the ghazardous wasteh designation. Here the 

beneficial use of CCR would be 49% of the baseline due to stigma. Since the maximum CCR beneficially used is less than 50% of all CCR, 

the constraint imposed on the straight 28% increase would not be necessary. Thus, once the full 51% decrease and 28% increase are accounted 

for, the future CCR beneficial use annual tonnages are calculated as displayed below in Exhibit 5C-15. 
178 

Exhibit 5C-15 

Two Alternative Scenarios of Projected Future CCR Beneficial Use 2012-2061 

(Short Tons) 

Year Scenario #1: 

w/out Stigma 

Scenario #2: 

w/Stigma Year Scenario #1: w/out Stigma 

Scenario #2: 

w/Stigma 

2012 71,527,755 33,924,749 2037 128,297,364 82,753,160 

2013 75,999,399 36,206,995 2038 129,708,417 84,404,170 

2014 80,338,539 38,457,590 2039 131,105,658 86,035,997 

2015 84,549,013 40,677,131 2040 132,489,375 87,649,041 

2016 88,634,566 42,866,206 2041 133,859,848 89,243,690 

2017 92,598,855 45,025,395 2042 135,217,354 90,820,330 

2018 96,445,450 47,155,270 2043 136,562,164 92,379,337 

2019 100,177,835 49,256,395 2044 137,894,545 93,921,081 

2020 101,892,669 51,329,323 2045 139,214,759 95,445,925 

2021 103,587,595 53,374,602 2046 140,523,061 96,954,227 

2022 105,263,001 55,392,770 2047 141,819,704 98,446,334 

2023 106,919,270 57,384,357 2048 143,104,936 99,922,592 

2024 108,556,775 59,349,885 2049 144,378,997 101,383,338 

2025 110,175,889 61,289,868 2050 145,642,128 102,828,900 

2026 111,776,973 63,204,812 2051 146,894,561 104,259,605 

2027 113,360,387 65,095,213 2052 148,136,525 105,675,770 

2028 114,926,484 66,961,561 2053 149,368,245 107,077,707 

2029 116,475,608 68,804,337 2054 150,589,942 108,465,723 

2030 118,008,102 70,624,016 2055 151,801,831 109,840,117 

2031 119,524,301 72,421,062 2056 153,004,125 111,201,184 

2032 121,024,534 74,195,934 2057 154,197,031 112,549,212 

2033 122,509,126 75,949,081 2058 155,380,753 113,884,485 

2034 123,978,394 77,680,946 2059 156,555,491 115,207,281 

2035 125,432,652 79,391,964 2060 157,721,441 116,517,870 

2036 126,872,208 81,082,562 2061 158,878,794 117,816,520 

Step 7: Estimate Potential Induced Effects on Future Annual Tonnages of CCR Beneficial Use 

 

Exhibit 5C-16 below shows beneficial use projected under Subtitle C. Beneficial use under the increasing disposal cost scenario would lead to 

an increase of 28% above the baseline estimate. However, as the market becomes more and more saturated, it will likely become harder to 

increase beneficial use. Thus, the increase is constrained to 28% of the remaining unused CCR. The elasticity column represents the effective 

percent change in quantity for each percent change in price once this constraint has been accounted for. While the elasticity is assumed to 

initially be 1.0, the effect of market saturation drives that elasticity towards zero over time as seen below. 
179 

Exhibit 5C-16 

Scenario #1: Increase in Future CCR Beneficial Use Under the Subtitle C Option 

Year CCR generation 

(tons) % beneficial use Beneficial use (tons) 

% 

increase 

Increased beneficial 

use (tons) 

Increase w/o mine 

filling (tons) 

Implied 

elasticity 

2012 134,764,862 53.08% 71,527,755 3.31% 2,293,574 2,241,198 0.95 

2013 135,558,881 56.06% 75,999,399 6.27% 4,482,972 4,380,599 0.90 

2014 136,352,901 58.92% 80,338,539 8.91% 6,571,517 6,421,451 0.85 

2015 137,146,920 61.65% 84,549,013 11.27% 8,562,450 8,366,919 0.80 

2016 137,940,940 64.26% 88,634,566 13.38% 10,458,928 10,220,089 0.76 

2017 138,734,959 66.75% 92,598,855 15.27% 12,264,028 11,983,968 0.73 

2018 139,528,979 69.12% 96,445,450 16.95% 13,980,748 13,661,485 0.69 

2019 140,322,998 71.39% 100,177,835 18.46% 15,612,008 15,255,494 0.66 

2020 141,117,018 72.20% 101,892,669 17.61% 15,253,914 14,905,577 0.63 

2021 141,911,037 72.99% 103,587,595 16.81% 14,903,561 14,563,225 0.60 

2022 142,705,057 73.76% 105,263,001 16.05% 14,560,799 14,228,291 0.57 

2023 143,499,076 74.51% 106,919,270 15.35% 14,225,480 13,900,629 0.55 

2024 144,293,096 75.23% 108,556,775 14.68% 13,897,458 13,580,097 0.52 

2025 145,087,115 75.94% 110,175,889 14.05% 13,576,588 13,266,555 0.50 

2026 145,881,135 76.62% 111,776,973 13.46% 13,262,729 12,959,864 0.48 

2027 146,675,154 77.29% 113,360,387 12.90% 12,955,743 12,659,887 0.46 

2028 147,469,174 77.93% 114,926,484 12.37% 12,655,491 12,366,492 0.44 

2029 148,263,193 78.56% 116,475,608 11.87% 12,361,839 12,079,545 0.42 

2030 149,057,213 79.17% 118,008,102 11.40% 12,074,654 11,798,919 0.41 

2031 149,851,232 79.76% 119,524,301 10.95% 11,793,807 11,524,485 0.39 

2032 150,645,252 80.34% 121,024,534 10.52% 11,519,168 11,256,118 0.38 

2033 151,439,271 80.90% 122,509,126 10.11% 11,250,612 10,993,695 0.36 

2034 152,233,291 81.44% 123,978,394 9.72% 10,988,015 10,737,095 0.35 

2035 153,027,310 81.97% 125,432,652 9.36% 10,731,256 10,486,198 0.33 

2036 153,821,330 82.48% 126,872,208 9.00% 10,480,214 10,240,889 0.32 

2037 154,615,349 82.98% 128,297,364 8.67% 10,234,772 10,001,052 0.31 

2038 155,409,369 83.46% 129,708,417 8.35% 9,994,815 9,766,574 0.30 

2039 156,203,388 83.93% 131,105,658 8.04% 9,760,228 9,537,345 0.29 

2040 156,997,408 84.39% 132,489,375 7.75% 9,530,902 9,313,255 0.28 

2041 157,791,427 84.83% 133,859,848 7.47% 9,306,725 9,094,198 0.27 

2042 158,585,447 85.26% 135,217,354 7.20% 9,087,592 8,880,069 0.26 

2043 159,379,466 85.68% 136,562,164 6.95% 8,873,395 8,670,764 0.25 

2044 160,173,486 86.09% 137,894,545 6.70% 8,664,032 8,466,182 0.24 

2045 160,967,505 86.49% 139,214,759 6.47% 8,459,401 8,266,224 0.23 

2046 161,761,525 86.87% 140,523,061 6.24% 8,259,402 8,070,792 0.22 

2047 162,555,544 87.24% 141,819,704 6.03% 8,063,938 7,879,791 0.22 

2048 163,349,564 87.61% 143,104,936 5.82% 7,872,911 7,693,126 0.21 

2049 164,143,583 87.96% 144,378,997 5.62% 7,686,228 7,510,706 0.20 
180 

Exhibit 5C-16 

Scenario #1: Increase in Future CCR Beneficial Use Under the Subtitle C Option 

Year CCR generation 

(tons) % beneficial use Beneficial use (tons) 

% 

increase 

Increased beneficial 

use (tons) 

Increase w/o mine 

filling (tons) 

Implied 

elasticity 

2050 164,937,603 88.30% 145,642,128 5.43% 7,503,796 7,332,440 0.19 

2051 165,731,622 88.63% 146,894,561 5.25% 7,325,524 7,158,239 0.19 

2052 166,525,642 88.96% 148,136,525 5.07% 7,151,323 6,988,016 0.18 

2053 167,319,661 89.27% 149,368,245 4.90% 6,981,106 6,821,687 0.18 

2054 168,113,681 89.58% 150,589,942 4.74% 6,814,787 6,659,166 0.17 

2055 168,907,700 89.87% 151,801,831 4.58% 6,652,282 6,500,372 0.16 

2056 169,701,720 90.16% 153,004,125 4.43% 6,493,509 6,345,224 0.16 

2057 170,495,739 90.44% 154,197,031 4.29% 6,338,387 6,193,644 0.15 

2058 171,289,759 90.71% 155,380,753 4.15% 6,186,835 6,045,554 0.15 

2059 172,083,778 90.98% 156,555,491 4.01% 6,038,778 5,900,878 0.14 

2060 172,877,798 91.23% 157,721,441 3.88% 5,894,139 5,759,541 0.14 

2061 173,671,817 91.48% 158,878,794 3.76% 5,752,842 5,621,471 0.13 

Exhibit 5C-17 below shows beneficial use projected under Subtitle C with a worst-case stigma assumption. Increased beneficial use under the 

increasing disposal costs of a Subtitle C rule are not accounted for. However, as soon as the rule becomes effective in 2012, the Scenario #2 of 

this RIA simulates a stigma effect which decreases the tons beneficially used by 51%. Once the disposal cost effect is fully captured by 2019, 

and the market has adjusted to stigma, beneficial use is assumed to grow at the same rate it would have otherwise. 

Exhibit 5C-17 

Scenario #2: Decrease in Future CCR Beneficial Use Because of Stigma Under Subtitle C Option 

Year CCR generation 

tons % beneficial use Beneficial use tons 

% 

Decrease Decrease tons Decrease w/out mine filling tons 

2012 134,764,862 25.17% 33,924,749 -51.00% -35,309,432 -33,342,859 

2013 135,558,881 26.71% 36,206,995 -49.37% -35,309,432 -33,342,859 

2014 136,352,901 28.20% 38,457,590 -47.87% -35,309,432 -33,342,859 

2015 137,146,920 29.66% 40,677,131 -46.47% -35,309,432 -33,342,859 

2016 137,940,940 31.08% 42,866,206 -45.17% -35,309,432 -33,342,859 

2017 138,734,959 32.45% 45,025,395 -43.95% -35,309,432 -33,342,859 

2018 139,528,979 33.80% 47,155,270 -42.82% -35,309,432 -33,342,859 

2019 140,322,998 35.10% 49,256,395 -41.75% -35,309,432 -33,342,859 

2020 141,117,018 36.37% 51,329,323 -40.75% -35,309,432 -33,342,859 

2021 141,911,037 37.61% 53,374,602 -39.81% -35,309,432 -33,342,859 

2022 142,705,057 38.82% 55,392,770 -38.93% -35,309,432 -33,342,859 

2023 143,499,076 39.99% 57,384,357 -38.09% -35,309,432 -33,342,859 

2024 144,293,096 41.13% 59,349,885 -37.30% -35,309,432 -33,342,859 

2025 145,087,115 42.24% 61,289,868 -36.55% -35,309,432 -33,342,859 
181 

Exhibit 5C-17 

Scenario #2: Decrease in Future CCR Beneficial Use Because of Stigma Under Subtitle C Option 

Year CCR generation 

tons % beneficial use Beneficial use tons 

% 

Decrease Decrease tons Decrease w/out mine filling tons 

2026 145,881,135 43.33% 63,204,812 -35.84% -35,309,432 -33,342,859 

2027 146,675,154 44.38% 65,095,213 -35.17% -35,309,432 -33,342,859 

2028 147,469,174 45.41% 66,961,561 -34.53% -35,309,432 -33,342,859 

2029 148,263,193 46.41% 68,804,337 -33.91% -35,309,432 -33,342,859 

2030 149,057,213 47.38% 70,624,016 -33.33% -35,309,432 -33,342,859 

2031 149,851,232 48.33% 72,421,062 -32.78% -35,309,432 -33,342,859 

2032 150,645,252 49.25% 74,195,934 -32.24% -35,309,432 -33,342,859 

2033 151,439,271 50.15% 75,949,081 -31.74% -35,309,432 -33,342,859 

2034 152,233,291 51.03% 77,680,946 -31.25% -35,309,432 -33,342,859 

2035 153,027,310 51.88% 79,391,964 -30.78% -35,309,432 -33,342,859 

2036 153,821,330 52.71% 81,082,562 -30.34% -35,309,432 -33,342,859 

2037 154,615,349 53.52% 82,753,160 -29.91% -35,309,432 -33,342,859 

2038 155,409,369 54.31% 84,404,170 -29.49% -35,309,432 -33,342,859 

2039 156,203,388 55.08% 86,035,997 -29.10% -35,309,432 -33,342,859 

2040 156,997,408 55.83% 87,649,041 -28.72% -35,309,432 -33,342,859 

2041 157,791,427 56.56% 89,243,690 -28.35% -35,309,432 -33,342,859 

2042 158,585,447 57.27% 90,820,330 -27.99% -35,309,432 -33,342,859 

2043 159,379,466 57.96% 92,379,337 -27.65% -35,309,432 -33,342,859 

2044 160,173,486 58.64% 93,921,081 -27.32% -35,309,432 -33,342,859 

2045 160,967,505 59.30% 95,445,925 -27.00% -35,309,432 -33,342,859 

2046 161,761,525 59.94% 96,954,227 -26.70% -35,309,432 -33,342,859 

2047 162,555,544 60.56% 98,446,334 -26.40% -35,309,432 -33,342,859 

2048 163,349,564 61.17% 99,922,592 -26.11% -35,309,432 -33,342,859 

2049 164,143,583 61.77% 101,383,338 -25.83% -35,309,432 -33,342,859 

2050 164,937,603 62.34% 102,828,900 -25.56% -35,309,432 -33,342,859 

2051 165,731,622 62.91% 104,259,605 -25.30% -35,309,432 -33,342,859 

2052 166,525,642 63.46% 105,675,770 -25.04% -35,309,432 -33,342,859 

2053 167,319,661 64.00% 107,077,707 -24.80% -35,309,432 -33,342,859 

2054 168,113,681 64.52% 108,465,723 -24.56% -35,309,432 -33,342,859 

2055 168,907,700 65.03% 109,840,117 -24.33% -35,309,432 -33,342,859 

2056 169,701,720 65.53% 111,201,184 -24.10% -35,309,432 -33,342,859 

2057 170,495,739 66.01% 112,549,212 -23.88% -35,309,432 -33,342,859 

2058 171,289,759 66.49% 113,884,485 -23.67% -35,309,432 -33,342,859 

2059 172,083,778 66.95% 115,207,281 -23.46% -35,309,432 -33,342,859 

2060 172,877,798 67.40% 116,517,870 -23.26% -35,309,432 -33,342,859 

2061 173,671,817 67.84% 117,816,520 -23.06% -35,309,432 -33,342,859 
182 

Exhibit 5C-18 below shows the projected future annual CCR generation and three trends in beneficial use (i.e., scenario #1 increase without 

stigma, scenario #2 decrease with stigma, and scenario #3 no change in relation to the increasing baseline trend). Scenario #1 assumes that the 

increased cost of disposal from regulation will induce the electric utility industry to seek out additional CCR beneficial use markets thereby 

increasing future annual beneficial use of CCR above the increasing baseline trend. Experiences with the EPA RCRA Subtitle C hazardous 

waste program indicate that industry often increases annual recycling and materials recovery rates after RCRA regulation (e.g., after EPA has 

listed certain types and sources of secondary industrial materials as RCRA ghazardous wastesh). Thus, EPA regards the increased beneficial 

use Scenario #1 as the most likely outcome. A second curve in the Exhibit below displays the Scenario #2 decreased CCR beneficial use 

stigma effect under the Subtitle C regulatory option (this RIA does not apply scenario #2 under the Subtitle D options). The Exhibit also 

presents Scenario #3 in which future annual CCR beneficial use is projected to continue on its recent upwardly increasing trendline without any 

induced future change as a result of the CCR rule. The future annual beneficial use tonnages for both scenario #1 and scenario #2 are estimated 

in this RIA incrementally relative to the scenario #3 baseline trend. 
183 

Exhibit 5C-18 

Beneficial Use Trends

0

15,000,000

30,000,000

45,000,000

60,000,000

75,000,000

90,000,000

105,000,000

120,000,000

135,000,000

150,000,000

165,000,000

180,000,000

2012 2017 2022 2027 2032 2037 2042 2047 2052 2057

Year

CCRs (Short Tons)

CCRs Generated Baseline BU Subtitle C BU Subtitle C w/Stigma
184 

Step 8: Monetize Potential Induced Effects on Future CCR Beneficial Use 

Based on multiplying a unitized average monetized social benefit value of $559 per ton consisting of (a) the $474 per ton unitized lifecycle 

benefit value, plus the (b) $85 per ton average avoided disposal cost estimated for the subtitle C option, to the 50-year (i.e., 2012 to 2061) 

projected future baseline tonnage displayed in Exhibit 5C-18 above, produces an estimated future baseline social benefit value from CCR 

beneficial use of: 

PV @3% discount PV @7% discount

Future baseline economic value: $102,290 million PV $51,170 million PV 

Future baseline lifecycle social value*: $1,554,323 million PV $777,541 million PV 

 (* Includes avoided CCR disposal cost to electric utility industry) 

x Monetization of Scenario #1 (Induced Increase in CCR Beneficial Use) 

Exhibit 5C-19 below provides an estimate of the potential increase in future annual tonnage and economic and social benefits associated with

CCR beneficial uses (not including minefilling) that could occur as a result of the CCR proposed rule. This quantity is incrementally calculated 

each year as the quantity projected under the Subtitle C option (without stigma), less the quantity projected under the baseline. 

Exhibit 5C-19 

Scenario #1: Benefit from Future Increase in CCR Beneficial User Under Subtitle C “Special Waste” 

Nominal Benefits 

(Millions) 

Discounted Benefits 

@ 3% (Millions) 

Discounted Benefits 

Year @ 7% (Millions) 

CCR Beneficial 

Use Increase 

(tons) Econ Social Econ Social Econ Social 

2012 2,241,198 $82 $1,253 $82 $1,253 $82 $1,253 

2013 4,380,599 $161 $2,449 $156 $2,377 $151 $2,289 

2014 6,421,451 $236 $3,590 $223 $3,384 $206 $3,135 

2015 8,366,919 $308 $4,677 $282 $4,280 $251 $3,818 

2016 10,220,089 $376 $5,713 $334 $5,076 $287 $4,359 

2017 11,983,968 $441 $6,699 $380 $5,779 $314 $4,776 

2018 13,661,485 $503 $7,637 $421 $6,396 $335 $5,089 

2019 15,255,494 $561 $8,528 $456 $6,934 $350 $5,311 

2020 14,905,577 $548 $8,332 $433 $6,578 $319 $4,850 

2021 14,563,225 $536 $8,141 $411 $6,239 $291 $4,428 

2022 14,228,291 $523 $7,954 $389 $5,918 $266 $4,043 

2023 13,900,629 $511 $7,771 $369 $5,614 $243 $3,692 

2024 13,580,097 $500 $7,591 $350 $5,324 $222 $3,371 

2025 13,266,555 $488 $7,416 $332 $5,050 $203 $3,077 
185 

Exhibit 5C-19 

Scenario #1: Benefit from Future Increase in CCR Beneficial User Under Subtitle C “Special Waste” 

Nominal Benefits 

(Millions) 

Discounted Benefits 

@ 3% (Millions) 

Discounted Benefits 

Year @ 7% (Millions) 

CCR Beneficial 

Use Increase 

(tons) Econ Social Econ Social Econ Social 

2026 12,959,864 $477 $7,245 $315 $4,790 $185 $2,810 

2027 12,659,887 $466 $7,077 $299 $4,542 $169 $2,565 

2028 12,366,492 $455 $6,913 $284 $4,308 $154 $2,342 

2029 12,079,545 $444 $6,753 $269 $4,085 $141 $2,138 

2030 11,798,919 $434 $6,596 $255 $3,874 $128 $1,951 

2031 11,524,485 $424 $6,442 $242 $3,674 $117 $1,781 

2032 11,256,118 $414 $6,292 $229 $3,484 $107 $1,626 

2033 10,993,695 $404 $6,146 $217 $3,304 $98 $1,484 

2034 10,737,095 $395 $6,002 $206 $3,132 $89 $1,355 

2035 10,486,198 $386 $5,862 $195 $2,970 $81 $1,237 

2036 10,240,889 $377 $5,725 $185 $2,816 $74 $1,129 

2037 10,001,052 $368 $5,591 $176 $2,670 $68 $1,030 

2038 9,766,574 $359 $5,460 $167 $2,532 $62 $940 

2039 9,537,345 $351 $5,331 $158 $2,400 $56 $858 

2040 9,313,255 $343 $5,206 $150 $2,276 $52 $783 

2041 9,094,198 $335 $5,084 $142 $2,157 $47 $715 

2042 8,880,069 $327 $4,964 $135 $2,045 $43 $652 

2043 8,670,764 $319 $4,847 $128 $1,939 $39 $595 

2044 8,466,182 $311 $4,733 $121 $1,838 $36 $543 

2045 8,266,224 $304 $4,621 $115 $1,742 $33 $496 

2046 8,070,792 $297 $4,512 $109 $1,651 $30 $452 

2047 7,879,791 $290 $4,405 $103 $1,565 $27 $413 

2048 7,693,126 $283 $4,301 $98 $1,484 $25 $376 

2049 7,510,706 $276 $4,199 $93 $1,406 $23 $343 

2050 7,332,440 $270 $4,099 $88 $1,333 $21 $313 

2051 7,158,239 $263 $4,002 $83 $1,263 $19 $286 

2052 6,988,016 $257 $3,906 $79 $1,198 $17 $261 

2053 6,821,687 $251 $3,813 $75 $1,135 $16 $238 

2054 6,659,166 $245 $3,723 $71 $1,076 $14 $217 

2055 6,500,372 $239 $3,634 $67 $1,019 $13 $198 

2056 6,345,224 $233 $3,547 $64 $966 $12 $181 

2057 6,193,644 $228 $3,462 $60 $916 $11 $165 

2058 6,045,554 $222 $3,380 $57 $868 $10 $150 

2059 5,900,878 $217 $3,299 $54 $822 $9 $137 

2060 5,759,541 $212 $3,220 $51 $779 $8 $125 

2061 5,621,471 $207 $3,142 $49 $738 $8 $114 

Present Value $9,806 $149,001 $5,560 $84,489 
186 

x Monetization of Potential “Stigma” Decrease in CCR Beneficial Use (Scenario #2) 

The $559 per ton social benefit value estimated above is the proper estimate for increased beneficial use because this RIA assumes that all 

beneficial uses will increase in equal proportions. However, it would not be appropriate to apply this same dollar estimate to decreased 

beneficial use from stigma because different uses decrease by different amounts, and therefore the decrease in benefits would not necessarily 

equal the 51% decrease in tons. Based on the breakdown of beneficial uses displayed below in Exhibit 5C-20, these individual use category 

losses were summed to create a weighted average benefit reduction of 42%. However, on a tonnage basis 51% of beneficial use tons are 

reduced. Dividing the weighted value by the unweighted value for each ton lost, the benefits decreased by only 82% of the average $559/ton, 

or $458/ton. This average unitized social benefits value is used to monetize the estimated tons lost from the stigma Scenario #2. 

