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 
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 

contractor DPRA Inc (Minneapolis MN) provided data analysis support for identifying affected entities and baseline CCR disposal practices and costs (Chapter 3), and for estimating costs of regulatory engineering crequirements (Chapter 4) in this RIA. EPA ORCR staff contributing to this RIA: Rachel Alford, Richard Benware, Mark Eads, Christina Kager, a
Table of Contents

Executive Summary Chapter 1: Problem Statement: The Need for RCRA Regulation of CCR Disposal Chapter 2: Potentially Affected Industries & RCRA Regulatory Options  2A. Identity of Potentially Affected Industries (Electric Utility Industry)  2B. Other Industries with CCR Disposal Units Not Covered by the Proposed Rule 

 2C. RCRA Regulatory Options Evaluated in this RIA Chapter 3: Baseline CCR Disposal in the Electric Utility Industry 

3A. Identity of Coal-Fired Electric Utility Plants 3B. Types of CCR Disposal Units 

 3C. Types of CCR Generated and Annual Quantities  3D. Size of CCR Disposal Units 

3E. Cost of Baseline CCR Disposal 

Chapter 4: Estimated Cost for RCRA Regulation of CCR Disposal  4A. EPA’s Prior Cost Estimates for RCRA Regulation of CCR Disposal at Electric Utility P 4B. Regulatory Cost Estimation Algorithms & Results  4B.1 Engineering Control Costs  4B.2 Ancillary Regulatory Requirement Costs  4B.3 Land Disposal Restriction (CCR Dewatering Treatment) Cost 

4C. State-by-State Distribution of Regulatory Cost 4D. Cost Estimation Uncertainty 

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

 5A. Groundwater Protection Benefits (Avoided Future Cancer Risks & Groundwater Reme 5B. Preventing Future CCR Impoundment Catastrophic Failures (Avoided Future Cleanup  5C. Induced Effect of RCRA Regulation of CCR Disposal on Future CCR Beneficial Use Chapter 6: Comparison of Regulatory Benefits to Costs  6A. Comparison of Benefits to Costs Based on Alternative Discount Rates (7%, 3%, 0%)  6B. Factors Applied for Scaling Benefits and Costs to the Regulatory Options Chapter 7: Supplemental Analyses Required by Congressional Statutes or White House Executive Orders 

7A. Electricity Price Impact (Executive Order 13211) 

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

7C. Minority & Low-Income Populations Near Electric Utility Plants (Executive Order 1287D. Child Population Statistics (Executive Order 13045) 

7E. Unfunded Mandates (UMRA) & Federalism Implications Analysis (Executive Order 13

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

Note: Because of its large number of pages (>400 pages), the Appendix is provided as a separate companion do

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 o

Appendix C List of 495 Operating Electric Utility Plants Potentially Affected by the CCR Rulemaking (200Appendix 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 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 RegulatoAppendix 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 Imp
Executive Summary 

This RIA evaluates the expected regulatory compliance costs, economic and environmental benefits, and potential imuse, of EPA’s proposed regulation of coal combustion residual (CCR) disposal by coal-fired electric utility plants. Th

regulatory options evaluated in this RIA are based on EPA’s statutory authority contained in the 1976 Resource Cons

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 RemeES-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 Industr

ES-5: Regulatory Compliance CostsES-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 optionBevill regulatory exclusion for CCR beneficial uses, and (b) propose the same set of 10 custom-tailored engineering cdesign and operating standards) for CCR disposal units: 

1. Subtitle C “Special Waste” Option: Regulate CCR landfills and impoundments as a “special waste” under Su

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 impoundm

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

those units, unless the states choose to adopt controls over such units. Also, all surface impoundments (existinto have composite liners within 5-years of the effective date. 

3. Subtitle “D prime” Option: Composite liners required only for new impoundments and landfills; unlined units 

operate. This approach would be the same as the Subtitle D option above, except that existing impoundments retrofit and install a composite liner, or close. 
ES-2: Benefits of Avoided Future Groundwater Contamination (Human Health & Avoided ReBy establishing management and permit standards for CCR disposal units under RCRA, the proposed regulatory optiuncontrolled releases and cancer risks, and improve detection and, if necessary, response to future groundwater conta

quantifies two components of groundwater protection benefits: (a) human cancer risks avoided from drinking contam(b) groundwater contamination remediation costs avoided. Summary Exhibit 1 below presents the monetized result

• Estimate of avoided human cancer risks from avoided future groundwater contamination by CCR disposal un

o Individual skin cancer risks avoided (by eliminating the groundwater pathway for arsenic at CCR impo

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

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,

o Taking into account current CCR disposal unit designs, an estimated 145 (using the IRIS cancer slope 

NRC lung and bladder cancer slope factor1) future human cancer risks are expected to occur in absenc

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

• 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 

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 impoundme

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 “D prime” 

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 CThis RIA estimated future avoided cleanup costs from catastrophic impoundment failures, like the one that occurred a

coal-fired electricity plant in December 2008, which would be prevented under the proposed rule. Given the increasi

1 EPA calculated a new cancer slope factor for arsenic from data in the National Research Council report “Arsenic in Drinking Water: 2001 U

http://www.nap.edu/openbook.php?isbn=0309076293 
impoundments, the relative number that present high or significant hazard potential, and the history of CCR impoundRIA presents three alternative scenarios of future catastrophic failures, the result for which are displayed in Summar

• Failure Scenario #1: Extrapolation of future CCR impoundment failure probability based on the relative (a) r

frequency, (b) CCR quantity release magnitude, and (c) cleanup costs, associated with three recent (2005, 200

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

• Failure Scenario #2: Assumes 10% of CCR impoundments in the high failure risk group (i.e., above 40 feet t

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

• Failure Scenario #3: Assumes 20% of CCR impoundments in the high failure risk group (i.e., above 40 feet t

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 “D prime

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 wquantify 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 

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-car

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

2 Based on the responses to our CERCLA 104(e) information requests to utilities with impoundments, there are 96 impoundments that meet t

RIA estimates that 16 of these impoundments have closed or are expected to close before the CCR rule is finalized and goes into effect. Thethese 16 impoundments and based the estimated future impoundment failure cleanup costs on a subset of 80 CCR impoundments meeting th

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

pH, total chlorine, and total suspended solids (TSS). EPA’s proposed CCR rule would eliminate CCR surface impoundments, eliminating m

addressed under revisions to the effluent guidelines, including risks posed by arsenic, selenium, mercury, cadmium, copper, chromium, and n
disposal units, can exceed the human health hazard quotient (HQ) or Maximum Contaminant Limit (MCL). Cprovides a list of contaminants of concern in CCR surface impoundment effluent and potential human health a

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

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

ES-4: Economic & Environmental Benefits from Future Increase in CCR Beneficial Uses by OThis RIA evaluated the potential impact that the CCR proposed rule may have on beneficial uses of CCR by other ind

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

benefits consisting of: (a) materials cost savings, plus (b) lifecycle avoided pollution benefits, plus (c) avoided CCR delectric utility industry. On a present value basis over the 50-year future period-of-analysis (2012-2061) applied in th

of CCR beneficial use amounts to $778 billion (@7% discount). Although the industries which use CCR for beneficithe requirements of the CCR proposed rule, this RIA presents three alternative scenarios of potential induced effect o

CCR beneficial use, consisting of increased use (scenario #1), decreased use (scenario #2), and no change (scenario #both scenario #1 and scenario #2 incrementally in relation to the “no change” scenario #3. EPA believes the increasin

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

options retain the existing RCRA Bevill exemption for CCR beneficial uses, and (c) the added cost of regulatory combeneficial use relatively more cost-effective and represent an “avoided disposal cost incentive”4 to electric utility planof CCR to industrial markets for CCR as a raw or intermediate input into industrial manufacturing and construction aEPA does not believe that market “stigma” of CCR regulation under RCRA Subtitle C --- as alleged in numerous stak

in 2009 --- will result in a reduction in future annual CCR beneficial use, because the proposed rule designates the Su

“special waste” rather than as a “hazardous waste.” Summary Exhibit 3 below presents the results for both the incrdecrease scenario #2. 

4 The concept of “avoided disposal cost incentive” is recognized and defined by the American Coal Ash Association (ACAA) on its website 

“If a [coal-fired electric utility] plant markets its [CCR] into commercial applications, then disposal of this [CCR] is not required. created for the [coal-fired electricity plant] but also the need to dispose of the [CCR] is avoided. As discussed above, disposal is noplacement of [CCR] in a disposal site. The need for future space is a concern. If [CCR is] marketed, then the need to develop futur(including land acquisition, permitting, design and construction costs) is avoided .... It is not uncommon for a company to help offsplacement at construction sites by providing the contractor or trucking firm a payment of some sort. For example, if the cost of dispdollars a ton, then the company may arrange a payment of four dollars or less to the contractors to cover transportation and placembetween the amount of this payment and the cost of disposal is also referred to as “avoided disposal costs.” Source: ACAA Frequewebpage at: http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=5#Q14 
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 “D 

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 +$8

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

Scenario #2: Induced Decrease in CCR Beneficial Use 

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

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

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

ES-5: Regulatory Compliance Costs Chapter 4 of the RIA presents the estimated costs for industry compliance (and for government implementation) of eSummary Exhibit 4 below presents the estimated costs on a present value basis. The RIA presents three categories cost. These regulatory costs are incremental to an estimated $5,556 million per year average annual baseline (i.e., curutility industry for CCR disposal, which represents a baseline cost of $76,678 million in present value on a 7% and 50

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 “D pri

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 conv

CCR disposal to dry CCR disposal. In fact, there are several upcoming EPA regulations which could accelerate this t

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

scrubbers and other air emission control technology at coal-fired power plants, as well as new wastewater effluent guWater Act which will require installation of treatment technology for wastewater discharges from CCR impoundmen
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” and “benefit-cost ratio” comparison indicators. The three Exhibits are based on the three alternative scenari

induced impact of the CCR rule on future annual CCR beneficial use as presented in Section 5C of this RIA (i.e., incr

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

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

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 

“Special Waste” 

Subtitle D 

(version 2) Sub

A. Present Values: 1. Regulatory Costs (1A+1B+1C): $20,349 $8,095  1A. Engineering Controls $6,780 $3,254  1B. Ancillary Regulatory Requirements $1,480 $5  1C. Conversion to Dry CCR Disposal $12,089 $4,836 2. Regulatory Benefits (2A+2B+2C+2D): $87,221 to $102,191 $34,964 to $41,761 $ 2A. Monetized Value of Human Cancer Risks Avoided $504 (726 cancer risks) $207 (296 cancer risks) $104  2B.Groundwater Remediation Costs Avoided $466 $168  2C. CCR Impoundment Failure Costs Avoided $1,762 to $16,732 $793 to $7,590  2D. Induced Impact on Future CCR Beneficial Use $84,489 $33,796 3. Net Benefits (2 - 1) $66,872 to $81,842 $26,869 to $33,666 $4. Benefit/Cost Ratio (2 / 1) 4.286 to 5.022 4.319 to 5.159 B. Average Annualized Equivalent Values:* 1. Regulatory Costs (1A+1B+1C) $1,474 $587  1A. Engineering Controls $491 $236  1B. Ancillary Regulatory Requirements $107 <$1  1C. Conversion to Dry CCR Disposal $876 $350 2. Regulatory Benefits (2A+2B+2C+2D): $6,320 to $7,405 $2,533 to $3,026  2A.Monetized Value of Human Cancer Risks Avoided $37 $15  2B. Groundwater Remediation Costs Avoided $34 $12  2C. CCR Impoundment Failure Cleanup Costs Avoided $128 to $1,212 $58 to $550  2D. Induced Impact on Future CCR Beneficial Use $6,122 $2,450 3. Net Benefits (2 - 1) $4,845 to $5,930 $1,947 to $2,439 4. Benefit/Cost Ratio (2 / 1) 4.286 to 5.022 4.319 to 5.159 * Note: Average annualized equivalent values calculated by multiplying 50-year present values by a 50-year 7% discount rate “

factor” of 0.07246. 
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 

“Special Waste” 

Subtitle D 

(version 2) Sub

A. Present Values: 1. Regulatory Costs (1A+1B+1C) $20,349 $8,095  1A. Engineering Controls $6,780 $3,254  1B. Ancillary Costs $1,480 $5  1C. Conversion to Dry CCR Disposal $12,089 4,836 2. Regulatory Benefits (2A+2B+2C+2D): ($230,817) to ($215,847) $1168 to $7,965  2A. Monetized Value of Human Cancer Risks Avoided $504 (726 cancer risks) $207 (296 cancer risks) $104  2B. Groundwater Remediation Costs Avoided $466 $168  2C. CCR Impoundment Failure Costs Avoided $1,762 to $16,732 $793 to $7,590  2D. Induced Impact on CCR Beneficial Use ($233,549) $0 (no impact) 3. Net Benefits (2-1) ($251,166) to ($236,196) ($6,927) to ($130) 4. Benefit/Cost Ration (2/1) (11.343) to (10.607) 0.144 to 0.984 B. Average Annualized Equivalent Values:*1. Regulatory Costs (1A+1B+1C) $1,474 $587  1A. Engineering Controls $491 $236  1B. Ancillary Costs $107 $0.36  1C. Dry Conversion $876 $350 2. Regulatory Benefits (2A+2B+2C+2D): ($16,725) to ($15,640) $85 to $577  2.A Monetized Value of Human Cancer Risks Avoided $37 $15  2.B Groundwater Remediation Costs Avoided $34 $12  2.C CCR Impoundment Failure Cleanup Costs Avoided $128 to $1,212 $57 to $550  2.D Induced Impact on CCR Beneficial Use ($16,923) NA 3. Net Benefits (2-1) ($18,199) to ($17,115) ($502) to ($9) 4. Benefit/Cost Ration (2/1) (11,347) to (10.610) 0.145 to 0.983 * Note: Average annualized equivalent values calculated by multiplying 50-year present values by a 50-year 7% discount rate “

factor” of 0.07246. 
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 

“Special Waste” 

Subtitle D 

(version 2) Sub

A. Present Values: 1. Regulatory Costs (1A+1B+1C) $20,349 $8,095  1A. Engineering Controls $6,780 $3,254  1B. Ancillary Costs $1,480 $5  1C. Conversion to Dry CCR Disposal $12,089 4,836 2. Regulatory Benefits (2A+2B+2C+2D): $2,732 to $17,702 $1168 to $7,965  2A. Monetized Value of Human Cancer Risks Avoided $504 (726 cancer risks) $207 (296 cancer risks) $104  2B. Groundwater Remediation Costs Avoided $466 $168  2C. CCR Impoundment Failure Costs Avoided $1,762 to $16,732 $793 to $7,590  2D. Induced Impact on CCR Beneficial Use $0 (no change) $0 (no change) 3. Net Benefits (2-1) ($17,617) to ($2,647) ($6,927) to ($130) 4. Benefit/Cost Ration (2/1) 0.134 to 0.870 0.144 to 0.984 B. Average Annualized Equivalent Values:*1. Regulatory Costs (1A+1B+1C) $1,474 $587  1A. Engineering Controls $491 $236  1B. Ancillary Costs $107 $0.36  1C. Dry Conversion $876 $350 2. Regulatory Benefits (2A+2B+2C+2D): $198 to $1,283 $85 to $577  2.A Monetized Value of Human Cancer Risks Avoided $37 $15  2.B Groundwater Remediation Costs Avoided $34 $12  2.C CCR Impoundment Failure Cleanup Costs Avoided $128 to $1,212 $57 to $550  2D. Induced Impact on CCR Beneficial Use $0 $0 3. Net Benefits (2-1) ($1,277) to ($192) ($502) to ($9) 4. Benefit/Cost Ration (2/1) 0.134 to 0.870 0.145 to 0.983 * Note: Average annualized equivalent values calculated by multiplying 50-year present values by a 50-year 7% discount rate “

factor” of 0.07246. 
Chapter 1 

Problem Statement: The Need for RCRA Regulation of CCR Dispo

1A. Institutional Context For purpose of evaluating Federal regulations, the 1993 Executive Order 12866 “Regulatory Planning and Review” (each Federal regulatory agency to identify the problem that it intends to address, including where applicable, the failupublic institutions that warrant new agency action, as well as to assess the significance of the problem. In line with th

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

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 agen

of regulatory analysis required under Section 6(a)(3)(c) of the 1993 Executive Order 128665 “Regulatory Planning an

guidance is OMB’s September 17, 2003 “Circular A-4 Regulatory Analysis.”6 Section A (Introduction) of Circular Aelements 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 alte

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

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

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 
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 ele

required by law and will correct market failure. 

1B. EPA’s Proposed Regulation of CCR Disposal Is Required by LawIn 1976, Congress amended the 1965 Solid Waste Disposal Act (the first federal statute that specifically focused on imdisposal methods) by adding industrial hazardous waste management requirements as Subtitle C, among other new reamendment is the 1976 Resource Conservation & Recovery Act (RCRA). The EPA’s regulatory evaluation of coal c

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

to implement Subtitle C (i.e., Sections 3001 to 3020 of RCRA). At that time, the EPA recognized that certain large-vincluding wastes from the combustion of fossil fuels (aka “CCR” as named in this RIA), might warrant special treatm

regulation. On 18 December 1978, EPA proposed but deferred and never finalized a relatively limited set of ten RCRhazardous waste regulations for the management of CCR.8 Included in this deferral of hazardous waste requirements 

industrial wastes --- which EPA termed “special wastes”9 --- until further study and assessment could be completed brisk 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 he

than the wastes being identified for regulation as RCRA hazardous waste. On 12 October 1980, Congress enacted thAct Amendments of 1980 (Public Law 96-482) which amended RCRA in several ways. Pertinent to “special wastes” 

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 “Utility Waste” of “Hazardous Waste Guidelines and 

proposed the following ten regulatory conditions: (a) waste analysis standards, (b) waste site selection standards, (c) waste site security, (d) wrecordkeeping, (f) reporting, (g) waste site visual inspections, (h) waste site closure, (i) waste site post-closure care, and (j) groundwater mon

9 To learn more about these six “special wastes” see EPA’s special waste website at http://www.epa.gov/osw/nonhaz/industrial/special/index
Bevill Amendments10 which exempted “special wastes” from regulation under Subtitle C of RCRA until further study 

could be performed: 

• 1980 Bentsen Amendment (RCRA 3001(b)(2)(A)): Exempted drilling fluids, produced waters, and other wastes a

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

• 1980 Bevill Amendment (RCRA 3001(b)(3)(A)(i-iii)): Exempted fossil fuel combustion waste; waste from the e

and processing of ores and minerals (including phosphate rock and overburden from uranium ore mining); and ce

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

Congress on its findings. As itemized in Appendix A to this RIA, since 1978, EPA continued to evaluate CCR (as w

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

supports is a continuation of those prior evaluations. 

1C. EPA’s Proposed Regulation of CCR Disposal Will Correct Market FailureOMB’s 2003 Circular A-4 “Regulatory Analysis” guidance (pages 4 to 5) to Federal agencies for implementation of E

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 “negative externality” of env

damages from CCR disposal landfills and impoundments. As summarized in the “Benefits” Chapter 5 of this RIA, thistorical and recent environmental damage cases which represent externalities, in that some or all of the (a) human hhuman cancer cases from contaminated groundwater near CCR disposal sites) and (b) environmental damages (i.e., eresource damages, and socio-economic damages from CCR spills/releases from structural failures in CCR disposal im

external to the capital and operating costs of the electric utility plants. If implemented, the CCR proposed rule may b

market failure externality, by internalizing into the capital and operating costs of the electric utility plants, the added cengineering 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. Haccountability can be imperfect. The primary human bearers of the external costs from CCR disposal are households 

When an unorganized group of households suffer external costs, they face a host of obstacles to having their costs rec

10 These 1980 RCRA “special waste” amendments are named after US Senator Lloyd Bentsen (D-TX; Senate service years 1971-1993) and U

Bevill (D-AL; House service years 1967-1997). Source: Biographical Directory of the US Congress at http://bioguide.congress.gov/biosearc
form a coherent organization and they must have enough funding to launch and maintain a lawsuit. On the other side households usually face a single firm often with greater legal funding resources. This imbalance suggests that extern

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 – inadequate or asymmetric information. Ci

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

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

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-economassociated with a large environmental disaster involving the collapse of a CCR impoundment in 2008. On 22 Decemgallons (i.e., 5.4 million cubic yards) of CCR was unintentional environmental released over 300 acres from the collaAuthority (TVA) coal-fired electric utility surface impoundment in Kingston TN. This event caused significant dama

Emory River, a nearby recreational lake, community roadways, a gas pipeline, and a railroad. As indicated in Exhibi

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

estimated at $933 million to $1.2 billion. This event attracted major citizen, national press, and Congressional interes

management and the urgent need for prevention of such future environmental and community damages. In the wake 14 January 2009 Senate confirmation hearing, EPA Administrator-designate Lisa P. Jackson, testified11: 

“I think that you’ve put your finger on a very important thing that EPA must do right away, which is to ass

of other sites that are out there. Many of them ... are ... up hill from schools or from areas where just the of having this mountain of wet coal ash, if there’s a break, can endanger lives immediately. So I would thto first and foremost assess the current state of what’s out here and where there might be another horrible to happen ... EPA currently has and has in the past, assessed its regulatory options with respect to coal astime to re-ask those questions and re-look at the state of regulation of them from an EPA perspective.” 

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

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

“Several lawmakers have introduced, or announced plans to introduce, competing legislation to regulate Senate Environment & Public Works Committee Chairwoman Barbara Boxer (D-CA) said she would introcompelling EPA to regulate CCR in the event the Obama EPA fails to act soon. "If we are not satisfied wimove legislatively," Boxer told EPA Administrator-designate Lisa Jackson at a January 14 [2009] confirm

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

11 Lisa Jackson’s 14 January 2009 Senate confirmation hearing testimony and webcast is available from the US Senate Committee on Enviro

website at: http://epw.senate.gov/public/index.cfm?FuseAction=Hearings.Hearing&Hearing_ID=ae2c3342-802a-23ad-4788-d1962403eb76 

12 Source: Waste Business Journal, “EPA Vows to Act on Coal Waste,” 23 January 2009, http://www.wastebusinessjournal.com/news/wbj20
Just three weeks after the TVA’s Kingston TN CCR impoundment disaster, House Natural Resources Committee ChWV) introduced legislation requiring federal standards to regulate the engineering of CCR impoundments.13 Introdu

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

design, engineering, and performance standards on CCR impoundments to avoid a repeat of the damage done in Kingwhich requires minimum design and stability standards for all surface impoundments constructed to hold coal ash, drmodel for impoundments that is used for coal slurry management under the Surface Mining Control and Reclamation 

In a letter dated 02 March 2009, the Environmental Integrity Project and Earthjustice, joined by the National ResourcSierra Club, Environmental Defense, and 104 other environmental groups requested EPA Administrator Lisa Jackson possible” to regulate CCR. A letter signed by the groups and delivered to EPA on 03 March 2009 identified 12 princ

development of EPA standards. These include the phase-out of CCR surface impoundments, locating CCR disposal groundwater or surface water, requiring liners, leachate collection systems and adequate monitoring, and requiring in

term liability for cleanup: 

“The recent disaster at TVA's Kingston Plant stands as a startling reminder that federal standards for CCoverdue. For too long, power companies have been able to dump CCR, laden with a host of toxic metals liselenium, lead, mercury, and boron, in unlined mines, quarries, landfills, and surface impoundments. Witfederal standards governing disposal practices, contaminants can leak or spill from these dump sites, threhuman health, natural resources and wildlife.”14

On 04 March 2009, US Senators Barbara Boxer (D-CA) and Tom Carper (D-DE) submitted Senate Resolution 64 to Environment and Public Works. This resolution calls on the EPA to “immediately” inspect all CCR impoundments acoal-fired electricity plants, and to propose and finalize “as quickly as possible” rules to regulate CCR under RCRA.1

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 
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. “Directly affectentities potentially subject to any of the rule’s requirements.16 In addition, there are 14 or more industries which bene

1. Coal-Fired Electric Utility Industry 

The scope of industrial plants directly affected by the regulatory options is classifiable according to at least two differ

• Classification #1 of 2: The scope of industrial plants is classifiable as “coal-fired electric utility plants” under th

North American Industrial Classification System” NAICS code 22 “Utilities” economic sector, and in that sector, 

1,245 establishments within the NAICS 221112 “Fossil Fuel Electric Power Generation” industry:17

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

generation facilities. These facilities use fossil fuels, such as coal, oil, or gas, in internal cocombustion turbine conventional steam process to produce electric energy. The electric enthese establishments is provided to electric power transmission systems or to electric powesystems. 

• Classification #2 of 2: The scope of industrial plants is classifiable as “electric utilities plus independent power 

Energy Information Administration (EIA) categorization system for its coal combustion electric power sector stat

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

distribution assets and operations, either directly or indirectly, through cost-based rates seauthority (e.g., State Public Service Commission), or is owned by a governmental unit or th

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

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

16 Source: “EPA’s Action Development Process: Final Guidance for EPA Rulewriters: Regulatory Flexibility Act”, OPEI Regulatory Develo

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 
2. Waste & Environmental Management Services Industries 

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

some regulatory options may trigger RCRA facility-wide corrective action, the regulatory options of the proposed rul

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

options evaluated in this RIA). 

NAICS 562212: Solid waste landfill industry (may represent baseline offsite CCR landfills to which th

495 electric utility plants may transport some or all of the 15 million tons per year CC

NAICS 562219: Other non-hazardous waste treatment and disposal industry (may represent baseline o

which some or all of 149 of the 495 electric utility plants may transport some or all o

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 “beneficia

industrial applications. These industrial applications are listed below with corresponding NAICS20 codes estimated b

the regulatory options evaluated in this RIA establish CCR disposal requirements, industries which beneficially use Cthis RIA as potentially “indirectly” affected by the proposed rule rather than “directly” affected (i.e., subject to the ru

1. Concrete/concrete products/grout NAICS 3273 Cement & Concrete Product Manufactur2. Blended cement/raw feed for clinker NAICS 3273 Cement & Concrete Product Manufactur3. Flowable fill NAICS 23 Construction 4. Structural fills/embankments NAICS 23 Construction 5. Road base/sub-base NAICS 237310 Highway, Street & Bridge Constructio6. Soil modification/stabilization NAICS 23 Construction 7. Mineral filler in asphalt NAICS 324121 Asphalt Paving Mixture & Block Man8. Snow and ice control NAICS 488490 Other Support Activities for Road Tra9. Blasting grit/  Roofing granules 

NAICS 212319 Other Crushed & Broken Stone MininNAICS 324122 Asphalt Shingle & Coating Materials 

10. Mining applications NAICS 212 Mining 

19 Source: American Coal Ash Association (ACAA) “2007 Coal Combustion Product (CCP) Production & Use Survey Results (Revised)” at 

usa.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/

• 2-digit codes represent economic sectors 

• 3-digit codes represent economic sub-sectors 

• 4-digit codes represent industry groups 

• 5-digit and 6-digit codes represent single industries 
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. The

are identified here to provide a rough estimate of potential additional cost for regulation if they were added to the scoaddressed in a separate but similar rulemaking. 

• 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. 

operating status categories consisting of an estimated count of at least 197 additional CCR disposal units excluded fro

• Inactive units: CCR impoundments and landfills not in operation or not receiving CCR. Inactive impoundm

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

• Abandoned units: CCR impoundments and landfills not in operation and closed. These impoundments usually 

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 

this RIA based on known data for large volume coal mining slurry waste impoundments. There are an estimated 1,60

impoundments in operation across the US in coal-related industries (i.e., coal mining industry plus industries which bthere are another 670 coal waste impoundments which are no longer in operation but still contain coal waste slurry (i

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 

plants estimated in this RIA using CCR impoundments, yields an estimate of at least 66 inactive/abandoned CCR implocated at electric utility plants (i.e., (158 impoundment using electric utility plants) x (0.42 ratio) = 66). 21 Source: Definitions of “inactive” and “abandoned” coal waste impoundments from page 23 of the National Research Council book Coal WResponses 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 footnote
This RIA did not discover similar data for coal waste landfills in active and inactive/abandoned status. For purpose oRIA, multiplying the 0.42 inactive/abandoned:to:active ratio by the 311 electric utility plants which use landfills, indi131 inactive or abandoned CCR landfills at or near electric utility plants (i.e., (311 landfill using electric utility plantsAs of 2004, the Mine Safety & Health Administration (MSHA) oversees 646 active coal mining slurry impoundment

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

158 electric utility plants, which implies that a fraction of 796 other active coal waste impoundments (i.e., 954 – 158 electric power plants in non-utility industries (see the next sub-section below “Other Industries Excluded from Scope

• Other Industries Excluded from Scope 

The scope of the proposed rule only includes NAICS code 22 coal-fired electric utility plants (495 plants). However, 759 non-utility facilities which currently, or have the capacity to, burn coal and thus generate CCR. Adding these facproposed rule could increase the cost estimates by 2% to 28%. This range is based on the following two data sourcesSource #1: As displayed below in Exhibit 2A based on 2005 data from the DOE-EIA, there are 139 non-utility co

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

other industry plants according to NAICS industry codes. If these other non-utility industries were to 

the CCR proposed rule, a rough estimate of potential additional cost and benefit impacts would be betw

to the impacts estimated in this RIA: • >2%: Compared to the 369,183 megawatts (MW) nameplate capacity for the coal-fired electr

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

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

electricity generation capacity. For purpose of rough estimation – in so far that electriccorrelates to annual CCR generation and thus to annual CCR disposal costs and to regu

percentage indicates that the additional economic impact of including these additional 1

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

• <28%: On the other hand, some CCR disposal costs and regulatory costs better correlate to the 

of CCR landfills and impoundments, not to electricity generating capacity. For such coutility plants to the scope of the proposed rule could increase the cost estimates for each to 28% (i.e., (495 + 139) / (495)). 

23 Source: MSHA “Supporting Statement” for Information Collection Request (ICR) 1219-0015 “Refuse Piles and Impoundment Structures, 

Requirements”, March 2008: http://www.msha.gov/regs/fedreg/paperwork/2004/04-24046.pdf 
Source #2: EPA’s 2002 analysis24 of the results from a 2001 survey of non-utility CCR generation identified 759 

the capacity to burn coal, and therefore, generate CCR.” The estimated annual CCR generation for thetons (as of year 2000), which is 5.5% to 6.3% of the 123.1 million to 141.2 million tons CCR generate

in 2005 as estimated in Exhibit 3D of this RIA. Allowing for annual growth of the 7.8 million tons siadding these 759 facilities to the scope of the proposed rule could increase the cost estimates by 7%.

24 Source: “Analysis of Non-Utility Coal Combustion Waste Generation and Management Based on the 2001 CIBO Voluntary Survey,” prep

Science Applications International Corp (SAIC) Engineering & Environmental Management Group (Reston VA) under subcontract to EasterVA), April 2002, EPA contract No. 68-W-02-036, WA 12:. 
Exhibit 2A 

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

2005 

Count 

NAICS 

Sector 

NAICS 

Industry NAICS Industry Code Definition 

2005 

Boiler coun

1 21 2122 Ore mining 4 2 31 311 Food Manufacturing 63 3 31 3122 Tobacco Manufacturing 3 4 31 314 Textile Product Mills 11 5 32 321 Wood Product Manufacturing 1 6 32 322 Paper Manufacturing 9 7 32 322122 Newsprint Mills 98 8 32 32213 Paperboard Mills 19 9 32 325 Chemical Manufacturing 31 

10 32 325188 All Other Basic Inorganic Chemical Manufacturing 5 11 32 325211 Plastics Material and Resin Manufacturing 9 12 32 326 Plastics and Rubber Products Manufacturing 4 13 32 327 Nonmetallic Mineral Product Manufacturing 8 14 32 32731 Cement Manufacturing 2 15 33 331 Primary Metal Manufacturing 5 16 33 331111 Iron and Steel Mills 1 17 33 331312 Primary Aluminum Production 3 18 33 333 Machinery Manufacturing 7 19 33 3345 Navigational, Measuring, Electromedical, Control Instruments Mfg 10 20 33 336 Transportation Equipment Manufacturing 1 21 33 337 Furniture and Related Product Manufacturing 1 22 33 339 Miscellaneous Manufacturing 1 23 48 482 Rail Transportation 2 24 48 483 Water Transportation 3 25 61 611 Educational Services 37 26 62 624 Social Assistance 2 27 92 92 Public Administration 14 

 Count = 8 Count = 27 Column Totals = 354 

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 Rep"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 des

group, the fifth digit designates the NAICS industry, and the sixth digit designates the national industry. The five-digit NAICS cwhich there is comparability in code and definitions for most of the NAICS sectors across the three countries participating in NAStates, Canada, and Mexico). The six-digit level allows for the United States, Canada, and Mexico each to have country-specific and valid NAICS code contains six digits. Source: http://www.census.gov/eos/www/naics/faqs/faqs.html#q5 
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 

and Subtitle D --- contained in EPA’s 1976 RCRA waste management statutory authority: 

Option 1: RCRA Subtitle C “special waste”: 

• Regulate CCR disposed in landfills and surface impoundments as “special wastes” und

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

• Eliminates health risks from groundwater and surface water contamination for both lan

impoundments, and avoids damages from uncontrolled ground “fill” operations (e.g., G

Chesapeake VA) and attendant environmental remediation costs. 

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

• Provides for corrective action, including at closed units at facilities with surface impoun

regulated under the rule, and imposes groundwater monitoring requirements. 

• Provides for Federal oversight, which EPA experience has shown is necessary for succe

RCRA industrial waste regulations, especially as it relates to ground-water monitoring when needed. Without Federal oversight, it is highly questionable whether CCR will bconsidering EPA’s experience with the RCRA program of the last 10 years, which illusthat could be expected of a Subtitle D rule. 

Option 2: RCRA Subtitle D “non-hazardous” industrial waste (version 2): 

• Liners required for all (i.e., existing and future new) CCR surface impoundments but on

Subtitle D requirements would set national criteria for landfills and surface impoundmeafter the rule goes into effect. For any CCR landfills and impoundments that closed bethere would be no regulatory controls over those units, unless the states choose to adopAlso, all surface impoundments (existing and new) would need to have composite linereffective date. Consistent with the Subtitle C approach, existing landfills would not nee

• Requirements would not be enforceable by EPA or the states (unless states had similar 

law). Lack of enforcement and Federal oversight may significantly reduce compliance implementation of regulatory requirements. 

• Although this option does not require phase-out of existing surface impoundments, it co

because all surface impoundments would need to have composite liners by a certain dat

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

• Eliminates some ground-water contamination over the current situation (e.g., because o

retrofitting), thus avoiding some damage cases, again assuming effective implementatio
• Require review of surface impoundments for stability by independent experts, but beca

remain in operation (because they are currently lined or owners choose to retrofit line th

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

Option 3: RCRA Subtitle “D prime”: 

• Regulation of disposal under subtitle D, with liners required only for new surface impound

approach would be the same as the subtitle D approach above, except that existing surface be required to retrofit and install a composite liner, or close. Unlined existing impoundmen

operate, but new landfills and surface impoundments or expansions of existing landfills mu

• Under this approach the potential for catastrophic failure of surface impoundments would r

phase-out of surface impoundments wouldn’t occur. 

• Would be less effective than the subtitle C or subtitle D approaches in eliminating groundw

having it be discovered sooner), but would still provide some benefits over no national reguon state regulations and enforcement would apply as in the subtitle D option.) 

• Would reduce regulatory costs significantly since conversion to dry disposal would not be 

provide fewer benefits. 

Evaluation of three regulatory options is consistent with OMB’s 2003 “Circular A-4: Regulatory Analysis” best pract

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

1. Beneficial use: All options propose to replace the 1980 RCRA “Bevill exclusion” under 40 CFR 261.4(b)(4) f

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

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., tech

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

standards” described in EPA’s August 1999 cement kiln dust (CKD) proposed rule26 were used in absence of 

specific to CCR disposal units. This was a reasonable starting point because the CKD management standards 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/ass26 EPA’s 20 August 1999 CKD proposed rule (Federal Register, 67 pages). 
During EPA’s April 2009 launch of this RIA, EPA defined three other RCRA options which are very similar to the abinitial set of options is included in EPA’s October, 8 2009 initial draft (165 pages) of this RIA which EPA submitted 

mid-October 2009. The regulatory cost estimation in Chapter 4 and the supplemental analyses in Chapter 7 of this initial set of three options, defined as follows: 

2009 Option 1: RCRA Subtitle C “hazardous” industrial waste: 

• Subtitle C provides Federal enforceability. 

• RCRA Section 3004(x)27custom-tailor engineering controls (i.e., technical standards) for C

• Subject CCR to Subtitle C land disposal restriction (LDR) treatment standards prior to disp

• Dry CCR (landfills): Moisture conditioning and compaction to attain 95% dry den• Wet CCR (impoundments): Dewatering and dry disposal within 5 years after rule’

2009 Option 2: RCRA Subtitle D “non-hazardous” industrial waste (version 1): 

• This option is different from the 2010 Option 2: Subtitle D option because it does not require 

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

landfills). 

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

controls as the 2009 Option 1. 

• Except under RCRA Section 7003 “imminent and substantial endangerment” authority, this 

enforceable because RCRA Subtitle D directs EPA only to assist state government waste ma

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

• Subtitle C regulation of CCR impoundments (same as the 2009 Option 1) • 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 “to modify” the RCRA 

for regulation of CCR disposal: 

“Section 3004(x): If... (2) fly ash waste, bottom ash waste, slag waste, and flue gas emission control waste generated primarily fro

other fossil fuels... is subject to regulation under this subtitle, the [EPA] Administrator is authorized to modify the requirements of 

(o) and (u) and section 3005(j), in the case of landfills or surface impoundments receiving such solid waste, to take into account the wastes, the practical difficulties associated with implementation of such requirements, and site-specific characteristics, including b

geology, hydrology and soil chemistry at the site, so long as such modified requirements assure protection of human health and the 

28 Section 4001 of Subtitle D of the 1976 RCRA statute prescribes the Federal role under Subtitle D as assistance to state governments: “The 

to assist in developing and encouraging methods for the disposal of solid waste... Such objectives are to be accomplished through Federal tassistance to States or regional authorities for comprehensive planning pursuant to Federal guidelines designed to foster cooperation among 

governments and private industry.” 
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. Thicomponents described in this Chapter: CCR disposal and CCR beneficial use. This Chapter begins with a description management quantities (i.e., annual tonnages of CCR) and CCR disposal methods used by the electric utility industrypresents an evaluation of baseline operating conditions (i.e., “engineering controls” and “ancillary costs”) of CCR disestimate of the associated costs to the electric utility industry. This Chapter concludes with a characterization of base

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

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 D

(DOE), Energy Information Agency (EIA) database for electricity power plants from the Form EIA-860 "Annual EleThis data was supplemented with the master list of utility plants from the 2007 EIA-860 database entitled “existingun

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

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

System (NAICS) industrial codes, and deleted all plants not assigned utility sector NAICS code 22 (only 2codes are provided by the EIA database). NAICS 22: The Utilities sector comprises establishments engaged in the provision of the following util

electric power, natural gas, steam supply, water supply, and sewage removal. Within this sactivities associated with the utility services provided vary by utility: electric power includtransmission, and distribution; natural gas includes distribution; steam supply includes prodistribution; water supply includes treatment and distribution; and sewage removal includtreatment, and disposal of waste through sewer systems and sewage treatment facilities. Exsector are establishments primarily engaged in waste management services classified in SuManagement and Remediation Services. These establishments also collect, treat, and dispo

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

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

The file contains generator-specific information such as initial date of commercial operation, prime movers, generating capacity, energy sourproposed generators, proposed changes to existing generators, county and State location (including power plant address), ownership, and FEAlso included are data related to the ability to use multiple fuels; specifically, data on co-firing and fuel switching are included. The DOE sis available at http://www.eia.doe.gov/cneaf/electricity/page/capacity/capacity.html. 
materials; however, they do not use sewer systems or sewage treatment facilities” Source: 

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

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

using the coal type codes displayed in Exhibit 3A below. In addition to these five categories of coal, examprimary or secondary energy sources reported by coal burning electric utility plants are agriculture byprod

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 f

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

• Database filter #3 of 3: The first two filter criteria resulted in a subset of 506 coal-fired electric utility p

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

out-of-service, 2 plants reported that all generators are on standby and all remaining plants reported that generators is operating. Removal of the 11 out-of-service plants from the master list resulted in a total a495 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 860 database to identify which plants are owned by the same company. Company owner classifications were also chusing internet searches by plant and company name which sometimes revealed parent company owners. As summari

30 OP = Operating - in service (commercial operation) and producing electricity. Includes peaking units that are run on an as needed (inter

Out of service – 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, available for service but not normally used (has little or no generation during the year) for this reporting period, RE = Retired - no longer in s

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

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 

31 This RIA filtered out 11 out-of-service electricity plant identification codes: 508, 511, 996, 1732, 2341, 2468, 2529, 2531, 2908, 3419, an32 In comparison, a 2008 EPA Office of Water (OW) study estimated a nationwide total of 497 coal-fired electric plants using the same 2005 

plants estimated in this RIA are less than the 2008 EPA OW estimate because this RIA takes account of more recent plant operating status in

have converted to other non-coal fuels or are not operating). Source: Table 3-1 (page 3-9) of EPA Office of Waster “Steam Electric Power GCategory: 2007/2008 Detailed Study Report,” report nr. 821-R-08-011, August 2008; http://www.epa.gov/guide/304m/2008/steam-detailed-2
Exhibit 3C below, these 495 coal-fired electric utility plants are owned and operated by 200 entities which are listed RIA. The 495 plants have a combined electricity generation nameplate capacity of 369,183 MW (megawatts), rangin

from 2.3 MW to 3,969 MW, with an average size of 746 MW and a median size of 497 MW. This combined capacit

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 

1 Federal government Non-small 11 2 State government jurisdictions (authorities, districts) Non-small 13 3 Medium & large population municipal government jurisdictions Non-small 27 4 Medium & large companies Non-small 372 5 Medium & large cooperatives (this RIA assumes all privately-owned) Non-small 20 6 Small county government jurisdictions (commission) Small 1 7 Small municipal government jurisdictions (agencies, commissions) Small 33 8 Small companies Small 12 9 Small cooperatives (this RIA assumes all privately-owned) Small 6 

Summary: 

Column totals = 495 

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

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

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

Notes: * Type of owner entity estimated and assigned by EPA ORCR based on owner name or internet research on type of ownershi** Size class determined according to the following numerical threshold criteria consistent with EPA’s Nov 2006 guidance fo

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 siz

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 “small government jurisdiction

government of a city, county, town, township, village, school district, or special district with a population of less t

• 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/epa
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 En

Item State 

Federal 

government 

State 

Government 

Non-small 

municipal 

Non-small 

company 

Non-small 

cooperative 

County 

government 

Small 

municipal 

Small 

company 

1 AK 2 2 AL 2 7 1 3 AR 3 4 AZ 2 3 1 5 CA 6 6 CO 1 2 11 7 CT 2 8 DC 9 DE 3 

10 FL 5 9 1 11 GA 10 1 12 HI 2 13 IA 1 13 3 14 ID 15 IL 2 21 16 IN 21 5 17 KS 2 6 18 KY 2 1 14 3 1 19 LA 4 20 MA 4 21 MD 8 22 ME 1 23 MI 2 13 5 2 24 MN 1 10 5 25 MO 5 10 2 2 26 MS 3 1 1 27 MT 4 1 28 NC 19 3 29 ND 2 5 30 NE 4 3 31 NH 2 32 NJ 1 6 33 NM 3 34 NV 2 35 NY 11 1 1 36 OH 2 20 4 37 OK 1 4 1 38 OR 1 
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 En

Item State 

Federal 

government 

State 

Government 

Non-small 

municipal 

Non-small 

company 

Non-small 

cooperative 

County 

government 

Small 

municipal 

Small 

company 

39 PA 32 2 40 RI 41 SC 4 10 42 SD 2 43 TN 7 44 TX 1 2 14 1 45 UT 1 4 1 46 VA 15 1 47 VT 48 WA 1 49 WI 12 3 2 50 WV 16 51 WY 8 1 

Column totals= 11 13 27 372 20 1 33 12 

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

according to the following five types of coal fuel categories: 

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

• Lignite coal (LIG): 21 plants (4%) • Coal-based synthetic fuel (SC): 19 plants (4%) • Sub-bituminous coal (SUB): 201 plants (41%) • 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 th

and the types of coal burned for the list of 495 plants. As displayed in the state-by-state Exhibit 3D below, 47 states utility plants (3 states --- ID, RI, VT --- and DC do not have electric utility plants). The top-5 state coal-fired electric 

1. PA 34 plants

2. IN & OH 26 plants each

3. IL 25 plants

4. MI & NC 22 plants each

5. KY 21plants
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 

and Associated CCR Gen

Item State 

Count of 

Plants 

(2007) % of Plants 

C

(t

30 NE 7 1.41% 31 NH 2 0.40% 32 NJ 7 1.41% 33 NM 3 0.61% 34 NV 2 0.40% 35 NY 13 2.63% 36 OH 26 5.25% 37 OK 6 1.21% 38 OR 1 0.20% 39 PA 34 6.87% 40 RI 0 0% 41 SC 14 2.83% 42 SD 2 0.40% 43 TN 7 1.41% 44 TX 19 3.84% 45 UT 6 1.21% 46 VA 16 3.23% 47 VT 0 0% 48 WA 1 0.20% 49 WI 17 3.43% 50 WV 16 3.23% 51 WY 9 1.82% 

 Total 495 100% 1

* Note: In comparison to this estimate based on DRIA, the American Coal Ash Association (ACAACCR generated in 2005 based on its annual volunhttp://acaa.affiniscape.com/associations/8003/file%2809-19-06%29Corrected-11-09-07.pdf 
3B. Types of CCR Disposal Units 

• 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 Inactive or abandoned units (i.e., non-operating units) are excluded from the scope of this RIA. The data source used management practices and active units is the 2005 U.S. Department of Energy (DOE) Energy Information Administra

“Steam-Electric Plant Operation and Design Report” database.34 The EIA-767 database is the primary data source fo

disposition for plants generating greater than 100 MW (megawatts) of electricity. Plants smaller than 100 MW are no

tonnage and disposition (i.e., type of disposal and beneficial use) data to the EIA-767 database. Schedule 3 of the EIAthe annual disposition of CCR in one or more of the following five forms of CCR management categories, according 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 disposal4. 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 EIAplants are over 100 MW in size and thus are covered by the EIA-767 database. For the 132 plants which did not repo

in the 2005 EIA-767 database because they are less than 100 MW in size, disposal of CCR is assumed to take place in landfills (whichever is the lowest-cost method as assigned by the CCR disposal engineering control cost model used fthe 495 coal-fired utility plants identified in the prior section of this RIA using the 2007 EIA-860 database, baseline Cwere assigned using the methodology and data sources presented below. Based on this analysis, 467 of the 495 planfollowing methods. The 28 remainder of the 495 plants do not dispose because they solely supply their CCR for bene

of the 495 plants supply CCR for beneficial uses. The total count of disposal methods exceeds the 467 total count of some plants use more than one disposal method. The EIA-767 database does not contain counts of disposal units for counts are summarized below according to disposal method, not CCR disposal unit counts. Because some plants use 

unit, the total count of CCR disposal units – although unknown for purpose of this RIA -- exceeds the 467 total count 

34 Source: The EIA-767 database includes annual data from organic-fueled or combustible renewable steam-electric plants with a generator n

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

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

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 

of the data elements previously collected on the Form EIA-767 for 2005 with the corresponding data elements to be collected beginning with Form EIA-860 or the Form EIA-923: http://www.eia.doe.gov/cneaf/electricity/2008forms/consolidate.html 
• Onsite landfills: 311 plants operate onsite CCR landfills (this RIA refers to these as “onsite” landfi

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

 212 plants: dentified through actual data reporting of 363 coal-fired electri

contained in the 2005 EIA-767 database, out of the total 495 plants identif860 database (as described in the previous section above). 

 99 plants: This estimate is based on the remainder 132 electric utility plan

plants = 132 plants) between 1 MW and 100 MW size for which there is nEIA-767 database, and for which the CCR disposal engineering control coassigned the lowest-cost of three landfill options: (1) onsite dug landfill, (2(3) offsite landfill. The cost model assignment was dependent upon the levcontrols assumed required by each plant’s state location and annual CCR d

model estimated that 99 of the 132 plants without data dispose CCR in ons

• Onsite impoundments: 158 plants operate onsite CCR surface impoundments (aka “ponds,” “embankmen

dumps,” “constructed wetlands”). This RIA assumes that all impoundments are “o

be located off plant property. The non-duplicative count of plants using onsite landfills and/or onsite impoundme

• Offsite disposal: 149 plants assigned as sending CCR offsite for disposal to commercial landfills (o

ship CCR for offsite disposal). Off-site landfills receiving CCR are assumed to alr

with EPA’s RCRA Subtitle D guidance. The 149 plants assigned as using offsite l

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

 116 plants: Electric utility plants >100 MW size (source: 2005 EIA-767 da

of wastes is reported as either (a) company-owned landfill, (b) company-owon-site use & storage, (d) sold, or (e) off-site disposal. This RIA assumes means offsite commercial landfill. Plants could have reported offsite minewas not "sold" (e.g., they paid to dispose it in a mine or it was used as minmade to the electric utility). However, it is unknown the sub-quantity of “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 R

disposal” tonnages as commercial landfills. The DOE-EIA contact person responded with additional information from four 2005 Form EIA-how electricity plant respondents optionally characterized the fly ash and bottom ash reported in the Form EIA-767 survey questionnaire as “· “This quantity of fly ash was given away at no cost” · “The fly ash was sent off site for beneficial use” · “The fly ash is injected into the nearby mines for recharging the mines” · “Ash is recycled as a beneficial re-use product for flowable fill in the construction industry” 
• 92 plants Offsite landfill fly ash • 76 plants Offsite landfill bottom ash • 4 plants Offsite landfill gypsum • 16 plants Offsite landfill FGD • 7 plants Offsite landfill other CCR (i.e., coal combustion by-produ

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

 33 plants: This estimate is based on the 132 electric utility plants between 

for which there is no CCR disposal data in the EIA-767 database, and for wengineering control cost model used in this RIA assigned the lowest-cost o(1) onsite dug landfill, (2) onsite pile landfill, or (3) offsite landfill. The codependent upon the level of baseline engineering controls assumed requirelocation and annual CCR disposal tonnage. 

