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Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

Regulatory Impact Analysis

EPA’s 2015 RCRA Final Rule

Regulating Coal Combustion Residual (CCR)

Landfills and Surface Impoundments

At Coal-Fired Electric Utility Power Plants

U.S. Environmental Protection Agency (EPA)

Office of Resource Conservation and Recovery (ORCR)

1200 Pennsylvania Avenue NW (Mailstop 5305P)

Washington DC, 20460 USA

OctoberDecember 2014
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Table of Contents

Acronyms ...................................................................................................................................... iii

Acknowledgements..........................................................................................................................v

Foreword........................................................................................................................................ vi

Executive Summary...................................................................................................................ES-1

ES.1 Overview ............................................................................................................ES-1

ES.2 Overview of the CCR Final Rule .........................................................................ES-2

ES.3 Summary of Estimated Regulatory Costs and Benefits for the CCR Rule ........ES-43

ES.4 Cost and Benefit Estimation Uncertainties ........................................................ES-11

ES.5 Other Regulatory and Distributional Issues .....................................................ES-12

Chapter 1: Background and Problem Statement: The Need for EPA Regulation of CCR

Landfills and CCR Surface Impoundments................................................................................. 1-1

1.1 Purpose of this Chapter............................................................................................. 1-1

1.2 EPA’s Prior Activities Addressing CCR Management (1978-2014) ....................... 1-2

1.3 Need for EPA Regulation of CCR Landfills and CCR Impoundments.................... 1-8

1.4 Summary of Public Comments on EPA’s 2010 CCR Proposed Rule RIA ........ 1-1819

Chapter 2: Affected Universe and Analytic Framework for the RIA......................................... 2-1

2.1 Directly Affected Industries...................................................................................... 2-1

2.2 Indirectly Affected Industries................................................................................... 2-6

2.3 Affected Electric Utility Plants................................................................................. 2-8

2.4 Analytic Framework for the RIA............................................................................ 2-26

Chapter 3: Baseline CCR Management in the Electric Utility Industry..................................... 3-1

3.1 Baseline CCR Management Practices and CCR Regulations................................... 3-1

3.2 Baseline CCR Management Cost Estimation ......................................................... 3-14

3.3 Baseline CCR Disposal Cost Estimation Results ................................................... 3-43

Chapter 4: Estimated Costs for the CCR Rule............................................................................ 4-1

4.1 Description of the Final CCR Rule and Cost Estimation Methodology................... 4-1

4.2 CCR Pollution Control Cost Elements ................................................................... 4-15

4.3 Summary of CCR Final Rule Regulatory Costs..................................................... 4-38

Chapter 5: Monetized Benefits ................................................................................................... 5-1

5.1 Avoided CCR Impoundment Releases ..................................................................... 5-6

5.2 Avoided Groundwater Contamination by CCR Surface Impoundments............ 5-1718

5.3 IncreasedInduced Increase in Future Annual CCR Beneficial Use .................... 5-2224

5.4 Reduced Incidence of Cancer ............................................................................. 5-2930

5.5 Mitigated IQ Losses from Mercury .................................................................... 5-3132

5.6 Reduced Lead Exposure ..................................................................................... 5-3133

5.7 Reduced Need for Specialized Education........................................................... 5-3234

5.8 Non-Market Benefits from Surface Water Quality Improvements..................... 5-3334

5.9 Protection of Threatened and Endangered Species............................................. 5-3435

5.10 Improved Air Quality........................................................................................ 5-3536
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5.11 Reduced Groundwater Withdrawals.....................5-36 from Conversion to Dry CCR 

Handling......................................................................................................................... 5-37

5.12 Conclusion ......................................................................................................... 5-3738

Chapter 6: Non-Monetized (Qualitative) Benefits...................................................................... 6-1

6.1 ReduceReduced Community Nuisance and Human Health Impacts from Fugitive 

CCR 

Dust.................................................................................................................................. 6-2

6.2 Financial Investment Benefit for the Electric Utility Industry ................................. 6-3

6.3 ReduceReduced Hazard Dread of Citizens Residing Near CCR Impoundments... 6-67

6.4 ReduceReduced Cancer and Non-Cancer Health Effects Resulting from 

Recreational Water Use ................................................................................................. 6-67

6.5 ReduceReduced Sediment Contamination ............................................................. 6-78

6.6 ReduceReduced Water Treatment Costs for Drinking and Irrigation Water.......... 6-89

6.7 ImproveImproved Commercial Fishing Yields and Harvest Quality................... 6-810

6.8 Increased Participation in Water-Based Recreation ............................................. 6-910

6.9 ReduceReduced Fish Impingement and Entrainment Mortality........................... 6-911

6.10 Increased Property Values Surrounding Electric Utility Plants......................... 6-1011

Chapter 7: Evaluation of Uncertainty for Cost and Benefit Estimates....................................... 7-1

7.1 Key Cost Uncertainties............................................................................................. 7-2

7.2 Key Benefit Uncertainties....................................................................................... 7-18

7.3 General Uncertainties: Compliance and Cost Data Limitations............................. 7-21

7.4 Specific Data Uncertainty Factors in this RIA ....................................................... 7-25

7.5 Summary of Uncertainty Factors............................................................................ 7-26

Chapter 8: Other Required Analyses .......................................................................................... 8-1

8.1 Electricity Price and Energy Market Impacts........................................................... 8-1

8.2 Small Business Impact Analysis (RFA/SBREFA) ................................................... 8-2

8.3 Demographic Analysis: Minority and Low-Income Population Statistics 

 (Executive Order 12898)........................................................................................... 8-8

8.4 Child Population Statistics (Executive Order 13045)............................................. 8-12

8.5 Unfunded Mandate Reform Act (UMRA) and Federalism Implications Analysis 

 (Executive Order 13132)......................................................................................... 8-14

Chapter 9: Updates to Assumptions, Data, and Rule Requriements: Final Cost and Benefit 

Estimates for the CCR Final Rule................................................................................................ 9-1

9.1 Overview of Modifications to the RIA ..................................................................... 9-1

9.2 Seven Technical Revisions to Assumptions and Data Applied in Other Chapters of 

the RIA............................................................................................................................. 9-3

9.3 Changes to Final CCR Rule Requirements: Compliance Alternative Closure 

Requirements for Leaking Unlined CCR Impoundments.............................................. 9-18

9.4 Updated Cost & Benefit Results for CCR Final Rule............................................. 9-25

9.5 Summary of the Cost and Benefits of the CCR Final Rule ................................ 9-3350

9.6 Sensitivity Analyses Related to Plants Fully Closing Coal-Fired Boilers Prior to 

and After 2015 ........................................................................................................... 9-3451
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9.7 Supplemental Analyses....................................................................................... 9-4057
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Acronyms

ACAA American Coal Ash Association

AEO Annual Energy Outlook

ASTSWMO Association of State and Territorial Solid Waste Management Officials

BCR Benefit-Cost Ratio

CAA Clean Air Act

CBI Confidential Business Information

CCR Coal Combustion Residual(s)

CDC Centers for Disease Control and Prevention

CERCLA: Comprehensive Environmental Response, Compensation, and Liability 

Act

CESQG Conditionally Exempt Small Quantity Generator

CFR Code of Federal Regulations

CMS Corrective Measures Study

COI Cost of Illness

CSAPR Cross-State Air Pollution Rule

CWA Clean Water Act

CY Cubic Yards

DOE Department of Energy

ECHOS Environmental Cost Handling Options and Solutions

EIA Energy Information Administration

EJ Environmental Justice

ELG Effluent Limitation Guidelines (see SPGELG)

EO Executive Order

EPA Environmental Protection Agency

EPRI Electric Power Research Institutes

ESP Electrostatic Precipitator

FERC Federal Energy Regulatory Commission

FGD Flue-Gas Desulfurization

FR Federal Register

GAO Government Accountability Office

ICR

IPM

Information Collection Request

Integrated Planning Model

KWH Kilowatt Hours

LDR Land Disposal Restriction

LF Landfill

LQG Large Quantity Generator

MATS Mercury and Air Toxics Standards

MSHA Mine Safety and Health Administration

MSW Muncipal Solid Waste

MW Megawatt(s)

NAAQS National Ambient Air Quality Standards

NAICS North American Industry Classification System

NERC

NEEDS

North American Electric Reliability Corporation

National Electric Energy Data System
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NODA Notice of Data Availability

NPDES National Pollutant Discharge Elimination System

NRC National Response Center

NRD Natural Resource Damages

O&M Operations and Maintenance

OMB Office of Management and Budget

ORCR Office of Resource Conservation and Recovery

OSMRE Office of Surface Mining Reclamation and Enforcement

OSRTI Office of Superfund Remediation and Technology Innovation

OSW Office of Solid Waste

OW Office of Water

P&T Pump-and-Treat

PCD Pollution Control Device

PGA Peak Ground Acceleration

PM Particulate Matter

PRB Permeable Reactive Barrier

PUC Public Utility Commission

RACER Remedial Action Cost Engineering and Requirements

RCRA Resource Conservation and Recovery Act

RFA Regulatory Flexibility Act

RFI RCRA Facility Investigation

RFSA Regulatory Flexibility Screening Analysis

RIA Regulatory Impact Analysis

RQ Reportable Quantity

RTC Report to Congress

RTI Research Triangle Institute

SBA Small Business Administration

SBREFA Small Business Regulatory Enforcement Fairness Act

SI Surface Impoundment

SIP State Implementation Plan

SISNOSE Significant Economic Impact on a Substantial Number of Small Entities

SMCRA Surface Mining Control and Reclamation Act

SPGELG Steam Power Generator Effluent Limitation Guidelines

SQG Small Quantity Generator

SWDA Solid Waste Disposal Act

TVA Tennessee Valley Authority

UMRA Unfunded Mandates Reform Act

USGS United States Geological Survey

USWAG Utility Solid Waste Activities Group 

VSL Value of a Statistical Life

WTP Willingness to Pay
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Acknowledgements

This regulatory impact analysis (RIA) updates and revises the April 30, 2010 RIA that EPA’s Office of 

Resource Conservation and Recovery (ORCR) completed in support of ORCR’s June 21, 2010 proposed 

RCRA regulation of coal combustion residual (CCR) landfills and surface impoundments at coal-fired 

electric utility power plants.

The April 2010 RIA (242 pages) and its companion “Appendices” document (443 pages) are available as 

document ID nr. EPA-HQ-RCRA-2009-0640-0003 from the federal regulatory docket at 

http://www.regulations.gov

This RIA updates and revises the April 2010 RIA by:

 Addressing 2010 public comments: Addresses limitations of the data and certain 

methodologies noted by public commenters on the 2010 RIA for the CCR proposed rule.

 Harmonizing with another EPA rule: Harmonizes certain cost and benefit elements of this 

RIA which are common elements in the RIA and economic analysis for EPA Office of 

Water’s June 7, 2013 proposed “Steam Electric Power Generating Effluent Limitations 

Guidelines” (ELG) rulemaking (a rule which would also affect coal-fired electric utility 

plants with surface impoundments).

 Updating affected entity data: The April 2010 RIA was founded largely on 2005 and 

2007 inventory data on coal-fired electric utility plants and associated CCR management 

practices (i.e., annual CCR tonnages generated, disposed, stored, sold, shipped) published 

by the Energy Information Administration (EIA) of the US. Department of Energy. This 

RIA is based on EIA’s more recent 2012 data.

 Single regulatory option: Whereas EPA’s RIA for the 2010 proposed CCR rule evaluated 

three alternative regulatory approaches (i.e., Subtitle C special waste, Subtitle D nonhazardous wate, and D-Prime approaches), this RIA only evaluates the single regulatory 

approach (i.e., Modified D-Prime) selected for the CCR final rule.

Between 2010 and 2014 under five consecutive work assignments, Industrial Economics Incorporated 

(IEc), with sub-contracting assistance from DPRA Incorporated, RTI International, Avenue C Advisors, 

Dr. Matthew Kocoloski, and GZA GeoEnvironmental Inc. provided analytic support for this RIA:

 2010: WA 3-33 (contract EP-W-07-011)

 2011: WA 4-33 (contract EP-W-07-011)

 June 2012 to April 2013: WA B-06 (contract EP-W-12-013)

 May 2013 to April 2014: WA 1-06 (contract EP-W-12-013)

 May 2014 to Dec 2014: WA 2-06 (contact EP-W-12-013)

Mark Eads, EPA ORCR Economist, was the EPA Contract Officer Technical Representative (COTR) for 

the work assignments. Other EPA staff assisting with data processing, analysis, and review of prior drafts 

of this RIA, include (in alphabetical order): Alan Barnosky, Richard Benware, Lee Hofmann, Rachel 

Horton, Mark J. Huff, and Amy Newman of ORCR, as well as Sharon Cooperstein, Chris Dockins, Robin 

Jenkins, Kelly Maguire, William Nickerson, and Sarah Rees of EPA’s Office of Policy.

EPA submitted an October 2014 draft of this RIA to the Office of Management & Budget (OMB) for 

Federal inter-agency review according to the requirements set forth in Section 6 of the 1993 Executive 

Order 12866 “Regulatory Planning and Review.”
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Foreword:

Key Updates to RIA Assumptions, Data and Rule Requirements

This RIA contains benefits, costs, and impacts estimates for the CCR final rule. In the two 

months just prior to the deadline for submission of this RIA, important modifications were made 

to assumptions, data, and rule requirements. As part of the ongoing work to complete this 

analysis, important modifications were made to assumptions, data, and rule requirements late in 

the process. Each modification to analytic assumptions and data reflected the most recent and 

appropriate information available. Rule requirements were adjusted to allow two alternative 

closure requirements to schedules due to special issues related to the closure of leaking, unlined 

CCR impoundments and to the closure of impoundments that do not meet the location 

restrictions in the rule. In order to provide the best estimates possible, EPA determined that 

adjusting the benefit and cost estimates to reflect the updated assumptions, data, and rule 

requirements was essential. EPA’s court-ordered deadline for the CCR final rule precluded 

revising the entire RIA and its Appendices (which are over 700 pages). 

While the full RIA could not be revised, incremental benefits and costs were re-estimated to 

incorporate this new information. The new estimates are presented in both the Executive 

Summary and in Chapter 9. 

Other chapters of this RIA are not fully updated to reflect these changes, but the sections where 

assumptions, data, or methods were subsequently changed are clearly indicated throughout. 

Those indications include the locations in Chapter 9 where relevant revisions can be located.

An important purpose of Chapter 9 is to describe in detail the nine necessary modifications to the 

RIA to reflect updated assumptions and data, and regulatory requirements. These fall into two 

categories: (1) seven updates to assumptions and data; and, (2) two updates to rule requirements.