Exhibit 5C-20 

Calculation of the “Stigma” Adjustment Factor for the CCR Beneficial Use Reduction Scenario #2 

Beneficial Use Industrial Category CCR Beneficial 

Use (2005 tons) 

Disposal Cost 

Savings 

(millions) 

Life Cycle 

Benefits 

(millions) 

Total 

Benefits 

(millions) 

Percent Lost From 

Stigma 

Benefits Lost 

(millions) 

1. Concrete/concrete products/grout 16,353,331 $1,390 $17,593 $18,983 37.5% $7,118.6 

2. Blended cement/raw feed for clinker 4,215,234 $358 Not estimated $358 50% $179.0 

3. Flowable fill 259,907 $22 Not estimated $22 37.5% $8.3 

4. Structural fill/embankments 8,349,999 $710 Not estimated $710 80% $568.0 

5. Road base/sub-base 1,461,992 $124 Not estimated $124 80% $99.2 

6. Soil modification/stabilization 1,139,640 $97 Not estimated $97 80% $77.6 

7. Mineral filler in asphalt 140,838 $12 Not estimated $12 50% $6.0 

8. Snow & ice control 547,541 $47 Not estimated $47 80% $37.6 

9. Blasting grit/roofing granules 1,633,407 $139 Not estimated $139 37.5% $52.1 

10. Gypsum panel products (wallboard) 8,178,079 $695 $5,387 $6,082 50% $3,041.0 

11. Waste stabilization/solidification 2,839,954 $241 Not estimated $241 0% $0.0 

12. Agriculture 415,741 $35 Not estimated $35 80% $28.0 

13. Aggregate 872,776 $74 Not estimated $74 80% $59.2 

14. Miscellaneous other 2,071,157 $176 Not estimated $176 65% $114.4 

Weighted Total = 48,479,596 $4,120 $22,980 $27,100 42% $11,382 

Unweighted Total = 48,479,596 $4,120 $22,980 $27,100 51% $13,821 

Adjustment Factor = 0.82 

Exhibit 5C-21 below provides an estimate of the beneficial use decrease scenario. This quantity is calculated each year as the quantity 

projected under subtitle C (with stigma) less the quantity projected under the baseline. 
187 

Exhibit 5C-21 

Scenario #2: Cost of Potential Future Reduction in CCR Beneficial Use Under Subtitle C with “Stigma” 

Nominal Costs 

(Millions) 

Discounted Costs 

@ 3% (Millions) 

Discounted Costs 

Year @ 7% (Millions) 

CCR Beneficial 

Use Decrease 

(Short Tons) Economic Social Economic Social Economic Social 

2012 -33,342,859 -$1,269 -$15,816 -$1,269 -$15,816 -$1,269 -$15,816 

2013 -33,342,859 -$1,269 -$15,816 -$1,232 -$15,355 -$1,186 -$14,781 

2014 -33,342,859 -$1,269 -$15,816 -$1,196 -$14,908 -$1,109 -$13,814 

2015 -33,342,859 -$1,269 -$15,816 -$1,162 -$14,474 -$1,036 -$12,910 

2016 -33,342,859 -$1,269 -$15,816 -$1,128 -$14,052 -$968 -$12,066 

2017 -33,342,859 -$1,269 -$15,816 -$1,095 -$13,643 -$905 -$11,276 

2018 -33,342,859 -$1,269 -$15,816 -$1,063 -$13,245 -$846 -$10,539 

2019 -33,342,859 -$1,269 -$15,816 -$1,032 -$12,860 -$790 -$9,849 

2020 -33,342,859 -$1,269 -$15,816 -$1,002 -$12,485 -$739 -$9,205 

2021 -33,342,859 -$1,269 -$15,816 -$973 -$12,122 -$690 -$8,603 

2022 -33,342,859 -$1,269 -$15,816 -$944 -$11,768 -$645 -$8,040 

2023 -33,342,859 -$1,269 -$15,816 -$917 -$11,426 -$603 -$7,514 

2024 -33,342,859 -$1,269 -$15,816 -$890 -$11,093 -$564 -$7,022 

2025 -33,342,859 -$1,269 -$15,816 -$864 -$10,770 -$527 -$6,563 

2026 -33,342,859 -$1,269 -$15,816 -$839 -$10,456 -$492 -$6,134 

2027 -33,342,859 -$1,269 -$15,816 -$815 -$10,152 -$460 -$5,732 

2028 -33,342,859 -$1,269 -$15,816 -$791 -$9,856 -$430 -$5,357 

2029 -33,342,859 -$1,269 -$15,816 -$768 -$9,569 -$402 -$5,007 

2030 -33,342,859 -$1,269 -$15,816 -$746 -$9,290 -$376 -$4,679 

2031 -33,342,859 -$1,269 -$15,816 -$724 -$9,020 -$351 -$4,373 

2032 -33,342,859 -$1,269 -$15,816 -$703 -$8,757 -$328 -$4,087 

2033 -33,342,859 -$1,269 -$15,816 -$682 -$8,502 -$307 -$3,820 

2034 -33,342,859 -$1,269 -$15,816 -$662 -$8,254 -$287 -$3,570 

2035 -33,342,859 -$1,269 -$15,816 -$643 -$8,014 -$268 -$3,336 

2036 -33,342,859 -$1,269 -$15,816 -$624 -$7,780 -$250 -$3,118 

2037 -33,342,859 -$1,269 -$15,816 -$606 -$7,554 -$234 -$2,914 

2038 -33,342,859 -$1,269 -$15,816 -$589 -$7,334 -$219 -$2,723 

2039 -33,342,859 -$1,269 -$15,816 -$571 -$7,120 -$204 -$2,545 

2040 -33,342,859 -$1,269 -$15,816 -$555 -$6,913 -$191 -$2,379 

2041 -33,342,859 -$1,269 -$15,816 -$539 -$6,711 -$178 -$2,223 

2042 -33,342,859 -$1,269 -$15,816 -$523 -$6,516 -$167 -$2,078 

2043 -33,342,859 -$1,269 -$15,816 -$508 -$6,326 -$156 -$1,942 

2044 -33,342,859 -$1,269 -$15,816 -$493 -$6,142 -$146 -$1,815 

2045 -33,342,859 -$1,269 -$15,816 -$479 -$5,963 -$136 -$1,696 

2046 -33,342,859 -$1,269 -$15,816 -$465 -$5,789 -$127 -$1,585 

2047 -33,342,859 -$1,269 -$15,816 -$451 -$5,621 -$119 -$1,481 

2048 -33,342,859 -$1,269 -$15,816 -$438 -$5,457 -$111 -$1,384 

2049 -33,342,859 -$1,269 -$15,816 -$425 -$5,298 -$104 -$1,294 
188 

Exhibit 5C-21 

Scenario #2: Cost of Potential Future Reduction in CCR Beneficial Use Under Subtitle C with “Stigma” 

Nominal Costs 

(Millions) 

Discounted Costs 

@ 3% (Millions) 

Discounted Costs 

Year @ 7% (Millions) 

CCR Beneficial 

Use Decrease 

(Short Tons) Economic Social Economic Social Economic Social 

2050 -33,342,859 -$1,269 -$15,816 -$413 -$5,144 -$97 -$1,209 

2051 -33,342,859 -$1,269 -$15,816 -$401 -$4,994 -$91 -$1,130 

2052 -33,342,859 -$1,269 -$15,816 -$389 -$4,848 -$85 -$1,056 

2053 -33,342,859 -$1,269 -$15,816 -$378 -$4,707 -$79 -$987 

2054 -33,342,859 -$1,269 -$15,816 -$367 -$4,570 -$74 -$923 

2055 -33,342,859 -$1,269 -$15,816 -$356 -$4,437 -$69 -$862 

2056 -33,342,859 -$1,269 -$15,816 -$346 -$4,308 -$65 -$806 

2057 -33,342,859 -$1,269 -$15,816 -$336 -$4,182 -$60 -$753 

2058 -33,342,859 -$1,269 -$15,816 -$326 -$4,060 -$56 -$704 

2059 -33,342,859 -$1,269 -$15,816 -$316 -$3,942 -$53 -$658 

2060 -33,342,859 -$1,269 -$15,816 -$307 -$3,827 -$49 -$615 

2061 -33,342,859 -$1,269 -$15,816 -$298 -$3,716 -$46 -$574 

Present Value -$33,639 -$419,145 -$18,744 -$233,549 

Step 9: Estimate Potential Induced Effect on CCR Beneficial Use of the Other RCRA Regulatory Options 

The analysis above demonstrates the valuation of beneficial use effects using only the subtitle C option. However, the results may be 

extrapolated to the other regulatory options. Exhibit 5C-22 below displays the beneficial use effect scenarios linearly extrapolated in relation 

to the result of subtitle C based on the potential increase in CCR disposal cost. In other words, the ratio of the disposal cost estimated under 

those other scenarios to the subtitle C disposal cost can be applied to the beneficial use benefits under those alternative options. 

Exhibit 5C-22 

Potential Induced Effect of RCRA Regulation on Future CCR Beneficial Use: 2 Scenarios 

($millions present value @7%) 

Component Subtitle C Special waste Subtitle D (version 2) Subtitle gD primeh 

Assumed scaling ratios relative to C value = 100% 40% 16% 

Scenario #1: Increase in Beneficial Use (Base Case) 

Percentage increase relative to baseline = +11% +4% +2% 

Economic market value +$5,560 +$2,224 +$890 

Lifecycle social value +$84,489 +$33,796 +$13,518 

Scenario #2: Decrease in Beneficial Use 

Percentage increase relative to baseline = -18% N/A N/A 

Economic market value -$18,744 N/A N/A 

Lifecycle social value -$233,549 N/A N/A 
189 

Step 10: Quantify Potential Capacity Impacts on Commercial Subtitle C Waste Landfills (Under Scenario #2)

For Scenario #2 estimated above involving a potential future reduction in annual CCR beneficial use, such loss would require additional 

disposal of 33.3 million tons CCR annually (source: Exhibit 5C-16) which will likely create four future industrial waste disposal problems: 

1. Annual disposal rate exceedance: Relative to the 33.3 million lost beneficial use annnual tonnages, there is a much smaller quantity of 

2 million tons per year of RCRA-regulated hazardous waste which is currently disposed in RCRA Subtitle C permitted onsite (captive) 

and offsite (commercial) landfills in the US.160 This implies a potential 1,665% annual increase (i.e., 16.65 times larger) in demand for 

hazardous waste landfill capacity. 

2. Limited geographic availability: There are currently 19 to 24 commercial hazardous waste landfills operating in 15 to 17 states. 161 

However, the CCR which is currently beneficially used is generated by 272 electric utility plants located in 41 states.162 Thus disposal 

at commercial hazardous waste landfills would require out-of-state shipment involving at least 24 to 26 states which do not have 

commercial hazardous waste landfills. 

3. Remaining disposal capacity exceedance: The 19 to 24 commercial hazardous waste landfills have an available total remaining capacity 

of 21.7 million to 25.4 million tons hazardous waste.163 The additional 33.3 million tons per year of CCR beneficial use needing 

disposal under the Scenario #2 will consume this entire remaining total capacity within less than one year. 

4. Increase landfill prices: In addition, such a large increase in nationwide economic demand for commercial hazardous waste landfills 

could drive-up landfill tipping fees which recently (2004) ranged between $61 and $139 per ton nationwide ($90 per ton national

average).164 As verification of this potential effect on landfill prices, a recent (August 2009) market study165 of the US commercial 

 

160 Source: 2 million tons per year is based on the annual average of landfill tonnages reported for years 2001 (2.09 million tons), 2003 (1.68 million tons), 2005 (2.04 

million tons), and 2007 (1.94 million tons) in EPA_s gRCRA National Analysis Biennial Hazardous Waste Reporth at 

http://www.epa.gov/waste/inforesources/data/biennialreport/index.htm 

161 Source: These two ranges (i.e., 19 to 24 commercial haz waste landfill counts and 15 to 17 states) are from two alternative data sources: 

x Source #1 of 2: 24 commercial RCRA-permitted hazardous waste landfill count and 17 state identities as listed in the Hazardous Waste Consultant g2007 Directory of 

US Commercial Hazardous Waste Management Facilities,h Vol.25, Issue 1, 2007, pp.4.1 to 4.44. The 17 states are AL, AR, CA, CO, ID, IL, IN, LA, MI, NV, NJ, NY, 

OH, OK, OR, TX, UT. 

x Source #2 of 2: As compiled 02 Oct 2009 by EPA OSWER-ORCR staff (Cpan Lee, Environmental Scientist), this available remaining capacity estimate is based on 

three sources: (a) actual capacity estimates provided to OSWER-ORCR by facilities in April-Sept 2009, (b) information provided to OSWER-ORCR by EPA Regions 

and States in April/May 2009, and (c) capacity estimates developed by OSWER-ORCR using 1995-2007 RCRA Biennial Report data. The 15 States are AL, CA, CO, 

ID, IL, IN, LA, MI, NV, NY, OH, OK, OR, TX, and UT. 162 The 41 states are AL, AR, AZ, CO, DE, FL, GA, IA, IL, IN, KS, KY, LA, MA, MD, MI, MN, MO, MS, MT, NC, ND, NE, NH, NJ, NM, NV, NY, ,OH, OK, OR, SC, 

SD, TN, TX, UT, VA, WA, WI, WV, WY. 

163 Source: 02 Oct 2009 estimates by EPA OSWER-ORCR staff (Cpan Lee, Environmental Scientist) cited in a prior footnote in this section of the RIA. 164 Source: US commercial hazardous waste landfill prices for bulk hazardous waste without treatment reported by the Environmental Technology Council (ETC) gMay 

2004 Incinerator and Landfill Cost Datah website at http://www.etc.org/costsurvey8.cfm 165 Source: Page 10 of gHazardous Waste Industry Review 2008-2009,h Joan Berkowitz and Robert Crisp, Farkas Berkowitz & Company, August 2009; 

http://www.farkasberkowitz.com/marketresearch.htm 
190 

hazardous waste industry, provides the following empirical evidence of price increases by commercial hazardous waste landfills in 

response to annual increases in landfill disposal tonnage: 

gOn average, the number of surveyed landfill firms that increased prices exceeds the number that received higher 

volumes in 2008. Volumes increased for 50 percent of respondents and decreased for 42 percent, but 67 percent raised 

prices and 33 percent left prices unchanged. The survey did not ask how much, if any, of the reported price increase was 

due to fuel surcharges. The survey did determine that 92 percent of respondents applied fuel surcharges, but fuel 

surcharges cannot account for all of the price increases because the surcharges cover increased costs, and 77 percent of 

respondents reported increased [profit] margins.h 
191 

Chapter 6 

Comparison of Regulatory Benefits to Costs 

Section 6A of this Chapter presents a series of exhibits which summarize and compare the results of the cost and benefit estimates presented in 

Chapter 4 and Chapter 5, respectively, scaled to the three 2010 regulatory options. Section 6B of this Chapter provides explanation of the 

scaling method and factors applied. 

6A. Comparison of Regulatory Benefits to Costs Based on Alternative Discount Rates 

The series of six Exhibits 6A to 6F below summarize cost and benefits according to the three alternative beneficial use scenarios (i.e., induced 

increase, induced decrease, and no change), and according to the two OMB-prescribed alternative discount rates of 7% and 3% for use in RIAs: 

7% discount rate: The 7% discount rate as a gbase caseh to represent the financial opportunity cost (i.e., borrowing cost) to affected 

businesses, which is consistent with OMB_s 2003 Circular A-4 guidance166 (page 33), and with OMB_s 1992 

Circular A-94 guidance167 (page 8) which indicate that a 7% discount rate gbase caseh should be used for 

regulatory analyses when regulation is expected to primarily and directly affect businesses and industries. 

3% discount rate: This is a second mandatory discount rate specified in OMB_s 2003 Circular A-4 guidance (page 34). 

In these six summary exhibits below, the comparison of regulatory benefits to costs involves two numerical comparisons: 

1. Net benefits (i.e., benefits minus costs) 

2. Benefit/cost ratios (i.e., benefits divided by costs) 

 Two alternative discount rates: 

Three alternative CCR beneficial use impact scenarios: 

7% discount rate 

(base case in this RIA)

3% discount rate

 Scenario #1: Induced increase (base case) Exhibit 6A Exhibit 6B 

 Scenario #2: Induced decrease Exhibit 6C Exhibit 6D 

 Scenario #3: No change Exhibit 6E Exhibit 6F 

 

166 OMB_s 17 Sept 2003 Circular A-4 gRegulatory Analysish guidance is available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/ 167 OMB_s 29 Oct 1992 Circular A-94 gGuidelines and Discount Rates for Benefit-Cost Analysis of Federal Programs,h is available at

http://www.whitehouse.gov/omb/rewrite/circulars/a094/a094.html 
192 

Exhibit 6A 

Comparison of Regulatory Benefits to Costs Under Scenario #1 – Induced Beneficial Use Increase @7% Discount Rate – Detailed Summary 

($Millions in 50-Year Present Values @2009$ Prices) 

Costs Subtitle C “Special Waste” Subtitle D (version 2) Subtitle “D prime” 

1. Engineering Controls $6,780 $3,254 $3,254 

2. Ancillary Costs $1,480 $5 $5 

3. Dry Conversion $12,089 4,836 $0 

Total Costs (1+2+3) = $20,349 $8,095 $3,259 

Benefits 

4. Groundwater Protection Benefits* $970 $375 $188 

 Count of Human Cancer Risks Avoided** 726 296 148 

 Monetized Value of Human Cancer Risks Avoided $504 $207 $104 

 Groundwater Remediation Costs Avoided $466 $168 $84 

5. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Econ. Benefits Social benefits 

Scenario #1 @7% discount rate = $5,560 $84,489 $2,224 $33,796 $890 $13,518 

6. CCR Impoundment Failure Costs Avoided 

 If Based on Extrapolated Recent Failure Cases $1,762 $793 $405 

 If Based on 10% Future Failures $8,366 $3,795 $1,897 

 If Based on 20% Future Failures $16,732 $7,590 $3,795 

7. Non-quantified Benefits*** Q R S 

Total Benefits (4+5+6): 

Total Benefits w/Extrapolated Recent Failure Cases = $8,292 $87,221 $3,392 $34,964 $1,483 $14,111 

Total Benefits @10% Future Failures = $14,896 $93,825 $6,394 $37,966 $2,975 $15,603 

Total Benefits @20% Future Failures = $23,262 $102,191 $10,189 $41,761 $4,873 $17,501 

Net Benefits (Total Benefits minus Total Costs) 

Net Benefits w/Extrapolated Recent Failure Cases = ($12,057) $66,872 ($4,703) $26,869 ($1,776) $10,852 

Net Benefits @10% Future Failures = ($5,453) $73,476 ($1,701) $29,871 ($284) $12,344 

Net Benefits @20% Future Failures = $2,913 $81,842 $2,094 $33,666 $1,614 $14,242 

Benefit/Cost Ratio (BCR) 

BCR w/Extrapolated Recent Failure Cases = 0.407 4.286 0.419 4.319 0.455 4.330 

BCR @10% Future Failures = 0.732 4.611 0.790 4.690 0.913 4.788 

BCR @20% Future Failures = 1.143 5.022 1.259 5.159 1.495 5.370 

Notes: 

* Cancer risk reflects the arsenic groundwater pathway only and does not include other human health mortality or morbidity risks from non-carcinogens, nor do they 

reflect ecological and socio-economic damages that could occur. Thus, the benefits are underestimated in this RIA. 

** Cancer risks avoided are based on National Academy of Science (2001) data, which represents recent scientific information. 

*** Q>R>S; For example, non-quantified ecological benefits could add 159%, and socio-economic benefits could add 24%, compared to avoided cleanup cost benefit. 
193 

Exhibit 6B 

Comparison of Regulatory Benefits to Costs Under Scenario #1 – Induced Beneficial Use Increase @3% Discount Rate 

($Millions in 50-Year Present Values @2009$ Prices) 

Costs Subtitle C “Special Waste” Subtitle D (version 2) Subtitle “D prime” 

1. Engineering Controls $12,640 $6,067 $6,067 

2. Ancillary Costs $2,759 $9 $9 

3. Dry Conversion $22,538 $9,016 $0 

Total Costs (1+2+3) = $37,938 $15,092 $6,076 

Benefits 

4. Groundwater Protection Benefits* $3,316 $1,321 $661 

 Count of Human Cancer Risks Avoided** 726 296 148 

 Monetized Value of Human Cancer Risks Avoided $1,825 $750 $375 

 Groundwater Remediation Costs Avoided $1,491 $571 $286 

5. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Econ. Benefits Social benefits 

Scenario #1 @3% discount rate = $9,806 $149,001 $3,922 $59,600 $1,569 $23,840 

6. CCR Impoundment Failure Costs Avoided 

 If Based on Extrapolated Recent Failure Cases $3,124 $1,406 $719 

 If Based on @ 10% Future Failures $13,046 $5,918 $2,959 

 If Based on @ 20% Future Failures $26,092 $11,836 $5,918 

7. Non-quantified Benefits*** Q R S 

Total Benefits (4+5+6): 

Total Benefits w/Extrapolated Recent Failure Cases = $16,246 $155,441 $6,649 $62,327 $2,949 25,220 

Total Benefits @10% Future Failures = $26,168 $165,363 $11,161 $66,839 $5,189 $27,460 

Total Benefits @20% Future Failures = $39,214 $178,409 $17,079 $72,757 $8,148 $30,419 

Net Benefits (Total Benefits minus Total Costs) 

Net Benefits w/Extrapolated Recent Failure Cases = ($21,692) $117,503 ($8,443) $47,235 ($3,127) $19,144 

Net Benefits @10% Future Failures = ($11,770) $127,425 ($3,931) $51,747 ($887) $21,384 

Net Benefits @20% Future Failures = $1,276 $140,471 $1,987 $57,665 $2,072 $24,343 

Benefit/Cost Ratio (BCR) 

BCR w/Extrapolated Recent Failure Cases = 0.428 4.097 0.441 4.130 0.485 4.151 

BCR @10% Future Failures = 0.690 4.359 0.740 4.429 0.854 4.519 

BCR @20% Future Failures = 1.034 4.703 1.132 4.821 1.341 5.006 

Notes: 

* Cancer risk reflects the arsenic groundwater pathway only and does not include other human health mortality or morbidity risks from non-carcinogens, nor do they reflect 

ecological and socio-economic damages that could occur. Thus, the benefits are underestimated in this RIA. 