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

• Source #1 of 2: ASTSWMO: The February-March 2009 ASTSWMO voluntary participation survey36 of 42 state

coverage of the 47 states identified in this RIA for the 495 coal-fired electric plants) estimates a total of 484 electrdisposal units: 

• 227 electric utility plant CCR landfill units in 41 states • 257 electric utility plant CCR impoundment units in 33 states • 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 NAICS code 221112, (b) may also include counts of CCR disposal units associated with other industries which genin the surveyed states, (c) may include inactive/abandoned as well as active CCR disposal units, or (d) may include 

operated by electric utility plants which contain other types of waste streams (e.g. waste water treatment ponds with

Source #2 of 2: EPA: In March 2009 EPA sent letters37 to 210 coal-fired electric plant facilities and owner compan

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

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

Conservation and Recovery: http://www.astswmo.org/files/publications/Positionpapers/ASTSWMO-CCB-letter-attachments.pdf 
flooding at the TVA Kingston TN electricity plant. Although not used in this RIA other than for reference here, the March 2009 EPA letters resulted in identification of 584 CCR impoundments units at electric utility plants. The lett

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 

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, lag

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

Schedule 8, Part A of the 2007 DOE EIA database for the Form EIA-932 “Power Plant Operations Report” database Instead, the most currently available waste data was from the 2005 DOE EIA Form 767 “Steam-Electric Plant Operat

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

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

categories in the 2005 EIA 767 database. As estimated in this RIA and displayed below in Exhibit 3E, the 495 electr141.2 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, respecti

123.1 million tons (2005) and the 131.1 million tons (2007) annual CCR generation estim

the American Coal Ash Association (ACAA).39 The numerical discrepancy between this the ACAA estimates may be explained by the fact that both estimates (i.e., this RIA and thbased on incomplete CCR tonnage disposition data for less than the “universe” of all know

37 Source: Additional information about these March 2009 EPA letters is available at http://www.epa.gov/osw/nonhaz/industrial/special/foss38 Source: EPA’s 584 CCR impoundment unit count is documented at http://www.epa.gov/osw/nonhaz/industrial/special/fossil/surveys/faqs.39 As of the date of this RIA, ACAA’s “Coal Combustion Products Production & Use Statistics” website contains annual CCR generation an

tonnage estimates for the US electric utility industry for years 2001, 2002, 2003, 2004, 2005, 2006, 2007, and 2008. As reported in footnoteresults data tables, ACAA’s CCR generation and CCR beneficial use annual tonnage estimates are based on the following survey coverages: 

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 

2008 274 plants. ACAA’s annual CCR tonnage data webpage is at http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=3 
electric utility plants in the data year, extrapolated to plants for which there is no CCR tonEIA database (in the case of this RIA’s estimation methodology) and in the case of the ACextrapolated to plants not covered by ACAA’s annual utility industry survey by supplemedata. 

The estimate of CCR generation developed in this RIA consists of the following breakout of generation estimates acc

utility plant size categories, which correspond to the CCR tonnage disposition data reporting cut-off requirement in th

• >100 MW plants: Exhibit 3E below presents CCR disposition data for a sub-total of 120.9 million tons CCR 

reported by plants with annual electricity generation >100 MW from Schedule 3A of the 2each plant. • Ash generation data (fly ash and bottom ash) were available for 385 plants. • FGD sludge generation data were available for 72 plants. • Gypsum generation data were available for 31 plants. • Other byproduct generation data were available for 40 plants. 

If plants > 100 MW reported either company landfill, company disposal ponds, sold for ben

disposal of CCR in the EIA-767 database, these final disposition practices are assumed in thtotal 179 plants with company-owned CCR landfills and 158 plants with company-owned Cimpoundments were reported in the 2005 EIA-767 database (i.e., 337 of the 495 electric pla

plants reported 8.2 million “on-site use and storage” which this RIA assigned as beneficial u

assumption is supported by (a) DOE’s August 2006 report41 “Coal Combustion Waste Man

Surface Impoundments 1994-2004” which interpreted the entire "onsite use & storage" quan

(b) the American Coal Ash Association (ACAA) which indicates that 49.6 million tons of cused in 200542. However, the beneficial use estimate in Exhibit 3E below is much less at 3

based on the EIA-767 “Sold” (i.e., beneficial use) CCR tonnage category. But adding the 8"onsite use & storage" yields an estimate of 47.0 million tons (Exhibit 3G), which nearly mbeneficial use estimate of 49.6 million tons. This suggests it is valid to assign the tonnage rdatabase 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 surfa

the 1995 EPRI Comanagement Survey. This data source was not used to identify CCR management units in this RIA given it dates back to used to identify existing engineering controls for the units identified in the 2005 EIA 767 database. In the 2005 DPRA Report, 14 additional 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%2

11-09-07.pdf 
• 1MW to 100 MW Exhibit 3F below presents an additional sub-total of 20.3 million tons per year of CCR ge

utility plants between 1 MW and 100 MW in capacity which had no CCR management inf

database, because plants less than 100 MW are not required to report their CCR managem

EIA-767 database. Therefore, this RIA formulated an estimate for this size category of plafollowing approach. Coal use and percent ash content data from Schedule 4A of the 2005 

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

EIA-767 coal use data were unavailable for 2005, coal use data from Schedule 4A of the 2were used to estimate CCR generation quantities for those 5 plants. FGD sludge generatioSchedule 843 of the 2005 EIA-767 database were used for 115 plants. Landfill (either on-s

is more economical) is the assumed CCR disposal practice. No gypsum or other byproduc

were estimated. For plants between 1 MW and 10 MW, ash generation quantities estimatenameplate capacity rating data from the 2007 DOE Form 860 database. This 1 MW to 100 plants consists of two sub-categories: 

• 10 MW to 100 MW: 5.4 million tons of CCR for 110 plants estimated by multiplyin

burned by the percent CCR content of the coal data from Schedule 4A of the 2005 EDOE EIA 923 database, or using generator nameplate rating data from the 2007 EIAaverage percent ash content. 

• 1 MW to 10 MW: 14.9 million tons of FGD sludge reported for 22 plants in Schedu

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

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

greater than 100 MW reported no final disposition quantities for FGD sludge in Schedule 3A of the 2005 EIA-767 database, the reported FGis assumed in this RIA to be placed in a landfill for that plant. 
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 

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) 

1 Fly Ash 21,324,280 15,212,590 3,744,370 20,760,230 9,314,540 2 Bottom Ash 5,707,740 4,311,630 3,487,660 5,453,717 1,907,480 3 Flue Gas Desulfurization Sludge 9,526,400 1,886,200 465,600 408,910 2,506,540 4 Gypsum (salable) 54,620 872,100 372,100 8,437,400 782,800 5 Other CCR 226,510 82,900 108,830 3,729,400 247,680 6 Totals 36.8 million 22.4 million 8.2 million 38.8 million 14.8 million 

Exhibit 3F 

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

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) 

1 Fly Ash 274,917 5,147,468 NA 2 Bottom Ash Included under Fly Ash Included under Fly Ash NA 3 Flue Gas Desulfurization Sludge NA NA 14,852,300 4 Gypsum (salable) NA NA Included in row 3 5 Other Byproducts Included under Fly Ash Included under Fly Ash NA 6 Totals 0.3 million 5.1 million 14.9 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 

Item CCR Category 

Company-Owned 

Landfill 

(Dry disposal) 

Company-Owned 

Disposal Ponds 

(Wet disposal) 

Beneficial Use 

(onsite BU + offsite 

BU + storage for BU) 

Offsite Disp

(assumed of

commercial lan

1 Fly Ash 26,471,748 15,212,590 24,504,600 9,52 Bottom Ash 5,707,740 4,311,630 8,941,377 1,93 Flue Gas Desulfurization Sludge 24,378,700 1,886,200 874,510 2,54 Gypsum (salable) 54,620 872,100 8,809,500 75 Other CCR 226,510 82,900 3,838,230 26 Totals 56.8 million 22.4 million 47.0 million 15.0 millio

 Percentages 40% 16% 33% 11% 
Exhibit 3H below summarizes the respective plant counts, annual tonnage CCR disposal, and electricity generation n467 plants which dispose CCR, according to type of CCR disposal method (i.e., CCR landfills and CCR impoundmenreported more than one management method, the sum of the plants across each disposal method exceeds the total cou

Exhibit 3H 

Summary of Plant Size and CCR Disposal Methods Estimated in this RIA

A B C 

Plants Using CCR Landfills (dry disposal) 

Characterizing Metrics Onsite Landfills Offsite** 

Plants Using CCR 

Impoundments*** 

(wet disposal) 

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) 

46

(C

2. Annual CCR Disposal (2005) • Minimum per plant = • Maximum per plant = • Mean per plant = • Median per plant = 

56.8 million tons (60%) 

• 400 tons • 1.82 million tons • 205,196 tons • 90,700 tons 

15.0 million tons (16%) 

• 20 tons • 1.28 million tons • 100,899 tons • 33,000 tons 

22.4 million tons (24%) 

• 500 tons • 1.04 million tons • 141,550 tons • 67,300 tons 

94

• • • • 

3. Nameplate capacity* (2007) • Minimum per plant = • Maximum per plant = • Mean per plant = • Median per plant = 

213,978 MW (58%) 

• 11 MW • 3,969 MW • 772 MW • 538 MW 

90,547 MW (25%) 

• 2 MW • 2,911 MW • 608 MW • 350 MW 

180,901 MW (49%) 

• 75.3 MW • 3,564 MW • 1,145 MW • 893 MW 

• • • • 

Notes: * Nameplate capacity = electricity generation output potential in megawatts (MW). ** This RIA assumes all reported “non-company offsite disposal” in the EIA-767 database involves offsite landfill dry disposal, bec

transport large volumes of wet (i.e., watery) CCR long distances. *** Surface impoundments are reported in the EIA-767 database as “company-owned ponds.” This RIA assumes all are located ons
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 mis based on the annual tonnage of CCR placed in the unit. CCR disposal unit size assumptions for this RIA are adoptthe 2005 DPRA Report: 

• Landfills sizes:

Designed as “combination fill landfills” 

 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 2,00

Designed as “pile fill landfills” 

 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 2,000,00

• 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 acre

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 (“Estimation of Costs for Regulating Fossil Fuel Combustion Ash Management at Large Electric Utilit

document ID nr. EPA-HQ-RCRA-2006-0796-0469), the EPA asked utility industry representatives for the typical lifespan years of CCR lan

Industry representatives provided a 40-year estimate for both. This estimate is supported by data provided by industry in the 1995 EPRI ComEPRI Survey, data describing six CCR landfills noted the year the unit was opened and the estimated date of closure. The average life expecmedian life expectancy is 38 years. Similarly, data provided for 18 CCR impoundments indicate an average life expectancy of 45 years and 

years. Therefore, this RIA assumes a 40-year lifespan for both landfills and impoundments. 
3E. Cost of Baseline CCR Disposal This Chapter presents characterizing data and estimates of the costs to the electric utility industry and to governmentindustry engineering controls and other costs associated with CCR disposal. OMB’s 2003 Circular A-4 “Regul

requires RIAs to measure the benefits and costs of regulations against a baseline defined as: 

Baseline = “[T]he best assessment of the way the world would look absent the proposed rule

The baseline developed here uses the most recent data year available and relies solely on publicly available data 

reports, updated using empirically-justifiable factors. For purpose of this RIA, the possible types of baseline costs in

A. Baseline “engineering control “costs for CCR disposal units: 

1. Ground water monitoring 2. Bottom liners 3. Leachate collection system 4. Dust controls – applicable to landfills only 5. Rain and surface water run-on/run-off controls – 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

8. Closure capping to cover unit 9. Post-closure monitoring requirements 10. Storage design and operating standards (tanks, containers, containment buildings) – not evaluated in this 

B. Baseline “ancillary costs” directly related to CCR disposal: 

11. Offsite disposal 12. Structural integrity inspections – impoundments only 13. RCRA facility-wide investigation (RFI) 14. Corrective action 15. Waste disposal permits 16. Inspection & enforcement 17. Remediation of environmental releases 

• 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 49

their CCR for beneficial uses not disposal), this RIA estimated baseline engineering controls at disposal units and ass
costs for each type of disposal (note: the sum of plant counts for each disposal category below exceeds 467 because sone 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 “baseline” is defined as existing conditions plus projection of future conditions over the 50-year futu

2012 to 2061 applied in this RIA (this RIA assumes year 2012 represents the first year when the final rule could take Baseline engineering controls were estimated using the following 2-step method which is based on two alternative anof information: 

• Step 1: If the plant reported controls in the 1995 EPRI Comanagement Survey, 1996 CIBO Survey, or the 199

the stricter of these controls or state-specified controls are assumed for the baseline. These studies contained contCCR landfills and 50 plants with CCR impoundments (i.e., 139 of the 495 electric utility plants). State regulationcontrols at 69 of the 89 landfill plants and 43 of the 50 impoundment plants with plant specific information (e.g., 

have indicated that the unit had a liner only but state regulations required groundwater monitoring and capping so were added). 

• Step 2: Controls specified under state regulations for 34 states are assumed for all other plants in those 34 stat

1995 EPRI Comanagement Survey data, 1996 CIBO Survey data, or 1994-2004 DOE-EPA Study data are availab

step resulted in assigning state-required controls to 201 plants with CCR landfills and 55 plants with CCR impoun495 plants). Overall state regulations were added to 270 plants with CCR landfills and 98 plants with CCR impou

For the 100 plants (i.e., 47 plants with landfills and 53 plants with impoundments) for which there 

studies, and no state-regulatory data on controls from Step 1, no controls are assumed under baseline for oimpoundments; this represents a worst case (i.e., high cost) assumption. 

The associated data sources and findings for each baseline characterization step are described below. 

• Step 1: Baseline Installed CCR Disposal Engineering Controls Identified in Prior Industry Surveys (1995, 1

The controls identified through the Step 1 prior studies were more stringent than the state government requirements d

o Landfills: Voluntary controls for 25 plants with landfills (9% of 227 plants landfills) receiving 6.4 mi

9% of total landfill CCR quantity) in 12 states (some are identified as voluntary because state regulatio

the state): AR, AZ, CA, IA, IN, KS, MD, MN, NE, SD, SI, WV. 
o Impoundments: Voluntary controls for 39 plants with impoundments (25% of 158 plants with impoun

million tons per year (i.e., 25% of total CCR impoundment quantity) in 14 states (some are identified a

regulations were not reviewed for the state): AL, FL, IA, IL, IN, LA, MN, MS, NM, OH, SC, TX, UT

• Step 2: Baseline State Government CCR Disposal Engineering Control Requirements for Landfills & Impo

Several states have already established certain CCR disposal unit design and operating requirements that are required 

upon the effective date of the regulation (e.g., groundwater monitoring), upon retirement of the disposal unit (e.g., pofor newly constructed units only. Appendix E of this RIA provides a summary of the state government requirements 

impoundments. Current CCR disposal regulations have been reviewed for the top 34 states that utilize coal for produrequired engineering controls at landfills and impoundments. The plants located in these states account for 99% of thmanaged in company-owned (i.e., onsite) landfills and impoundments. State regulations were reviewed for the followCO, FL, GA, IA, IL, IN, KS, KY, LA, MD, MI, MN, MS, MO, MT, NV, NM, NY, NC, ND, OH, OK, PA, SC, TN, TWI, WY. Below is a synopsis of the baseline state government requirements according to the engineering controls lis1. Groundwater monitoring requirements: 

• Point-of Compliance: 

Two options for point-of-compliance groundwater monitoring include installing monitoring wells at the unit b

meters of the unit boundary. Recent changes to state regulations suggest that states typically require unit boun

• Number of Wells: 

Certain states specify a minimum number of monitoring wells: FL (3 wells for impoundments), IA (1 well for 

wells for landfills), KY (3 wells for landfills), LA (3 wells for impoundments and landfills), MO (4 wells for i

landfills), ND (3 wells for impoundments), OK (3 wells for impoundments and 4 wells for landfills), TN (3 w

wells for landfills), WV (3 wells for impoundments and 4 wells for landfills). Well spacing design criteria for 

detection wells for FL, IA, and KS were reviewed. FL requires a minimum of one down-gradient detection w

within 50 feet of the unit. Iowa requires a minimum of one detection well every 600 feet placed within 50 fee

recommends a minimum of one-down-gradient detection well every 500 feet. 

• Monitoring Parameters: 

Two options for sampling include testing for chemical indicators and testing for RCRA hazardous waste Appe

(i.e., 40 CFR 261 Appendix VIII). Of the 34 state regulations reviewed, three states require chemical indicatoimpoundments [CO, PA, WV] and 11 states require chemical indicator monitoring for landfills [IA, FL, KY, M

WI, WV]. Three states require RCRA Appendix VIII constituent monitoring for impoundments [MO, PA, W

RCRA Appendix VIII constituent monitoring for landfills [GA, FL, IA, IL, MI, MO, OH, TN, UT, WV]. 

• Monitoring Frequency: 

Three options for groundwater sampling frequency include quarterly, semi-annual and annual. Of the 34 state one state requires quarterly sampling for surface impoundments [CO (depending on the ground-water classificrequire quarterly monitoring for landfills [IA (until baseline conditions are established), IL (first 5 years), MI]
annual sampling for surface impoundments [LA, MO, ND, PA (chemical indicators), WV] and 12 states requimonitoring for landfills [FL, GA, KY, LA, MO, OH (chemical indicators), OK, PA (indicator parameters), TN 

UT, WV, WY]. Three states require annual sampling for surface impoundments [CO (depending on the groun

PA (metals and VOCs), WV] and five states require annual sampling for landfills [IA (after baseline establish(metals, TOC, TDS, chloride, sodium and radionuclides), PA (metals and VOCs), TN (RCRA Appendix VIII 

• Timing of State Regulation Implementation: 

In the baseline, certain states require groundwater monitoring only for newly constructed units. These baselinfuture baseline cost streams in the cost model. Of the 34 state regulations reviewed, nine states require immedmonitoring requirements for impoundments: LA, MN, MO, ND, NV, NY, OK, SC, UT. Eight states that only monitoring only at newly constructed surface impoundments: CO, FL, KY, MI, NC, PA, WI, WV. 21 states rcompliance with monitoring requirements for landfills: AL, CO, GA, IA, IN, KS, KY, MI, MN, MT, NC, NDUT, VA, WA, WY. Ten states require groundwater monitoring only at newly constructed landfills: FL, IL, L

TX, WV, WI. 

2. Bottom liner requirements: 

• Impoundments: 

Of the 34 state regulations reviewed, 10 states require immediate compliance with liner requirements for surfa

(composite), KS (composite), KY (composite), LA (composite), MO (composite), ND (clay or synthetic), NV (composite), OK (composite), and PA (composite). Six states require liners only at newly constructed surface 

or soil), MI (clay or composite), NC (composite), WI (composite, synthetic or clay), WV (composite), WY (c

• Landfills: 

Of the 34 state regulations reviewed, 19 states require immediate compliance with liner requirements for land(clay or synthetic), GA (composite), IN (clay), KS (composite), LA (composite), MI (composite), MN (clay), (composite), ND (clay or synthetic), NY (composite), OH (composite), PA (composite), SC (composite or cla(composite), VA (composite), and WA (composite). 10 states require liners only at newly constructed landfil

double), IL (clay or composite), MS composite), MO (composite), NV (composite), OK (composite), TX (com

WV (composite), WY (composite). 

3. Leachate collection/detection system requirements: 

• Impoundments: 

Of the 34 state regulations reviewed, nine states require immediate compliance with leachate collection/detect

for surface impoundments: FL, KS, KY, LA, MO, ND, NV, NY, PA. Five states require leachate collection/dnewly constructed surface impoundments: CO, MI, NC, WV, WI. 

• Landfills: 

Of the 34 state regulations reviewed, 18 states require immediate compliance with leachate collection system AL, CO, GA, IN (karst areas only), KS, MI, MN, MT, NC, ND, NY, OH, PA, SC, TN, UT, VA, WA. 11 stat

collection systems at newly constructed landfills: FL, IL, LA, MS, MO, NV, OK, TX, WI, WV, WY. 
4. Dust control requirements: (landfills only) 

Of the 34 state regulations reviewed, 16 states require immediate compliance with dust control requirements (wett

and/or compaction) for landfills: CO, GA (compaction only), IA, IN, KS, MI, MN (includes compaction), ND (inc

OH, PA, SC, TN, UT, VA, WA. Nine states require dust controls only at newly constructed landfills: FL, IL (incl

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 requiremGA, IA, IN, KS, MD, MN, MT, NC, NY, OH, PA, SC, TN, UT, VA, WA. 11 states require run-on/run-off only alandfills: FL, IL, LA, MS, MO, NV, OK, TX, WI, WV, WY. 

6. Financial assurance for CCR disposal unit closure & post-closure care 

• Impoundments: 

Of the 34 state regulations reviewed, 11 states require immediate compliance with financial assurance require

impoundments: AZ, KY, LA, MN, MO, ND, NM, NV, OK, TN, and UT. Four states require financial assuranewly constructed surface impoundments: CO, MI, NC, WI. 

• Landfills: 

Of the 34 state regulations reviewed, 22 states require immediate compliance with financial assurance require

FL (new construction), GA, IA, IN, KS, KY, MI, MN, MO, MT, NC, ND, NY, OH, SC, TN, UT, TX, VA, Wrequire financial assurance requirements only at newly constructed landfills: FL, IL, LA, MS, NV, OK, WI, W

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 regulations were not updated as part of this RIA. The following is a synopsis of state government location restrictsurface impoundments and landfills, according to six categories of location restrictions (water table, floodplains, w

seismic zones, unstable karst terrain). • 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 s

NC (4 feet above seasonal water table), ND (within aquifer), OK (if less than 15 feet above ground-water ta

ground-water table), WY. 

o Of the 25 state regulations reviewed, eight states have location restrictions below the natural water table for 

above ground water), MI (4 feet above ground water), MN (5 feet above ground water), NC (4 feet above se(within aquifer), OH (5 feet above water table for wastes with higher leachate concentrations), TN (if less thtable). 

• 7-2: Floodplains: 
o Of the 25 state regulations reviewed, eight states have location restrictions in floodplains for surface impoun

permit), KY, MO (if closed with waste in place), NC, ND, OK (if dike not at least 1 foot above 100-year flo

o Of the 25 state regulations reviewed, 20 states have location restrictions in floodplains for landfills: AZ, CO

MI, MN, MO, NC, ND, OH, OK, PA, TN, WV, WI, WY. 

• 7-3: Wetlands 

o Of the 25 state regulations reviewed, five states have location restrictions in wetlands for surface impoundm

with waste in place), ND, PA, WV. 

o Of the 25 state regulations reviewed, 17 states that have location restrictions in wetlands for landfills includ

KY, MI, MN, MO, ND, OK, PA, TN, WV, WI, WY. 

• 7-4: Fault areas: 

o Of the 25 state regulations reviewed, two states have location restrictions in fault areas for surface impound

waste in place), WV. 

o Of the 25 state regulations reviewed, seven states have location restrictions in fault areas for landfills: AZ, C

and WI. 

• 7-5: Seismic zones: 

o Of the 25 state regulations reviewed, two states have location restrictions in seismic impact areas for surfac

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 landf

(if within 5 miles of epicenter of 4.0 earthquakes), TN, WV, WI. 

• 7-6: Karst areas: 

o Of the 25 state regulations reviewed, five states have location restrictions in unstable areas for surface impo

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, 

MO, ND, PA, TN, WV (1,000 feet away), WI. 

8. Closure cap controls 

• Of the 34 state regulations reviewed, nine states require immediate compliance with closure control require

impoundments: AZ (synthetic cap), KY (synthetic cap), LA (clay cap), MO (soil cap), ND (clay or syntheti

cap), OK (clay or synthetic cap), PA (clay or synthetic), TN (synthetic cap). Four states require closure conconstructed surface impoundments: CO (clay or synthetic cap), MI (clay or synthetic cap), NC (soil cap), W

• Of the 34 state regulations reviewed, 23 states require immediate compliance with closure control requirem

(synthetic cap), CO (clay cap), GA (soil cap), IA (clay cap), IN (clay cap), KS (soil cap), KY, MD (clay capcap), MN (clay cap), MO (soil cap), MT (clay cap), NC (soil cap), ND (clay or synthetic cap), NY (syntheti

cap), PA (synthetic cap), SC (synthetic cap), TN (clay cap), TX (synthetic cap), UT (soil cap), VA (syntheticap). Nine states require closure controls only at newly constructed landfills: FL (synthetic cap), IL (clay or cap), MS (soil cap), NV (soil cap), OK (clay cap), WI (clay cap), WV (soil or clay cap), WY (synthetic cap
9. Post-closure monitoring requirements 

• Of the 34 state regulations reviewed, 11 states require immediate compliance with post-closure groundwater mon

surface impoundments: AZ, LA, MO, ND, NM, NV, NY, OK, SC, TN, UT. Seven states require post-closure gr

only at newly constructed surface impoundments: CO, KY, MI, NC, PA, WI, WV. 

• Of the 34 states reviewed, 22 states require immediate compliance with post-closure groundwater monitoring requ

AL, CO, GA, IA, KS, KY, MD, MI, MN, MO, MT, ND, NY, OH, PA, SC, TN, TX, UT, VA, WA, WY. Eight st

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 

count and conditions of CCR storage or treatment tanks, containers, and containment buildings at electric utility plant

• 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 

utility plants which onsite dispose CCR (84 plants solely dispose CCR offsite; this RIA assumes that all offsite CCR 

and further assumes that all of those offsite landfills currently comply with the engineering controls described in this 

options). Exhibits 3I (for landfills) and Exhibit 3J (for impoundments) below summarize the assignment of baseline 

for these 411 plants which dispose CCR onsite. 
Exhibit 3I 

Baseline Compliance with State Government Engineering Control Requirements: CCR Landfills 

A B C D E F 

Future new CCR landfills Existing CCR 

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 

Volu

CCR d

in la

(ton

1. Groundwater Monitoring 302 97%* 69,706,646 97%* 272 81% 60,62. Bottom Liner 302 97%* 69,706,646 97%* 238 71% 52,53. Leachate Collection System 273 81% 62,696,310 88% 222 66% 49,24. Dust Controls 215 64% 40,634,681 57% 205 61% 42,75. Run on/Run off Controls 261 77% 60,342,426 84% 209 62% 46,26. Financial Assurance 266 79% 56,861,231 79% 231 69% 49,47. Site restrictins 1. Water table 98 29% 18,878,963 26% ND ND N 2. Floodplains 232 69% 50,072,235 70% ND ND N 3. Wetlands 199 59% 40,227,659 56% ND ND N 4. Fault areas 72 21% 18,816,363 26% ND ND N 5. Seismic zone 66 20% 13,056,165 18% ND ND N 6. Karst areas 152 45% 33,970,045 47% ND ND N8. Cap Synthetic or Clay 245 73% 52,234,482 73% 213 63% 46,0

Soil 48 14% 10,990,166 15% 50 15% 12,0

Clay/Soil 13 4% 5,419,918 8% 5 1% 3,02

9. Post Closure Monitoring 271 80% 61,444,140 86% 232 69% 53,210. Storage design standards ND ND ND ND ND ND N

Notes: ND = Not determined. Comparisons have not been made comparing the date the state site restriction regulation became effective and the construction for each plant. * According to the August 2006 DOE/EPA report “Coal Combustion Waste Management at Landfills and Surface Impoundments, 1994-

0004, 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 ac
Exhibit 3J 

Baseline Compliance with State Government Engineering Control Requirements: CCR Surface Impoundm

A B C D E F 

Future new CCR impoundments Existing CCR im

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 

V

CC

imp

(t

1. Groundwater Monitoring 123 78%* 17,472,000 78%* 78 49% 92. Bottom Liner 158 100%* 22,400,000 100%* 62 39% 63. Leachate Collection System 61 39% 7,676,710 34% 48 30% 54. Dust control NA NA NA NA NA NA 5. Runon/runoff control NA NA NA NA NA NA 6. Financial Assurance 63 40% 7,694,010 34% 58 37% 77. Site restrictns 1. Water table 28 18% 3,039,860 14% ND ND  2. Floodplains 51 32% 6,902,610 31% ND ND  3. Wetlands 34 22% 5,347,550 24% ND ND  4. Fault areas 15 9% 1,675,350 7% ND ND  5. Seismic zone 15 9% 1,675,350 7% ND ND  6. Karst areas 34 22% 5,347,550 24% ND ND 8. Cap Synthetic 38 24% 5,911,760 26% 31 20% 4

Soil 27 17% 2,490,050 11% 23 15% 2

Clay 3 2% 254,800 1% 3 2% 2

9. Post Closure Monitoring 78 49% 9,520,360 43% 65 41% 710. Storage design standards 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 thimpoundment construction for each plant. * According to the August 2006 DOE/EPA report “Coal Combustion Waste Management at Landfills and Surface Impoundments, 1994

0004, 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 ac
• Baseline CCR Disposal Cost Estimation 

This section presents baseline cost estimates for both onsite and offsite CCR disposal units (i.e., landfills and impounelectric utility plants which dispose CCR (CCR from the remainder 28 of the 495 plants is solely beneficially used). 

• Cost Estimation Framework 

• Cost calculations: This RIA contains three types of cost estimates (with decreasing relative degrees of expect

o Data-based estimates: Based on a landfill and impoundment engineering controls cost estimatio

robust and recent data inputs (e.g., 2005 or newer) pertaining to CCR quantities and disposal me

electric utility plants. The cost model was first developed by EPA in 1988 to support EPA’s 199

municipal solid waste RCRA Subtitle D landfills, and EPA’s 1999 proposed rule cement kiln du

The cost model consists of two software components; Appendix G to this RIA provides additionmodel: 

 1st of 2 cost model components: Unit Cost Component: The first component is a Fortran 

cost model which dates back to 1988. This model specifies the various steps and physica

footage sizes and associated quantities of labor, equipment and materials for the specified designing, constructing, operating, and closing a landfill or impoundment. Then it combcomponent data inputs, with input data on the prices/ costs/ fees for the physical componoutputs, the capital and annual O&M costs of specified sizes of landfills and impoundmecosts/fees used as input data include a wide range of items, such as the per-acre cost of la

equipment, labor, bottom liner materials, and cover materials. For this RIA, the model wgenerate individual cost estimates for a series of five alternatively-sized CCR landfills an

varying types of engineering controls to represent the range of sizes and engineering con

495 electric utility plants. The size categories are defined in tons per day of CCR dispos

45 The 1988 cost model is documented in the “User’s Manual for the Subtitle D Municipal Landfill Cost Model” draft report prepared for EP

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) “Draft Regulatory Impact Analysis for Pr

Criteria for Municipal Solid Waste Landfills,” prepared for US EPA Office of Solid Waste by Temple, Barker & Sloane, Inc., ICF IncorporaDPRA Inc.) and American Management Systems, Inc., 05 Aug 1988 (this document includes about a 4-page summary of the cost model); (bfor the Final Criteria for Municipal Solid Waste Landfills,” prepared for US EPA Office of Solid Waste by Temple, Barker & Sloane/Clayto

ICF Inc, DPRA Inc, and American Management Systems, Inc., Dec 1990 (this document includes about a 4-page summary of the cost modeRegulatory Impact Analysis for the Final Criteria for Municipal Solid Waste Landfills,” prepared for US EPA, Office of Solid Waste by TemEnvironmental Consultants and ICF Inc, August 1991; (d) “40 CFR Parts 257 and 258 Solid Waste Disposal Facility Criteria: Proposed Rule

No.168, pp.33314-33422, 30 Aug 1988; (e) “Revised Criteria for Municipal Solid Waste Landfills,” Federal Register Volume 56, pp. 50978Background Document: Compliance Cost Estimated for the Proposed Land Management Regulation of Cement Kiln Dust,” prepared for the Waste by DPRA Inc, 10 April 1998.; and (g) “40 CFR Parts 259, 261, 266, and 270 Standards for the Management of Cement Kiln Dust; Pro

Vol.64, No.161, pp. 45632-45697, 20 Aug 1999. 
impoundment is assumed to operate 300 days per year (average number of operating day

based on 2005 DOE EIA 767 database). The size categories are 10,000, 50,000, 200,000tons of CCR per year. Size is the primary determinant of overall cost; however, landfills exhibit increasing returns to scale: the larger the landfill or impoundment, the lower the c

managed. The cost equations generated by these unit cost model runs are used as inputs 

of the cost model to compute landfill and impoundment cost curves (equations) based on 

of engineering controls, so that a unique cost estimate may be assigned to each of the 495 

according to each plant’s unique annual CCR disposal tonnage. 

 2nd of 2 cost model components: Plant-by-Plant & Aggregate Cost Component: The seco

model is an Excel spreadsheet with Visual Basic programming used to estimate unique b

regulatory option costs for each electric utility plant. The spreadsheet is populated with pincluding plant location, known disposal and beneficial reuse practices, known or estimacontrols on CCR disposal units, annual CCR disposal tonnages, and known or estimated impoundment future closure years. The spreadsheet is also populated with the cost equatcomponent of the model for the various engineering controls (e.g., groundwater monitoriand for off-site landfill disposal costs. The Visual Basic programming is used for this RIcontrol costs for both the (a) baseline and (b) regulatory options for each plant over a 50-analysis (i.e., 2012 to 2061). The plant-by-plant estimated costs are then aggregated in ththe model on an average annualized basis. 

o Assumption-based estimates: These are based on relatively limited data, and/or older data (e.g., 

analysis transfer of results from other studies, or data from case studies, or based mostly on profassumptions 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 

potential lower- and upper-bound costs (i.e., bounding estimates). EPA defines “scenarios” as q

possible future conditions based on variations in key drivers of change, including social, technolinstitutional drivers. Scenario construction is a futures analysis method; as such, scenario-based predict the future with absolute certainty, but to explore uncertainties, possible consequences, an

• 2009 price level: Costs are normalized to beginning-of-year 2009 dollars using inflation factors developed by 

Record (ENR) Construction Cost Index, and using regional cost adjustment factors applied estimate involving on-site construction. These regional factors account for the variability band landscape construction costs. Cost adjustment factors are derived from the Means BuilYear 2003 city factors. All the cities for each state were averaged together to derive a state 

46 “Source: EPA Office of Science Policy, “Shaping Our Environmental Future: Foresight in the Office of Research & Development,” report 

at: http://www.epa.gov/osp/futures/FuturesHandbook.pdf 
• Before-tax costs: Baseline disposal costs estimated on a before-tax basis to approximate the overall economic c

allocation for the economy as a whole, rather than on an after-tax basis which would approximfinancial cost to the electric utility industry because after-tax costs subtract business expense 

depreciation of capital expenditures for pollution control equipment. 

• 50-year period: A 50-year future time horizon (aka period-of-analysis) was applied because new construction 

CCR disposal units and end of existing lifespan is estimated to have occurred at least once by 

• 7% discount rate: A 7% discount rate was applied for calculating both net present value cost and average annua

engineering control unit costs applied in this RIA. Because both the annualized baseline cost incremental proposed rule costs estimated in this RIA consist of primarily (i.e., >95%) indust

government cost, this RIA applies a 7% discount rate rather than a lower (e.g., 3%, 2%, 1% o

represent the opportunity cost of business capital investment and business expense financing return to corporate capital). This is consistent with OMB’s 2003 Circular A-447 (page 33) an

(page 8) which indicate that a 7% discount rate base-case should be used for regulatory analyexpected to primarily and directly affect businesses and industries. 

• 0.73% growth: Baseline cost estimates increased 0.73% per year over the 50-year future time horizon to refl

growth in coal consumption at electric utility plants (which is a proxy for future annual growt

CCR generation needing disposal from those plants). The 0.73% annual growth factor is bas2009 "Annual Energy Outlook 2009" forecast change in US coal consumption for electricity 2010 (22.91 quadrillion Btus) and 2030 (26.41 quadrillion Btus), available at: 

http://www.eia.doe.gov/oiaf/aeo/index.html

• Beneficial use: If reported in the baseline by any particular plant, beneficial use was assumed to continue in t

under the baseline projection over the 50-year future period-of-analysis. Section 5C in Chap

evaluates potential changes to this beneficial use baseline under alternative regulatory impact 

• Offsite disposal: If reported in baseline by any particular plant, offsite disposal was assumed to continue in the 

Offsite disposal landfill cost estimated under both baseline and regulatory options using the emodel. Truck operating cost estimated separately outside of the model. 

• Existing unit closure: One set of years for the opening and closure of disposal units are assumed for each facility

operation were provided in the 1995 EPRI Comanagement Survey, these data were used. If t

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/ 
one disposal unit and more than one reported date for initial year of operation, the years were 

if a facility had three disposal units (2 landfills and 1 impoundment) with installation dates of this RIA assumed the installation date of all the units was 1980. This assumption simplified t

per facility basis instead of a per disposal unit basis. If no disposal unit installation data were 

year is assumed to be equal to the earliest boiler installation year reported in either the 2007 Eplant or 1998 EIA 767 database, whichever was older. If no disposal unit or boiler installatio

available, an installation year of 1980 was assumed. If the 1995 EPRI Comanagement Surveclosure year for a unit, new unit installation is assumed to occur in that year. Otherwise, if no 

provided, closure is assumed to occur 40 years after the year of installation (assumed average 

and impoundments). 

• New unit construction: The timing of when baseline state regulatory requirements for newly constructed units be

on the installation and closure date for the existing disposal units. Baseline state regulatory c

incurred at the closure date of the disposal unit when new unit construction occurs. For examunit is assumed in this RIA to close in 2019; new unit construction costs required under state 

over its assumed 40-year future lifespan beginning in 2020. 

• New landfills: The most economic of three landfill options – (1) combination landfill w

ground and 50% above ground, (2) pile landfill with 5 % of waste below ground and 95

offsite landfill -- is determined within the cost model. The cost for the most economicathat plant unless available data specify otherwise. The choice is dependent upon on estcontrol costs and annual CCR disposal tonnage. 

• New impoundments: If currently used as a disposal unit, this RIA assumes a landfill w

future new disposal unit as impoundments reach end of lifespan, because the model calare more economical to construct for two cost reasons: (a) if no pre-existing land depreimpoundment, the cost for a larger excavation for a new impoundment rather than a smlandfill is necessary, and (b) the primary determinant of many of the cost for engineerin

of the disposal unit such that the same set of engineering controls for a new impoundme

expensive than for a new landfill. However, the cost model does not estimate the assocO&M costs for future conversion of existing wet ash and wet scrubber boilers and convconveyance equipment used for moving CCR to disposal units. These conversion costs outside of the cost model in this RIA. 
• Baseline “Engineering Control” Cost Estimates 

1. Baseline ground water monitoring Groundwater monitoring costs are based on the Remedial Action Cost Engineering and Requirements (RACER

(2002) with costs based on the R.S. Means, Environmental Cost Handling Options and Solutions (ECHOS), Enviro

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 c

150 meter point-of-compliance” criterion. Plants monitoring at the unit boundary will incur no additional costs unplacement criteria. 

 Number of wells: 

EPA’s March 1985 “Ground Water Technical Enforcement Guidance” Document (pages 2-8 to 2-16) recommendspacing between down-gradient wells. EPA’s December 1980 SW-611 “Procedures Manual for Groundwater MoDisposal Facilities” (pages 40 to 43) recommends a maximum of 250 feet spacing between down-gradient wells. 

documents are the most stringent and the state regulation minimums are the least stringent, a middle ground within 

and used in the cost estimates. This RIA does not evaluate the cost differences between the upper and lower boun

Groundwater monitoring well costs in this analysis assume a minimum of 2 down-gradient wells for the first 800 f

sides of the landfill or impoundment unit, which is assumed to be square, plus additional wells spaced every 400 f

gradient well is assumed. 

 Constituents: 

The cost estimates include monitoring for the following chemical indicators and metals, which represents a reasonscenario between indicators only and RCRA 40 CFR 261 Appendix VIII constituent monitoring which includes absubstances: 

o Chemical indicators: Based on EPA’s 1999 cement kiln dust proposed rule parameters (i.e., pH, conductivity

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, A

Cr, Pb, Hg, Se, Tl). 

 Frequency: 

The cost estimates only include semi-annual sampling (most-likely case) analogous to EPA’s 1999 cement kiln du

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

water monitoring, by the count of electric utility plants estimated in Exhibit 3I (row 1, column A) and Exhibit 3J 

to conduct that activity under state government requirements, yields an average annual per-plant (i.e., unitized) cocomparison, EPA’s most recent (2008) Information Collection Request (ICR) No. 0959.13 “Ground-Water Monito

(renewal) for the RCRA Subtitle C 40 CFR 264.92 and 265.92 TSDF “ground-water protection standard” provides 
per year.49 The $64,000 unitized cost for groundwater monitoring generated by the above assumptions applied in 

cost model used for this RIA is 2.3 times larger and more appropriate to this RIA because it reflects a larger numbmonitor the groundwater under the larger sized CCR disposal units compared to the average sizes of other types of 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

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. I

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 sprayi

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 in

model cost assumption is that four passes are made by the roller in 6-inch lifts. With these assumptions, the roller approximately 1,300 cy of ash per day. The operating life of purchased compaction equipment is assumed to be fisheepsfoot 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) 

• Water Truck for Compaction: 

Ash is assumed to be wetted in the waste management area by water trucks to facilitate compaction and to control duthat FFC plants currently use water trucks 50% of the operational day to control dust on roads (see Water Spray on R

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 repo

ICR 0959.13, Federal Register, Vol.73, No.103, page 30617; 28 May 2008; http://edocket.access.gpo.gov/2008/pdf/E8-11888.pdf 
assume that the same water trucks will be used for the roads and the ash management unit. Therefore, it is assumed this available for compaction 50% of the operational day. Additional water trucks are assumed to be necessary to facilitfacilities. The cost of tarps, tarp mechanisms, and installation of the mechanisms, as well as the life of each tarp were Functions for Alternative CKD Control Technologies” (Draft), 19 July 1996. A model assumption is that a water tru

compaction 50% of the time required by the compaction equipment. The water truck time for compaction is estimated 

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 leyear of ash. Facilities managing between 391,000 and 1,173,000 tons per year are assumed to purchase one additionamanaging between 1,173,000 and 1,955,000 tons per year are assumed to purchase two additional water trucks. Facil1,955,000 tons per year to the maximum facility size modeled of 2,000,000 tons per year are assumed to purchase thrThe cost of a water truck is assumed to be $101,000 in 1995 dollars. The water truck operating life is assumed to be fcosts for water spray for compaction are estimated assuming that the truck travels approximately five miles per day, ffuel consumption of five miles per gallon at a fuel cost of $1.15 per gallon. The truck is assumed to operate 50% of thcompaction. The daily water volume used is assumed to be 10,000 gallons, at a cost of $2 per 1,000 gallons. The annuash 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)] 

• Covers on Trucks: 

Covers on hauling trucks as a fugitive dust control technology is an option for the compliance scenarios. Capital cost

technology include the cost of the roll-on tarp mechanism and the installation of this mechanism. Capital costs for co

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 “Cost Functions for Alternative CKD Con

(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 e

every 150 loads. Replacement of a tarp is estimated to require 15 minutes. Annual costs for covers on trucks are estim

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) 

• Water Spray on Roads: 

Water spray on roads is required as a fugitive dust control technology for the compliance scenarios. A model assumpt

currently have water trucks and use water spray on roads as a baseline management practice. A model assumption 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 gallons and requires approximately one hour to fill. The water truck can spray a width of five meters at an assumed sp

For the baseline scenario, a model assumption is that the entire water volume (5,000 gallons) will be sprayed on each 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 hou
road and refill the truck, is approximately 2.5 times that of the average hourly daytime evaporation rate. Therefore, w

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 estimat

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 estim

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 approxievaporation rate. Since the total time required for water spray (1.25 hour) times 2.5 is approximately 3, a model assum

on roads is required approximately every 3 hours. In order to coordinate the water truck use for road spray and ash co

that the truck alternates between these two requirements during the day. Therefore, over a nine-hour day (eight workilunch), roads are sprayed 3 times, requiring a total of approximately 4 hours, or 50% of the operational day. Because facilities currently spray water on roads for dust control, the incremental cost from the baseline to the compliance sce

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 l

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 p

of closure, post-closure care, and corrective action for known releases, and to assure that adequate funds will be avail

these costs if the owner or operator is unwilling or unable to do so. Financial assurance helps protect future generatiodamages caused by or the prevention of damages potentially created from current waste management activities. Requ

financial assurance during operation of landfills and impoundments places the cost burden on the current owner and c

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 esta

The differences between RCRA Subtitle C and Subtitle D financial assurance mechanisms are not assessed. This RIA requirements for both landfills and impoundments: 

• Capital cost includes selection of financial assurance mechanism, establishment of financial test, and establishThe letter of credit is assumed to be most available to utilities and will be utilized in most circumstances. This is cost. • Annual cost includes maintenance of financial test and maintenance of letter of credit. Establishment and ann

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 anapplied the 2% midpoint of this range. Implementation costs are estimated on the assumption that an outside con

assistance will assist in obtaining and maintaining the letter of credit ($692 per year in 1995 dollars or $1,051 per 

dollars). Estimate obtained from Mohammad Iqbal and John Collier, ICF, Inc., “Local Government Financial Te
memorandum to George Garland, EPA, 30 April 1995. Additional supporting information obtained from EPA “EEconomic Benefits of RCRA Noncompliance,” 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. Cacapital expense. So, if a unit is expected to close in one year the total capping cost is assigned to the last year in the l

businesses are likely to borrow money from a bank for these large capital costs and annualize them over a set period o

20 years. Incremental cost estimates in the cost model are overestimated for large capital expenditures applied to exi

added over short time periods. In addition, owners are likely to close these units prior to the proposed rule coming in

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 s

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 

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-s

 Soil/clay cover is comprised of 0.5 foot clay, 0.5 foot earthfill, and 0.5 foot topsoil, and vegetation. Cover costs wo

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 assum

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 mo

basis. The physical parameters (i.e., point of compliance, number of wells, sets of chemical indicators and sets of monitored, and semi-annual frequency) and unit cost are assumed identical as defined in the baseline groundwater 

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 aff

utility owners) during the assumed average 40-year operating life of the CCR disposal unit. At the time of closure available in the fund to cover post-closure monitoring for the next 30 years beyond end-of-lifespan, assuming an a

10. Baseline storage tank/container design and operating standards Baseline cost not estimated in this RIA 
• 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 Subtit

using the same cost model as the engineering controls for onsite disposal units. In addition, the offsite disposal baselfor 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) 

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) = 

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 

Combustion Waste Management at Landfills and Surface Impoundments, 1994-2004”, report nr. DOE/PI-0004, Aug 

http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=2008). Per-plant cost for inspections estimated in Exhibit 3K be

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 

distance was reported by an OH plant at http://www.columbusdispatch.com/live/content/local_news/stories/2008/04/14/Powerfills.ART_AR08_B1_FF9TI0U.html?sid=101, and a WI plant, respectively at http://www.lacrossetribune.com/articles/2007/09/21/news/03landfill0921.txt 
Exhibit 3K 

Summary of Industry & State Government Labor Costs for MSHA Surface Impoundment Safety Plan & Annual 

& Estimate of Annual Costs for Similar Structural Integrity Activities for Electric Utility Plant Surface Impou

Item Paperwork Burden Element* Labor hours Cost (2006) C

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 

2 Revisions to Impoundment Safety Plan prepared by mining company engineer2 40 $70.07/hr 3 Fire Extinguishing Plan prepared by mining company engineer or supervisor 20 $70.07/hr 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 

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 

Subtotal (Industry costs): 

State Government Costs 

6 Review of Impoundment Safety Plans 160 hrs tech review + 

2 hrs admin review 

$30.57/hr 

7 Review of revisions to Impoundment Safety Plans 30 hrs tech review + 

2 hrs admin review 

$30.57/hr 

8 Review and prepare responses for impoundment abandonment plans 1 $30.57/hr 9 Review of annual inspection Status Reports and Certifications 1 $30.57/hr 

Subtotal (State government costs): 

Total Cost 

Total industry + state government cost: 

Notes: * Elements, labor hours, and labor costs are based on the “Supporting Statement” for the March 2008 DOL/MSHA ICR 12-19-0015, “RefuStructures, Recordkeeping, and Reporting Requirements” 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 in
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 

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 unalso located at the same plant) corrective action requirements, although some state governments have the following uaction requirements affecting CCR disposal units. State regulations for the top 25 coal usage states (for electricity) were reviewed for correction action requirements in were not updated as part of this RIA. Corrective action requirements were identified in 21 of the 25 states. 

• Surface impoundments: 71% of CCR impoundments representing 67% of CCR impoundment annual tonnage have 

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 

regulations 

o MO requires corrective action for units closed with waste in place, otherwise, corrective action may be estab

o NM requires an abatement plan. 