Seven updates are to assumptions and data that do not otherwise involve changes to the 

methodology or modeling approaches described in prior chapters of this RIA:

1. Revised universe of coal-fired electric utility plants affected by the CCR final rule: 

o Removes plants identified as already retired or planning to retire in the National 

Electric Energy Data System (NEEDS) v.5.13 dataset.

o More accurate reflection of plants affected by regulatory requirements.

o More information in Chapter 2 and Section 9.2.1

2. Revised projections of future annual change in coal consumption: 

o AdoptsReplaces the Energy Information Administration (EIA) 2014 Annual Energy 

Outlook (AEO) Reference case 2015-2040 forecast of coal consumption for 

electricity generation described in Chapter 2, with the base case projection of future 

2014-2050 coal consumption for electricity generation for future estimates of CCR 

tonnage generation over time as EPA’sfrom EPA's power sector modeling platform 

v.5.13 (developed for application of the Integrated Planning Model (IPM)).
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o Replaces the Energy Information Administration (EIA) 2014 Annual Energy Outlook 

(AEO) Reference case forecast described in Chapter 2.

o This change is made for purpose of harmonizing the coal consumption forecast 

applied in this RIA, with the RIAs and economic analyses for other EPA rules which 

also affect the electric utility industry.

o More information in Chapter 2 and Section 9.2.2

3. Adjusted scaling factor for CCR quantities managed in storage impoundments: 

o Revises the estimated tonnage of CCR managed in storage (dredged) impoundments.

o Reflects updated information from EPA’s Office of Water RIA for its Steam Electric 

Power Generation Effluent Limitation Guidelines (SPGELG) June 2013 proposed 

rule about the distribution of CCR impoundments receiving and treating different 

types of coal ash.

o More information in Sections 3.2.4.3 and 4.1.3, and Section 9.2.3

4. Adjustments to CCR beneficial use impacts: 

o Reflects the changes in annual CCR disposal tonnage associated with the revisions to 

the universe of coal-fired electric utility plants described in (1) and (2), above. 

o Revised per-ton benefits estimates to use unadjusted values from published study by 

Fann, et al. (2009) consistent with Agency practice. This estimate is used to value 

reductions in the use of virgin materials and avoided health impacts from criteria 

pollutant emission.

o More information in Section 5.3 and Section 9.2.4 

5. Revised adjustment factors to scale common set of benefits from SPELG proposed rule

o This RIA shares a common subset of benefits with the 2013 SPELG proposed rule 

and adopts a set of adjustment factors are used to scale and harmonize these common 

benefits.1

o These factors have been revised to reflect different analytical assumptions in the CCR 

RIA compared to the SPELG RIA regarding storage impoundments. To account for 

the continuation of storage impoundment operation under the CCR rule, there is a 

downward adjustment of SPELG benefits by 12%.

o More information in Sections 5.4 through 5.11, and Section 9.2.5

6. Adjustments to CCR impoundment release projections: 

o Revises the post-rule probability of a wall breach release to a more appropriate 

published source rather than relying on an estimate based on averaging multiple 

sources, some of which were lower quality.

o Revises assumption that the rule will reduce all “other release” events by dropping 

seepage events from the population, and assuming the rule will not affect release 

events due to certain causes. 

o Assumes the rule will not reduce the capacity factors associated with release events. 

All of these changes reflect more conservative benefit estimates.

o More information in Section 5.1 and Section 9.2.6

 

1 For a discussion of why scaling of SPELG’s benefits is appropriate, see pages 5-1 and 5-2 of Chapter 5.
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7. Revised social cost of carbon (SCC): 

o Adoption of the Federal interagency more recent November 2013 revised social cost 

of carbon (SCC) applied to the CCR beneficial use benefit monetization, in place of 

the May 2013 version of the SCC applied in Chapter 5.

o More information in Sections 5.3 and Section 9.2.7

Two additional updates are described in detail in Chapter 9. They reflect substantive changes in 

the CCR final rule that provide two alternative closure requirements for certain subsets of 

electric utility plants with leaking unlined CCR impoundments and impoundments that fail to 

meet the rule’s location standards. These updates require modifications to the decision logic of 

the cost estimation model and to related benefits.

8. Alternative Closure Requirement #1: 10-year extension of time for initiating closure of 

surface impoundments at plants that lack alternative disposal capacity:

o For plants that certify a lack of alternative CCR disposal capacity, a 10-year extension 

(2028) for initiating closure for leaking, unlined CCR impoundments.

o Delays the date when closure costs begin for these plants compared to the 2019 date 

applied in the RIA.

o Revised analysis shifts 10 years out to 2028 the leaking unlined impoundment closure 

costs estimated in the RIA for this sub-set of eligible plants.

o More information in Section 9.3.1

9. Alternative Closure Requirement #2: 5-year extension of time for closure of surface 

impoundments at plants that certify future plans to cease burning coal permanently cease 

operations of coal-fired generating units. 

o Allows 5-year extension (2023) for initiating closure for leaking, unlined CCR 

impoundments, 

o Delays the date when closure costs begin compared to the 2019 date applied in the 

RIA. 

o Impact of this alternative closure requirement presented only as a sensitivity analysis 

due to uncertainty regarding the universe of plants which may cease operations and 

avail themselves of this alternative closure requirement, and due to multiple modeled 

impacts for firms with plans to retire.

o More information in Section 9.3.2 and 9.6. 

Except for these modifications and the associated results, which are specifically described in 

Chapter 9, the original data, assumptions, and methods described in chapters 1 through 8 of this 

RIA, and associated appendices, remain accurate.

As a result of updating the assumptions, data, and rule requirements, EPA wished to more fully 

understand their impact on the benefit, cost, and economic impacts of the CCR rule. Thus, 

Chapter 9 fulfills three additional purposes. First, it (and the Executive Summary) summarize the 

updated benefit and cost estimates by specific categories, at different discount rates, and in 

present values and annualized terms. It compares the updated estimates to those appearing in the 

remainder of the RIA. Second, Chapter 9 presents sensitivity analyses related to the updated 

assumptions. Third, the chapter includes updates to four supplemental analyses in Chapter 8 of 
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the RIA (the Federalism analysis, the small business impacts analysis, the demographic analysis 

of low-income and minority populations, and the demographic analysis of child populations)., as 

well as state-by-state incremental costs and benefits of the rule.

EPA believes that the original (non-updated) analyses in the RIA and associated appendices still 

apply in direction and may still apply in proportion. For example, the rationale for cost 

uncertainty bounds is unchanged and thus the original results in the RIA are still informative.
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Executive Summary 

Note: In the two months just prior to the deadline for submission of this RIA, important 

modifications were made to assumptions, data, and rule requirements. As part of the 

ongoing work to complete this analysis, important modifications were made to assumptions,

data, and rule requirements late in the process. Each modification to analytic assumptions 

and data reflected the most recent and appropriate information available. Rule 

requirements were adjusted to allow two alternative closure requirements to schedules due 

to special issues related to the closure of leaking, unlined CCR impoundments and surface 

impoundments that don’t meet the location restrictions of the rule. In order to provide the 

best estimates possible, EPA determined that adjusting the benefit and cost estimates to 

reflect the updated assumptions, data, and rule requirements was essential, thus EPA has 

updated these estimates in this Executive Summary. However, to meet the court-ordered 

schedule for EPA’s development and promulgation of the CCR final rule, EPA was unable to 

modify and recalculate all estimates throughout this RIA to reflect the updated data or other 

information. EPA has updated the regulatory cost and benefit exhibits of this Executive 

Summary, but EPA was unable to make conforming modificiations to Chapters 2, 3, 4, 5, 7, 

and 8 of this RIA, and to all associated RIA appendices. Text boxes in those chapters indicate 

which sections EPA subsequently updated, and which analyses in each chapter are affected 

by those updates. Chapter 9 of this RIA gives a detailed explanation of the data, information, 

and analyses that were updated.

ES.1 Overview 

The Environmental Protection Agency (EPA or Agency) is publishing a final rule to regulate the 

management of coal combustion residuals (CCR) as solid waste under Subtitle D of the Resource 

Conservation and Recovery Act (RCRA). This regulatory impact analysis (RIA) is prepared as 

required under the 1993 Executive Order 12866 “Regulatory Planning and Review” and 2011 

Executive Order 13563 “Improving Regulation and Regulatory Review,” and consistent with the 

White House Office of Management and Budget’s (OMB) 2003 “Circular A-4: Regulatory 

Analysis.”

This RIA presents an assessment of the future expected social benefits and costs for the CCR 

final rule, and provides a range of supporting analyses and information that address the unique 

analytic requirements of assorted Executive Orders and federal statutes, as well as sensitivity 

analyses of key uncertainty factors for the benefit and cost estimates. The RIA includes the 

following sections: 

 Chapter 1 describes the justification for the CCR rule (problem statement);

 Chapter 2 summarizes the industrial sectors and facilities affected by the rule, 

and presents an overview of the methodology used in the RIA;

 Chapters 3 and 4 identify baseline and incremental costs of the rule, 

respectively;

 Chapters 5 and 6 present monetized and qualitative benefits of the rule, 

respectively;

 Chapter 7 describes key uncertainties in the RIA and provides sensitivity 

analyses for each;
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 Chapter 8 examines other economic impacts of the rule, as required by federal 

statutes and Executive Orders; and 

 Chapter 9 presents a revised set of future costs and benefits estimates for this 

RIA, based on several modifications to the requirements of the CCR final rule, the 

analytical assumptions underpinning the analysis of this RIA, and parameter 

estimates used in this RIA. The modifications are based on updated information 

that only became available near the end of, or after, production of the previous 

chapters of the RIA.

The CCR final rule is founded on the RCRA Subtitle D solid waste regulatory authority, and is a 

modified version of the D-prime regulatory approach considered for public comment in the June 

2010 proposed CCR rule.

2 This RIA evaluates only the modified D-prime approach EPA 

selected for the CCR final rule.

ES.2 Overview of the CCR Final Rule

The CCR final rule establishes minimum national criteria regulating the accumulation of CCR in 

landfills and surface impoundments at coal-fired electric utility plants operating as of its 

effective date. In this rule, EPA is establishing the minimum requirements necessary to ensure 

the safe accumulation of CCRs in these units.

EPA is regulating CCR in order to: respond to public petitions (2004, 2009) to EPA and 

Congressional requests (2010) for EPA regulation of CCR disposal; EPA is regulating CCR in 

order to respond to public petitions (2004, 2009) to EPA for EPA regulation of CCR disposal to:

prevent continuedreduce CCR contamination of groundwater and surface water; preventreduce

future CCR impoundment structural failures (breakages); reduce continued public exposure to 

CCR fugitive dust; and correct negative externalities and inadequate and asymmetric information 

about CCR disposal risks.

Specifically, the CCR final rule regulates CCR under RCRA Subtitle D as a non-hazardous 

waste. The rule includes standardized CCR pollution control and other requirements for CCR 

landfills and CCR surface impoundments. In addition, the rule allows CCR surface 

impoundments to operate indefinitely unless an unlined leaking impoundment’s groundwater 

chemical constituent sampling analysis is found to exceed health-based thresholds. Unlined CCR 

impoundments with chemical constituent sampling analyses exceeding health-based thresholds

are required to retrofit to install a composite liner, or to close within five years of the date on 

which the exceedance is determined (unless power plants certify for compliance deadline 

flexibility). All CCR landfills and impoundments will be subject to groundwater monitoring and to 

groundwater contamination clean-up corrective action.

Under the final CCR rule, existing and future new CCR landfills, existing and future new CCR 

surface impoundments, and all future lateral expansions of both types of units will be subject to, 

among other things, location restrictions, design and operating criteria, groundwater monitoring, 

closure requirements, and post-closure care. Specifically, under this rule, Subtitle D requirements 

 

2 EPA’s June 21, 2010 Federal Register notice (Vol. 75, No. 118, pages 35128 to 35264) of the proposed CCR rule 

presented the “D-prime” approach on pages 35134, 35149, and 35210.
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will set national criteria for landfills and surface impoundments that manage CCR after the final 

rule goes into effect in early 2015, the effective date assumed for this RIA. Groundwater 

monitoring is required one year after the effective date of the rule (2016). Based on the 

regulatory compliance cost estimation in this RIA, it is likely that the liner requirements 

associated with unlined leaking impoundments whose groundwater chemical constituent 

sampling analysis is found to exceed health-based thresholds will result in a phase-out of some 

CCR surface impoundments at some electric utility plants. This phase-out could occur because of 

the high cost of retrofitting or opening new impoundments compared with other CCR 

management options (e.g., converting to dry CCR handling involving onsite or offsite landfill 

disposal).

The CCR final rule includes 12 CCR pollution control requirements for electric utility plants:

1. Groundwater monitoring for detection of CCR contamination;

2. Bottom liners (composite or equivalent);

3. Leachate collection systems (landfills only);

4. Fugitive CCR dust controls;

5. Rain and surface water run-on/run-off controls;

6. CCR management unit location restrictions;

7. Closure capping to cover unit; 

8. Post-closure groundwater monitoring for 30 years;

9. Structural integrity requirements (surface impoundments only);

10. Corrective action for CCR contaminated groundwater (groundwater clean-up);

11. Reporting and recordkeeping; and

12. For existing unlined impoundments with leaks, or that fail the land disposal 

restrictions or structural integrity requirements, either retrofit with composite 

liners (item 2 above) or close impoundments at active utilities and convert to dry 

CCR handling when groundwater chemical constituent sampling analysis is found 

to exceed health-based thresholds.

In addition to the above CCR pollution control requirements, this RIA estimates costs associated 

with requirements for inactive surface impoundments to dewater and undergo closure capping.

The CCR final rule also allows for two compliance alternative closure requirements for certain 

subsets of electric utility plants with leaking unlined CCR impoundments and for surface 

impoundments and landfills that do not meet the location standards of the rule. Alternative 

closure requirement #1 allows, for plants that certify no alternative CCR disposal capacity, a 10-

year an extension of time for completing closure of extension for initiating closure for their 

leaking, unlined impoundments and impoundments and landfills that do not meet the rule’s 

location restrictions. In addition, alternative closure requirement #2 allows, for plants that certify 

plans to permanently cease operation cessation oof a coal-fired boiler(s) by a date uncertain, a 5-

yeara time extension for initiating completing closure for of their leaking, unlined 

impoundments and impoundments and landfills that do not meet the location restrictions of the 

rule; however, due to uncertainty regarding the universe of plants which may choose to cease 

operating when faced with the CCR final rule, this RIA presents the impact of this alternative 

closure requirement only as a sensitivity analysis.
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ES.3 Summary of Estimated Regulatory Costs and Benefits for the CCR Rule

Within the constraints of data availability, this RIA considers 34 quantifiable and qualitative 

expected future impacts for the CCR final rule, consisting of:

 12 regulatory costs (listed above)

 11 monetized benefits (listed below)

 11 non-monetized (qualitative) benefits (listed below)

As indicated above, this RIA estimates compliance costs imposed upon coal-fired electric utility 

plants and relevant owner entities. In addition, the analysis monetizes a number of expected 

future benefits of the rule, including: reduction in future cleanup costs, transaction (e.g., legal)

fees, and natural resource damages due to avoided releases from CCR impoundments, including 

those from structural failures;

3

reduction in CCR contaminated groundwater clean-up costs; and 

preventionreduction of cancer and illness due to CCR contamination of groundwater used as 

drinking water. Due to data and resource limitations, this RIA was unable to quantify several 

additional categories of benefits; these are presented qualitatively. In conducting these analyses, 

this RIA also assesses the sensitivity of outcomes to key assumptions.