** Cancer risks avoided are based on National Academy of Science (2001) data, which represents recent scientific information. 

*** Q>R>S. 
194 

Exhibit 6C 

Comparison of Regulatory Benefits to Costs Under Scenario #2 – Induced Beneficial Use Decrease @7% Discount Rate 

($Millions in 50-Year Present Values @2009$ Prices) 

Costs Subtitle C “Special Waste” Subtitle D (version 2) Subtitle “D prime” 

1. Engineering Controls $6,780 $3,254 $3,254 

2. Ancillary Costs $1,480 $5 $5 

3. Dry Conversion $12,089 4,836 $0 

Total Costs (1+2+3) = $20,349 $8,095 $3,259 

Benefits 

4. Groundwater Protection Benefits* $970 $375 $188 

 Count of Human Cancer Risks Avoided** 726 296 148 

 Monetized Value of Human Cancer Risks Avoided $504 $207 $104 

 Groundwater Remediation Costs Avoided $466 $168 $84 

5. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Econ. Benefits Social benefits 

Scenario #2 @7% discount rate = ($18,744) ($233,549) $0 (no impact) $0 (no impact) $0 (no impact) $0 (no impact) 

6. CCR Impoundment Failure Costs Avoided 

 If Based on Extrapolated Recent Failure Cases $1,762 $793 $405 

 If Based on 10% Future Failures $8,366 $3,795 $1,897 

 If Based on 20% Future Failures $16,732 $7,590 $3,795 

7. Non-quantified Benefits*** Q R S 

Total Benefits (4+5+6): 

Total Benefits w/Extrapolated Recent Failure Cases = ($16,012) ($230,817) $1,168 $1,168 $593 $593 

Total Benefits @10% Future Failures = ($9,408) ($224,213) $4,170 $4,170 $2,085 $2,085 

Total Benefits @20% Future Failures = ($1,042) ($215,847) $7,965 $7,965 $3,983 $3,983 

Net Benefits (Total Benefits minus Total Costs) 

Net Benefits w/Extrapolated Recent Failure Cases = ($36,361) ($251,166) ($6,927) ($6,927) ($2,666) ($2,666)

Net Benefits @10% Future Failures = ($29,757) ($244,562) ($3,925) ($3,925) ($1,174) ($1,174)

Net Benefits @20% Future Failures = ($21,391) ($236,196) ($130) ($130) $724 $724 

Benefit/Cost Ratio (BCR) 

BCR w/Extrapolated Recent Failure Cases = (0.787) (11.343) 0.144 0.144 0.182 0.182 

BCR @10% Future Failures = (0.462) (11.018) 0.515 0.515 0.640 0.640 

BCR @20% Future Failures = (0.051) (10.607) 0.984 0.984 1.222 1.222 

Notes: 

* Cancer risk reflects the arsenic groundwater pathway only and does not include other human health mortality or morbidity risks from non-carcinogens, nor do they 

reflect ecological and socio-economic damages that could occur. Thus, the benefits are underestimated in this RIA. 

** Cancer risks avoided are based on National Academy of Science (2001) data, which represents recent scientific information. 

*** Q>R>S. 
195 

Exhibit 6D 

Comparison of Regulatory Benefits to Costs Under Scenario #2 – Induced Beneficial Use Decrease @3% Discount Rate 

($Millions in 50-Year Present Values @2009$ Prices) 

Costs Subtitle C “Special Waste” Subtitle D (version 2) Subtitle “D prime” 

1. Engineering Controls $12,640 $6,067 $6,067 

2. Ancillary Costs $2,759 $9 $9 

3. Dry Conversion $22,538 $9,016 $0 

Total Costs (1+2+3) = $37,938 $15,092 $6,076 

Benefits 

4. Groundwater Protection Benefits* $3,316 $1,321 $661 

 Count of Human Cancer Risks Avoided** 726 296 148 

 Monetized Value of Human Cancer Risks Avoided $1,825 $750 $375 

 Groundwater Remediation Costs Avoided $1,491 $571 $286 

5. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Econ. Benefits Social benefits 

Scenario #2 @3% discount rate = ($34,946) ($435,419) $0 (no impact) $0 (no impact) $0 (no impact) $0 (no impact) 

6. CCR Impoundment Failure Costs Avoided 

 If Based on Extrapolated Recent Failure Cases $3,124 $1,406 $719 

 If Based on 10% Future Failures $13,046 $5,918 $2,959 

 If Based on 20% Future Failures $26,092 $11,836 $5,918 

7. Non-quantified Benefits*** Q R S 

Total Benefits (4+5+6): 

Total Benefits w/Extrapolated Recent Failure Cases = ($28,506) ($428,979) $2,727 $2,727 $1,380 $1,380 

Total Benefits @10% Future Failures = ($18,584) ($419,057) $7,239 $7,239 $3,620 $3,620 

Total Benefits @20% Future Failures = ($5,538) ($406,011) $13,157 $13,157 $6,579 $6,579 

Net Benefits (Total Benefits minus Total Costs) 

Net Benefits w/Extrapolated Recent Failure Cases = ($66,443) ($466,917) ($12,365) ($12,365) ($4,696) ($4,696) 

Net Benefits @10% Future Failures = ($56,521) ($456,995) ($7,853) ($7,853) ($2,456) ($2,456) 

Net Benefits @20% Future Failures = ($43,475) ($443,949) ($1,935) ($1,935) $503 $503 

Benefit/Cost Ratio (BCR) 

BCR w/Extrapolated Recent Failure Cases = (0.751) (11.307) 0.181 0.181 0.227 0.227 

BCR @10% Future Failures = (0.490) (11.046) 0.480 0.480 0.596 0.596 

BCR @20% Future Failures = (0.146) (10.702) 0.872 0.872 1.083 1.083 

Notes: 

* Cancer risk reflects the arsenic groundwater pathway only and does not include other human health mortality or morbidity risks from non-carcinogens, nor do they 

reflect ecological and socio-economic damages that could occur. Thus, the benefits are underestimated in this RIA. 

** Cancer risks avoided are based on National Academy of Science (2001) data, which represents recent scientific information. 

*** Q>R>S. 
196 

Exhibit 6E 

Comparison of Regulatory Benefits to Costs Under Scenario #3 – No Change to Beneficial Use @ 7% Discount Rate 

($Millions in 50-Year Present Values @2009$ Prices) 

Costs Subtitle C “Special Waste” Subtitle D (version 2) Subtitle “D prime” 

1. Engineering Controls $6,780 $3,254 $3,254 

2. Ancillary Costs $1,480 $5 $5 

3. Dry Conversion $12,089 4,836 $0 

Total Costs (1+2+3) = $20,349 $8,095 $3,259 

Benefits 

4. Groundwater Protection Benefits* $970 $375 $188 

 Count of Human Cancer Risks Avoided** 726 296 148 

 Monetized Value of Human Cancer Risks Avoided $504 $207 $104 

 Groundwater Remediation Costs Avoided $466 $168 $84 

5. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Econ. Benefits Social benefits 

Scenario #3 @7% discount rate = $0 (no change) $0 (no change) $0 (no change) $0 (no change) $0 (no change) $0 (no change) 

6. CCR Impoundment Failure Costs Avoided 

 If Based on Extrapolated Recent Failure Cases $1,762 $793 $405 

 If Based on 10% Future Failures $8,366 $3,795 $1,897 

 If Based on 20% Future Failures $16,732 $7,590 $3,795 

7. Non-quantified Benefits*** Q R S 

Total Benefits (4+5+6): 

Total Benefits w/Extrapolated Recent Failure Cases = $2,732 $2,732 $1,168 $1,168 $593 $593 

Total Benefits @10% Future Failures = $9,336 $9,336 $4,170 $4,170 $2,085 $2,085 

Total Benefits @20% Future Failures = $17,702 $17,702 $7,965 $7,965 $3,983 $3,983 

Net Benefits (Total Benefits minus Total Costs) 

Net Benefits w/Extrapolated Recent Failure Cases = ($17,617) ($17,617) ($6,927) ($6,927) ($2,666) ($2,666) 

Net Benefits @10% Future Failures = ($11,013) ($11,013) ($3,925) ($3,925) ($1,174) ($1,174) 

Net Benefits @20% Future Failures = ($2,647) ($2,647) ($130) ($130) $724 $724 

Benefit/Cost Ratio (BCR) 

BCR w/Extrapolated Recent Failure Cases = 0.134 0.134 0.144 0.144 0.182 0.182 

BCR @10% Future Failures = 0.459 0.459 0.515 0.515 0.640 0.640 

BCR @20% Future Failures = 0.870 0.870 0.984 0.984 1.222 1.222 

Notes: 

* Cancer risk reflects the arsenic groundwater pathway only and does not include other human health mortality or morbidity risks from non-carcinogens, nor do they 

reflect ecological and socio-economic damages that could occur. Thus, the benefits are underestimated in this RIA. 

** Cancer risks avoided are based on National Academy of Science (2001) data, which represents recent scientific information. 

*** Q>R>S. 
197 

Exhibit 6F 

Comparison of Regulatory Benefits to Costs Under Scenario #3 – No Change to Beneficial Use @ 3% Discount Rate 

($Millions in 50-Year Present Values @2009$ Prices) 

Costs Subtitle C “Special Waste” Subtitle D (version 2) Subtitle “D prime” 

1. Engineering Controls $12,640 $6,067 $6,067 

2. Ancillary Costs $2,759 $9 $9 

3. Dry Conversion $22,538 $9,016 $0 

Total Costs (1+2+3) = $37,938 $15,092 $6,076 

Benefits 

4. Groundwater Protection Benefits* $3,316 $1,321 $661 

 Count of Human Cancer Risks Avoided** 726 296 148 

 Monetized Value of Human Cancer Risks Avoided $1,825 $750 $375 

 Groundwater Remediation Costs Avoided $1,491 $571 $286 

5. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Econ. Benefits Social benefits 

Scenario #3 @3% discount rate = $0 (no change) $0 (no change) $0 (no change) $0 (no change) $0 (no change) $0 (no change) 

6. CCR Impoundment Failure Costs Avoided 

 If Based on Extrapolated Recent Failure Cases $3,124 $1,406 $719 

 If Based on 10% Future Failures $13,046 $5,918 $2,959 

 If Based on 20% Future Failures $26,092 $11,836 $5,918 

7. Non-quantified Benefits*** Q R S 

Total Benefits (4+5+6): 

Total Benefits w/Extrapolated Recent Failure Cases = $6,440 $6,440 $2,727 $2,727 $1,380 $1,380 

Total Benefits @10% Future Failures = $16,362 $16,362 $7,239 $7,239 $3,620 $3,620 

Total Benefits @20% Future Failures = $29,408 $29,408 $13,157 $13,157 $6,579 $6,579 

Net Benefits (Total Benefits minus Total Costs) 

Net Benefits w/Extrapolated Recent Failure Cases = ($31,498) ($31,498) ($12,365) ($12,365) ($4,696) ($4,696) 

Net Benefits @10% Future Failures = ($21,576) ($21,576) ($7,853) ($7,853) ($2,456) ($2,456) 

Net Benefits @20% Future Failures = ($8,530) ($8,530) ($1,935) ($1,935) $503 $503 

Benefit/Cost Ratio (BCR) 

BCR w/Extrapolated Recent Failure Cases = 0.170 0.170 0.181 0.181 0.227 0.227 

BCR @10% Future Failures = 0.431 0.431 0.480 0.480 0.596 0.596 

BCR @20% Future Failures = 0.775 0.775 0.872 0.872 1.083 1.083 

Notes: 

* Cancer risk reflects the arsenic groundwater pathway only and does not include other human health mortality or morbidity risks from non-carcinogens, nor do they 

reflect ecological and socio-economic damages that could occur. Thus, the benefits are underestimated in this RIA. 

** Cancer risks avoided are based on National Academy of Science (2001) data, which represents recent scientific information. 

*** Q>R>S. 
198 

6B. Factors Applied for Scaling Benefits and Costs to the Three 2010 Regulatory Options 

The regulatory compliance cost estimation presented in Chapter 4 of this RIA was initially formulated with reference to the October 2009 

draft RIA regulatory options. Furthermore, the regulatory benefits evaluation in Chapter 5 of this RIA was based only on the 2010 regulatory 

options. To resolve this inconsistency in scope between the two different sets of regulatory options evaluated for costs and for benefits, 

respectively, this RIA applies the scaling factors (i.e., percentage extrapolation multipliers) displayed below in Exhibit 6F. 

The cost analysis presented in Chapter 4 of this RIA is built upon a detailed (i.e., plant-by-plant for all 495 coal-fired electric utility plants) 

engineering cost model which estimated "engineering control" costs associated with the RCRA 3004(x) custom-tailored technical standards of 

the 2009 regulatory options (i.e., Subtitle C "hazardous waste" option, Subtitle D non-hazardous waste option requiring composite liners for 

new CCR disposal units, and a "hybrid" C/D option). Although the engineering control costs were the same for each of the three October 2009 

options, "ancillary costs" differed according to whether an option was formulated in reference to Subtitle C or to Subtitle D authority. For 

example, only the Subtitle C "hazardous waste" option and the Subtitle C component of the "Hybrid C/D" option required the cost associated 

with manifesting offsite shipments of CCR between coal-fired electric utility plants and offsite CCR disposal locations. The October 2009 

draft RIA presented the "dry conversion cost" element as a separable "sub-option" for both the Subtitle C and Subtitle D options. 

However, in 2010 EPA identified a different set of three regulatory options to describe in the proposed rule and evaluate in RIA (i.e., Subtitle C 

"special waste" option with wet disposal phase-out, Subtitle D option which in effect would phase-out wet CCR disposal by requiring 

retrofitting existing impoundments with composite liners, and a Subtitle "D prime" option requiring liners only for new disposal units). In 

order to meet EPA_s end-of-March 2010 internal deadline for completing the 2nd draft of this RIA, EPA did not revised the Chapter 4 cost 

analysis or the Chapter 7 supplemental analyses, but applied scaling factors for bridging the cost estimates to the 2010 options. Numerically, 

the scaling factors represent alternative compliance rate assumptions in relation to the 2009 draft RIA_s Subtitle C "hazardous waste" option as 

a reference case for both cost and benefit estimate scaling to the three 2010 regulatory options. The scaling factors assume less compliance 

under the non-Federally enforceable Subtitle D based options compared to the Federally-enforceable Subtitle C option. Section 6B of this RIA 

provides the numerical values assigned to the scaling factors on an itemized basis according to the separate cost element and benefit element 

categories, for each of the three 2010 regulatory options. 

Exhibit 6F 

Scaling Factors (Extrapolation Multipliers) Applied in this RIA to Estimate the Costs & Benefits 

of the 2010 Regulatory Options for CCR Disposal 

Economic Impact Category Subtitle C 

Special Waste 

Subtitle D 

(version 2) 

Subtitle 

gD primeh 

Regulatory Compliance Costs: 

1. Engineering control costs 100% 48% 48% 

2. Ancillary costs 100% 48% 48% 

3. Dry conversion costs 100% 40% 0% 

Regulatory Benefits: 
199 

Exhibit 6F 

Scaling Factors (Extrapolation Multipliers) Applied in this RIA to Estimate the Costs & Benefits 

of the 2010 Regulatory Options for CCR Disposal 

Economic Impact Category Subtitle C 

Special Waste 

Subtitle D 

(version 2) 

Subtitle 

gD primeh 

1. Groundwater contamination prevention benefits: 

 Groundwater remediation costs avoided 100% 48% 30% 

 Monetized value of human cancer risks avoided 100% 48% 30% 

2. Impoundment structural failure cleanup costs avoided 100% 45% 23% 

3. Induced impact on CCR beneficial use: 

 Scenario #1: Induced increase 

 Scenario #2: Induced decrease 

 Scenario #3: No change 

100% 

100% 

Not relevant 

40% 

None (0%) 

Not relevant 

16% 

None (0%) 

Not relevant 

The following two sub-sections (6B.1 and 6B.2) provide explanation and documentation of the scaling factors displayed in Exhibit 6F above. 

6B.1 Regulatory Cost Scaling Factors 

o Engineering control costs: For both RCRA subtitle C and subtitle D, the engineering control costs would be identical under both 

options. However, state governments are not required to develop comparable programs under RCRA Subtitle D rules, and states 

cannot enforce Federal subtitle D rules. In addition, because of the nature of subtitle D authority, individual requirements (e.g., 

groundwater monitoring, impoundment closure) will be more generic, allowing industry great latitude in complying. Thus, 

actual costs under Subtitle D options will be lower than under Subtitle C, because facilities would not be expected to comply to 

the same extent. In estimating future annual tons of CCR that might be managed under new standards, and the extent to which 

they would be similar under the Subtitle C option, this RIA applies the percentage of tons of CCR disposed in states with 

groundwater monitoring requirements as a way to estimate the likely costs incurred by industry for the other options. Although

the engineering control cost category consists of 10 cost elements as defined in this RIA, the percentage of states with 

groundwater monitoring programs is a reasonable surrogate indicator because states imposing groundwater monitoring 

requirements indicates which states will generally address specific units, and which are likely to upgrade their programs under

subtitle D, if EPA were to issue a national subtitle D rule. In those states, management standards may significantly improve, 

although not to the level of subtitle C for the reasons discussed above. On the other hand, certainly some facilities in states 

without programs will choose to comply with the national regulation (taking full advantage of the more generic nature of the 

federal D standards). Taking these two factors together, using the percentage of CCR disposed in states with groundwater 

monitoring programs provides a reasonable estimate of the extent to which facilities will take steps to comply with the national 

standards, and therefore of the costs of compliance. For the federally-enforceable subtitle C option, the cost recognizes that all 

states (100%) will be required by the CCR rule to install groundwater monitoring (and all other engineering controls). For both 

the non-federally enforceable subtitle D and the gD primeh options, the cost estimates assume that the 48% of waste disposed of

in states that currently require surface impoundments to have groundwater monitoring (either for new units only or for new and 
200 

existing units) will generally upgrade their programs, improving compliance, and that a modest number of facilities in other 

states would independently make efforts to comply v giving an overall estimate of 48%. This 48% is applied as a scaling factor

multiplier to estimate engineering control costs for both the Subtitle D and gD primeh in relation to the Subtitle C engineering 

cost estimate. 

o Ancillary costs: The RIA separately estimated gancillaryh costs under both Subtitle C and Subtitle D assuming 100% 

nationwide adoption. For the Subtitle D or gD primeh options, the cost estimate only includes inspections of surface 

impoundments by qualified engineers. The same logic applies to this requirement as it does to the engineering controls, and 

therefore this RIA applied the same 48% scaling factor multiplier relative to the Subtitle D ancillary cost estimates. 

o Dry conversion costs: For the dry conversion cost, 40% is only applied as a scaling multiplier under the Subtitle D option 

because the gD primeh option does not require dry conversion. The 40% value is calculated in Exhibit 6G below, which is 

based in part on assuming that the cost for retrofitting or building new impoundments is 63% of the cost of dry conversion under 

Subtitle C as calculated in Exhibit 6H below. 