• Landfills: 66% of CCR landfills with 81% of CCR landfill annual tonnage have state government corrective action r

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 s

o MO, TN require assessment only 

o NM requires an abatement plan 

15. Baseline waste disposal permit cost 

• Assumptions: 

o 93% of CCR landfills have a state government non-hazardous waste disposal permit and 12% of CCR im

permits. Source: page 28, Table 9 of “Coal Combustion Waste Management at Landfills and Surface Im

August 2006 at http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=2008

• Industry waste disposal permit cost: 

o ($5,000 RCRA Part A permit) + ($50,000 RCRA general facility permit requirements) + ($25,000 avera

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 RCR

permits. Based on factor of 3.3 times more technical standards listed in RCRA Subtitle C (40 CFR 264/2

Subtitle D (40 CFR 257, 258), assume Subtitle D permitting costs are lower by the 3.3 factor: 
($80,000 per year average Subtitle C waste disposal permit cost) / (3.3) = $24,300 per non-haz waste dis[((93% landfills w/permit) x (337 landfills)) + ((12% impoundments w/permit) x (158 impoundments))] $8.1 million 

 Amortized industry cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $

• State government waste disposal permit cost: 

o Build estimate based on the following four RCRA Subtitle C permit-related state government activities a

Subtitle C waste disposal permits:51

(1,215 pre-application activities) + ($27,063 application review) + ($26,846 permit issuance) + ($3,110 p

$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 RCR

permits. Based on factor of 3.3 times more technical standards listed in RCRA Subtitle C (40 CFR 264/2

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 dis

o State Cost Calculation: 

[((93% landfills w/permit) x (337 landfills)) + ((12% impoundments w/permit) x (158 impoundments))] $5.85 million Amortized state cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $0.42 m

 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 “State RCRA Subtitle C Core Hazardous Waste Managemen

Costs Final Report” at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20C
• 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 av

plant 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 

A. Engineering controls (onsite disposal): 1. Ground water monitoring $19.2 $8.0 2. Bottom liners $2,751 $1,219 3. Leachate collection system $105.5 $52.2 4. Dust controls $24.2 $2.8 5. Water run-on/run-off controls $4.8 $0.7 6..Financial assurance $61.2 $17.9 7. Disposal location restrictions Not estimated Not estimated No8. Closure capping to cover unit $72.7 $15.7 9. Post-closure groundwater monitoring $1.3 $0.5 10. Storage design/operating requirements Not estimated Not estimated No

Subtotal Engineering Control costs = $3,040 $1,317 

B. Ancillary costs for CCR disposal: 11. Offsite disposal (commercial landfills) $1,193 $0 12. Structural integrity inspections $2.46 $2.18 13. RCRA facility-wide investigation (RFI) $0 $0 14. Corrective action Not estimated Not estimated No15. Waste disposal permits $0.69 $0.32 16. Enforcement inspection Not estimated Not estimated No17. Remediation of environmental releases Not estimated Not estimated No

Subtotal Ancillary costs = $1,196 $2.5 

Cost Summary (A+B) 

Column total annualized cost = $4,236 $1,320 

(includ

PV = 

Average annual cost per plant = $13.6 million per plant $8.4 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) 

(94.2 
• Validity Check of Baseline Cost Estimate (2 Tests): 

o Validity Test #1 of 2: Comparison to ACAA Published Estimate of Average CCR Disposal 

As displayed above in Exhibit 3L the estimated baseline (i.e., current) average annualized cost to the 495 coal-fired edisposal of CCR is $5.6 billion per year (2009$). This annualized cost includes amortization of capital investment in 

units and associated equipment (i.e., in-plant equipment for extracting CCR from boilers, CCR storage equipment, CCsuch as slurry pipelines for wet CCR or trucks and mechanical conveyor belts for dry CCR, and the disposal units the

expenditures for operation, maintenance and replacement/expansion of this equipment and disposal units. On a unitizcalculated by dividing the annualized baseline cost by the estimated 94.2 million tons per year (as of 2005) CCR disp

plus (b) offsite landfills plus (c) impoundments annually – the estimated baseline cost represents an average unitized 

In comparison, the American Coal Ash Association (ACAA) estimates that the average unit cost (per-ton) for baselin

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 displocated near the power plant and the material being disposed can be easily handled. If the material can be pi

trucked, costs are usually lower. In these types of situations, cost may be as low as $3 to $5 per ton. In other 

distance is far away and the [CCR] must be handled several times due to its moisture content or volume, costs 

$20 to $40 per ton. In some areas, the costs are even higher. If new sites are required and extensive permitti

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 h

cost range of $3 to over $40 per-ton reported by the ACAA, are: 

• Low-end unitized cost: The low-end of ACAA’s reported cost range is $3 to $5 per-ton. Assuming the chea

impoundment does not include a liner and leachate collection costs as estimated in this RIA for impoundmen

regulatory requirements, the baseline surface impoundment unitized cost may be as low as $2 per-ton based applied in this RIA. This low-end unitized cost may be derived from the impoundment cost column of Exhi

(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 

• High-end unitized cost: The upper-end of ACAA’s reported cost range is $20 to $40 per ton, which applies 

cost estimation of this RIA incorporates off-site commercial disposal costs on a state-by-state specific basis 

52 Source: ACAA webpage containing Frequently Asked Question nr. 13 at http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticl
power plant location, using commercial landfill tipping fees ($2009) for contaminated soil, which range wid

$135 per-ton, with a national average of $50 per-ton. For example, commercial landfill tipping fees for contthe high coal usage states are: TN = $11.19/ton, IN = $32.73/ton, OH = $35.48/ton, and PA = $57.96/ton. Testimation method of this RIA then added a CCR offsite transportation and loading cost of approximately $3

RACER cost estimation tool. For the estimated 15.0 million tons per-year of CCR disposed in offsite landficost is $1,193 million per-year, which is equivalent to $79.53 per-ton over the 50-year time period of the RI

assumes increasing coal usage (0.73% per-year) by electric utilities and subsequent offsite landfill disposal operiod. It is unknown what cost elements are included in the high-end of the ACAA reported cost range (e.g

and/or landfill tipping fee cost). In addition, electric utility companies likely have annual or multi-year contoperators that offer lower tipping fees than the state-average off-site contaminated soil tipping fees used in th

o Validity Test #2 of 2: Comparison to CCR Disposal Costs Contained in the EIA Form 767 

The 2005 Energy Information Administration (EIA) Form 767 database (Schedule 3, Part B) indicates $5,890 million 

O&M cost reported by steam electric plants with nameplate capacity of 100 MW or greater, including (a) $0.314 millpollution controls, (b) $0.193 million per year for solid waste disposal, (c) $0.185 million per year for other pollution 

million per year capital expense for air pollution abatement, and (e) $1,546 million per year for collection and disposbottom ash, and FGD. This last cost element --- $1,546 million per year for CCR disposal --- is only 28% of the $5,5estimate displayed in Exhibit 3L above. However, the 2005 EIA Form 767 cost data are associated with only 179 coplants, which represent only 36% of the 495 coal-fired electric utility plants addressed by this RIA. Therefore, to facthe $1,546 million per year cost from the data in EIA Form 767 may be extrapolated to all 495 plants by multiplying 495 / 179), which produces an estimated extrapolated cost for all 495 plants of $4,275 million per year (i.e., 2.765 x $

This extrapolated cost is 23% lower than the $5,556 million per year baseline cost estimated in this RIA. This compabaseline cost estimated in this RIA may be an over-estimate, but it is not clear whether the cost data in the EIA Form baseline costs to the electric utility plants for compliance with existing state government regulations concerning CCR 

annualized cost for obtaining and maintaining state government disposal permits and the annualized cost for impound

inspections), as does this RIA. 
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 optionshigh-end cost of those options (i.e., for the Subtitle C “hazardous waste” option) is larger than the high-end coregulatory options (i.e., for the Subtitle C “special waste” option), the costs in this Chapter are proportionately However, Section 6B of this RIA applies scaling factors to adjust the costs estimated in this Chapter to the 20

4A. EPA’s Prior Cost Estimates for Possible RCRA Regulation of CCR Disposal at Electric UIn prior studies, EPA’s Office of Solid Waste (which EPA renamed as the ORCR effective 18 January 2009), formula

compliance cost estimates for different RCRA-based regulatory approaches to CCR disposal by the electric utility ind1988: OSW's 1988 Report to Congress on CCR estimated $2.4 billion to $4.7 billion per year (1986$) in potential a

industry cost (514 plants in 1984) for compliance with technical standards contained in 40 CFR 264 RCRA Su

regulations. The range reflects different liner assumptions (i.e., single versus double liners) and whether only 

or all existing units close requiring construction of new units. This cost includes closure costs but not a cost f

excavating and removing CCR to Subtitle C facilities for closure of existing units. This report separately estimaction “at a cost of about $2.0 billion per plant, industry-wide costs would exceed $1.0 trillion” lump-sum cos

$43 billion annualized cost (discounted @3% over 40-years). Source: EPA-OSWER report nr. EPA/530-SW

1999: OSW’s 1999 Report to Congress focused on the “co-management” (i.e., low-volume mixed with high-volume

(i.e., 206 units at 353 plants in 1994), constituting 53 million tons (50%) of the 105 million total high-volume generation in 1997. This report estimated a range of $800 million to $900 million per year (1998$) in potent

compliance cost to the electric utility industry to comply with technical standards similar to 40 CFR 258 RCR

hazardous waste regulations. This cost estimate includes opening new CCR units to replace existing units that 

standards, including the following itemized costs: land purchase, site development, liner installation, leachate wells & monitoring, closure costs, and post-closure costs. This estimate accounted for state CCR managemen

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 

average annualized cost for the electric utility industry (i.e., 470 units at 452 plants in 2003) to comply with redeveloped with reference to the “tailored standards” of EPA’s 1999 cement kiln dust proposed rule which basCFR 258 RCRA Subtitle D non-hazardous waste regulations. Cost elements in this report included (a) locatio

criteria such as cover material, dust control, run-on/run-off control, (c) design criteria such as liner and leachagroundwater monitoring, (e) closure and post-closure standards, and (f) financial assurance for closure, post-c
action. This estimate accounted for state CCR management requirements as of 2004, but did not include costs 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 upestimates to the current 2009 price level, all three prior cost estimates exceed the 1993 Executive Order 12866 Sectiosignificant” $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) landfills and impoundments, and by size/type of affected electric utility plant owner entity. Incremental comparison o

each regulatory option to the baseline (as estimated in Chapter 3 of this RIA) is consistent with OMB’s 2003 “Circu

Analysis” best practices guidance to Federal agencies: 

“Identify a baseline. Benefits and costs are defined in comparison with a clearly stated alternative. This norm

action” baseline: what the world will be like if the proposed rule is not adopted.” 

As listed below, this RIA estimates 18 potential regulatory costs and the land disposal restriction (LDR) dewatering t

on many of the same unit cost data sources and the same framework (i.e., 2009 price level, 50-year period of analysisprior chapter of this RIA for baseline cost estimation. According to three methodological groupings, this RIA estima

regulatory costs: 

A. Engineering controls for CCR disposal units – estimated using the cost model described in the prior chapter 

1. Ground water monitoring 2. Bottom liners – for future new units only 3. Leachate collection system – for future new units only 4. Dust controls – applicable to landfills only 5. Rain and surface water run-on/run-off controls – 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, k

8. Closure capping to cover unit 9. Post-closure monitoring requirements 10. Temporary storage requirements – not estimated in this RIA because do not have information on the b

conditions of CCR storage tanks and storage buildings at electric utility plants. 
B. Ancillary costs for CCR disposal – estimated outside of the engineering control cost model: 11. Offsite disposal (hazmat trucking, RCRA manifesting, offsite RCRA TSDF permits) 12. Structural integrity inspections – 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 – Sections 3004(d) and (m) of the RCRA statute 

land disposal for Subtitle C hazardous waste listings, but not for Subtitle D non-hazardous waste regulation. Th

is to “substantially diminish the toxicity of the waste or substantially reduce the likelihood of migration of hazar

waste so that short-term and long-term threats to human health and the environment are minimized” (source: sec

o Dry CCR disposal (landfills): Moisture conditioning and compaction included in engineering c

o Wet CCR disposal (impoundments): Estimated outside and separately of the engineering controls cost 

This RIA does not include either qualitative or quantitative estimation of the potential effects of the proposed rule on 

economic growth, employment, job creation, or international economic competitiveness. These potential effects are i

both the 1993 Executive Order “Regulatory Planning and Review” (section 3(f)(1)) and in the 1995 Unfunded Manda

202(a)(4)). These other potential economic effects are excluded from this RIA because the upper-end of the range in regulatory cost across all regulatory options as estimated in this chapter below, does not exceed the 0.25% to 0.5% of 

(GDP) threshold identified in OMB’s 1995 guidance53 for attempting to measure such other economic effects for pur

analysis compliance. Based on the 2008 US GDP of $14.42 trillion,54 the 0.25% to 0.5% threshold is equal to $36 bi

 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 othe costs for engineering controls for all regulatory options are mostly, but not entirely, based on the same cost estima

above in Chapter 3 for estimation of baseline engineering control costs. Furthermore, this RIA assumes that the eng

53 Source: Section 4.B(3) of OMB’s 31 March 1995 guidance for implementing the UMRA state that “We would note that such macro-econo

measurable, in nation-wide econometric models, only if the economic impact of the regulation reaches 0.25 percent to 0.5 percent of Gross Dwith a smaller aggregate effect is highly unlikely to have any measurable impact in macro-economic terms unless it is highly focuses on a pa

economic sector.” 

54 Source: 2008 3rd quarter estimate of 2008 US GDP as reported in “TABLE B–8.—Gross domestic product by major type of product, 1959

Report of the President at http://www.gpoaccess.gov/eop/tables09.html 
similarly specified in EPA’s cement kiln dust 20 August 1999 proposed rule.55 This assumption was required to laun

prior to the initial draft of the CCR proposed rule and its regulatory options. This RIA assumes that liners and leacha

requirements apply only to future new CCR landfills and impoundments. Offsite disposal costs are assumed unaffect

options because offsite CCR disposal units are assumed to be commercially-owned units (i.e., owned by the waste ma

assumed currently in compliance with the custom-tailored engineering controls. For engineering controls added to ex

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 

• 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 location restrictions. As summarized below, the GIS analysis was conducted for three of the six possible site restricti

based datasets pertaining to fault areas, seismic zones, and karst zones readily available to EPA-ORCR at the 2009 la

limitation potentially results in under-estimation in this RIA of the number or electric utility plants which may be affe

estimation of regulatory location restriction costs. On the other hand, the average per-plant cost of $4.1 million appli

the potential cost of this regulatory element is over five-times higher than the $0.75 million56 cost per-plant cost estim

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

Plant Decision Matrix: Pond or Peninsula?,” 27 Jan 2005 Plant Managers Conference Room at http://www.tva.gov/kingston/tdec/pdf/TVA-0
location restriction mitigation involving karst mitigation and floodplain/wetland mitigation; this probably overly offs

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 

(disregarding four plants not present in the eGRID database). Appendix I of this RIA presents site location data for e

used in the GIS analysis. In order to geographically capture both the facilities and their waste units, and to compensaexists uncertainty as to the exact facility location versus the reported geographic coordinates (i.e., depending on whet

by plant centroid, street address, smokestack, etc.), this GIS analysis used both a 1-mile and a 3-mile buffer around th

coordinates. This RIA presumes these buffers are likely to ensure inclusion of the facility's onsite CCR disposal unit

uncertainty in the location data. The 1-mile buffer should capture all impoundments; the 3-mile buffer represents an 

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, “Quarternary Fault and Fold Database for the United States,” which 

location data on faults and associated folds.57 This analysis identified plants including their buffers which fall within 

have exhibited movement in the Holocene era. The USGS dataset includes fault lines that are believed to have been a greater than magnitude 6 during the Quarternary (the past 1,600,000 years) and it defines “Holocene” as the past 15 th

• 1-mile buffer: 1 plant falls within 200 feet of a fault line. • 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 are

According to the USGS fault line database, no relevant faults are located in the central and eastern US. The USGS description that this absence of identified faults with movement in the central and eastern US is partly a real phenomUS has more tectonic activity, but that it is partly a detection problem caused by geological characteristics present in US, such as glacial sediments, that conceal evidence of movement along faults. For this reason, the analysis of seismare defined based on the likelihood of future seismic activity, may represent a more reliable estimate of the number affected by fault area restrictions.60

57 US Geological Survey, 2006, “Quarternary Fault and Fold Database for the United States” at: http//earthquakes.usgs.gov/regional/qfaults. 58 RCRA defines “Holocene” as “the most recent epoch of the Quarternary period, extending from the end of the Pleistocene to the present” 59 Faults designated by the dataset as showing movement during the Holocene are not necessarily believed to have produced an earthquake o

the Holocene. Rather, they are believed to have produced an earthquake of magnitude 6 or greater during the Quarternary, but their most recdegree 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 Southw

appears generally consistent with a separate analysis in the RCRA Practice Manual (Garrett, Theodore L., 2004, published by American Bar 

number of plants affected is not unexpected given the relatively small number of plants in these regions. However, the RCRA Practice Manuplants 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 plants (out of the 491 plants analyzed), if all facilities in the identified states may be affected by fault area restrictions.
5. Seismic zone restrictions: To identify seismic zones, USGS National Seismic Hazard Maps provide peak horizontal acceleration at different proin 50 years.61 Identified those facilities, including their buffers, which overlap with the seismic impact zones that hav

probability of exceeding a maximum horizontal acceleration of 10% the force of gravity (i.e., 0.10 g) in 250 years.62 

probabilities of exceedance over 50 years; thus used a data layer presenting 2% probability of exceedance, and assum

10% probability of exceedance in 250 years. 

• 1-mile buffer: 151 plants fall within seismic zones • 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 t(disregarding four plants that were not present in the eGRID database), and (2) the USGS's GIS database "Engineerinwhich provides national-scale data on karst coverage.63 Four types of karst areas are identified in the dataset: (a) lontubes, and caves over 1000 feet long and 250 feet deep); (b) short karst (fissures, tubes, and caves less than 1000 feet 

(c) areas where karst features are generally absent but present in small isolated areas, and (d) pseudo-karst areas, whanalogous to karst. 

• 1-mile buffer: 138 plants fall within karst zones • 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 analys

upper bound of potentially affected facilities. 

• 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, count of 177 plants could be affected (this is the upper-end of the affected plant counts across the three location eva

cost to these plants of the location restrictions is estimated in this RIA using the cost to retro-fit existing CCR dispo

new CCR disposal units with a berm (aka levee). A berm is a type of engineering measure which may serve to dem

measures have been incorporated into disposal unit design to mitigate the potential adverse impacts disposal units m

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 

“Flood Proofing – How to Evaluate Your Options,” (July 1993), which provides unit costs in 1993 dollars to constr

levees that are two, four, and six-feet high. This RIA inflated these unit costs to 2009 dollars using the ENR Constrconducted a regression analysis on the unit costs (i.e., extrapolated the cost based on the implied cost curve of the smthe cost to construct a 10-foot tall berm. The estimated cost per linear foot to construct a 10-foot tall berm is $375. 

cost could apply to both existing and new units, and that the berm would be constructed physically separate from th

integral as “freeboard” to the disposal unit’s structure. 

61 U.S. Geological Survey, 2008, “National Seismic Hazard Maps,” from USGS website: http://gldims.cr.usgs.gov/nshmp2008/viewer.htm. 62 This threshold for seismic impact zones is consistent with RCRA’s municipal solid waste landfill location restrictions (40 CFR 258.14(a)(63 U.S. Geological Survey, 1984, “Engineering aspects of karst,” from USGS website: http://pubs.usgs.gov/of/2004/1352. File used: karst.sh
o Impoundment berms: The average surface impoundment size for existing units in the cost model is 34

square impoundment and that the berm would be constructed on three sides of the impoundment the aver

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. Ass

and that the berm would be constructed on three sides of the landfill (leaving one side open for truck acclength 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 

o Existing units: ($4.1 million average berm cost) x (177 disposal units) = $726 million 

Amortized with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $53 million/

o New units: Apply 0.73% average annual growth rate in future CCR generation (cited elsewhere in this R

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 

(712 units over 50-years) – (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 Amortized with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $23 million/

 Average annualized berm cost for existing + new units = $76 million/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 u

4B.2 Ancillary Regulatory Requirement Costs 

For estimating most of the “Other Ancillary Costs” in this section, this RIA distinguishes between RCRA Subtitle C a

requirements according to the respective basis of each regulatory option, as well as between costs to electric utility pl

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 estima

estimated an “assumed” cost of $500,000 for karst mitigation and $250,000 for floodplain mitigation for a potential new CCR disposal site imitigation. 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) 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 “Kingston Fossil Pl

Peninsula?”, 27 January 2005 Plant Managers Conference, http://www.tva.gov/kingston/tdec/pdf/TVA-00007487.pdf 
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 Subtitle C permitted. This cost estimate does not include taxes/trans-state government fees associated with off-site di

11a & 11b. Added truck hauling cost (Subtitle C options) 

Assumptions: 

• Affects the 12% (15 million tons per year) annual CCR generation currently trucked offsite to non-haz 

• 6 miles average one-way trucking distance to offsite LFs65

• $0.19/ton/mile hazardous waste truck operating cost • 12 tons CCR per full truckload (source: Gambrills MD case study); (15 million tons/year) / (12 tons/lotruckloads per year 

Cost Calculations: 

• 11a. RCRA manifest cost: (1.25 million truckloads) x ($53 per manifest per load average cost from EP

$66 million per year • 11b. Trucking cost (distance + operating cost): (15 million tons/year) x (6 miles) x ($0.09/ton/mile addfor hazardous waste loads) = $8.1 million per year • 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: 

• Added operating cost to offsite CCR landfills for meeting engineering control requirements under each of 

evaluated in this RIA are included in the “Engineering Control Costs” section above, so are not again calcdouble-counting. Only the paperwork burden cost for obtaining a RCRA permit is estimated here. 

• Industry average cost per waste disposal permit: 

($44066 average RCRA Part A permit application cost per-plant per-year) + ($68,96067 average RCRA 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) = $

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 

distance was reported by an OH plant at http://www.columbusdispatch.com/live/content/local_news/stories/2008/04/14/Powerfills.ART_AR08_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 “RCRA Hazardous Waste Permit A

Part A”, 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 “Part B Permit Application”, Fe

page 25237, 27 May 2009; http://edocket.access.gpo.gov/2009/pdf/E9-12285.pdf 
• 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 p$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) = $0.6

• Total Subtitle C permit cost (industry + state government) = $2.9 million per year 

Total cost for item 11 (11a + 11b + 11c): 

• Industry share of cost = $76.35 million per year 

• State government share of cost = $0.63 million per year 

• Total (industry + states) = $76.98 million per year 

12. Regulatory structural integrity inspection cost 

• Assumptions: 

EPA assumed that the residual 18% of the non-inspected plants require inspection over the 82% baseline inspec

The per-plant cost for inspections is estimated in the Chapter 3 baseline above. 

• 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 

• Industry RFI cost: • As of 2008, state government corrective action covers 64% of electric utility industry impoundments and 78% assume that 57 plants with impoundments (i.e., 36% x 158 plants with impoundments) plus 74 plants with landfilwith landfills) may require RFIs, for a total of 131 RFIs. • The purpose of an RFI is to obtain information to fully characterize the nature, extent and rate of migration of 

waste or constituents to determine whether interim corrective measures and/or a Corrective Measures Study may waste units at the facility (source: EPA 530/SW-89-031, May 1989, Vol.I). RFIs may include: rapid field screeniinstruments, drilling in soils, excavating test pits, ground-water monitoring, waste testing, biomonitoring, and site photography, site mapping. • 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 “State RCRA Subtitle C Core Hazardous Waste Managemen

Costs Final Report” at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20C
 $0.69 million average cost for RFIs involving captive industrial waste management (assume applies to impoun

Source: EPA OSRE memorandum “Transmittal of Average Cost of Investigation Derived from Fund-Lead SuMeasures Cost Compendium, and Compendium of Related Guidance Documents”, 01 Nov 2004. This memo remedial investigation costs can be used as a proxy for RCRA RFI costs. Industry RFI cost calculations: 

• Landfills: (74 landfills) x ($0.75 million average cost per RFI) = $55.5 million total cost • Impoundments: (57 impoundments) x ($0.69 million average cost per RFI) = $39.3 million total 

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 

• 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 Amortized state government RFI cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = 

equivalent • 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. Thro

corrective action, RCRA Subtitle C requires RCRA-regulated facilities to investigate and clean-up releases of hazardto the environment identified in the RCRA facility-wide investigation (RFI). After the RFI, if the need for cleanup is 

regulated facility must perform a “Corrective Measures Study” (CMS) which may range in cost from $100,000 to $80

State government cost for corrective measures study & corrective action review, approval, oversight is $117,300 per 

CMS is to develop and evaluate the corrective action alternative(s) and to recommend the corrective measure(s) be ta

As of 2008 the RCRA corrective action universe is about 3,800 sites nationwide.73 Relative to the RCRA-reg

217,500 facilities (consisting of about 16,000 hazardous waste LQG “large quantity generators” plus about 200,000 h“small quantity generators” plus about 1,500 hazardous waste TSDF “treatment, storage, disposal facilities” as of 200action universe implies a 1.75% relative incidence of occurrence (i.e., 3,800 / 217,500 = 1.75%). Corrective action c

facility depending on the number and types of waste management units and other industrial equipment/processes and 

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 ASTSW

Subtitle C Core Hazardous Waste Management Program Implementation Costs Final Report” 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 “Unit Cost Compendium” , document ID nr. EPA-HQ-RCRA-2002-0031-0429 71 Source: derived from cost data contained on page 83 of the ASTSWMO “State RCRA Subtitle C Core Hazardous Waste Management Pro

Final Report”, January 2007 at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%2

72 Source: “Corrective Measures Study Scope of Work”, EPA Region 3 at: http://www.epa.gov/reg3wcmd/ca/pdf/CMSATTC.pdf 73 Source: 3,800 corrective action cases represents EPA’s “2020 Corrective Action Universe” as identified on EPA Hazardous Waste Correc

website at: http://www.epa.gov/waste/hazard/correctiveaction/facility/index.htm#2020 
corrective action remedies usually involve mitigating damages to surface water and groundwater. The General Accou

reported74 that RCRA corrective action could cost 3,698 non-Federal hazardous waste treatment, storage, or disposal 

$16 billion (1996$) to clean up their properties contaminated by hazardous substances, representing an average $4.32

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) as described in 40 CFR 270 consisting of a two-part (i.e., Part A and Part B) application process. The paperwork burrequirement is estimated below. Furthermore, but not included in the cost estimate below, are separate, additional RCcontaining “technical requirements” used by permit issuing authorities (e.g., RCRA-authorized state government wasRegional offices) to determine what technical requirements must be placed in permits. The separate cost of technical 

in the “Engineering Controls” regulatory cost section of this RIA above. 

• Assumptions: 

o Although 93% of CCR landfills have a state government non-hazardous waste disposal permit and 12% 

have such state permits, assume CCR disposal units will need new RCRA disposal permits under Subt

o 383 of the 495 total electric utility plants currently dispose onsite (i.e., 84 of the 495 plants solely disp

plants solely supply CCR for beneficial uses). 

• Industry average cost per waste disposal permit: 

o ($44076 average RCRA Part A permit application cost per-plant per-year) + ($68,96077 average RCRA 

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) = $

• State government average cost per waste disposal permit: 

o Build estimate based on the following four RCRA Subtitle C permit-related state government activitie

Subtitle C waste disposal permits:78

(1,215 pre-application activities) + ($27,063 application review) + ($26,846 permit issuance) + ($3,11

$58,200 average cost per Subtitle C waste disposal permit per year. 

74 Source: page 1 of US General Accountability Office (GAO), “Hazardous Waste: Progress Under the Corrective Action Program is Limited

Accelerate Cleanups,” 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 “Gross Domestic Product Deflator Inflation Calculator” at http://cost.jsc.nasa.gov/inflateG76 $440 unitized cost derived for this RIA from EPA Information Collection Request (ICR) No. 0262.12 “RCRA Hazardous Waste Permit A

Part A”, 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 “Part B Permit Application”, Fe

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 “State RCRA Subtitle C Core Hazardous Waste Managemen

Costs Final Report” at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20C
o State Cost Calculation: 

 (383 electricity plants dispose CCR onsite) x ($58,200 per Subtitle C permit per year) = $22.3 million 

• Total Subtitle C permit cost (industry + state government) = $28.1 million per year 

16. Regulatory RCRA enforcement inspection cost 

• Assumptions: 

o State government average cost = $7,900 per Subtitle C inspection (source: hazardous waste LQG large 

average calculated by dividing the $1,517,357 annual enforcement inspection cost to 10 surveyed state 

annual enforcement cases, from page 87 of the January 2007 ASTSWMO report “State RCRA Subtitle 

Management Program Implementation Costs Final Report” 

o 1.6% average annual enforcement inspection frequency based on dividing the 11,965 LQG “large quan

reported by 10 survey states by the 192 hazardous waste LQG enforcement cases reported in the Janua

report “State RCRA Subtitle C Core Hazardous Waste Management Program Implementation Costs F

• Cost calculation: 

($7,900 per LQG enforcement) x (495 electric utility plants) x (1.6% LQG enforcements annually) = $0.063 m

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 regSubtitle C rather than Subtitle D, is based on the two example case studies summarized in Exhibit 4A below. 
Exhibit 4A 

Two Case Studies: 

Possible Added Cost Under RCRA Subtitle C Regulation of CCR Cleanup at Electricity Plants from CCR Impound

(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 

If cleanup as non-hazardous waste: Baseline Assumptions: 

• 3.32 million tons released • $0.10/ton/mile truck operating cost (source: OSW-EMRAD) • 45 miles to Subtitle D LF (source: OSW-EMRAD) • $35/ton tipping fee (source: 2005 Chartwell) • 154,000 truckloads (source: TVA assumes 21.6 tons ash per load) 

Baseline Cost Calculations: 

• Trucking cost: (3.32 million tons) x (45 miles) x ($0.10/ton /mile) = 

$15 million 

• LF tipping fee: ($35/ton) x (3.32 million tons) = $116 million • Manifest: $0 • Case #1 total = $131 million for event 

If cleanup as non-hazardous waste: Baseline Assumptions: 

• 0.25 million tons released • $0.10/ton/mile truck operating cost (source: OS• 193 miles to Subtitle D LF (Constellation Energ

to existing VA fly ash LF) 

• $35/ton tipping fee (source: 2005 Chartwell) • 20,833 truckloads (source: Constellation Energy 

per load) 

 Baseline Cost Calculations: 

• Trucking cost: (0.25 million tons released) x (1

/mile) = $5 million 

• LF tipping fee: ($35/ton) x (0.25 million.tons) = • Manifest: $0 

Case #2 total = $14 million for event 

If cleanup as RCRA Subtitle C hazardous waste Assumptions: 

• 3.32 million tons released • $0.19/ton/mile truck operating cost (source: TVA) • 370 miles to Subtitle C LF (source: TVA) • $80/ton Subtitle C tipping fee (source: TVA) • 154,000 truckloads (source: TVA assumes 21.6 tons ash per load) 

Cost Calculations: 

• Trucking cost: (3.32 million tons) x (370 miles) x ($0.19/ton/mile 

truck operating cost) = $233 million 

• LF tipping fee: ($80/ton) x (3.32 million tons) = $266 million • Manifest: (154,000 truckloads) x ($53 manifest cost per load) = $8 

million 

• Case #1 total = $507 million for event 

If cleanup as RCRA Subtitle C hazardous waste Assumptions: 

• 0.25 million tons released • $0.19/ton/mile truck operating cost (from TVA• 179 miles to Subtitle C LF (closest is Envirosaf

tons permitted capacity) 

• $90/ton tipping fee (2004 ETC national median • 20,833 truckloads (source: Constellation Energy 

per load) 

Cost Calculations: 

• Trucking cost: (0.25 million tons) x (179 miles) 

truck operating cost) = $8.5 million 

• LF tipping fee: ($90/ton) x (0.25 million tons) = • Manifest: (20,833 truckloads) x ($53 manifest c

million 

• 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-ha

$18.5 million for cleanup even
18. EPA administrative reporting and recordkeeping costs Three of the regulatory costs itemized above -- item 11 offsite disposal truck manifesting and offsite disposal hazardo

structural integrity inspections, and item 13 RCRA facility-wide investigation (RFI) – include the cost of paperwork b

addition, certain features of the Subtitle C options of the proposed rule require four other paperwork burden activities18a. Notice of Regulated Waste Activity & EPA ID Number 

RCRA Subtitle C regulations for hazardous waste “generators” require generators to notify their facilities as such and numbers (40 CFR 262.12). According to EPA’s most recent (2009) estimate, the average per-facility response burde

Applied to the 495 electric utility plants yields an estimated one-time notification cost of $80,190 (i.e., (495 electric unotification)). Amortized with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $5,800 per yeaequivalent. 

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., 264.10 265.19) and includes (1) maintaining records for hazardous waste that is stored, treated, and/or disposed onsite, (2) de

design, construction, operating methods, techniques, and practices for onsite hazardous waste storage, treatment, and/contingency plans for unanticipated damages from hazardous waste onsite storage, treatment and/or disposal, (4) mai

facility ownership, (5) maintaining continuity and financial responsibility of facility operation, and (6) employee hazaAccording to EPA’s most recent (2009) estimate the average per-facility paperwork burden is $27,350 per facility per 383 electric utility plants which currently dispose onsite (i.e., 84 of the 495 plants solely dispose CCR offsite with oth

plants solely provide CCR for beneficial uses) yields an estimated cost of ($27,350 per facility pre year) x (383 plants 

$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 TSdisposal facilities (40 CFR 264.75 and 265.75) to submit “Hazardous Waste Report” information on a 2-year repeatin

79 $162 per year notification cost derived from EPA Information Collection Request (ICR) No. 0261.16 “Notification of Regulated Waste AcRegister, 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 “General Hazardous WasRegister, Vol.74, No.23, pages 6152-6154, 05 Feb 2009. 
Biennial Report”). According to EPA’s most recent (2009) estimate, the average annualized per-facility response bur

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 (NRCrelease (e.g., spill, leak) into the environment if the amount of the release equals or exceeds the substance’s reportable 

general there are five RQ categories (1, 10, 100, 1,000 or 5,000 pounds). Subtitle C options may add CCR to the CER

substances and assign an RQ of one-pound, as well as allowing the use of concentrations to determine RQ thus resultpounds to 10,000,000 pounds for 12 chemicals. Using the total count of facilities (i.e., establishments) in the US man

31, 32, 33) plus the US waste management sector (NAICS 562) as rough indicators, there are 315,000 industrial facil

handle RQ-listed hazardous substances.82 According to EPA’s most recent (2007) estimate, the average per-facility r

(i.e., 4.1 burden hours) per facility per response, based on an average annual 25,861 facilities at an annual paperwork 

million.83 Relative to this 300,000 industrial facility universe, this annual count of RQ-reporting facilities represents 

Extrapolated to the 495 electric utility plants yields a rough estimate of 40 possible RQ reports per year, at a cost of $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 “Ancillary Cost” 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 “2009 Hazardous Waste R

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 “Number of Establishments” published for NAICS codes 31-33 Manufacturing (293,919 establishme

Waste management and remediation services (21,254 establishments) from the US Census Bureau in its “2007 Economic Census.” Not all mmanagement facilities necessarily handle hazardous substances so this is an over-estimate, but there are also other economic sectors (e.g., mitransporters, 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 “Notification of Episodic Releases of 

(Renewal); Federal Register, Vol.72, No.205, 24 Oct 2007, pp.60357-60358; http://edocket.access.gpo.gov/2007/pdf/E7-20934.pdf 
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 

11. Ancillary offsite disposal costs Subtitle C $76.35 $0.63 12. Impoundment structural integrity inspections Subtitle C and Subtitle D $0.96 $0.054 13. RCRA facility-wide investigations (RFIs) Subtitle C $6.9 $0.7 14. RCRA facility-wide corrective action Subtitle C Not estimated – 

historical 

average cost = 

$5.4 million per 

facility 

Not estimated 

15. RCRA TSDF waste disposal permits Subtitle C $5.8 $22.3 16. RCRA enforcement inspections Subtitle C $0 $0.063 17. Future disposal unit failure cleanup remediation as RCRA hazardous waste 

Subtitle C Not est. – case 

study example 

Not est. – case 

study example 

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 

Column Totals for the three options of the October 2009 draft RIA : 

 Subtitle C hazardous waste $100.4 $25.6  Subtitle D (version 1) $0.96 $0.05  Hybrid C&D* $7.9 $7.7 

* Hybrid C&D costs for ancillary cost items 13, 14, 15, 16, 17, 18 are proportioned only to the 158 plants with impoundments thregulated under Subtitle C for this option, by the proportionate multiplier: (158 plants w/impoundments) / (495 total plants) = 0.
4B.3 Land Disposal Restriction Cost (for dewatering treatment of CCR) 

This element consists of two components: 

• Dry CCR disposal (landfills): Moisture conditioning and compaction to 95% maximum dry density value accordi

ASTM D 1557 test methods prior to disposal in landfills. 

• Wet CCR disposal (impoundments): Dewatering to remove solids prior to disposal in impoundments within 5-yea

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 

potential cost for meeting the dry CCR moisture conditioning and compaction requirements are already estimated in i

controls” in this chapter above: 

• Examples of CCR Dewatering Methods 

Based on the following recent (1997-2009) example descriptions of dry CCR disposal practices at existing or planned 

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 wi

and the water will be re-circulated to transport additional bottom ash. Bottom ash will be removed using a chthen be hauled by truck to a lined landfill offsite. The fly ash will be conveyed in a dry state. Both ashes will close to the plant site. 

2. Pressure squeeze conveyor: Another tank-based example apparently similar to the Basin Cooperative method 

disposal conversion by the coal mining industry, involving the Phoenix Process Equipment company supplier 

processing equipment. This second example involves a thickening tank, porous conveyor belt and pressure to coal washings, producing a semi-solid, 75% dewatered cake which is scraped off the conveyor belt and stacke

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 f

electric utility industry, and a new modified horizontal belt filter method involving two feedboxes allows fly a

be dewatered simultaneously. 

4. Storage silos & rail system: As described June 200987 for a $10 million conversion project located at Detroit E

Michigan Power Plant -- a four boiler unit, 3,200-megawatt power station originally constructed in 1974. Inst

collect the coal ash in a dry state, plus dry ash storage facilities (storage silos), and truck/rail loading equipme

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_ash85 Source: Dave Cooper, “Better, Safer Ways to Handle Coal Slurry Do Exist”, page 14 of the Nov 2001 “E”-Notes Newsletter of the Ohio V

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/6.30.09MonroeAshR
5. Integrated silo system: Integrated with precipitators, vacuum pumps and bag filter/receivers, as described in a

about the 1997 dry fly ash system conversion of Northern Indiana Public Service Company’s Michigan City P

For this RIA, EPA ORCR identified four alternative existing studies with cost estimates (dated 1981, 1985, 2005, and wet CCR disposal at coal-fired electric utility plants. The first three studies provided cost estimates on a per-plant ba

study provided an extrapolated nationwide cost estimate. However, only the 2005 study is used in this RIA as a basis estimate for the wet CCR dewatering land disposal treatment, because the first two studies are over 25-years old (198

study does not provide sufficient details for verification of data and calculations. These three other studies are summ

chapter to illustrate the magnitude of cost estimation uncertainty implied by the other studies, compared to the estimasection of the RIA. 

• Summary of 2005 TVA CCR Dry Disposal Cost Study • In August 2009 TVA announced a proposed plan to convert its wet CCR disposal to dry disposal. TVA’s CEO T

28 July 2009 US Congressional subcommittee hearing that TVA has developed a 5-year plan to shift CCR disposimpoundments to dry landfills. TVA estimated it will cost between $1.5 billion to $2 billion over 8 to 10 years fo

utility plants.89 Detailed or semi-detailed calculations of TVA’s 2009 cost estimate are not available for this RIA 

nationwide. 

• However, a 2005 TVA cost estimate titled “Kingston Fossil Plant Decision Matrix: Pond or Peninsula?” provides 

dry conversion of the TVA Kingston TN plant.90 The TVA cost study involves conversion of an existing impoun

dispose wet fly ash and wet bottom ash at the TVA Kingston TN electric utility plant, for future dry fly ash and dr

The FGD stream remains wet-sluiced before and after this hypothetical conversion in the cost study. In addition t

the electric plant boilers and the impoundment for dry ash disposal, the cost study also includes the cost for constr

water runoff management pond (Source: row item 68 of TVA’s “Appendix C Detailed Cost Sheets”, slide nr. TVA

• TVA cost study involves conversion of 475,600 cubic yards of fly ash plus bottom ash per year; this RIA estimate

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 “TVA Coal Combustion Products Remediation Plan Proposed”, 20 Aug 2009 http://www.tva.gov/news/release90 Source: TVA 27 January 2005 plant managers conference slide presentation (25 pages).. Wet disposal is presented as “Option 1” and dry d

2” in the TVA cost presentation. Additional details for the TVA cost estimates are available at http://www.tva.gov/kingston/tdec/pdf/TVA-0

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 Repor

Combustion of Coal by Electric Utility Power Plants,” page 3-14), the dry density of fly ash is 80-90 lbs/cubic ft which translates to a specif

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 31.4 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 shor

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 shor
• The TVA cost study did not estimate the cost for dewatering FGD (gypsum) because FGD is already dewatered b

plants for beneficial uses, thus only four of the 495 electric utility plants (i.e., TVA Widows Creek plant, TVA Pa

Gas & Electric Co Trimble County plant, and Northern Indiana Public Service Company R.M. Schafer plant) wet 

FGD per year in impoundments as of 2005 (source: column B of Exhibit 3G of this RIA). 

• Unit cost (i.e., average cost per ton) of conversion from wet to dry disposal estimated from the 2005 TVA cost an

estimates for converting from wet ash disposal to dry ash disposal: 

TVA wet disposal TVA dry disposal Added cost for dry Unitized dry 

o Capital cost $13.12 million PV $38.45 million PV Cost not incremental $43.7/ton pe

o Annual O&M cost $10.63 million PV $17.51 million PV $6.88 million PV $0.60/ton (@

(Note: PV = present value for TVA’s 25-year period of analysis 2005-2029; TVA costs are in 2005$ pric

• Cost estimate calculation under conversion to dry disposal scenario, calculated based on TVA’s per-ton cost extra

tons per year baseline wet CCR (i.e., wet fly ash, wet bottom ash, wet FGD, wet gypsum, wet other CCR) disposaof 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 p

cost) x (20 years capitalization period) x (1.174 price update multiplier92 to 2009$ price level) = $22,9

capital cost Annual equivalent capital: ($22,984 million) x (0.07246 capital recovery factor @7% & 50-years) = $

o O&M cost: ($0.60/ton conversion O&M cost) x (22.4 million tons/year wet CCR disposal for conversi

years future operational period 2017-2061 which assumed to begin 5 years after 2012 final rule promu

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 m

o Total annualized cost (capital + O&M) = ($1,665 million/year capital) + ($11 million/year O&M) = $1

• 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 cand 2009) which are summarized below. The first two studies provide cost estimates on a per-plant basis for a few p

study provides a nationwide cost estimate. This RIA did not apply these other studies because the first two are over 21985) and the third study does not provide sufficient details for verification of data and calculations. These studies arused as a basis for formulating alternative nationwide cost estimates for land disposal treatment, for the purpose of illmagnitude 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 
• Study #1 of 3: 1981 TVA/EPA 

• In January 1981, TVA’s Energy Demonstrations and Technology Office (Chattanooga TN) co-authored with EPA’

Environmental Research Laboratory (Research Triangle Park NC) a study titled “Economic Analysis of Wet VersuSystems,” Interagency Energy/Environment R&D Program Report, report no. TVA/OP/EDT-81/30 and EPA-600-7

• The study compares the relative costs of wet and dry methods of coal ash disposal for five electric plant power size 

MW, 900 MW, 1,300 MW, 2,600 MW) with annual coal ash generation ranging from 0.2 million to 1.7 million per 

• Per-plant capital and O&M costs estimated based on 35-year assumed plant lifespan in 1980$. Capital costs for (a) 

handling systems, (b) conveyance/transport, and disposal units, were obtained from equipment suppliers. 

• The study found (page 67) there is not a significant difference in ash system economics based on the method of ana

analysis “indicates that wet disposal is typically the least cost alternative. However, various dry disposal options a

range of those costs. The costs are, in fact, sensitive to spreading the dry disposal area capital costs over the life othe in-plant handling system cost. Use of either the lower dilute phase transport system cost or the dense phase coin the dry disposal system alternative become the least cost alternative.” 

• The study also noted that staged construction may provide 30% saving in system total cost: “[T]he above analyses 

all the required facilities upon start-up. In the case of dry disposal, this is a reasonable assumption although site p

proceed during the development of the site. In the case of wet disposal, it may be economically sound to construct even if the amount of material to be placed or the engineering estimate is higher for staged construction. This is dudam or levee and the cost of money over the life of the project. As an example... wet disposal area was analyzed fooccurring in 1980 and by a staged construction sequence (3 stages). In this case, staged construction provided a 3

total cost of the system.” 

• The 1981 study used two cost methods. The “Present Worth” (aka present value PV) cost method findings (page 6

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=t

&EndTime=&SearchMethod=3&TocRestrict=n&Toc=&TocEntry=&QField=pubnumber%5E%22600781013%22&QFieldYear=&QFieldMld=pubnumber&IntQFieldOp=1&ExtQFieldOp=1&XmlQuery=&File=D%3A%5Czyfiles%5CIndex%20Data%5C81thru85%5CTxt%5C000er=ANONYMOUS&Password=anonymous&SortMethod=h%7C-&MaximumDocuments=10&FuzzyDegree=0&ImageQuality=r75g8/r75g8/x150y150g16/i425&Display=p%7Cf&DefSeekPage=x&SearchB

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/inflateG
• Using the EPA ORCR 2009$ updated unit cost midpoints displayed above yields the following rough cost estima

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

unitized present value cost) x (40.6% capital cost fraction) x (50 years period-of-analysis for this RIA) $4,488 million present value capital cost Annualized capital cost: ($2,187 million to $4,488 million) x (0.07246 capital recovery factor @7% & 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 

unitized present value cost) x (59.4% dry O&M fraction)) – (($4.08 to $12.46 per ton wet disposal uni(31.6% wet O&M fraction))] x (45 years dry disposal operational period 2017-2061 which assumed to 

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% 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 

per year O&M) = $273 million to $466 million per year 

• Study #2 of 3: 1985 EPA 

• EPA’s Air and Energy Engineering Research Laboratory (Research Triangle Park NC) published cost estimates for 

disposal at coal-fired electric utility plants in the report “Full-Scale Field Evaluation of Waste Disposal from Coal-

Plants”, document nr. EPA/600/S7-85/028, August 1985, 12 pages.96

• This is a 3-year study of waste characterization, environmental data, engineering, and cost evaluations associated w

and FGD waste by six coal-fired electricity plants ranging in nameplate capacity between 310 to 1,786 megawatts aNC, PA, and WY. EPA used this study to assist preparation of EPA’s 1988 “Report to Congress on Wastes from th

Electric Utility Power Plants” (report no. EPA530-SW-88-002, Feb 1988). 

• This study developed “generic” capital and annual O&M costs for both wet CCR pond disposal and dry CCR landf

involving fly ash, bottom ash, and FGD, based on specific costs for the six sites combined with cost estimates from 

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% 

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=

ethod=1&TocRestrict=n&Toc=&TocEntry=&QField=pubnumber%5E%22600S785028%22&QFieldYear=&QFieldMonth=&QFieldDay=&

FieldOp=1&ExtQFieldOp=1&XmlQuery=&File=D%3A%5Czyfiles%5CIndex%20Data%5C81thru85%5CTxt%5C00000010%5C2000TNFPassword=anonymous&SortMethod=h%7C-&MaximumDocuments=10&FuzzyDegree=0&ImageQuality=r75g8/r75g8/x150y150g16/i425&Display=p%7Cf&DefSeekPage=x&SearchB

ionS&BackDesc=Results%20page&MaximumPages=1&ZyEntry=1&SeekPage=x 
EPRI, and other organizations. Exhibit 4C below displays the unitized capital costs and Exhibit 4D below displayfrom the study updated for this RIA to 2009 price level. 