Baseline CCR Management Cost

For the baseline this RIA evaluates 12 baseline costs to the electric utility industry associated 

with current (i.e, without the CCR rule) CCR management requirements either (a) mandated by 

state governments or (b) according to power company voluntary best management practices: 

closure capping to cover disposal units; composite liners at the bottom of disposal units; location 

restrictions (i.e., water table wetlands, fault areas, seismic zones, and unstable “karst” areas) for 

disposal units; groundwater monitoring during active lifespan of disposal units; leachate 

collection under disposal units; CCR fugitive dust controls; post‐closure groundwater 

monitoring; rain water run-on/run-off controls; impoundment structural integrity requirements; 

state corrective action requirements; state paperwork reporting/recordkeeping; and off-site 

disposal costs.

Some state governments currently require CCR pollution controls for future newly-constructed 

CCR management units, and some states also require pollution controls for existing CCR 

management units. Other states have few or no pollution control requirements specific to CCR 

management. This RIA reviews state government CCR management regulations in effect as of 

2011 in a sample of 34 states with coal-fired electric utility plants. The plants in these 34 states 

accounted for 98% of the annual quantity of CCR generated in 2012.4 This RIA estimates the 

electric utility industry currently spends between $2.4 billion per year (7% discount rate) and 

 

3 The use of the phrase CCR impoundment “avoided releases” in this RIA is intended to refer broadly to the expected future 

avoidance of multiple possible causes and types of CCR impound release events including (a) major structural failures (i.e., wall 

breaches and (b) relatively smaller release events involving overtopping, embankment sloughing, and miscellaneous failures to 

impoundment appurtenant structures (e.g., pumps, discharge structures, decant weirs, and hydraulic piping).

4 The 34 states are Alabama, Arizona, Colorado, Florida, Georgia, Iowa, Illinois, Indiana, Kansas, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, Mississippi, Missouri, Montana, Nevada, New Mexico, New York, North Carolina, North 

Dakota, Ohio, Oklahoma, Pennsylvania, South Carolina, Tennessee, Texas, Utah, Virginia, Washington, West Virginia, 

Wisconsin, and Wyoming.
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$2.8 billion per year (3% discount rate) to meet state-government-required and company 

voluntary pollution controls for CCR management. This baseline cost is not attributable to the 

CCR rule.

Industry Compliance Cost offorof the CCR Rule

The estimated costs for the CCR rule are incremental to the baseline cost summarized above, and 

are estimated in this RIA using both an average annualized and a present value equivalent basis 

over the 100-year period of analysis (2015-2114) at both 7% and 3% alternative discount rates. 

This RIA estimates costs to comply with the 12 CCR pollution control requirements associated 

with the rule. The estimated cost of the CCR rule represents the incremental expenditures above 

baseline costs for meeting the requirements of the rule by electric utility plants, to the extent that 

these plants are not already regulated by state governments. The total cost includes both 

incremental costs borne by electric utility plants, and the costs to state governments to administer 

and enforce the CCR rule. 

In addition to the cost estimates, this RIA addresses two compliance alternative closure 

requirements for certain subsets of electric utility plants with leaking unlined CCR 

impoundments. Due to data limitations EPA was unable to estimate the costs and benefits of 

these two alternative closure requirements for and ssurface impoundments and landfills that do 

not meet the rule’s location standards (however EPA believes these costs and benefits will be 

very small given the small number of units; approximately 22 surface impoundments and 14 

landfills):. Although the alternative closure requirements apply to different subsets of electric 

utility plants, both alternative closure requirements apply only to plants with leaking unlined 

CCR impoundments that exceed groundwater chemical contamination maximum concentration 

limits (MCL) standards:

1. Alternative Closure Requirement #1: For plants that certify no alternative CCR 

disposal capacity, a 10-year extension (2028a time extension) for initiating 

closurecompleting the closure of for leaking, unlined CCR impoundments and surface 

impoundments and landfills that do not meet the location requirements of the rule, 

thereby delaying the date when closure costs begin compared to the 2019 date applied in 

the RIA. , thereby delaying the date when closure costs begin compared to the 2019 date 

applied in the RIA (i.e., this chapter shifts 10 years out to 2028 the leaking unlined 

impoundment closure costs estimated in the RIA for this sub-set of eligible plants).

1.

2. Alternative Closure Requirement #2: For plants that certify plans to permanently

cessation cease operation of of a coal-fired boiler(s) by a date uncertain, a time extension 

for completing closure, 5-year extension (2023) for initiating closure for leaking, unlined 

CCR impoundments, thereby delaying the date when closure costs begin compared to the 

2019 date applied in the RIA. Due to uncertainty regarding the universe of plants which 

may choose to cease operating when faced with the CCR final rule and avail themselves 

of this alternative closure requirement, this RIA presents the impact of this alternative 

closure requirement only as a sensitivity analysis, rather than including potential impacts 

in its primary estimates.
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As displayed in Exhibit ES-A below, the central estimate of the annualized cost of the rule

assuming a 7% discount rate is $508 million in industry compliance costs. In addition, this RIA 

estimates that state governments will incur costs associated with implementing the CCR rule of 

$1.2 million. 

Environmental and Human Health Benefits and Cost Savings offorof the CCR 

Rule

This RIA estimates 11 categories of expected future human health and environmental benefits 

and cost savings for the CCR rule. These include reduced CCR impoundment release

prevention;releases; reduced groundwater contamination prevention; improved air quality; and 

non-market surface water quality benefits. Each category is summarized below and in Exhibit 

ES-B.

1. Impoundment release prevention.Reduced CCR impoundment releases. The 

monetary value of this benefit consists of avoided future: impoundment 

releasestructural failure cleanup costs; transaction (e.g, legal) fees; and natural 

resource damages. This benefit is attributable to the following CCR pollution 

control requirements of the CCR rule: impoundment structural integrity annual 

evaluation requirements; annual integrity evaluation results recordkeeping; 

induced closures of CCR surface impoundments (SIs); and location restrictions 

for new units. As monetized in this RIA, this benefit applies to different sized 

impoundments (i.e., large and small) and all future failure event types (i.e., wall 

breach, “other” releases).

2. GroundwaterReduced groundwater contamination prevention. The physical 

nature of this benefit consists of expected future reduction in contamination of 

groundwater by preventingreducing future leaching of CCR into groundwater 

from CCR landfills and CCR impoundments. The monetary value of this benefit 

consists of future avoided: groundwater remediation costs; transaction (e.g., legal)

fees; and groundwater natural resource damages. This benefit is attributable to the 

following CCR pollution control requirements of the rule: induced closures of 

surface impoundments; bottom liners; leachate collection; capping of closed units; 

groundwater monitoring (during operation); post-closure groundwater monitoring 

(30-years after closure); recordkeeping (groundwater monitoring results); 

groundwater corrective action; and rain water run-on/run-off controls.

3. IncreasedInduced increase in future annual CCR beneficial use. The physical 

nature of this environmental benefit consists of avoided disposal costs as well 

asthe expected future reductions in air pollutant emissions and resource

consumption. The monetary value of this benefit includes two components: (i) 

Reduced compliance costs of the rule due to diversion of CCR away from 

disposal to beneficial use management;5and (ii) Reduced (i.e., reduced incidence 

 

5 The reduced compliance costs from increased CCR beneficial use could just as appropriately be treated as a reduction in costs

of the rule rather than as a benefit. This would leave net benefits unchanged, although the benefit to cost ratio would decline.
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of premature mortality and chronic bronchitis,), as well as avoided energy and 

water costsconsumption, due to reduced use of virgin materials. from the CCR 

final rule’s expected induced diversion of some CCRs away from disposal to 

beneficial uses. This benefit is attributable to requirements that would increase the 

the “avoided disposal cost of ” business behavior of electric utility plants as 

defined by the American Coal Ash Association. This section of the RIA also 

estimates an CCR rule “cost offset” associated with the future annual CCR 

tonnage estimated in this RIA to potentially switch from disposal relative to 

beneficial use and thereby provide incentives to increase(the CCR final rule does 

not regulate beneficial use). Note: This ”cost offset” could have been included in 

(i.e., subtracted from) the cost estimate of this RIA (in Exhibit ES-A). ,

Hhowever, the beneficial use impact model was not intertwinedintegrated with 

the CCR rule cost estimation model of CCR. The most significantthis RIA, and 

thus this cost offset was estimated in conjunction with this benefit category (see 

row 3 of these are likely to be the requirements of liners for new impoundments 

and the closure of existing unlined impoundments. Exhibit ES-B).

4. Reduced incidence of cancer. The physical nature of this benefit consists of 

expected future reduction in consumption of fish contaminated by CCR, and is 

expected to result from reduced releases of CCR to surface water due to closure 

and improved management of impoundments and landfills. This benefit is a 

national estimate of reductions in health effects among populations who are 

exposed to CCR contaminants through consumption of recreationally caught fish, 

using the value of a statistical life (VSL) approach, which is based on estimates of 

society’s willingness to pay to avoid the risk of premature mortality. 

5. Mitigated IQ losses from mercury. The physical nature of this benefit consists 

of expected future reduction in adverse health effects on children exposed to 

mercury in-utero as a result of preventingreducing maternal consumption of 

contaminated recreationally caught fish, and is expected to result from reduced 

releases of CCR to surface water due to closure and improved management of 

impoundments and landfills. The monetary value of this benefit consists of the 

avoided lost future expected lifetime earnings for children born with lower IQ 

levels. This benefit monetization method represents only one component of 

society’s willingness-to-pay to avoid IQ decrement, and thus underestimates the 

total value of benefits to children from reduced exposure to mercury.

6. Mitigated IQ losses from lead exposure. The physical nature of this benefit 

consists of expected future reductions in the exposure of pre-school age children 

(ages 0 to 7) to lead from the consumption of contaminated recreationally caught 

fish, and is expected to result from reduced releases of CCR to surface water due 

to closure and improved management of impoundments and landfills. The 

monetary value of this benefit consists of the future expected lifetime earnings 

lost for children born with lower IQ levels. This benefit monetization method 

represents only one component of society’s willingness-to-pay to avoid IQ 
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reductions from lead exposure, and thus underestimates the total value of benefits 

to children from reduced exposure to lead.

7. Reduced need for specialized education. The physical nature of this benefit 

consists of expected future reductions in the exposure of children to lead from the 

consumption of contaminated fish tissue, and is expected to result from reduced 

releases of CCR to surface water due to closure and improved management of 

impoundments and landfills. The monetary value of this benefit consists of the 

avoided cost of compensatory education for children with learning disabilities. As 

noted above, this benefit monetization method represents only one component of 

society’s willingness-to-pay to avoid IQ reductions, and thus underestimates the 

total value of benefits to children from reduced exposure to lead.

8. Non-market benefits from surface water quality improvements. The physical 

nature of this benefit consists of expected future reduction in contamination of 

surface water by reducing the risk of CCR surface impoundment failures, and is 

expected to result from reduced releases of CCR to surface water due to closure 

and improved management of impoundments and landfills. Heavy metals, 

nutrients, and other pollutants found in CCR can have a wide range of effects on 

surface water resources following discharges associated with impoundment 

releases. These environmental changes affect environmental goods and services 

valued by humans, including, among others: improved aquatic and wildlife 

habitat; enhanced water-based recreation; aesthetic improvements of surface 

water; increased non-use ecosystem value; and reduced risks to aquatic wildlife. 

The monetary value of this benefit consists of the public’s willingness-to-pay for

improvements in the quality of surface water. The expected changes in nonmarket values of the surface water resources affected by the CCR rule are additive 

to the benefits from avoided groundwater contamination, described above.

9. Protection of Threatened and Endangered Species. The physical nature of this 

benefit consists of expected future reduction in contamination of surface water by 

reducing the risk of CCR surface impoundment releases. Threatened and 

endangered species are species vulnerable to future extinction or at risk of 

extinction in the near future, respectively. Certain chemicals, pollutants, and even 

nutrients found in CCR and permitted discharges can pose serious threats to 

ecological health due to bioaccumulation, high concentrations, high loadings, and 

eutrophication. For species vulnerable to future extinction, even minor changes to 

growth and reproductive rates and small levels of mortality may represent a 

substantial portion of annual population growth. The monetary value of this 

benefit consists of the public’s willingness-to-pay for the non-use benefits (e.g., 

conservation and recovery) associated with threatened and endangered species. 

10. Improved air quality. from reduced power plant air pollution. The physical 

nature of this benefit consists of expected future reductions in the generation of 

air pollutants, such as nitrogen oxides (NOx), sulfur oxides (SOx), and carbon 

dioxide (CO2) from changes in electricity generation, fuel consumption, and 
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combustion expected because of changes in the handling of CCRs. d ashCCR

handling. The monetary value of this benefit consists of national level estimates 

of monetized benefits of emissions avoided. Additional values for this category 

will be forthcoming in an addendum reporting presented in the output from the 

Integrated Planning Model (IPM).

11. Reduced groundwater withdrawals. The physical nature of this benefit consists 

of the increased availability of groundwater for local municipalities from water 

intake reductions. In the case of the CCR rule, reductions in water intake are 

assumed to result from the conversion from wet to dry ash handling associated 

with impoundment closures. The monetary value of this benefit consists of the 

avoided cost of supplementing drinking water supplies through alternative means, 

such as bulk drinking water purchases. 