Exhibit 6G 

Estimate of Subtitle D (version 2) Impoundment Liner Retrofit or Build New Lined Impoundment Cost 

A B C D E F G (D x F x 63%**) 

Row Year 

Count of existing 

electric utility 

plants with 

impoundments 

Subtitle C 

special waste: 

Dry Conversion Cost 

Percent existing CCR 

impoundments 

with composite 

liners* 

Percent of CCR 

impoundments 

without 

composite liners 

Subtitle D (v.2): 

Must Retrofit or 

Build New Lined 

Impoundments 

1 2012 158 $22,984,000,000 5.5% 94.5% $13,709,900,000 

2 2013 158 $0 5.5% 94.5% $0 

3 2014 158 $0 5.5% 94.5% $0 

4 2015 158 $0 5.5% 94.5% $0 

5 2016 158 $0 5.5% 94.5% $0 

6 2017 158 $15,800,000 5.5% 94.5% $9,400,000 

7 2018 158 $15,800,000 5.5% 94.5% $9,400,000 

8 2019 158 $15,800,000 5.5% 94.5% $9,400,000 

9 2020 158 $15,800,000 5.5% 94.5% $9,400,000 

10 2021 158 $15,800,000 5.5% 94.5% $9,400,000 

11 2022 158 $15,800,000 5.5% 94.5% $9,400,000 

12 2023 158 $15,800,000 5.5% 94.5% $9,400,000 

13 2024 158 $15,800,000 5.5% 94.5% $9,400,000 

14 2025 158 $15,800,000 5.5% 94.5% $9,400,000 

15 2026 158 $15,800,000 5.5% 94.5% $9,400,000 

16 2027 158 $15,800,000 5.5% 94.5% $9,400,000 

17 2028 158 $15,800,000 5.5% 94.5% $9,400,000 

18 2029 158 $15,800,000 5.5% 94.5% $9,400,000 

19 2030 158 $15,800,000 5.5% 94.5% $9,400,000 

20 2031 158 $15,800,000 5.5% 94.5% $9,400,000 
201 

Exhibit 6G 

Estimate of Subtitle D (version 2) Impoundment Liner Retrofit or Build New Lined Impoundment Cost 

A B C D E F G (D x F x 63%**) 

Row Year 

Count of existing 

electric utility 

plants with 

impoundments 

Subtitle C 

special waste: 

Dry Conversion Cost 

Percent existing CCR 

impoundments 

with composite 

liners* 

Percent of CCR 

impoundments 

without 

composite liners 

Subtitle D (v.2): 

Must Retrofit or 

Build New Lined 

Impoundments 

21 2032 158 $15,800,000 5.5% 94.5% $9,400,000 

22 2033 158 $15,800,000 5.5% 94.5% $9,400,000 

23 2034 158 $15,800,000 5.5% 94.5% $9,400,000 

24 2035 158 $15,800,000 5.5% 94.5% $9,400,000 

25 2036 158 $15,800,000 5.5% 94.5% $9,400,000 

26 2037 158 $15,800,000 5.5% 94.5% $9,400,000 

27 2038 158 $15,800,000 5.5% 94.5% $9,400,000 

28 2039 158 $15,800,000 5.5% 94.5% $9,400,000 

29 2040 158 $15,800,000 5.5% 94.5% $9,400,000 

30 2041 158 $15,800,000 5.5% 94.5% $9,400,000 

31 2042 158 $15,800,000 5.5% 94.5% $9,400,000 

32 2043 158 $15,800,000 5.5% 94.5% $9,400,000 

33 2044 158 $15,800,000 5.5% 94.5% $9,400,000 

34 2045 158 $15,800,000 5.5% 94.5% $9,400,000 

35 2046 158 $15,800,000 5.5% 94.5% $9,400,000 

36 2047 158 $15,800,000 5.5% 94.5% $9,400,000 

37 2048 158 $15,800,000 5.5% 94.5% $9,400,000 

38 2049 158 $15,800,000 5.5% 94.5% $9,400,000 

39 2050 158 $15,800,000 5.5% 94.5% $9,400,000 

40 2051 158 $22,984,000,000 5.5% 94.5% $13,709,900,000 

41 2052 158 $15,800,000 5.5% 94.5% $9,400,000 

42 2053 158 $15,800,000 5.5% 94.5% $9,400,000 

43 2054 158 $15,800,000 5.5% 94.5% $9,400,000 

44 2055 158 $15,800,000 5.5% 94.5% $9,400,000 

45 2056 158 $15,800,000 5.5% 94.5% $9,400,000 

46 2057 158 $15,800,000 5.5% 94.5% $9,400,000 

47 2058 158 $15,800,000 5.5% 94.5% $9,400,000 

48 2059 158 $15,800,000 5.5% 94.5% $9,400,000 

49 2060 158 $15,800,000 5.5% 94.5% $9,400,000 

50 2061 158 $15,800,000 5.5% 94.5% $9,400,000 

Non-discounted total cost = $46,663,000,000 $27,833,000,000 

Non-discounted average cost = $933,000,000 $557,000,000 

Present value cost (@7% disc.) = $23,167,000,000 $13,819,000,000 

Average annualized cost (@7%) = $1,679,000,000 $1,001,000,000 

Percent reduction in annualized cost compared to Subtitle C Option conversion cost = 40% 

Notes: 
202 

Exhibit 6G 

Estimate of Subtitle D (version 2) Impoundment Liner Retrofit or Build New Lined Impoundment Cost 

A B C D E F G (D x F x 63%**) 

Row Year 

Count of existing 

electric utility 

plants with 

impoundments 

Subtitle C 

special waste: 

Dry Conversion Cost 

Percent existing CCR 

impoundments 

with composite 

liners* 

Percent of CCR 

impoundments 

without 

composite liners 

Subtitle D (v.2): 

Must Retrofit or 

Build New Lined 

Impoundments 

* 5.5% existing impoundments with composite liners based on EPA_s 2000 CCR regulatory determination and on the August 2006 

joint EPA-DOE survey report. 

** EPA estimated the capital and annual O&M costs for the Subtitle D requirement for either retrofitting or building new CCR 

impoundments with composite liners, by assuming that the cost for those requirements are 63% of the $23.167 billion present value 

cost for dry conversion under the Subtitle C option. This 63% cost scaling factor is calculated in Exhibit 6H of this RIA. 

Exhibit 6H 

Reference Data for Calculation of "63% Cost Scaling Factor" Applied in Exhibit 6G

Capital cost O&M cost Row total Percent Capital cost Percent 

Dry Coal Ash Management (35-year lifespan cost in 1980$)

1 In-plant handling system $19,500,000 $693,100,000 $712,600,000 76% $19,500,000 23% 

2 Conveyance (transport) $10,364,000 $116,996,000 $127,360,000 14% $10,364,000 12% 

3 Disposal (lined landfill) $53,952,000 $39,926,000 $93,878,000 10% $53,952,000 64% 

 Total = $83,816,000 $850,022,000 $933,838,000 100% $83,816,000 100% 

Wet Coal Ash Management (35-year lifespan cost in 1980$)

1 In-plant handling system $8,500,000 $302,121,000 $310,621,000 69% $8,500,000 9% 

2 Conveyance (transport) $31,954,000 $42,140,000 $74,094,000 16% $31,954,000 34% 

3 Disposal (lined impoundment) $52,906,000 $14,448,000 $67,354,000 15% $52,906,000 57% 63%* 

 Total = $93,360,000 $358,709,000 $452,069,000 100% $93,360,000 100% 

Source: Based on cost data for an example 2600 megawatt (MW) nameplate capacity electric utility plant from pages B-8 (dry) and C-9 (wet) of the 

EPA/TVA joint study gEconomic Analysis of Wet Versus Dry Ash Disposal Systems: Interagency Energy/Environment R&D Program Report,h report nr. 

EPA-600/7-81-013, January 1981: http://nepis.epa.gov/Exe/ZyPURL.cgi?Dockey=20006ORT.txt

* EPA estimated the capital and annual O&M costs for the Subtitle D requirement for either retrofitting or building new CCR impoundments with 

composite liners, by assuming that the cost for those requirements are 63% of the $23.167 billion present value cost for dry conversion under the Subtitle C 

option. This 63% cost scaling factor is calculated in this exhibit. 

6B.2 Regulatory Benefits Scaling Factors 

o Groundwater contamination benefits: Percentages are based on an examination of state programs related to groundwater 

monitoring requirements as described in Chapter 5 of this RIA. The percentages given in Exhibit 6F above refer only to the 

input values to the estimation of groundwater protection benefits presented in Chapter 5 of this RIA. For the Subtitle C option, 

all states will be required by the rule to have groundwater monitoring in place so that 100% of facilities over the baseline would 
203 

detect contamination early and thus human cancers would be prevented. For the Subtitle D option, 48% of CCR are placed in 

surface impoundments in states with groundwater monitoring in place for new units only (or for new and existing units). It is 

likely that these states with some level of attention to groundwater monitoring would increase their attention (e.g., because they 

already have a RCRA program infrastructure) to groundwater monitoring, providing for much more effective systems, while 

other states would tend not to (although some individual facilities within those states would upgrade groundwater monitoring to

some extent). Thus, this RIA estimates that overall, the new regulation would result in 48% of facilities detecting contamination 

early and 48% of cancers would be prevented. For the Subtitle D prime option, retrofitting existing units would not be required, 

and therefore existing and future releases would continue to occur from unlined surfaced impoundments. Currently 12% of 

CCR are placed in surface impoundments in states with groundwater monitoring. Some of these states would certainly upgrade 

their regulations, but given that surface impoundments would remain a potential source of release in all states, the Subtitle D

prime option is less protective of groundwater than the Subtitle D option. Since this fraction is likely to fall between 48% and 

12%, the mid-point of 30% was chosen as a best estimate for the D prime option. 

o Impoundment structural failure cleanup costs avoided: This factor is not based on estimates of percentages of states likely to 

implement the new requirements (which for subtitle D would require liners for existing surface impoundments); it is unlikely 

that many states will choose to implement this requirement. Instead, compliance will not be enforceable, and will be left up to 

self-imposed schedules of industry or citizens suits. While most impoundments may eventually close, it will be a lengthy 

process. As a general estimate, through delaying closures and lengthening the process, industry may be able to reduce costs by 

50%. In addition, since 5.5% of surface impoundments have composite liners already, they would remain in place, and therefore 

would not incur costs. Taking these figures together, this RIA applies a 45% scaling factor for this benefit. 

o Induced impact on CCR beneficial uses: 

 Under Scenario #1 induced increase in beneficial use, beneficial uses are assumed to be linear with respect to total costs 

because increases in usage are directly proportional to the cost of the regulatory options. Therefore, under the Subtitle D 

option, the net reduction in total costs compared to the Subtitle C option is 40%. Under the Subtitle gD primeh option, 

since the dry conversion costs are 0%, a net result of 16% was applied. This percentage was derived by dividing the 

Subtitle gD primeh option cost by the total cost of Subtitle C. 

 Under Scenario #2 induced decrease in beneficial use, for the reasons described in Section 5C of this RIA, this RIA 

assumes that potential induced future decrease on beneficial use only applies to the Subtitle C regulatory option, not to 

the Subtitle D-based options. 

 Under Scenario #3 no change in beneficial use (relative to baseline), there is no impacts under any of the regulatory 

options, so no scaling assumptions are applied. 
204 

Chapter 7

Supplemental Analyses Required by Congressional Statutes or White House Executive Orders 

Note: The computations presented in this Chapter are based on the cost estimates for the October 2009 draft RIA regulatory 

options using the larger dry conversion cost estimate prior to its update in Chapter 4. Because the high-end cost of the October 

2009 draft RIA regulatory options (i.e., for the Subtitle C ghazardous wasteh option) is larger than the high-end cost for the 2010 

options (i.e., for the Subtitle C gspecial wasteh option), the effects estimated in this Chapter are proportionately over-estimated. 

7A. Electricity Price Impact (Executive Order 13211) 

The 2001 Executive Order 13211168 gActions Concerning Regulations that Significantly Affect Energy Supply, Distribution, or Useh requires 

Federal agencies to evaluate and prepare a statement on any potential adverse effects of economically-significant rulemakings on energy 

supply, distribution or use, including: 

x Shortfall in energy supply 

x Energy price increases 

x Increased use of foreign energy supplies 

The OMB_s 13 July 2001 Memorandum M-01-27169 guidance for implementing this Executive Order identifies nine numerical indicators 

(thresholds) of potential adverse energy effects, three of which are relevant for evaluation in this RIA: 

x Increases in the cost of energy production in excess of 1%

x Increases in the cost of energy distribution in excess of 1%

x Other similarly adverse outcomes.

Because this RIA did not collect and analyze data on energy production cost or energy distribution cost, this RIA evaluated the potential impact 

of the CCR regulatory options on electricity prices relative to the 1% threshold of both indicators as an indicator of gother similarly adverse 

outcomeh. This RIA calculated the potential increase in statewide electricity prices that the industry compliance costs might induce under each 

CCR regulatory option. This calculation involved plant-by-plant annual revenue estimates and annualized compliance cost estimates, and 

respective statewide average electricity prices for the 495 electric utility plants, according to the following four steps. 

 

168 The 18 May 2001 EO-13211 is available at: http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=2001_register&docid=fr22my01-133.pdf 169 OMB_s 13 July 2001 Memorandum M-01-27 is available at: http://www.whitehouse.gov/omb/memoranda_m01-27/ 
205 

x Step 1: Downloaded the annual million megawatt capacity data for each of the 495 plants from the DOE-EIA website (2007), and 

estimated annual electricity output for each plant, by multiplying the capacity data by three factors: 

o 365 operating days per year 

o 24 operating hours per day 

o 86.8% capacity utilization per year170

x Step 2: Estimated the annual electricity sales revenue for each plant by multiplying the estimated annual electricity output sold by each 

plant (from Step 1), by the respective statewide average retail price (May 2009) of electricity for all sectors (i.e., residential, commercial, 

industrial, transportation) from DOE-EIA at http://www.eia.doe.gov/cneaf/electricity/epm/table5_6_a.html

x Step 3: Added the estimated incremental regulatory costs on a plant-by-plant basis, to the estimated annual electricity sales revenue for 

each plant, to obtain a hypothetical future annual revenue target, which represents a 100% cost pass-thru scenario. This simple scenario 

represents an upper-bound case of potential electricity price increase. Furthermore, if this 100% cost pass-thru is averaged over the entire 

electricity supply in each state, not just averaged over the 495 coal-fired electricity plants as done in this RIA, the potential percentage 

increase in electricity price would be less than this upper-bound case presented in this RIA. 

x Step 4: Divided the hypothetical future annual revenue target by the estimated annual electricity output for each plant, to obtain a 

hypothetical future (higher) target price for each plant, which incorporates the added regulatory cost. Compared the higher target price to 

the current price to calculate the potential price increase on a percentage basis for each of the 495 plants. 

Exhibit 7A below presents the findings of this energy price evaluation on a state-by-state basis. As displayed in the bottom row of Exhibit 

7A, none of the options have an expected nationwide average energy price increase >1%. Appendix L presents the plant-by-plant calculation 

spreadsheet used for this electricity price impact analysis. 

Exhibit 7A 

State by State Breakout of Average Electricity Price Increases Per Option 

Item 

Number of 

Plants State 

May 2009 

statewide average 

electricity price ($ 

per kilowatt hour) 

Subtitle C 

hazardous waste 

Average Price 

Increase 

Subtitle D 

(version 1) 

Average Price 

Increase 

C - impoundments 

D - landfills 

Average Price 

Increase 

Average annualized cost (from Exhibit 4F) = $2,274 $492 $2,176 

1 2 AK $0.1518 1.30% 1.23% 1.25% 

2 10 AL $0.0856 1.43% 0.189% 1.419% 

 

170 Source: 86.8% capacity utilization is the 1972-2008 annual average published in the 15 May 2009 Federal Reserve Statistical Release G.17 gIndustrial Production & 

Capacity Utilizationh data for Utilities at http://www.federalreserve.gov/releases/g17/Current/default.htm 
206 

Exhibit 7A 

State by State Breakout of Average Electricity Price Increases Per Option 

Item 

Number of 

Plants State 

May 2009 

statewide average 

electricity price ($ 

per kilowatt hour) 

Subtitle C 

hazardous waste 

Average Price 

Increase 

Subtitle D 

(version 1) 

Average Price 

Increase 

C - impoundments 

D - landfills 

Average Price 

Increase 

3 3 AR $0.0762 0.293% 0.225% 0.283% 

4 6 AZ $0.1002 1.141% 0.622% 1.113% 

5 6 CA $0.1337 0.717% 0.676% 0.687% 

6 14 CO $0.0797 0.121% 0.006% 0.017% 

7 2 CT $0.1712 0.074% 0.000% 0.000% 

8 0 DC $0.1337 

9 3 DE $0.1236 0.156% 0.127% 0.129% 

10 15 FL $0.1136 0.131% 0.077% 0.113% 

11 11 GA $0.0859 1.160% 0.163% 1.152% 

12 2 HI $0.1892 0.245% 0.171% 0.174% 

13 19 IA $0.0710 0.548% 0.198% 0.537% 

14 0 ID $0.0602 

15 25 IL $0.0924 0.531% 0.099% 0.488% 

16 26 IN $0.0766 1.387% 0.207% 1.348% 

17 8 KS $0.0822 0.545% 0.190% 0.532% 

18 21 KY $0.0640 2.307% 0.593% 2.237% 

19 4 LA $0.0748 0.464% 0.040% 0.462% 

20 4 MA $0.1534 0.027% 0.000% 0.000% 

21 8 MD $0.1316 0.080% 0.017% 0.037% 

22 1 ME $0.1222 0.520% 0.346% 0.352% 

23 22 MI $0.0986 0.459% 0.052% 0.455% 

24 16 MN $0.0804 2.013% 0.471% 1.993% 

25 20 MO $0.0757 0.817% 0.116% 0.798% 

26 5 MS $0.0893 0.197% 0.106% 0.193% 

27 5 MT $0.0720 5.582% 1.193% 5.531% 

28 22 NC $0.0839 1.122% 0.148% 1.102% 

29 7 ND $0.0698 0.994% 0.012% 0.982% 

30 7 NE $0.0705 0.223% 0.206% 0.210% 

31 2 NH $0.1544 0.055% 0.004% 0.004% 

32 7 NJ $0.1421 0.118% 0.045% 0.045% 

33 3 NM $0.0769 2.103% 0.407% 1.729% 

34 2 NV $0.0960 0.548% 0.518% 0.526% 

35 13 NY $0.1543 0.024% 0.000% 0.000% 

36 26 OH $0.0930 1.193% 0.132% 1.157% 

37 6 OK $0.0698 0.151% 0.050% 0.081% 

38 1 OR $0.0751 0.212% 0.200% 0.204% 

39 34 PA $0.0960 0.702% 0.229% 0.665% 
207 

Exhibit 7A 

State by State Breakout of Average Electricity Price Increases Per Option 

Item 

Number of 

Plants State 

May 2009 

statewide average 

electricity price ($ 

per kilowatt hour) 

Subtitle C 

hazardous waste 

Average Price 

Increase 

Subtitle D 

(version 1) 

Average Price 

Increase 

C - impoundments 

D - landfills 

Average Price 

Increase 

40 0 RI $0.1343 

41 14 SC $0.0826 0.394% 0.028% 0.384% 

42 2 SD $0.0742 0.098% 0.084% 0.086% 

43 7 TN $0.0860 0.517% 0.001% 0.504% 

44 19 TX $0.1019 0.292% 0.038% 0.256% 

45 6 UT $0.0690 0.602% 0.336% 0.588% 

46 16 VA $0.0916 0.688% 0.078% 0.629% 

47 0 VT $0.1282 

48 1 WA $0.0684 0.000% 0.000% 0.000% 

49 17 WI $0.0918 0.082% 0.063% 0.078% 

50 16 WV $0.0668 1.441% 0.615% 1.379% 

51 9 WY $0.0602 1.396% 0.315% 1.351% 

Summary:

Minimum = $0.0602 0.0000% 0.0000% 0.0000% 

Maximum = $0.1892 5.5822% 1.2259% 5.5313% 

Average = $0.0985 0.7489% 0.2259% 0.7076% 

Median = $0.0860 0.5205% 0.1316% 0.4876% 

Nationwide = $0.0884 0.795% 0.172% 0.761% 

Because this price analysis is based only on the 495 potentially affected coal-fired electric utility plants (with 333,500 megawatts nameplate 

capacity) rather than on all electric utility and independent electricity producer plants in each state using other fuels such as natural gas, 

nuclear, hydroelectric, etc. (with 678,200 megawatts nameplate capacity), these price effects are higher than would be if the regulatory costs 

were averaged over the entire electric utility and independent electricity producer supply (totaling 1,011,700 megawatts, not counting the 

76,100 megawatts of combined heat and electricity producers).171

x Electricity Impact Findings 

On a nationwide basis for all 495 plants, compared to the estimated average electricity price of $0.0884 per kilowatt-hour across the 495 plants, 

the 100% regulatory cost pass-thru scenario may increase prices for the 495 plants by 0.172% to 0.795% across the regulatory options. None 

of the regulatory options exceed the 1% threshold of EO 13211, thus this RIA does not include a gStatement of Energy Effecth as would be 

required by Section 1 of EO 13211 if the price impact indicator as estimated in this RIA exceeded 1%.

 

171 Source: 2007 megawatt nameplate capacity data from the Energy Information Administration gTable 2.3. Existing Capacity by Producer Type, 2007h at 

http://www.eia.doe.gov/cneaf/electricity/epa/epaxlfile2_3.pdf 
208 

7B. Small Business Impact Analysis (RFA/SBREFA)

According to the requirements of the 1980 Regulatory Flexibility Act (RFA) as amended by the 1996 Small Business Regulatory Enforcement 

Fairness Act (SBREFA), Federal regulatory agencies are required to make initial determinations if proposed regulatory actions may have a 

gsignificant economic impact on a substantial number of small entitiesh (SISNOSE). Small entities include small businesses, small 

organizations, and small governmental jurisdictions. Agencies are required to conduct a Regulatory Flexibility Screening Analysis (RFSA) to 

make this determination. This section of the RIA presents the methodology and findings for the RFSA conducted for the proposed rule. 

Unless Agencies are able to certify that a particular regulatory action is not expected to have a SISNOSE, the RFA/SBREFA requires a formal 

analysis of the potential adverse economic impacts on small entities, completion of a Small Business Advocacy Review Panel (proposed rule 

stage), preparation of a Small Entity Compliance Guide (final rule stage), and Agency review of the rule within 10 years of promulgation. 

The small business impact analysis of this RIA follows the four analytic steps described in EPA_s RFA/SBREFA analysis guidance172: 

Step 1: Determine which small entities are subject to the rule_s requirements 

Step 2: Select appropriate measures for determining economic impacts on these small entities and estimate those impacts 

Step 3: Determine whether the rule may be certified as not having a significant impact on small entities (SISNOSE) 

Step 4: Document the screening analysis and include the appropriate RFA statements in the preamble 

x Step 1: Identification of Small Entities 

The scope of entities addressed by this analysis includes the affected coal-fired electric utility plants in NAICS code 221112. Not included in 

the scope of this RFA/SBREFA analysis are offsite commercial landfills which currently receive and dispose CCR generated by electric utility 

plants. EPA_s RCRA statute does not provide EPA with authority to collect information from solid waste facilities; it only provides EPA with 

authority to collect information from RCRA-regulated hazardous waste management facilities (via the RCRA biennial report). EPA does not 

know the identity, company size, or other information about the offsite landfills currently used by the electric utility industry. Therefore, this 

RFA/SBREFA analysis is limited to only electric utility plants. Consistent with EPA_s RFA/SBREFA guidance (page 15), this RIA applies the 

following small size definitions for owner entities of electric utility plants: 

Small company: Based on the US Small Business size standard for NAICS code 221112 (fossil fuel electric utility plants): a 

company which generates less than 4 million megawatt-hours electricity output per year. 

 

172 EPA_s RFA/SBREFA guidance: gEPA_s Action Development Process: Final Guidance for EPA Rulewriters: Regulatory Flexibility Act as amended by the Small 

Business Regulatory Enforcement Fairness Acth, EPA Office of Policy, Economics & Innovation, Nov 2006, 105 pages: 

http://www.epa.gov/sbrefa/documents/rfaguidance11-00-06.pdf 
209 

Small government: Based on the RFA/SBREFA_s definition (5 US Code section 601(5)) of small government jurisdiction as the 

government of a city, county, town, township, village, school district, or special district with population <50,000. 

Based on the nameplate megawatt (MW) capacity for all electricity generating units (including those powered by non-coal fuel types) at each 

electricity plant from the 2007 DOE-EIA 860 database, this RIA estimated annual megawatt-hours electricity generation capacity by 

multiplying the nameplate capacity by (a) 365 days per year, and (b) 24 hours per day to calculate each owner entity_s annual electricity 

capacity. Appendix D of this RIA indicates the assigned size of the owner company or city government for each electric utility plant according 

to two size categories: gSmallh or gNon-smallh.173 Exhibit 7B below presents the resultant count and summary of the characteristics of the 

small electric utility entities as estimated in this RIA. 