• Using the 2009-updated mean unit capital and O&M cost estimates displayed in Exhibit 4C and Exhibit 4D, provi

estimates for conversion to dry disposal, based on extrapolation to 22.4 million tons per year baseline wet CCR (i.eash, wet FGD, wet gypsum, wet other CCR) disposal in impoundments at 158 of the 495 electric utility plants whic180,901 MW nameplate total capacity: 

o Capital cost: (180,901,000 kilowatt capacity for 158 electric utility plants with surface impoundments) x 

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) = $4

o O&M cost: (22.4 million tons per year wet CCR disposed in impoundments) x (-$17.40 cost savings per 

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) – ($389 million/year O

$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 

Acr

Item Disposal Operation 

Wet or Dry 

CCR Min Max Min Max Min Max Min Max Min 

1A Fly ash handling/processing Wet $2.3 $6.8 $1.9 $5.5 $1.5 $6.4 $1.3 $3.6 $1.3 

1B Dry $2.2 $4.1 $1.8 $3.3 $1.4 $2.7 $1.2 $2.2 $1.2 

2 Fly ash storage Dry $4.7 $8.8 $4.2 $7.7 $3.7 $6.8 $3.2 $5.9 $3.2 

3A Fly ash transport Wet $3.5 $6.4 $2.7 $5.1 $2.2 $4.0 $1.7 $3.2 $1.7 

3B Dry $0.3 $0.5 $0.3 $0.6 $0.3 $0.5 $0.2 $0.5 $0.2 

4A Fly ash placement/disposal Wet $15.1 $27.8 $12.9 $23.9 $11.0 $20.5 $9.4 $17.5 $9.4 

4B Dry $4.3 $8.1 $3.3 $6.1 $2.5 $4.7 $1.9 $3.6 $1.9 

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 

6A Bottom ash transport Wet $3.0 $5.6 $2.4 $4.5 $1.9 $3.6 $1.5 $2.8 $1.5 

6B Dry $0.2 $0.4 $0.2 $0.3 $0.1 $0.2 $0.1 $0.2 $0.1 

7A Bottom ash 

placement/disposal 

Wet $6.4 $11.8 $5.1 $9.6 $4.2 $7.7 $3.4 $6.2 $3.4 

7B Dry $1.3 $2.4 $1.1 $2.0 $0.9 $1.6 $0.7 $1.3 $0.7 

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 

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 

2009 Updated Wet Subtotal* Wet (2009$) $72.8 $141.1 $59.8 $117.1 $49.5 $101.2 $41.0 $79.9 $41.0 

2009 Updated Dry Subtotal* Dry (2009$) $34.0 $64.7 $28.2 $53.1 $22.8 $43.7 $18.6 $36.0 $18.6 

* Note: 2009 price update multiplier (source: ENR Construction Cost Index ratio 2009:to:1982 = 8564/3825) = 2.239 
Exhibit 4D 

Comparison of Annual O&M Costs for Wet and Dry CCR Disposal (Source: 1985 EPA Study; $/dry metric 

Plant Size Categories (MW = megawatts) 

250 500 1000 2000 

Ac

Item Disposal Operation 

Wet or Dry 

CCR Min Max Min Max Min Max Min Max Min 

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 

1B Dry $2.5 $4.7 $2.1 $3.9 $1.7 $3.2 $1.5 $2.7 $1.5 

2 Fly ash storage Dry $3.3 $6.1 $3.0 $5.6 $2.8 $5.2 $2.5 $4.7 $2.5 

3A Fly ash transport Wet $4.2 $7.6 $3.2 $5.9 $2.5 $4.7 $2.0 $3.7 $2.0 

3B Dry $1.7 $3.1 $1.5 $2.8 $1.3 $2.5 $1.2 $2.2 $1.2 

4A Fly ash placement/disposal Wet $11.5 $21.3 $9.1 $16.8 $7.2 $13.5 $5.7 $10.5 $5.7 

4B Dry $7.0 $13.0 $5.6 $10.5 $4.6 $8.5 $3.7 $6.9 $3.7 

 Subtotal fly ash Wet (1982$) $18.2 $35.7 $13.3 $28.1 $11.3 $22.5 $9.0 $17.8 $8.7  Dry (1982$) $11.2 $20.8 $9.2 $17.2 $7.6 $14.2 $6.4 $11.8 $6.4 

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 

6A Bottom ash transport Wet $9.2 $17.1 $7.3 $13.5 $5.6 $10.3 $4.3 $7.9 $4.3 

6B Dry $3.4 $6.3 $2.8 $5.2 $2.2 $4.1 $1.8 $3.3 $1.8 

7A Bottom ash 

placement/disposal 

Wet $9.2 $17.1 $7.9 $14.6 $6.5 $12.1 $5.4 $10.0 $5.4 

7B Dry $5.4 $10.0 $4.7 $8.8 $4.1 $7.6 $3.5 $6.5 $3.5 

 Subtotal bottom ash Wet (1982$) $29.7 $57.0 $24.2 $47.2 $19.0 $38.1 $15.0 $30.7 $15.0  Dry (1982$) $20.1 $39.1 $16.5 $33.1 $13.2 $27.4 $10.6 $22.6 $10.6 

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 

 Dry (1982$) $13.2 $24.8 $10.8 $20.7 $8.8 $17.1 $7.3 $14.2 $7.3 

2009 updated weighted average** Wet (2009$) $46.4 $90.4 $35.2 $72.3 $29.1 $58.1 $23.1 $46.2 $22.6 

 Dry (2009$) $29.5 $55.6 $24.2 $46.4 $19.8 $38.3 $16.4 $31.8 $16.4 

Incremental cost from convers

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 ton** 2009 price update multiplier (source: ENR Construction Cost Index ratio 2009:to:1982 = 8564/3825) = 2.239 
• Study #3 of 3: 2009 USWAG 

• On 11 June 2009 the Utility Solid Waste Action Group (Jim Roewer, Executive Director) provided to EPA a 14-

sponsored by the EOP Group Inc., containing an estimate of $39,000 million present value (PV) for conversion tEstimates for Closure of Ash Ponds at Fossil Fuel Power Generation Facilities”, prepared in 2009 by EOP Group $39,000 million PV estimate uses a 3% discount rate over 20 years with a 10-year implementation period, and co

o $12,900 million PV (33%) for fly ash and bottom ash conversion to dry disposalo $2,500 million PV (6%) for foregone sunk cost in pondso $23,700 million PV (61%) for construction of new wastewater plants for other non-ash ancillary wastewat

which are currently co-mingled with the wet ash.

• For purpose of comparing this estimate with the other two cost studies above, the following rough calculations ex

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 

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 

= $21,000 million (undiscounted). 

PV discounted @7% over 50-years = $3,558 million PV present value 

• Substituting these 50-year based PV O&M cost estimates for the 20-year based PV O&M cost estimates int

$39,000 million 20-year PV total cost estimate produces the following 50-year based average annualized co

o Capital cost:($39,000 million PV total cost) – ($400 million 20-year PV dry management O&M) – ($

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-yea

year annualized capital cost 

o O&M cost: ($279 million 50-year PV dry management O&M) + ($3,558 million 50-year PV WWTP 

PV present value O&M 

Annualized O&M cost: ($3,837 million PV) x (0.07246 capital recovery factor @7% & 50-years) = $27

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 th

studies, compared to the cost estimate based on the 2005 TVA cost study applied in this RIA. 
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 

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 

1. Capital cost: 

1a. Present value (PV) = $2,187 to $4,488 $6,810 $22,984 $33,400 

1b. Annualized equivalent* = $158 to $325 $494 $1,665 $2,420 

2. Average annual O&M cost $115 to $141 -$389 savings $11 $278 -3. Total annualized cost (1b+2) $273 to $466 $105 $1,676 

(PV** = $23,137) 

$2,698 

Row 3 implied uncertainty range compared to estimate based on 2005 TVA study = 

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% discoun

• 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 disposal (i.e., landfills). The initial $23.137 billion estimate (present value discounted at 7% over 50-years) presenteof the RIA is based on the 2005 universe of 158 coal-fired electric utility plants (classified in NAICS code 22) with aaddressed in EPA’s October 2009 draft RIA for the proposed rule. Exhibit 4F below provides a summary of this init

February 2010, the 2005 universe is the latest available data from the U.S. Department of Energy’s Energy InformatioForm 767 database, because the EIA temporarily suspended its electric utility industry data collection survey question

97 EPA’s 2009 draft RIA cost estimate was based on an extrapolation of a cost estimate developed in 2005 by the Tennessee Valley Authorit

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-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 wethe 158 electric utility plants with active CCR impoundments as of 2005. Exhibit 4F below displays how the draft RIA timed the capital an

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. 
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 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 fin a l ru le

1 201 2 1 5 8 $ 2 2 , 9 8 4 ,0 0 0 , 0 0 02 201 3 158 $03 201 4 158 $04 201 5 158 $05 201 6 158 $06 2 0 1 7 1 5 8 $ 1 5 ,8 0 0 , 0 0 07 2 0 1 8 1 5 8 $ 1 5 ,8 0 0 , 0 0 08 2 0 1 9 1 5 8 $ 1 5 ,8 0 0 , 0 0 09 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 01 1 2 0 2 2 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 2 2 0 2 3 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 3 2 0 2 4 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 4 2 0 2 5 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 5 2 0 2 6 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 6 2 0 2 7 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 7 2 0 2 8 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 8 2 0 2 9 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 9 2 0 3 0 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 0 2 0 3 1 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 1 2 0 3 2 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 2 2 0 3 3 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 3 2 0 3 4 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 4 2 0 3 5 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 5 2 0 3 6 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 6 2 0 3 7 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 7 2 0 3 8 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 8 2 0 3 9 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 9 2 0 4 0 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 0 2 0 4 1 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 1 2 0 4 2 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 2 2 0 4 3 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 3 2 0 4 4 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 4 2 0 4 5 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 5 2 0 4 6 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 6 2 0 4 7 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 7 2 0 4 8 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 8 2 0 4 9 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 9 2 0 5 0 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 0 2 0 5 1 1 5 8 $ 2 2 , 9 8 4 ,0 0 0 , 0 0 04 1 2 0 5 2 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 2 2 0 5 3 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 3 2 0 5 4 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 4 2 0 5 5 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 5 2 0 5 6 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 6 2 0 5 7 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 7 2 0 5 8 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 8 2 0 5 9 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 9 2 0 6 0 1 5 8 $ 1 5 ,8 0 0 , 0 0 05 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 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 f o 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

PR O P O SE D R U LE OC T 200 9 R IA "O P TIO N 1" (R C R A S 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 

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 te d lu m p -s u m ) = 

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 ) = 

A 

Co u n t o f e x is ti n g 0 8 

e le c tric u tilit y 

p la n t s w ith lu m 

R o w Y e a r im p o u n d m e n ts i n 

1 201 2 1 5 8 

2 201 3 158 3 201 4 158 4 201 5 158 5 201 6 158 6 2 0 1 7 1 5 8 7 2 0 1 8 1 5 8 8 2 0 1 9 1 5 8 9 2 0 2 0 1 5 8 

1 0 2 0 2 1 1 5 8 1 1 2 0 2 2 1 5 8 1 2 2 0 2 3 1 5 8 1 3 2 0 2 4 1 5 8 1 4 2 0 2 5 1 5 8 1 5 2 0 2 6 1 5 8 1 6 2 0 2 7 1 5 8 1 7 2 0 2 8 1 5 8 1 8 2 0 2 9 1 5 8 1 9 2 0 3 0 1 5 8 2 0 2 0 3 1 1 5 8 2 1 2 0 3 2 1 5 8 2 2 2 0 3 3 1 5 8 2 3 2 0 3 4 1 5 8 2 4 2 0 3 5 1 5 8 2 5 2 0 3 6 1 5 8 2 6 2 0 3 7 1 5 8 2 7 2 0 3 8 1 5 8 2 8 2 0 3 9 1 5 8 2 9 2 0 4 0 1 5 8 3 0 2 0 4 1 1 5 8 3 1 2 0 4 2 1 5 8 3 2 2 0 4 3 1 5 8 3 3 2 0 4 4 1 5 8 3 4 2 0 4 5 1 5 8 3 5 2 0 4 6 1 5 8 3 6 2 0 4 7 1 5 8 3 7 2 0 4 8 1 5 8 3 8 2 0 4 9 1 5 8 3 9 2 0 5 0 1 5 8 4 0 2 0 5 1 1 5 8 4 1 2 0 5 2 1 5 8 4 2 2 0 5 3 1 5 8 4 3 2 0 5 4 1 5 8 4 4 2 0 5 5 1 5 8 4 5 2 0 5 6 1 5 8 4 6 2 0 5 7 1 5 8 4 7 2 0 5 8 1 5 8 4 8 2 0 5 9 1 5 8 4 9 2 0 6 0 1 5 8 5 0 2 0 6 1 1 5 8 

N o n -d is c o u n t e d t o ta l c o s t = 

N o n -d is co u n t e d a v e ra g e c o s t = 

P re s e n t va lu e c o s t (@ 7 % d is c .r a te ) = 

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 ) = 

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 = 

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 = 

P re se n t v a lu e c o s t (@ 7 % d is c . ra t e ) = 
o Recent Trend in CCR Impoundment Phase-Outs 

Since formulating the initial cost estimate above, EPA obtained new information which indicates that many electric uclosed or are planning to close CCR impoundments and convert to dry disposal (i.e., landfill disposal and/or sell and for beneficial use by other industries) for reasons independent of the CCR proposed rule. As displayed below in Exhdata98 for the electric utility industry indicate that between 1996 and 2005, the tonnage of CCR disposed in impoundm

10% from 25.2 to 22.5 million tons despite total CCR generation at electric utility plants increasing 24% over that sammillion tons (1996) to 126.3 million tons (2005). This represents an average annual CCR impoundment phase-out ra

 1996 2005 10-year decre

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 Util

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 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 Sludge 12,938 3,484 1,011 236 987 18,655 18% 9,592 1,886 467 409 2,507 14,861 Gypsum 502 987 379 1,190 88 3,146 3% 55 872 372 8,513 783 10,595 Other 171 35 0 691 305 1,202 1% 227 83 116 3,749 315 4,490 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 1

% 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 20051996 2005

98 Source: US Department of Energy EIA F767_PLANT database at: http://www.eia.doe.gov/cneaf/electricity/page/eia767.html 
One important reason for this change is that dry systems allow plants more flexibility in the type of coal they use as f

plants switched from bituminous to sub-bituminous coal, they also converted to dry fly ash handling systems because bituminous coals has cementitious properties that can cause plugging and high maintenance costs for some wet ash dinecessitating dry ash systems. Also, some types of sub-bituminous coal fly ash are in economic demand by the cemetheir low carbon content and need to be stored dry for transport. EIA’s historical data for coal-fired electric plant fly same trend away from wet disposal to dry disposal (and to beneficial reuse). In 1996, 26% of fly ash was disposed of 

“impoundments”). This fly ash disposal method dropped to 21% in 2005. 

• 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 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 

and the Clean Water Act. For example anticipated Clean Air Act regulations will likely lead to increased controls on existing electric utility plants that will increase the tonnage of flue gas desulfurization (FGD) s

processed (i.e., beneficially used or disposed) and is some cases add calcium derivatives to the existing fly 

of dry scrubbers). While the incremental costs of handling such additional materials are site specific, ther

factors that are likely to drive electric utility companies to give more consideration to dry CCR disposal. W

was common on earlier generations of wet scrubbers, in recent cases, some electric utility companies have 

more strongly on options to reduce costs by finding beneficial uses for CCR. Furthermore, given the mag

upcoming projects and growing public interest in how CCR are handled and disposed, expediting approva

may also drive towards consideration of dry disposal methods. 

2. State regulations: A number of state governments are considering programs that may affect their respectiv

economic demand for electricity. 

3. Technology: New technologies for generation, transmission, and use of electricity are being introduced in

4. Fuel cost: Spot markets for coal make it easy for plants to fuel switch or mix coal fuel types. This means, 

things that wet CCR disposal systems, because they limit the types of coal that these plants can use, are lik

reduced. 

5. Plant property: As land availability constraints becomes more important to electric utility plants (e.g., som

plants are located in riparian settings), on-site wet disposal areas become less important in favor of smalledry 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 h

operating their plants. In fact, this is evident in the fact that some electric utility companies have already announced aclosures of a number of coal-fired electric generator units, while other companies have announced plans to switch som
from coal to other fuels such as natural gas. This consideration of the way electric utility plants will operate is likely 

reconsideration of how the plants will handle and disposal CCR. Furthermore, since future air pollution regulations 

more reassessment at electricity plants with older and less efficient air emission particulate control devices and air po

air regulations themselves are likely to provide further inducement to reconsider CCR disposal practices at plants that 

using wet disposal. These actions in the near future also mean that the market and regulatory environment in which twill continue to be in flux and the ability to operate in a way that will make them able to respond quickly to changes w

Corroborating continuation of this historical phase-out trend are recent (2009) announcements by five electric utility Valley Authority (TVA), Duke Energy Company, Hoosier Energy REC Inc, Vectren Southern Indiana Gas & Electri

Energy Company)99 that they plan to convert all or a significant portion of their CCR impoundments to dry managem

years corroborates continuation of this recent impoundment phase-out trend. These 18 plants alone comprise 17% of 

tons CCR disposed annually in impoundments (as of 2005). In addition, three companies have announced planned coclosures or planned switching from coal to other fuels. These three plants comprise 3% of the annual CCR impoundm

See Exhibit 4H below for a list of these companies, their plant names, and associated CCR impoundment disposal andevelopments in the electric utility industry, including compliance with upcoming Clean Air Act and Clean Water Ac

development at EPA, will increase the dry disposal conversion trend. It is inappropriate to assign the costs of these c

proposed rule, because they would happen anyway, in absence of the rule. 

99 TVA’s 20 August 2009 news release “TVA Coal Combustion Products Remediation Plan Proposed” announced that TVA plans “to conve

storage to dry...over eight to 10 years.” . Recent plans to convert from wet CCR impoundment disposal to dry landfill disposal for electric u

Duke Energy Company, the Hoosier Electric Cooperative, and Vectren Southern Indiana Gas & Electric Company were reported 24 October 

Courier Press “Coal Ash Disposal Varies From Company to Company” at http://btop.courierpress.com/news/2009/oct/24/coal-ash-disposal-v

company/?print=1 Westar Energy apparently converted to dry fly ash management by December 2006 according to “Coal Plant O&M: Retrofit Flyash-HandlinDouglas J. Smith, Contributing Editor, Coal Power magazine, 01 Nov 2007: http://www.coalpowermag.com/transportation/Coal-Plant-O-an

System-Pays-Dividends_79.html 
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 Plant

or Switching Away From Coal Fuel with CC

A B C D E F 

Company Name Plant Name State 2005 CCR 

Pond Tons 

(1,000s)**

* 

Company Name Plant Name 

1. PSI Energy Inc (Duke Energy) Cayuga IN 210.9 1. Progress Energy Cape Fear 2. PSI Energy Inc (Duke Energy) Edwardsport IN 11.5 2. Progress Energy Lee 3. PSI Energy Inc (Duke Energy) R Gallagher IN 125.6 3. Progress Energy L V Sutton 4. PSI Energy Inc (Duke Energy) Wabash River IN 192.1 4. Progress Energy W H Weatherspo5. PSI Energy Inc (Duke Energy) Gibson IN 897.8 5. Duke Energy Company Buck 6. Tennessee Valley Authority Colbert TN 29.2 6. Duke Energy Company Dan River 7. Tennessee Valley Authority Widows Creek TN 852.8 7. Northern States (Xcel Energy) High Bridge 8. Tennessee Valley Authority Paradise TN 517.9 8. Northern States (Xcel Energy) Riverside 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 l

% of 22.4 million tons 2005 wet disposal tonnage by 158 plants = 17% % of 22.4 million tons 2005 wet disposal tonnage by 

Notes: * EPA-ORCR identified the 18 plants with recent plans to convert from wet to dry CCR landfill disposal for electric utility plants operated Company, the Vectren Company, and the Hoosier Electric Cooperative, from the 24 October 2009 news report by Mark Wilson of the Cou

Varies From Company to Company.” . The Westar Energy plant was identified by an EPA-ORCR staff person based on knowledge of that 

** EPA identified the 8 plants switching from coal from SourceWatch websites: http://www.sourcewatch.org/index.php?title=Coal_plant_c

and http://www.sourcewatch.org/index.php?title=Existing_U.S._Coal_Plants *** Source: Based on the 2005 DOE-EIA data. 
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. incorporates the average annual 1.1% decrease in CCR impoundment disposal tonnage calculated based on the 199presented in Exhibit 4G above, relative to the 2005 base year impoundment disposal tonnage of 22.4 million tons ov(i.e., 2012 to 2061) applied in the RIA. This adjustment provides a declining future CCR impoundment tonnage trend impacted by the CCR proposed rule when it is implemented, rather than simply assigning to the rule a dry conversion 

impoundment tonnage (i.e., 22.4 million tons) as was done in the initial cost estimate. The cost adjustment using this 

Step 1: Assign a dry conversion cost to the extrapolation phase-out trend (i.e., 2006 to 2061) representing wh

industry could be expected to incur in the future in absence of the CCR rule. The results of this 1st step are di

A4 of Exhibit 4I below. 

Step 2: Re-estimate the phase-out cost under this same industry trend but by adding the requirement under th

remaining CCR impoundment tonnage that is not projected to be voluntarily phased-out within 5-years of the be phased-out. This step incorporates three assumptions: (a) EPA promulgates the final rule at the start of 20

adopt the final rule 2-years later at end of 2013, and (c) the final rule allows a 5-year phase-out period which sresults of this 2nd step are displayed in columns B1 to B4 of Exhibit 4I below. 
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 year2 2006 22.2 0.3 $22,122,377 $22,122,377 22.2 0.3 $22,122,377 $22,122,3773 2007 21.9 0.3 $22,122,377 $44,244,754 21.9 0.3 $22,122,377 $44,244,7544 2008 21.7 0.3 $22,122,377 $66,367,131 21.7 0.3 $22,122,377 $66,367,1315 2009 21.4 0.3 $22,122,377 $88,489,508 21.4 0.3 $22,122,377 $88,489,5086 2010 21.1 0.3 $22,122,377 $110,611,885 21.1 0.3 $22,122,377 $110,611,8857 2011 20.8 0.3 $22,122,377 $132,734,262 20.8 0.3 $22,122,377 $132,734,2628 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 $475,683,68011 4 2015 19.6 0.3 $22,122,377 $221,223,771 19.6 4.0 $298,704,663 $774,388,34412 5 2016 19.3 0.3 $22,122,377 $243,346,148 19.3 4.0 $298,704,663 $1,073,093,00713 6 2017 19.0 0.3 $22,122,377 $265,468,525 19.0 4.0 $298,704,663 $1,371,797,67114 7 2018 18.7 0.3 $22,122,377 $287,590,902 18.7 4.0 $298,704,663 $1,670,502,33415 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 $1,670,502,33417 10 2021 17.8 0.3 $22,122,377 $353,958,033 0 0 $0 $1,670,502,33418 11 2022 17.5 0.3 $22,122,377 $376,080,410 0 0 $0 $1,670,502,33419 12 2023 17.2 0.3 $22,122,377 $398,202,787 0 0 $0 $1,670,502,33420 13 2024 16.9 0.3 $22,122,377 $420,325,164 0 0 $0 $1,670,502,33421 14 2025 16.6 0.3 $22,122,377 $442,447,541 0 0 $0 $1,670,502,33422 15 2026 16.4 0.3 $22,122,377 $464,569,919 0 0 $0 $1,670,502,33423 16 2027 16.1 0.3 $22,122,377 $486,692,296 0 0 $0 $1,670,502,33424 17 2028 15.8 0.3 $22,122,377 $508,814,673 0 0 $0 $1,670,502,33425 18 2029 15.5 0.3 $22,122,377 $530,937,050 0 0 $0 $1,670,502,33426 19 2030 15.2 0.3 $22,122,377 $553,059,427 0 0 $0 $1,670,502,33427 20 2031 14.9 0.3 $22,122,377 $575,181,804 0 0 $0 $1,670,502,33428 21 2032 14.6 0.3 $22,122,377 $597,304,181 0 0 $0 $1,670,502,33429 22 2033 14.3 0.3 $22,122,377 $619,426,558 0 0 $0 $1,670,502,33430 23 2034 14.0 0.3 $22,122,377 $641,548,935 0 0 $0 $1,670,502,33431 24 2035 13.7 0.3 $22,122,377 $663,671,312 0 0 $0 $1,670,502,33432 25 2036 13.4 0.3 $22,122,377 $685,793,689 0 0 $0 $1,670,502,33433 26 2037 13.1 0.3 $22,122,377 $707,916,066 0 0 $0 $1,670,502,33434 27 2038 12.8 0.3 $22,122,377 $730,038,443 0 0 $0 $1,670,502,33435 28 2039 12.5 0.3 $22,122,377 $752,160,821 0 0 $0 $1,670,502,33436 29 2040 12.2 0.3 $22,122,377 $774,283,198 0 0 $0 $1,670,502,33437 30 2041 11.9 0.3 $22,122,377 $796,405,575 0 0 $0 $1,670,502,33438 31 2042 11.6 0.3 $22,122,377 $818,527,952 0 0 $0 $1,670,502,33439 32 2043 11.3 0.3 $22,122,377 $840,650,329 0 0 $0 $1,670,502,33440 33 2044 11.0 0.3 $22,122,377 $862,772,706 0 0 $0 $1,670,502,33441 34 2045 10.8 0.3 $22,122,377 $884,895,083 0 0 $0 $1,670,502,33442 35 2046 10.5 0.3 $22,122,377 $907,017,460 0 0 $0 $1,670,502,33443 36 2047 10.2 0.3 $22,122,377 $929,139,837 0 0 $0 $1,670,502,33444 37 2048 9.9 0.3 $22,122,377 $951,262,214 0 0 $0 $1,670,502,33445 38 2049 9.6 0.3 $22,122,377 $973,384,591 0 0 $0 $1,670,502,33446 39 2050 9.3 0.3 $22,122,377 $995,506,968 0 0 $0 $1,670,502,33447 40 2051 9.0 0.3 $22,122,377 $1,017,629,345 0 0 $0 $1,670,502,33448 41 2052 8.7 0.3 $22,122,377 $1,039,751,722 0 0 $0 $1,670,502,33449 42 2053 8.4 0.3 $22,122,377 $1,061,874,100 0 0 $0 $1,670,502,33450 43 2054 8.1 0.3 $22,122,377 $1,083,996,477 0 0 $0 $1,670,502,33451 44 2055 7.8 0.3 $22,122,377 $1,106,118,854 0 0 $0 $1,670,502,33452 45 2056 7.5 0.3 $22,122,377 $1,128,241,231 0 0 $0 $1,670,502,33453 46 2057 7.2 0.3 $22,122,377 $1,150,363,608 0 0 $0 $1,670,502,33454 47 2058 6.9 0.3 $22,122,377 $1,172,485,985 0 0 $0 $1,670,502,33455 48 2059 6.6 0.3 $22,122,377 $1,194,608,362 0 0 $0 $1,670,502,33456 49 2060 6.3 0.3 $22,122,377 $1,216,730,739 0 0 $0 $1,670,502,33457 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%
As summarized below in comparison to the initial cost estimate, the updated conversion cost is the difference in the 

utility industry for continuation of the phase-out trend without the CCR rule, compared to the step-2 cost for mandato

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 owhich contains two other cost categories as estimated for the Subtitle C option (i.e., $491 million/year for engineering 

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 estiby 35% the overall compliance cost estimate (i.e., dry conversion cost plus engineering control costs plus ancillary co

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 impoundmutility plants, regardless of the CCR rule, and that this trend will continue. Described below, EPA has identified sevecorroborate continuation of this impoundment phase-out trend, some of which have been quantified in the cost adjust

1. Industry conversions to dry CCR disposal: This factor corroborates the phase-out trend applied in the cabove, there is a documented over two-decade long trend 1996 to 2019 away from wet CCR disposal in the 

This trend consists of two parts: (a) the 1996-2005 historical data period, plus (b) the more recent (2009) anno

conversions which occurred between 2005 and 2009, and planned conversions to occur within the next 10 yea

According to one company (United Conveyor Corporation) who has been supplying dry disposal equipment a

the electric utility industry, the main historical drivers for this voluntary shift have been (1) generating dry fly product to other industries for beneficial uses, and (2) decreasing the volume of fly ash going to impoundmen

capacity for bottom ash. Since then, concern over possible future environmental release liabilities associated 

and pressure from individual state governments, has led electric utility companies to consider dry conversion. 

prominent example of this trend which publicly announced100 in 2009 it plans to convert its wet fly ash and w

100 TVA’s 20 August 2009 news release is at http://www.tva.gov/news/releases/julsep09/ccprp_other.htm 
dry disposal within the next eight to 10 years (i.e. by 2019). Conversions of this sort are a current trend, and tcontinue, even in the absence of the CCR proposed rule. As summarized in Exhibit 4H above (columns A to 

such plants constituting 17% of the industry-wide wet CCR disposal tonnage as of 2005. It is inappropriate to phase-out cost of the CCR proposed rule to plants independently moving to dry CCR disposal. At this point, 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 

fired electricity plants have since 2005 switched, or are planning to switch, some or all of their coal-fired boilcoal to other fuels (e.g. natural gas) for reasons unrelated to the CCR proposed rule. In such cases, the cost of disposal impoundments should not be attributed to the cost of the proposed rule. This factor decreases the estand particularly EPA’s estimated future cost of phasing-out wet disposal attributable to the proposed rule. FoEPA’s recent internet search, as also displayed in Exhibit 4H above (columns E to H), EPA identified 8 coal-

using impoundments (as of 2005) representing 3% of wet CCR disposal by the 158 plants, which have or plan 

more of their coal-fired electricity generation boilers within one or more plants, or to close one or more of theentire coal-fired plants. 3. Lifespan expiration of existing CCR impoundments: This factor suggests a faster future phase-out trenupdate, but is not applied in the cost update. Another factor which corroborates the future continuation of the 

voluntary phase-out of CCR impoundments, is the fact that existing (i.e., active, operational) CCR impoundmoperational lifespans. When an impoundment reaches its end-of-lifespan, the electric utility plant must in that 

new impoundment capacity by installing another impoundment, or convert to dry disposal by installing a land

annual CCR for beneficial uses). For purpose of estimating the “engineering cost” component (in Chapter 4 assigned impoundment lifespan start years (i.e., year in which impoundment construction was completed and 

and future expected impoundment operational lifespan closure years, to each of the 158 coal-fired plants with impoundments (as of 2005) identified in this RIA. For the most part, the impoundment start years were based 

reported data from the references cited in this RIA. However, expected closure years were provided by indusplants; thus, EPA assigned expected closure years to the remainder 80 plants assuming a 40-year lifespan. Ex

summary of the expected future closure years in relation to the remaining lifespan years and associated impouare expected to reach end of operational lifespan in absence of the CCR rule. This summary indicates that all impoundments could be expected to reach end-of-lifespan by year 2051, and that 20% of impoundments will 

lifespan by year 2018. According to the cost update assumptions discussed in the 2nd update steps of prior sec

represents the 5th year of the CCR final rule’s assumed 5-year phase-out period spanning 2014 to 2018, which 

final rule is promulgated by EPA at the start of 2012 and that state governments will adopt the rule 2-years lat

This lifespan expiration trend corroborates the assumed continuation of the phase-out trend depicted in Exhibindicates that 17% of CCR impoundment tonnage may be expected to have phased-out by year 2018 (i.e., 18.by 2018 compared to 22.5 million tons in the analysis base year 2005) in absence of the CCR rule. In fact, giv

provides companies with a low-cost opportunity to convert to dry disposal, the higher 20% end-of-lifespan pe
17% phase-out trend suggest the future phase-out trend may be accelerated compared to the 1.1% annual phasthe 1996-2005 trend. For example, this result suggests that by 2018 the annual phase-out rate in that year cou(20%/17%) x 1.1%)). 

4. EPA’s Clean Air Act emissions standards: This factor is not quantified in the cost update. Where existin

utility plants put in new air emission scrubbing systems, EPA believes they will overwhelmingly rely on CCR 

do not require wet disposal impoundments. Two of EPA’s upcoming Clean Air Act (CAA) air pollution regul

plants to begin using large amounts of reagent to capture SO2 from boiler flue gas: • EPA’s Clean Air Mercury Rule (CAMR) which was vacated by the DC Circuit Court in 2007 compels EPA 

112 to issue maximum achievable control technology (MACT) regulations for coal- and oil-fired electric uti

http://www.epa.gov/ttn/atw/utility/utilitypg.html

• EPA’s remanded Clean Air Interstate Rule (CAIR) was also vacated by the DC Circuit Court in 2007 but w

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 

the reactants are either captured with the fly ash or with the wet FGD waste. If these plants currently dispose owet FGD waste in wet impoundments, the likelihood of significantly increased future disposal tonnages may p

switch to dry disposal. Therefore, new CCR generated as a result of new Clean Air Act emissions requiremenplants to switch away from wet disposal independent from the CCR proposed rule. EPA has not quantified thi

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 curre

industrial wastewater effluent regulations for coal-fired electricity plants. These new regulations are likely to t

existing effluent limits. These new regulations will be one more factor likely to influence plants to switch to d6. State government implementation of rule: This factor is quantified in the cost update. It recognizes that 

for their state legislatures or environmental regulatory programs to adopt new RCRA regulations such as the C

necessary for the rule to become federally enforceable. In the initial cost estimate, EPA assumed that the CCR 

effective (i.e., adopted by states) in year 2012 and that dry conversion capital costs would all be incurred in tha

to that simple cost estimation framework, this cost update factor pushes the dry conversion cost 2-years out int

2014. The 5-year allowed dry conversion (i.e., impoundment phase-out) period is thus 2014 to 2018. In realitdistinction to be made. For states which operate EPA-authorized RCRA regulatory programs (as of 2005, EPAcomprise 97% of the 22.4 million tons annual CCR impoundment disposal tonnage), they could have 2-years ain non-authorized states (i.e., AK, IA), territories, and Indian country, the CCR rule becomes effective in 2012 

implement it directly. According to the 2005 EIA data, in this 2nd group there are four plants with impoundme
with impoundment(s) on tribal land totaling 3% of the 22.4 million tons impoundment disposal in 2005.101 Be

comprises a very small 3% fraction of the annual CCR impoundment disposal tonnage, and to avoid adding anto the cost update which would only result in a very small (i.e., <5%) difference in updated estimate, the cost ucalculate costs for both groups addressing under this factor, but applies implementation year to the entire 22.4 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 elelikely to incur dry conversion capital costs spread across each of the years in the CCR rule’s 5-year mandated pthan incurring all dry conversion capital cost in one year as was simply assumed in the initial cost estimate. Th

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 

(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 

tons/year). 
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 C

-

5,000,000

10,000,00015,000,00020,000,00025,000,000

2012 Total 2014 Total 2016 Total 2018 Total 2020 Total 2022 Total 2024 Total 2026 Total 2028 Total 2030 Total 2032 Total 2034 Total 2036 Total 2038 

Projection of Future Percentage of 2005 CCR Pon

Closure

0%

10%20%30%40%50%60%70%80%90%

100%

2012 Total 2014 Total 2016 Total 2018 Total 2020 Total 2022 Total 2024 Total 2026 Total 2028 Total 2030 Total 2032 Total 2034 Total 2036 Total 2038 Tot

20
Exhibit 4K below summarizes the above regulatory cost estimates on an incremental basis (i.e., without including th

estimated in Chapter 3 of this RIA). Appendix J presents regulatory costs estimates for each of the 495 electric util

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) 

A. Engineering Controls (onsite): $491 $491 1. Groundwater monitoring $13 $13 2. Bottom liners $95 $95 3. Leachate collection $8 $8 4. Fugitive dust controls $5 $5 5. Water runon/runoff controls $2 $2 6. Financial assurance $30 $30 7. Disposal unit location restrictions $76 $76 8. Closure capping to cover unit $255 $255 9. Post-closure groundwater monitoring $2 $2 10. Storage design & operating standards Not estimated in this RIA Not estimated in this RIA NoB. Other Ancillary Costs: $107 $1 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 

(off

so n

12. Structural integrity inspections $1 $1 13. RCRA facility-wide investigation $7.6 Not relevant 14. RCRA facility-wide corrective action Not estimated in this RIA; 

historical average = 

$5.4 million per case 

Not relevant No

15. RCRA TSDF haz waste disposal permit $7 Not relevant 16. RCRA enforcement inspection $0.06 $0 17. Future added cleanup cost as “hazardous waste” Not estimated in this RIA: 

case studies indicate possible 

$18 to $376 million per case 

Not relevant No

case 

$18 

18. EPA paperwork reporting/recordkeeping $13 Not relevant C. Land Disposal Restriction Dewatering Treatment $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)

$1,3

($

Note: Chapter 6 of this RIA scales these cost estimates based on the October 2009 draft RIA options, to the 2010 reg
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. Tsummary is based on apportionment of nationwide average annualized cost estimated for each regulatory option, accoannual 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 Op

($million average annualized cost in 2009$ over 50-year period of analysis 2012 to 2061) 

A B C D E F G 

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) 

Hyb

Subtitle C Subtitle D 

1 AK 2 46,179 0.03% $0.4 $0.4 2 AL 16 3,210,337 2.27% $33.5 $31.1 3 AR 4 744,267 0.53% $7.8 $7.3 4 AZ 8 3,334,030 2.36% $34.8 $32.3 5 CA 6 159,927 0.11% $1.6 $1.5 6 CO 12 1,704,433 1.21% $17.8 $16.6 7 CT 0 172,280 0.12% $1.8 $1.6 8 DC 0 0 0.00% $0.0 $0.0 9 DE 2 251,205 0.18% $2.7 $2.5 

10 FL 15 6,132,345 4.34% $64.0 $59.4 11 GA 13 6,077,700 4.30% $63.4 $58.9 12 HI 1 58,968 0.04% $0.6 $0.5 13 IA 15 1,136,289 0.80% $11.8 $11.0 14 ID 0 0 0.00% $0.0 $0.0 15 IL 17 3,856,748 2.73% $40.2 $37.4 16 IN 33 8,798,845 6.23% $91.8 $85.3 17 KS 8 1,495,099 1.06% $15.6 $14.5 18 KY 31 9,197,567 6.51% $96.0 $89.1 19 LA 3 1,614,800 1.14% $16.8 $15.6 20 MA 0 363,150 0.26% $3.8 $3.6 21 MD 4 1,932,740 1.37% $20.2 $18.8 22 ME 1 48,000 0.03% $0.4 $0.4 23 MI 24 2,369,673 1.68% $24.8 $23.0 24 MN 20 1,525,979 1.08% $15.9 $14.8 25 MO 20 2,679,742 1.90% $28.0 $26.0 26 MS 6 1,229,400 0.87% $12.8 $11.9 
Exhibit 4L 

State-by-State Distribution of Estimated Incremental Costs for the October 2009 Draft RIA Regulatory Op

($million average annualized cost in 2009$ over 50-year period of analysis 2012 to 2061) 

A B C D E F G 

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) 

Hyb

Subtitle C Subtitle D 

27 MT 5 1,830,624 1.30% $19.2 $17.8 28 NC 27 5,504,531 3.90% $57.5 $53.4 29 ND 9 3,038,100 2.15% $31.7 $29.4 30 NE 6 614,473 0.44% $6.5 $6.0 31 NH 1 176,900 0.13% $1.9 $1.8 32 NJ 2 735,214 0.52% $7.7 $7.1 33 NM 4 3,983,300 2.82% $41.6 $38.6 34 NV 2 391,500 0.28% $4.1 $3.8 35 NY 11 1,479,792 1.05% $15.5 $14.4 36 OH 24 10,429,446 7.39% $108.9 $101.2 37 OK 3 1,490,800 1.06% $15.6 $14.5 38 OR 1 99,900 0.07% $1.0 $1.0 39 PA 28 15,359,680 10.88% $160.4 $148.9 40 RI 0 0 0.00% $0.0 $0.0 41 SC 14 2,178,360 1.54% $22.7 $21.1 42 SD 2 103,753 0.07% $1.0 $1.0 43 TN 12 3,240,120 2.29% $33.8 $31.4 44 TX 18 13,165,728 9.32% $137.4 $127.6 45 UT 7 2,582,144 1.83% $27.0 $25.1 46 VA 13 2,388,526 1.69% $24.9 $23.1 47 VT 0 0 0.00% $0.0 $0.0 48 WA 1 1,405,220 1.00% $14.7 $13.7 49 WI 12 1,412,534 1.00% $14.7 $13.7 50 WV 20 9,231,718 6.54% $96.4 $89.5 51 WY 12 2,224,848 1.58% $23.3 $21.6 

Totals = 495 141.2 million 100% $1,474/year $1,368/year $1,
4D. Cost Estimation Uncertainty 

This section addresses OMB’s 2003 Circular A-4 “Regulatory Analysis” guidance (page 40) requirement for RIAs inexpected annual economic effects of $1 billion or more, to present a formal quantitative analysis of the uncertainties a

estimates. This section only addresses uncertainties with respect to cost estimates for both baseline cost and incremenregulatory options. This section first presents three specific examples of data quality uncertainty factors in this RIAuncertainty factor to represent all such specific data quality uncertainty factors combined (the three factors below ar

low- and high-end percentage range endpoints because such simple addition would represent unlikely compounding o

• 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 dispos

tonnages reported by electric utility plants to the 2005 DOE-EIA Form 767 database. How

data reporting form102 does not provide respondents with a definition for the “tons” collecte

data reporting form. Because there are three numerical definitions of “ton” commonly used 

= 2,000 pounds, long-ton = 2,200 pounds; and metric ton = 2,205 pounds), this factor poten

+20% uncertainty range. For purpose of consistency with the use of short-tons in most EPreports,103 this RIA interprets CCR “tons” as short-tons. 

2. Data sources: Also with respect to CCR tonnage data, this RIA cites multiple possible sources of data bas

sources. For example, as displayed in Exhibit 4D of this RIA, one source (American Coal 

provides an industry survey-based estimate of CCR generation by electric utility plants in 2Whereas this RIA estimates 141.2 million tons CCR generation in 2005 based on data from 767 database for plants >100 MW in size and based on supplemental estimates made in this 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 pract

published sources dated 1995, 1996, and 2006. Furthermore, unit costs for CCR disposal uapplied in this RIA are from different published data years such as 2000, 2004, and 2007. historical data to 2009 price levels using various indexes, some of which were specific to a cost, and other indexes were general (e.g., GDP Price Deflator). The uncertainty in accuracby use of historical data is not quantified. 

• 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/eia7

103 One example of the standardized use of “short-tons” in EPA RCRA program reports is the RCRA Biennial Hazardous Waste Reports whi

http://www.epa.gov/waste/inforesources/data/biennialreport/index.htm 
The method applied to characterize the overall level of quantitative uncertainty in the cost estimates of this RIA, is ba

2005 “Recommended Practice No. 18R-97: Cost Estimate Classification System as Applied in Engineering, Procurem

the Process Industries”104. This method is specifically applicable to cost estimates developed for mechanical and che

used for engineering, procurement and construction across a wide variety of industries including the electric utility incode 22). As summarized in Exhibit 4M below, this cost estimate classification system involves five estimation cate

2, Class 3, Class 4, Class 5) reflecting different relative (a) levels of cost definition, (b) purposes and uses of cost estimethodologies, (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 R

Estimate 

Category 

Level of Detail 

(Quantity of Input Information & Data) 

Level of Effort 

(Time Required to Complete the Cost Estimate) 

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, some

requiring less than one hour FTE to prepare the cost esti

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 preparincost estimate. 

Data quality uncertainty range applied in this RIA (i.e., between Class 3 and Clas

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. 

Class 2 30% to 70% complete, detailed information May require up to 1.5 years FTE to prepare the cost estiClass 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 th

estimate. 

Because the bulk of the data collection and analysis presented in this RIA was executed in a relatively short time (i.e.

detailed information for baseline CCR disposal conditions, disposal unit costs, and engineering control and ancillary 

options, the level of numerical uncertainty for the baseline cost and incremental costs for each of the regulatory optio

may be classified between a Class 3 and Class 4 type of estimate (i.e., -25% to +40%), as displayed below in Exhibit 

ranges represent a probability distribution about the cost estimates, and may be interpreted as the expected values (i.e

end and high-end ranges about each cost estimate. Such quantitative indicators of uncertainty are identified in OMB’

41) as acceptable for characterizing probability distributions for cost estimates involving major rules with possible an

$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.aac
Exhibit 4N 

Cost Estimation Uncertainty with Overall Data Quality Uncertainty Factor Applied to the October 2009 Draft RI

($millions in 2009$) 

Cost Estimate Uncertainty Indicator 

Subtitle C 

Hazardous waste

Subtitle D 

(version 1)

Hybri

Subtitle C for imSubtitle D for la

Best estimate (w/updated LDR cost): $1,474/year (updated) 

$20,343 PV 

$1,368/year (updated) 

$18,880 PV 

$1,376/yea

$18,9

-25% uncertainty low-end $1,106/year 

$15,264 PV 

$1,026/year 

$14,160 PV 

$1,03

$14,2

+40% uncertainty high-end $2,064/year 

$28,485 PV 

$1,915/year 

$26,429 PV 

$1,92

$26,5

Note: PV = present value of average annualized cost over 50-years @7% discount rate, calculated by multiplying the average annua

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 r
Chapter 5 

Potential Benefits of RCRA Regulation of CCR Disposal in the Electric Util

Exhibit 5A below displays social benefits associated with EPA’s RCRA regulatory program, a few or many of which any particular RCRA regulation. To a lesser or greater degree, a range of these benefit elements may be associated w

RCRA regulation of CCR disposal, according to the unique physical and environmental attributes at any particular CC

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 

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

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 specie8) Biodiversity 9) Water filtration 10) Soil fertilization 

11) Pest control 

12) Reduced pressure on enda

13) Avoided habitat destructio

4. Avoided Economic Costs 1) Avoided costs of providing government mandated 

alternate drinking water supplies 

2) Avoided costs associated 

cleanups of industrial was

5. Avoided Materials Damages, Improved Aesthetics, & Historical Preservation 

1) Aesthetic pleasure 

2) Improved taste, order, visibility 

3) Protection of resources w4) Protection of constructed 

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 t

protection from unforesee

4) Benefits from long-term i

environmental quality 

* Source: Exhibit 1-1 of EPA Office of Solid Waste, “Approaches to Assessing the Benefits, Costs, and Impacts of the RCRA Subtitle C P

Industrial Economics Inc., October 2000, 
In contrast to the Exhibit 5A list of RCRA regulatory program benefits, because of time, data, and methodological lim

benefits estimated in this RIA do not represent a complete list of expected benefits of the CCR proposed rule. For ex

analysis in this Chapter of the RIA does not estimate benefits of (a) reducing cancer risks associated with preventing 

of CCR to surface waters, (b) ecological and ecosystem benefits, (c) off-site CCR disposal regulatory benefits, or (d) 

protection benefits. In contrast to this large number of possible benefit elements, this RIA monetizes only three bene

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. E

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 RemedThis section estimates the potential future benefits of reduced human cancer risks and avoided groundwater contaminassociated with controlling arsenic from onsite CCR landfills and surface impoundments. The estimates are based on 

which predicts leaching behavior using SPLP and TCLP data. Recent research and damage cases indicate that these l

estimate risks from dry disposal.105 Human cancer risks avoided are based on the individual “excess” lifetime cancer 

below. This estimation follows an 8-step method which begins by characterizing the cancer risks and expected numbfrom arsenic releases to groundwater from CCR landfills and surface impoundments in the absence of EPA or state ac

monetize these cancers using accepted economic practices. Next, a baseline is established for the operation of state r

105 Recent EPA research demonstrates that CCR can leach significantly more aggressively under different pH conditions potentially present i

EPA study of 34 electric utility plants, CCR from 19 facilities exceeded at least one of the 40 CFR Toxicity Characteristic regulatory values 

(e.g., fly ash or FGD residue) at the self-generated pH of the material (source: EPA Office of Research & Development, “Characterization of 

from Electric Utilities – Leaching and Characterization Data,” EPA-600/R-09/151. Office of Research and Development, Air Pollution Cont

Park, NC. December 2009). This behavior likely explains the rapid migration of chemical constituents from CCR disposal sites like ChesapSee also EPA “Characterization of Mercury-Enriched Coal Combustion Residues from Electric Utilities Using Enhanced Sorbents for Mercu06/008. Office of Research and Development. Research Triangle Park, NC. January 2006; and EPA “Characterization of Coal Combustion RUsing Wet Scrubbers for Multi-Pollutant Control,” EPA/600/R-08/077. Office of Research and Development, Air Pollution Control Division

July 2008. 
programs. Groundwater remediation costs and cancer costs under the baseline and each regulatory option are then estaggregate 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 tonnagesF of this RIA for the 495 coal-fired electric utility plants. A subtotal 84 of the 495 plants dispose CCR offsite only, a

assigned to these facilities in this benefits analysis.106 Some of the plants have multiple data entries because they wer

CCR disposal units on-site. This estimation step assigned only the riskiest disposal unit type and liner type combinateach such plant, which resulted in the six combinations displayed below in Exhibit 5A-1.107 This hierarchy was base

trivalent arsenic cancer risks in the EPA-ORCR 2009 CCR risk report as follows, with those units posing the greatest 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. Tonly dispose CCR compared to facilities that co-manage CCR with coal refuse is displayed below in Exhibit 5A-1. Tto model a single number of potential cancer cases as a best estimate. The data used in the 2009 risk assessment108 w

survey. Thus, there is some uncertainty regarding the current accuracy of these ratios. To account for this uncertaintbounding range of cancers based on the assumption that all facilities would dispose of CCR only, and that all facilitiewith 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 107 Multiple CCR disposal units at a single industrial facility will all affect the same surrounding population. To avoid duplication of populat

simplifying assumption that the human health risks will be driven by the riskiest single WMU, when multiple waste management units are prall WMUs are accounted for in Appendix K2 of this RIA. 

108 Source: EPA “Human and Ecological Risk Assessment of Coal Combustion Wastes,” Office of Resource Conservation and Recovery, De
Step 2. Determine Potentially Affected Populations of Groundwater Drinkers With information on the universe of facilities, WMUs, and liners nearby groundwater-drinking populations were assiEPA first assigned latitude and longitude coordinates to the 495 sites based on its 2007 eGRID database. Only a few and it is assumed that these sites were constructed since the 2007 eGRID data collection. Once latitude and longitude used GIS data to ascertain the location of private groundwater wells within a one-mile radius from the latitude and lothen the number of individuals drinking from those wells.109,110 The data divide populations into adults (18 and older

two populations examined in the 2009 risk assessment. Once these data were attached to specific sites, they were aggliner/WMU categories above. Aggregated data were then scaled to account for the missing population information and population growth. First, thaccount for the missing population data in the sites not identified in eGRID. There were 5 unlined landfills, 1 clay-lin

composite-lined landfills that had onsite disposal but no eGRID data from which to determine the population. All surthe necessary eGRID data. To account for these individuals, EPA made the assumption that these plants had populati

EPA had data for, since EPA had no data to suggest otherwise.111 Thus, the population was scaled up by a scaling fa

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 oOnce these preliminary population estimates were produced, it was also necessary to account for the size of the waste 

2009 risk assessment, WMUs were assumed to be square as a requirement of the model. Using the same assumption 

radius around the square area of a WMU could be estimated by scaling the population density of the original 1-mile r

around a square WMU of average size. This led to scaling factors of 1.81 and 2.56 for landfills and surface impoundFurther 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 would be down-gradient of the WMU. For the purposes of this assessment, populations were assumed to be equally d

109 This data was developed through the use of the 2000 census block data in combination with the 1990 census drinking water source data. 

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 

these systems were not included in the 2009 Risk Assessment or in this analysis. However, exposure through this pathway is possible, which 

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. 
square whose center was the facility WMU. This is illustrated in Exhibit 5A-2 below. It was also assumed that only populations would be affected (red rectangle), and no up-gradient populations would be affected. This was accounted mile population by two. The issue of surface waterbodies is addressed below. Appendix K3 provides a detailed expof the exposed population by plant. Overall, 715,855 individuals are potentially exposed to CCR. Of this total, 34,53water wells. 