In addition to these monetized benefit categories, this RIA examines 11 additional benefit 

categories. Due to significant uncertainties and weaknesses in supporting documentation for 

quantifying and monetizing these benefits, this RIA presents these benefits separately from the 

benefits listed above, and does not include them in the quantified comparison of benefits and 

costs. These qualitative benefits, also included in Exhibit ES-B, include:

1. Financial market benefits

2. Reduced dread of CCR impoundment releases

3. Reduced health and nuisance impacts from CCR fugitive dust 

4. Cancer and non-cancer human health benefit from fish consumption (additional to 

monetized avoided health effects)

5. Cancer and non-cancer human health benefits from other recreational uses (additional to 

monetized avoided health effects)

6. Avoided sediment contamination in surface waters near power plants

7. Water quality benefits from avoided treatment costs for drinking and irrigation water

8. Commercial fisheries benefit near power plants

9. Increased participation in surface water-based recreation near power plants

10. Avoided fish impingement and entrainment mortality from power plant water intakes

11. Increased property values surrounding electric utility plants

Comparison of Benefits to Costs for the CCR Rule

Exhibit ES-A below provides a summary of the estimated costs for the CCR final rule as 

estimated in this RIA, under both a 7% and 3% discount rate in both annualized and present 

value terms. Exhibit ES-B below summarizes monetized and non-monetized benefits; the 

monetized benefits are similarly shown under both a 7% and 3% discount rate in both annualized 

and present value terms. Lastly, Exhibit ES-C presents the total costs and benefits of the rule 

under both a 7% and 3% discount rate.
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ES-A

Incremental CCR Management Costs – All CCR Management Units (millions of 2013$)

CCR Pollution Control 3% discount rate 7% discount rate

Annualized Present value Annualized Present value

A. Unit-level pollution control costs*

1. Groundwater monitoring for CCR contamination $4.79 $151 $2.80 $39.9

2. Bottom liners $491 $15,500 $297 $4,230

3. Leachate collection systems (landfills only) $51.6 $1,630 $18.4 $263

4. DustCCR fugitive dust controls $7.09 $224 $3.36 $48.0

5. Run-Stormwater run-on/run-off controls $18.8 $594 $13.0 $186

6. Location restrictions $43.6 $1,380 $20.0 $285

7. Closure capping $20.1 $630 $12.0 $171

8. Post-closure groundwater monitoring (30 years) $0.0760 $2.40 $0.0430 $0.613

9. ImpoundmentCCR impoundment structural integrity 

inspectionsrequirements

$10.9 $344 $11.1 $158

B. Other ancillary costs

10. Groundwater correctiveCorrective action

(groundwater cleanup) $19.0 $600 $19.1 $273

11. Reporting & recordkeeping $26.3 $831 $27.3 $389

12. Conversion from wet to dry CCR handling $29.0 $916 $57.3 $818

13. Dewater & capping costs for inactive CCR 

impoundments $12.0 $380 $26.7 $381

14. Subtotal Industry Costs (1+...+13) = $734 $23,200 $508 $7,240

C. State Agency Paperwork Burden Costs

15. ImpoundmentCCR impoundment structural integrity 

inspectionsrequirements

$0.218 $6.88 $0.221 $3.16

16. Groundwater cleanup corrective action $0.380 $12.0 $0.382 $5.45

17. Reporting & recordkeeping $0.526 $16.6 $0.546 $7.78

18. Subtotal State Paperwork Burden Cost (15+16+17) 

=

$1.12 $35.5 $1.15 $16.4

19. Column Total Costs (14+ 18) = $735 $23,200 $509 $7,260

Note: Notes

 Except for location restrictions, all unit-level CCR pollution control costs cannot be dissociated due to nonlinearity in the cost estimation 

modeling process. See Section 4.2 for additional information. As a result, relative costs for unit-level pollution controls are assigned 

based on the relative unit cost of these requirements and weighted by the number of existing and new landfills subject to these 

requirements.

 For reason explained in Section 5.3.4 of this RIA, row 19 above (total cost) does not subtract the “cost offset” which is displayed in row 3 

of Exhibit ES-B. Instead, this RIA includes the “cost offset” within the CCR beneficial use benefit category rather than as a negative cost.
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Exhibit ES-B

Environmental and Human Health Benefits for the CCR Final Rule

(millions of 2013$)

Row Benefit Category

3% discount rate 7% discount rate

Annualized Present value Annualized Present value

Monetized Benefits

1 Prevention ofReduced CCR impoundment 

releases $151 $4,760 $138 $1,960

2 Prevention ofReduced CCR groundwater 

contamination $12.8 $405 $9.86 $141

Closures $1.60 $50.7 $1.46 $20.9

Bottom liners $6.56 $207 $5.06 $72.2

Groundwater monitoring $4.65 $147 $3.34 $47.7

3 Increase in CCR beneficial useuses* $117 $3,130 $79.0 $1,120

Avoided compliance costair pollution & 

resource consumption $8432.5 $2,670459 $57.121.9 $956164

Avoided air pollution & resource useCCR rule 

“cost offset” (alternatively could be subtracted 

from row 19 of Exhibit ES-A)

$3284.5 $4592,670 $21.957.1 $164956

4 Reduced incidence of cancer $0.00546 $0.173 $0.00273 $0.0390

5 Avoided IQ losses from mercury $0.279 $8.80 $0.0246 $0.351

6 Avoided IQ losses from lead $0.186 $5.87 $0.0164 $0.234

7 Reduced need for specialized education $0.00273 $0.0863 $0.000 $0.000

8 Non-market surface water quality benefits

$2.26 $71.4 $1.89 $27.0

Improved aquatic and wildlife habitat

Enhanced water-based recreation

Aesthetic improvements of surface water

Increased non-use ecosystem value

Reduced risks to aquatic wildlife

9 Protection of threatened and endangered 

species in vicinity of CCR disposal units $0.909 $28.7 $0.759 $10.8

10 Improved air quality from reduced power 

plant air pollutant emissions (fuel switching) $4.66 $147 $2.04 $29.1 Reduced air emissions of NOx, SO2

Reduced air emissions of CO2

11 Reduced groundwater withdrawals (after 

conversion from wet to dry CCR handling) $0.00273 $0.0863 $0.00273 $0.0390

Column Totals = $289 $8,550 $232 $3,290

Non-Monetized Benefits

12 Financial benefit. Reduced investment risk and information asymmetry in financial markets for the electric utility industry.

13 Dread reduction benefit. Reduced fear, stress, and anxiety (i.e., hazard dread) of citizens residing near CCR 

impoundments.

14 DustCCR dust nuisance benefit. Reduced community nuisance from fugitive CCR dust. This is a separate benefit from the 

human health benefit from reduction in CCR dust inhalation, which is estimated in Chapter 5.

15 Non-cancer human health benefit. Reduced non-cancer health effects resulting from fish consumption. This is a separate 

benefit from the avoided cancer risks monetized in Chapter 5.

16 Cancer and non-cancer human health benefit. Reduced cancer and non-cancer health effects resulting from recreational 

water use. This is a separate benefit from the human health benefit from reduction in fish consumption, which is estimated in

Chapter 5.

17 Avoided sediment contamination. Reduced sediment contamination from reduced deposition of toxic pollutants.

18 Water quality benefit. Reduced water treatment costs for drinking and irrigation water.

19 Commercial fisheries benefit. Improved commercial fishing yields and harvest quality due to aquatic habitat 

improvements.

20 Tourism benefit. Increased participation in water-based recreation due to water quality improvements.

21 Avoided impingement and entrainment mortality. Reduced fish impingement and entrainment mortality from CCR 

handling surface water intake.

22 Increased property values: Improvement of aesthetic conditions of the local landscape stemming from the induced closure 

of CCR impoundments and the associated de-watering, capping, and re-vegetation requirement of the CCR final rule.
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* The beneficial use benefit in this RIA consists of two components. The sub-rows below display an approximate breakdown of the relative 

contribution to the total beneficial use benefit across these two components, cognizant of the downscaling factor applied to these benefits in this 

chapter, as described in Section 9.2.4.

Note: Figures are rounded to three significant digits; totals may not add due to rounding.

Exhibit ES-C

Incremental Costs and Benefits: Alternate Discount Rates

(millions of 2013$)

3% Discount Rate 7% Discount Rate

Present values:

1. Costs $23,200 $7,260

2. Benefits $8,550 $3,290

3. Net Benefits (2 - 1) ($14,700) ($3,970)

4. Benefit Cost Ratio (BCR2 / 

1)

0.37 0.45

Annualized:

1. Costs $735 $509

2. Benefits $289 $232

3. Net Benefits (2 - 1) ($446) ($277)

4. Benefit Cost Ratio (BCR2 / 

1)

0.39 0.46

Figures rounded to three significant digits. Totals may not sum due to rounding.

ES.4 Cost and Benefit Estimation Uncertainties

The analyses in this RIA represent best estimates, and reflect an approach designed to ensure that 

both costs and benefits of the rule are not over- or understated. Several key areas of uncertainty 

associated with the cost and benefit analyses may affect the accuracy of these estimates, 

including:

 Reasonable cost estimations. The cost modeling in this RIA applies average 

engineering costs and standard design assumptions to assess unit-level costs 

across all facilities in the universe. In light of the assumptions made, the model 

may not describe operating conditions at any given unit with perfect accuracy, 

due to unit-specific technologies and design specifications. Nonetheless, the cost 

estimates are based on rational, neutral assumptions regarding engineering and 

design. While cumulative cost estimates and facilityplant-level decisions are 

likely reasonable, the specific facilityplant-level calculations in the model should 

not be interpreted as facilityplant-level predictions.

 Uncertainty of benefits estimates. Benefits estimates rely on limited data and 

reflect significant uncertainty. In addition, this RIA has identified several benefits 

that cannot be reliably estimated and are therefore not included in monetized 

benefit estimates. This uncertainty is addressed in a series of sensitivity analyses. 

Finally, to harmonize the benefits of the final CCR rule with EPA Office of 

Water’s (EPA-OW’s) Steam Power Generator Effluent Limitation Guidelines

(SPGELG) proposed rule, this RIA scales eight benefit categories using the 
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benefits estimates associated with the SPGELG proposed rule.6 This scaling is 

appropriate due to similarities in the universe affected and the physical nature of 

the benefit categories. This method assumes that a linear relationship exists 

between pollution inputs and benefits and that plant management and closure 

behavior are similar under the SPGELG and the CCR final rule. Each of these 

assumptions adds uncertainty to the overall result. We note, however, that these

scaled benefits for which the most uncertainty exists represent 2% of overall 

benefits at a 7% discount rate (3% of overall benefits at a 3% discount rate).

 Potential for cost-effective fuel switching. Both benefits and costs of this rule 

could be affected by recent changes in the price of natural gas. This RIA does not 

consider the ability of facilities to cost-effectively switch fuels from coal to 

natural gas, because until late 2011, the price of natural gas has not historically 

been a cost-competitive alternative to coal. However, to the extent that the 

estimated cost increases under this rule could trigger fuel switching in the current 

market context as a lower-cost compliance option, this RIA may overstate 

compliance costs. Moreover, fuel switching to natural gas in response to this 

regulation would reduce emissions of criteria air pollutants; those benefits are 

considered in an addendum toAppendix X of this RIA which will analyzes output 

from the Integrated Planning Model (IPM). 

 Electricity price impacts and social costs. This RIA evaluates social cost as the 

total of compliance costs and the costs to states to implement the requirements. 

Separately from this RIA, EPA plans to run the Integrated Planning Model (IPM)

to estimate the impact of the rule on electricity prices. Separately from the main 

analysis in this RIA, EPA ran the Integrated Planning Model (IPM) to estimate 

the impact of the rule on electricity prices (shown in Appendix X). It is 

important to note that any increases in electricity prices to consumers would not 

affect the total social cost estimates, because they would be offset by decreases in 

compliance costs to utilities.

 Full compliance assumption. This RIA implements an assumption of full (i.e., 

100%) industry compliance with all requirements. To the extent that states do not 

fully enforce all requirements, this RIA may overstate both costs and benefits 

associated with the CCR rule. A sensitivity analysis in Chapter 7 examines 

alternatives to this assumption.

ES.5 Other Regulatory and Distributional Impacts

Consistent with requirements under various statutes and executive orders, this RIA also assesses 

the following potential impacts of the CCR rule:

 

6 Because the SPGELG rulemaking affects the same universe of CCR ponds as the CCR rule and because all benefit categories 

are directly or indirectly correlated with pollutant removal quantities, the benefits in this RIA are harmonized with the benefit 

categories of EPA-OW’s RIA for the 2013 SPGELG proposed rule. For additional information, see Chapter 5.
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 Electricity price and energy market impacts. To assess the impact of the final 

rule on electricity markets pursuant to 2001 Executive Order 13211, Actions 

Concerning Regulations That Significantly Affect Energy Supply, Distribution, or 

Use (May 18, 2001) and associated OMB guidance, EPA plans to perform 

aperformed an electricity market analysis using the Integrated Planning Model 

(IPM). The IPM analysis is provided as a separate report (December 2014) in the 

docket for the CCR final rule (docket nr. EPA-HQ-RCRA-2009-0640 at 

http://www.regulations.gov) Appendix X of the RIA.

 Regulatory flexibility. In accordance with the 1980 Regulatory Flexibility Act 

(RFA) and its 1996 corollary, the Small Business Regulatory Enforcement 

Fairness Act (SBREFA), this RIA determined that only six of 81 small entities 

(counties, cities, companies, and coops) experience compliance costs that exceed 

1% of revenues, and only one of these experiences compliance costs that exceed 

3% of revenues. Therefore, this RIA concludes that the rule will not have a 

significant impact on a substantial number of small entities (SISNOSE).

 Impacts on minority and low-income populations. The rule is not expected to 

create any disproportionately high or adverse human health and environmental 

impacts on minority or low-income populations, as defined in 1994 Executive 

Order 12898, Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations (59 FR 7629, February 16, 1994).

 Children’s health protection. The rule is not expected to have a disproportionate 

risk impact on children’s health, as defined inAs ordered by Section 101(b) of the 

1997 Executive Order 13045, Protection of Children fromFrom Environmental 

Health Risks and Safety Risks (62 FR 1988519883, April 23, 1997). ), EPA has 

ensured that the CCR final rule addresses disproportionate risks to children that 

result from environmental health risks. The rule is not expected to create 

additional or new risk to children.

 Unfunded mandates. The rule is subject to the requirements of sections 202 and 

205 of the 1995 Unfunded Mandates Reform Act (UMRA) because it contains 

federal mandates that may result in expenditures of $100 million or more in any 

one year to both the private sector and to state, local, and tribal governments. This 

RIA also includes an UMRA Written Statement. (Appendix V).

 Federalism. 1999 Executive Order 13132, Federalism (64 FR 43255, August 10, 

1999), defines federalism implications to include substantial direct effects on 

states, on the relationship between the national government and states, or on the 

distribution of responsibilities and power among the levels of government. EPA 

typically considers a policy to have federalism implications if it results in 

aggregate expenditures by state and/or local governments of $25 million or more 

in any one year, or expenditures that exceed 1% of revenue. This analysis finds 

federalism impacts to be ambiguous; expenditures are likely to exceed $25 

million, but not to exceed 1% of revenue.
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Chapter 1

Background and Problem Statement: The Need for EPA Regulation 

of CCR Landfills and CCR Surface Impoundments

1.1 Purpose of this Chapter

The U.S. Environmental Protection Agency (EPA or the Agency) is publishing a final rule to 

regulate coal combustion residual (CCR) landfills and CCR surface impoundments under 

Subtitle D of the Resource Conservation and Recovery Act (RCRA). To evaluate Federal 

regulations, the 1993 Executive Order 12866, Regulatory Planning and Review, Section 1(b)(1) 

requires Federal regulatory agencies such as the EPA to identify the problem that it intends to 

address with the regulation (including, where applicable, the failures of private markets or public 

institutions that warrant new agency action), and to assess the significance of the problem. 