Exhibit 7B 

Summary of Characteristics of Small Electric Utility Entities 

A B C D E (D / B) 

Small Entity Sub-Categories 

Count of coalfired electric 

utility plants 

(2005/2007) 

Estimated count of 

owner entities 

(2005/2007) 

Estimated 2007 annual 

megawatt hours (mwh) 

capacity for all electricity 

plants owned by all 

entities 

Estimated 2009 

annual electricity 

sales for all entities 

($millions/year) 

2009 average annual 

electricity sales 

revenue per entity 

($millions/year) 

1. Small City Government 33 33 34.0 $2,592 $78.5 

2. Small Company 12 11 10.6 $948 $86.2 

3. Small Cooperative 6 6 12.0 $947 $157.8 

4. Small County Government 1 1 0.3 $23 $23 

Summary: 

All small entities = 52 plants 

(11%) 

51 entities 

(26%) 

 56.8 

(1%) 

$4,509 

(1%) 

$88.4 

All non-small entities = 443 plants 

(89%) 

149 entities 

(74%) 

5,380.5 

(99%) 

$419,056 

(99%) 

$2,812.5 

All entities (non-small + small) = 495 plants 200 entities 5,437 million mwh* $423,565** $2,118 

Notes: 

* Annual electricity generation capacity based on all electric plants and types of electric generation units (e.g. coal-fired, oil-fired, hydropower, nuclear, 

wind, biomass, etc.) owned by these companies, not just coal-fired electricity generation capacity. 

** $423.6 billion per year annual electricity sales estimated in this RIA is 73% of the $581.6 billion per year total revenues reported for NAICS code 22 

(Utilities sector) in the 2007 Economic Census at: http://factfinder.census.gov/servlet/IBQTable?_bm=y&-geo_id=D&-ds_name=EC0700A1&-_lang=en 

 

173 It should be noted that some of the companies identified as small using the SBA size standard for NAICS 22 and the utility code specification in the 2007 EIA 860 

database to identify each corporate entity may be subsidiaries of a larger holding company (classified under a different NAICS) rather than a larger power company. In 

addition some of these power companies may have merged. For example, State Line is owned by Dominion Resources of Virginia, Northeastern Power is owned by Suez 

Energy North America, Inc. (SEGNA), Rio Bravo Poso and Rio Bravo Jasmin are owned by the North American Power Group, Ltd (NAPG), TES Filer City Station LP is 

owned by TONDU, Public Service Enterprise Group (PSEG) and Excelon are merged. This approach likely overstates the number of small entities. 
210 

x Step 2: Measures for Determining Economic Impacts on Small Entities 

According to Exhibit 1 of EPA_s 2006 RFA/SBREFA small business impact analytic guidance, there are the following suggested tests that may 

be used to determine if small entities may be significantly impacted by a proposed rule: 

x Small business impact tests: 

o Sales test: Annualized compliance costs as a percentage of sales 

o Cash flow test:Debt-financed capital compliance costs relative to current cash flow 

o Profit test: Annualized compliance costs as a percentage of profits 

x Small government impact tests: 

o Revenue test: Annualized compliance costs as a percentage of annual government revenues 

o Income test: Annualized compliance costs to household (per capita) as a percentage of median household (per capita) income 

Based on annual electricity generation data for the small owner entities in the electric utility industry identified in Appendix D of this RIA, the 

annual sales/annual revenue test was used for this analysis. As itemized and estimated for each owner entity in the spreadsheets presented as 

Appendix M to this RIA, for each small entity EPA computed the respective sales revenue test percentages by the equation below: 

(AEGC x 1,000) x (ASP) x (CU) = annual $sales or $revenues per small entity 

Where: 

AEGC = Annual electricity generation capacity per-entity in annual million megawatts (per-entity megawatt data is displayed in 

Appendix D). This estimate involved downloading the annual million megawatt capacity data for each of the 495 

electricity plants from the DOE-EIA website (2007), and then multiplying the capacity data by two factors: 

o 365 operating days per year 

o 24 operating hours per day 

ASP = February 2009 average statewide retail price to ultimate consumers for electricity (i.e., cents per kilowatt-hour) for the 

relevant state or states applicable to the location of electric plants owned by each company; electricity price reflects the 

composite price charged to residential, commercial, industry and transportation sectors174 

CU = 86.8% electric utility industry capacity utilization from 1972-2008 average reported by the 15 May 2009 Federal Reserve 

Statistical Release G.17 gIndustrial Production & Capacity Utilizationh data for Utilities at: 

http://www.federalreserve.gov/releases/g17/Current/default.htm 

 

174 DOE_s Energy Information Administration (EIA) publishes state-by-state average retail electricity prices for four end-user sectors (i.e., residential, commercial, 

industrial, transportation) and on a composite basis at: http://www.eia.doe.gov/cneaf/electricity/epm/table5_6_a.html
211 

x Step 3 & Step 4: Determine and document whether the proposed rule may be certified as having “No SISNOSE” 

EPA determined whether each regulatory option may have a gsignificant impact on a substantial number of small entitiesh (i.e., SISNOSE) 

which may become subject to the requirements of the proposed rule. This determination involved comparing the estimated regulatory 

compliance costs for each entity as displayed in Appendix J of this RIA and as summarized in Exhibit 7C below (small entity row items 6, 7, 

8, 9), to the respective annual sales and revenues for each entity estimated in Step 2 above. Numerically, this comparison involved calculating 

the percentage of regulatory compliance costs relative to annual sales and revenues for each company for each of the regulatory options. Then 

compared the percentage results for each small entity to the following three impact thresholds defined in Table 2 of EPA_s RFA/SBREFA 

analytic guidance. Exhibit 7D below displays the numerical results of this analysis and the suggested RFA/SBREFA impact interpretation 

according to the three thresholds. 

<1% threshold: Annualized regulatory costs may be less then 1% of annual sales or revenues for small entities 

1% or more threshold: Annualized regulatory costs may be 1% or more of annual sales or revenues for affected small entities 

3% or more threshold: Annualized regulatory costs may be 3% or more of annual sales or revenues for affected small entities 

Exhibit 7C 

Summary of Regulatory Cost Estimates According to Electric Utility Plant Owner Entity Size/Type Category 

($millions in 2009 price level; average annual amortized @7% discount rate over 50-year period 2012 to 2061)

Size/Type of Entity* 

Count of plants 

in category*** 

Subtitle C 

Hazardous waste

Subtitle D 

(version 1) 

Subtitle C for impoundments 

Subtitle D for landfills 

1. Non-Small City 27 plants $46.9 $27.1 $43.9 

2. Non-Small Company 372 plants $1,897.2 $378.5 $1,821.2 

3. Non-Small Coop 20 plants $87.7 $34.6 $85.3 

4. Non-Small Federal 11 plants $183.2 $20.8 $181.0 

5. Non-Small State** 13 plants $41.6 $27.1 $39.8 

6. Small City 33 plants $2.8 $1.6 $2.5 

7. Small Company 12 plants $4.1 $1.9 $2.0 

8. Small Coop 6 plants $10.4 $0.3 $0.3 

9. Small County 1 plant $0.004 $0.004 $0.004 

Total all 9 categories = 495 plants*** $2,274 $492 $2,176 

Notes: 

* Size/Type classification methodology defined according to Exhibit 3B of this RIA. 

** State government costs include costs to (a) state government electric utility plants regulatory costs, plus (b) state government RCRA-authorized 

programs for option implementation. 

*** The total count of coal-fired electric utility plants is shown in the Exhibit; however, only a sub-total of 467 of the 495 may incur these 

regulatory costs because 28 plants solely supply their CCR for beneficial uses. 
212 

Exhibit 7D 

Estimated Impact of Regulatory Options on Small Entities (RFA/SBREFA Analysis Results) 

($millions average annualized direct costs @7% discount rate over 50-year period 2012-2061) 

Cost as Percentage of 

Annual Electricity Revenues 

Subtitle C 

Hazardous waste 

Subtitle D 

(version 1) 

Subtitle C for impoundments 

Subtitle D for landfills 

A. Count of Small Entities: 

Annualized cost on small entities:* $17.3 $3.8 $4.8 

Less than 1% 46 50 50 

1% or greater 5 1 1 

3% or greater 0 0 0 

B. % of Small Entities: 

Less than 1% 90% 98% 98% 

1% or greater 10% 2% 2% 

3% or greater 0% 0% 0% 

C. SISNOSE Findings: 

Less than 1% Presumed No SISNOSE Presumed No SISNOSE Presumed No SISNOSE 

1% or greater Presumed No SISNOSE Presumed No SISNOSE Presumed No SISNOSE 

3% or greater Presumed No SISNOSE Presumed No SISNOSE Presumed No SISNOSE 

* Source: 

Costs for each option based on total cost for the four small entity categories displayed as rows 6 + 7 + 8 + 9 from Exhibit 7C. 

x Limitations of RFA/SBREFA Determination 

Not included in the RFA/SBREFA analysis of this RIA are two factors unique to the electric utility industry, which may reduce the small 

entity impacts relative to the estimates above in this RIA: 

x Factor #1 of 2: According to the 2007 DOE-EIA database on electric utility plants, two-thirds of the coal-fired electricity generation 

units at electric utility plants owned by small entities can switch to at least one of six other fuels: 

1. Agricultural byproducts (database code = AB) 

2. Distillate fuel oil (DFO) 

3. Natural gas (NG) 

4. Petroleum coke (PC) 

5. Propane (PG) 

6. Wood & wood waste solids (WDS) 
213 

x Factor #2 of 2: The small business impact analysis in this RIA applies the full industry compliance cost to the revenue and sales tests. 

However, because consumer demand for electricity is (a) highly price-inelastic and (b) projected go grow by 30% by year 2025175, 

electric utility plants may be expected to pass-thru much, if not all, of their regulatory costs (pending state government utility rate 

hike approval). The next section of this RIA evaluates the possibility of regulatory compliance cost pass-thru. 

x Compliance Cost Pass-Thru Analysis 

o Ability to Raise Electricity Prices 

Traditionally, the electric utility industry has functioned as a regulated monopoly, providing essential electrical services under an exclusive 

franchise in exchange for having rates closely regulated by State public utility commissions (PUCs; sometimes called PSC public service 

commissions) and the Federal Energy Regulatory Commission (FERC). The FERC regulates rates charged for sales of bulk power between 

utilities, even if they are in the same state. It also regulates the pricing and use of transmission for wheeling, and asset transfers, including 

mergers. In most states (California de-regulated electricity in 1998), the PUCs/PSCs set allowable rates upon application by the utility, with 

other affected parties allowed to present testimony. By law the utility must recover its cost of service, which includes "prudently" incurred 

expenses and a "fair" return on equity.176

Based on the electricity ratemaking process described by the Pennsylvania PUC177as a case example, when an electric utility company seeks a 

price increase (aka rate hike), it must file a request with the PUC showing the proposed new rates and effective date, and must prove that the 

increase is needed. The utility also must notify customers at least 60 days in advance. The notice must include the amount of the proposed rate 

increase, the proposed effective date, and how much more the ratepayer can expect to pay. Under the law, the utility is entitled to recovery of 

its reasonably incurred expenses and a fair return on its investment. The PUC evaluates each utility_s request for a rate increase based on those 

criteria. During the investigation, hearings are held before an Administrative Law Judge (ALJ) at which the evidence in support of the rate 

increase is examined and expert witnesses testify. In addition, consumers are offered an opportunity to voice their opinions and give testimony. 

Briefs may be submitted by the formal parties. A recommendation to the PUC is made by the ALJ. Finally, the matter is brought before the 

Commissioners for a vote and final decision. Together with the 60-day notice period, the rate increase process takes about nine months. 

Recent (2008) examples of requested or PUC-approved electricity rate hikes are summarized in Exhibit 7E below:178 

 

175 30% additional electricity demand forecst for year 2025 relative to year 2005, from slide 17 of gEnergy & Water: Emerging Issues and Trandsh by Richard Kottenstette 

and Mike Hightower, Sandia National Laboratories, at: http://www.ct-si.org/Summit2007/spk/RKottenstette.pdf 176 Source: gElectric Utility Regulationh by Robert J. Michaels in the Concise Encyclopedia of Economics at: 

http://www.econlib.org/library/Enc1/ElectricUtilityRegulation.html 

177 Source: Pennsylvania Public Utility Commission, gThe PUC Ratemaking Process and the Role of Consumersh, January 2008 at: 

http://www.puc.state.pa.us/general/consumer_ed/pdf/Ratemaking_Complaints.pdf 178 Source: gRecent Examples of Rate Increases in Vertically Integrated Statesh, The Compete Coalition, Washington DC, 05 November 2008 at: 

http://www.competecoalition.com/resources/recent-examples-rate-increases-vertically-integrated-states 
214 

Exhibit 7E 

Summary of 2008 US Electricity Price Hikes

Item State Effective date Requested or approved price hike 

1 AL Oct 2008 14.6% 

2 CO Feb 2008 28% 

3 FL July to Oct 2008 10 to 37% (8 companies) 

4 KS 2008 15% 

5 MO Jan 2008 28% 

6 NC Sept 2008 to Jan 2009 10% to 17.7% (3 companies) 

7 SC July to Oct 2008 6% to 10% (4 companies) 

8 TVA (7 states) Oct 2008 20% 

Overall range = Jan to Oct 2008 6% to 37% 

Average (20 electricity plant owner entities) = 19% 

Some state governments have deregulated the electric utility industry, thereby allowing multiple electric suppliers, not just a monopoly 

electricity supplier, to compete and set their own retail prices in those state markets. As of 2003, 18 states have deregulated and six states may 

soon deregulate:179

x Deregulated states (18): AZ, CT, DE, DC, IL, ME, MD, MA, MI, NH, NJ, NY, OH, OR, PA, RI, TX, VA 

(11 of these states no longer have a price cap) 

x May soon deregulate (6): AR, MT, NM, NV, OK, WV (note: CA deregulated in 1998 but has suspended) 

While average prices rose 21% in regulated states from 2002 to 2006, prices increased 36% during that period in 11 of the 18 deregulated states 

where rate caps expired, suggesting greater pricing flexibility in deregulated states.180

o Inelastic Demand for Electricity 

At the wholesale level, as a result of technological and regulatory barriers, the majority of electricity pricing plans do not allow end users to see 

and react to the actual market value of their electricity consumption/ conservation. Since end-users do not face the real-time market price in 

making their consumption decisions, there is little demand reaction to changes in real time wholesale electricity prices.181 At the retail level, 

consumer demand for electricity has been largely inelastic. The lack of real time metering at the retail level means that consumers don't know 

 

179 Source: gStatus of State Electric Industry Restructuring Activity as of February 2003h, US Dept of Energy, Energy Information Administration at: 

http://www.eia.doe.gov/cneaf/electricity/chg_str/restructure.pdf 180 Source: gShocking Electricity Prices Follow Deregulationh, USA Today, 10 Aug 2007 at: http://www.usatoday.com/money/industries/energy/2007-08-09-powerprices_n.htm 

181 Source: page 1 of gDemand Responsiveness in Electricity Marketsh, Ronald Lafferty et al., Office of Markets, Tariffs and Rates, 15 Jan 2001 at: 

http://www.naseo.org/committees/energyproduction/documents/demand_responsiveness_in_electricity_markets.pdf 
215 

how much they use or indeed how much electricity costs until after the fact. Thus consumers cannot react to high prices easily by cutting 

consumption.182

o Cost Pass-Thru Conclusion 

Based on the above three cost pass-thru factors consisting of (a) 20 examples of recent (2008) PUC-regulated rate hikes which average almost 

19% per company which far exceeds the 1% and 3% SISNOSE screening analysis thresholds defined by EPA_s guidance, (b) 11 of the 18 

deregulated states which have de-regulated the price of electricity, and (c) the fact that consumer demand for electricity has been relatively 

inelastic, this RIA concludes that it is likely that electric utility suppliers could pass-thru all, or nearly all, of the future average annual 

regulatory compliance costs for the CCR proposed rule such that a significant impact on small entities and non-small entities would not occur.

 

182 Source: gPower Price Volatility and Risk Management: An Introductionh, Anne Ku, Sept 2000 (this is the original, unedited article, later submitted to Global Energy 

Business magazine Sept/Oct 2000) at: http://www.analyticalq.com/energy/volatility/default.htm 
216 

7C. Minority & Low-Income Population Statistics (Executive Order 12898)

Under the 1994 Executive Order (EO) 12898183 it is the responsibility of Federal agencies to the greatest extent practicable and permitted by 

law, and consistent with the principles set forth in the report on the National Performance Review, each Federal agency shall make achieving 

environmental justice (EJ) part of its mission by identifying and addressing, as appropriate, disproportionately high and adverse human health 

or environmental effects of its programs, policies, and activities on (a) minority populations and (b) low-income populations. Although not 

defined in EO 12898, for purpose of this RIA the following definitions are applied: 

x Minority population: Numerically measured according to Census Bureau gnon-whiteh statistics (does not include Hispanics). 

x Low-income population: Numerically measured according to Census Bureau gindividuals below poverty184 level.h 

Furthermore, section 3-302(b) of EO 12898 provides a trigger which indicates that Federal agencies shall collect and evaluate EJ data for any 

facilities or sites expected to have gsubstantial environmental, human health, or economic effecth when such facilities or sites become subject 

to gsubstantialh Federal environmental action: 

gIn connection with the development and implementation of agency strategies in section 1-103 of this order, each Federal 

agency, whenever practicable and appropriate, shall collect, maintain and analyze information on the race, national origin, 

income level, and other readily accessible and appropriate information for areas surrounding facilities or sites expected to have 

substantial environmental, human health, or economic effect on the surrounding populations, when such facilities or sites 

become the subject of a substantial Federal environmental administrative or judicial action. Such information shall be made 

available to the public unless prohibited by law.h 

The EO 12898 does not establish quantitative thresholds for gsubstantial effecth on the surrounding populations, nor does this RIA formulate a 

quantitative threshold. This RIA uses the (1) CCR disposal baseline environmental and human health hazards (e.g., damage cases), and (2) the 

environmental and human health protection objectives described in the CCR proposed rule, as indicators of gsubstantial effecth. For that 

reason, this section of the RIA presents an EJ data collection and analysis involving a 5-step process to compare minority and low-income 

population data for each electric utility plant location, to respective statewide population data, to identify whether these two population subgroups disproportionately reside in geographic areas where electric utility plants are located. In addition, this RIA identifies two other possible 

affects of the CCR proposed rule on (a) environmental justice populations surrounding offsite landfills which may receive CCR, and (b) 

environmental justice populations within electric utility plant customer service areas. 

 

183 Source: 1994 Executive Order 12898 is available at: http://www.epa.gov/fedrgstr/eo/eo12898.htm 184 The US Census Bureau defines gpovertyh following the Office of Management and Budget's (OMB) Statistical Policy Directive 14. The Census Bureau uses a set of 

money income thresholds that vary by family size and composition to determine who is in poverty. If a family_s total income is less than the family_s threshold, then that 

family and every individual in it is considered in poverty. Poverty income thresholds are available at http://www.census.gov/hhes/www/poverty/threshld/thresh08.html 
217 

x Collection of Minority & Low-Income Demographic Data 

Step 1: Plant address 5-digit gZip Code Tabulation Areash (ZCTAs) formed the geographic basis for this EJ population data collection. 

Because ZCTAs represent irregularly shaped geographic areas, this ZCTA based data collection may be considered a gscreening levelh 

analysis. The US Bureau of Census uses over 33,000 ZCTA for its Census counts of population and other demographic statistics based 

on the US Postal Service_s over 42,000 nationwide ZCTAs.185 Currently, there are no size restrictions limiting how large or small a 

ZCTA can be in terms of either a minimum/maximum number of housing units or geographic area. Any particular ZCTA may be as 

small as a few city blocks or may cover many square miles. Many ZCTAs are for villages, census-designated places, portions of cities, 

or other entities that are not municipalities. The nationwide average ZCTA population is about 7,200 persons (i.e., (306.6 million mid2009 US population) / (42,500 ZCTAs)). The nationwide average ZCTA area is about 83 square miles (i.e., (3,536,278 square miles 

total US land and water area) / (42,500 ZCTAs)), which is a land area equivalent to a five-mile radial distance (i.e., ((83 square miles) / 

(3.1416))^0.5). In comparison, the radial area monitored for contamination in response to the December 2009 TVA Kingston TN 

electric plant CCR spill is reportedly four miles,186and this average four-mile ZCTA radial distance falls between the 1-mile to 15-mile 

radial distances used by EPA_s Superfund gHazard Ranking Systemh (HRS) to define affected populations of sites having either (a) soil 

contamination only (1-mile), (b) groundwater and/or airborne contamination (4-miles), or (c) surface water contamination (15-miles 

downstream). More information about EPA_s HRS is available at http://www.epa.gov/superfund/programs/npl_hrs/hrsint.htm. 

Using the Census search engine Factfinder (http:factfinder.census.gov/home/saff/main.html?_lang=en), EPA retrieved population 

statistics for 464 (94%) of the 495 electric utility plants. For 42 plants (8%) there was no ZCTA Census data because the plants did not 

have complete address data from DOE, or because the Census search engine did not have data for the ZCTA. 

Step 2: EPA collected statewide percentage data for minority and low-income subgroups for purpose of benchmark comparison to the 

plant-by-plant sub-group population statistics. 

o EPA collected low-income population statewide percentages (3-year averages for 1998 to 2000) from the following 

Census Bureau website: http://www.census.gov/hhes/www/poverty/poverty00/tabled.pdf

o EPA collected statewide percentages for white population sub-group (data year 2000) from the Census Bureau website: . 

EPA then subtracted the percentage of white population in each state from 100% to produce the respective minority 

percentage for each state. For data year 2000, the Census Bureau expanded the white population classification by 

collecting both data for people who claimed to be gwhite-onlyh and for people who claimed to be gmixed whiteh. Since 

the purpose of the EJ analysis is to evaluate all minorities, this step involved collecting the gwhite-onlyh data in order to 

calculate the minority percentage which includes people who reported to be of mixed race. Exhibit 7F below displays 

the statewide Census data for low-income and minority sub-populations. 