WMU

Groundwater Flow Potentially Exposed 

Population Unexposed 

Population 

Exhibit 5A-2 

Conceptual Model for Exposed Well-Drinking Population 

1-mile

Surface 

Waterbody 

Contaminant 

Plume 
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 popul

populations residing near the CCR disposal sites. There are two sources of information on individual risks associated 

IRIS 1998: Based on skin cancer incidence, as data on skin cancer risks were available prior to the availabilit

internal cancers. Skin cancer is a health endpoint associated with lower fatality risk than the inter

arsenic. The skin cancer based risk assessments no longer represent the current state of the scienc

assessment for arsenic. This RIA presents these estimates below for informational purposes only. distribution of risks to a hypothetical individual who drinks water from a well located at a randomdown-gradient from the waste management unit edge. The probabilistic risk estimates were “sitespecific, but based roughly on 181 actual coal-fired power plants that were operating in 1995). Erisks (i.e., those corresponding generally to the highest groundwater concentrations that are modeanalysis because computer modeling of peak risks contain gigabytes worth of information, and wkeep track of risks up to 10,000 years of the computer model run, the data in these large files becaunusable. However, below in this RIA EPA does extrapolate population risks in other years. Theyears between the cessation of operation of the landfill, or the years after the beginning of operatiimpoundment, leading up to the years in which the “peak” risks occur at half of the modeled facil

NRC 2001: The latest science on health risks associated with arsenic exposure is from the National Research 

“Arsenic in Drinking Water: 2001 Update”112 which reviewed the available toxicological, epidem

assessment literature on the health effects of inorganic arsenic, building upon the NRC’s prior rep

Water” (1999). The 2001 report, developed by an eminent committee of scientists with expertise risk assessment provides a scientifically sound and transparent assessment of cancer risks from in

Science Advisory Board endorses these estimates and the IRIS estimates are currently being upda

science. Therefore, while IRIS estimates exist, because the more recent NRC scientific informati

relies on the NRC information for analysis of the cancer risks associated with CCR. Appendix Kinformation 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 a

obtained with the latest (i.e., 1998) IRIS value. However, in Step 5 below, the 2001 NRC research was used to updatIt should be noted that the 1998 IRIS skin cancer value does not examine bladder and lung cancer incidence, and therthe 2001 NRC cancer risk research in this area. To the extent that the skin cancers estimated by the IRIS value are no

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.ph
This RIA extracted only those results from the EPA 2009 risk assessment to either represent (a) conventional CCR (i

boiler slag, and flue gas desulphurization waste managed in the landfill or impoundment without mixing with other m

managed with coal refuse.113 Of these results, only those for trivalent arsenic were used.114 For the primary analysis

arsenic was speciated in this manner. As noted in the EPA source data, arsenic III and arsenic V cancer risk results foimpoundments that co-dispose CCR with coal refuse were not statistically different at the 90th percentile, and these ri

population risk estimates. A sensitivity analysis was conducted where all arsenic was assumed to be speciated in the analysis is presented in Appendix K5. Finally, risks for both adult and child receptors were included so that each grorepresented. 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 estima

the modeled distance to a surface water body was less than the modeled distance to a drinking water well EPA assum

plume is fully intercepted by a surface waterbody.115 To this end, EPA extracted the model inputs for the distance to 

distance to surface waterbodies used in the EPA source, randomly selected from input distributions.116 These two welogical test in Microsoft Excel. This test returned a 0 if the surface waterbody was closer than the drinking water wel

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 

individual’s lifetime risk that was experienced in a one-year period. EPA accomplished this by matching the probabi

inputs, to their corresponding age category. Then, each probabilistic run was sorted to return the exposure duration ocategory. These Monte Carlo data constituted a weighted approach for estimating individual human cancer risks. Pocalculated by multiplying risk results by the affected population. Since there were thousands of equally valid model iassigned each of these risks an equal weight in its final population risks by using the average of these individual risksIndividual risk estimation took into account the fact that the contaminant plumes might be intercepted by surface wat

either 0 or 1 as identified above. Each of these risks was then divided by exposure duration to estimate the yearly can

these risks were calculated for a given WMU/liner type they were summed and divided by the number of iterations to 

increment of risk for that WMU/liner type at the peak risk. Thus, the final equation that was used for calculating aver

113 Fluidized Bed Combustion waste results were not deemed appropriate for use for the reasons discussed in EPA “Human and Ecological R

Combustion Wastes,” Office of Resource Conservation & Recovery, August 2009. 

114 A 1981 Oak Ridge National Laboratory study states “As (III) is likely to be the predominant arsenic species in ash pore water and ground

R. “Oxidation State of Arsenic in Coal Ash Leachate,” 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 perpen

simplifying assumption serves to minimize the influence of the model runs in which interception may have occurred, but was not reflected in Risk Assessment of Coal Combustion Wastes,” Office of Resource Conservation & Recovery, August 2009. 

116 For further discussion of how these distributions were developed, see Appendix C of EPA “Human and Ecological Risk Assessment of C

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. 
N

EDn

RISKn WELLREACH

iRISK

∑ ×

=

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 undscenarios. For full distributions of individual risks before averaging, see Appendix K6 – Distributions. 

Exhibit 5A-3 

Peak One Year Risks For CCR Cancer 

Conventional CCR CCR Co-managed With Coal Refu

Liner - Receptor Landfills Impoundments Landfills Impoundme

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 o

risks significantly underestimates total cancers avoided. To compensate for this shortfall, this RIA formulated an app

Exhibit 5A-4 below. The blue parabolic curve for population risk is based on the well concentrations over time in thcannot reconstruct the exact curve due to data availability issues, a parabolic curve represents groundwater contamina

clear that the peak population risks only capture a fraction of total population risks. Using an assumption of linear inlinear decreases from the peak, produced the simplified risk profile seen as a red line in Exhibit 5A-4. 
t = time to peak risk Exhibit 5A-4 – Population Risk Method 

t 

t0 = WMU built t0 t 

Rt Rt = peak population risk 

 = Actual Risk Profile  = Simplified Risk Profile 

Population Risks At Peak One Year Exposure Only 
The constant slope allowed estimation of the population risks from each year’s exposure by assembling the model ite

Dividing peak risks (y-value) by the time to peak (x-value), the slope of the time line was determined for each WMU

Exhibit 5A-5 below. 

Exhibit 5A-5 

Human Cancer Time Slope Factors For CCR 

Slopes For Conventional CCR Slopes For CCR Co-managed With Co

Liner - Receptor Landfills Impoundments Landfills Impound

Unlined - Adult 1E-08 6E-07 8E-09 3E-0Unlined - Child 2E-08 1E-06 2E-08 6E-0Clay-Lined - Adult 5E-09 4E-07 3E-09 1E-0Clay-Lined - Child 1E-08 7E-07 6E-09 3E-0

Multiplying this slope by the number of years elapsed yields the yearly increment of individual risk for that year. Mu

incremental individual risk by the population exposed in each year119 EPA estimated the number of cancers in each y

estimates cancer incidence by the difference between the blue and red profiles it is the best estimate based on currentl

As displayed in Exhibit 5A-6 below, this approach results in an estimate between 45 and 196 potential cancer cases o

of arsenic consumed through contaminated groundwater using EPA’s 1995 cancer slope factor (1.5 mg/kg/d-1) for arscancers. Using the ratios of conventional CCR co-managed with coal refuse a best estimate within this range is 145 c

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 m

groundwater well occurring beyond the nearest surface waterbody. Since the longer arrival times occur with longer travel distances, and 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 shorte

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, thi

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’

additional year for installing groundwater monitoring. Seventy-eight years are the time at which the risks for typical unlined and clay-lined 

not intercepted by surface water will peak. Cancers occurring after year 78, though potentially significant, are unlikely to play a significant r

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 

will be further reduced by state regulations, detection of contamination, and a general trend away from wet handling. 
Exhibit 5A-6 

Potential Future Human Cancer Cases from the Disposal of CCR Based on Arsenic Cancer-Slope Factor from E

Disposal of Conventional CCR Disposal of CC

Co-Managed with Coa

WMU Adult Child Totals Adult Child 

Unlined Landfills 0.1 0.1 0.2 0.1 0.1 Clay-Lined Landfills 0.1 0.1 0.2 0.0 0.0 Unlined Surface Impoundments 20.1 16.3 36.4 98.1 67.6 Clay-Lined Surface Impoundments 4.8 3.5 8.3 17.6 12.6 

Totals 25.1 20.0 45 115.8 80.3 

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 bexcess male lung cancers per 10,000 people. Under the exposure factor assumptions used by the NRC the equivalent 

is 26 mg/kg/d-1. For details of how this cancer slope factor was calculated, see Appendix K4 – Cancer Calculations.

displays the population risk estimates for CCR disposal base on the NRC source.122 Using the NRC (2001) cancer slo

expect between approximately 778 and 3,392 cancer cases over 75 years as a result of arsenic consumed through conUsing the ratios of conventional CCR co-managed with coal refuse produces a best estimate within this range of 2,50

Exhibit 5A-7 

Potential Future Human Cancer Cases from CCR Disposal Based on Arsenic Cancer-Slope Factor from N

Disposal of Conventional CCR Disposal of CC

Co-Managed with Coa

WMU Adult Child Totals Adult Child 

Unlined Landfills 2 2 4 1 1 Clay-Lined Landfills 1 1 2 1 1 Unlined Surface Impoundments 348 281 629 1,696 1,169 Clay-Lined Surface Impoundments 82 61 144 305 218 

Totals 433 345 778 2,003 1,389 

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. 
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. Ap

further explanation as to why the NRC science is considered more appropriate than the older skin cancer research tha

was derived from. Because EPA has greater confidence in the NRC estimates, it chose to use the 2,509 cancers calcuestimate. EPA also used the NRC ratio of 23 male bladder cancers to 14 male lung cancers to estimate how many of 

occur in each year. That is, 62%, or 1,556 cancers, are assumed to be bladder cancers and 38% or 953 are assumed to 

Appendix K7 shows the best estimate number of lung and bladder cancers in each year that was used in the remainin

Since cancers are not all fatal, the next step was to estimate the number of cancers that are fatal and non-fatal. This weach type of cancer using 5-year survival rates from the EPA-ORCR 2009 CCR risk report. The 5-year survival rate 82% and the 5-year survival rate used for lung cancer is 14%. Thus, 1,276 (82%) of bladder cancers are non-fatal an

lung cancer, 133 (14%) are non-fatal and 820 (86%) are fatal. Again, these cancers are spread over the 75 years of thmonetize avoided cancer risks, this RIA applied the value of a statistical life (VSL) plus the cost of terminal cancer trExhibit 5A-8 below. To monetize avoided non-fatal cancer risks, this RIA used an estimate from Magat et al. (1996)

a typical individual’s assessment of a non-fatal lymphoma risk reduction was the equivalent of 58.3% of a fatal lymp

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 20

Fatal cancers: value of statistical life (VSL)* $8,8Non-fatal cancers: 58.3% of VSL* $5,1Medical costs associated with fatal bladder cancer** $14Medical costs associated with fatal lung cancer** $8Notes: *Median VSL of $4.65 million (1997$) from Exhibit 7-3 (page 89) of EPA “Guidelines for Preparing Economic AnalysesR-00-003, Sept 2000; converted for this RIA to 2008 dollars using the Consumer Price Index. In addition, projections of bfuture years are subject to income elasticity adjustments. These represent changes in valuation in relation to changes in reFor example, if, for every 1% increase in real income, a particular consumer’s willingness-to-pay for a particular item incr

this would be represented by an income elasticity of 1.0. For most items, income elasticity values are actually less than 1, 

that valuation of most items does not increase as fast as real income levels. To do so, applied the change in Gross Domestper-capita between the original dollar year of the estimates and 2008, and an income elasticity of 0.5 based on estimates fr

W. K. and Aldy, J. E. “The Value of a Statistical Life: A Critical Review of Market Estimates throughout the World,” Jou

and Uncertainty, Vol.27, 2003, pp. 15–76. 

** These costs reflect the inpatient hospital stays, skilled nursing facility stays, home health agency charges, physicians' se

outpatient and other medical services - in other words the treatment and maintenance costs. Costs are assumed to occur du

123 Magat, Wesley A., V. Kip Viscusi and Joel Huber "A Reference Lottery Metric for Valuing Health," Management Science, Vol.42, Issue 124 EPA acknowledges that alternative approaches to valuing non-fatal cancers are available. One such alternative is presented in Appendix 
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 prio

• Bladder cancer costs are based on survival and death rates each year for 20 years which captures most deaths 

bladder cancer among those who are diagnosed with the disease. 

• 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 “The Cost of Illness Handbook,” Office of P

Prevention & Toxics, October 2001). These costs are updated for this RIA to 2008 dollars using the Medical Care CompoConsumer Price Index. 

These values are further adjusted for cessation lag and income as described in Appendix K8. EPA used the cessation from arsenic in Chen and Gibb (2003)125 to construct a Weibull curve approximating the lag time between reduced ar

reduced cancer outcomes. Because this lag will reduce willingness to pay compared to an immediate risk reduction, t

statistical cancers are 83% and 67% of what they would be using an unadjusted VSL (at a 3% and 7% discount rate, rdescribed in more detail in Appendix K8. For income, EPA projected per capita GDP, and used this combined with income elasticity of 0.5 from Viscusi and Aldy (2003) to estimate the growth in VSL until the exposure year. There h

over whether VSL should be adjusted to the year of exposure or the year of the cancer. However, typically, it is not p

exposure occurred. Because of the model used here, this RIA applied the VSL adjustment at the time of exposure. Tadjustment 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 cu

avoiding cancer risk was calculated for each of the 75 years. These values can be seen in Appendix K7. The presen

values is approximately $4,696 million at a 3% discount rate and $885 million at a 7% discount rate. This would refl

future cancer risks assuming that no steps were taken to prevent contamination and the resulting cancers. However, a

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 (be

account in the model). The benefits of regulatory options would be reflected by lower rates of cancer, resulting from (including ground-water monitoring, permitting, corrective action, phase-out of surface impoundments, financial assu

will also have the benefits of reducing or eliminating groundwater remediation cost, because groundwater releases ar

125 Source: Chen, C.W. & Gibb, H. “Procedures for Calculating Cessation Lag.” Regulatory Toxicology and Pharmacology,” Vol.38, Issue 2126 The two Subtitle D Options evaluated were: (1) Subtitle D — regulation of landfills and surface impoundments, with liners required for 

impoundments, and new landfills and (2) Subtitle “D Prime” — regulation of landfills and surface impoundments, with liners required only and landfills. 
controls like surface-impoundment phase-out, or reduced because releases are caught earlier. These benefits, and how 

in the section below. First, even in the absence of federal regulations, CCR disposal units will not leach and cause cancers in all cases estim

evaluation above. Even without federal regulation, there will be facilities that discover contamination and clean the c

cancers occur, either due to state regulations or good practice. Where exposures are identified, this RIA assumed that 

off (e.g., through provision of alternative water sources). Even facilities that fail to prevent contamination may detecclean it up at a later time, although after exposure has occurred. This Step of the estimation attempted to account for To estimate the different speed and cost of groundwater remediation likely under the baseline and under the three regSubtitle C, Subtitle D and Subtitle D Prime), this RIA began by examining the differences across states in groundwatrequirements pertaining to CCR disposal units, and focused on groundwater monitoring requirements because adequa

determine whether a release has occurred. This RIA assumes that, where releases of concern have been identified, an

people may be at risk, drinking water pathways will be cut off and alternative drinking water will be provided. Then 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 Exhibit 5A-9 below presents these percentages for states requiring at least some monitoring (categories 2 and 3 abov

monitoring at exiting facilities (category 3 above). The first value in the table, 91%, is the percentage of CCR discardsome form of monitoring requirements, whether for new landfills only, or for both new and existing landfills. 62% is discarded in landfills that impose monitoring requirements on both new and existing CCR disposal units (a subset of 

are also provided for CCR that are managed in surface impoundments. Appendix K9 provides these data for each in

127 Some states may require monitoring only for off-site units; however, in the absence of a specific breakdown, EPA made the assumption th

monitored in all states that require monitoring. 
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 

Existing Unit

(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 remed

identified, under the baseline and three regulatory scenarios. Since all but 4 of the 2,509 cancers projected above resu

impoundments, only surface impoundment monitoring data were used in the calculations.128 For the baseline scenari

states with the highest level of monitoring requirements (those requiring groundwater monitoring at both new and exi

generally find groundwater contamination relatively early and would require preventive measures that would avoid c

plume and/or put residents on municipal or bottled water). Thus, 12% of contamination that could occur would have and the resulting cancers prevented. To the extent that cleanups and/or alternative water are required, that was consiTo model the Subtitle D option, EPA assumed that states with groundwater monitoring requirements at new units, or 

units in question, would upgrade their existing programs to provide fuller coverage – because they already have a regbut other states with no program would not. While states that do not currently regulate units would not change their p

EPA issued national rules, EPA recognizes that facilities in these latter states will to a certain extent comply, to avoid EPA’s and states’ experience in implementing the RCRA program demonstrates that self-implementing ground-water of limited reliability. Given these factors, the percentage of waste disposed of in states with some level of groundwata reasonable estimate of benefits for the subtitle D approach. Under these assumptions, contamination in states with mfor only new units, as well as contamination in states with monitoring requirements for new and existing units would 

This leads to 48% of surface impoundment groundwater contamination being detected before extensive damage has o48% of cancers being prevented. Since the Subtitle “D Prime” option does not require the retrofitting of existing units, unlined surface impoundments continuing source of release. However, the presence of a new national rule accompanied by EPA support would lead make such updates. Since the potential risks will fall somewhere between the Subtitle D option and the baseline, the baseline and the Subtitle D option (30%) was chosen as a best estimate. This leads to 30% of contamination being imthus 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 b

rates at different pHs and the damage cases. 
Finally, for Subtitle C, there would be federal oversight of the groundwater monitoring requirement, and therefore thifacilities would have contamination detected early. Looking forward, this would effectively prevent all cancers.129 In 

standards of the subtitle C rule would largely prevent future releases because surface impoundments would be phasedlandfills would require composite liners. Similarly, closure requirements would largely prevent releases after closure 

Where releases of arsenic from disposal units occur in the future, they will be detected promptly after they occur undwell as under the other options where good monitoring programs are in place. In these cases, there may be response cOn the other hand, if facilities do not have adequate detection systems in place (and other adequate controls, e.g., linethen detection will be delayed. This RIA assumes that releases will eventually be discovered, but that detection may quantify this assumed that contamination would be discovered consistently until it was all discovered. Since the rate unpredictable, further assumed detection would be at a constant rate, reaching 100% detection by the final year of the 

discoveries were assumed not to start for six years because the first percentile of time duration until peak risks for unimpoundments occurred. Restated, this profile assumes that facilities in states that require groundwater monitoring fogenerally find contamination in the future soon after it occurred, reducing response costs, and preventing cancer risksand other controls were not adequate, releases would potentially go undetected for lengthy periods, causing cancers ueventually detected and those residents switched to municipal or bottled drinking water. In addition, response costs wincreased. The present value of avoiding all of the risks in the baseline case is the upper-bound on benefits, and this udetection and groundwater remediation as described in this section. The risk reduction benefit for each regulatory opbetween baseline risks and remaining risks under that option. These benefits, accounting for the detection and remed

Exhibit 5A-10 below. Baseline expected cancer risks are accounting for detection and remediation, compared to witinto 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 islowly moving from wet handling in impoundments to dry handling in landfills or to beneficial uses. While this trend discussed above, it is unlikely to have a significant effect on risks for two reasons. First, surface impoundments, to thare typically closed with waste in place. Thus, they are likely to continue to leach beyond the 75-year period modeled assessment; this is particularly true in situations where they are not lined (which are overwhelmingly the case) and whstates without strong regulation. In the latter case, closures are likely to be inadequate, leading to continued infiltratiothat occurred before the surface impoundments are closed will continue to migrate until they reach the groundwater wintercepted by a surface waterbody (again particularly in states without strong programs). Given the relatively very laimpoundments, and the presence of a hydraulic head at least before closure, these historic releases have the potential these considerations, the closure of surface impoundments in states without regulations (e.g., corrective action, grounwould behave very similarly to active surface impoundments in terms of their risks to human health and the environmregulatory 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 reason

this RIA assumed 100% detection. 
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 estimat

estimating the number of coal-fired electric utility plants that would require responses under various state environmenthe 2009 risk assessment. In any particular situation, a state could require remediation of a site involving potential dr

or 10-6 levels. In addition, states may choose to require groundwater remediation for groundwater that is not a likely 

because of ecological concerns. Exhibit 5A-11 below shows the number of facilities potentially requiring cleanup. 

equally acceptable under current state programs, the average is believed to be a best estimate for how many electric uneed 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 Avera

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 sites would leach at above various clean up levels. Typically, solid waste cleanups can be conducted at either 10-4, 10

cancer risk levels. Exhibit 5A-12 uses the PERCENTRANK function in Excel to estimate what percent of risk resulclean up level. For example, in the first cell of Exhibit 5A-12, the 78% means that 10-4 is higher than 78% of the pro

unlined landfills with conventional ash. 

UL = Unlined CL = Clay-Lined A = Conventionally Managed Ash C = Co-managed Ash LF = Landfill SI = Surface Impoundment 
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 percencleanup level displayed in Exhibit 5A-13 can be derived by subtracting the percents in Exhibit 5A-12 above from 10states may require remediation of all groundwater, whether or not it is potable, they may also choose not to on a site bin the EPA-ORCR 2009 CCR risk report, it is estimated that two-thirds of sites are located closer to a surface waterbogroundwater well. Therefore, sites located on surface waterbodies may not be cleaned in some states. This 2/3 decresecond 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 F plant data from this RIA and combining it with the conventional versus co-managed rates. 
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 5A-13 above yields the estimated number of facilities that would lead to state or federal clean ups in Exhibit 5A-15 bthe number of facilities requiring cleanup does not account for any cleanups resulting from other constituents exceedi

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 baselioption presented above. Groundwater remediation costs were estimated in two steps. First, EPA assumed contaminasites in states with more stringent monitoring requirements, would be discovered promptly. This suggests that there i

remediation required than at the typical site. Thus, EPA assigned these sites the 25th percentile remediation costs disp

below as the midpoint of the bottom half of costs. These future remediation events were spread evenly across all 75 y
Exhibit 5A-16 

Per-Site Groundwater Contamination Remediation Costs* 

Cost element category 25th percentile “early costs” 75th percentile “later costs” 

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 “Cost Analyses for Selected Groundwater Cleanup Projects: Pump and Treat Systems and Permeable Reactive Barriers,” 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 assu

contamination would take longer. That is, CCR contamination would have migrated for some number of years, resul

groundwater plume to remediate, or more extensive remediation. EPA assigned these sites the 75th percentile remedi

of the top half of costs. Since the first percentile time to peak results for unlined surface impoundments is six years, idiscoveries and cleanups will be made in the first six years for these sites (three years once the two years for state adogroundwater monitoring are considered). The costs are thus spread evenly over the remaining 72 years. The present remediations, accounting for the slow, but continued discovery of contaminated sites, is presented in Exhibit 5A-17 b

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 
Aggregate benefits from cancer risk reductions and avoided remediation costs are summarized in Exhibit 5A-18 belo

calculated by subtracting the costs resulting under that option from the costs resulting under the baseline (i.e., cost av

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% discountGroundwater 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 

groundwater protection benefits: • Estimates do not account for historic releases at operating plants. These releases could lead to further migration a

without proper regulatory actions like groundwater monitoring. 

• A linear slope for individual cancer risk was used to approximate the increase in cancer risks instead of the parabo• Approximately 18% of plants dispose of CCR off-site only. Since these facilities were not accounted for, additio

exposed to arsenic cancer risks from disposal as recently illustrated by the Gambrills, MD and Chesapeake, VA d

• Three new research studies131 (2006, 2008, 2009) from EPA’s Office of Research and Development, indicates tha

metals much faster than originally believed. The damage cases at Gambrills MD and Chesapeake VA resulted in 

contamination much more quickly than would be expected, and are therefore consistent with this research. 

131 The three new EPA studies are: 

1. “Characterization of Mercury-Enriched Coal Combustion Residues from Electric Utilities Using Enhanced Sorbents for Mercury 

Office of Research and Development. Research Triangle Park, NC. January 2006. 
• Multiple CCR disposal units at a single electric utility plant will all affect the same population. The risk estimate

additive risks from multiple units. However, the populations around these units are accounted for as described in 

• Multiple landfills could exist at some facilities. While the area of multiple surface impoundments was considered

landfills was not considered because EPA did not have survey results for dry handling even though some facilitiethan one CCR landfill onsite. 

• Residents on municipal water systems were not included in the 2009 risk assessment or in this analysis. However

pathway is possible, which means this RIA likely under-estimated the human population that may be exposed to C

• Populations that are farther than 1-mile that may be within the plume were not included. • Some surface water bodies that this analysis assumes fully intercept the groundwater plume may in fact only parti

or not intercept it at all. This situation would be more likely to occur when surface water bodies are small or shal

relative to the size of the aquifer underneath the CCR disposal unit, or are oriented such that they would not likely groundwater plume. 

• Potential cancer cases resulting from consumption of recreationally-caught fish (contaminated by direct surface im

and leaching from groundwater to surface water) are not included in the calculations. 

• According to the EPA-ORCR 2009 CCR risk study, cancers can continue well after the analysis ends, but these c

in the population risk estimates. 

• The use of a 5-year survival rate does not take into account those who may die from the cancer after year 5. Sinc

year cancer survivors would have died in later years, they are undervalued in this assessment. 

• The estimated number of cleanups is based only on modeled arsenic contamination. It does not account for clean

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: • Cancer risk estimates might include some individuals who are down-gradient, but are outside the plume. • All arsenic was assumed to be present in the arsenic III state. Appendix K5 contains an analysis in which all arse

speciated in the arsenic V state, and EPA concluded that even if some portion of arsenic was speciated in the arse

results would not significantly change. 

• The male CSF estimate from NRC (2001) was used instead of the female CSF. Appendix K5 contains an analys

CSF was applied. 

• It is possible that some states would choose not to remediate CCR contamination above cleanup levels once local 

municipal or bottled water. 

2. “Characterization of Coal Combustion Residues from Electric Utilities Using Wet Scrubbers for Multi-Pollutant Control,” EPA/6

Research and Development, Air Pollution Control Division. Research Triangle Park, NC. July 2008. 3. “Characterization of Coal Combustion Residues from Electric Utilities – Leaching and Characterization Data,” EPA-600/R-09/15

Development, Air Pollution Control Division. Research Triangle Park, NC. December 2009. 
• Willingness to pay estimates for non-fatal cancers has been assigned lower values in some research. An alternativ

cancers is presented in Appendix K5. 

• 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: • This RIA assumed an evenly distributed population for establishing up-gradient and down-gradient populations, a

population for the WMU area. 

• The latitude and longitude data of the WMU are uncertain. • State programs serve as a proxy for units managed well and units managed poorly. However, there could be som

states without any program. Conversely, there could be some WMUs managed poorly in states with an existing p

• State regulatory programs affecting CCR disposal may be different than summarized in Appendix E of this RIA. 

• Remediation costs are very site-specific, and the 25th and 75th percentile costs used here may overestimate or unde

remediation costs of any particular cleanup. For example, the cost of responses to new releases caught early will estimated costs. In other cases, even if contamination is identified early, those costs can exceed the 75th percentiResponses at Gambrills MD and Chesapeake VA, two sites where CCR contamination was identified relatively ewhere actual groundwater remediation responses will far exceed the cost estimates. 

• This RIA assumed that discovery of CCR groundwater contamination and the resulting remediation costs would b

75 year period for regulated facilities and evenly over the 72 years for unregulated facilities. However, experienc

solid waste program indicates that the incorporation of lined units could reduce contamination over time. 
5B. Benefit of Preventing Future CCR Impoundment Structural Failures (Avoided Cleanup In December 2008, a failure of a CCR impoundment at the Tennessee Valley Authority (TVA) Kingston Fossil Fuel 

environmental release of 5.4 million cubic yards of CCR. This impoundment failure event illustrated the potential enseverity of structural failures involving CCR impoundments. This section of the RIA estimates future avoided impoucosts 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 au

of the Comprehensive Emergency Response, Compensation and Liability Act (CERCLA), from 162 individual electr

61 electric utility corporate headquarters offices. EPA obtained its list of facilities from a 2005 Department of Energy burning electric utility facilities. EPA used DOE’s 2005 Energy Information Agency F767 database, which provides 

disposition of coal ash from coal burning electricity producers. The database included "steam-electric plants with a geof 10 or more megawatts." The term “generator,” means the actual electric generator, not the whole plant. A plant ty

more generators. EPA also sent the letters to corporate offices of the electric utilities to make sure that all of their fac

due to limitations in the DOE survey. Based on information received in response to the initial letter to the utility corp

offices, on April 27, 2009, EPA sent information request letters to an additional 48 plants that had been identified by 

Based EPA’s initial collation of the mail survey data, 42 CCR releases from impoundments were reported, all of whic15 years (1995-2009), in response to Question 8 of the survey questionnaire which asked for electric power plants to impoundment releases which occurred within the last 10 years (i.e., 1999 to 2008). Exhibit 5B-1 below presents a su

impoundments release cases. Appendix K11 provides additional information about these 42 release cases. 
Exhibit 5B-1 

2009 EPA Mail Survey Data for 42 Historical Release Events Involving CCR Impoundments at Coal-Fired Electric 

Item Owner Company Name of Coal-Fired Electric Plant Name of CCR Impoundment 

Capacity 

(acre feet) 

Height 

(feet) 

Year 

Installed 

1 Allete Inc Clay Boswell Power Station Coal Pile Sump 1 20 1972 2 Ameren Energy Generating Co Meredosia Power Station Fly Ash Pond 650 24 1968 3 American Electric Power Cardinal Power Station Fly Ash Reservoir 2 11350 237 1987 4 City of Springfield Lakeside Metal Cleaning Waste Basin 4 1982 5 City of Springfield Lakeside Metal Cleaning Waste Basin 4 1982 6 Dominion Chesterfield Power Station Lower (Old) Ash Pond 740 19 1964 7 Duke Energy Corp Walter C. Beckjord Power Station Ash Pond C 1400 50 1966 8 East Kentucky Power Coop Inc Dale Power Station Dale Ash Pond #4 112 26 1977 9 First Energy Generation Corp Bruce Mansfield Power Station Lakeside Ash Pond 20 1957 

10 Georgia Power Co Harllee Branch Power Station C 1240 83 1971 11 Georgia Power Co Bowen Power Station Ash Pond 3719 45 1968 12 Georgia Power Co Bowen Power Station Ash Pond 3719 45 1968 13 Indianapolis Power & Light Co Eagle Valley Generating Station A/B/C Pond 1949 14 Indianapolis Power & Light Co Eagle Valley Generating Station A/B/C Pond 1949 15 Kansas City Power & Light Co LaCygne Generating Station Scrubber Sludge Ponds 6818 45 1971 16 Kansas City Power & Light Co LaCygne Generating Station Scrubber Sludge Ponds 6818 45 1971 17 Kansas City Power & Light Co LaCygne Generating Station Scrubber Sludge Ponds 6818 45 1971 18 MidAmerican Energy Co Riverside Generating Station South Surface Impoundment 109 10 1967 19 Northern Indiana Pub Serv Co R. M. Schahfer Power Station Little Blue Run Dam 84300 388 1975 20 Northern States Power Co Sherburne County Power Station Pond No. 2 57 1984 21 PacifiCorp Naughton Power Station FGD Pond #2 382 25 1999 22 PacifiCorp Naughton Power Station North Ash Pond 2100 61 1973 23 PacifiCorp Dave Johnston Power Station Blowdown Canal 1 0 1972 24 PacifiCorp Jim Bridger Power Station FGD Pond #1 1340 32 1979 25 PacifiCorp Jim Bridger Power Station FGD Pond #2 11534 42 1990 26 PPL Generation, LLC PPL Montour Power Station Detention Basin 53 8 1968 27 PPL Generation, LLC PPL Martins Creek Power Station Ash Basin 4 40 43 1989 28 PPL Generation, LLC PPL Montour Power Station Ash Basin No. 1 40 1968 29 PPL Montana LLC Colstrip Steam Electric Station Units 1 & 2 Stage Evaporation Ponds 4370 88 1992 30 PPL Montana LLC Colstrip Steam Electric Station Units 3 & 4 Effluent Holding Pond 17000 138 1983 31 PPL Montana LLC Colstrip Steam Electric Station Units 1 & 2 Stage Evaporation Ponds 4370 88 1992 32 PPL Montana LLC Colstrip Steam Electric Station Units 1 & 2 A Pond 245 25 1975 33 PPL Montana LLC Colstrip Steam Electric Station Units 3 & 4 Effluent Holding Pond 17000 138 1983 34 PPL Montana LLC Colstrip Steam Electric Station Units 3 & 4 Effluent Holding Pond 17000 138 1983 35 PPL Montana LLC Colstrip Steam Electric Station Units 1 & 2 Stage Evaporation Ponds 4370 88 1992 36 Progress Energy Carolinas Inc W. H. Weatherspoon Power Station 1979 Pond 28 1979 37 Progress Energy Carolinas Inc Roxboro Power Station FGD Flush Pond 33 2008 38 Santee Cooper Winyah Power Station Unit 3 & 4 Slurry Pond 1190 30 1980 39 Tennessee Valley Authority Kingston Power Station Dredge Pond 1955 40 Tennessee Valley Authority Widows Creek Power Station Gypsum Stack (Wet Stacking Area) 11157 75 1986 41 Xcel Energy PSCo Comanche Station Polishing Pond (#4) 12 0 1972 42 Xcel Energy PSCo Valmont Station West Ash Settling Pond 16 0 1964 

 Minimum = 1 0 1949  Maximum = 84,300 388 2008  Mean (average) = 6,874 59 1976  Median = 1,750 42 1974 

 Column total (based on gallons released data for 15 of the 42 events) = 
As displayed below in Exhibit 5B-2, EPA was able to collect cost data on three of the most significant and recent relresulting 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) 

1 PPL Generation LLC PPL Martins Creek Power Station PA 

(“Ash basin 4”) 

2005 100 million 

2 Tennessee Valley Authority (TVA) Kingston TN 

(“Dredge cell dike”) 

2008 1.1 billion 

(5.4 million cubic yards) 

3 Tennessee Valley Authority (TVA) Widows Creek Power Station TN 

(“Gypsum stack”) 

2009 6.1 million 

Column totals = 1.2061 billion 

* Data sources: • Item 1: Page 29 of “Public Health Issues Surrounding Coal as an Energy Source,” Brian Schwartz, MD, MS, Department of Environmental H

2009 at http://www.jhsph.edu/bin/g/f/Coal_and_public_health_Mar_2009.pdf

• Item 2: $3.0 billion is EPA’s initial “social cost” estimate assigned in this RIA to the December 2008 TVA Kingston TN impoundment relea

represents the opportunity costs incurred by society, not just the monetary costs for cleanup. OMB's 2003 "Circular A-4: Regulatory Analysi

Federal agencies to estimate "opportunity costs" for purpose of valuing benefits and costs in RIAs. This $3.0 billion social cost estimate is la

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 ot

in addition to TVA’s cleanup cost estimate: (a) TVA cleanup cost, (b) response, oversight and ancillary costs associated with local, state, and 

(c) ecological damages, and (d) local (community) socio-economic damages. Appendix Q to this RIA provides EPA's documentation and cacost elements, which total $3.0 billion in social cost. Appendix Q to this RIA also provides an alternative, lower estimate of social costs, ba

modeling assumptions for capturing such costs. This alternative analysis suggests that TVA’s cleanup costs alone may be close to the social cKingston impoundment failure. EPA specifically requests comment on this social cost estimate, and will continue to develop this estimate fo

• Item 3: 25 January 2010 e-mail entitled “TVA Widow’s Creek Clean Up Info” from Anda Ray, Sr. Vice President of TVA Environment & T

Sustainablity Officer, to Jim Kohler, EPA-ORCR Environmental Engineer. 
Given this limited data, this RIA attempted to quantify the likelihood and costs of future releases using a historical m

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 

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 

TVA Widow’s Creek (6,100,000 gallons) and PPL Martin’s Creek (100,000,000 gallons) are the lowest and 

this category, respectively. As an approximation, EPA assumes their costs should also bracket the costs of o

releases.132 Thus, EPA estimates that the typical costs of a significant failure will be $23.1 million (the aver

Creek and PPL Martin’s Creek). 

3. Seepage failures: Involving releases below one million gallons. While these releases can still be significant 

human health and the environment, this RIA does not include these in this analysis, which under-estimates tohistorical methodology. These smaller seeps are common to earthen dams and are not necessarily a problem 

volume is increasing or the seepage becomes cloudy - indicating the possible transport of CCR through the e

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 cos

their frequency. Since relatively little data are available, this RIA applies a Poisson distribution. The Poisson distribudiscrete events, and not continuous functions, are being modeled. To be a Poisson process, the arrival of events must multiplicity, and independence. Here, the events (releases) satisfy non-multiplicity because the probability of two or period of time is very small. They also satisfy independence because releases occurring in one time period are indepe

other time period. However, as these impoundments increase in age, it is quite likely that releases might increase oveviolate the stationarity requirement. This potential problem is dealt with in Step 4 below. For the present, it will be a

at a constant rate in the future. In general, a Poisson distribution can be represented by the equation: 

!

( ) ( )

k

t ek λt λ −

132 This is a valid assumption if cleanup costs are closely correlated to tonnage released. Since cost modeling software typically requires an i

correlation is likely strong. 
Where: λ = 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 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 

Events (K)

Probability

Catastrophic Significant

133 λ was calculated by dividing the number of events observed between 1995 and 2009 by the 15-year time period. 
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 

Events

Probability

Catastrophic Significant
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 da

above. This was done for the average case and three high-end cases (90th, 95th, and 99th percentiles). For each case, t

releases seen in Exhibit 5B-4 below was divided by 50 to get the expected number of releases per year. These event

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 Even

Catastrophic 8 7 6 3 $3.0 billion* 

Significant 27 24 22 17 $23.1 million 

* Note: $3.0 billion is EPA’s initial “social cost” estimate assigned in this RIA to the December 2008 TVA KingsTN impoundment release event. Social cost represents the opportunity costs incurred by society, not just the moncosts for cleanup. OMB's 2003 "Circular A-4: Regulatory Analysis" (page 18) instructs Federal agencies to estim"opportunity costs" for purpose of valuing benefits and costs in RIAs. This $3.0 billion social cost estimate is largthan 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 estimateTVA cleanup cost, (b) response, oversight and ancillary costs associated with local, state, and other Federal agenc(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. Appendi

to this RIA also provides an alternative, lower estimate of social costs, based on different modeling assumptions fcapturing such costs. This alternative analysis suggests that TVA’s cleanup costs alone may be close to the social 

associated with the Kingston impoundment failure. EPA specifically requests comment on this social cost estimaand 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 

below in Exhibit 5B-5, this will lead to a decrease of approximately 300,000 tons being disposed of in surface impou

approximately 1.3% of the initial 22.5 million tons in 2005. Since the tons disposed of (and similarly, the number of likely relate to the number of releases, these decreases are accounted for by using 2005 wet tonnage as a benchmark a

of wet tonnage declines 300,000 tons per year. The cost for each year is multiplied by the remaining percent still han
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 calcuas displayed in Exhibit 5B-6 below. A full table of year-by-year costs can be found in Appendix K11. Approximatresult from catastrophic releases, and the remaining 3% result from significant releases. It is important to note that no 2012-2014 as the rule will not be adopted and implemented until 2015. However, all costs beginning in 2015 are assusubtitle C. Although facilities are given 5 years to phase out CCR impoundments under one of the proposed regulato

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 tsurface impoundments be closed if they aren’t lined when compared to compliance with the surface impoundment ph

Compliance will largely depend on the uncertainties of state regulations, the implementation of those regulations, and 

some facilities will line their surface impoundments instead of converting to dry handling, these facilities will continucatastrophic failure even though they may no longer require cleanup costs for groundwater contamination. The perce
some surface impoundment regulations, 48% as described in Appendix K9, is used as a proxy for the phase-out of exHowever, the 5.5% of those 48% that would retrofit with composite liners could still pose release risks. This results ibenefits 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 

inspections of surface impoundments would be required under this option, but it is difficult to predict the extent to whwould actually occur and would decrease catastrophic failures. In any case, the benefits of subtitle D prime would be D and greater than the baseline in terms of costs of catastrophic failures avoided. Thus, EPA used the midpoint as a beffectiveness that these inspections would have, which results in 23% of the subtitle C benefits being realized in a sub

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 “D Prime” 

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 disthe trend of increasing release frequency based on the aging structure of the earthen impoundments. EPA attempted t

trend was likely between releases and the average age of the surface impoundments. First, EPA limited the universe 

reported release dates within the past 15 years. Next, the number of releases in 2009 was scaled up to account for the 

survey questionnaires were returned by June of 2009. Thus, the four releases in 2009 were scaled up by 12 months/6 Using commission age and only those releases for which a release year was known, EPA constructed the profile of re

from 1995 to 2009 displayed in Exhibit 5B-7 below. 
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 incyears. All five significant releases and the catastrophic release at TVA Kingston TN have happened since 2005. To a

lack of stationarity, EPA conducted a sensitivity analysis with alternate values of λ. Instead of looking at the last 15 ythe previous 5-year period best reflects impoundment releases. Thus, in place of the earlier calculated lambda values 

by dividing the number of catastrophic and significant failures between 1995 and 2009 by 15, EPA calculated higher 

dividing the catastrophic and significant failures between 2005 and 2009 by 5. Using these new lambda values, but k

forecast period, EPA derived the Poisson distribution seen in the two figures below. The probability of a specific num

significant releases is illustrated in Exhibit 5B-8 and Exhibit 5B-9 (cumulative distribution) below. 
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 

Events (K)

Probability

Catastrophic Significant
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 

Events

Probability

Catastrophic Significant
With these new distributions, EPA performed the same calculations as described in Step 3. The expected number of rbelow was divided by 50 to get releases per year; these releases were multiplied by the cost per release; an adjustmen

voluntary switching to dry handling; and yearly values were discounted. A full exhibit of year-by-year costs can be f

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 rele

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 “social cost” estimate assigned in this RIA to the December 2008 TVA KingTN 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 agenci

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 Fe2010), because EPA’s social cost estimate consists of three other social cost elements in addition to TVA’s cleancost estimate: (a) TVA cleanup cost, (b) response, oversight and ancillary costs associated with local, state, and oFederal agencies, (c) ecological damages, and (d) local (community) socio-economic damages. Appendix Q to t

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 S

helps to explain how significant the assumption of lambda, and the potential non-stationarity of the data, can have on Sensitivity results were also calculated for subtitle D (version 2) and subtitle “D prime” approaches. As assumed abo

(version 2) option, EPA expects delayed compliance with the requirement that surface impoundments be lined and thimpoundments be closed if they are not lined when compared to compliance with the surface impoundment phaseout Compliance will largely depend on the uncertainties of state regulations, the implementation of those regulations, and 

some facilities will line their surface impoundments instead of converting to dry handling, these facilities will continucatastrophic failure even though they may no longer require cleanup costs for groundwater contamination. The percesome surface impoundment regulations, 48% as described in Appendix K9, is used as a proxy for the phase-out of ex

However, the 5.5% of those 48% that would retrofit with composite liners could still pose release risks. This results i(special waste) benefits being realized in Subtitle D (version 2). 
For the subtitle “D prime” approach, existing impoundments will not need to be lined, but can continue to operate uninspections of surface impoundments would be required under this option, but it is difficult to predict the extent to whwould actually occur and would decrease catastrophic failures. In any case, the benefits of subtitle “D prime” would subtitle D (version 2) and greater than the baseline in terms of costs of catastrophic failures avoided. Thus, this RIA u

best-estimate of the effectiveness that these inspections would have. This results in 23% of the subtitle C (special warealized in a subtitle “D prime” approach. Exhibit 5B-11 below presents the avoided cleanup cost estimates for the t(i.e., Subtitle C special waste, Subtitle D version 2, and Subtitle “D prime”). 

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 “D Prime” 

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 (Scenar

Not all of these releases are likely to pose the type of catastrophic risks that were seen at TVA’s Kingston, TN plant. more likely where there is a high potential for impoundment materials to disperse over large areas. This is most likel

impoundments. Thus, this RIA presents an alternative assumption that the Kinston-like catastrophic releases would oimpoundments. In addition, as age appears to be a driving factor in releases, this analysis also assumed that Kingstonwould occur at older impoundments. Particularly, 96 impoundments of the 584 covered in the 2009 EPA mail survey 

and at least 25 years old. The analysis below assumes that 10% - 20% of these impoundments could fail within the n

equivalent to the upper percentiles of failures predicted in Steps 3 and 4 above; however it moves the costs forward in sensitivity of the benefits with respect to time. 
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 @

(in mill

88.2% 2014 - - 88.2% - - 86.9% 2015 $1,146 $1,022 70.6% $930 $8385.6% 2016 $1,095 $941 52.9% $677 $5884.3% 2017 $1,047 $866 35.3% $438 $3683.0% 2018 $1,001 $797 17.6% $213 $1681.7% 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 $1,94

Given the costs above, the total benefits of a Subtitle C phase out over 5 years would be the difference between the po

failure costs under C and the catastrophic failure costs under the baseline. For the 20% “Scenario #3”, this figure is d

in Exhibit 5B-13. For Subtitle D, it is assumed that the 48% of states (by tonnage, as described in Appendix K9) tha

regulatory oversight currently, would enforce the retrofitting requirement. However, since 5.5% of impoundments al

liners, these units would not be expected to close. Thus 94.5% times 48% leads to an approximately 45% of the SubtSubtitle D prime, the requirement of dam safety inspections would be likely to result in some amount catastrophic fai

baseline and the Subtitle D approach. This RIA uses the midpoint, a 23% reduction, as a best estimate. While these higher than the actual benefits from preventing catastrophic failures, they do help to define the upper bound of what i

practices of mismanagement. 
Exhibit 5B-13 

Avoided Future CCR Impoundment Catastrophic Failure Cleanup Costs 

($millions present value) 

Scenarios Subtitle C Special waste Subtitle D (version 2) Subtitle “D Prime” 

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 “catastrophic.” 
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 

beneficially used. It also estimates the values of social and economic impacts associated with baseline and different l

estimates the expected increase in beneficial use from increased cost of disposal of CCR and evaluates future changes coal combustion residuals (CCR) as a result of a potential “stigma” effect. 

5C1. Baseline Environmental & Economic Benefits of CCR Beneficial Use by Other Ind

According to CCR beneficial use market data compiled for year 2005 as displayed below in Exhibit 5C-1, and extrap

as displayed in Exhibit 5C-2 below, 62 million tons of annual CCR generated by 272 of the 495 electric utility plants 

beneficially used as material substitutes in at least 14 industrial applications. The purpose of this section is to provicategories of baseline benefits associated with baseline CCR beneficial use, consisting of five sub-elements (i.e., 1a, 

1. Economic benefits: Economic benefits estimated in this section are based on recent market prices and in

a. Annual cost savings to over 14 CCR beneficial use industries in the form of red

intermediate materials purchase prices relative to purchasing higher-priced subs

to paying electric utility plants lower prices for buying and using CCR as an ind

b. Cost savings to electric utility plants for avoiding the cost of disposing CCR wh

2. Lifecycle benefits: Lifecycle benefits as quantified in this RIA are based on market or social values ass

physical consequences of using CCR compared to substitute industrial materials, th

flow” chain of the national economy which consists of five basic stages (1. raw matmaterials processing, 3. industrial manufacturing, 4. product use, 5. product end-of-disposal/recycling). Three lifecycle physical consequences are quantified in this RIa. 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 cement, and wallboard representing a sub-total of 58% of all CCR beneficial uses) wthe prior 2008 study134 used as a reference for this section of the RIA. 

134 Source: EPA Office of Solid Waste “Waste and Materials-Flow Benchmark Sector Report: Beneficial Use of Secondary Materials – Coal 

Report, EPA report nr. 530-R-08-003, prepared by Industrial Economics Inc., 95 pages, 12 Feb 2008 at: http://www.epa.gov/osw/partnershipThe beneficial use market data cited in this source is summarized from the American Coal Ash Association (ACAA) 2005 national survey of 
Lifecycle benefits encompass economic benefits so these two categories are not additive but duplicative. Lifecycle bbased on “lifecycle analysis” (LCA), a method which involves estimating both internalized (e.g., market priced) and not captured in market prices) material flow consequences: 

“Life cycle analysis depicts the production of materials in a system of complex physical outcomes, and can princremental physical consequences of a change in material inputs, technology, waste management practices, In LCA, as in reality, one change in the physical system, such as the substitution of fly ash for virgin Portland 

corresponding cascade of economy-wide impacts and shifts. As inputs are substituted, technologies, physical exposure pathways change. Using a range of modeling platforms and life cycle inventories to calculate the owith each incremental change, LCA calculates the net result of all of these interactions, capturing the total ina change in operations on physical environmental impacts such as air emissions, and energy and water use.” 

• 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 Umillion per-year based on annual CCR sales revenue data supplied by 233 electric utility plants to the 2005 EIA-767 RIA to 2009. Based on comparison with the average higher prices for substitute industrial materials, using lower-pricnational economy with $2,300 million in annual net cost savings compared to the higher $2,477 million annual cost o

these 14 industrial applications (see Column I of Exhibit 5C-1). 
Exhibit 5C-1 

Estimate of Annual Materials Cost Savings Benefit of CCR Generated by the Electric Utility Industry for Beneficial Use in I

A B C D E F (C x E) G 

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) 

2

m

1 Construction concrete ingredient 

NAICS code 3273 

See 1A + 1B See 1A + 1B See 1A + 1B See 1A + 1B See 1A + 1B S

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 $

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 $

2 Construction structural fill for building 

foundations and embankments NAICS code 238910 

8.35 16.8% $1 $8.35 million $3 $

3 Construction wall board 

NAICS code 327420 

8.18 16.5% $0 to $8 $0 to $65.4 million $4.5 to $12 $

4 Waste stabilization (substitute for lime) 

NAICS code 5622 

2.84 5.7% $15 to $25 $42.6 to $71.0 million $66 $

5 Blasting grit 

NAICS code 212322 

1.63 3.3% Not reported Not reported Not reported N

6 Roofing granules 

NAICS code 324122 

Included with 

grit (row 5) 

Included with 

grit (row 5) 

Not reported Not estimated Not reported N

7 Minor uses (n=7)** 8.04 16.2% $3 to $20 $24.1 to $160.8 

million 

$5 to $83 $4

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 

$

(b

$1

2008 updated estimates = 62** * $177 million $

Explanatory notes: Source: Data in columns C, E, and G are from “Waste and Materials-Flow Benchmark Sector Report: Beneficial Use of Secondary Materials 

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/p

* Average price includes “free on board” (FOB) shipping and insurance costs paid by the supplier from the point of manufacture to a specifie** Minor uses include: (1) agricultural soil amendment for flue gas desulfurization gypsum, (2) road base foundation layer underlying pavemreclamation material as substitute for soil, (4) mineral filler in asphalt, (5) soil stabilizer, (6) snow and ice control substitute for sand, and (7) *** 2009 update estimated tonnage (Column C above) derived in Exhibit 5C-2 of this RIA; 2009:to2005 multiplier = 62.09/49.61 = 1.25. 