In September 2003, the White House Office of Management and Budget (OMB) published its 

Circular A-4, Regulatory Analysis, which updated guidance to federal agencies on the 

development of regulatory analyses required under Section 6(a)(3)(c) of Executive Order 12866.7

Section A of Circular A-4 defines three key elements of good regulatory analysis:

 Statement of the need for the regulation;

 Examination of alternative approaches; and

 Evaluation of the benefits and costs (quantitative and qualitative) of the proposed 

regulation and its main alternatives.

This chapter first summarizes EPA’s prior activities addressing the management of CCR, and 

then presents the need for regulatory action by EPA of CCR landfills and CCR impoundments 

(the first key element listed above).

EPA’s June 2010 proposed CCR rule presented and examined alternative regulatory approaches 

(the second key element listed above), and EPA’s RIA for the June 2010 proposed CCR rule

provided an evaluation of the expected benefits and costs of the 2010 proposed alternatives (the 

third key element listed above).

8, 9 Thus, this chapter only addresses the need for regulation. 

Furthermore, this RIA only evaluates the actual single regulatory approach (i.e., the Modified DPrime approach) EPA selected for the CCR final rule.

A section at the end of this chapter provides a summary of organizations which submitted public 

comments on EPA’s RIA for the June 2010 proposed CCR rule.

 

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

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

8 EPA published the June 2010 proposed CCR rule in the Federal Register, Vol.75, No.118, June 21, 2010, pp. 35128 to 35264.

9 2010 RIA: Regulatory Impact Analysis for EPA’s Proposed RCRA Regulation of Coal Combustion Residues (CCR) Generated 

by the Electric Utility Industry, EPA Office of Resource Conservation and Recovery, 30 April 2010, 242 pages, available as 

document ID nr. EPA-HQ-RCRA-2009-0640-0003 at http://www.regulations.gov
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1.2 EPA’s Prior Activities Addressing CCR Management (1978-2014)

This section presents historical highlights of EPA’s prior activities concerning regulatory 

evaluation of CCR landfills and CCR surface impoundments.

10

1978 EPA’s regulatory evaluation of CCR dates back to 1978, two years after enactment of the 

1976 Resource Conservation and Recovery Act. RCRA was an amendment to the 1965 

Solid Waste Disposal Act (SWDA), the first federal statute that specifically focused on 

improving solid waste disposal methods. RCRA added Subtitle C to address industrial 

hazardous waste management requirements, among others. In December 1978, EPA 

proposed the first industrial hazardous waste regulations to implement RCRA Subtitle C 

(Sections 3001 to 3020 of RCRA). At that time, EPA recognized that certain largevolume industrial wastes, including wastes from the combustion of fossil fuels (such as 

CCR), might warrant special treatment under RCRA regulation. On December 18, 1978, 

EPA proposed a relatively limited set of 10 RCRA Subtitle C industrial hazardous waste 

regulations for the management of CCR; these were never finalized.11 EPA determined 

that six categories of industrial wastes (“special wastes”) required further assessment to 

determine their risk to human health and the environment:12

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; and

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

These wastes are typically generated in large volumes and, at the time, were believed to 

pose less risk to human health and the environment than the wastes being identified for 

regulation as RCRA hazardous waste.

1980 Although on May 19, 1980, EPA promulgated initial regulations implementing RCRA 

Subtitle C, Congress restricted EPA’s authority to regulate large-volume wastes under 

Subtitle C during its 1980 re-authorization debates for RCRA. As a result, EPA excluded 

fossil fuel combustion wastes from the initial Subtitle C regulations. On October 12, 

1980, Congress enacted the Solid Waste Disposal Act Amendments of 1980 (Public Law 

 

10 Additional details are available at http://www.epa.gov/waste/nonhaz/industrial/special/fossil/regs.htm.

11 Federal Register, Vol. 43, No. 243, 18 December 1978, page 59015, Section 250.46-2; this action proposed the following 10 

industrial hazardous waste regulatory conditions: (a) waste analysis standards, (b) waste site selection standards, (c) waste site 

security, (d) waste shipment manifesting, (e) recordkeeping, (f) reporting, (g) waste site visual inspections, (h) waste site closure, 

(i) waste site post-closure care, and (j) groundwater monitoring.

12 To learn more about these six industrial special wastes see EPA’s special waste“Special Waste” website at: 

http://www.epa.gov/osw/nonhaz/industrial/special/index.htm
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96-482), which amended RCRA in several ways. Pertinent to the 1978-deferred special 

wastes were the 1980 Bentsen and Bevill Amendments, which exempted special wastes 

from regulation under Subtitle C until further study and assessment of risk could be 

performed.13

The Bentsen Amendment (RCRA 3001(b)(2)(A)) exempted drilling fluids, produced 

waters, and other wastes associated with the exploration, development, and production of 

crude oil or natural gas or geothermal energy. The Bevill Amendment (RCRA 

3001(b)(3)(A)(i-iii)) exempted fossil fuel combustion waste; waste from the extraction, 

beneficiation, and processing of ores and minerals (including phosphate rock and 

overburden from uranium ore mining); and cement kiln dust. These amendments required 

EPA to complete full assessments of each exempted waste and submit a formal Report to 

Congress (RTC) on its findings.

In October 1980, Congress:

 Amended RCRA to temporarily exempt four types of large-volume CCR wastes 

from Subtitle C regulation (i.e., fly ash, bottom ash, boiler slag, and flue gas 

emission control desulfurization residues);

 Directed EPA to submit a RTC evaluating the adverse effects on human health 

and the environment of these four CCR waste types;

 Directed EPA to conduct public hearings to decide whether Subtitle C regulation 

of these temporarily exempt CCR wastes was warranted; and

 Directed EPA to decide whether Subtitle C regulation is warranted for the four 

CCR waste types within six months of publishing the RTC.

1981 EPA issued an interpretation of RCRA Subtitle C that exempted the four CCR types 

exempted by Congress in October 1980.14

1984 Congress again amended RCRA, and gave EPA flexibility to promulgate Subtitle C 

regulations that considered the unique characteristics of some large-volume wastes, 

including fossil fuel combustion wastes. This amendment also provided EPA flexibility 

both to determine whether some or all CCR should be regulated, and to modify certain 

RCRA Subtitle C regulatory requirements to take into account special characteristics and 

practical difficulties associated with CCR. 

 

13 These 1980 RCRA special waste amendments are named after U.S. Senator Lloyd Bentsen (D-TX; Senate service years 1971-

1993) and U.S. House Congressman Tom Bevill (D-AL; House service years 1967-1997). Biographical Directory of the U.S. 

Congress at: http://bioguide.congress.gov/biosearch/biosearch.asp

14 13 January 1981 letter from Gary Dietrich, EPA Associate Deputy Assistant Administrator for Solid Waste, to Paul Emler Jr., 

Chairman, Utility Solid Waste Activities Group (USWAG); a copy of this letter is available at: http://yosemite.epa.gov/osw/ 

rcra.nsf/0c994248c239947e85256d090071175f/DB19FB013F06B99585256E150051C757/$file/12021.pdf
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1988 EPA published a Report to Congress with a scope limited to only coal-fired electric 

utilities that generate a large majority of all fossil fuel combustion wastes and that 

manage them separately from other wastes (i.e., in monofills). Utilities and non-utilities 

burning other types of fossil fuels were not addressed by the Report.15

1992 Because EPA did not publish a RCRA Subtitle C regulatory determination within six 

months of issuing the 1988 Report to Congress, an Oregon citizens group filed a legal 

suit forcing EPA on June 30, 1992 to enter into a Consent Decree to establish a schedule 

for the Subtitle C regulatory determination. In accordance with the Consent Decree, EPA 

notified the litigation parties that it would make a Subtitle C regulatory determination for 

the four exempt CCR waste types by August 2, 1993, and a Subtitle C regulatory 

determination for all remaining fossil fuel combustion wastes generated by other utilities 

and non-utilities by April 1, 1993.

1993 On February 12, 1993, EPA published the first of five CCR-related NODAs (notice of 

data availability) in the Federal Register requesting public comment on a proposed 

methodology to be used in making a final RCRA Subtitle C regulatory determination for 

the coal-fired electric utility wastes.

16

1993 On August 9, 1993, EPA issued a final determination for the first set of four waste types 

from coal-fired electricity plants, concluding that regulation under RCRA Subtitle C

would be inappropriate due to limited risks and the adequacy of state and federal 

regulatory programs.17 EPA decided to continue to exempt these wastes from Subtitle C 

hazardous waste regulation. This decision is known as the Part 1 determination. 

However, EPA indicated that industry and the states should continue to review these 

wastes, and that EPA would consider these wastes during its ongoing assessment of 

industrial non-hazardous wastes under RCRA Subtitle D.

1999 On March 31, 1999, EPA published a second Report to Congress on the remaining wastes 

(i.e., CCR generated by other types of facilities than coal-fired electricity power plants) 

not covered by the 1988 RTC. EPA provided a 45-day public comment period and held a 

public meeting with stakeholders on May 21, 1999 to gather feedback on the RTC.18

2000 On May 22, 2000, EPA published a regulatory determination on whether the regulation 

of the other types of fossil fuel combustion wastes generated by other types of facilities 

not addressed in the 1993 final determination is warranted under RCRA Subtitle C or 

 

15 See U.S. EPA, Office of Solid Waste and Emergency Response, Report to Congress, “Wastes from the Combustion of Coal by 

Electric Utility Power Plants,” February 1988, doc. no. EPA/530-SW-88-002, 

http://www.epa.gov/osw/nonhaz/industrial/special/fossil/coal-rtc.pdf.

16 Federal Register, Vol. 58, No. 28, 12 February 1993, pages 8273 to 8275, “Additional Information on Waste Studied in the 

Report to Congress on Wastes from the Combustion of Coal by Electric Utility Power Plants.”

17 Federal Register, Vol. 58, No. 151, 09 August 1993, pages 42466 to 42482 “Final Regulatory Determination on Four LargeVolume Wastes from the Combustion of Coal by Electric Utility Power Plants.”

18 See U.S. EPA, Office of Solid Waste and Emergency Response, Report to Congress, “Wastes from the Combustion of Fossil 

Fuels,” March 1999, doc. no. EPA 530-S-99-010 (volume 1) and EPA 530-R-99-010 (volume 2), 

http://www.epa.gov/osw/nonhaz/industrial/special/fossil/volume_1.pdf and 

http://www.epa.gov/osw/nonhaz/industrial/special/fossil/volume_2.pdf. 
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Subtitle D.19 This is known as the Part 2 determination. EPA concluded that Subtitle C 

regulation was not warranted, but that national regulations under Subtitle D were 

warranted when these wastes were used to fill surface or underground mines or deposited 

in surface impoundments (SIs) and landfills.

For CCR used as mine fill, EPA consulted with the Office of Surface Mining (OSM), in 

the U.S. Department of the Interior, to assess whether equivalent protectiveness could be 

achieved using regulatory authorities available under the Surface Mining Control and 

Reclamation Act (SMCRA). Subsequently, a March 2006 National Academy of Science 

report recommended that the OSM take the lead in developing standards for CCR 

minefilling under SMCRA.20 Since then, EPA has deferred to OSM. EPA also concluded 

that no additional regulations were warranted for CCR used beneficially (other than for 

mine filling), such as use in cement and concrete products, waste stabilization, and 

construction products such as wallboard.

2005 In November 2005, EPA completed a report estimating the potential costs to the electric 

utilities industry to comply with hypothetical new regulatory requirements for CCR 

management units under EPA’s 40 CFR Part 258 RCRA Subtitle D regulations. These 

requirements included groundwater monitoring, liner and leachate collection/detection 

system design controls, fugitive dust controls, storm runoff controls, end-of-lifespan 

closure controls, post-closure groundwater monitoring, financial assurance, siting 

standards, and corrective action.

2007 For the purpose of evaluating and proposing RCRA Subtitle D regulations, on August 29, 

2007, EPA published the second of five CCR NODAs announcing the availability of new 

information concerning the management of CCR in landfills and surface impoundments, 

as well as the intent to peer review the new draft EPA risk assessment of these wastes 

deposited in the two types of management units. In the NODA, EPA requested comments 

on: (a) the joint U.S. Department of Energy (DOE) and EPA report entitled Coal 

Combustion Waste Management at Landfills and Surface Impoundments 1994-2004, (b) 

the draft risk assessment conducted by EPA on the management of CCR in landfills and 

surface impoundments, and (c) EPA's CCR damage case assessment. The NODA also 

presented two alternative approaches to regulating CCR: a Voluntary Action Plan that 

was formulated by the electric utility industry through their trade association, the Utility 

Solid Waste Activities Group (USWAG), and a framework prepared by a number of 

citizens’ groups for federal regulation under RCRA Subtitle D (non-hazardous wastes).

2008 The externally conducted peer review of EPA’s new draft CCR risk analysis was 

completed in September 2008.

2009 In March and April 2009 EPA issued Information Request Letters to electric utility plants 

that had “surface impoundments or similar diked or bermed management units designated 

 

19 Federal Register, Vol. 65, No. 99, 22 May 2000, pages 32214 to 32237, “Notice of Regulatory Determination on Wastes from 

the Combustion of Fossil Fuels.”

20 The 2006 NAS report on CCW mine filling is available at: http://books.nap.edu/openbook.php?isbn=0309100496
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as landfills” that receive, store or dispose liquid-borne coal combustion wastes.

21 The 

letters requested that electric utility plants supply, within 10 business days, information to 

assist EPA in evaluating the structural integrity of these management units. EPA worked 

closely with other Federal agencies and states to review the information provided by the 

utility plants to identify CCR impoundments or similar units that need priority attention.

22

As part of this assessment, in 2009 EPA began visiting utility plants to evaluate the 

structural integrity of CCR impoundments identified in the information request survey. 

EPA required appropriate remedial action (action plans) at any utility plant found to pose 

a risk for potential impoundment releases, including those from structural failure. These 

site evaluations continued into 2013 and covered over 650 CCR impoundments 

nationwide.23

2010 EPA published the June 21, 2010 proposed CCR rule. The 2010 CCR proposal coproposed both a RCRA Subtitle C special waste approach and a RCRA Subtitle D nonhazardous waste approach, and discussed a modified RCRA Subtitle D option (named Dprime) which would exempt (grandfather) existing unlined CCR landfills and unlined 

CCR impoundments from the liner retrofit requirement.