 

185 Source: US Census Bureau ZIP Code Tabulation Area (ZCTA) Frequently Asked Questions at: Nationwide total ZCTA count is from the US Postal Service_s FAQ 

website at: http://zip4.usps.com/zip4/welcome.jsp 

186 Source: 4 mile radial monitoring area reported by Waste & Recycling News, 13 Feb 2009; http://www.wasterecyclingnews.com/email.html?id=1234543579 
218 

Exhibit 7F 

Statewide Benchmark Data on Low-Income and Minority Populations (2000) 

Item State Low Income % Minority % 

1 AK 8.4% 30.7% 

2 AL 14.7% 28.9% 

3 AR 15.8% 20.0% 

4 AZ 13.5% 24.5% 

5 CA 14.0% 40.5% 

6 CO 8.5% 17.2% 

7 CT 7.7% 18.4% 

8 DC 17.4% 69.2% 

9 DE 9.9% 25.4% 

10 FL 12.1% 22.0% 

11 GA 12.5% 34.9% 

12 HI 10.6% 75.7% 

13 IA 7.9% 6.1% 

14 ID 13.3% 9.0% 

15 IL 10.5% 26.5% 

16 IN 8.3% 12.5% 

17 KS 10.5% 13.9% 

18 KY 12.5% 9.9% 

19 LA 18.5% 36.1% 

20 MA 10.1% 15.5% 

21 MD 7.3% 36.0% 

22 ME 9.8% 3.1% 

23 MI 10.2% 19.8% 

24 MN 7.8% 10.6% 

25 MO 9.8% 15.1% 

26 MS 15.5% 38.6% 

27 MT 16.% 9.4% 

28 NC 13.2% 27.9% 

Item State Low Income % Minority % 

29 ND 12.7% 7.6% 

30 NE 10.7% 10.4% 

31 NH 7.6% 4.0% 

32 NJ 8.1% 27.4% 

33 NM 19.3% 33.2% 

34 NV 10.1% 24.8% 

35 NY 14.7% 32.1% 

36 OH 11.1% 15.0% 

37 OK 14.1% 23.8% 

38 OR 12.9% 13.4% 

39 PA 9.8% 14.6% 

40 RI 10.2% 15.0% 

41 SC 12.0% 32.8% 

42 SD 9.4% 11.3% 

43 TN 13.4% 19.8% 

44 TX 14.9% 29.0% 

45 UT 8.1% 10.8% 

46 VA 8.1% 27.7% 

47 VT 10.3% 3.2% 

48 WA 9.5% 18.2% 

49 WI 9.0% 11.1% 

50 WV 15.8% 5.0% 

51 WY 11.1% 7.9% 

 Min = 7.3% (MD) 3.1% (ME) 

 Max = 19.3% (NM) 75.7% (HI) 

 National = 11.9% 24.9% 
219 

x Comparison of Minority & Low-Income Populations Surrounding Electric Utility Plants to Statewide Benchmarks 

Step 3, Step 4 and Step 5 of this evaluation described below involved three complementary levels of data comparisons. All three comparisons 

also involved two complementary numerical comparisons, one based on calculating numerical percentages and the other on numerical ratios: 

1. Plant level: Plant-by-plant disaggregated data comparison to statewide benchmarks 

2. State level: State-by-state aggregated plant data comparison to statewide benchmarks 

3. Nationwide level: Nationwide aggregated plant data comparison to nationwide benchmarks 

x Calculation of Three Alternative Demographic Statistics Comparison Methods 

Step 3: On a plant-by-plant basis, EPA compared the plant ZCTA percentage minority and percentage low-income population data, to the 

respective statewide average percentages for each sub-group. This constituted the 1st level of data comparison. 

Step 4: For purpose of summary, EPA aggregated the plant level population comparison data for each state as displayed in Exhibit 7G below. 

This constituted the 2nd level of data comparison. There are no data displayed for DC, ID, RI or VT because there are no coal-fired 

electric utility plants in those states. Appendix N of this RIA presents the plant-by-plant Census data on which this Exhibit is based. 

This step also involved aggregating the data across all 495 plants for comparison with the nationwide aggregate minority and lowincome percentage benchmarks. This constituted the 3rd level of data comparison. 

Exhibit 7G 

Minority and Low-Income Population Data Aggregated on State-by-State Basis 

A B C D E F 

(E/D) 

G 

(Exh 7F) 

H 

(DxG) 

I J K 

(DxJ) 

L 

(Exh 7F) 

M 

(DxL) 

N 

General Population Data Low Income Population Data (Below Poverty) Minority Population Data 

Item State 

ZCTA 

count 

2000 

population 

residing in 

electric utility 

plant ZCTA 

areas 

Count of 

plant 

ZCTA 

residents 

below 

poverty 

level 

% of plant 

ZCTA 

residents 

below poverty 

level 

State % 

below 

poverty 

level 

Expected 

count of 

residents 

below 

poverty 

based on 

state% 

Count of 

plants with 

ZCTA% > 

state% 

poverty 

level 

% of 

plant 

ZCTA 

residents 

that are 

minority 

Count of 

plant ZCTA 

residents 

that are 

minority 

Statewide % 

minority 

Expected 

count of 

minority 

based on 

state% 

Count of 

plants 

with 

ZCTA% > 

state% 

minority 

level 

1 AK 2 18,552 2,284 12.31% 8.40% 1,558 1 31.95% 5,928 30.70% 5,695 1 

2 AL 9 82,854 20,331 24.54% 14.70% 12,180 6 42.17% 34,942 28.90% 23,945 4 

3 AR 3 11,786 1,214 10.30% 15.80% 1,862 0 7.74% 912 20.00% 2,357 0 

4 AZ 6 34,941 7,433 21.27% 13.50% 4,717 5 43.70% 15,270 24.50% 8,561 3 

5 CA 4 112,895 24,749 21.92% 14.00% 15,805 5 45.22% 51,049 40.50% 45,722 2 

6 CO 15 214,095 29,395 13.73% 8.50% 18,198 10 17.88% 38,275 17.20% 36,824 8 

7 CT 2 42,716 6,427 15.05% 7.70% 3,289 1 45.14% 19,284 18.40% 7,860 1 

8 DC ND 
220 

Exhibit 7G 

Minority and Low-Income Population Data Aggregated on State-by-State Basis 

A B C D E F 

(E/D) 

G 

(Exh 7F) 

H 

(DxG) 

I J K 

(DxJ) 

L 

(Exh 7F) 

M 

(DxL) 

N 

General Population Data Low Income Population Data (Below Poverty) Minority Population Data 

Item State 

ZCTA 

count 

2000 

population 

residing in 

electric utility 

plant ZCTA 

areas 

Count of 

plant 

ZCTA 

residents 

below 

poverty 

level 

% of plant 

ZCTA 

residents 

below poverty 

level 

State % 

below 

poverty 

level 

Expected 

count of 

residents 

below 

poverty 

based on 

state% 

Count of 

plants with 

ZCTA% > 

state% 

poverty 

level 

% of 

plant 

ZCTA 

residents 

that are 

minority 

Count of 

plant ZCTA 

residents 

that are 

minority 

Statewide % 

minority 

Expected 

count of 

minority 

based on 

state% 

Count of 

plants 

with 

ZCTA% > 

state% 

minority 

level 

9 DE 3 46,925 3,979 8.48% 9.90% 4,646 1 28.86% 13,543 25.40% 11,919 1 

10 FL 13 224,502 23,866 10.63% 12.10% 27,165 5 20.76% 46,617 22.00% 49,390 3 

11 GA 9 202,973 29,461 14.51% 12.50% 25,372 4 42.66% 86,581 34.90% 70,838 4 

12 HI 1 25,054 1,150 4.59% 10.60% 2,656 0 78.17% 19,584 75.70% 18,966 1 

13 IA 14 324,050 31,434 9.70% 7.90% 25,600 13 7.02% 22,744 6.10% 19,767 9 

14 ID ND 

15 IL 23 455,834 83,407 18.30% 10.50% 47,863 14 41.46% 188,970 26.50% 120,796 8 

16 IN 17 323,323 25,460 7.87% 8.30% 26,836 10 6.96% 22,488 12.50% 40,415 2 

17 KS 6 59,517 7,718 12.97% 10.50% 6,249 4 36.76% 21,881 13.90% 8,273 3 

18 KY 17 255,033 32,497 12.74% 12.50% 31,879 7 8.48% 21,615 9.90% 25,248 2 

19 LA 4 30,381 7,546 24.84% 18.50% 5,620 3 45.16% 13,721 36.10% 10,968 2 

20 MA 3 95,798 14,420 15.05% 10.10% 9,676 1 20.69% 19,819 15.50% 14,849 1 

21 MD 7 101,141 10,622 10.50% 7.30% 7,383 4 12.39% 12,527 36.00% 36,411 1 

22 ME 1 6,748 1,037 15.37% 9.80% 661 1 1.30% 88 3.10% 209 0 

23 MI 20 383,284 30,735 8.02% 10.20% 39,095 8 10.56% 40,477 19.80% 75,890 2 

24 MN 15 187,012 20,910 11.18% 7.80% 14,587 10 10.78% 20,157 10.60% 19,823 3 

25 MO 19 251,484 24,714 9.83% 9.80% 24,645 10 7.47% 18,794 15.10% 37,974 2 

26 MS 4 69,209 17,675 25.54% 15.50% 10,727 3 51.63% 35,735 38.60% 26,715 2 

27 MT 5 53,209 8,441 15.86% 16.00% 8,513 2 13.25% 7,050 9.40% 5,002 4 

28 NC 16 238,874 37,388 15.65% 13.20% 31,531 9 34.49% 82,397 27.90% 66,646 12 

29 ND 5 27,087 2,440 9.01% 12.70% 3,440 1 4.40% 1,193 7.60% 2,059 0 

30 NE 6 79,313 8,992 11.34% 10.70% 8,486 2 11.38% 9,027 10.40% 8,249 2 

31 NH 2 53,302 4,355 8.17% 7.60% 4,051 2 5.40% 2,877 4.00% 2,132 2 

32 NJ 6 119,286 17,958 15.05% 8.10% 9,662 3 43.96% 52,438 27.40% 32,684 3 

33 NM 4 17,491 4,638 26.52% 19.30% 3,376 3 55.72% 9,746 33.20% 5,807 3 

34 NV 3 8,471 823 9.72% 10.10% 856 1 15.75% 1,334 24.80% 2,101 1 

35 NY 13 226,416 29,187 12.89% 14.70% 33,283 3 17.42% 39,451 32.10% 72,680 3 

36 OH 23 391,705 42,242 10.78% 11.10% 43,479 7 12.24% 47,953 15.00% 58,756 2 

37 OK 6 30,357 6,117 20.15% 14.10% 4,280 4 38.84% 11,791 23.80% 7,225 1 

38 OR 1 3,884 596 15.35% 12.90% 501 1 39.19% 1,522 13.40% 520 1 

39 PA 28 167,254 15,499 9.27% 9.80% 16,391 15 6.61% 11,048 14.60% 24,419 3 

40 RI ND 

41 SC 12 222,414 28,746 12.92% 12.00% 26,690 8 31.40% 69,831 32.80% 72,952 6 

42 SD 2 30,508 1,763 5.78% 9.40% 2,868 1 5.55% 1,694 11.30% 3,447 0 
221 

Exhibit 7G 

Minority and Low-Income Population Data Aggregated on State-by-State Basis 

A B C D E F 

(E/D) 

G 

(Exh 7F) 

H 

(DxG) 

I J K 

(DxJ) 

L 

(Exh 7F) 

M 

(DxL) 

N 

General Population Data Low Income Population Data (Below Poverty) Minority Population Data 

Item State 

ZCTA 

count 

2000 

population 

residing in 

electric utility 

plant ZCTA 

areas 

Count of 

plant 

ZCTA 

residents 

below 

poverty 

level 

% of plant 

ZCTA 

residents 

below poverty 

level 

State % 

below 

poverty 

level 

Expected 

count of 

residents 

below 

poverty 

based on 

state% 

Count of 

plants with 

ZCTA% > 

state% 

poverty 

level 

% of 

plant 

ZCTA 

residents 

that are 

minority 

Count of 

plant ZCTA 

residents 

that are 

minority 

Statewide % 

minority 

Expected 

count of 

minority 

based on 

state% 

Count of 

plants 

with 

ZCTA% > 

state% 

minority 

level 

43 TN 8 158,267 26,572 16.79% 13.40% 21,208 4 37.38% 59,159 19.80% 31,337 1 

44 TX 17 98,402 14,147 14.38% 14.90% 14,662 10 22.41% 22,052 29.00% 28,537 3 

45 UT 6 34,209 3,885 11.36% 8.10% 2,771 6 5.22% 1,784 10.80% 3,695 0 

46 VA 15 220,800 21,822 9.88% 8.10% 17,885 11 37.78% 83,411 27.70% 61,162 11 

47 VT ND 

48 WA 1 21,842 3,394 15.54% 9.50% 2,075 1 9.54% 2,083 18.20% 3,975 0 

49 WI 13 178,705 23,577 13.19% 9.00% 16,083 8 12.00% 21,446 11.10% 19,836 4 

50 WV 13 64,771 15,577 24.05% 15.80% 10,234 11 6.45% 4,179 5.00% 3,239 2 

51 WY 8 69,736 6,439 9.23% 11.10% 7,741 1 4.92% 3,428 7.90% 5,509 0 

Summary: 

Column totals 430 6,076,410 783,062 12.9% 11.9% 658,336 240 21.7% 1,317,895 24.9% 1,241,382 129 

 18.9% -5.8% 

 Min = 4.6% 7.3% 1.3% 3.1% 

 Max = 26.5% 19.3% 78.2% 75.7% 

Extrapolated to 495 plants = 256 138 
222 

Step 5: Ratios: EPA compared the percentages of minority and low-income populations surrounding the plants to their respective statewide 

benchmark percentages and to the nationwide percentages of these populations as calculated in Step 4, by calculating numerical ratios 

between the plant ZCTA group populations compared to statewide and nationwide percentages of minority and low-income 

populations. The purpose of these ratios is to indicate the relative degree by which the percentages are below or above the statewide 

percentages. Exhibit 7H below displays the results. 

Exhibit 7H 

Comparison of Minority and Low-Income Populations Near Coal-Fired Electric Utility Plants to Statewide Percentages 

A B C D E F (DvE) G (D/E) H I J (HvI) K (I/J) 

Low-Income Data Comparison Minority Data Comparison 

Item State 

Count 

of 

plants 

Percent 

Low-Income 

Population 

Surrounding 

Plants 

Statewide 

Low-Income 

Percentage 

(Exhibit 7F) Difference Ratio 

Percent 

Minority 

Population 

Surrounding 

Plants 

Statewide 

Minority 

Percentage 

(Exhibit 7F) 

Differenc

e Ratio 

1 AK 2 12.3% 8.4% 3.9% 1.47 32.0% 30.7% 1.3% 1.04 

2 AL 9 24.5% 14.7% 9.8% 1.67 42.2% 28.9% 13.3% 1.46 

3 AR 3 10.3% 15.8% -5.5% 0.65 7.7% 20.0% -12.3% 0.39 

4 AZ 6 21.3% 13.5% 7.8% 1.58 43.7% 24.5% 19.2% 1.78 

5 CA 5 21.9% 14.0% 7.9% 1.57 45.2% 40.5% 4.7% 1.12 

6 CO 15 13.7% 8.5% 5.2% 1.62 17.9% 17.2% 0.7% 1.04 

7 CT 2 15.0% 7.7% 7.3% 1.95 45.1% 18.4% 26.7% 2.45 

8 DC NR NA NA NA NA NA NA NA NA 

9 DE 3 8.5% 9.9% -1.4% 0.86 28.9% 25.4% 3.5% 1.14 

10 FL 14 10.6% 12.1% -1.5% 0.88 20.8% 22.0% -1.2% 0.94 

11 GA 9 14.5% 12.5% 2.0% 1.16 42.7% 34.9% 7.8% 1.22 

12 HI 1 4.6% 10.6% -6.0% 0.43 78.2% 75.7% 2.5% 1.03 

13 IA 17 9.7% 7.9% 1.8% 1.23 7.0% 6.1% 0.9% 1.15 

14 ID NR NA NA NA NA NA NA NA NA 

15 IL 25 18.3% 10.5% 7.8% 1.74 41.5% 26.5% 15.0% 1.56 

16 IN 19 7.9% 8.3% -0.4% 0.95 7.0% 12.5% -5.5% 0.56 

17 KS 7 13.0% 10.5% 2.5% 1.24 36.8% 13.9% 22.9% 2.64 

18 KY 19 12.7% 12.5% 0.2% 1.02 8.5% 9.9% -1.4% 0.86 

19 LA 4 24.8% 18.5% 6.3% 1.34 45.2% 36.1% 9.1% 1.25 

20 MA 4 15.1% 10.1% 5.0% 1.49 20.7% 15.5% 5.2% 1.33 

21 MD 8 10.5% 7.3% 3.2% 1.44 12.4% 36.0% -23.6% 0.34 

22 ME 1 15.4% 9.8% 5.6% 1.57 1.3% 3.1% -1.8% 0.42 

23 MI 23 8.0% 10.2% -2.2% 0.79 10.6% 19.8% -9.2% 0.53 

24 MN 15 11.2% 7.8% 3.4% 1.43 10.8% 10.6% 0.2% 1.02 

25 MO 19 9.8% 9.8% 0.0% 1.00 7.5% 15.1% -7.6% 0.49 

26 MS 4 25.5% 15.5% 10.0% 1.65 51.6% 38.6% 13.0% 1.34 
223 

Exhibit 7H 

Comparison of Minority and Low-Income Populations Near Coal-Fired Electric Utility Plants to Statewide Percentages 

A B C D E F (DvE) G (D/E) H I J (HvI) K (I/J) 

Low-Income Data Comparison Minority Data Comparison 

Item State 

Count 

of 

plants 

Percent 

Low-Income 

Population 

Surrounding 

Plants 

Statewide 

Low-Income 

Percentage 

(Exhibit 7F) Difference Ratio 

Percent 

Minority 

Population 

Surrounding 

Plants 

Statewide 

Minority 

Percentage 

(Exhibit 7F) 

Differenc

e Ratio 

27 MT 6 15.9% 16.0% -0.1% 0.99 13.2% 9.4% 3.8% 1.41 

28 NC 19 15.7% 13.2% 2.5% 1.19 34.5% 27.9% 6.6% 1.24 

29 ND 7 9.0% 12.7% -3.7% 0.71 4.4% 7.6% -3.2% 0.58 

30 NE 6 11.3% 10.7% 0.6% 1.06 11.4% 10.4% 1.0% 1.09 

31 NH 2 8.2% 7.6% 0.6% 1.08 5.4% 4.0% 1.4% 1.35 

32 NJ 6 15.1% 8.1% 7.0% 1.86 44.0% 27.4% 16.6% 1.60 

33 NM 4 26.5% 19.3% 7.2% 1.37 55.7% 33.2% 22.5% 1.68 

34 NV 3 9.7% 10.1% -0.4% 0.96 15.7% 24.8% -9.1% 0.63 

35 NY 13 12.9% 14.7% -1.8% 0.88 17.4% 32.1% -14.7% 0.54 

36 OH 24 10.8% 11.1% -0.3% 0.97 12.2% 15.0% -2.8% 0.82 

37 OK 6 20.2% 14.1% 6.1% 1.43 38.8% 23.8% 15.0% 1.63 

38 OR 1 15.3% 12.9% 2.4% 1.19 39.2% 13.4% 25.8% 2.92 

39 PA 31 9.3% 9.8% -0.5% 0.95 6.6% 14.6% -8.0% 0.45 

40 RI NR NA NA NA NA NA NA NA NA 

41 SC 12 12.9% 12.0% 0.9% 1.08 31.4% 32.8% -1.4% 0.96 

42 SD 2 5.8% 9.4% -3.6% 0.61 5.6% 11.3% -5.7% 0.49 

43 TN 8 16.8% 13.4% 3.4% 1.25 37.4% 19.8% 17.6% 1.89 

44 TX 18 14.4% 14.9% -0.5% 0.96 22.4% 29.0% -6.6% 0.77 

45 UT 6 11.4% 8.1% 3.3% 1.40 5.2% 10.8% -5.6% 0.48 

46 VA 16 9.9% 8.1% 1.8% 1.22 37.8% 27.7% 10.1% 1.36 

47 VT NR NA NA NA NA NA NA NA NA 

48 WA 1 15.5% 9.5% 6.0% 1.64 9.5% 18.2% -8.7% 0.52 

49 WI 15 13.2% 9.0% 4.2% 1.47 12.0% 11.1% 0.9% 1.08 

50 WV 16 24.0% 15.8% 8.2% 1.52 6.5% 5.0% 1.5% 1.29 

51 WY 9 9.2% 11.1% -1.9% 0.83 4.9% 7.9% -3.0% 0.62 

Summary:

 Min = 4.6% 7.3% -6.0% 0.43 4.4% 3.1% -23.6% 0.34 

 Max = 26.5% 19.3% 10.0% 1.95 78.2% 75.7% 26.7% 2.92 

Nationwide = 464 12.9% 11.9% 1.0% 1.08 21.7% 24.9% -3.2% 0.87 
224 

x Minority & Low-Income Demographic Findings 

Below is a summary of the three alternative but complementary comparison approaches based on the same minority and low-income population 

data: (a) itemized plant-by-plant basis, (b) nationwide aggregation basis, and (c) state-by-state aggregation basis. For purpose of determining the 

relative degree by which either group living near the 495 plants may exceed their respective statewide population percentages, the percentages 

are compared as a numerical ratio whereby a ratio of 1.00 indicates that the group population percentage living near a plant is equal to the 

statewide average, a ratio greater than 1.00 indicates the group population percentage near the plant is higher than the statewide population, and a 

ratio less than 1.00 indicates the group population is less than the respective statewide average. 

x General population findings: 

o 464 plants (i.e., 94% of the 495 universe) for which year 2000 Census plant address ZCTA data are available are located in 47 

states. 

o The plant address ZCTA population surrounding the 464 plants with ZCTA data is 6.08 million, which is an average of 13,091 

surrounding population per plant. 

x Low-income population findings: 

o 0.78 million low-income population surrounding the 464 plants represents 12.9% of the 6.08 million total surrounding 

populations; this is higher than the 11.9% national percentage. 

o State-by-state low-income population percentages surrounding these plants range from 4.6% in HI to 26.5% in NM. 

o Extrapolated and aggregated across all 495 plants, 256 plants (52%) have surrounding populations which exceed their statewide 

benchmark percentage of low-income population. 

o The ratios of low-income population percentages surrounding these plants range from 0.43 to 1.95, and the average of the ratios

compared to the national average ratio of the low-income population is 1.08. 

o Approximately 29 of the 47 states (62%) have higher percentages of low-income populations compared to their respective 

statewide benchmarks. 

o States with the largest difference in low-income populations surrounding the plants compared to their statewide benchmarks are:

1. Mississippi (26% vs. 16%) 

2. Alabama (25% vs. 15%) 

3. Illinois (18% vs. 11%) 

4. New Jersey (15% vs. 8%) 

5. Connecticut (15% vs. 8%) 

x Minority population findings: 

o 1.32 million minority population surrounding the 464 plants represents 21.7% of the 6.08 million total surrounding populations; 

this is lower than the 24.9% national minority population. 
225 

o The state-by-state range of minority population percentages surrounding these plants ranges from 1.3% in ME to 78.2% in HI. 

o Extrapolated and aggregated across all 495 plants, 138 plants (28%) have surrounding populations which exceed their statewide 

benchmark minority percentage of population. 

o The ratio of minority population percentages surrounding these plants range from 0.34 to 2.92, and the average of the ratios 

compared to the national average ratio of the minority population is 0.87. 

o Approximately 24 of the 47 states (51.1%) have disproportionately high percentages of minority populations within the plant 

address ZCTA area compared to the rest of the state. 

o States with the largest difference in minority populations between the ZCTA where the plants are located compared to the rest of 

the state are as follows: 

1. Connecticut (45% vs. 18%) 

2. Arizona (44% vs. 25%) 

3. Oregon (39% vs. 13%) 

4. Tennessee (37% vs. 20%) 

5. Kansas (37% vs. 14%) 

x Plant level results: 

Using the plant-by-plant (i.e., itemized ZCTA) basis, 138 plants (28%) have surrounding minority populations which exceed their statewide 

minority benchmark percentages, whereas 357 plants (72%) have minority populations below their statewide benchmarks, which represents a 

plant ZCTA ratio of 0.39 (i.e., 138/357). Because this ratio is 61% less than 1.00 (i.e., 1.00 minus 0.39), this finding indicates that only a 

relatively small count of plants have surrounding minority population percentages which disproportionately exceed their statewide benchmarks. 