**** “Best estimate” in Column F based on sum of coal-fired electric plant CCR “byproduct sales revenues” from the DOE-EIA F767_PLA

 “Best estimate” in Columns H and I derived by numerical interpolation of the ranges displayed based on the proportionate best estimate 
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 1,859,12Actual = 2003 46,384,405 +1.9% 38% Observations 8 Actual = 2004 49,089,818 +5.8% 40% CoefficienActual = 2005 49,612,541 +1.1% 40% Intercept 39,784,05Actual = 2006 54,203,170 +9.3% 43% X Variable 2,867,59Actual = 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

** “Beneficial use” 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 

30,000,00035,000,00040,000,00045,000,00050,000,00055,000,00060,000,00065,000,000

2001 2002 2003 2004 2005 2006 2007 2008 20

Year

ACAA actual data Trendline
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 

Item State 

2004 CCR 

generation 

(short tons) 

20

ben

(sh

31 NH 141,000 32 NJ 600,000 33 NM 3,668,000 34 NV 825,000 35 NY 1,379,000 36 OH 6,980,000 37 OK 1,277,000 38 OR 95,000 39 PA 9,545,000 40 RI 0 41 SC 2,172,000 42 SD 105,000 43 TN 3,803,000 44 TX 12,943,000 45 UT 2,341,000 46 VA 2,442,000 47 VT 0 48 WA 2,301,000 49 WI 1,437,000 50 WV 7,220,000 51 WY 2,106,000 

 Totals = 129,001,000 

Notes: * Source: DOE & EPA, “Coal Combustion WLandfills and Surface Impoundments 1994-22006, page 5 (Table 1) at: http://www.ead.anl.gov/pub/doc/coal_waste_

In comparison, the ACAA reports that a 5% 122,465,119 tons CCR was generated in 200
• 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 

because mine-filling is not covered in the proposed rule.135 As displayed in Exhibit 5C-4 below, subtracting 2.3% of 

beneficial use category decreased the baseline CCR beneficial use from 49.6 million tons to 48.5 million tons (relativ

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 

of two of the 14 CCR beneficial use industrial applications (i.e., concrete and wallboard) there are 12 environmental bannual magnitudes estimated below in Exhibit 5C-5. This estimate of environmental benefits is based on only 47% (

the 49.62 million tons for the 2005 CCR beneficial use market as reported in that 2008 study. Thus, these estimates m

environmental benefits of CCR beneficial uses. These net benefits are not additive to the economic benefits, but enco

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 “Waste and Materials-Flow Benchmark Sector Report: Beneficial Use of Secondary Materials – Coal Combustion 

Industrial Economics Inc for the EPA Office of Solid Waste, 12 Feb 2008, 95 pages at http://www.epa.gov/osw/partnerships/c2p2/pubs/benu
To avoid double-counting of economic and social benefits, EPA evaluated the monetization of the energy, water, and impacts for any such double counting. Based on this evaluation, this RIA concludes that each of the individual mone

impacts are fully additive and do not double count benefits, with one exception regarding partial overlap between enevalue of avoided SOx air emissions. For SOx, where there exists a cap and trade permit program, firms must pay to e

SOx emissions avoided from beneficially using CCR is from the energy sector. Under the presumption that the marg

equal the value of marginal damages, the value of the portion of SOx emissions from the energy sector will be reflectsavings. The portion of avoided SOx emissions that comes from sectors other than energy is not reflected in energy c

should be retained. However, separately adding a value for reduced SOx emissions likely represents some amount o

Unlike the SOx permit program, most regulation of NOx and particulate matter (PM) does not require firms to purcha

Thus there is little to no overlap between the external costs of these air pollutants and energy costs. In addition, aside programs, GHG damages are not currently regulated and would not be reflected in the market price for energy. Thusparticulates and GHG reductions are fully additive to private energy cost savings. Furthermore, for water use, the onthe direct cost savings, and because the water savings in these cases are not associated with energy production, these 

captured elsewhere. Reduced water use in the production process is a real cost savings that should be a component oTherefore, this RIA concludes that there is only a partial double counting between energy cost savings and the saving

SOx emissions. No other beneficial use benefits categories are affected by this double counting issue. Thus, Exhibit 

subtracted the $1,491 million benefits attributable to SOx reductions from the environmental benefits estimate, result

estimate of $22,980 million per year, or $474 per ton average lifecycle benefit, assigning zero values to tonnage othwallboard. In addition to baseline lifecycle benefits, there are an estimated $2,927 million per year in baseline avoidto the electric utility industry (i.e., (49.61 million tons CCR beneficial use in 2005) x ($59 per ton average baseline diExhibit 3L of this RIA)), which constitutes a total of $25,907 million per year (relative to 2005 CCR beneficial use 

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$)** 

A. Resource Consumption Savings 1. Energy consumption 158 trillion BTU energy savings $0.00003093 per BT2. Water consumption 32.1 billion gallons water savings $0.0025259 per gall Subtotal (1+B. Air Pollution Savings 3. GHG - greenhouse gases 11.5 million metric tons CO2 equivalent emissions avoided $20.76 per metric to4. CO – carbon monoxide 9,200 metric tons emissions avoided Not estimated 5. NOx – nitrous oxides 30,400 metric tons emissions avoided $10,255 per metric t
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$)** 

6. SOx – sulfur oxides 23,900 metric tons emissions avoided $62,375 per metric t7. PM – particulate matter 9,704 metric tons emissions avoided $486,312 per metric 8. Particles non-specified 26,200 metric tons emissions avoided $486,312 per metric 9. Hg - mercury 0.584 metric tons emissions avoided Not estimated 10. Pb - lead 0.656 metric tons emissions avoided Not estimated 

Subtotal (3 to 

Subtotal air pollution savings excluding SOx & excluding mine-filling u

C. Other Environmental Savings 11. Waterborne wastes 2,446 short tons waste generation avoided (SM + BOD + COD + Cu + Hg + Pb + Se) Not estimated 12. Solid waste 27,991 short tons waste generation avoided Not estimated 

Total (1 to 1

Total annual lifecycle benefits (excluding SOx & excluding mine-filling u

Notes: * Physical quantity of environmental benefits are based on only two of the 14 beneficial use industrial applications (i.e., 15.0 million tons 

concrete, plus 8.2 million tons per year FGD CCR used in wallboard). These estimates are from Exhibit 5-3 (page 5-6) of “Waste and Ma

Sector Report: Beneficial Use of Secondary Materials – Coal Combustion Products,” prepared by Industrial Economics Inc for the EPA O2008; available at http://www.epa.gov/osw/partnerships/c2p2/pubs/benuse07.pdf. This 2008 reference report does not provide environme

other 12 beneficial use industrial applications. ** Unit monetary values applied for monetization are from the following sources: • Row 1 & Row 2: 2007 values from Exhibit 5-3 (page 5-6) of the Industrial Economics Inc reference report. Unit values updated for t

using NASA’s Gross Domestic Product Deflator Inflation Calculator at http://cost.jsc.nasa.gov/inflateGDP.html

• 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 E

“Proposed Rulemaking to Establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy SVolume 74, No. 186, 28 Sept 2009. The value applied in this RIA is the $19.50 per ton median value from the $5 to $56 per ton rangcolumn in that source. Furthermore, this RIA updated the 2007$ median value from 2007 to 2009 dollars using the NASA Gross DomInflation Calculator at http://cost.jsc.nasa.gov/inflateGDP.html. EPA is aware that final SCC values were published on March 9, 2010 

Department of Energy final rule. EPA intends to use the final SCC values for the CCR final rule RIA. The final SCC values are publEnergy, Energy Efficiency & Renewable Energy Building Technologies Program, "Small Electric Motors Final Rule Technical Suppo

Regulatory Impact Analysis", March 9, 2010 at http://www1.eere.energy.gov/buildings/appliance_standards/commercial/sem_finalrul

• Rows 4-10: Unit values from the report “The Influence of Location, Source, and Emission Type in Estimates of the Human Health Be

Air Pollution” by Neal Fann, Charles Fulcher and Bryan Hubbell, in Air Quality, Atmosphere & Health, Volume 2, No.3, Sept 2009, 

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 

• Rows 12-13: Waterborne waste and solid waste generation avoided benefits were not monetized in the 2008 Industrial Economics Inc
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 udo not face increased disposal costs associated with Subtitle C or D regulation of disposed CCR. The increased costs 

result of their regulation under RCRA subtitle C will create a strong economic and regulatory incentive for increased In fact, EPA concludes that the increased costs of disposal of CCR under subtitle C of RCRA, but not the beneficial u

increase their usage in non-regulated beneficial uses, simply as a result of the economics of supply and demand. The availability of a low-cost, functionally equivalent or often superior substitute for other raw materials - will continue to increasingly desirable product. Furthermore, it has been EPA’s experience in the RCRA hazardous waste regulations 

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 waste” will impose a “stigma” on CCR beneficial use which will significantly curtail these uses. In their view, even only the disposal of CCR in landfills or surface impoundments as hazardous waste, but retains the Bevill exemption fhave this effect. Also, the states particularly have argued that, by operation of state law, the beneficial use of CCR wmany 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 – i.e., an induced increase (Scenario #1) and an (Scenario #2) -- in future CCR beneficial use, and to explain the basis for this RIA selecting the former (Scenario #1) 

• 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 are used and recycled, suggests that a “hazardous waste” designation of industrial secondary materials and wastes, dosignificant barrier to its beneficial use (e.g., recycling), and that non-regulated uses generally increase as the costs of increase. As summarized below, EPA’s experience has shown that the economic incentive of a high disposal cost ha

hypothetical stigma effect in case after case of hazardous waste recycling. Six examples listed below illustrate the po“hazardous waste” designation does not stand in the way of a material’s (or waste’s) subsequent industrial recycling ointermediate material: 

1. Electric arc furnace dust: RCRA hazardous waste (waste code = K061), and yet it is a highly recycled materi

2001 and 2007, approximately 42% to 51% of K061 was recycled as evidenced by Biennial Reporting System currently and historically, K061 has been used as an ingredient in fertilizer, an input in making steel, and in th

products, including pharmaceutical materials. Slag from the smelting of K061 is in high demand for use in roof slag is regulated under Pennsylvania’s beneficial use program, despite the fact that it is derived from a listefact, there is little doubt that, without its regulation as a hazardous waste, a significantly greater amount of K0

from recycling to disposal in non-hazardous landfills. 
2. Electroplating wastewater sludge: Listed hazardous waste (F006) that is recycled for its copper, zinc, and nic

commercial market. In 2007, approximately 35% of F006 material was recycled according to BRS data. Theno way stigmatized in the marketplace. 

3. Chat: Superfund cleanup waste with lead contamination is used in road construction in Oklahoma and the sur

case, the very waste that has triggered an expensive Superfund cleanup is successfully offered in the marketpl

road building. The alternative costs of disposal in this case are a significant driver in the beneficial use of this 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. 

recycled is subject to a separate set of standards under subtitle C (and is not identified as a hazardous waste), “home do-it-yourselfers from collecting used oil, or automotive shops from accepting it and sending it on for re

oil may be re-refined, reused, or used as a fuel in boilers, often at the site where it is collected. One large com

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 wid

can be classified as “hazardous” materials, and many come with warning labels. For example, motor oil comes with 

would be a characteristic hazardous waste if disposed of, as would many common drain cleaners and household cleanmonitors for TVs and computers, as well as many fluorescent lamps are all hazardous wastes if disposed of. Fluorescpotentially hazardous when disposed of because of mercury. Mercury is an indispensable resource, and virtually all o

lamps and other uses in the U.S. is derived from discarded mercury or mercury products – that is, from hazardous waunlikely as nicotine gum or dental amalgam would be a hazardous waste when disposed of. Consumers are generally 

products, and their regulatory status does not discourage their use. 

• Differing Views About Prospect of Future “Stigma” 

Stakeholders have also expressed the concern that standards-setting organizations might prohibit the use of CCR in sp

materials in their voluntary standards. Recently, the American Standards and Testing Materials (ASTM) Internationasubcommittee, C09.24, in a December 23, 2009 letter to EPA indicated that ASTM would remove fly ash from the pr

concrete standard if EPA determined that CCR were a hazardous waste. However, ASTM standards are developed th

process, and current standards cover the use of numerous hazardous materials in construction and other activities. Foprovides specifications for the reuse of solvents and thus, by implication, does not appear to take issue with the use o

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 S

ASTM D5396 - 04 Standard Specification for Reclaimed Perchloroethylene. 
Others take a different view on how standard-setting organizations will react. Most notably, a US Green Building Co

been quoted in the New York Times as saying that LEED incentives for using fly ash in concrete would remain in pla

hazardous determination. If the Green Building Council (along with EPA) continues to recognize fly ash as an enviro

substitute for Portland cement, EPA believes that the use of this material is unlikely to decrease solely because of “sti

In addition, Congress directed government agencies to increase their purchase of recycled-content products. Specific

RCRA requires EPA to designate products that can be made with recovered materials and to recommend practices foOnce a product is designated, “procuring agencies” 138 are required to purchase it with the highest recovered material 

if they spend more than $10,000 a year on that item. EPA’s federal Comprehensive Procurement Guidelines (CPG), in cement for federally funded projects, would remain in place. Thus, any federal, state, or local agency carrying out 

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 

programs, and therefore that, if EPA lists CCR as a hazardous waste (even if only for disposal), their use would be prEPA has reviewed the regulations of 10 states with the highest consumption of fly ash and/or cement and concluded tnot allow the use of hazardous waste in their beneficial use programs, CCR that are beneficially reused will remain B

or in some cases, would not be considered wastes at all and thus, the continued use of CCR under these programs shoproposed CCR rule. For EPA’s summary of 10 state government CCR beneficial use regulations, see Appendix K12

this RIA presents the increased future CCR beneficial use (Scenario #1) as the “base case.” However, this RIA moneinduced increase and induced “stigma” 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 industry. The amount of CCR is likely to increase proportionally, as utilities comply with new Clean Air Act require

proportional increase, this RIA relied on the EIA future forecast for coal burned by the electric utility industry.139 As 

6 below, the EIA data extends out to the year 2035. However, to remain consistent with the other cost and benefit est

this trend out to the year 2061 based on regression-fit extrapolation using the following first-order regression of coal 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 fun139 Source: Based on 2007 to 2035 annual short tons coal consumption by electric power sector forecast data from the Energy Information Ad

Year Reference Case Tables (2008-2035): Table 15 Coal Supply, Disposition, and Prices” from the report “Annual Energy Outlook 2010 Ea2009 at http://www.eia.doe.gov/oiaf/aeo. The EIA report presents a midterm projection and analysis of US energy supply, demand, and pric

EIA’s National Energy Modeling System. Further information on the EIA’s projections is available at 
y x = β 0 + β1

Where: y = Tons coal burned at time = x β0 = Tons coal burned at time = 0 

β1 = Additional tons coal burned each year, on average 

x = Time elapsed (years) 

Running the regression, calculated a β0 (or intercept) of 1,001,902,312; a β1 (or slope) of 6,082,277; and an R-squared 

regression was used to extrapolate the EIA projection out to the year 2061 as displayed in Exhibit 5C-7 and as graph

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 2020 13 2021 14 2022 15 2023 16 2024 17 2025 18 2026 19 2027 20 2028 21 2029 22 2030 23 2031 24 2032 25 2033 26 2034 27 2035 28 
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 Proj

Year Tons Burned Year 

2021 1,087,054,189 2049 2022 1,093,136,466 2050 2023 1,099,218,743 2051 2024 1,105,301,019 2052 2025 1,111,383,296 2053 2026 1,117,465,573 2054 2027 1,123,547,850 2055 2028 1,129,630,127 2056 2029 1,135,712,404 2057 2030 1,141,794,681 2058 2031 1,147,876,958 2059 2032 1,153,959,235 2060 2033 1,160,041,511 2061 2034 1,166,123,788 Total 
Exhibit 5C-8 

Extending EIA Projections

900,000,000950,000,000

1,000,000,0001,050,000,0001,100,000,0001,150,000,0001,200,000,0001,250,000,0001,300,000,0001,350,000,0001,400,000,000

2007 2012 2017 2022 2027 2032 2037 2042 2047 2052 

Year

Coal Burned (Tons)

EIA Projection EPA Regression
Based on the most recent CCR beneficial use data from ACAA, EPA estimated the average tons of CCR generated fo

by electric utility plants. For this calculation, this RIA only used the most recent data year (2008) to estimate a conve

time, the quantities of CCR generated per ton of coal combusted has steadily increased. Thus an average of recent yetrend. The steady increase over time is due to tightening of industrial air pollution regulations. This trend would like

as further facilities undergo new source review, or implement new Clean Air Act requirements under upcoming EPA Interstate Rule (CAIR) and the Clean Air Mercury Rule (CAMR). Thus, the future annual tonnages of CCR estimate

under-estimates. Dividing the 2008 tons of CCR generated (136 million tons) by the 2008 tons of coal burned by the 

(1,042 million tons), EPA produced a CCR-to-coal relationship factor of 0.131. Applying this factor to the extrapolaprojection 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 trend in the ratio of tons CCR generated to the tons coal combustion. For example, in year 2035 the constant ratio pr

value of 153 million tons CCR generated whereas the increasing ratio projection in Appendix K5 yields a value of 19generated. While the exact magnitude of such an increase is uncertain, there would be at least some increase as a resupollution controls. These include future changes due to EPA’s New Source Review (NSR), EPA’s Clean Air InterstaEPA’s Clean Air Mercury Rule (CAMR).
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 RCR

disposal (i.e., future baseline CCR beneficial use). Exhibit 5C-10 below displays the recent (i.e., 2001 to 2008) trend 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 used before year 2061. Furthermore, a linear extrapolation for beneficial use would not be appropriate because as mo

it would likely become increasingly difficult to use the remaining CCR due to saturation of local markets, competitiogenerators, and other factors, depending on overall macro-economic factors. Thus, for purpose of extrapolation to th

analysis (2012 to 2061), this RIA instead modeled the recent trend data as an asymptotic, exponential function of the 

*( )

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 
Beneficial uses of CCR have been consistently growing in the recent past. Since the percent of CCR beneficially use

sought to characterize that trend so that the future percent beneficially used could be applied to the future tons of CCR2001 to 2008 indicate that this trend was increasing. After running several regressions, EPA disposed of the typical treasons. A first-order (linear) trend line was abandoned because it would have led to beneficial use above 100% well the analysis. Higher order regressions led to oddities where beneficial use would trend away from 100% at some poin

fits were ruled out, EPA assumed that CCR beneficial use would not exceed 100% of CCR generated.140 Instead, it w

more and more difficult to use CCR as a higher percent went to beneficial uses, because of market limitations. Thus, 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 program

residual sum of squares between the actual and projected percent of CCR beneficial use by changing the regression eq

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 fu

projection as measured on a percentage basis relative to CCR generation were estimated, as displayed in Exhibit 5C-below. The percentage of CCR beneficially used under the baseline (i.e., without RCRA regulation) is expected to grnever reach 100% of CCR generation. By 2061 at the end of the 50-year period-of-analysis, 88% of CCR would be bprojection. While this is a relatively high number, current experiences in at least one US state and in at least 16 other European countries + Japan), already demonstrate that very high CCR beneficial use rates of 90% and above are achi

1. Wisconsin: Several companies are developing technologies to convert CCR into bricks used in construction, 

was recently commercialized in Wisconsin.141 Some of these technologies have the potential for using 100% 

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 m

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 i

applications, 6 civil engineering applications, 3 construction applications, 2 agriculture/forestry/fisheries applother 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 

which could underestimate future potential growth of CCR beneficial use. For example, one electric utility company reported a 106% CCR 

its four electricity plants because it recovered CCR that it had previously disposed. 

141 Source: “CalStar Gives Sneak Peek of Low-Carbon Brick Factory,” Cleantech Group, 27 Oct 2009 at http://cleantech.com/news/5217/cal142 Source: Europe’s 2007 CCR beneficial use rate is reported by ECOBA (European Coal Combustion Products Association) which was fou

energy producers to deal with matters related to the usage of construction raw materials from coal. As of 2009, membership in ECOBA conassociations from 15 countries in Europe, all generators of electricity and heat. ECOBA members represent over 86 % of total CCR generaticountries. ECOBA’s 15 member countries are Belgium, Denmark, Finland, France, Germany, Greece, Ireland, Italy, Netherlands, Poland, P

Spain, and United Kingdom. ECOBA’s 2007 CCR beneficial use rate is reported in “Production and Utilisation of CCPs in 2007 in Europe 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 “Status of Coal Ash 

http://www.jcoal.or.jp/coaltech_en/coalash/ash01e.html
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 % Beneficia

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 “Breakdown of Fields for the Effective Use of Coal AOverview Environmental Protection Technologies (Technologies to Effectively Use Coal Ash): 5C1. Coal Ash Generation Process and Applhttp://www.brain-c-jcoal.info/cctinjapan-files/english/2_5C1.pdf 
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 

Year

Beneficial Use (%)

Actual Projected
Applying the percent of CCR beneficially used in each year to the quantities of CCR shown above, the following futubeneficially used CCR may be expected as displayed below in Exhibit 5C-13. The monetized value of this future ba

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 Be

2012 69,234,181 2025 96,599,301 2038 119,713,602 2051 139,2013 71,516,427 2026 98,514,244 2039 121,345,430 2052 140,2014 73,767,022 2027 100,404,645 2040 122,958,473 2053 142,2015 75,986,563 2028 102,270,993 2041 124,553,122 2054 143,2016 78,175,638 2029 104,113,770 2042 126,129,762 2055 145,2017 80,334,827 2030 105,933,448 2043 127,688,769 2056 146,2018 82,464,703 2031 107,730,494 2044 129,230,513 2057 147,2019 84,565,827 2032 109,505,366 2045 130,755,358 2058 149,2020 86,638,755 2033 111,258,513 2046 132,263,659 2059 150,2021 88,684,034 2034 112,990,378 2047 133,755,767 2060 151,2022 90,702,202 2035 114,701,396 2048 135,232,025 2061 153,2023 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 alternafuture 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 
Increases due to increased disposal costs were estimated first and constitute the “base case” of this RIA. By increasin

utility plants face an “avoided disposal cost incentive” to ship their CCR farther for beneficial uses by other industriewilling to pay more transportation costs to avoid the higher disposal costs. Thus, RCRA regulation of CCR disposal markets at farther transport distances, or increase purchases by existing markets. The effect of this stimulus would be 

beneficial use. The concept of “avoided disposal cost incentive” is recognized and defined by the American Coal Ash its website as follows: 

“If a [coal-fired electric utility] plant markets its [CCR] into commercial applications, then disposal of this [Crequired. Not only is a revenue stream created for the [coal-fired electricity plant] but also the need to dispoavoided. As discussed above, disposal is not just the transportation and placement of [CCR] in a disposal sit

future space is a concern. If [CCR is] marketed, then the need to develop future [CCR disposal] sites (includacquisition, permitting, design and construction costs) is avoided .... It is not uncommon for a company to heof transportation or placement at construction sites by providing the contractor or trucking firm a payment of example, if the cost of disposal at a plant is normally four dollars a ton, then the company may arrange a paydollars or less to the contractors to cover transportation and placement costs. The difference between the ampayment and the cost of disposal is also referred to as “avoided disposal costs.” Source: ACAA Frequently A

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 “hazardous waste” approach would have a “stigmreducing their use. That is, due to the label of “hazardous waste,” some purchasers of CCR might opt to turn down th

expensive substitutes in fear that the CCR might either harm their sales or create liability, and generators might be relmaterial to users because of liability concerns. The final alternative, that beneficial use quantities remain the same, re

benefits for the Subtitle C approach because it is assumed that the baseline trend plays out the same as it would absen

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 historicadata.144 ACAA data on the beneficial use was modified to remove the use of CCR in minefilling applications becaus

not address minefilling operations. Excluding 100% of the ACAA reported quantity of CCR used in minefilling resu

million tons per year in the amount beneficially used. As a result, the 2005 quantity of beneficial use relied upon for 

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) “Coal Combustion Products -- Production 

http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=3 
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 woulincrease of 28% in CCR beneficial uses. This growth estimate is a generalized, aggregate estimate across all 15 exist

markets. Due to a lack of available data (i.e., market location, elasticity, cross-elasticity, etc.), this estimate does not 

economic supply or economic demand conditions in any single market or for any particular beneficial use, relative to estimate. However, key uses, such as use of fly ash as a Portland cement replacement, have great opportunity for incin the initial year. For example, if fly ash use in concrete increased to a 30% replacement rate for Portland cement (a 

replacement rate, consistent with current specifications), fly ash usage could increase by more than 100% from the 14 annually at current replacement rates of 10% to 12%. One of the main barriers to this increase usage is transportation 

not have specific data on this market, this RIA does not specifically quantify it; however, it is exactly the type of use costs could foster. The method presented below may be characterized as a "Raw Material Cost Method" which represents the 1st stage o

materials flow lifecycle (MFL) through the economy. This 4-stage MFL conceptual framework has been integrated isoftware systems145 used by government agencies and the private sector, and consists of the following four material f

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 cond

current conditions without RCRA regulation of CCR disposal. The second condition (Subtitle C) represents future coregulation for CCR disposed by electric utilities. The economic mechanism in this estimation method, which affects different raw material acquisition costs under the is the “avoided disposal cost incentive” described above. In other words, it is the avoided disposal cost under RCRA 

the industry’s baseline disposal cost. This difference in cost is an incremental cost relative to baseline. From an econ

represents an incremental economic incentive to electric utility plants to reduce or eliminate CCR disposal, thereby reregulatory compliance costs by increasing their future annual supply of CCR to beneficial use markets. This “avoide

induced by RCRA regulation has already been anticipated in 2009 by at least one CCR beneficial use industry (bold f

145 Example cost modeling/estimation software systems using this 4-stage framework are 1. FAST, 2. EE Energy/ Environment Life-Cycle A

Accounting Method, and 4. TEAM (Tools for Environmental Analysis and Mangement); source: “Table 3-1. Overview of Life-Cycle Stages 

Software Systems and Tools” at http://www.p2pays.org/ref/01/00047/00047e.htm 
“Using [coal] fly ash in building materials is nothing new, as it’s already incorporated in products including 

and asphalt concrete. However, it’s estimated that 65 percent of fly ash from coal-fired power plants worldwilandfills, with the U.S. reporting a slightly lower 57 percent, according to the American Coal Ash Associationkey to CalStar’s products is that they offer the same performance as aesthetics as traditional bricks, but withoCurrently, the cost to buy a ton of fly ash in the U.S. ranges from about $5 to $30, but that could change as flfaces tighter government restrictions, he said. “The cost to send fly ash to landfills will go up, and utilities w

finding the most beneficial use,” Kane said.”146

The baseline average “raw material acquisition cost” is $94.50/ton, consisting of CCR price, CCR disposal cost, and 

1. CCR price: Price paid to electric utility plants by beneficial use industries for the purchase of CCR. ACAA i

beneficial use markets involving the beneficial use of CCR, many of which involve the construction industry.

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 “av

incentive” in the sense that this is an “avoided cost” to the electric utility industry for CCR tonnages beneficia

industries. A unitized “total cost” ($ per ton) for CCR disposal consisting of both a 50-year amortized capital 

units plus a 50-year amortized O&M costs for CCR disposal is used to monetize this cost factor.149 The avera

cost is $59/ton (source: Exhibit 3L). This is additive to the “CCR price” element because it represents a subs

3. CCR transport cost: Average one-way CCR transport distance between electric utility plants and their CCR b

industries. This method does not explicitly distinguish whether the transport cost is paid by the electric utility 

beneficial use industries.150 Average CCR transport cost from electric utility plants to beneficial use sites is e

($0.26/mile/ton)151 x (125 miles)152 = $32.50/ton. 

146 Source: Cleantech Group, “CalStar Gives Sneak Peek of Low-Carbon Brick Factory,” 29 Oct 2009 at http://cleantech.com/news/5217/cal147 ACAA lists 15 beneficial use markets: concrete, cement, flowable fill, structural fill/embankments, road base/sub-base, soil modification, 

snow/ice control, blasting grit/roofing granules, mining applications, gypsum panel products, waste stabilization/solidification, agriculture, c

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 rang149 Although in the short-run (< 3 years), marginal business decisions may be made relative to short-term O&M costs, long-term (> 3 years) b

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 “FOB” prices which may include some portion 

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 “Estimation of the Marginal Greenhouse G

Beneficial Use of Fly Ash as a Substitute for Portland Cement in Ready-Mix Concrete Production,” EPA Office of Resource Conservation a

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 “Report to Congress: S

of Recovered Mineral Components in Federal Funded Projects Involving Procurement of Cement or Concrete to Address the Safe, AccountaTransportation, Equity Act: A Legacy for Uses by the EPA, the Department of Transportation (DOT) and the Department of Energy (DOE),” available at http://www.epa.gov/waste/conserve/tools/cpg/products/cement2.htm. 
In comparison to these baseline “raw materials acquisition cost” elements, CCR disposal costs are estimated to be $8option (source: Exhibit 4K). While this represents a 44% increase ($26/ton) over the baseline disposal cost of $59/to

price and the transportation cost elements. Factoring these components in, the $26/ton increase represents a 28% incr

baseline raw material cost of $94.50/ton. This RIA applies this 28% growth factor to represent demand elasticity153 a

+0.64 with respect to the CCR “avoided disposal cost incentive” factor (i.e., +28%/+44%). +1.00 with respect to total “raw material acquisition cost” consisting of all three cost factors included (i.e., +2

This RIA applies the elasticity estimate of 1.0 in reference to the “raw material acquisition cost” to represent the potebeneficial use by 28% over the baseline under the Subtitle C option. The other regulatory options are proportionately comparison to historical annual percentage changes in CCR beneficial use tonnages, this 28% increase is a reasonable 

between the -22.6% decrease and +55.2% increase min-max range (annual mean = +8.2% increase) over the 43 year 

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 % ch

CCR beneficia

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 

change in quantity supplied) / (% change in its price)). Similarly, the elasticity of demand indicates the responsiveness of the quantity of maservice 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_C
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 % ch

CCR beneficia

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% 
This is a limiting analysis because it does not include other developments that may be expected increasingly to push C

1. Aspects of the proposed CCR rule: This analysis does not take into account that some RCRA regulatory optio

require electricity plants to move to dry management of CCR, either through changes to air pollution control sdrying 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 produc

for example, involving the use of CCR in brick construction.155 An increased “avoided disposal cost incentiv

to such new beneficial use technologies, applications, and products. 

• Comparison of “Raw Materials Acquisition Cost Method” to “Travel Cost Method” 

The method applied above involved three cost components of the “raw material acquisition cost,” not just in relation component, which is relatively narrower approach that can be called a “Transportation Cost Method.” Compared to material acquisition cost method provides a smaller estimate of effect because the incremental cost is evaluated relatithereby translating numerically into a smaller percentage change, rather than relative to only one cost factor which worelatively larger percentage change. This methodological difference may be illustrated by using the calculation numb

the transportation cost factor. Using a simplistic transportation distance model which uses the CCR disposal unit cos

the average circular radius of a CCR transportation market between electricity utility plant suppliers of CCR and theicustomers, the increase in transport distance would be calculated as follows (relative to the 2005 49.6 million tons CC

reported by the ACAA): 

• 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 

million/year transport cost 

• Hypothetical new transportation cost (with rule) 

Transport subsidy equivalency = ($85/ton avoided disposal cost under rule) – ($59/ton avoided disposal cost 

subsidy equivalency (49.6 million tons/year beneficial use) x ($26/ton subsidy equivalency) = $1,290 million per year subsidy eq

• Hypothetical new transport distance: 

[($1,612 million/year) + ($1,290 million/year)] / (49.6 million tons per year beneficial use) / ($0.26/mile/tonPercentage increase in transport distance: [(225 miles) – (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 co

in Wisconsin. Some of these technologies have the potential for using 100% CCR (fly ash) in brick production, as opposed to the convention

replacing Portland cement in concrete. 
• Hypothetical expansion of CCR customer delivery area: 

Baseline customer area @125 miles radial transport distance = (3.1415 x (125 miles)^2) = 49,100 squa

Expanded customer area @225 miles radial transport distance = (3.1415 x (225 miles)^2) = 159,000 squIncremental increase in customer area = (159,000 – 49,100 sq. miles) / (49,100 sq.miles) = 124% increa

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 hazardodesignation is only applicable to those CCR that are disposed of) would create a “stigma” that would reduce or curtaibeneficial use of CCR. This RIA presents an alternative stigma effect scenario in an effort to evaluate what counterv

“stigma” may have on the increased beneficial use of CCR estimated in this RIA above. This potential reduction scen

potential impacts in three categories of beneficial CCR usage (uses covered in the CPGs, consolidated uses, and uncodocumentation of the calculations discussed in this section, see Appendix K13. 

• “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 ComprGuidelines (CPGs), which require procuring agencies that spend more than $10,000 a year on an item to buy productmaterials. Procuring agencies are federal, state, and local agencies, and their contractors, that use appropriated federa

county agency spends more than $10,000 a year on an EPA-designated item and part of that money is from appropriaagency must purchase that item made from recovered materials.156 As such, if there were any impacts due to stigma, 

markets for these uses are less likely to be affected by a hazardous waste label for CCR. CCR categories currently coinclude 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 20had swelled to 35.4% by Nov. 2009 (likely in direct relationship to the current state of the economy and current feder

Similarly, U.S. EPA (2008d) estimates that for concrete projects, the cement demand attributable to federal concrete papproximately 20% of the annual total demand. EPA then apportioned the amounts of CCR usage into a public const

construction split. Based on the Census Bureau and EPA data,157 EPA established a 25% / 75% split of the totals for 

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 

time; or items do not meet the agency's reasonable performance specifications. 

157 Source: EPA “Report to Congress: Study on Increasing the Usage of Recovered Mineral Components in Federal Funded Projects Involvin

Concrete to Address the Safe, Accountable, Flexible, Efficient Transportation, Equity Act: A Legacy for Uses by the EPA, the Department oDepartment of Energy (DOE),” EPA530-R-08-007, June 3, 2008 at: http://www.epa.gov/waste/conserve/tools/cpg/products/cement2.htm
Given that the public procurement of these products should continue because of their CPG designation, this RIA assunegative impact on the public portion of CCR usage. That is, the demand for CPG products made from CCR will be for the public portion of the construction market. However, this RIA assumes a 50% reduction of total private uses.15

estimated 6.8 million tons per year reduction in CCR use for this category of beneficial uses. 

• “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 im

in non-CPG, consolidated uses. These CCR categories include blended cement/raw feed for clinker, mineral filler in 

products, waste stabilization/solidification, and miscellaneous/other. In the case of CCR used in blended cement, mingypsum for wallboard, and miscellaneous/other applications, this RIA assumed that 50% of these uses will be reduce

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 neguse, the CCR are already being used in a waste management context. The CCR are used in secure landfills to immob

hazardous than the CCR themselves. Therefore, this RIA projects no reduction in the future annual tonnage of CCR u

• “Stigma” for Unconsolidated Uses 

In addition to the consolidated uses of CCR discussed above, CCR can be employed in unconsolidated uses. For som

products may be more similar to the disposed material proposed to be regulated. In addition, they have typically not within a product. As a result, stigma concerns may be more plausible. Markets that involve unconsolidated uses of Cfill/embankments, road base/sub-base, soil modification/stabilization, snow/ice control, aggregate, agriculture, and mpurpose of the sensitivity analysis, this RIA assumed a potential reduction of 80%.159 This results in an additional 11

reduction of beneficially used CCR. By adding the 6.8 million tons from CPG consolidated uses, to the 6.8 million to

consolidated uses, plus the 11.1 million tons from unconsolidated uses, this RIA estimates that a severe stigma effect 

reduction of beneficial use. 

158 The 50% reduction is considered a worst-case assumption because these materials provide significant value at competitive costs – for exa

ash typically performs better than non-CCR concrete, and is likely to retain favorable treatment under Leadership in Energy and Environmen

addition, academic studies of “stigma” associated with products rarely leads to decreased usage to this extent. 

159 EPA has assumed this high “stigma” effect because a number of the uses may appear close to the disposal scenario, e.g., structural fills. A

that CCR in unconsolidated uses may present risks, if used in the wrong conditions. (Indeed, EPA takes comment on unconsolidated uses in proposed rule due to the increased potential for risks.) Some of these uses are likely to be particularly sensitive to public concerns and liabiliagricultural 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 preasonable to assume it will be significant for unconsolidated uses. Even for the purposes of a worst-case sensitivity analysis, however, EPA 

success of many of these uses in states with rigorous beneficial use programs, “stigma” will not completely eliminate such uses; therefore, it 

80%. 
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 

makes sense when there is ample room for growth. But as the market becomes more and more saturated, it is less and elasticity would apply. Instead, the elasticity is likely to decrease with increasing saturation. To account for this, the was set to 28% of either the existing beneficial use tonnage, or to 28% of the remaining CCR tonnage, whichever wa

once beneficial use was greater than 50% of total CCR, the increase would be constrained to 28% of what was left ovaccounted for. EPA also accounted for the fact that the price change would not fully affect the market until the rule (

had been phased in. Full implementation was assumed to occur by 2019. However, industry would undoubtedly like

these increased costs as soon as a final rule was passed, and therefore the beneficial use increases were assumed to lin2019. 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 odiscussed in Step 4 above, there is also the possibility that there would be a stigma associated with the “hazardous wabeneficial use of CCR would be 49% of the baseline due to stigma. Since the maximum CCR beneficially used is lesthe constraint imposed on the straight 28% increase would not be necessary. Thus, once the full 51% decrease and 28

for, the future CCR beneficial use annual tonnages are calculated as displayed below in Exhibit 5C-15. 
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 c

an increase of 28% above the baseline estimate. However, as the market becomes more and more saturated, it will likincrease beneficial use. Thus, the increase is constrained to 28% of the remaining unused CCR. The elasticity colum

percent change in quantity for each percent change in price once this constraint has been accounted for. While the elainitially be 1.0, the effect of market saturation drives that elasticity towards zero over time as seen below. 
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 m

filling (tons) 

2012 134,764,862 53.08% 71,527,755 3.31% 2,293,574 2,241,198 2013 135,558,881 56.06% 75,999,399 6.27% 4,482,972 4,380,599 2014 136,352,901 58.92% 80,338,539 8.91% 6,571,517 6,421,451 2015 137,146,920 61.65% 84,549,013 11.27% 8,562,450 8,366,919 2016 137,940,940 64.26% 88,634,566 13.38% 10,458,928 10,220,089 2017 138,734,959 66.75% 92,598,855 15.27% 12,264,028 11,983,968 2018 139,528,979 69.12% 96,445,450 16.95% 13,980,748 13,661,485 2019 140,322,998 71.39% 100,177,835 18.46% 15,612,008 15,255,494 2020 141,117,018 72.20% 101,892,669 17.61% 15,253,914 14,905,577 2021 141,911,037 72.99% 103,587,595 16.81% 14,903,561 14,563,225 2022 142,705,057 73.76% 105,263,001 16.05% 14,560,799 14,228,291 2023 143,499,076 74.51% 106,919,270 15.35% 14,225,480 13,900,629 2024 144,293,096 75.23% 108,556,775 14.68% 13,897,458 13,580,097 2025 145,087,115 75.94% 110,175,889 14.05% 13,576,588 13,266,555 2026 145,881,135 76.62% 111,776,973 13.46% 13,262,729 12,959,864 2027 146,675,154 77.29% 113,360,387 12.90% 12,955,743 12,659,887 2028 147,469,174 77.93% 114,926,484 12.37% 12,655,491 12,366,492 2029 148,263,193 78.56% 116,475,608 11.87% 12,361,839 12,079,545 2030 149,057,213 79.17% 118,008,102 11.40% 12,074,654 11,798,919 2031 149,851,232 79.76% 119,524,301 10.95% 11,793,807 11,524,485 2032 150,645,252 80.34% 121,024,534 10.52% 11,519,168 11,256,118 2033 151,439,271 80.90% 122,509,126 10.11% 11,250,612 10,993,695 2034 152,233,291 81.44% 123,978,394 9.72% 10,988,015 10,737,095 2035 153,027,310 81.97% 125,432,652 9.36% 10,731,256 10,486,198 2036 153,821,330 82.48% 126,872,208 9.00% 10,480,214 10,240,889 2037 154,615,349 82.98% 128,297,364 8.67% 10,234,772 10,001,052 2038 155,409,369 83.46% 129,708,417 8.35% 9,994,815 9,766,574 2039 156,203,388 83.93% 131,105,658 8.04% 9,760,228 9,537,345 2040 156,997,408 84.39% 132,489,375 7.75% 9,530,902 9,313,255 2041 157,791,427 84.83% 133,859,848 7.47% 9,306,725 9,094,198 2042 158,585,447 85.26% 135,217,354 7.20% 9,087,592 8,880,069 2043 159,379,466 85.68% 136,562,164 6.95% 8,873,395 8,670,764 2044 160,173,486 86.09% 137,894,545 6.70% 8,664,032 8,466,182 2045 160,967,505 86.49% 139,214,759 6.47% 8,459,401 8,266,224 2046 161,761,525 86.87% 140,523,061 6.24% 8,259,402 8,070,792 2047 162,555,544 87.24% 141,819,704 6.03% 8,063,938 7,879,791 2048 163,349,564 87.61% 143,104,936 5.82% 7,872,911 7,693,126 2049 164,143,583 87.96% 144,378,997 5.62% 7,686,228 7,510,706 
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 m

filling (tons) 

2050 164,937,603 88.30% 145,642,128 5.43% 7,503,796 7,332,440 2051 165,731,622 88.63% 146,894,561 5.25% 7,325,524 7,158,239 2052 166,525,642 88.96% 148,136,525 5.07% 7,151,323 6,988,016 2053 167,319,661 89.27% 149,368,245 4.90% 6,981,106 6,821,687 2054 168,113,681 89.58% 150,589,942 4.74% 6,814,787 6,659,166 2055 168,907,700 89.87% 151,801,831 4.58% 6,652,282 6,500,372 2056 169,701,720 90.16% 153,004,125 4.43% 6,493,509 6,345,224 2057 170,495,739 90.44% 154,197,031 4.29% 6,338,387 6,193,644 2058 171,289,759 90.71% 155,380,753 4.15% 6,186,835 6,045,554 2059 172,083,778 90.98% 156,555,491 4.01% 6,038,778 5,900,878 2060 172,877,798 91.23% 157,721,441 3.88% 5,894,139 5,759,541 2061 173,671,817 91.48% 158,878,794 3.76% 5,752,842 5,621,471 

Exhibit 5C-17 below shows beneficial use projected under Subtitle C with a worst-case stigma assumption. Increase

increasing disposal costs of a Subtitle C rule are not accounted for. However, as soon as the rule becomes effective in 

this RIA simulates a stigma effect which decreases the tons beneficially used by 51%. Once the disposal cost effect i

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

mine filling 

2012 134,764,862 25.17% 33,924,749 -51.00% -35,309,432 -33,342013 135,558,881 26.71% 36,206,995 -49.37% -35,309,432 -33,342014 136,352,901 28.20% 38,457,590 -47.87% -35,309,432 -33,342015 137,146,920 29.66% 40,677,131 -46.47% -35,309,432 -33,342016 137,940,940 31.08% 42,866,206 -45.17% -35,309,432 -33,342017 138,734,959 32.45% 45,025,395 -43.95% -35,309,432 -33,342018 139,528,979 33.80% 47,155,270 -42.82% -35,309,432 -33,342019 140,322,998 35.10% 49,256,395 -41.75% -35,309,432 -33,342020 141,117,018 36.37% 51,329,323 -40.75% -35,309,432 -33,342021 141,911,037 37.61% 53,374,602 -39.81% -35,309,432 -33,342022 142,705,057 38.82% 55,392,770 -38.93% -35,309,432 -33,342023 143,499,076 39.99% 57,384,357 -38.09% -35,309,432 -33,342024 144,293,096 41.13% 59,349,885 -37.30% -35,309,432 -33,342025 145,087,115 42.24% 61,289,868 -36.55% -35,309,432 -33,34
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

mine filling 

2026 145,881,135 43.33% 63,204,812 -35.84% -35,309,432 -33,342027 146,675,154 44.38% 65,095,213 -35.17% -35,309,432 -33,342028 147,469,174 45.41% 66,961,561 -34.53% -35,309,432 -33,342029 148,263,193 46.41% 68,804,337 -33.91% -35,309,432 -33,342030 149,057,213 47.38% 70,624,016 -33.33% -35,309,432 -33,342031 149,851,232 48.33% 72,421,062 -32.78% -35,309,432 -33,342032 150,645,252 49.25% 74,195,934 -32.24% -35,309,432 -33,342033 151,439,271 50.15% 75,949,081 -31.74% -35,309,432 -33,342034 152,233,291 51.03% 77,680,946 -31.25% -35,309,432 -33,342035 153,027,310 51.88% 79,391,964 -30.78% -35,309,432 -33,342036 153,821,330 52.71% 81,082,562 -30.34% -35,309,432 -33,342037 154,615,349 53.52% 82,753,160 -29.91% -35,309,432 -33,342038 155,409,369 54.31% 84,404,170 -29.49% -35,309,432 -33,342039 156,203,388 55.08% 86,035,997 -29.10% -35,309,432 -33,342040 156,997,408 55.83% 87,649,041 -28.72% -35,309,432 -33,342041 157,791,427 56.56% 89,243,690 -28.35% -35,309,432 -33,342042 158,585,447 57.27% 90,820,330 -27.99% -35,309,432 -33,342043 159,379,466 57.96% 92,379,337 -27.65% -35,309,432 -33,342044 160,173,486 58.64% 93,921,081 -27.32% -35,309,432 -33,342045 160,967,505 59.30% 95,445,925 -27.00% -35,309,432 -33,342046 161,761,525 59.94% 96,954,227 -26.70% -35,309,432 -33,342047 162,555,544 60.56% 98,446,334 -26.40% -35,309,432 -33,342048 163,349,564 61.17% 99,922,592 -26.11% -35,309,432 -33,342049 164,143,583 61.77% 101,383,338 -25.83% -35,309,432 -33,342050 164,937,603 62.34% 102,828,900 -25.56% -35,309,432 -33,342051 165,731,622 62.91% 104,259,605 -25.30% -35,309,432 -33,342052 166,525,642 63.46% 105,675,770 -25.04% -35,309,432 -33,342053 167,319,661 64.00% 107,077,707 -24.80% -35,309,432 -33,342054 168,113,681 64.52% 108,465,723 -24.56% -35,309,432 -33,342055 168,907,700 65.03% 109,840,117 -24.33% -35,309,432 -33,342056 169,701,720 65.53% 111,201,184 -24.10% -35,309,432 -33,342057 170,495,739 66.01% 112,549,212 -23.88% -35,309,432 -33,342058 171,289,759 66.49% 113,884,485 -23.67% -35,309,432 -33,342059 172,083,778 66.95% 115,207,281 -23.46% -35,309,432 -33,342060 172,877,798 67.40% 116,517,870 -23.26% -35,309,432 -33,342061 173,671,817 67.84% 117,816,520 -23.06% -35,309,432 -33,34
Exhibit 5C-18 below shows the projected future annual CCR generation and three trends in beneficial use (i.e., scena

stigma, scenario #2 decrease with stigma, and scenario #3 no change in relation to the increasing baseline trend). Sce

increased cost of disposal from regulation will induce the electric utility industry to seek out additional CCR benefici

increasing future annual beneficial use of CCR above the increasing baseline trend. Experiences with the EPA RCRA waste program indicate that industry often increases annual recycling and materials recovery rates after RCRA regula

listed certain types and sources of secondary industrial materials as RCRA “hazardous wastes”). Thus, EPA regards 

use Scenario #1 as the most likely outcome. A second curve in the Exhibit below displays the Scenario #2 decreased 

stigma effect under the Subtitle C regulatory option (this RIA does not apply scenario #2 under the Subtitle D options

presents Scenario #3 in which future annual CCR beneficial use is projected to continue on its recent upwardly increa

induced future change as a result of the CCR rule. The future annual beneficial use tonnages for both scenario #1 and in this RIA incrementally relative to the scenario #3 baseline trend. 
Exhibit 5C-18 

Beneficial Use Trends

0

15,000,00030,000,00045,000,00060,000,00075,000,00090,000,000

105,000,000120,000,000135,000,000150,000,000165,000,000180,000,000

2012 2017 2022 2027 2032 2037 2042 2047 2052 

Year

CCRs (Short Tons)

CCRs Generated Baseline BU Subtitle C BU Subtitle C w/Stigma
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 pe

benefit value, plus the (b) $85 per ton average avoided disposal cost estimated for the subtitle C option, to the 50-yea

projected future baseline tonnage displayed in Exhibit 5C-18 above, produces an estimated future baseline social ben

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) 

• 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 sociaCCR beneficial uses (not including minefilling) that could occur as a result of the CCR proposed rule. This quantity ieach year as the quantity projected under the Subtitle C option (without stigma), less the quantity projected under the 