2010 In August, September, and October 2010 EPA’s Office of Resource Conservation and 

Recovery (ORCR) held eight public hearings in different locations across the US to 

provide the public opportunity to present their views on the June 2010 CCR proposed 

rule.24 The hearing dates and locations were:

1. August 30, 2010 Arlington, VA

2. September 2, 2010 Denver, CO

3. September 8, 2010 Dallas, TX

4. September 14, 2010 Charlotte, NC

5. September 16, 2010 Chicago, IL

6. September 21, 2010 Pittsburgh, PA

7. September 28, 2010 Louisville, KY

8. October 27, 2010 Knoxville TN

 

21 The full text is available at: http://www.epa.gov/epawaste/nonhaz/industrial/special/fossil/coalashletter.htm

22 Responses by electric utility companies to EPA’s 2009 “information request letters” are posted at 

http://www.epa.gov/waste/nonhaz/industrial/special/fossil/surveys/index.htm (weblink correct as of 20 March 2014).

23 The results of EPA’s 2010 to 2013 CCR impoundment site evaluations are posted at 

http://www.epa.gov/waste/nonhaz/industrial/special/fossil/surveys2/index.htm (weblink correct as of 20 March 2014).

24 Transcripts of the eight 2010 public hearings are posted at http://www.epa.gov/waste/nonhaz/industrial/special/fossil/ccrrule/ccr-hearing.htm (weblink correct as of 20 March 2014).
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2010 On October 21, 2010 EPA published the third of five CCR NODAs to announce and 

invite public comment on EPA’s 2009 information request letter survey of electric utility 

plants and on the 2009 start of EPA’s site assessments of the structural integrity of CCR

surface impoundments.

2011 On October 12, 2011 EPA published the fourth of five CCR NODAs to announce and 

invite public comment on additional information obtained by EPA in conjunction with 

the June 21, 2010 proposed CCR rule. The additional information was generally 

categorized as: chemical constituent data from coal combustion residuals; facilityutility 

plant and waste management unit data; information on additional alleged damage cases; 

adequacy of state government regulatory programs; and CCR beneficial use. The 

comment period closed November 14, 2011.

2012 In April 2012, 13 plaintiffs filed three lawsuits to the US District Court concerning 

EPA’s CCR rulemaking:

1. On April 5, 2012 a group of 11 plaintiffs filed in US District Court a lawsuit 

asking the Court to compel EPA to publish a final CCR rule: Plaintiffs 

Appalachian Voices, Chesapeake Climate Action Network, Environmental 

Integrity Project, Kentuckians For The Commonwealth, Moapa Band of Paiutes, 

Montana Environmental Information Center, Physicians for Social Responsibility, 

Prairie Rivers Network, Sierra Club, Southern Alliance for Clean Energy, and 

Western North Carolina Alliance (hereinafter “Plaintiffs”) seek to compel the 

EPA to undertake long overdue action to address the serious and widespread 

risks that unsafe disposal of coal combustion waste or "coal ash" poses to human 

health and the environment.

2. On April 13, 2012 Headwaters Resources Inc. of South Jordan UT also filed a 

lawsuit requesting the US District Court to compel the EPA to publish a final 

CCR rule.

3. On April 20, 2012 Boral Material Technologies Inc of Roswell GA also filed a 

lawsuit requesting the US District Court to compel the EPA to publish a final 

CCR rule.

2013 On August 2, 2013 EPA published the fifth of five NODAs to announce and invite public 

comment on additional information obtained by EPA in conjunction with the June 21, 

2010 proposed CCR rule. The information on which EPA sought public comment was 

categorized as: additional data to supplement the regulatory impact analysis and risk 

assessment; information on large scale CCR fill; and data on EPA’s CCR surface 

impoundment structural integrity assessments from 2009 to 2013. The comment period 

closed September 3, 2013.

2014 On January 29, 2014 the DC District Court ordered the EPA to complete a CCR final rule 

for signature by the EPA Administrator no later than December 19, 2014. A Consent 
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Decree25 signed by all parties to the Appalachian Voices vs Gina McCarthy lawsuit was 

delivered to the DC District Court on January 29, 2014. Section III (page 5) of the 

Consent Decree states: “The EPA Administrator shall, by December 19, 2014, sign for 

publication in the Federal Register a notice taking final action regarding EPA’s proposed 

revision of RCRA Subtitle D regulations pertaining to coal combustion residuals.”

1.3 Need for EPA Regulation of CCR Landfills and CCR Impoundments

In general, Section B of OMB Circular A-4 requires Federal regulatory agencies to demonstrate 

that Federal regulation is necessary. In line with the three criteria identified in the preamble to 

the 1993 Executive Order 12866, Circular A-4 indicates that Federal agencies should only 

promulgate regulations that are:

 Required by law; or

 Necessary to interpret law; or

 Made necessary by compelling public need (such as market failure).

As explained below, EPA’s CCR final rule, in regulating CCR landfills and CCR surface 

impoundments, addresses at least six indicators of compelling public need for regulation:

1. Respond to public petitions submitted to EPA and to the DC District Court 

between 2004 and 2012 by citizen, environmental, and industry groups, proposing 

standards and EPA regulatory approaches for a CCR final rule;

2. Respond to 2009 Congressional requests for EPA regulation of CCR landfills and 

CCR surface impoundments;

3.2. PreventReduce future CCR contamination of groundwater and surface water;

4.3. PreventReduce future CCR surface impoundment structural failures and 

associated releases of CCR into the environment;

5.4. Reduce future public exposure to fugitive CCR dust from CCR landfills and CCR 

surface impoundments; and

6.5. Correct negative externalities, and inadequate and asymmetric information, about 

the risks to human health and the environment from CCR landfills and CCR 

surface impoundments.

The remainder of this chapter describes how the CCR final rule addresses each of these six 

indicators of public need for EPA regulation of CCR landfills and CCR surface impoundments.

 

25 The January 29, 2014 Consent Decree (18 pages) is available online (weblink correct as of 13 March 2014) at: 

http://earthjustice.org/sites/default/files/files/044-1-Consent-Decree.pdf
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1. Respond to public petitions submitted to EPA and to the DC District Court 

between 2004 and 2012 by citizen, environmental, and industry groups, 

proposing standards and EPA regulatory approaches for a CCR final rule

2004 In February 2004, 125 environmental and citizens groups petitioned the EPA 

Administrator for a rulemaking prohibiting the disposal of coal-fired electric power plant 

wastes into groundwater and surface water until such time as EPA promulgates federally 

enforceable regulations pursuant to RCRA.26

2006 In October 2006, the electric utility industry, through the trade association USWAG,

submitted to EPA a Utility Industry Action Plan for the Management of Coal Combustion 

Products.

27 The plan outlines the utility industry's commitment to adopt groundwater 

performance standards and monitoring, conduct risk assessments prior to placement of 

CCRs in sand and gravel pits, and to consider dry-handling of CCR prior to constructing 

new CCR surface impoundments (which involve wet-handling of CCR).

2007 In January 2007, 28 environmental and citizens groups jointly submitted to EPA a 

Proposal for the Federal Regulation of Coal Combustion Waste.

28 The proposal provides 

a framework for comprehensive regulation under RCRA Subtitle D of CCR landfills and 

CCR surface impoundments at coal-fired electric power plants.

2009 In a letter dated March 2, 2009, the Environmental Integrity Project and Earthjustice, as 

well as the National Resources Defense Council, the Sierra Club, Environmental 

Defense, and 104 other environmental groups, requested EPA Administrator Lisa Jackson 

“to act as soon as possible” to regulate CCR. The request letter identified 12 principles to 

guide the development of EPA standards, including the phase-out of CCR surface 

impoundments, locating CCR landfills and CCR impoundments away from groundwater 

or surface water, requiring liners, leachate collection systems and adequate monitoring, 

and requiring industry to assume long term liability for cleanup.29 The letter stated:

The recent disaster at TVA's Kingston Plant stands as a startling reminder that 

federal standards for CCR are long overdue. For too long, power companies have 

been able to dump CCR, laden with a host of toxic metals like arsenic, selenium, 

lead, mercury, and boron, in unlined mines, quarries, landfills, and surface 

impoundments. Without federal standards governing disposal practices, 

 

26 A copy of the 2004 petition is available at: 

http://www.regulations.gov/fdmspublic/component/main?/main=DocumentDetail&o=09000064801cf8d1

27 The October 2006 USWAG Action Plan (11 pages) is at: http://www.uswag.org/2006/ActPlan.pdf

28 The proposal (63 pages) was submitted jointly by Earthjustice, Clean Air Task Force, Environmental Integrity Project, Sierra 

Club, Natural Resources Defense Council, Waterkeeper Alliance, Hoosier Environmental Council, Public Citizen, Jefferson 

Action Group, Dine CARE, Army for a Clean Environment, Plains Justice, Appalachian Center for the Economy and the 

Environment, People in Need of Environmental Safety, Valley Watch, West Highlands Conservancy, Montana Environmental 

Information Center, San Juan Citizens Alliance, Clean Wisconsin, Residents against the Power Plant, Ohio Valley Environmental 

Coalition, Neighbors for Neighbors, Delaware Riverkeeper Network, Healthlink, Wenham Lake Watershed Association, Coal 

River Mountain Watch, Dakota Resource Council, and S.U.F.F.E.R. It is available online at: 

http://www.catf.us/resources/filings/power_plant_waste/CCWproposal013107_final.pdf.

29 The May 2, 2009 letter is available at: http://www.environmentalintegrity.org/pub608.cfm
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contaminants can leak or spill from these dump sites, threatening human health, 

natural resources and wildlife.

In July 2009, six environmental and citizens groups filed a second petition requesting that 

the EPA Administrator promulgate regulations that designate CCRs as hazardous waste 

under Subtitle C of RCRA.30 In support of their petition, the environmental groups cited:

...numerous reports and data produced by the Agency since EPA’s final 

Regulatory Determination ... which quantify the waste’s toxicity, threat to human 

health and the environment, inadequate state regulatory programs, and the 

damage caused by mismanagement.

2. Respond to 2009 Congressional requests for EPA regulation of CCR landfills 

and CCR surface impoundments.

The December 2008 impoundment failure at the Tennessee Valley Authority’s (TVA) Kingston, 

Tennessee site attracted citizen, media, and Congressional interest in the subject of protective 

CCR management requirements, and the urgent national need for prevention of such future

environmental and community damages. In the wake of this disaster, during her January 14, 

2009 Senate confirmation hearing, EPA Administrator-designate Lisa P. Jackson testified:31

I think that you’ve put your finger on a very important thing that EPA must do right 

away, which is to assess the hundreds of other sites that are out there. Many of them... 

are... uphill from schools or from areas where just the physical hazard of having this 

mountain of wet coal ash, if there’s a break, can endanger lives immediately. So I would 

think that EPA needs to first and foremost assess the current state of what’s out here and 

where there might be another horrible accident waiting to happen ... EPA currently has 

and has in the past, assessed its regulatory options with respect to coal ash, and I think 

it’s time to re-ask those questions and re-look at the state of regulation of them from an 

EPA perspective.

According to a January 23, 2009 news report, Congress was by then interested in EPA regulating 

CCR impoundments, whether within its existing RCRA regulatory authorities or through new 

legislation:32

Several lawmakers have introduced, or announced plans to introduce, competing 

legislation to regulate CCR. For example, Senate Environment and Public Works 

Committee Chairwoman Barbara Boxer (D-CA) said she would introduce legislation 

compelling EPA to regulate CCR in the event the Obama EPA fails to act soon. “If we 

 

30 The petition was jointly filed by Earthjustice; Sierra Club; Environmental Integrity Project; Natural Resources Defense 

Council; Southern Environmental Law Center; and Kentucky Resources Council. A copy of the petition is available in the docket 

to the June 21, 2010 CCR proposed rule (docket nr. EPA-HQ-RCRA-2009-0640) at: http://www.regulations.gov

31 Lisa Jackson’s 14 January 2009 Senate confirmation hearing testimony and webcast is available from the U.S. Senate 

Committee on Environment and Public Works’ website at: 

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

32 Waste Business Journal, “EPA Vows to Act on Coal Waste,” 23 January 2009, 

http://www.wastebusinessjournal.com/news/wbj20090127B.htm
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are not satisfied with action we may move legislatively,” Boxer told EPA Administratordesignate Lisa Jackson at a January 14 [2009] confirmation hearing. “I don't want to get 

to that point because I think you have the authority to regulate this. It needs to be done.”

Three weeks after the Kingston impoundment disaster, House Natural Resources Committee 

Chairman Nick Rahall introduced legislation requiring federal standards to regulate the 

engineering of CCR impoundments.33 Introduced on January 14, 2009, the Coal Ash 

Reclamation and Environmental Safety Act of 2009 (H.R. 493) directs the Department of 

Interior to impose uniform federal design, engineering, and performance standards on CCR 

impoundments to avoid a repeat of the damage done in Kingston TN. The legislation, which 

requires minimum design and stability standards for all surface impoundments constructed to 

hold coal ash, draws on the regulatory model for impoundments that is used for coal slurry 

management under SMCRA.

On March 4, 2009, U.S. Senators Barbara Boxer and Tom Carper submitted Senate Resolution 

64 to the Senate Committee on Environment and Public Works. This resolution calls on the EPA 

to “immediately” inspect all CCR impoundments and landfills operating at coal-fired electricity 

plants, and to propose and finalize “as quickly as possible” rules to regulate CCR under RCRA.34

3.2. PreventReduce future CCR contamination of groundwater and surface 

water

Under the Bevill Amendment for the special waste categories of the RCRA statute, EPA was 

statutorily required to examine “documented cases in which danger to human health or the 

environment from surface runoff or leachate has been proved” from the disposal of coal 

combustion wastes (RCRA Section 8002(n)). At the time of EPA’s May 2000 CCR Regulatory 

Determination, EPA was aware of 11 documented cases of proven damage to groundwater and 

36 cases of potential damage to human health and the environment from the improper 

management of CCRs in landfills and surface impoundments.35 Additionally, EPA determined 

that another four cases were documented cases of ecological damages. However, for the May 

2000 CCR Regulatory Determination, EPA did not consider these ecological damage cases 

because all involved some form of discharge from CCR impoundments to nearby lakes or creeks 

that would be subject to the Clean Water Act (CWA) regulations. Moreover, EPA concluded that

the threats in those cases were not substantial enough to cause large-scale, system-level 

ecological disruptions.

On review, EPA has concluded that the ecological damage cases are appropriate for 

consideration because, while they might involve CWA violations, they nevertheless reflect 

damages from CCR releases that might be handled under RCRA pollution controls. And, while 

they may or may not have involved systems-level disruption, they were significant enough to 

lead to state response actions (e.g., fish advisories). EPA now believes that ecological damages 

warranting state environmental response are generally appropriate for inclusion as damage cases, 

and to fail to include them would lead to an undercounting of real and recognized damages. 