Also on a plant-by-plant ZCTA basis, 256 plants (52%) have surrounding low-income populations which exceed their respective statewide 

benchmarks, whereas 239 plants (48%) have surrounding low-income populations below their statewide benchmarks, which represents a plant 

ZCTA ratio of 1.07 (i.e., 256/239). Because this ratio is only slightly (7%) above 1.00, it indicates that a slightly disproportionate count of plants 

have surrounding low-income population percentages which exceed their statewide benchmarks. 

x State level results: 

Using the state-by-state aggregation basis, the percentages of minority and low-income populations surrounding the plants were compared to 

their respective statewide population benchmarks. From this, state ratios revealed that 24 of the 47 states (51%) have higher minority 

percentages, and 29 of the 47 states (62%) have higher low-income percentages surrounding the 495 plants, suggesting a slightly disproportionate 

higher minority surrounding population and a relatively large disproportionate, higher low-income surrounding population. However, in 

comparison to the other two numerical comparisons, this state-by-state count approach does not include numerically-weighting of state plant 

counts or state surrounding populations, which explains why this comparison method yields a different numerical result. This method illustrates 

how population comparison results may be sensitive to the comparison method. 
226 

x Nationwide results: 

Using the nationwide aggregation basis across all 495 plants in all 47 states where the plants are located, 6.08 million people live in ZCTA 

surrounding the plants, which include a sub-total of 1.32 million (21.7%) minority and a sub-total of 0.8 million (12.9%) low-income population 

groups. A comparison of these percentages to the national benchmark averages across all states of 24.9% minority and 11.9% low-income, 

represents a minority ratio of 0.87 (i.e., 21.7%/24.9%) and a low-income ratio of 1.08 (i.e., 12.9%/11.9%). These nationwide aggregate ratios 

indicate a slightly lower disproportionate minority population surrounding the 495 plants, and a slightly higher disproportionate low-income 

population surrounding the plants. Comparison of nationwide population sub-totals for all plants for each demographic group compared to the 

expected value based on statewide averages, reveals that: 

o +18.9% additional low-income residents near the plants compared to the expected low-income population based on statewide 

averages (i.e., 783,062 low-income population for all 464 plants compared to 658,336 expected count if based on statewide 

averages.) 

o -5.8% less minority residents near the plants compared to the expected minority population based on statewide averages (i.e., 

1,317,896 minority population for all 464 plants compared to 1,241,382 expected count if based on statewide averages). 

These three alternative comparisons indicate that the current (baseline) environmental and human health hazards and risks from electric utility 

CCR disposal units, and the expected future benefits of the regulatory options, may have a disproportionately lower effect on minority 

populations and may have a disproportionately higher effect on low-income populations. 

x Other Potentially Affected Minority & Low-Income Populations 

There are two other potential differential effects of the regulatory options on two other population groups: (a) populations surrounding offsite 

CCR landfills, and (b) populations within the customer service areas of the 495 electric utility plants. 

o Offsite CCR Landfills 

The potential effect on offsite landfills involves the RCRA Subtitle C based regulatory options whereby four different fractions of CCR 

generation may be required to be disposed in RCRA Subtitle C permitted landfills rather than in non-RCRA permitted waste landfills: 

x CCR fraction #1: Electric utility plants may switch the management of CCR, in whole or in part, from current onsite disposal to offsite 

commercial RCRA-permitted hazardous waste landfills (56.8 million is disposed in onsite landfills, and 22.4 million is 

disposed in onsite impoundments, totaling 79.2 million tons disposed onsite). 

x CCR fraction #2: Some or all of the CCR which is currently disposed in offsite landfills that do not have RCRA Subtitle C permits may 

also switch to RCRA-permitted commercial hazardous waste landfills if the current receiving landfills do not obtain 

RCRA Subtitle C permits (15.0 million tons is disposed offsite). 
227 

x CCR fraction #3: Annual CCR generation which is currently supplied for industrial beneficial use applications could also switch to 

offsite commercial RCRA Subtitle C permitted landfills if such use becomes curtailed in part or in whole from either 

state government regulations or from market stigma (47.0 million tons is beneficially used). 

x CCR fraction #4: Future cleanup of CCR disposal unit failures (e.g., impoundment collapse) would require disposal in RCRA Subtitlepermitted waste landfills (the two CCR impoundment release case studies in Exhibit 4A of this RIA represent a range 

of 0.25 million to 3.3 million tons per failure event). 

One or more of these four potential shifts of CCR disposal from current non-hazardous landfills to hazardous waste landfills, could have a 

disproportionate effect on populations surrounding these locations, and in particular, minority and low-income populations surrounding 

commercial hazardous waste facilities, if current landfills operated by electric utility plants do not obtain future Subtitle C permits (Option 1). 

A recent (2007) study determined that minority and low-income populations disproportionately live near commercial hazardous waste 

facilities, although the study included other types of commercial hazardous waste treatment and disposal facilities in addition to commercial 

hazardous waste landfills.187 An example of such potential EJ concerns is a 2009 US national news item involving the decision made by the 

Tennessee Valley Authority (TVA) to train transport 3 million tons of the TVA_s (Kingston TN electricity plant) December 2008 CCR 

impoundment collapse site cleanup waste, 350 miles away to a landfill in a rural Alabama county which reportedly has about 70% minority 

(African American) and 33% low-income residents.188 However, this example serves to illustrate that EJ concerns are not necessarily 

conclusive or shared by all affected EJ populations, as evidenced by the following remarks made to news reporters by the Alabama county 

government officials and county residents:189

gTo county leaders, the train’s loads, which will total three million cubic yards of coal ash from a massive spill at a power plant 

in east Tennessee last December [2008], are a tremendous financial windfall. A per-ton “host fee” that the landfill operators 

pay the county will add more than $3 million to the county’s budget of about $4.5 million. The ash has created more than 30 

jobs for local residents in a county where the unemployment rate is 17 percent and a third of all households are below the 

poverty line. A sign on the door of the landfill’s scale house says job applications are no longer being accepted — 1,000 were

more than enough. But some residents worry that their leaders are taking a short-term view, and that their community has been 

too easily persuaded to take on a wealthier, whiter community’s problem.... County leaders, who are mostly black, bristle at 

accusations of environmental injustice, saying that the ash is perfectly safe and that criticism has been fostered by outsiders, or 

even competitors who wanted the ash disposal contract for themselves..... Bob Deacy, vice president of clean strategies and 

 

187 Source: United Church of Christ, gToxic Wastes and Race at Twenty 1987-2007h, March 2007. . This study evaluated and made findings on minority and low-income 

population data within a 1.8-mile radius ghost neighborhoodh of 413 commercial hazardous waste facilities, compared to gnon-hosth areas. The study (page x) found that 

gHost neighborhoods of commercial hazardous waste facilities are 56% people of color whereas non-host areas are 30% of color{ Poverty rates in the host neighborhoods 

are 1.5 times greater than non-host areas (18% vs. 12%).h 

188 Source: Shaila Dewan, gClash in Alabama Over Tennessee Coal Ash,h The New York Times, 30 Aug 2009 at http://www.nytimes.com/2009/08/30/us/30ash.html 189 Source: At least two news organizations identically reported these remarks on 30 Aug 2009: 

#1 of 2: New York Times, gClash in Alabama Over Tennessee Coal Ashh at http://www.nytimes.com/2009/08/30/us/30ash.html 

#2 of 2: Waste Business Journal, gWaste From TVA Spill Begins to Arrive at Alabama Landfill Amid Controversyh at 

http://www.wastebusinessjournal.com/news/wbj20090901D.htm 
228 

project development for the Tennessee Valley Authority, whose Kingston Fossil Plant was the site of the ash spill that covered 

almost 300 acres of land and waterways, said Arrowhead [Alabama landfill] was chosen because it was reachable by train 

instead of truck, because it underbid other sites and because, unlike closer landfills, it had the capacity to handle all the ash.h 

o Electricity Service Area Customers 

A third potential effect of the regulatory options described in today_s notice is the price of electricity supplied by some or all of the affected 495 

electric utility plants could increase to cover the cost of regulatory compliance. Thus customers in electric utility service areas could 

experience price increases, although the RIA estimates that future potential price increases could be expected to be below 1% increase relative 

to the $0.0900 per kilowatt hour national average price (February 2009) for all four customer sectors (i.e., residential, commercial, industrial, 

and transportation). The RIA for today_s action did not evaluate the customer service area populations for the 495 plants. 
229 

7D. Child Population Statistics (Executive Order 13045)

x Purpose of Child Population Data Analysis 

Under Executive Order (EO) 13045 of 21 April 1997, Federal Agencies shall make it a high priority (a) to identify and assess environmental 

health and safety risks that may disproportionately affect children, and (b) shall ensure that its policies, programs, activities, and standards 

address disproportionate risks to children that result from environmental health or safety risks. Although the EO does not define children, the 

US Census Bureau defines gchildrenh as follows190: 

Children: The term "children"... are all persons under 18 years, excluding people who maintain households, families, or 

subfamilies as a reference person or spouse. 

The purpose of this section is not to evaluate children risks, but to evaluate whether disproportionate percentages of children live near electric 

utility plants. This analysis involves a 5-step process for comparing children population data for each electric utility plant location, to statewide 

children population data to identify whether children disproportionately reside in geographic areas where electric utility plants are located. 

x Collection of Child Demographic Data 

Step 1:Plant address 5-digit gZip Code Tabulation Areash (ZCTAs) formed the geographic basis for this child population data collection. 

Because ZCTAs represent irregularly shaped geographic areas, this ZCTA based data collection may be considered a gscreening levelh 

analysis. The US Bureau of Census uses over 33,000 ZCTAs for its Census counts of population and other demographic statistics based 

on the US Postal Service_s over 42,000 nationwide ZCTAs.191 Currently, there are no size restrictions limiting how large or small a 

ZCTA can be in terms of either a minimum/maximum number of housing units or geographic area. Any particular ZCTA may be as 

small as a few city blocks or may cover many square miles. Many ZCTAs are for villages, census-designated places, portions of cities, 

or other entities that are not municipalities. The nationwide average ZCTA population is about 7,200 persons (i.e., (306.6 million mid2009 US population) / (42,500 ZCTAs)). The nationwide average ZCTA area is about 83 square miles (i.e., (3,536,278 square miles 

total US land and water area) / (42,500 ZCTAs)), which is a land area equivalent to a 5-mile radial distance (i.e., ((83 square miles) / 

(3.1416))^0.5). In comparison, the radial area monitored for contamination in response to the December 2009 TVA Kingston TN 

electric plant CCR spill is reportedly four miles,192 and this average 5-mile ZCTA radial distance falls between the 1-mile to 15-mile 

radial distances used by EPA_s Superfund gHazard Ranking Systemh (HRS)193 to define affected populations of sites having either (a) 

soil contamination only (1-mile), (b) groundwater and/or airborne contamination (4-miles), or (c) surface water contamination (15-miles 

 

190 The US Census Bureau definition of gchildrenh is from its gCurrent Population Survey (CPS) - Definitions and Explanationsh website at: 

http://www.census.gov/population/www/cps/cpsdef.html 

191 Source: US Census Bureau ZIP Code Tabulation Area (ZCTA) Frequently Asked Questions.: Nationwide total ZCTA count is from the US Postal Service_s FAQ 

website at: http://zip4.usps.com/zip4/welcome.jsp 

192 Source: 4 mile radial monitoring area reported by Waste & Recycling News, 13 Feb 2009; http://www.wasterecyclingnews.com/email.html?id=1234543579 193 More background information about EPA_s HRS is available at http://www.epa.gov/superfund/programs/npl_hrs/hrsint.htm. 
230 

downstream). Using the Census search engine Factfinder (http:factfinder.census.gov/home/saff/main.html?_lang=en), EPA retrieved 

total population and people 18 and over for 464 (94%) of the 495 electric utility plants. For 42 plants (8%) there was no ZCTA Census 

data because the plants did not have complete address data from DOE or because the Census search engine did not have data for the 

ZCTA. 

Step 2: EPA collected 3-year (2005 to 2007) average statewide percentages for people 18 and older data as displayed in Exhibit 7I below. 

Exhibit 7I 

State-by-State Data on Child Populations (2005-2007 Average) 

Row State % children in state 

1 AK 27.0% 

2 AL 24.4% 

3 AR 24.8% 

4 AZ 26.4% 

5 CA 25.9% 

6 CO 24.7% 

7 CT 23.7% 

8 DC 19.5% 

9 DE 23.9% 

10 FL 22.3% 

11 GA 26.5% 

12 HI 22.3% 

13 IA 23.9% 

14 ID 27.3% 

15 IL 25.1% 

16 IN 25.1% 

17 KS 25.2% 

18 KY 23.9% 

19 LA 25.4% 

20 MA 22.5% 

21 MD 24.4% 

22 ME 21.5% 

23 MI 24.6% 

24 MN 24.5% 

25 MO 24.4% 

26 MS 26.3% 

27 MT 23.2% 

28 NC 24.4% 

29 ND 22.5% 

30 NE 25.3% 

Row State % children in state 

31 NH 23.1% 

32 NJ 24.0% 

33 NM 25.6% 

34 NV 25.8% 

35 NY 23.2% 

36 OH 24.2% 

37 OK 24.9% 

38 OR 23.2% 

39 PA 22.6% 

40 RI 22.3% 

41 SC 24.2% 

42 SD 24.8% 

43 TN 24.1% 

44 TX 27.7% 

45 UT 30.9% 

46 VA 23.9% 

47 VT 21.6% 

48 WA 23.9% 

49 WI 23.8% 

50 WV 21.5% 

51 WY 24.0% 

Max (UT) 30.9% 

Min (DC) 19.5% 

Nationwide 24.7% 
231 

x Comparison of Child Populations Living Near Electric Utility Plants to Statewide Benchmarks 

Step 3, Step 4 and Step 5 of this evaluation described below involved three complementary levels of data comparisons. All three comparisons 

also involved two complementary numerical comparisons, one based on calculating numerical percentages and the other based on calculating 

numerical ratios: 

1. Plant level: Plant-by-plant disaggregated data comparison to statewide benchmarks 

2. State level: State-by-state aggregated plant data comparison to statewide benchmarks 

3. National level: National aggregated plant data comparison to statewide benchmarks 

Step 3: On a plant-by-plant basis, EPA compared the plant ZCTA percentage children, to the respective statewide average percentage children. 

Step 4: For purpose of summary, EPA aggregated the plant level children population comparison data for each state as displayed in Exhibit 7J

below. There are no data displayed for DC, ID, RI or VT because there are no coal-fired electric utility plants in those states. 

Appendix O of this RIA presents the plant-by-plant Census data on which this Exhibit is based. 

Exhibit 7J 

State-by-State Child Population Data for Coal-Fired Electric Utility Plants 

General Population Data Child Population Data 

Item 

Count of 

plant 

unique 

ZCTAds State 

Count of plant 

ZCTAs which 

have Census 

population data 

2000 plant 

ZCTA 

resident 

population 

Child 

population 

count (<18 

years) in plant 

ZCTAs 

Child 

population 

percentage 

in plant 

ZCTAs 

Statewide 

percentage 

child 

population 

Expected 

children count in 

plant ZCTAs if 

based on state % 

If plant 

ZCTA 

child% > 

state 

children% 

1 2 AK 2 18,552 5,188 27.96% 27.00% 5,009 2 

2 9 AL 9 82,854 21,978 26.53% 24.40% 20,216 4 

3 3 AR 3 11,786 3,359 28.50% 24.80% 2,923 3 

4 6 AZ 6 34,941 11,526 32.99% 26.40% 9,224 5 

5 5 CA 4 112,895 36,285 32.14% 25.90% 29,240 5 

6 15 CO 15 214,095 49,190 22.98% 24.70% 52,881 11 

7 2 CT 2 42,716 10,743 25.15% 23.70% 10,124 1 

8 NA DC 

9 3 DE 3 46,925 11,169 23.80% 23.90% 11,215 1 

10 14 FL 13 224,502 55,025 24.51% 22.30% 50,064 11 

11 9 GA 9 202,973 50,964 25.11% 26.50% 53,788 5 

12 1 HI 1 25,054 8,158 32.56% 22.30% 5,587 1 

13 17 IA 14 324,050 77,708 23.98% 23.90% 77,448 15 

14 NA ID 
232 

Exhibit 7J 

State-by-State Child Population Data for Coal-Fired Electric Utility Plants 

General Population Data Child Population Data 

Item 

Count of 

plant 

unique 

ZCTAds State 

Count of plant 

ZCTAs which 

have Census 

population data 

2000 plant 

ZCTA 

resident 

population 

Child 

population 

count (<18 

years) in plant 

ZCTAs 

Child 

population 

percentage 

in plant 

ZCTAs 

Statewide 

percentage 

child 

population 

Expected 

children count in 

plant ZCTAs if 

based on state % 

If plant 

ZCTA 

child% > 

state 

children% 

15 25 IL 23 455,834 129,772 28.47% 25.10% 114,414 14 

16 19 IN 17 323,323 83,594 25.85% 25.10% 81,154 14 

17 7 KS 6 59,517 16,532 27.78% 25.20% 14,998 6 

18 19 KY 17 255,033 63,012 24.71% 23.90% 60,953 15 

19 4 LA 4 30,381 8,617 28.36% 25.40% 7,717 4 

20 4 MA 3 95,798 23,078 24.09% 22.50% 21,555 1 

21 8 MD 7 101,141 23,529 23.26% 24.40% 24,678 5 

22 1 ME 1 6,748 1,561 23.13% 21.50% 1,451 1 

23 23 MI 20 383,284 94,994 24.78% 24.60% 94,288 13 

24 15 MN 15 187,012 46,208 24.71% 24.50% 45,818 5 

25 19 MO 19 251,484 60,084 23.89% 24.40% 61,362 12 

26 4 MS 4 69,209 19,867 28.71% 26.30% 18,202 4 

27 6 MT 5 53,209 14,115 26.53% 23.20% 12,344 5 

28 19 NC 16 238,874 57,728 24.17% 24.40% 58,285 6 

29 7 ND 5 27,087 7,411 27.36% 22.50% 6,095 4 

30 6 NE 6 79,313 20,853 26.29% 25.30% 20,066 4 

31 2 NH 2 53,302 10,713 20.10% 23.10% 12,313 0 

32 6 NJ 6 119,286 29,806 24.99% 24.00% 28,629 4 

33 4 NM 4 17,491 5,656 32.34% 25.60% 4,478 3 

34 2 NV 2 8,471 1,827 21.57% 25.80% 2,186 1 

35 13 NY 13 226,416 57,612 25.45% 23.20% 52,529 9 

36 24 OH 23 391,705 101,253 25.85% 24.20% 94,793 14 

37 6 OK 6 30,357 8,513 28.04% 24.90% 7,559 6 

38 1 OR 1 3,884 1,378 35.48% 23.20% 901 1 

39 31 PA 28 167,254 36,581 21.87% 22.60% 37,799 13 

40 NA RI 

41 12 SC 12 222,414 60,391 27.15% 24.20% 53,824 10 

42 2 SD 2 30,508 7,510 24.62% 24.80% 7,566 1 

43 8 TN 8 158,267 40,682 25.70% 24.10% 38,142 4 

44 18 TX 17 98,402 27,471 27.92% 27.70% 27,257 7 

45 6 UT 6 34,209 11,769 34.40% 30.90% 10,571 4 

46 16 VA 15 220,800 55,824 25.28% 23.90% 52,771 10 

47 NA VT 

48 1 WA 1 21,842 5,514 25.24% 23.90% 5,220 1 

49 15 WI 13 178,705 36,428 20.38% 23.80% 42,532 10 
233 

Exhibit 7J 

State-by-State Child Population Data for Coal-Fired Electric Utility Plants 

General Population Data Child Population Data 

Item 

Count of 

plant 

unique 

ZCTAds State 

Count of plant 

ZCTAs which 

have Census 

population data 

2000 plant 

ZCTA 

resident 

population 

Child 

population 

count (<18 

years) in plant 

ZCTAs 

Child 

population 

percentage 

in plant 

ZCTAs 

Statewide 

percentage 

child 

population 

Expected 

children count in 

plant ZCTAs if 

based on state % 

If plant 

ZCTA 

child% > 

state 

children% 

50 16 WV 13 64,771 10,946 16.90% 21.50% 13,926 10 

51 9 WY 8 69,736 19,732 28.30% 24.00% 16,737 6 

Summary: 

Total 464 429 6,076,410 1,541,854 25.37% 24.70% 1,480,831 291 

 4.1% 

 Min= 16.90% 21.50% 

 Max= 35.48% 30.90% 

Extrapolated to 495 plants = 310 

Step 5: The percentage of children population surrounding the plant ZCTAs were compared to overall state percentages and the 

nationwide percentage of this sub-group population, by calculating ratios between the plant ZCTA children populations 

compared to statewide and nationwide percentages of children population. Exhibit 7K below displays the results. 