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 Socia

2012 2,241,198 $82 $1,253 $82 $1,253 $82 $1,22013 4,380,599 $161 $2,449 $156 $2,377 $151 $2,22014 6,421,451 $236 $3,590 $223 $3,384 $206 $3,12015 8,366,919 $308 $4,677 $282 $4,280 $251 $3,82016 10,220,089 $376 $5,713 $334 $5,076 $287 $4,32017 11,983,968 $441 $6,699 $380 $5,779 $314 $4,72018 13,661,485 $503 $7,637 $421 $6,396 $335 $5,02019 15,255,494 $561 $8,528 $456 $6,934 $350 $5,32020 14,905,577 $548 $8,332 $433 $6,578 $319 $4,82021 14,563,225 $536 $8,141 $411 $6,239 $291 $4,42022 14,228,291 $523 $7,954 $389 $5,918 $266 $4,02023 13,900,629 $511 $7,771 $369 $5,614 $243 $3,62024 13,580,097 $500 $7,591 $350 $5,324 $222 $3,32025 13,266,555 $488 $7,416 $332 $5,050 $203 $3,0
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 Socia

2026 12,959,864 $477 $7,245 $315 $4,790 $185 $2,82027 12,659,887 $466 $7,077 $299 $4,542 $169 $2,52028 12,366,492 $455 $6,913 $284 $4,308 $154 $2,32029 12,079,545 $444 $6,753 $269 $4,085 $141 $2,12030 11,798,919 $434 $6,596 $255 $3,874 $128 $1,92031 11,524,485 $424 $6,442 $242 $3,674 $117 $1,72032 11,256,118 $414 $6,292 $229 $3,484 $107 $1,62033 10,993,695 $404 $6,146 $217 $3,304 $98 $1,42034 10,737,095 $395 $6,002 $206 $3,132 $89 $1,32035 10,486,198 $386 $5,862 $195 $2,970 $81 $1,22036 10,240,889 $377 $5,725 $185 $2,816 $74 $1,12037 10,001,052 $368 $5,591 $176 $2,670 $68 $1,02038 9,766,574 $359 $5,460 $167 $2,532 $62 $92039 9,537,345 $351 $5,331 $158 $2,400 $56 $82040 9,313,255 $343 $5,206 $150 $2,276 $52 $72041 9,094,198 $335 $5,084 $142 $2,157 $47 $72042 8,880,069 $327 $4,964 $135 $2,045 $43 $62043 8,670,764 $319 $4,847 $128 $1,939 $39 $52044 8,466,182 $311 $4,733 $121 $1,838 $36 $52045 8,266,224 $304 $4,621 $115 $1,742 $33 $42046 8,070,792 $297 $4,512 $109 $1,651 $30 $42047 7,879,791 $290 $4,405 $103 $1,565 $27 $42048 7,693,126 $283 $4,301 $98 $1,484 $25 $32049 7,510,706 $276 $4,199 $93 $1,406 $23 $32050 7,332,440 $270 $4,099 $88 $1,333 $21 $32051 7,158,239 $263 $4,002 $83 $1,263 $19 $22052 6,988,016 $257 $3,906 $79 $1,198 $17 $22053 6,821,687 $251 $3,813 $75 $1,135 $16 $22054 6,659,166 $245 $3,723 $71 $1,076 $14 $22055 6,500,372 $239 $3,634 $67 $1,019 $13 $12056 6,345,224 $233 $3,547 $64 $966 $12 $12057 6,193,644 $228 $3,462 $60 $916 $11 $12058 6,045,554 $222 $3,380 $57 $868 $10 $12059 5,900,878 $217 $3,299 $54 $822 $9 $12060 5,759,541 $212 $3,220 $51 $779 $8 $12061 5,621,471 $207 $3,142 $49 $738 $8 $1

Present Value $9,806 $149,001 $5,560 $84,4
• 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 beneficial uses will increase in equal proportions. However, it would not be appropriate to apply this same dollar esti

beneficial use from stigma because different uses decrease by different amounts, and therefore the decrease in benefitequal the 51% decrease in tons. Based on the breakdown of beneficial uses displayed below in Exhibit 5C-20, these 

losses were summed to create a weighted average benefit reduction of 42%. However, on a tonnage basis 51% of ben

reduced. Dividing the weighted value by the unweighted value for each ton lost, the benefits decreased by only 82% 

or $458/ton. This average unitized social benefits value is used to monetize the estimated tons lost from the stigma S

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 L

Stig

1. Concrete/concrete products/grout 16,353,331 $1,390 $17,593 $18,983 37.52. Blended cement/raw feed for clinker 4,215,234 $358 Not estimated $358 503. Flowable fill 259,907 $22 Not estimated $22 37.54. Structural fill/embankments 8,349,999 $710 Not estimated $710 805. Road base/sub-base 1,461,992 $124 Not estimated $124 806. Soil modification/stabilization 1,139,640 $97 Not estimated $97 807. Mineral filler in asphalt 140,838 $12 Not estimated $12 508. Snow & ice control 547,541 $47 Not estimated $47 809. Blasting grit/roofing granules 1,633,407 $139 Not estimated $139 37.510. Gypsum panel products (wallboard) 8,178,079 $695 $5,387 $6,082 5011. Waste stabilization/solidification 2,839,954 $241 Not estimated $241 0% 12. Agriculture 415,741 $35 Not estimated $35 8013. Aggregate 872,776 $74 Not estimated $74 8014. Miscellaneous other 2,071,157 $176 Not estimated $176 65

Weighted Total = 48,479,596 $4,120 $22,980 $27,100 42

Unweighted Total = 48,479,596 $4,120 $22,980 $27,100 51

Adjustment 

Exhibit 5C-21 below provides an estimate of the beneficial use decrease scenario. This quantity is calculated each y

projected under subtitle C (with stigma) less the quantity projected under the baseline. 
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 C

Year @ 7% (Milli

CCR Beneficial 

Use Decrease 

(Short Tons) Economic Social Economic Social Economic 

2012 -33,342,859 -$1,269 -$15,816 -$1,269 -$15,816 -$1,269 2013 -33,342,859 -$1,269 -$15,816 -$1,232 -$15,355 -$1,186 2014 -33,342,859 -$1,269 -$15,816 -$1,196 -$14,908 -$1,109 2015 -33,342,859 -$1,269 -$15,816 -$1,162 -$14,474 -$1,036 2016 -33,342,859 -$1,269 -$15,816 -$1,128 -$14,052 -$968 2017 -33,342,859 -$1,269 -$15,816 -$1,095 -$13,643 -$905 2018 -33,342,859 -$1,269 -$15,816 -$1,063 -$13,245 -$846 2019 -33,342,859 -$1,269 -$15,816 -$1,032 -$12,860 -$790 2020 -33,342,859 -$1,269 -$15,816 -$1,002 -$12,485 -$739 2021 -33,342,859 -$1,269 -$15,816 -$973 -$12,122 -$690 2022 -33,342,859 -$1,269 -$15,816 -$944 -$11,768 -$645 2023 -33,342,859 -$1,269 -$15,816 -$917 -$11,426 -$603 2024 -33,342,859 -$1,269 -$15,816 -$890 -$11,093 -$564 2025 -33,342,859 -$1,269 -$15,816 -$864 -$10,770 -$527 2026 -33,342,859 -$1,269 -$15,816 -$839 -$10,456 -$492 2027 -33,342,859 -$1,269 -$15,816 -$815 -$10,152 -$460 2028 -33,342,859 -$1,269 -$15,816 -$791 -$9,856 -$430 2029 -33,342,859 -$1,269 -$15,816 -$768 -$9,569 -$402 2030 -33,342,859 -$1,269 -$15,816 -$746 -$9,290 -$376 2031 -33,342,859 -$1,269 -$15,816 -$724 -$9,020 -$351 2032 -33,342,859 -$1,269 -$15,816 -$703 -$8,757 -$328 2033 -33,342,859 -$1,269 -$15,816 -$682 -$8,502 -$307 2034 -33,342,859 -$1,269 -$15,816 -$662 -$8,254 -$287 2035 -33,342,859 -$1,269 -$15,816 -$643 -$8,014 -$268 2036 -33,342,859 -$1,269 -$15,816 -$624 -$7,780 -$250 2037 -33,342,859 -$1,269 -$15,816 -$606 -$7,554 -$234 2038 -33,342,859 -$1,269 -$15,816 -$589 -$7,334 -$219 2039 -33,342,859 -$1,269 -$15,816 -$571 -$7,120 -$204 2040 -33,342,859 -$1,269 -$15,816 -$555 -$6,913 -$191 2041 -33,342,859 -$1,269 -$15,816 -$539 -$6,711 -$178 2042 -33,342,859 -$1,269 -$15,816 -$523 -$6,516 -$167 2043 -33,342,859 -$1,269 -$15,816 -$508 -$6,326 -$156 2044 -33,342,859 -$1,269 -$15,816 -$493 -$6,142 -$146 2045 -33,342,859 -$1,269 -$15,816 -$479 -$5,963 -$136 2046 -33,342,859 -$1,269 -$15,816 -$465 -$5,789 -$127 2047 -33,342,859 -$1,269 -$15,816 -$451 -$5,621 -$119 2048 -33,342,859 -$1,269 -$15,816 -$438 -$5,457 -$111 2049 -33,342,859 -$1,269 -$15,816 -$425 -$5,298 -$104 
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 C

Year @ 7% (Milli

CCR Beneficial 

Use Decrease 

(Short Tons) Economic Social Economic Social Economic 

2050 -33,342,859 -$1,269 -$15,816 -$413 -$5,144 -$97 2051 -33,342,859 -$1,269 -$15,816 -$401 -$4,994 -$91 2052 -33,342,859 -$1,269 -$15,816 -$389 -$4,848 -$85 2053 -33,342,859 -$1,269 -$15,816 -$378 -$4,707 -$79 2054 -33,342,859 -$1,269 -$15,816 -$367 -$4,570 -$74 2055 -33,342,859 -$1,269 -$15,816 -$356 -$4,437 -$69 2056 -33,342,859 -$1,269 -$15,816 -$346 -$4,308 -$65 2057 -33,342,859 -$1,269 -$15,816 -$336 -$4,182 -$60 2058 -33,342,859 -$1,269 -$15,816 -$326 -$4,060 -$56 2059 -33,342,859 -$1,269 -$15,816 -$316 -$3,942 -$53 2060 -33,342,859 -$1,269 -$15,816 -$307 -$3,827 -$49 2061 -33,342,859 -$1,269 -$15,816 -$298 -$3,716 -$46 

Present Value -$33,639 -$419,145 -$18,744 

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, th

extrapolated to the other regulatory options. Exhibit 5C-22 below displays the beneficial use effect scenarios linearlto the result of subtitle C based on the potential increase in CCR disposal cost. In other words, the ratio of the disposthose other scenarios to the subtitle C disposal cost can be applied to the beneficial use benefits under those alternativ

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) Su

Assumed scaling ratios relative to C value = 100% 40% Scenario #1: Increase in Beneficial Use (Base Case) Percentage increase relative to baseline = +11% +4% Economic market value +$5,560 +$2,224 Lifecycle social value +$84,489 +$33,796 Scenario #2: Decrease in Beneficial Use Percentage increase relative to baseline = -18% N/A Economic market value -$18,744 N/A Lifecycle social value -$233,549 N/A 
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 

disposal of 33.3 million tons CCR annually (source: Exhibit 5C-16) which will likely create four future industrial wa

1. Annual disposal rate exceedance: Relative to the 33.3 million lost beneficial use annnual tonnages, there is a 

2 million tons per year of RCRA-regulated hazardous waste which is currently disposed in RCRA Subtitle C p

and offsite (commercial) landfills in the US.160 This implies a potential 1,665% annual increase (i.e., 16.65 ti

hazardous waste landfill capacity. 

2. Limited geographic availability: There are currently 19 to 24 commercial hazardous waste landfills operating 

However, the CCR which is currently beneficially used is generated by 272 electric utility plants located in 41 

at commercial hazardous waste landfills would require out-of-state shipment involving at least 24 to 26 states 

commercial hazardous waste landfills. 

3. Remaining disposal capacity exceedance: The 19 to 24 commercial hazardous waste landfills have an availab

of 21.7 million to 25.4 million tons hazardous waste.163 The additional 33.3 million tons per year of CCR bendisposal 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 haz

could drive-up landfill tipping fees which recently (2004) ranged between $61 and $139 per ton nationwide ($

average).164 As verification of this potential effect on landfill prices, a recent (August 2009) market study165 o

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), and 2007 (1.94 million tons) in EPA’s “RCRA National Analysis Biennial Hazardous Waste Report” 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: 

• Source #1 of 2: 24 commercial RCRA-permitted hazardous waste landfill count and 17 state identities as listed in the Hazardous Waste 

US Commercial Hazardous Waste Management Facilities,” Vol.25, Issue 1, 2007, pp.4.1 to 4.44. The 17 states are AL, AR, CA, CO, IDOH, OK, OR, TX, UT. 

• Source #2 of 2: As compiled 02 Oct 2009 by EPA OSWER-ORCR staff (Cpan Lee, Environmental Scientist), this available remaining 

three sources: (a) actual capacity estimates provided to OSWER-ORCR by facilities in April-Sept 2009, (b) information provided to OS

and States in April/May 2009, and (c) capacity estimates developed by OSWER-ORCR using 1995-2007 RCRA Biennial Report data. 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

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 164 Source: US commercial hazardous waste landfill prices for bulk hazardous waste without treatment reported by the Environmental Techn

2004 Incinerator and Landfill Cost Data” website at http://www.etc.org/costsurvey8.cfm 

165 Source: Page 10 of “Hazardous Waste Industry Review 2008-2009,” Joan Berkowitz and Robert Crisp, Farkas Berkowitz & Company, A

http://www.farkasberkowitz.com/marketresearch.htm 
hazardous waste industry, provides the following empirical evidence of price increases by commercial hazardresponse to annual increases in landfill disposal tonnage: 

“On average, the number of surveyed landfill firms that increased prices exceeds the number that rece

volumes in 2008. Volumes increased for 50 percent of respondents and decreased for 42 percent, but prices and 33 percent left prices unchanged. The survey did not ask how much, if any, of the reported due to fuel surcharges. The survey did determine that 92 percent of respondents applied fuel surchargsurcharges cannot account for all of the price increases because the surcharges cover increased costsrespondents reported increased [profit] margins.” 
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 benChapter 4 and Chapter 5, respectively, scaled to the three 2010 regulatory options. Section 6B of this Chapter provscaling 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 uincrease, induced decrease, and no change), and according to the two OMB-prescribed alternative discount rates of 7% 

7% discount rate: The 7% discount rate as a “base case” to represent the financial opportunity cost (i.e., b

businesses, which is consistent with OMB’s 2003 Circular A-4 guidance166 (page 33), a

Circular A-94 guidance167 (page 8) which indicate that a 7% discount rate “base case” 

regulatory analyses when regulation is expected to primarily and directly affect busines

3% discount rate: This is a second mandatory discount rate specified in OMB’s 2003 Circular A-4 guidan

In these six summary exhibits below, the comparison of regulatory benefits to costs involves two numerical comparis

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% discou

 Scenario #1: Induced increase (base case) Exhibit 6A Exhibi Scenario #2: Induced decrease Exhibit 6C Exhibi Scenario #3: No change Exhibit 6E Exhibi

166 OMB’s 17 Sept 2003 Circular A-4 “Regulatory Analysis” guidance is available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/ 167 OMB’s 29 Oct 1992 Circular A-94 “Guidelines and Discount Rates for Benefit-Cost Analysis of Federal Programs,” is available at

http://www.whitehouse.gov/omb/rewrite/circulars/a094/a094.html 
Exhibit 6A 

Comparison of Regulatory Benefits to Costs Under Scenario #1 – Induced Beneficial Use Increase @7% Discount Rate – 

($Millions in 50-Year Present Values @2009$ Prices) 

Costs Subtitle C “Special Waste” Subtitle D (version 2) 

1. Engineering Controls $6,780 $3,254 2. Ancillary Costs $1,480 $5 3. Dry Conversion $12,089 4,836 

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

Benefits 

4. Groundwater Protection Benefits* $970 $375  Count of Human Cancer Risks Avoided** 726 296  Monetized Value of Human Cancer Risks Avoided $504 $207  Groundwater Remediation Costs Avoided $466 $168 5. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Ec

Scenario #1 @7% discount rate = $5,560 $84,489 $2,224 $33,796 

6. CCR Impoundment Failure Costs Avoided  If Based on Extrapolated Recent Failure Cases $1,762 $793  If Based on 10% Future Failures $8,366 $3,795  If Based on 20% Future Failures $16,732 $7,590 7. Non-quantified Benefits*** Q R 

Total Benefits (4+5+6): 

Total Benefits w/Extrapolated Recent Failure Cases = $8,292 $87,221 $3,392 $34,964 

Total Benefits @10% Future Failures = $14,896 $93,825 $6,394 $37,966 Total Benefits @20% Future Failures = $23,262 $102,191 $10,189 $41,761 

Net Benefits (Total Benefits minus Total Costs) 

Net Benefits w/Extrapolated Recent Failure Cases = ($12,057) $66,872 ($4,703) $26,869 

Net Benefits @10% Future Failures = ($5,453) $73,476 ($1,701) $29,871 Net Benefits @20% Future Failures = $2,913 $81,842 $2,094 $33,666 

Benefit/Cost Ratio (BCR) 

BCR w/Extrapolated Recent Failure Cases = 0.407 4.286 0.419 4.319 

BCR @10% Future Failures = 0.732 4.611 0.790 4.690 BCR @20% Future Failures = 1.143 5.022 1.259 5.159 

Notes: * Cancer risk reflects the arsenic groundwater pathway only and does not include other human health mortality or morbidity risks from non-

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 av
Exhibit 6B 

Comparison of Regulatory Benefits to Costs Under Scenario #1 – Induced Beneficial Use Increase @3% Discou

($Millions in 50-Year Present Values @2009$ Prices) 

Costs Subtitle C “Special Waste” Subtitle D (version 2) 

1. Engineering Controls $12,640 $6,067 2. Ancillary Costs $2,759 $9 3. Dry Conversion $22,538 $9,016 

Total Costs (1+2+3) = $37,938 $15,092 

Benefits 

4. Groundwater Protection Benefits* $3,316 $1,321  Count of Human Cancer Risks Avoided** 726 296  Monetized Value of Human Cancer Risks Avoided $1,825 $750  Groundwater Remediation Costs Avoided $1,491 $571 5. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Eco

Scenario #1 @3% discount rate = $9,806 $149,001 $3,922 $59,600 

6. CCR Impoundment Failure Costs Avoided  If Based on Extrapolated Recent Failure Cases $3,124 $1,406  If Based on @ 10% Future Failures $13,046 $5,918  If Based on @ 20% Future Failures $26,092 $11,836 7. Non-quantified Benefits*** Q R 

Total Benefits (4+5+6): 

Total Benefits w/Extrapolated Recent Failure Cases = $16,246 $155,441 $6,649 $62,327 

Total Benefits @10% Future Failures = $26,168 $165,363 $11,161 $66,839 Total Benefits @20% Future Failures = $39,214 $178,409 $17,079 $72,757 

Net Benefits (Total Benefits minus Total Costs) 

Net Benefits w/Extrapolated Recent Failure Cases = ($21,692) $117,503 ($8,443) $47,235 

Net Benefits @10% Future Failures = ($11,770) $127,425 ($3,931) $51,747 Net Benefits @20% Future Failures = $1,276 $140,471 $1,987 $57,665 

Benefit/Cost Ratio (BCR) 

BCR w/Extrapolated Recent Failure Cases = 0.428 4.097 0.441 4.130 

BCR @10% Future Failures = 0.690 4.359 0.740 4.429 BCR @20% Future Failures = 1.034 4.703 1.132 4.821 

Notes: * Cancer risk reflects the arsenic groundwater pathway only and does not include other human health mortality or morbidity risks from non-

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. 
Exhibit 6C 

Comparison of Regulatory Benefits to Costs Under Scenario #2 – Induced Beneficial Use Decrease @7% Disco

($Millions in 50-Year Present Values @2009$ Prices) 

Costs Subtitle C “Special Waste” Subtitle D (version 2) 

1. Engineering Controls $6,780 $3,254 2. Ancillary Costs $1,480 $5 3. Dry Conversion $12,089 4,836 

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

Benefits 

4. Groundwater Protection Benefits* $970 $375  Count of Human Cancer Risks Avoided** 726 296  Monetized Value of Human Cancer Risks Avoided $504 $207  Groundwater Remediation Costs Avoided $466 $168 5. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Ec

Scenario #2 @7% discount rate = ($18,744) ($233,549) $0 (no impact) $0 (no impact) $0 

6. CCR Impoundment Failure Costs Avoided  If Based on Extrapolated Recent Failure Cases $1,762 $793  If Based on 10% Future Failures $8,366 $3,795  If Based on 20% Future Failures $16,732 $7,590 7. Non-quantified Benefits*** Q R 

Total Benefits (4+5+6): 

Total Benefits w/Extrapolated Recent Failure Cases = ($16,012) ($230,817) $1,168 $1,168 

Total Benefits @10% Future Failures = ($9,408) ($224,213) $4,170 $4,170 Total Benefits @20% Future Failures = ($1,042) ($215,847) $7,965 $7,965 

Net Benefits (Total Benefits minus Total Costs) 

Net Benefits w/Extrapolated Recent Failure Cases = ($36,361) ($251,166) ($6,927) ($6,927) 

Net Benefits @10% Future Failures = ($29,757) ($244,562) ($3,925) ($3,925) Net Benefits @20% Future Failures = ($21,391) ($236,196) ($130) ($130) 

Benefit/Cost Ratio (BCR) 

BCR w/Extrapolated Recent Failure Cases = (0.787) (11.343) 0.144 0.144 

BCR @10% Future Failures = (0.462) (11.018) 0.515 0.515 BCR @20% Future Failures = (0.051) (10.607) 0.984 0.984 

Notes: * Cancer risk reflects the arsenic groundwater pathway only and does not include other human health mortality or morbidity risks from non-

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. 
Exhibit 6D 

Comparison of Regulatory Benefits to Costs Under Scenario #2 – Induced Beneficial Use Decrease @3% Disco

($Millions in 50-Year Present Values @2009$ Prices) 

Costs Subtitle C “Special Waste” Subtitle D (version 2) 

1. Engineering Controls $12,640 $6,067 2. Ancillary Costs $2,759 $9 3. Dry Conversion $22,538 $9,016 

Total Costs (1+2+3) = $37,938 $15,092 

Benefits 

4. Groundwater Protection Benefits* $3,316 $1,321  Count of Human Cancer Risks Avoided** 726 296  Monetized Value of Human Cancer Risks Avoided $1,825 $750  Groundwater Remediation Costs Avoided $1,491 $571 5. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Ec

Scenario #2 @3% discount rate = ($34,946) ($435,419) $0 (no impact) $0 (no impact) $0 

6. CCR Impoundment Failure Costs Avoided  If Based on Extrapolated Recent Failure Cases $3,124 $1,406  If Based on 10% Future Failures $13,046 $5,918  If Based on 20% Future Failures $26,092 $11,836 7. Non-quantified Benefits*** Q R 

Total Benefits (4+5+6): 

Total Benefits w/Extrapolated Recent Failure Cases = ($28,506) ($428,979) $2,727 $2,727 

Total Benefits @10% Future Failures = ($18,584) ($419,057) $7,239 $7,239 Total Benefits @20% Future Failures = ($5,538) ($406,011) $13,157 $13,157 

Net Benefits (Total Benefits minus Total Costs) 

Net Benefits w/Extrapolated Recent Failure Cases = ($66,443) ($466,917) ($12,365) ($12,365) 

Net Benefits @10% Future Failures = ($56,521) ($456,995) ($7,853) ($7,853) Net Benefits @20% Future Failures = ($43,475) ($443,949) ($1,935) ($1,935) 

Benefit/Cost Ratio (BCR) 

BCR w/Extrapolated Recent Failure Cases = (0.751) (11.307) 0.181 0.181 

BCR @10% Future Failures = (0.490) (11.046) 0.480 0.480 BCR @20% Future Failures = (0.146) (10.702) 0.872 0.872 

Notes: * Cancer risk reflects the arsenic groundwater pathway only and does not include other human health mortality or morbidity risks from non-

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. 
Exhibit 6E 

Comparison of Regulatory Benefits to Costs Under Scenario #3 – No Change to Beneficial Use @ 7% Discoun

($Millions in 50-Year Present Values @2009$ Prices) 

Costs Subtitle C “Special Waste” Subtitle D (version 2) 

1. Engineering Controls $6,780 $3,254 2. Ancillary Costs $1,480 $5 3. Dry Conversion $12,089 4,836 

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

Benefits 

4. Groundwater Protection Benefits* $970 $375  Count of Human Cancer Risks Avoided** 726 296  Monetized Value of Human Cancer Risks Avoided $504 $207  Groundwater Remediation Costs Avoided $466 $168 5. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Ec

Scenario #3 @7% discount rate = $0 (no change) $0 (no change) $0 (no change) $0 (no change) $0 

6. CCR Impoundment Failure Costs Avoided  If Based on Extrapolated Recent Failure Cases $1,762 $793  If Based on 10% Future Failures $8,366 $3,795  If Based on 20% Future Failures $16,732 $7,590 7. Non-quantified Benefits*** Q R 

Total Benefits (4+5+6): 

Total Benefits w/Extrapolated Recent Failure Cases = $2,732 $2,732 $1,168 $1,168 

Total Benefits @10% Future Failures = $9,336 $9,336 $4,170 $4,170 Total Benefits @20% Future Failures = $17,702 $17,702 $7,965 $7,965 

Net Benefits (Total Benefits minus Total Costs) 

Net Benefits w/Extrapolated Recent Failure Cases = ($17,617) ($17,617) ($6,927) ($6,927) 

Net Benefits @10% Future Failures = ($11,013) ($11,013) ($3,925) ($3,925) Net Benefits @20% Future Failures = ($2,647) ($2,647) ($130) ($130) 

Benefit/Cost Ratio (BCR) 

BCR w/Extrapolated Recent Failure Cases = 0.134 0.134 0.144 0.144 

BCR @10% Future Failures = 0.459 0.459 0.515 0.515 BCR @20% Future Failures = 0.870 0.870 0.984 0.984 

Notes: * Cancer risk reflects the arsenic groundwater pathway only and does not include other human health mortality or morbidity risks from non-

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. 
Exhibit 6F 

Comparison of Regulatory Benefits to Costs Under Scenario #3 – No Change to Beneficial Use @ 3% Discoun

($Millions in 50-Year Present Values @2009$ Prices) 

Costs Subtitle C “Special Waste” Subtitle D (version 2) 

1. Engineering Controls $12,640 $6,067 2. Ancillary Costs $2,759 $9 3. Dry Conversion $22,538 $9,016 

Total Costs (1+2+3) = $37,938 $15,092 

Benefits 

4. Groundwater Protection Benefits* $3,316 $1,321  Count of Human Cancer Risks Avoided** 726 296  Monetized Value of Human Cancer Risks Avoided $1,825 $750  Groundwater Remediation Costs Avoided $1,491 $571 5. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Ec

Scenario #3 @3% discount rate = $0 (no change) $0 (no change) $0 (no change) $0 (no change) $0 

6. CCR Impoundment Failure Costs Avoided  If Based on Extrapolated Recent Failure Cases $3,124 $1,406  If Based on 10% Future Failures $13,046 $5,918  If Based on 20% Future Failures $26,092 $11,836 7. Non-quantified Benefits*** Q R 

Total Benefits (4+5+6): 

Total Benefits w/Extrapolated Recent Failure Cases = $6,440 $6,440 $2,727 $2,727 

Total Benefits @10% Future Failures = $16,362 $16,362 $7,239 $7,239 Total Benefits @20% Future Failures = $29,408 $29,408 $13,157 $13,157 

Net Benefits (Total Benefits minus Total Costs) 

Net Benefits w/Extrapolated Recent Failure Cases = ($31,498) ($31,498) ($12,365) ($12,365) 

Net Benefits @10% Future Failures = ($21,576) ($21,576) ($7,853) ($7,853) Net Benefits @20% Future Failures = ($8,530) ($8,530) ($1,935) ($1,935) 

Benefit/Cost Ratio (BCR) 

BCR w/Extrapolated Recent Failure Cases = 0.170 0.170 0.181 0.181 

BCR @10% Future Failures = 0.431 0.431 0.480 0.480 BCR @20% Future Failures = 0.775 0.775 0.872 0.872 

Notes: * Cancer risk reflects the arsenic groundwater pathway only and does not include other human health mortality or morbidity risks from non-

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. 
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 referencdraft RIA regulatory options. Furthermore, the regulatory benefits evaluation in Chapter 5 of this RIA was based onoptions. To resolve this inconsistency in scope between the two different sets of regulatory options evaluated for cosrespectively, this RIA applies the scaling factors (i.e., percentage extrapolation multipliers) displayed below in Exhib

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 engineering cost model which estimated "engineering control" costs associated with the RCRA 3004(x) custom-tailorthe 2009 regulatory options (i.e., Subtitle C "hazardous waste" option, Subtitle D non-hazardous waste option requirin

new CCR disposal units, and a "hybrid" C/D option). Although the engineering control costs were the same for each options, "ancillary costs" differed according to whether an option was formulated in reference to Subtitle C or to Subt

example, only the Subtitle C "hazardous waste" option and the Subtitle C component of the "Hybrid C/D" option requwith manifesting offsite shipments of CCR between coal-fired electric utility plants and offsite CCR disposal location

draft RIA presented the "dry conversion cost" element as a separable "sub-option" for both the Subtitle C and Subtitle However, in 2010 EPA identified a different set of three regulatory options to describe in the proposed rule and evalu"special waste" option with wet disposal phase-out, Subtitle D option which in effect would phase-out wet CCR disporetrofitting existing impoundments with composite liners, and a Subtitle "D prime" option requiring liners only for neorder to meet EPA’s end-of-March 2010 internal deadline for completing the 2nd draft of this RIA, EPA did not revis

analysis or the Chapter 7 supplemental analyses, but applied scaling factors for bridging the cost estimates to the 201the scaling factors represent alternative compliance rate assumptions in relation to the 2009 draft RIA’s Subtitle C "ha reference case for both cost and benefit estimate scaling to the three 2010 regulatory options. The scaling factors as

under the non-Federally enforceable Subtitle D based options compared to the Federally-enforceable Subtitle C optio

provides the numerical values assigned to the scaling factors on an itemized basis according to the separate cost elemcategories, 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) 

Subtitl

“D prim

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: 
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) 

Subtitl

“D prim

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 relev

The following two sub-sections (6B.1 and 6B.2) provide explanation and documentation of the scaling factors display

6B.1 Regulatory Cost Scaling Factors 

o Engineering control costs: For both RCRA subtitle C and subtitle D, the engineering control costs wou

options. However, state governments are not required to develop comparable programs under RCRA 

cannot enforce Federal subtitle D rules. In addition, because of the nature of subtitle D authority, indivgroundwater monitoring, impoundment closure) will be more generic, allowing industry great latitude actual costs under Subtitle D options will be lower than under Subtitle C, because facilities would not the same extent. In estimating future annual tons of CCR that might be managed under new standardsthey would be similar under the Subtitle C option, this RIA applies the percentage of tons of CCR dispgroundwater monitoring requirements as a way to estimate the likely costs incurred by industry for the the engineering control cost category consists of 10 cost elements as defined in this RIA, the percentaggroundwater monitoring programs is a reasonable surrogate indicator because states imposing groundwrequirements indicates which states will generally address specific units, and which are likely to upgra

subtitle D, if EPA were to issue a national subtitle D rule. In those states, management standards may although not to the level of subtitle C for the reasons discussed above. On the other hand, certainly sowithout programs will choose to comply with the national regulation (taking full advantage of the morfederal D standards). Taking these two factors together, using the percentage of CCR disposed in state

monitoring programs provides a reasonable estimate of the extent to which facilities will take steps to 

standards, and therefore of the costs of compliance. For the federally-enforceable subtitle C option, the 

states (100%) will be required by the CCR rule to install groundwater monitoring (and all other enginethe non-federally enforceable subtitle D and the “D prime” options, the cost estimates assume that the 

in states that currently require surface impoundments to have groundwater monitoring (either for new 
existing units) will generally upgrade their programs, improving compliance, and that a modest numbestates would independently make efforts to comply – giving an overall estimate of 48%. This 48% is amultiplier to estimate engineering control costs for both the Subtitle D and “D prime” in relation to the cost estimate. 

o Ancillary costs: The RIA separately estimated “ancillary” costs under both Subtitle C and Subtitle D a

nationwide adoption. For the Subtitle D or “D prime” options, the cost estimate only includes inspectiimpoundments by qualified engineers. The same logic applies to this requirement as it does to the engtherefore this RIA applied the same 48% scaling factor multiplier relative to the Subtitle D ancillary co

o Dry conversion costs: For the dry conversion cost, 40% is only applied as a scaling multiplier under th

because the “D prime” option does not require dry conversion. The 40% value is calculated in Exhibibased in part on assuming that the cost for retrofitting or building new impoundments is 63% of the coSubtitle C as calculated in Exhibit 6H below. 

Exhibit 6G 

Estimate of Subtitle D (version 2) Impoundment Liner Retrofit or Build New Lined Impoundment Cos

A B C D E F G (D x 

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 

Subtit

Must 

Build N

Impo

1 2012 158 $22,984,000,000 5.5% 94.5% $132 2013 158 $0 5.5% 94.5% 3 2014 158 $0 5.5% 94.5% 4 2015 158 $0 5.5% 94.5% 5 2016 158 $0 5.5% 94.5% 6 2017 158 $15,800,000 5.5% 94.5% 7 2018 158 $15,800,000 5.5% 94.5% 8 2019 158 $15,800,000 5.5% 94.5% 9 2020 158 $15,800,000 5.5% 94.5% 

10 2021 158 $15,800,000 5.5% 94.5% 11 2022 158 $15,800,000 5.5% 94.5% 12 2023 158 $15,800,000 5.5% 94.5% 13 2024 158 $15,800,000 5.5% 94.5% 14 2025 158 $15,800,000 5.5% 94.5% 15 2026 158 $15,800,000 5.5% 94.5% 16 2027 158 $15,800,000 5.5% 94.5% 17 2028 158 $15,800,000 5.5% 94.5% 18 2029 158 $15,800,000 5.5% 94.5% 19 2030 158 $15,800,000 5.5% 94.5% 20 2031 158 $15,800,000 5.5% 94.5% 
Exhibit 6G 

Estimate of Subtitle D (version 2) Impoundment Liner Retrofit or Build New Lined Impoundment Cos

A B C D E F G (D x 

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 

Subtit

Must 

Build N

Impo

21 2032 158 $15,800,000 5.5% 94.5% 22 2033 158 $15,800,000 5.5% 94.5% 23 2034 158 $15,800,000 5.5% 94.5% 24 2035 158 $15,800,000 5.5% 94.5% 25 2036 158 $15,800,000 5.5% 94.5% 26 2037 158 $15,800,000 5.5% 94.5% 27 2038 158 $15,800,000 5.5% 94.5% 28 2039 158 $15,800,000 5.5% 94.5% 29 2040 158 $15,800,000 5.5% 94.5% 30 2041 158 $15,800,000 5.5% 94.5% 31 2042 158 $15,800,000 5.5% 94.5% 32 2043 158 $15,800,000 5.5% 94.5% 33 2044 158 $15,800,000 5.5% 94.5% 34 2045 158 $15,800,000 5.5% 94.5% 35 2046 158 $15,800,000 5.5% 94.5% 36 2047 158 $15,800,000 5.5% 94.5% 37 2048 158 $15,800,000 5.5% 94.5% 38 2049 158 $15,800,000 5.5% 94.5% 39 2050 158 $15,800,000 5.5% 94.5% 40 2051 158 $22,984,000,000 5.5% 94.5% $1341 2052 158 $15,800,000 5.5% 94.5% 42 2053 158 $15,800,000 5.5% 94.5% 43 2054 158 $15,800,000 5.5% 94.5% 44 2055 158 $15,800,000 5.5% 94.5% 45 2056 158 $15,800,000 5.5% 94.5% 46 2057 158 $15,800,000 5.5% 94.5% 47 2058 158 $15,800,000 5.5% 94.5% 48 2059 158 $15,800,000 5.5% 94.5% 49 2060 158 $15,800,000 5.5% 94.5% 50 2061 158 $15,800,000 5.5% 94.5% 

Non-discounted total cost = $46,663,000,000 $27

Non-discounted average cost = $933,000,000 $

Present value cost (@7% disc.) = $23,167,000,000 $13

Average annualized cost (@7%) = $1,679,000,000 $1

Percent reduction in annualized cost compared to Subtitle C Option conversion cost = 

Notes: 
Exhibit 6G 

Estimate of Subtitle D (version 2) Impoundment Liner Retrofit or Build New Lined Impoundment Cos

A B C D E F G (D x 

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 

Subtit

Must 

Build N

Impo

* 5.5% existing impoundments with composite liners based on EPA’s 2000 CCR regulatory determination and on the Augjoint EPA-DOE survey report. ** EPA estimated the capital and annual O&M costs for the Subtitle D requirement for either retrofitting or building new impoundments with composite liners, by assuming that the cost for those requirements are 63% of the $23.167 billion pre

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 P

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 2 Conveyance (transport) $10,364,000 $116,996,000 $127,360,000 14% $10,364,000 3 Disposal (lined landfill) $53,952,000 $39,926,000 $93,878,000 10% $53,952,000 

 Total = $83,816,000 $850,022,000 $933,838,000 100% $83,816,000 

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 2 Conveyance (transport) $31,954,000 $42,140,000 $74,094,000 16% $31,954,000 3 Disposal (lined impoundment) $52,906,000 $14,448,000 $67,354,000 15% $52,906,000 

 Total = $93,360,000 $358,709,000 $452,069,000 100% $93,360,000 

Source: Based on cost data for an example 2600 megawatt (MW) nameplate capacity electric utility plant from pages B-8 (dry) and C-9 (w

EPA/TVA joint study “Economic Analysis of Wet Versus Dry Ash Disposal Systems: Interagency Energy/Environment R&D Program ReEPA-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 impoundmencomposite liners, by assuming that the cost for those requirements are 63% of the $23.167 billion present value cost for dry conversion undoption. 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 rela

monitoring requirements as described in Chapter 5 of this RIA. The percentages given in Exhibit 6F 

input values to the estimation of groundwater protection benefits presented in Chapter 5 of this RIA. 

all states will be required by the rule to have groundwater monitoring in place so that 100% of facilitie
detect contamination early and thus human cancers would be prevented. For the Subtitle D option, 48surface impoundments in states with groundwater monitoring in place for new units only (or for new a

likely that these states with some level of attention to groundwater monitoring would increase their att

already have a RCRA program infrastructure) to groundwater monitoring, providing for much more efother states would tend not to (although some individual facilities within those states would upgrade g

some extent). Thus, this RIA estimates that overall, the new regulation would result in 48% of facilitiearly and 48% of cancers would be prevented. For the Subtitle D prime option, retrofitting existing un

and therefore existing and future releases would continue to occur from unlined surfaced impoundmen

CCR are placed in surface impoundments in states with groundwater monitoring. Some of these states 

their regulations, but given that surface impoundments would remain a potential source of release in alprime option is less protective of groundwater than the Subtitle D option. Since this fraction is likely t12%, 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 percen

implement the new requirements (which for subtitle D would require liners for existing surface impouthat many states will choose to implement this requirement. Instead, compliance will not be enforceabself-imposed schedules of industry or citizens suits. While most impoundments may eventually close, 

process. As a general estimate, through delaying closures and lengthening the process, industry may b

50%. In addition, since 5.5% of surface impoundments have composite liners already, they would remwould not incur costs. Taking these figures together, this RIA applies a 45% scaling factor for this ben

o Induced impact on CCR beneficial uses: 

 Under Scenario #1 induced increase in beneficial use, beneficial uses are assumed to be linear 

because increases in usage are directly proportional to the cost of the regulatory options. There

option, the net reduction in total costs compared to the Subtitle C option is 40%. Under the Susince the dry conversion costs are 0%, a net result of 16% was applied. This percentage was dSubtitle “D prime” option cost by the total cost of Subtitle C. 

 Under Scenario #2 induced decrease in beneficial use, for the reasons described in Section 5C 

assumes that potential induced future decrease on beneficial use only applies to the Subtitle C r

the Subtitle D-based options. 

 Under Scenario #3 no change in beneficial use (relative to baseline), there is no impacts under 

options, so no scaling assumptions are applied. 
Chapter 7

Supplemental Analyses Required by Congressional Statutes or White House Ex

Note: The computations presented in this Chapter are based on the cost estimates for the October 2009 draft 

options using the larger dry conversion cost estimate prior to its update in Chapter 4. Because the high-end c

2009 draft RIA regulatory options (i.e., for the Subtitle C “hazardous waste” option) is larger than the high-enoptions (i.e., for the Subtitle C “special waste” option), the effects estimated in this Chapter are proportionatel

7A. Electricity Price Impact (Executive Order 13211) The 2001 Executive Order 13211168 “Actions Concerning Regulations that Significantly Affect Energy Supply, Distr

Federal agencies to evaluate and prepare a statement on any potential adverse effects of economically-significant rule

supply, distribution or use, including: 

• Shortfall in energy supply • Energy price increases • Increased use of foreign energy supplies 

The OMB’s 13 July 2001 Memorandum M-01-27169 guidance for implementing this Executive Order identifies nine (thresholds) of potential adverse energy effects, three of which are relevant for evaluation in this RIA: 

• Increases in the cost of energy production in excess of 1%

• Increases in the cost of energy distribution in excess of 1%• Other similarly adverse outcomes.

Because this RIA did not collect and analyze data on energy production cost or energy distribution cost, this RIA eva

of the CCR regulatory options on electricity prices relative to the 1% threshold of both indicators as an indicator of “ooutcome”. This RIA calculated the potential increase in statewide electricity prices that the industry compliance cost

CCR regulatory option. This calculation involved plant-by-plant annual revenue estimates and annualized complianc

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=fr22my01169 OMB’s 13 July 2001 Memorandum M-01-27 is available at: http://www.whitehouse.gov/omb/memoranda_m01-27/ 
• Step 1: Downloaded the annual million megawatt capacity data for each of the 495 plants from the DOE-EIA 

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

• Step 2: Estimated the annual electricity sales revenue for each plant by multiplying the estimated annual electr

plant (from Step 1), by the respective statewide average retail price (May 2009) of electricity for all sectors (i.e., r

industrial, transportation) from DOE-EIA at http://www.eia.doe.gov/cneaf/electricity/epm/table5_6_a.html

• Step 3: Added the estimated incremental regulatory costs on a plant-by-plant basis, to the estimated annual ele

each plant, to obtain a hypothetical future annual revenue target, which represents a 100% cost pass-thru scenariorepresents an upper-bound case of potential electricity price increase. Furthermore, if this 100% cost pass-thru is electricity supply in each state, not just averaged over the 495 coal-fired electricity plants as done in this RIA, the increase in electricity price would be less than this upper-bound case presented in this RIA. 

• Step 4: Divided the hypothetical future annual revenue target by the estimated annual electricity output for eac

hypothetical future (higher) target price for each plant, which incorporates the added regulatory cost. Compared tthe 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 b

7A, none of the options have an expected nationwide average energy price increase >1%. Appendix L presents the p

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 - impoundm

D - landfi

Average Pr

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.1

Capacity Utilization” data for Utilities at http://www.federalreserve.gov/releases/g17/Current/default.htm 
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 - impoundm

D - landfi

Average Pr

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% 
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 - impoundm

D - landfi

Average Pr

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 capacity) rather than on all electric utility and independent electricity producer plants in each state using other fuels s

nuclear, hydroelectric, etc. (with 678,200 megawatts nameplate capacity), these price effects are higher than would be 

were averaged over the entire electric utility and independent electricity producer supply (totaling 1,011,700 megawa76,100 megawatts of combined heat and electricity producers).171

• Electricity Impact Findings 

On a nationwide basis for all 495 plants, compared to the estimated average electricity price of $0.0884 per kilowatt-hthe 100% regulatory cost pass-thru scenario may increase prices for the 495 plants by 0.172% to 0.795% across the r

of the regulatory options exceed the 1% threshold of EO 13211, thus this RIA does not include a “Statement of Energrequired 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 “Table 2.3. Existing Capacity by Producer T

http://www.eia.doe.gov/cneaf/electricity/epa/epaxlfile2_3.pdf 
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 

Fairness Act (SBREFA), Federal regulatory agencies are required to make initial determinations if proposed regulato

“significant economic impact on a substantial number of small entities” (SISNOSE). Small entities include small bus

organizations, and small governmental jurisdictions. Agencies are required to conduct a Regulatory Flexibility Scree

make this determination. This section of the RIA presents the methodology and findings for the RFSA conducted for 

Unless Agencies are able to certify that a particular regulatory action is not expected to have a SISNOSE, the RFA/SB

analysis of the potential adverse economic impacts on small entities, completion of a Small Business Advocacy Reviestage), preparation of a Small Entity Compliance Guide (final rule stage), and Agency review of the rule within 10 yeThe small business impact analysis of this RIA follows the four analytic steps described in EPA’s RFA/SBREFA ana

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 thStep 3: Determine whether the rule may be certified as not having a significant impact on small entities (SISNStep 4: Document the screening analysis and include the appropriate RFA statements in the preamble 

• 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 

the scope of this RFA/SBREFA analysis are offsite commercial landfills which currently receive and dispose CCR gplants. EPA’s RCRA statute does not provide EPA with authority to collect information from solid waste facilities; authority to collect information from RCRA-regulated hazardous waste management facilities (via the RCRA bienn

know the identity, company size, or other information about the offsite landfills currently used by the electric utility 

RFA/SBREFA analysis is limited to only electric utility plants. Consistent with EPA’s RFA/SBREFA guidance (pagfollowing 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 fue

company which generates less than 4 million megawatt-hours electricity output per yea

172 EPA’s RFA/SBREFA guidance: “EPA’s Action Development Process: Final Guidance for EPA Rulewriters: Regulatory Flexibility Act a

Business Regulatory Enforcement Fairness Act”, EPA Office of Policy, Economics & Innovation, Nov 2006, 105 pages: http://www.epa.gov/sbrefa/documents/rfaguidance11-00-06.pdf 
Small government: Based on the RFA/SBREFA’s definition (5 US Code section 601(5)) of small gove

government of a city, county, town, township, village, school district, or special district 

Based on the nameplate megawatt (MW) capacity for all electricity generating units (including those powered by nonelectricity plant from the 2007 DOE-EIA 860 database, this RIA estimated annual megawatt-hours electricity generatmultiplying the nameplate capacity by (a) 365 days per year, and (b) 24 hours per day to calculate each owner entity’capacity. Appendix D of this RIA indicates the assigned size of the owner company or city government for each electo two size categories: “Small” or “Non-small”.173 Exhibit 7B below presents the resultant count and summary of th

small electric utility entities as estimated in this RIA. 

Exhibit 7B 

Summary of Characteristics of Small Electric Utility Entities 

A B C D 

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) 

1. Small City Government 33 33 34.0 $2,592 2. Small Company 12 11 10.6 $948 3. Small Cooperative 6 6 12.0 $947 4. Small County Government 1 1 0.3 $23 Summary: 

All small entities = 52 plants 

(11%) 

51 entities 

(26%) 

 56.8 

(1%) 

$4,509 

(1%) 

All non-small entities = 443 plants 

(89%) 

149 entities 

(74%) 

5,380.5 

(99%) 

$419,056 

(99%) 

All entities (non-small + small) = 495 plants 200 entities 5,437 million mwh* $423,565** 

Notes: * Annual electricity generation capacity based on all electric plants and types of electric generation units (e.g. coal-fired, oil-fired, hywind, 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 (Utilities sector) in the 2007 Economic Census at: http://factfinder.census.gov/servlet/IBQTable?_bm=y&-geo_id=D&-ds_name=EC

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 specifica

database to identify each corporate entity may be subsidiaries of a larger holding company (classified under a different NAICS) rather than a addition some of these power companies may have merged. For example, State Line is owned by Dominion Resources of Virginia, NortheaEnergy North America, Inc. (SEGNA), Rio Bravo Poso and Rio Bravo Jasmin are owned by the North American Power Group, Ltd (NAPG)owned by TONDU, Public Service Enterprise Group (PSEG) and Excelon are merged. This approach likely overstates the number of small e
• 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 followin

be used to determine if small entities may be significantly impacted by a proposed rule: 

• 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 

• 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 house

Based on annual electricity generation data for the small owner entities in the electric utility industry identified in Ap

annual sales/annual revenue test was used for this analysis. As itemized and estimated for each owner entity in the spAppendix M to this RIA, for each small entity EPA computed the respective sales revenue test percentages by the eq

(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 mega

Appendix D). This estimate involved downloading the annual million megawatt capacity data electricity plants from the DOE-EIA website (2007), and then multiplying the capacity data by 

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 pe

relevant state or states applicable to the location of electric plants owned by each company; elecomposite 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 M

Statistical Release G.17 “Industrial Production & Capacity Utilization” 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., r

industrial, transportation) and on a composite basis at: http://www.eia.doe.gov/cneaf/electricity/epm/table5_6_a.html
• Step 3 & Step 4: Determine and document whether the proposed rule may be certified as having “No SISN

EPA determined whether each regulatory option may have a “significant impact on a substantial number of small ent

which may become subject to the requirements of the proposed rule. This determination involved comparing the esticompliance costs for each entity as displayed in Appendix J of this RIA and as summarized in Exhibit 7C below (sm8, 9), to the respective annual sales and revenues for each entity estimated in Step 2 above. Numerically, this comparthe percentage of regulatory compliance costs relative to annual sales and revenues for each company for each of the 

compared the percentage results for each small entity to the following three impact thresholds defined in Table 2 of Eanalytic guidance. Exhibit 7D below displays the numerical results of this analysis and the suggested RFA/SBREFA according to the three thresholds. 