 

33 Text of the 2009 H.R. 493 bill is available at: http://www.govtrack.us/congress/billtext.xpd?bill=h111-493

34 U.S. Senate Resolution 64 is at: http://www.govtrack.us/congress/bill.xpd?bill=sr111-64&tab=committees

35 “Regulatory Determination on Wastes from the Combustion of Fossil Fuels; Final Rule,” Federal Register, May 22, 2000, Vol. 

65, Nr. 99, 32213 to 32237, http://www.epa.gov/fedrgstr/EPA-WASTE/2000/May/Day-22/f11138.htm
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Accordingly, at the time of the May 2000 CCR Regulatory Determination, in total, 15 cases of 

proven damages had occurred. Subsequently, one of the 15 proven damage cases has been 

reclassified as a potential damage case, resulting in a total of 14 proven cases of damage.

Since the May 2000 Regulatory Determination, additional groundwater and surface water 

damage cases have occurred, including ecological damage cases, and were discussed in EPA’s 

August 2007 CCR NODA.36 Specifically, EPA has gathered or received information on 135 

alleged CCR damage cases to groundwater or surface water since 2000.

Human health risks from CCR leaching into groundwater are described and quantified in EPA’s 

risk assessment in support of the CCR final rule. The CCR final rule will preventis expected to 

reduce continued human health risks and natural resource damage from current and future CCR 

contamination of groundwater and surface waters in neighborhoods and communities 

surrounding coal-fired electric utility plants.

With respect to groundwater, this need is of particular national significance because 43 million 

people in the United States,37 living in about 16 million housing units,38 rely on groundwater for 

their primary water supply through private domestic wells. The remaining 112 million U.S. 

housing units receive municipal water, of which 33% nationwide is sourced from groundwater.39

As displayed in Exhibit 1-A below, across all eight major fresh water withdrawal categories 

(i.e., municipal, residential, agriculture irrigation, livestock, aquaculture, industrial, mining, and 

electric utilities), groundwater constitutes 23% (79.6 billion gallons) of the 349 billion gallons of 

fresh surface water and fresh groundwater used daily in the United States as of 2005.40 Exhibit 

1-B below presents the 55-year nationwide trend in groundwater use, which has increased from 

20% in 1950 to 23% in 2005 of total freshwater withdrawals. These statistics indicate that 

groundwater is a significant natural resource for the U.S. economy.

 

36 “Notice of Data Availability on the Disposal of Coal Combustion Wastes in Landfills and Surface Impoundments,” Federal 

Register, Vol. 72, Nr. 167, August 29, 2007, pp. 49714 to 49719. Additional information about EPA’s 2007 NODA is available 

at: http://www.epa.gov/waste/nonhaz/industrial/special/fossil/noda07.htm

37 U.S. Geological Survey on page 19 of “Estimated Use of Water in the United States in 2005,” Circular 1344, 2009, 

http://pubs.usgs.gov/circ/1344/ Year 2010 data will not be available until 2014 according to the USGS at: 

http://water.usgs.gov/watuse/

38 “Table 1A-4: Selected Equipment and Plumbing – All Housing Units,” in U.S. Department of Housing and Urban 

Development and the U.S. Census Bureau joint report “American Housing Survey for the United States: 2007,” report nr. 

H150/07, Sept 2008, http://www.census.gov/prod/2008pubs/h150-07.pdf

39 U.S. Geological Survey “Estimated Use of Water in the United States in 2005,” Circular 1344, 2009, 

http://pubs.usgs.gov/circ/1344/

40 U.S. Geological Survey “Estimated Use of Water in the United States in 2005,” Circular 1344, 2009, 

http://pubs.usgs.gov/circ/1344/
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Furthermore, by reducing future incidences of CCR contamination of groundwater and surface 

waters, the CCR final rule is expected to reduce the future costs associated with groundwater and 

surface water cleanup (i.e., remediation and corrective action costs). As summarized above, a 

number of historical and recent environmental CCR damage cases represent externalities, in that 

some or all of the human health damages and environmental damages may be characterized as 

“external” to the capital and operating costs of the electric utility plants. The CCR final rule may 

be expected to reduce this externality, by internalizing into the capital and operating costs of the 

electric utility plants, the added costs of installing CCR pollution controls and oversight of the 

physical integrity of CCR impoundments. Externalities are is a type of market failure recognized 

in OMB’s Circular A-4 guidance (page 4): “An externality occurs when one party’s actions 

impose uncompensated benefits or costs on another party. Environmental problems are a classic 

case of externality.”
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Exhibit 1-A

Groundwater Supply to Major Categories of Freshwater Use in the United States (2005)a

Major water use 

categoriesb

Total Daily 

Freshwater 

Withdrawals

(Mill.Gals/Day)

Total Daily Freshwater 

Supplied by Surface Water

Total Daily Freshwater 

Supplied by Groundwater

Mill.Gals/Day % Total Mill.Gals/Day % Total

Public (municipal) 44,200 29,600 67% 14,600 33%

Domestic (residential) 3,830 90 2% 3,740 98%

Irrigation 128,000 74,500 58% 53,500 42%

Livestock 2,140 850 40% 1,290 60%

Aquaculture 8,780 6,870 78% 1,910 22%

Industrial 17,000 13,930 82% 3,070 18%

Mining 2,310 1,290 56% 1,020 44%

Electricity plants 143,000 142,490 99.96% 510 0.4%

Totals 349,000 269,400 77% 79,600 23%

a Mill.Gals/Day = million gallons per day. Total freshwater withdrawals found in Table 2A (page 7), and groundwater 

withdrawals found in Table 4A (page 11) of the U.S. Geological Survey (USGS) report Estimated Use of Water in the 

United States in 2005, Circular 1344, 2009, http://pubs.usgs.gov/circ/1344/. Year 2010 data will not be available until late 

2014 according to the USGS at http://water.usgs.gov/watuse/.

b The USGS definitions of major water use categories are:

 Public: Water withdrawn by public and private water suppliers that provide water to at least 25 people or have a 

minimum of 15 connections. Public-supply water is delivered to users for domestic, commercial, and industrial purposes, 

and also is used for public services.

 Domestic: Indoor and outdoor uses at residences. Common indoor water uses are drinking, food preparation, washing 

clothes and dishes, and flushing toilets. Common outdoor uses are watering lawns and gardens and washing cars. 

Domestic water is either self-supplied or provided by public suppliers. Self-supplied domestic water use is usually 

withdrawn from a private source, such as a well, or captured as rainwater in a cistern. An estimated 42.9 million people 

in the United States, or 14% of the population, supplied their own water for domestic use in 2005.

 Irrigation: Water applied by an irrigation system to sustain plant growth in all agricultural and horticultural practices. 

Irrigation also includes water applied for pre-irrigation, frost protection, application of chemicals, weed control, field 

preparation, crop cooling, harvesting, dust suppression, leaching salts from the root zone. Irrigation of golf courses, 

parks, nurseries, turf farms, cemeteries, and other landscape uses also are included.

 Livestock: Water associated with livestock watering, feedlots, dairy operations, and other on-farm needs. Livestock 

includes dairy cows and heifers, beef cattle and calves, sheep and lambs, goats, hogs and pigs, horses, and poultry. Other 

livestock water uses include cooling of facilities for the animals and animal products such as milk, dairy sanitation and 

wash down of facilities, animal waste-disposal systems

 Aquaculture: Water associated with raising organisms that live in water—such as finfish and shellfish—for food, 

restoration, conservation, or sport. Aquaculture occurs under controlled feeding, sanitation, and harvesting procedures 

primarily in ponds, flow-through raceways, cages, net pens, and closed-recirculation tanks.

 Industrial: Water used for fabricating, processing, washing, diluting, cooling, or transporting a product; incorporating 

water into a product; or for sanitation needs within the manufacturing facility. Some industries that use large amounts of 

water produce food, paper, chemicals, refined petroleum, or primary metals.

 Mining: Water used for the extraction of minerals that may be in the form of solids, such as coal, iron, sand, and gravel; 

liquids, such as crude petroleum; and gases such as natural gas. The category includes quarrying, milling (crushing, 

screening, washing, and flotation of mined materials), re-injecting extracted water for secondary oil recovery, and other 

operations associated with mining activities.

 Electricity plants: Water used in generating electricity with steam-driven turbine generators. Once-through (also known 

as open-loop) cooling refers to water circulated through heat exchangers and then returned to a surface-water body. 

Recirculation (also known as closed-loop) cooling refers to water circulated through heat exchangers, cooled using ponds 

or towers, and then re-circulated.
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Source: Table 14 “Trends in Estimated Water Use in the United States 1950-2005,” page 43 of the USGS report Estimated Use of 

Water in the United States in 2005 2009 Circular 1344 at http://pubs.usgs.gov/circ/1344/pdf/c1344.pdf

More recent five-year interval 2010 data will not be available from the USGS until late 2014 according to the USGS at 

http://water.usgs.gov/watuse/

4.3. PreventReduce future CCR surface impoundment structural failures and 

associated releases of CCR into the environment

In addition to the groundwater and surface water damage cases summarized in the prior section, 

within the last ten years (2005-2014), EPA learned of seven additional cases of environmental 

damages involving the structural failure (e.g., breach, break, rupture) of CCR surface 

impoundments. Structural failure involves dam safety and structural integrity, a damage pathway 

involving CCR impoundments that EPA did not consider at the time of the May 2000 CCR 

Regulatory Determination. These seven additional CCR impoundment structural failure cases 

involved:

2005 A 0.5 million cubic yard release of water and fly ash to the Delaware River at the 

Martin's Creek Power Plant in Pennsylvania in 2005, leading to a response action costing 

$37 million. Fortunately, no homes were in the path of the release and damage was 

confined to power plant property and the Delaware River.

20% 21% 21% 22% 21%

24% 23% 22% 24% 23% 24% 23%

0

50

100

150

200

250

300

350

400

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005

Billion Gallons Per Day Withdrawal

Exhibit 1-B

55-Year U.S. Historical Trend in Groundwater Use for 

National Fresh Water Supply

Groundwater (fresh) Surface water (fresh)

20% 21% 21% 22% 21%

24% 23% 22% 24% 23% 24% 23%

0

50

100

150

200

250

300

350

400

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005

Billion Gallons Per Day Withdrawal

Exhibit 1-B

55-Year U.S. Historical Trend in Groundwater Use for 

National Fresh Water Supply

Groundwater (fresh) Surface water (fresh)
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2007 In February 2007, CCR impoundments at the Eagle Valley power plant operated by 

Indianapolis Power and Light released 30 million gallons of CCR. A wall separating two 

CCR impoundments failed (breached).

2008 In January 2008, the same wall which failed in February 2007 at the Eagle Valley power 

plant collapsed and again released 30 million gallons of CCR.

The December 2008 catastrophic failure of a dike at TVA's Kingston, Tennessee utility 

plant, releasing 5.4 million cubic yards of fly ash sludge over an approximately 300 acre 

area and into a branch of the Emory River. This event disrupted electrical power, 

ruptured a gas line, knocked one home off its foundation and damaged others. 

Fortunately, there were no injuries. The massive cleanup operation overseen by EPA and 

the state of Tennessee is estimated to cost $1.2 billion.

2009 Another case involved the January 2009 failure of a discharge pipe at the TVA Widows 

Creek plant in Stevenson, Alabama, resulting in a 6.1 million gallon release from a fluegas desulfurization (FGD) pond, leading to $9.2 million in remediation costs.

2011 In October 2011, a bluff collapsed near an ongoing construction project at the Wisconsin 

Energy Oak Creek power plant, releasing 4.6 million gallons of CCR into Lake 

Michigan. According to the US EPA On-Scene Coordinator, Wisconsin Energy reported 

spending $12.1 million on remediation and restoration.

2014 In early February 2014, a release of 27 to 35 million gallons (39,000 tons) of CCR from a 

CCR surface impoundment occurred at the Dan River power plant operated by Duke 

Energy in North Carolina. The release was caused by collapse of concrete and corrugated 

steel storm sewer pipes running under the impoundment. Total remediation cost estimates 

were not available for this RIA but Duke Energy reportedly paid $15 million in 

immediate response costs to contain the spill.

41

In response to the catastrophic December 2008 impoundment failure, EPA mailed letters in 

March and April 2009 requesting that electric utility companies with CCR surface 

impoundments (and similar bermed or diked CCR units that receive liquid-borne CCR) provide 

information about the structural integrity of their units, and about “known spills or unpermitted 

releases over the last 10 years” (1999 to 2008).42 In response to the letters, electric utility 

companies reported a total of 42 structural failure release events involving CCR impoundments, 

all of which occurred within the last 15 years (1995-2009).43

During the 2010 public comment period for EPA’s June 2010 CCR proposed rule, citizens 

residing near electric utility plants expressed to EPA their fear and anxiety concerning the risk of 

future impoundment structural failures. EPA heard evidence of public fear concerning CCR 

 

41 Source: “Duke Energy Agrees to Fund Dan River Cleanup,” the Associated Press, June 9, 2014.

42 The content of the March and April 2009 letters mailed to electric utility companies, and additional background information, is 

available at: http://www.epa.gov/waste/nonhaz/industrial/special/fossil/coalashletter.htm#letter

43 The 42 CCR impoundment failure events are listed in Exhibit 6-A in Section 6.1.2 of this RIA.
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impoundments from 113 citizens in comments on the June 2010 proposed CCR rule.44 This 

count consists of 40 citizens submitting written comments to EPA’s docket for the June 2010 

proposed CCR rule, and 73 citizens making verbal statements at EPA’s eight public hearings on 

the June 2010 proposed CCR rule held from August to October 2010.45 Citizens who made these 

comments to EPA reside within 0.25 to 1.5 miles of CCR impoundments. According to 2000 

Census Bureau data, over 25163,5000 people reside within one-mile of CCR landfills and CCR 

impoundments located at coal-fired electric utility plants.46

The CCR impoundment structural failure damages cases spanning 1995 to 2014, as well as the 

fear expressed by citizens residing near CCR impoundments, underscore the ongoing nationwide 

need for CCR impoundment structural integrity regulatory requirements.

5.4. Reduce future public exposure to fugitive CCR dust from CCR landfills and 

CCR surface impoundments

Prior to EPA’s June 2010 proposed CCR rule, the public need for control of fugitive CCR dust 

was manifest in at least five sources:

 Peer review comment to EPA’s 2008 draft CCR Risk Assessment;

 Stakeholder comments on EPA’s 2007 CCR NODA;

 Photographic documentation of fugitive dust associated with the hauling and 

disposal of CCRs;

 EPA’s efforts to control and monitor fugitive dust emissions from the December 

2008 TVA Kingston CCR impoundment spill;47 and

 OSHA’s requirement for Material Safety Data Sheets for coal ash.