Exhibit 7K 

Comparison of Child Population Data on a State-by-State Basis 

Item State Plants 

Percentage of 

ZCTA 

Population 

Under 18 

Years Old 

Statewide 

Percentage of 

Children 

(Exhibit 7I) Difference Ratio 

1 AK 2 28.0% 27.0% 1.0% 1.04 

2 AL 9 26.5% 24.4% 2.1% 1.09 

3 AR 3 28.5% 24.8% 3.7% 1.15 

4 AZ 6 33.0% 26.4% 6.6% 1.25 

5 CA 5 32.1% 25.9% 6.2% 1.24 

6 CO 15 23.0% 24.7% -1.7% 0.93 

7 CT 2 25.1% 23.7% 1.4% 1.06 

8 DC NR NA NA NA NA 

9 DE 3 23.8% 23.9% -0.1% 1.00 

10 FL 14 24.5% 22.3% 2.2% 1.10 

11 GA 9 25.1% 26.5% -1.4% 0.95 

12 HI 1 32.6% 22.3% 10.3% 1.46 
234 

Exhibit 7K 

Comparison of Child Population Data on a State-by-State Basis 

Item State Plants 

Percentage of 

ZCTA 

Population 

Under 18 

Years Old 

Statewide 

Percentage of 

Children 

(Exhibit 7I) Difference Ratio 

13 IA 17 24.0% 23.9% 0.1% 1.00 

14 ID NR NA NA NA NA 

15 IL 25 28.5% 25.1% 3.4% 1.13 

16 IN 19 25.9% 25.1% 0.8% 1.03 

17 KS 7 27.8% 25.2% 2.6% 1.10 

18 KY 19 24.7% 23.9% 0.8% 1.03 

19 LA 4 28.4% 25.4% 3.0% 1.12 

20 MA 4 24.1% 22.5% 1.6% 1.07 

21 MD 8 23.3% 24.4% -1.1% 0.95 

22 ME 1 23.1% 21.5% 1.6% 1.08 

23 MI 23 24.8% 24.6% 0.2% 1.01 

24 MN 15 24.7% 24.5% 0.2% 1.01 

25 MO 19 23.9% 24.4% -0.5% 0.98 

26 MS 4 28.7% 26.3% 2.4% 1.09 

27 MT 6 26.5% 23.2% 3.3% 1.14 

28 NC 19 24.2% 24.4% -0.2% 0.99 

29 ND 7 27.4% 22.5% 4.9% 1.22 

30 NE 6 26.3% 25.3% 1.0% 1.04 

31 NH 2 20.1% 23.1% -3.0% 0.87 

32 NJ 6 25.0% 24.0% 1.0% 1.04 

33 NM 4 32.3% 25.6% 6.7% 1.26 

34 NV 2 21.6% 25.8% -4.2% 0.84 

35 NY 13 25.4% 23.2% 2.2% 1.10 

36 OH 24 25.8% 24.2% 1.6% 1.07 

37 OK 6 28.0% 24.9% 3.1% 1.13 

38 OR 1 35.5% 23.2% 12.3% 1.53 

39 PA 31 21.9% 22.6% -0.7% 0.97 

40 RI NR NA NA NA NA 

41 SC 12 27.2% 24.2% 3.0% 1.12 

42 SD 2 24.6% 24.8% -0.2% 0.99 

43 TN 8 25.7% 24.1% 1.6% 1.07 

44 TX 18 27.9% 27.7% 0.2% 1.01 

45 UT 6 34.4% 30.9% 3.5% 1.11 

46 VA 16 25.3% 23.9% 1.4% 1.06 

47 VT NR NA NA NA NA 

48 WA 1 25.2% 23.9% 1.3% 1.06 
235 

Exhibit 7K 

Comparison of Child Population Data on a State-by-State Basis 

Item State Plants 

Percentage of 

ZCTA 

Population 

Under 18 

Years Old 

Statewide 

Percentage of 

Children 

(Exhibit 7I) Difference Ratio 

49 WI 15 20.4% 23.8% -3.4% 0.86 

50 WV 16 16.9% 21.5% -4.6% 0.79 

51 WY 9 28.3% 24.0% 4.3% 1.18 

 Min = 16.9% 19.5% -4.6% 0.79 

 Max = 35.5% 30.9% 12.3% 1.53 

 Nationwide = 464 25.4% 24.7% 0.7% 1.03 

x Child Population Data Findings 

Below is a summary of the three alternative but complementary comparison approaches based on the same children population data: (a) plantby-plant (i.e., itemized ZCTA) basis, (b) nationwide aggregation basis, and (c) state-by-state aggregation basis. For purpose of determining the 

relative degree by which children may exceed these statewide percentages, the percentages are compared as a numerical ratio whereby a ratio 

of 1.00 indicates that the child population percentage living near a plant is equal to the statewide average, a ratio greater than 1.00 indicates the 

child population percentage near the plant is higher than the statewide population, and a ratio less than 1.00 indicates the child population is 

less than the respective statewide average.

x General population findings 

o 464 plants (i.e., 94% of the 495 universe) for which Census plant address ZCTA data are located in 47 states. 

o The plant address ZCTA population surrounding these plants is 6.08 million, which is an average of 13,091 surrounding 

population per plant. 

x Child population findings 

o The sub-total number of children surrounding these 464 plants is 1.54 million (i.e., 25.4% of 6.08 million). In comparison, 

the national average of the child population in the US is 24.7%. 

o The ratios of the children population percentages surrounding these plants range from 0.79 to 1.53, and the average of the 

ratios compared to the national average ratio of the low-income population is 1.03. 

o 27 of the 47 states (57%) have disproportionately high percentages of children within the plant address ZCTAs compared to 

the statewide percentages. 

o States with the largest difference in the children population between the ZCTAs where the plants are located compared to 

the statewide percentages are as follows: 

1. Oregon (36% vs. 23%) 
236 

2. Hawaii (33% vs. 22%) 

3. New Mexico (32% vs. 26%) 

4. Arizona (33% vs. 26%) 

5. California (32% vs. 26%) 

o A sub-total of 291 plants (63%) have surrounding children populations which exceed their respective statewide percentage. 

x Plant level results: 

Using the plant-by-plant (i.e. itemized ZCTA) basis, 310 plants (63%) have surrounding child populations which exceed their statewide 

children benchmark percentages, whereas 185 plants (37%) have children populations below their statewide benchmarks, which represents a 

plant ZCTA ratio of 1.68 (i.e., 310/185). Since this ratio is much greater than 1.00, this finding indicates that a highly disproportionate count of 

plants have surrounding child population percentages which exceed their statewide benchmark. 

x State level results: 

Using the state-by-state aggregation basis, the percentage of child populations surrounding the plants were compared to their respective 

statewide population benchmarks. The state-by-state ratios revealed that approximately 27 of the 47 states (57%) have disproportionate 

percentages of children within the plant address ZCTA compared to the rest of the state suggesting a disproportionate surrounding child 

population. However, in comparison to the other two numerical comparisons above, this state-by-state count approach does not include 

numerically-weighting of state plant counts or state surrounding populations, which explains why this comparison method yields a different 

numerical result. This method illustrates how population comparison results may be sensitive to the comparison method. 

x Nationwide results: 

Using the nationwide aggregation basis across all 495 plants in all 47 states where the plants are located, 6.08 million people live in ZCTAs 

surrounding the plants, which include a sub-total of 1.54 million children (25.4%). Comparison of this percentage to the national aggregate 

benchmark across all states of 24.7% children yields a ratio of 1.03 (i.e., 25.4%/24.7%). This ratio indicates a slightly higher disproportionate 

child population surrounding the 495 plants. Comparison of the nationwide child population sub-total for all plants reveals that +4.1% 

additional children reside near the plants, compared to the expected child population if based on state averages (i.e., 1,541,854 children living 

near the 464 plants compared to 1,480,831 expected children count). 

These three alternative comparisons indicate that the current (baseline) environmental and human health hazards and risks from electric utility 

CCR disposal units, and the expected future benefits of the regulatory options, may have a disproportionately higher effect on child 

populations. 
237 

7E. Unfunded Mandates (UMRA) & Federalism Implications Analysis (Executive Order 13132) 

x UMRA 

Among its other purposes and Federal agency rulemaking requirements, Title II of the 1995 Unfunded Mandates Reform Act (UMRA; 2

U.S.C. 1531-1538), requires Federal agencies, unless otherwise prohibited by law, to assess the effects of their regulatory actions on State, 

local, and tribal governments and on the private sector, to determine whether any proposed rulemaking: 

 g...is likely to result in promulgation of any rule that includes any Federal mandate that may result in the expenditure by State,

local, and tribal governments, in the aggregate, or by the private sector, of $100 million or more in any one year.h 

Section 202 of UMRA requires Federal agencies which propose rules that are likely to exceed this $100 million expenditure threshold on either 

the private sector or on state/local/tribal governments, to prepare a gWritten Statementh containing the following five components, and supply 

the Written Statement to OMB as well as summarize it in the Federal Register notice (aka gpreambleh) for the proposed rule: 

1. Identification of the applicable authorizing Federal law 

2. Qualitative and quantitative assessment of the anticipated costs and benefits of the rule including the costs and benefits to State, local, 

and tribal governments or the private sector, and an analysis of whether Federal resources may be available to pay these costs 

3. Estimates of future compliance costs and any disproportionate budgetary effects 

4. Estimates of effects on the national economy such as productivity, economic growth, employment, job creation, international 

competitiveness 

5. Description and summary of agency_s prior consultation with elected representatives of the affected State, local and tribal governments. 

Section 202 of UMRA allows Federal agencies to prepare the gWritten Statement gin conjunction with or as a part of any other statement or 

analysis. Accordingly, the purpose of this section of the RIA is to determine whether the regulatory options evaluated in this RIA exceed this 

UMRA direct cost threshold. 

Findings: The private sector and the state/local government shares of direct compliance costs under each option are displayed below in 

Exhibit 7L, which indicates that: 

 Private sector cost test: All of the regulatory options are expected to result in expenditures of $100 million or more in the 

aggregate for the private sector, in any one year (i.e., 139 companies and cooperatives of the total 200 owner entities). 

 State/local/tribal government cost test: None of the regulatory options are expected to result in expenditures of $100 

million or more for State, local, and tribal governments in the aggregate in any one year (there are 60 state/local 

government owner entities identified in Exhibit 7M below, no known tribal owner entities, plus one Federal owner). 

According to the private sector test finding, EPA has prepared an gUMRA Written Statementh which is attached to this RIA as Appendix P. 
238 

x Federalism (Executive Order 13132) 

The 1999 Federalism Executive Order 13132 (Federal Register, Vol.64, No. 153, 10 Aug 1999) furthers the policies of the 1995 Unfunded 

Mandates Reform Act (UMRA) by establishing federalism principles, federalism policymaking criteria, and a state/local government 

consultation process for the development of Federal regulations that have federalism implications. Federalism implications refers to 

regulations and other Federal policies and actions that have substantial direct effects on states, on the relationship between the Federal 

government and the states, or on the distribution of power and responsibilities among the various levels of government. 

For purpose of complying with the Section 6 consultation process of EO 13132, this section of the RIA evaluates whether the CCR regulatory 

options may gimpose substantial direct compliance costsh on state/local governments. As summarized in Exhibit 7L, the proposed rule might 

impose four types of direct costs on the 60 state/local government owner entities identified in Exhibit 7M below: 

x State/local government owned electric utility plants: 

1. Engineering control costs for CCR disposal units located at electric utility plants owned by state/local governments. 

2. Ancillary costs for CCR disposal units located at electric utility plants owned by state/local governments. 

3. Conversion to dry disposal costs for CCR disposal units located at electricity utility plants owned by state/local governments.

x State government environmental agencies: 

4. Regulatory implementation, administration, and enforcement costs to RCRA-authorized state government programs/agencies. 

Consistent with the gdirect costh scope of EO 13132, not included in Exhibit 7L are potential indirect costs in the form of potential lost annual 

revenues to electricity plants associated with potential reductions in CCR sold by plants for beneficial use under the three Subtitle C options for 

which such an possible indirect effect is estimated in this RIA. 

EPA_s 2008 guidance194 for compliance with EO 13132 describes two numerical methods (i.e., numerical tests) for evaluating whether an EPA 

rule may have federalism implications with respect to gsubstantial direct compliance costsh: 

1. $25 million test: Annualized direct compliance cost expenditures to state/local governments in aggregate of $25 million or more195

2. 1% test: Annualized direct compliance costs faced by state/local governments is likely to equal or exceed 1% of their annual revenues*

[* Note: Page 29 of gAttachment A: Guidance for Implementing the Federalism 1% Testh to EPA_s Nov 2008 gGuidance on Executive 

Order 13132: Federalismh defines small government ggeneral revenueh as gmade up of intergovernmental revenue plus revenue from 

their own sources and excludes utility, liquor store and employee retirement revenue.h However, given that the CCR proposed rule 

affects electric utility industry, this RIA applies the g1% Testh in relation to only State/local government electric utility annual revenue.] 

 

194 The two methods are from page 6 of gEPA_s Action Development Process -- Guidance on Executive Order 13132: Federalism,h OPEI Regulatory Development Series, 

Nov 2008, 62 pages at http://intranet.epa.gov/adplibrary/documents/federalismguide11-00-08.pdf 

195 Although one of the stated purposes of EO 13132 in its first paragraph is gto further the policies of the 1995 Unfunded Mandates Reform Act (UMRA), EPA_s $25 

million annual direct cost trigger is 75% lower than the $100 million annual direct cost trigger prescribed in Section 202 of UMRA. 
239 

x Findings for UMRA Impact and Federalism Implication Tests 

Based on estimated regulatory costs on state/local governments displayed in Exhibit 4B of this RIA for each regulatory option, Exhibit 7L

below displays whether the costs potentially exceed the UMRA and Federalism thresholds defined above. 

o UMRA finding: All options >$100 million private sector test; all options <$100 million state/local government test 

o Federalism finding: All options >$25 million state/local government test; all options <1% state/local government test 

However, for consistency with the RFA/SBREFA small business impact analysis presented in a separate section above in this RIA, this RIA 

estimates it is highly likely that the direct compliance costs under each option may be passed-thru to electricity plant customers in the form of 

higher electricity prices. The feasibility of such a compliance cost pass-thru scenario is evaluated and confirmed by the information presented 

in the RFA/SBREFA small business impact section of this RIA. 

Exhibit 7L 

UMRA and Federalism Tests for CCR Disposal Regulatory Options 

($millions average annualized costs @7% discount rate over 50-years 2012 to 2061, 2009$) 

Type of Direct Compliance Cost 

Subtitle C 

Hazardous waste 

Subtitle D 

(version 1) 

Subtitle C for impoundments 

Subtitle D for landfills 

Average annualized cost (source: Exhibit 5F): $2,274 $492 $2,176 

UMRA Test: 

1. Private sector $100 million direct cost threshold test $1,999.4 $415.3 $1,908.8 

2. State/local government $100 million direct cost threshold test* $96.7 $55.9 $91.6 

Federalism Test: 

1. $25 million threshold test: sub-total State/Local govt cost $96.7 $55.9 $91.6 

2. 1% Test: State/local govt cost as percentage of State/Local 

government electric utility annual revenues 

0.227% 0.131% 0.215% 

* Note: 

Remainder Federal government costs represent costs associated with Federally-owned electric utility plants (i.e., Tennessee Valley Authority) which are not 

subject to either the UMRA or Federalism tests. Therefore, the sub-total private sector direct cost plus the state/local government direct cost does not add-up 

to the total annual cost estimate under each option; the remainder cost is for the Federally-owned plants. 
240 

Exhibit 7M 

List of 74 Coal-Fired Electric Utility Generation Plants Which EPA Estimates Are Owned by 60 State/Local Governments 

Source: Compiled by EPA-OSWER-ORCR based on 2007 data from the US Energy Information Administration* 

Item Owner Entity Name Electric Utility Plant Name State 

Owner Entity 

Size/Type** 

1 Grand River Dam Authority GRDA OK Non-Small State 

2 Lower Colorado River Authority Fayette Power Project TX Non-Small State 

3 Nebraska Public Power District Gerald Gentleman NE Non-Small State 

4 Nebraska Public Power District Sheldon NE Non-Small State 

5 Omaha Public Power District Nebraska City NE Non-Small State 

6 Omaha Public Power District North Omaha NE Non-Small State 

7 Platte River Power Authority Rawhide CO Non-Small State 

8 Salt River Project Coronado AZ Non-Small State 

9 Salt River Project Navajo AZ Non-Small State 

10 South Carolina Pub Service Auth Cross SC Non-Small State 

11 South Carolina Pub Service Auth Dolphus M Grainger SC Non-Small State 

12 South Carolina Pub Service Auth Jefferies SC Non-Small State 

13 South Carolina Pub Service Auth Winyah SC Non-Small State 

14 American Municipal Power-Ohio, Inc Richard Gorsuch OH Non-Small City 

15 Ames City of Ames Electric Services Power Plant IA Non-Small City 

16 City of Columbia Columbia MO Non-Small City 

17 City of Hamilton Hamilton OH Non-Small City 

18 City of Lakeland C D McIntosh Jr FL Non-Small City 

19 City of Owensboro Elmer Smith KY Non-Small City 

20 City of Springfield Dallman IL Non-Small City 

21 City of Springfield Lakeside IL Non-Small City 

22 City Utilities of Springfield James River Power Station MO Non-Small City 

23 City Utilities of Springfield Southwest Power Station MO Non-Small City 

24 Colorado Springs City of Martin Drake CO Non-Small City 

25 Colorado Springs City of Ray D Nixon CO Non-Small City 

26 Gainesville Regional Utilities Deerhaven Generating Station FL Non-Small City 

27 Independence City of Blue Valley MO Non-Small City 

28 Independence City of Missouri City MO Non-Small City 

29 JEA Northside Generating Station FL Non-Small City 

30 JEA St Johns River Power Park FL Non-Small City 

31 Kansas City City of Nearman Creek KS Non-Small City 

32 Kansas City City of Quindaro KS Non-Small City 

33 Lansing Board of Water and Light Eckert Station MI Non-Small City 

34 Lansing Board of Water and Light Erickson Station MI Non-Small City 

35 Los Angeles City of Intermountain Power Project UT Non-Small City 

36 Orlando Utilities Comm Stanton Energy Center FL Non-Small City 

37 Rochester Public Utilities Silver Lake MN Non-Small City 
241 

Exhibit 7M 

List of 74 Coal-Fired Electric Utility Generation Plants Which EPA Estimates Are Owned by 60 State/Local Governments 

Source: Compiled by EPA-OSWER-ORCR based on 2007 data from the US Energy Information Administration* 

Item Owner Entity Name Electric Utility Plant Name State 

Owner Entity 

Size/Type** 

38 San Antonio City of J K Spruce TX Non-Small City 

39 San Antonio City of J T Deely TX Non-Small City 

40 Vineland City of Howard Down NJ Non-Small City 

41 Crisp County Power Comm Crisp Plant GA Small - County 

42 Austin City of Austin Northeast MN Small City 

43 Board of Water Electric & Communications Muscatine Plant #1 IA Small City 

44 Cedar Falls Utilities Streeter Station IA Small City 

45 City of Dover Dover OH Small City 

46 City of Grand Haven J B Sims MI Small City 

47 City of Holland James De Young MI Small City 

48 City of Jasper Jasper 2 IN Small City 

49 City of Logansport Logansport IN Small City 

50 City of Marquette Shiras MI Small City 

51 City of Marshall Marshall MO Small City 

52 City of Menasha Menasha WI Small City 

53 City of Orrville Orrville OH Small City 

54 City of Painesville Painesville OH Small City 

55 City of Richmond Whitewater Valley IN Small City 

56 City of Shelby Shelby Municipal Light Plant OH Small City 

57 City of Sikeston Sikeston Power Station MO Small City 

58 City of Virginia Virginia MN Small City 

59 Crawfordsville Electric Light & Power Crawfordsville IN Small City 

60 Fremont City of Lon Wright NE Small City 

61 Grand Island City of Platte NE Small City 

62 Greenwood Utilities Commission Henderson MS Small City 

63 Hastings City of Whelan Energy Center NE Small City 

64 Henderson City Utility Commission Henderson I KY Small City 

65 Hibbing Public Utilities Commission Hibbing MN Small City 

66 Jamestown Board of Public Utilities S A Carlson NY Small City 

67 Manitowoc Public Utilities Manitowoc WI Small City 

68 Michigan South Central Power Agency Endicott Station MI Small City 

69 New Ulm Public Utilities Commission New Ulm MN Small City 

70 Pella City of Pella IA Small City 

71 Peru City of Peru IN Small City 

72 Texas Municipal Power Agency Gibbons Creek TX Small City 

73 Willmar Municipal Utils Commission Willmar MN Small City 

74 Wyandotte Municipal Service Commission Wyandotte MI Small City 
242 

Exhibit 7M (Continued) 

List of 74 Coal-Fired Electric Utility Generation Plants Which EPA Estimates Are Owned by 60 State/Local Governments 

Source: Compiled by EPA-OSWER-ORCR based on 2007 data from the US Energy Information Administration* 

Footnotes: 

* NAICS code 22 electric gutilityh generator plants listed in EIA_s 2007 data source at: 

http://www.eia.doe.gov/cneaf/electricity/page/eia860.html 

**Type of owner entity assigned by EPA ORCR based on business type disclosed in owner name or plant-by-plant internet research on 

type of ownership. Size class determined according to the following numerical criteria consistent with EPA_s Nov 2006 guidance for 

Regulatory Flexibility Act (RFA) Small Business Regulatory Enforcement Fairness Act (SBREFA) compliance: 

~ Small non-government = Based on the US Small Business Administration NAICS code 221112 small business size standard of 

<4 million megawatt hours per year total annual electricity generation by all plants owned by the entity. 

~ Non-small non-government = Entity_s total annual electricity generation >4 million megawatt hours per year. 

~ Small government = Based on the RFA_s definition (5 US Code section 601(5)) of gsmall government jurisdictionh as the 

government of a city, county, town, township, village, school district, or special district with a population less than 50,000.

~ Non-small government = Entity_s jurisdiction population with more than 50,000 people.