<1% threshold: Annualized regulatory costs may be less then 1% of annual sales or revenues fo1% or more threshold: Annualized regulatory costs may be 1% or more of annual sales or revenues for 3% or more threshold: Annualized regulatory costs may be 3% or more of annual sales or revenues for 

Exhibit 7C 

Summary of Regulatory Cost Estimates According to Electric Utility Plant Owner Entity Size/Type Categ

($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 foSubtitle D fo

1. Non-Small City 27 plants $46.9 $27.1 2. Non-Small Company 372 plants $1,897.2 $378.5 $3. Non-Small Coop 20 plants $87.7 $34.6 4. Non-Small Federal 11 plants $183.2 $20.8 5. Non-Small State** 13 plants $41.6 $27.1 6. Small City 33 plants $2.8 $1.6 7. Small Company 12 plants $4.1 $1.9 8. Small Coop 6 plants $10.4 $0.3 9. Small County 1 plant $0.004 $0.004 

Total all 9 categories = 495 plants*** $2,274 $492 $

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 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 regulatory costs because 28 plants solely supply their CCR for beneficial uses. 
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 impouSubtitle D for landfi

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 S

1% or greater Presumed No SISNOSE Presumed No SISNOSE Presumed No S3% or greater Presumed No SISNOSE Presumed No SISNOSE Presumed No S

* Source: Costs for each option based on total cost for the four small entity categories displayed as rows 6 + 7 + 8 + 9 from Exhibit 

• 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 m

entity impacts relative to the estimates above in this RIA: 

• Factor #1 of 2: According to the 2007 DOE-EIA database on electric utility plants, two-thirds of the coal-fi

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) 
• Factor #2 of 2: The small business impact analysis in this RIA applies the full industry compliance cost to t

However, because consumer demand for electricity is (a) highly price-inelastic and (b) projected go grow b

electric utility plants may be expected to pass-thru much, if not all, of their regulatory costs (pending state ghike approval). The next section of this RIA evaluates the possibility of regulatory compliance cost pass-th

• 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 servicfranchise in exchange for having rates closely regulated by State public utility commissions (PUCs; sometimes called commissions) and the Federal Energy Regulatory Commission (FERC). The FERC regulates rates charged for sales utilities, even if they are in the same state. It also regulates the pricing and use of transmission for wheeling, and asse

mergers. In most states (California de-regulated electricity in 1998), the PUCs/PSCs set allowable rates upon applicaother affected parties allowed to present testimony. By law the utility must recover its cost of service, which includes expenses and a "fair" return on equity.176

Based on the electricity ratemaking process described by the Pennsylvania PUC177as a case example, when an electri

price increase (aka rate hike), it must file a request with the PUC showing the proposed new rates and effective date, increase is needed. The utility also must notify customers at least 60 days in advance. The notice must include the amincrease, the proposed effective date, and how much more the ratepayer can expect to pay. Under the law, the utility 

its reasonably incurred expenses and a fair return on its investment. The PUC evaluates each utility’s request for a racriteria. During the investigation, hearings are held before an Administrative Law Judge (ALJ) at which the evidence increase is examined and expert witnesses testify. In addition, consumers are offered an opportunity to voice their opiBriefs may be submitted by the formal parties. A recommendation to the PUC is made by the ALJ. Finally, the matt

Commissioners for a vote and final decision. Together with the 60-day notice period, the rate increase process takes 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 “Energy & Water: Emerging Issues and Tr

and Mike Hightower, Sandia National Laboratories, at: http://www.ct-si.org/Summit2007/spk/RKottenstette.pdf 

176 Source: “Electric Utility Regulation” 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, “The PUC Ratemaking Process and the Role of Consumers”, January 2008 at: 

http://www.puc.state.pa.us/general/consumer_ed/pdf/Ratemaking_Complaints.pdf 

178 Source: “Recent Examples of Rate Increases in Vertically Integrated States”, The Compete Coalition, Washington DC, 05 November 200

http://www.competecoalition.com/resources/recent-examples-rate-increases-vertically-integrated-states 
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, no

electricity supplier, to compete and set their own retail prices in those state markets. As of 2003, 18 states have dereg

soon deregulate:179

• Deregulated states (18): AZ, CT, DE, DC, IL, ME, MD, MA, MI, NH, NJ, NY, OH, OR, PA, RI, TX, V

(11 of these states no longer have a price cap) 

• 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 o

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 

and react to the actual market value of their electricity consumption/ conservation. Since end-users do not face the remaking their consumption decisions, there is little demand reaction to changes in real time wholesale electricity price

consumer demand for electricity has been largely inelastic. The lack of real time metering at the retail level means th

179 Source: “Status of State Electric Industry Restructuring Activity as of February 2003”, US Dept of Energy, Energy Information Administ

http://www.eia.doe.gov/cneaf/electricity/chg_str/restructure.pdf 

180 Source: “Shocking Electricity Prices Follow Deregulation”, USA Today, 10 Aug 2007 at: http://www.usatoday.com/money/industries/ene

prices_n.htm 

181 Source: page 1 of “Demand Responsiveness in Electricity Markets”, Ronald Lafferty et al., Office of Markets, Tariffs and Rates, 15 Jan 2

http://www.naseo.org/committees/energyproduction/documents/demand_responsiveness_in_electricity_markets.pdf 
how much they use or indeed how much electricity costs until after the fact. Thus consumers cannot react to high pri

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 hik19% per company which far exceeds the 1% and 3% SISNOSE screening analysis thresholds defined by EPA’s guida

deregulated states which have de-regulated the price of electricity, and (c) the fact that consumer demand for electriciinelastic, this RIA concludes that it is likely that electric utility suppliers could pass-thru all, or nearly all, of the futurregulatory compliance costs for the CCR proposed rule such that a significant impact on small entities and non-small 

182 Source: “Power Price Volatility and Risk Management: An Introduction”, Anne Ku, Sept 2000 (this is the original, unedited article, later Business magazine Sept/Oct 2000) at: http://www.analyticalq.com/energy/volatility/default.htm 
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 pract

law, and consistent with the principles set forth in the report on the National Performance Review, each Federal agen

environmental justice (EJ) part of its mission by identifying and addressing, as appropriate, disproportionately high an

or environmental effects of its programs, policies, and activities on (a) minority populations and (b) low-income pop

defined in EO 12898, for purpose of this RIA the following definitions are applied: 

• Minority population: Numerically measured according to Census Bureau “non-white” statistics (does • Low-income population: Numerically measured according to Census Bureau “individuals below poverty

Furthermore, section 3-302(b) of EO 12898 provides a trigger which indicates that Federal agencies shall collect and facilities or sites expected to have “substantial environmental, human health, or economic effect” when such facilities 

to “substantial” Federal environmental action: 

“In connection with the development and implementation of agency strategies in section 1-103 of this order, e

agency, whenever practicable and appropriate, shall collect, maintain and analyze information on the race, nincome level, and other readily accessible and appropriate information for areas surrounding facilities or sitesubstantial environmental, human health, or economic effect on the surrounding populations, when such facibecome the subject of a substantial Federal environmental administrative or judicial action. Such information available to the public unless prohibited by law.” 

The EO 12898 does not establish quantitative thresholds for “substantial effect” on the surrounding populations, nor dquantitative threshold. This RIA uses the (1) CCR disposal baseline environmental and human health hazards (e.g., d

environmental and human health protection objectives described in the CCR proposed rule, as indicators of “substant

reason, this section of the RIA presents an EJ data collection and analysis involving a 5-step process to compare minopopulation data for each electric utility plant location, to respective statewide population data, to identify whether thegroups disproportionately reside in geographic areas where electric utility plants are located. In addition, this RIA idaffects of the CCR proposed rule on (a) environmental justice populations surrounding offsite landfills which may recenvironmental 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.htm184 The US Census Bureau defines “poverty” following the Office of Management and Budget's (OMB) Statistical Policy Directive 14. The 

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 and every individual in it is considered in poverty. Poverty income thresholds are available at http://www.census.gov/hhes/www/pov
• Collection of Minority & Low-Income Demographic Data 

Step 1: Plant address 5-digit “Zip Code Tabulation Areas” (ZCTAs) formed the geographic basis for this EJ populatio

Because ZCTAs represent irregularly shaped geographic areas, this ZCTA based data collection may be consi

analysis. The US Bureau of Census uses over 33,000 ZCTA for its Census counts of population and other demon the US Postal Service’s over 42,000 nationwide ZCTAs.185 Currently, there are no size restrictions limitin

ZCTA can be in terms of either a minimum/maximum number of housing units or geographic area. Any parti

small as a few city blocks or may cover many square miles. Many ZCTAs are for villages, census-designated 

or other entities that are not municipalities. The nationwide average ZCTA population is about 7,200 persons 2009 US population) / (42,500 ZCTAs)). The nationwide average ZCTA area is about 83 square miles (i.e., (

total US land and water area) / (42,500 ZCTAs)), which is a land area equivalent to a five-mile radial distance (3.1416))^0.5). In comparison, the radial area monitored for contamination in response to the December 2009 electric plant CCR spill is reportedly four miles,186and this average four-mile ZCTA radial distance falls betw

radial distances used by EPA’s Superfund “Hazard Ranking System” (HRS) to define affected populations of contamination only (1-mile), (b) groundwater and/or airborne contamination (4-miles), or (c) surface water co

downstream). More information about EPA’s HRS is available at http://www.epa.gov/superfund/programs/npUsing the Census search engine Factfinder (http:factfinder.census.gov/home/saff/main.html?_lang=en), EPA statistics for 464 (94%) of the 495 electric utility plants. For 42 plants (8%) there was no ZCTA Census data 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 c

plant-by-plant sub-group population statistics. 

o EPA collected low-income population statewide percentages (3-year averages for 1998 to 2000) from 

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 

EPA then subtracted the percentage of white population in each state from 100% to produce the respecpercentage for each state. For data year 2000, the Census Bureau expanded the white population classcollecting both data for people who claimed to be “white-only” and for people who claimed to be “mixthe purpose of the EJ analysis is to evaluate all minorities, this step involved collecting the “white-onlycalculate the minority percentage which includes people who reported to be of mixed race. Exhibit 7F 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 th

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.htm
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 % 

29 ND 12.7% 30 NE 10.7% 31 NH 7.6% 32 NJ 8.1% 33 NM 19.3% 34 NV 10.1% 35 NY 14.7% 36 OH 11.1% 37 OK 14.1% 38 OR 12.9% 39 PA 9.8% 40 RI 10.2% 41 SC 12.0% 42 SD 9.4% 43 TN 13.4% 44 TX 14.9% 45 UT 8.1% 46 VA 8.1% 47 VT 10.3% 48 WA 9.5% 49 WI 9.0% 50 WV 15.8% 51 WY 11.1% 

 Min = 7.3% (MD)  Max = 19.3% (NM)  National = 11.9% 
• Comparison of Minority & Low-Income Populations Surrounding Electric Utility Plants to Statewide Be

Step 3, Step 4 and Step 5 of this evaluation described below involved three complementary levels of data comparisonalso involved two complementary numerical comparisons, one based on calculating numerical percentages and the ot

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 

• 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 po

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 display

This constituted the 2nd level of data comparison. There are no data displayed for DC, ID, RI or VT because t

electric utility plants in those states. Appendix N of this RIA presents the plant-by-plant Census data on whicThis step also involved aggregating the data across all 495 plants for comparison with the nationwide aggregaincome 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 

General Population Data Low Income Population Data (Below Poverty) Minority Pop

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 

Sta

wid

mino

1 AK 2 18,552 2,284 12.31% 8.40% 1,558 1 31.95% 5,928 30.72 AL 9 82,854 20,331 24.54% 14.70% 12,180 6 42.17% 34,942 28.93 AR 3 11,786 1,214 10.30% 15.80% 1,862 0 7.74% 912 20.04 AZ 6 34,941 7,433 21.27% 13.50% 4,717 5 43.70% 15,270 24.55 CA 4 112,895 24,749 21.92% 14.00% 15,805 5 45.22% 51,049 40.56 CO 15 214,095 29,395 13.73% 8.50% 18,198 10 17.88% 38,275 17.27 CT 2 42,716 6,427 15.05% 7.70% 3,289 1 45.14% 19,284 18.48 DC ND 
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 

General Population Data Low Income Population Data (Below Poverty) Minority Pop

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 

Sta

wid

mino

9 DE 3 46,925 3,979 8.48% 9.90% 4,646 1 28.86% 13,543 25.4

10 FL 13 224,502 23,866 10.63% 12.10% 27,165 5 20.76% 46,617 22.011 GA 9 202,973 29,461 14.51% 12.50% 25,372 4 42.66% 86,581 34.912 HI 1 25,054 1,150 4.59% 10.60% 2,656 0 78.17% 19,584 75.713 IA 14 324,050 31,434 9.70% 7.90% 25,600 13 7.02% 22,744 6.114 ID ND 15 IL 23 455,834 83,407 18.30% 10.50% 47,863 14 41.46% 188,970 26.516 IN 17 323,323 25,460 7.87% 8.30% 26,836 10 6.96% 22,488 12.517 KS 6 59,517 7,718 12.97% 10.50% 6,249 4 36.76% 21,881 13.918 KY 17 255,033 32,497 12.74% 12.50% 31,879 7 8.48% 21,615 9.919 LA 4 30,381 7,546 24.84% 18.50% 5,620 3 45.16% 13,721 36.120 MA 3 95,798 14,420 15.05% 10.10% 9,676 1 20.69% 19,819 15.521 MD 7 101,141 10,622 10.50% 7.30% 7,383 4 12.39% 12,527 36.022 ME 1 6,748 1,037 15.37% 9.80% 661 1 1.30% 88 3.123 MI 20 383,284 30,735 8.02% 10.20% 39,095 8 10.56% 40,477 19.824 MN 15 187,012 20,910 11.18% 7.80% 14,587 10 10.78% 20,157 10.625 MO 19 251,484 24,714 9.83% 9.80% 24,645 10 7.47% 18,794 15.126 MS 4 69,209 17,675 25.54% 15.50% 10,727 3 51.63% 35,735 38.627 MT 5 53,209 8,441 15.86% 16.00% 8,513 2 13.25% 7,050 9.428 NC 16 238,874 37,388 15.65% 13.20% 31,531 9 34.49% 82,397 27.929 ND 5 27,087 2,440 9.01% 12.70% 3,440 1 4.40% 1,193 7.630 NE 6 79,313 8,992 11.34% 10.70% 8,486 2 11.38% 9,027 10.431 NH 2 53,302 4,355 8.17% 7.60% 4,051 2 5.40% 2,877 4.032 NJ 6 119,286 17,958 15.05% 8.10% 9,662 3 43.96% 52,438 27.433 NM 4 17,491 4,638 26.52% 19.30% 3,376 3 55.72% 9,746 33.234 NV 3 8,471 823 9.72% 10.10% 856 1 15.75% 1,334 24.835 NY 13 226,416 29,187 12.89% 14.70% 33,283 3 17.42% 39,451 32.136 OH 23 391,705 42,242 10.78% 11.10% 43,479 7 12.24% 47,953 15.037 OK 6 30,357 6,117 20.15% 14.10% 4,280 4 38.84% 11,791 23.838 OR 1 3,884 596 15.35% 12.90% 501 1 39.19% 1,522 13.439 PA 28 167,254 15,499 9.27% 9.80% 16,391 15 6.61% 11,048 14.640 RI ND 41 SC 12 222,414 28,746 12.92% 12.00% 26,690 8 31.40% 69,831 32.842 SD 2 30,508 1,763 5.78% 9.40% 2,868 1 5.55% 1,694 11.3
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 

General Population Data Low Income Population Data (Below Poverty) Minority Pop

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 

Sta

wid

mino

43 TN 8 158,267 26,572 16.79% 13.40% 21,208 4 37.38% 59,159 19.844 TX 17 98,402 14,147 14.38% 14.90% 14,662 10 22.41% 22,052 29.045 UT 6 34,209 3,885 11.36% 8.10% 2,771 6 5.22% 1,784 10.846 VA 15 220,800 21,822 9.88% 8.10% 17,885 11 37.78% 83,411 27.747 VT ND 48 WA 1 21,842 3,394 15.54% 9.50% 2,075 1 9.54% 2,083 18.249 WI 13 178,705 23,577 13.19% 9.00% 16,083 8 12.00% 21,446 11.150 WV 13 64,771 15,577 24.05% 15.80% 10,234 11 6.45% 4,179 5.051 WY 8 69,736 6,439 9.23% 11.10% 7,741 1 4.92% 3,428 7.9

Summary: 

Column totals 430 6,076,410 783,062 12.9% 11.9% 658,336 240 21.7% 1,317,895 24.

18.9% 

 Min = 4.6% 7.3% 1.3% 3.1 Max = 26.5% 19.3% 78.2% 75.

Extrapolated to 495 plants = 256 
Step 5: Ratios: EPA compared the percentages of minority and low-income populations surrounding the plants to the

benchmark percentages and to the nationwide percentages of these populations as calculated in Step 4, by calc

between the plant ZCTA group populations compared to statewide and nationwide percentages of minority anpopulations. The purpose of these ratios is to indicate the relative degree by which the percentages are below 

percentages. Exhibit 7H below displays the results. 

Exhibit 7H 

Comparison of Minority and Low-Income Populations Near Coal-Fired Electric Utility Plants to Statewide Per

A B C D E F (D–E) G (D/E) H I J (H

Low-Income Data Comparison Minority Data Com

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) 

Diff

1 AK 2 12.3% 8.4% 3.9% 1.47 32.0% 30.7% 1.2 AL 9 24.5% 14.7% 9.8% 1.67 42.2% 28.9% 133 AR 3 10.3% 15.8% -5.5% 0.65 7.7% 20.0% -124 AZ 6 21.3% 13.5% 7.8% 1.58 43.7% 24.5% 195 CA 5 21.9% 14.0% 7.9% 1.57 45.2% 40.5% 4.6 CO 15 13.7% 8.5% 5.2% 1.62 17.9% 17.2% 0.7 CT 2 15.0% 7.7% 7.3% 1.95 45.1% 18.4% 268 DC NR NA NA NA NA NA NA N9 DE 3 8.5% 9.9% -1.4% 0.86 28.9% 25.4% 3.

10 FL 14 10.6% 12.1% -1.5% 0.88 20.8% 22.0% -111 GA 9 14.5% 12.5% 2.0% 1.16 42.7% 34.9% 7.12 HI 1 4.6% 10.6% -6.0% 0.43 78.2% 75.7% 2.13 IA 17 9.7% 7.9% 1.8% 1.23 7.0% 6.1% 0.14 ID NR NA NA NA NA NA NA N15 IL 25 18.3% 10.5% 7.8% 1.74 41.5% 26.5% 1516 IN 19 7.9% 8.3% -0.4% 0.95 7.0% 12.5% -517 KS 7 13.0% 10.5% 2.5% 1.24 36.8% 13.9% 2218 KY 19 12.7% 12.5% 0.2% 1.02 8.5% 9.9% -119 LA 4 24.8% 18.5% 6.3% 1.34 45.2% 36.1% 9.20 MA 4 15.1% 10.1% 5.0% 1.49 20.7% 15.5% 5.21 MD 8 10.5% 7.3% 3.2% 1.44 12.4% 36.0% -2322 ME 1 15.4% 9.8% 5.6% 1.57 1.3% 3.1% -123 MI 23 8.0% 10.2% -2.2% 0.79 10.6% 19.8% -924 MN 15 11.2% 7.8% 3.4% 1.43 10.8% 10.6% 0.25 MO 19 9.8% 9.8% 0.0% 1.00 7.5% 15.1% -726 MS 4 25.5% 15.5% 10.0% 1.65 51.6% 38.6% 13
Exhibit 7H 

Comparison of Minority and Low-Income Populations Near Coal-Fired Electric Utility Plants to Statewide Per

A B C D E F (D–E) G (D/E) H I J (H

Low-Income Data Comparison Minority Data Com

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) 

Diff

27 MT 6 15.9% 16.0% -0.1% 0.99 13.2% 9.4% 3.28 NC 19 15.7% 13.2% 2.5% 1.19 34.5% 27.9% 6.29 ND 7 9.0% 12.7% -3.7% 0.71 4.4% 7.6% -330 NE 6 11.3% 10.7% 0.6% 1.06 11.4% 10.4% 1.31 NH 2 8.2% 7.6% 0.6% 1.08 5.4% 4.0% 1.32 NJ 6 15.1% 8.1% 7.0% 1.86 44.0% 27.4% 1633 NM 4 26.5% 19.3% 7.2% 1.37 55.7% 33.2% 2234 NV 3 9.7% 10.1% -0.4% 0.96 15.7% 24.8% -935 NY 13 12.9% 14.7% -1.8% 0.88 17.4% 32.1% -1436 OH 24 10.8% 11.1% -0.3% 0.97 12.2% 15.0% -237 OK 6 20.2% 14.1% 6.1% 1.43 38.8% 23.8% 1538 OR 1 15.3% 12.9% 2.4% 1.19 39.2% 13.4% 2539 PA 31 9.3% 9.8% -0.5% 0.95 6.6% 14.6% -840 RI NR NA NA NA NA NA NA N41 SC 12 12.9% 12.0% 0.9% 1.08 31.4% 32.8% -142 SD 2 5.8% 9.4% -3.6% 0.61 5.6% 11.3% -543 TN 8 16.8% 13.4% 3.4% 1.25 37.4% 19.8% 1744 TX 18 14.4% 14.9% -0.5% 0.96 22.4% 29.0% -645 UT 6 11.4% 8.1% 3.3% 1.40 5.2% 10.8% -546 VA 16 9.9% 8.1% 1.8% 1.22 37.8% 27.7% 1047 VT NR NA NA NA NA NA NA N48 WA 1 15.5% 9.5% 6.0% 1.64 9.5% 18.2% -849 WI 15 13.2% 9.0% 4.2% 1.47 12.0% 11.1% 0.50 WV 16 24.0% 15.8% 8.2% 1.52 6.5% 5.0% 1.51 WY 9 9.2% 11.1% -1.9% 0.83 4.9% 7.9% -3

Summary:

 Min = 4.6% 7.3% -6.0% 0.43 4.4% 3.1% -23 Max = 26.5% 19.3% 10.0% 1.95 78.2% 75.7% 26

Nationwide = 464 12.9% 11.9% 1.0% 1.08 21.7% 24.9% -3
• Minority & Low-Income Demographic Findings 

Below is a summary of the three alternative but complementary comparison approaches based on the same minority adata: (a) itemized plant-by-plant basis, (b) nationwide aggregation basis, and (c) state-by-state aggregation basis. For relative degree by which either group living near the 495 plants may exceed their respective statewide population per

are compared as a numerical ratio whereby a ratio of 1.00 indicates that the group population percentage living near a 

statewide average, a ratio greater than 1.00 indicates the group population percentage near the plant is higher than the ratio less than 1.00 indicates the group population is less than the respective statewide average. 

• General population findings: 

o 464 plants (i.e., 94% of the 495 universe) for which year 2000 Census plant address ZCTA data are av

states. 

o The plant address ZCTA population surrounding the 464 plants with ZCTA data is 6.08 million, whic

surrounding population per plant. 

• Low-income population findings: 

o 0.78 million low-income population surrounding the 464 plants represents 12.9% of the 6.08 million t

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 2

o Extrapolated and aggregated across all 495 plants, 256 plants (52%) have surrounding populations wh

benchmark percentage of low-income population. 

o The ratios of low-income population percentages surrounding these plants range from 0.43 to 1.95, an

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 compare

statewide benchmarks. 

o States with the largest difference in low-income populations surrounding the plants compared to their 

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%) 

• Minority population findings: 

o 1.32 million minority population surrounding the 464 plants represents 21.7% of the 6.08 million tota

this is lower than the 24.9% national minority population. 
o The state-by-state range of minority population percentages surrounding these plants ranges from 1.3% 

o Extrapolated and aggregated across all 495 plants, 138 plants (28%) have surrounding populations wh

benchmark minority percentage of population. 

o The ratio of minority population percentages surrounding these plants range from 0.34 to 2.92, and the 

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 popu

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 loca

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%) 

• Plant level results: 

Using the plant-by-plant (i.e., itemized ZCTA) basis, 138 plants (28%) have surrounding minority populations which 

minority benchmark percentages, whereas 357 plants (72%) have minority populations below their statewide benchm

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 

relatively small count of plants have surrounding minority population percentages which disproportionately exceed th

Also on a plant-by-plant ZCTA basis, 256 plants (52%) have surrounding low-income populations which exceed thei

benchmarks, whereas 239 plants (48%) have surrounding low-income populations below their statewide benchmarksZCTA ratio of 1.07 (i.e., 256/239). Because this ratio is only slightly (7%) above 1.00, it indicates that a slightly disphave surrounding low-income population percentages which exceed their statewide benchmarks. 

• State level results: 

Using the state-by-state aggregation basis, the percentages of minority and low-income populations surrounding the ptheir respective statewide population benchmarks. From this, state ratios revealed that 24 of the 47 states (51%) hav

percentages, and 29 of the 47 states (62%) have higher low-income percentages surrounding the 495 plants, suggestinhigher minority surrounding population and a relatively large disproportionate, higher low-income surrounding populcomparison to the other two numerical comparisons, this state-by-state count approach does not include numerically-

counts or state surrounding populations, which explains why this comparison method yields a different numerical reshow population comparison results may be sensitive to the comparison method. 
• Nationwide results: 

Using the nationwide aggregation basis across all 495 plants in all 47 states where the plants are located, 6.08 million 

surrounding the plants, which include a sub-total of 1.32 million (21.7%) minority and a sub-total of 0.8 million (12.9groups. A comparison of these percentages to the national benchmark averages across all states of 24.9% minority anrepresents 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 nat

indicate a slightly lower disproportionate minority population surrounding the 495 plants, and a slightly higher dispropopulation surrounding the plants. Comparison of nationwide population sub-totals for all plants for each demograph

expected value based on statewide averages, reveals that: 

o +18.9% additional low-income residents near the plants compared to the expected low-income popula

averages (i.e., 783,062 low-income population for all 464 plants compared to 658,336 expected count 

averages.) 

o -5.8% less minority residents near the plants compared to the expected minority population based on s

1,317,896 minority population for all 464 plants compared to 1,241,382 expected count if based on sta

These three alternative comparisons indicate that the current (baseline) environmental and human health hazards and 

CCR disposal units, and the expected future benefits of the regulatory options, may have a disproportionately lower epopulations and may have a disproportionately higher effect on low-income populations. 

• Other Potentially Affected Minority & Low-Income Populations 

There are two other potential differential effects of the regulatory options on two other population groups: (a) populat

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 differen

generation may be required to be disposed in RCRA Subtitle C permitted landfills rather than in non-RCRA permitte

• CCR fraction #1: Electric utility plants may switch the management of CCR, in whole or in part, from current o

commercial RCRA-permitted hazardous waste landfills (56.8 million is disposed in onsite lan

disposed in onsite impoundments, totaling 79.2 million tons disposed onsite). 

• CCR fraction #2: Some or all of the CCR which is currently disposed in offsite landfills that do not have RCRA 

also switch to RCRA-permitted commercial hazardous waste landfills if the current receiving RCRA Subtitle C permits (15.0 million tons is disposed offsite). 
• CCR fraction #3: Annual CCR generation which is currently supplied for industrial beneficial use applications 

offsite commercial RCRA Subtitle C permitted landfills if such use becomes curtailed in part state government regulations or from market stigma (47.0 million tons is beneficially used). 

• CCR fraction #4: Future cleanup of CCR disposal unit failures (e.g., impoundment collapse) would require disp

permitted waste landfills (the two CCR impoundment release case studies in Exhibit 4A of th

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 la

disproportionate effect on populations surrounding these locations, and in particular, minority and low-income popula

commercial hazardous waste facilities, if current landfills operated by electric utility plants do not obtain future Subti

A recent (2007) study determined that minority and low-income populations disproportionately live near commercial 

facilities, although the study included other types of commercial hazardous waste treatment and disposal facilities in 

hazardous waste landfills.187 An example of such potential EJ concerns is a 2009 US national news item involving th

Tennessee Valley Authority (TVA) to train transport 3 million tons of the TVA’s (Kingston TN electricity plant) Decimpoundment collapse site cleanup waste, 350 miles away to a landfill in a rural Alabama county which reportedly ha

(African American) and 33% low-income residents.188 However, this example serves to illustrate that EJ concerns ar

conclusive or shared by all affected EJ populations, as evidenced by the following remarks made to news reporters by 

government officials and county residents:189

“To county leaders, the train’s loads, which will total three million cubic yards of coal ash from a massive spi

in east Tennessee last December [2008], are a tremendous financial windfall. A per-ton “host fee” that the lapay the county will add more than $3 million to the county’s budget of about $4.5 million. The ash has create

jobs for local residents in a county where the unemployment rate is 17 percent and a third of all households apoverty line. A sign on the door of the landfill’s scale house says job applications are no longer being acceptmore than enough. But some residents worry that their leaders are taking a short-term view, and that their cotoo easily persuaded to take on a wealthier, whiter community’s problem.... County leaders, who are mostly baccusations of environmental injustice, saying that the ash is perfectly safe and that criticism has been fostere

even competitors who wanted the ash disposal contract for themselves..... Bob Deacy, vice president of clean 

187 Source: United Church of Christ, “Toxic Wastes and Race at Twenty 1987-2007”, March 2007. . This study evaluated and made findings 

population data within a 1.8-mile radius “host neighborhood” of 413 commercial hazardous waste facilities, compared to “non-host” areas. T

“Host neighborhoods of commercial hazardous waste facilities are 56% people of color whereas non-host areas are 30% of color... Poverty are 1.5 times greater than non-host areas (18% vs. 12%).” 

188 Source: Shaila Dewan, “Clash in Alabama Over Tennessee Coal Ash,” The New York Times, 30 Aug 2009 at http://www.nytimes.com/2189 Source: At least two news organizations identically reported these remarks on 30 Aug 2009: 

#1 of 2: New York Times, “Clash in Alabama Over Tennessee Coal Ash” at http://www.nytimes.com/2009/08/30/us/30ash.html 

#2 of 2: Waste Business Journal, “Waste From TVA Spill Begins to Arrive at Alabama Landfill Amid Controversy” at 

http://www.wastebusinessjournal.com/news/wbj20090901D.htm 
project development for the Tennessee Valley Authority, whose Kingston Fossil Plant was the site of the ash salmost 300 acres of land and waterways, said Arrowhead [Alabama landfill] was chosen because it was reacinstead of truck, because it underbid other sites and because, unlike closer landfills, it had the capacity to han

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 somelectric utility plants could increase to cover the cost of regulatory compliance. Thus customers in electric utility serv

experience price increases, although the RIA estimates that future potential price increases could be expected to be beto the $0.0900 per kilowatt hour national average price (February 2009) for all four customer sectors (i.e., residential, 

and transportation). The RIA for today’s action did not evaluate the customer service area populations for the 495 pl
7D. Child Population Statistics (Executive Order 13045)

• 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 an

health and safety risks that may disproportionately affect children, and (b) shall ensure that its policies, programs, actaddress disproportionate risks to children that result from environmental health or safety risks. Although the EO doeUS Census Bureau defines “children” as follows190: 

Children: The term "children"... are all persons under 18 years, excluding people who maintain households, 

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 c

utility plants. This analysis involves a 5-step process for comparing children population data for each electric utility children population data to identify whether children disproportionately reside in geographic areas where electric util

• Collection of Child Demographic Data 

Step 1:Plant address 5-digit “Zip Code Tabulation Areas” (ZCTAs) formed the geographic basis for this child popula

Because ZCTAs represent irregularly shaped geographic areas, this ZCTA based data collection may be consianalysis. The US Bureau of Census uses over 33,000 ZCTAs for its Census counts of population and other deon the US Postal Service’s over 42,000 nationwide ZCTAs.191 Currently, there are no size restrictions limitin

ZCTA can be in terms of either a minimum/maximum number of housing units or geographic area. Any parti

small as a few city blocks or may cover many square miles. Many ZCTAs are for villages, census-designated 

or other entities that are not municipalities. The nationwide average ZCTA population is about 7,200 persons 2009 US population) / (42,500 ZCTAs)). The nationwide average ZCTA area is about 83 square miles (i.e., (

total US land and water area) / (42,500 ZCTAs)), which is a land area equivalent to a 5-mile radial distance (i(3.1416))^0.5). In comparison, the radial area monitored for contamination in response to the December 2009 electric plant CCR spill is reportedly four miles,192 and this average 5-mile ZCTA radial distance falls betwee

radial distances used by EPA’s Superfund “Hazard Ranking System” (HRS)193 to define affected populations 

soil contamination only (1-mile), (b) groundwater and/or airborne contamination (4-miles), or (c) surface wate

190 The US Census Bureau definition of “children” is from its “Current Population Survey (CPS) - Definitions and Explanations” 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 

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.htm193 More background information about EPA’s HRS is available at http://www.epa.gov/superfund/programs/npl_hrs/hrsint.htm. 
downstream). Using the Census search engine Factfinder (http:factfinder.census.gov/home/saff/main.html?_l

total population and people 18 and over for 464 (94%) of the 495 electric utility plants. For 42 plants (8%) thdata because the plants did not have complete address data from DOE or because the Census search engine di

ZCTA. 

Step 2: EPA collected 3-year (2005 to 2007) average statewide percentages for people 18 and older data as displayed 

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 % chi

31 NH 32 NJ 33 NM 34 NV 35 NY 36 OH 37 OK 38 OR 39 PA 40 RI 41 SC 42 SD 43 TN 44 TX 45 UT 46 VA 47 VT 48 WA 49 WI 50 WV 51 WY 

Max (UT) 

Min (DC) 

Nationwide 
• 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 comparisonalso involved two complementary numerical comparisons, one based on calculating numerical percentages and the otnumerical 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 aveStep 4: For purpose of summary, EPA aggregated the plant level children population comparison data for each state a

below. There are no data displayed for DC, ID, RI or VT because there are no coal-fired electric utility plants 

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 

Expec

children co

plant ZCT

based on s

1 2 AK 2 18,552 5,188 27.96% 27.00% 5,002 9 AL 9 82,854 21,978 26.53% 24.40% 20,213 3 AR 3 11,786 3,359 28.50% 24.80% 2,924 6 AZ 6 34,941 11,526 32.99% 26.40% 9,225 5 CA 4 112,895 36,285 32.14% 25.90% 29,246 15 CO 15 214,095 49,190 22.98% 24.70% 52,887 2 CT 2 42,716 10,743 25.15% 23.70% 10,128 NA DC 9 3 DE 3 46,925 11,169 23.80% 23.90% 11,21

10 14 FL 13 224,502 55,025 24.51% 22.30% 50,0611 9 GA 9 202,973 50,964 25.11% 26.50% 53,7812 1 HI 1 25,054 8,158 32.56% 22.30% 5,5813 17 IA 14 324,050 77,708 23.98% 23.90% 77,4414 NA ID 
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 

Expec

children co

plant ZCT

based on s

15 25 IL 23 455,834 129,772 28.47% 25.10% 114,416 19 IN 17 323,323 83,594 25.85% 25.10% 81,1517 7 KS 6 59,517 16,532 27.78% 25.20% 14,9918 19 KY 17 255,033 63,012 24.71% 23.90% 60,9519 4 LA 4 30,381 8,617 28.36% 25.40% 7,7120 4 MA 3 95,798 23,078 24.09% 22.50% 21,5521 8 MD 7 101,141 23,529 23.26% 24.40% 24,6722 1 ME 1 6,748 1,561 23.13% 21.50% 1,4523 23 MI 20 383,284 94,994 24.78% 24.60% 94,2824 15 MN 15 187,012 46,208 24.71% 24.50% 45,8125 19 MO 19 251,484 60,084 23.89% 24.40% 61,3626 4 MS 4 69,209 19,867 28.71% 26.30% 18,2027 6 MT 5 53,209 14,115 26.53% 23.20% 12,3428 19 NC 16 238,874 57,728 24.17% 24.40% 58,2829 7 ND 5 27,087 7,411 27.36% 22.50% 6,0930 6 NE 6 79,313 20,853 26.29% 25.30% 20,0631 2 NH 2 53,302 10,713 20.10% 23.10% 12,3132 6 NJ 6 119,286 29,806 24.99% 24.00% 28,6233 4 NM 4 17,491 5,656 32.34% 25.60% 4,4734 2 NV 2 8,471 1,827 21.57% 25.80% 2,1835 13 NY 13 226,416 57,612 25.45% 23.20% 52,5236 24 OH 23 391,705 101,253 25.85% 24.20% 94,7937 6 OK 6 30,357 8,513 28.04% 24.90% 7,5538 1 OR 1 3,884 1,378 35.48% 23.20% 901 39 31 PA 28 167,254 36,581 21.87% 22.60% 37,7940 NA RI 41 12 SC 12 222,414 60,391 27.15% 24.20% 53,8242 2 SD 2 30,508 7,510 24.62% 24.80% 7,5643 8 TN 8 158,267 40,682 25.70% 24.10% 38,1444 18 TX 17 98,402 27,471 27.92% 27.70% 27,2545 6 UT 6 34,209 11,769 34.40% 30.90% 10,5746 16 VA 15 220,800 55,824 25.28% 23.90% 52,7747 NA VT 48 1 WA 1 21,842 5,514 25.24% 23.90% 5,2249 15 WI 13 178,705 36,428 20.38% 23.80% 42,53
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 

Expec

children co

plant ZCT

based on s

50 16 WV 13 64,771 10,946 16.90% 21.50% 13,9251 9 WY 8 69,736 19,732 28.30% 24.00% 16,73

Summary: 

Total 464 429 6,076,410 1,541,854 25.37% 24.70% 1,480,8

4.1% 

 Min= 16.90% 21.50%  Max= 35.48% 30.90% 

Extrapolated to 495 plants = 

Step 5: The percentage of children population surrounding the plant ZCTAs were compared to overall state pe

nationwide percentage of this sub-group population, by calculating ratios between the plant ZCTA chi

compared to statewide and nationwide percentages of children population. Exhibit 7K below display

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 
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 
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 

• Child Population Data Findings 

Below is a summary of the three alternative but complementary comparison approaches based on the same children pby-plant (i.e., itemized ZCTA) basis, (b) nationwide aggregation basis, and (c) state-by-state aggregation basis. For p

relative degree by which children may exceed these statewide percentages, the percentages are compared as a numeri

of 1.00 indicates that the child population percentage living near a plant is equal to the statewide average, a ratio greachild population percentage near the plant is higher than the statewide population, and a ratio less than 1.00 indicates less than the respective statewide average.

• General population findings 

o 464 plants (i.e., 94% of the 495 universe) for which Census plant address ZCTA data are located i

o The plant address ZCTA population surrounding these plants is 6.08 million, which is an average 

population per plant. 

• 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 

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

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 ad

the statewide percentages. 

o States with the largest difference in the children population between the ZCTAs where the plants 

the statewide percentages are as follows: 

1. Oregon (36% vs. 23%) 
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 respect

• Plant level results: 

Using the plant-by-plant (i.e. itemized ZCTA) basis, 310 plants (63%) have surrounding child populations which exc

children benchmark percentages, whereas 185 plants (37%) have children populations below their statewide benchmaplant ZCTA ratio of 1.68 (i.e., 310/185). Since this ratio is much greater than 1.00, this finding indicates that a highly plants have surrounding child population percentages which exceed their statewide benchmark. 

• State level results: 

Using the state-by-state aggregation basis, the percentage of child populations surrounding the plants were compared 

statewide population benchmarks. The state-by-state ratios revealed that approximately 27 of the 47 states (57%) havpercentages of children within the plant address ZCTA compared to the rest of the state suggesting a disproportionate 

population. However, in comparison to the other two numerical comparisons above, this state-by-state count approacnumerically-weighting of state plant counts or state surrounding populations, which explains why this comparison menumerical result. This method illustrates how population comparison results may be sensitive to the comparison meth

• Nationwide results: 

Using the nationwide aggregation basis across all 495 plants in all 47 states where the plants are located, 6.08 million surrounding the plants, which include a sub-total of 1.54 million children (25.4%). Comparison of this percentage to benchmark across all states of 24.7% children yields a ratio of 1.03 (i.e., 25.4%/24.7%). This ratio indicates a slightl

child population surrounding the 495 plants. Comparison of the nationwide child population sub-total for all plants radditional children reside near the plants, compared to the expected child population if based on state averages (i.e., 1near 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 

CCR disposal units, and the expected future benefits of the regulatory options, may have a disproportionately higher populations. 
7E. Unfunded Mandates (UMRA) & Federalism Implications Analysis (Executive Order 131

• UMRA 

Among its other purposes and Federal agency rulemaking requirements, Title II of the 1995 Unfunded Mandates Ref

U.S.C. 1531-1538), requires Federal agencies, unless otherwise prohibited by law, to assess the effects of their regulalocal, and tribal governments and on the private sector, to determine whether any proposed rulemaking: 

 “...is likely to result in promulgation of any rule that includes any Federal mandate that may result in the explocal, and tribal governments, in the aggregate, or by the private sector, of $100 million or more in any one y

Section 202 of UMRA requires Federal agencies which propose rules that are likely to exceed this $100 million expe

the private sector or on state/local/tribal governments, to prepare a “Written Statement” containing the following five the Written Statement to OMB as well as summarize it in the Federal Register notice (aka “preamble”) for the propos

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 

and tribal governments or the private sector, and an analysis of whether Federal resources may be available to 

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 creatio

competitiveness 

5. Description and summary of agency’s prior consultation with elected representatives of the affected State, loc

Section 202 of UMRA allows Federal agencies to prepare the “Written Statement “in conjunction with or as a part of 

analysis. Accordingly, the purpose of this section of the RIA is to determine whether the regulatory options evaluate

UMRA direct cost threshold. Findings: The private sector and the state/local government shares of direct compliance costs under each option 

Exhibit 7L, which indicates that: 

 Private sector cost test: All of the regulatory options are expected to result in expenditures of $

aggregate for the private sector, in any one year (i.e., 139 companies and cooperatives of the to

 State/local/tribal government cost test: None of the regulatory options are expected to result in 

million or more for State, local, and tribal governments in the aggregate in any one year (there 

government owner entities identified in Exhibit 7M below, no known tribal owner entities, plu

According to the private sector test finding, EPA has prepared an “UMRA Written Statement” which is attached to th
• Federalism (Executive Order 13132) 

The 1999 Federalism Executive Order 13132 (Federal Register, Vol.64, No. 153, 10 Aug 1999) furthers the policies o

Mandates Reform Act (UMRA) by establishing federalism principles, federalism policymaking criteria, and a state/lo

consultation process for the development of Federal regulations that have federalism implications. Federalism implicregulations and other Federal policies and actions that have substantial direct effects on states, on the relationship bet

government and the states, or on the distribution of power and responsibilities among the various levels of governmen

For purpose of complying with the Section 6 consultation process of EO 13132, this section of the RIA evaluates whe

options may “impose substantial direct compliance costs” on state/local governments. As summarized in Exhibit 7L

impose four types of direct costs on the 60 state/local government owner entities identified in Exhibit 7M below: 

• State/local government owned electric utility plants: 

1. Engineering control costs for CCR disposal units located at electric utility plants owned by state/local gov

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/

• State government environmental agencies: 

4. Regulatory implementation, administration, and enforcement costs to RCRA-authorized state government 

Consistent with the “direct cost” scope of EO 13132, not included in Exhibit 7L are potential indirect costs in the forrevenues to electricity plants associated with potential reductions in CCR sold by plants for beneficial use under the twhich 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 ev

rule may have federalism implications with respect to “substantial direct compliance costs”: 

1. $25 million test: Annualized direct compliance cost expenditures to state/local governments in aggregate of $2

2. 1% test: Annualized direct compliance costs faced by state/local governments is likely to equal or exceed 1% 

[* Note: Page 29 of “Attachment A: Guidance for Implementing the Federalism 1% Test” to EPA’s Nov 2008 Order 13132: Federalism” defines small government “general revenue” as “made up of intergovernmental revtheir own sources and excludes utility, liquor store and employee retirement revenue.” However, given that th

affects electric utility industry, this RIA applies the “1% Test” in relation to only State/local government elect

194 The two methods are from page 6 of “EPA’s Action Development Process -- Guidance on Executive Order 13132: Federalism,” OPEI Re

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 “to further the policies of the 1995 Unfunded Mandates Reform 

million annual direct cost trigger is 75% lower than the $100 million annual direct cost trigger prescribed in Section 202 of UMRA. 
• 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 regulato

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/loc

o Federalism finding: All options >$25 million state/local government test; all options <1% state/loca

However, for consistency with the RFA/SBREFA small business impact analysis presented in a separate section abovestimates it is highly likely that the direct compliance costs under each option may be passed-thru to electricity plant higher electricity prices. The feasibility of such a compliance cost pass-thru scenario is evaluated and confirmed by t

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) 

SubtitSubtit

Average annualized cost (source: Exhibit 5F): $2,274 $492 UMRA Test: 1. Private sector $100 million direct cost threshold test $1,999.4 $415.3 2. State/local government $100 million direct cost threshold test* $96.7 $55.9 Federalism Test: 1. $25 million threshold test: sub-total State/Local govt cost $96.7 $55.9 2. 1% Test: State/local govt cost as percentage of State/Local government electric utility annual revenues 

0.227% 0.131% 

* Note: Remainder Federal government costs represent costs associated with Federally-owned electric utility plants (i.e., Tennessee Valley Au

subject to either the UMRA or Federalism tests. Therefore, the sub-total private sector direct cost plus the state/local government direto the total annual cost estimate under each option; the remainder cost is for the Federally-owned plants. 
Exhibit 7M 

List of 74 Coal-Fired Electric Utility Generation Plants Which EPA Estimates Are Owned by 60 State/Local Gov

Source: Compiled by EPA-OSWER-ORCR based on 2007 data from the US Energy Information Administratio

Item Owner Entity Name Electric Utility Plant Name State 

O

S

1 Grand River Dam Authority GRDA OK Non2 Lower Colorado River Authority Fayette Power Project TX Non3 Nebraska Public Power District Gerald Gentleman NE Non4 Nebraska Public Power District Sheldon NE Non5 Omaha Public Power District Nebraska City NE Non6 Omaha Public Power District North Omaha NE Non7 Platte River Power Authority Rawhide CO Non8 Salt River Project Coronado AZ Non9 Salt River Project Navajo AZ Non

10 South Carolina Pub Service Auth Cross SC Non11 South Carolina Pub Service Auth Dolphus M Grainger SC Non12 South Carolina Pub Service Auth Jefferies SC Non13 South Carolina Pub Service Auth Winyah SC Non14 American Municipal Power-Ohio, Inc Richard Gorsuch OH Non15 Ames City of Ames Electric Services Power Plant IA Non16 City of Columbia Columbia MO Non17 City of Hamilton Hamilton OH Non18 City of Lakeland C D McIntosh Jr FL Non19 City of Owensboro Elmer Smith KY Non20 City of Springfield Dallman IL Non21 City of Springfield Lakeside IL Non22 City Utilities of Springfield James River Power Station MO Non23 City Utilities of Springfield Southwest Power Station MO Non24 Colorado Springs City of Martin Drake CO Non25 Colorado Springs City of Ray D Nixon CO Non26 Gainesville Regional Utilities Deerhaven Generating Station FL Non27 Independence City of Blue Valley MO Non28 Independence City of Missouri City MO Non29 JEA Northside Generating Station FL Non30 JEA St Johns River Power Park FL Non31 Kansas City City of Nearman Creek KS Non32 Kansas City City of Quindaro KS Non33 Lansing Board of Water and Light Eckert Station MI Non34 Lansing Board of Water and Light Erickson Station MI Non35 Los Angeles City of Intermountain Power Project UT Non36 Orlando Utilities Comm Stanton Energy Center FL Non37 Rochester Public Utilities Silver Lake MN Non
Exhibit 7M 

List of 74 Coal-Fired Electric Utility Generation Plants Which EPA Estimates Are Owned by 60 State/Local Gov

Source: Compiled by EPA-OSWER-ORCR based on 2007 data from the US Energy Information Administratio

Item Owner Entity Name Electric Utility Plant Name State 

O

S

38 San Antonio City of J K Spruce TX Non39 San Antonio City of J T Deely TX Non40 Vineland City of Howard Down NJ Non41 Crisp County Power Comm Crisp Plant GA Sma42 Austin City of Austin Northeast MN Sma43 Board of Water Electric & Communications Muscatine Plant #1 IA Sma44 Cedar Falls Utilities Streeter Station IA Sma45 City of Dover Dover OH Sma46 City of Grand Haven J B Sims MI Sma47 City of Holland James De Young MI Sma48 City of Jasper Jasper 2 IN Sma49 City of Logansport Logansport IN Sma50 City of Marquette Shiras MI Sma51 City of Marshall Marshall MO Sma52 City of Menasha Menasha WI Sma53 City of Orrville Orrville OH Sma54 City of Painesville Painesville OH Sma55 City of Richmond Whitewater Valley IN Sma56 City of Shelby Shelby Municipal Light Plant OH Sma57 City of Sikeston Sikeston Power Station MO Sma58 City of Virginia Virginia MN Sma59 Crawfordsville Electric Light & Power Crawfordsville IN Sma60 Fremont City of Lon Wright NE Sma61 Grand Island City of Platte NE Sma62 Greenwood Utilities Commission Henderson MS Sma63 Hastings City of Whelan Energy Center NE Sma64 Henderson City Utility Commission Henderson I KY Sma65 Hibbing Public Utilities Commission Hibbing MN Sma66 Jamestown Board of Public Utilities S A Carlson NY Sma67 Manitowoc Public Utilities Manitowoc WI Sma68 Michigan South Central Power Agency Endicott Station MI Sma69 New Ulm Public Utilities Commission New Ulm MN Sma70 Pella City of Pella IA Sma71 Peru City of Peru IN Sma72 Texas Municipal Power Agency Gibbons Creek TX Sma73 Willmar Municipal Utils Commission Willmar MN Sma74 Wyandotte Municipal Service Commission Wyandotte MI Sma
Exhibit 7M (Continued) 

List of 74 Coal-Fired Electric Utility Generation Plants Which EPA Estimates Are Owned by 60 State/Local Gov

Source: Compiled by EPA-OSWER-ORCR based on 2007 data from the US Energy Information Administratio

Footnotes: * NAICS code 22 electric “utility” 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 

type of ownership. Size class determined according to the following numerical criteria consistent with EPA’s Nov 2006 guiRegulatory 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 siz<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 “small government jurisdiction

government of a city, county, town, township, village, school district, or special district with a population less than • Non-small government = Entity’s jurisdiction population with more than 50,000 people.