Fugitive CCR dust from CCR landfills and CCR impoundments may originate from CCR 

unloading operations, CCR landfill spreading and compacting operations, the re-suspension of 

CCR particulates from truck traffic on or near coal-fired power plants, and wind erosion of CCR

landfills and CCR impoundments (there are reported cases of dust from frozen impoundments).

To evaluate the potential risk of exposure to residents who live near coal-fired electric utility 

plants to fugitive CCR dust, in 2010 EPA performed a screening-level analysis Inhalation of 

Fugitive Dust: A Screening Assessment of the Risks Posed by Coal Combustion Waste 

Landfills.

48 The study concluded that without fugitive CCR dust controls, fine particulate matter 

 

44 Comments identified as containing one or more of the following terms: fear, danger, afraid, scared, and worry.

45 In the states of CO, IL, KY, NC, PA, TN, TX, and VA.

46 See 2009 EPA risk assessment by RTI International.Appendix U to this RIA presents one mile population data.

47 Air monitoring results for fine particulate matter at the TVA Kingston TN CCR impoundment spill site are available at: 

http://www.epakingstontva.com/Air%20and%20Water%20Data%20Summaries/Forms/AllItems.aspx

48 EPA’s 2010 fugitive CCR dust screening analysis is available as document ID nr. EPA-HQ-RCRA-2009-0640-0142 at 

http://www.regulations.gov
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in the air at residences located near CCR landfills could exceed the National Ambient Air 

Quality Standards (NAAQS).
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After EPA’s June 2010 CCR proposed rule, a number of citizens who reside near coal-fired 

electric utility plants testified about CCR dust problems at EPA’s eight public hearings, held 

between August and October 2010 on the CCR proposed rule.49 There are 129 references to CCR 

dust made by citizens in the manuscripts of the eight public hearings.

6.5. Correct negative externalities, and inadequate and asymmetric information, 

about the risks to human health and the environment from CCR landfills 

and CCR surface impoundments

The In addition to item 3 above, the CCR final rule also addresses aanother type of market 

failure: inadequate or asymmetric information. recognized by OMB Circular A-4 recognizes 

“material failures of private markets to protect or improve the health and safety of the public, the 

environment, or the well-being of the American people(page 5) “Inadequate or Asymmetric 

Information” as an example of compelling public need for federal regulation.

The CCR final rule may be characterized as addressing the negative externality of environmental 

pollution and damages from CCR landfills and CCR impoundments. As summarized above, a 

number of historical and recent environmental CCR damage cases represent externalities, in that 

some or all of the human health damages (such as human cancer cases from contaminated 

groundwater near CCR landfills and impoundments), and environmental damages (ecological 

damages, natural resource damages, and socio-economic damages from CCR spills/releases from 

impoundment structural failures) may be external to the capital and operating costs of the electric 

utility plants. The CCR final rule may be expected to reduce this market failure externality, by 

internalizing into the capital and operating costs of the electric utility plants, the added costs of 

installing engineering controls and oversight of the physical integrity of CCR impoundments.

Citizens residing near CCR landfills and impoundments may be unaware of exposure to toxic 

chemical constituents contained in CCR which may be leaching into the ground and groundwater 

at certain locations. Thus, while nearby citizens may have the right to legal lawsuits to recuperate 

health and property damages, citizens may not be aware of the need to do so until health risks 

(and health costs) have already been incurred.

Firms are sometimes held accountable for some of the externalhealth and environmental damage

costs through lawsuits brought by affected citizens. However, the system of accountability can 

be imperfect and may not represent the total economic value of avoiding or reducing risks. The 

primary human bearers of the external costs from CCR landfills and impoundments are residents 

of households located near those units. When

When information is lacking, and when unorganized households suffer external costs, they face a 

host of obstacles to having those costs recuperated. They must form a coherent organization and 

they must have enough funding to launch and maintain a lawsuit. On the other side of such 

litigation, households usually face a single firm, which is an existing effective organization and 

also often possesses greater legal funding resources. This information and resource imbalance 

 

49 Transcripts from EPA’s eight public hearings on the 2010 CCR proposed rule are available at the following EPA website: 

http://www.epa.gov/waste/nonhaz/industrial/special/fossil/ccr-rule/ccr-hearing.htm. Hearings were held in CO, IL, KY, NC, PA, 

TN, TX, and VA.
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suggests that external costs of contamination from industrial waste sites (such as leaking CCR 

landfills and CCR impoundments) may not be recuperated at an efficient level.

The CCR final rule will increase the public availability of information about actual and potential 

CCR contamination risks to households and communities by multiple requirements:

 The CCR rule contains a number of provisions requiring electric utility companies to 

document their compliance with the CCR rule’s technical requirements.

 To post those documents on a publically available website in a timely and transparent 

manner.

 The rule also requires utility companies to notify state government environmental 

agencies of numerous actions, including that certified CCR pollution control and safety 

demonstrations have been completed. This transparency will facilitate citizen and state 

government oversight and overall enforcement of the CCR rule.

 Finally, the rule establishes specific time frames by which these actions must occur, 

including time frames by which facilities must document compliance with the various 

technical requirements in the rule. Time frames have been established for: (1) technical 

compliance demonstrations made by the owner or operator; (2) certifications made by a 

qualified professional engineer verifying the technical accuracy and veracity of the 

compliance demonstration; (3) notifications made to the State Director; (4) submittals 

(e.g., data, reports and other documentation) to the operating record; and (5) postings to 

the owner or operator’s publicly accessible internet site.
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1.4 Summary of Public Comments on EPA’s 2010 CCR Proposed Rule RIA

Exhibit 1-C below provides an overview of the 17 types of organizations50 which submitted a 

total of 1,355 comments, in part or in whole, on topics directly or indirectly related to EPA’s 

RIA for the June 2010 proposed CCR rule. The public comments consist of two sets:

 Docket comments: 431 organizations submitted 1,067 RIA-related comments during the 

5-month (June 21 to November 19, 2010) public comment period51 for EPA’s June 21, 

2010 proposed CCR rule.

 Hearings comments: 170 organizations submitted 288 RIA-related comments at EPA’s 

eight public hearings52 on the June 21, 2010 proposed CCR rule held sequentially 

between August 30 and October 27, 2010 in VA, CO, TX, NC, IL, PA, KY, and TN.

Appendix W to this RIA provides a list of the identities of the 431 docket commenters and the 

170 hearing commenters.

Exhibit 1-C

Types of Organizations Which Submitted Comments Related to EPA’s 2010 CCR RIA

A B C D E F G H I

Organization Type

Docket Comments Hearings Comments

Organization Count Comment Count Organization Count Comment Count

Count % Count % Count % Count %

1 Academia 4 0.9% 4 0.4% 3 1.8% 6 2.1%

2 Advocacy Group 25 5.8% 155 14.5% 17 10.0% 25 8.7%

3 Anonymous 1 0.2% 1 0.1% 0 0% 0 0%

4 Beneficial User 157 36.4% 250 23.4% 27 15.9% 39 13.5%

5 Community/ Religious/ Social 0 0.0% 0 0.0% 7 4.1% 11 3.8%

6 Electric Utility Company 86 20.0% 234 21.9% 43 25.3% 86 29.9%

7 Electric Utility FacilityPlant 7 1.6% 19 1.8% 6 3.5% 10 3.5%

8 Federal Agency 1 0.2% 4 0.4% 0 0% 0 0%

9 Federal Elected Official 1 0.2% 2 0.2% 2 1.2% 6 2.1%

10 Local Government 9 2.1% 12 1.1% 1 0.6% 1 0.3%

11 Other Company 11 2.6% 23 2.2% 2 1.2% 2 0.7%

12 Private Citizen 21 4.9% 35 3.3% 19 11.2% 25 8.7%

13 State Elected Official 3 0.7% 3 0.3% 0 0% 0 0%

14 State Government 38 8.8% 121 11.3% 3 1.8% 6 2.1%

15 Trade Association 60 13.9% 192 18.0% 38 22.4% 67 23.3%

16 Tribal Government 4 0.9% 9 0.8% 0 0% 0 0%

17 Union 3 0.7% 3 0.3% 2 1.2% 4 1.4%

Column totals = 431 100% 1,067 100% 170 100% 288 100%

 

50 For the purpose of this RIA an “organization” is defined as a commenting organization and its spokesperson. For example, if 

one company submitted two comments by two separate spokespeople, it is counted as two organizations. “No organization 

provided” is counted as a single organization, and if one organization commented individually and also commented jointly with 

other organizations, the two comments are counted as separate organizations.

51 On page 35128 of EPA’s Federal Register notice (Vol. 75, No. 118, June 21, 2010) for the 2010 CCR proposed rule, EPA 

initially provided a 3-month public comment period spanning June 21 to September 20, 2010. In addition to publishing on 

August 20, 2010 in the Federal Register (Vol. 75, No. 161, pages 51434 to 51436) several administrative corrections to the 

proposed rule, EPA also in that same notice extended the public comment period by 60-days to November 19, 2010. The docket 

ID number for written public comments on the 2010 CCR proposed rule is EPA-HQ-RCRA-2009-0640 at 

http://www.regulations.gov

52 Transcripts from EPA’s eight public hearings on the 2010 CCR proposed rule are available at the following EPA website: 

http://www.epa.gov/waste/nonhaz/industrial/special/fossil/ccr-rule/ccr-hearing.htm
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Exhibit 1-D below provides a summary of the specific RIA-related topics associated with the 

1,355 public comments. As indicated in row 7 of Exhibit 1-D, a sub-total 363 (27%) of the 

1,355 total comments were not directly related to the 2010 RIA but involved non-specific RIA 

topics (such as comments on the CCR proposed rule and the national economy more generally) 

which did not directly relate to or associate with any particular sections, data, calculations, or 

results of the 2010 RIA. The largest sub-total of comments (i.e., 471 (35%) of the 1,355 total 

comments) addressed regulatory costs as indicated in row 2 of Exhibit 1-D below.

Exhibit 1-D

Public Comment Topics Related to EPA’s RIA for the 2010 CCR Proposed Rule

RIA Topic and Sub-Topic Categories

Count of Docket 

Comments

Count of Hearings 

Comments

1 General comments on RIA:

RIA’s problem statement

Identity of affected entities

12 1.1% 0 0%

2 Regulatory costs:

Historical/baseline costs

CCR pollution control cost assumptions

371 34.8% 100 34.7%

3 Regulatory environmental and economic benefits:

Appropriateness of benefit categories

Benefit monetization issues

Avoided cost benefits

99 9.3% 3 1.0%

4 Impacts on CCR beneficial uses:

Accuracy of beneficial use lifecycle benefits

Industry-specific data sources

Beneficial use impact scenarios (e.g., market stigma)

231 21.6% 71 24.7%

5 Net benefits:

Cost/benefit scaling under Subtitle D options

Comparison of benefits to costs

37 3.5% 5 1.7%

6 Supplemental analyses:

(i.e., analyses to address Executive Orders and Statutes (energy impact, 

environmental justice, children’s health, small business impact, unfunded 

mandates, Federalism, tribal consultation)

63 5.9% 0 0%

7 Other topics:

(although initially categorized by EPA as RIA-related, these comments 

are about other topics not specifically related to the 2010 RIA data, 

methods, calculations, or results)

254 23.8% 109 37.8%

Column totals = 1,067 100% 288 100%

According to the topic categories displayed in Exhibit 1-D above, some specific examples of public 

comment sub-topics related to the 2010 RIA include:

 Affected Industrial Entities and CCR Management Units

o RIA has incorrect count data on CCR surface impoundments.

o RIA has incorrect power plant ownership information.

 Environmental and Economic Benefits

o RIA understates benefits of avoided accidental releases of CCR.

o RIA did not do a complete job evaluating benefits.

o RIA needs to monetize stigma of household value loss near potential CCR spill 

sites.

o RIA should quantify avoided (1) litigation costs, (2) reduction of effluent 

discharges through phase out of CCR surface impoundments, (3) reduction in 
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health risk to non-carcinogenic but toxic chemicals in CCR, and (4) human health

effects from improperly managed CCR dry disposal.

o RIA underestimates the ecological impact damage of significant CCR spills.

o RIA applies a 15 year period of historical record for CCR impoundment structural 

failures, but the actual historical record is 10 years of data.

o RIA does not fully monetize health risk benefits.

o RIA does not evaluate other types of ecological damages other than groundwater.

 Regulatory Compliance and Implementation Costs

o RIA has errors and problems in assumptions and calculation of regulatory 

compliance costs.

o RIA has a transcription error in ancillary cost #15 (waste disposal permit cost).

o RIA underestimates Subtitle D costs.

o RIA underestimates Subtitle C costs.

o Disagrees with some cost assumptions.

o RIA does not include relevant data from a recent EPRI cost analysis.

 Net Benefits and Benefit-Cost Ratios

o The Subtitle C option would have greatest net benefits if a relatively small dollar 

value is also assigned to the many benefits categories that are not monetized in the 

RIA.

o RIA repeatedly omits categories of costs and benefits which would support the 

case for stronger regulation of CCR.

o RIA’s cost and benefit scaling factors are inaccurate for both Subtitle D options.

 CCR Beneficial Use Impact Scenarios

o RIA overstates annual lifecycle benefits of beneficial reuse of CCR.

o RIA assigns an incorrect dollar value to beneficial use stigma.

o RIA’s magnitude and duration scenario of potential stigma seems arbitrary.

o RIA’s avoided disposal cost offset for increased CCR beneficial use is incorrect.

o RIA does not discuss potential insurance cost increases for beneficial use of CCR.
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Chapter 2

Affected Universe and Analytic Framework for the RIA

Note: EPA’s final estimates of total costs and benefits, displayed in the executive summary, 

reflect updates to the universe and analytic framework. These modifications were made to 

reflect actual and projected changes in the universe of coal-fired electric utility plants

occurring after 2012, and conform to the Base Case projected by the Integrated Planning 

Model, v.5.13. The modifications are not included in this chapter. See Sections 9.2.1 and 

9.2.2 in Chapter 9 of this RIA for a description of the relevant modifications and updates to 

the universe and analytic framework.

This chapter consists of four sections that define the analytic scope and framework of this RIA. 

The first three sections, Sections 2.1 – 2.3, define the universe of facilities and units affected by 

the rule as follows: 

 Section 2.1 - Directly Affected Industries. Identifies the types of industries that 

may be directly affected by the CCR final rule. The rule directly impacts coalfired electricity generating plants operated by the electric utility industry, 

specifically the North American Industry Classification System (NAICS) 221112 

“Fossil Fuel Electric Power Generation” industry. Three additional industries (offsite commercial waste transport, offsite commercial waste disposal, and 

sand/gravel pits and quarries) may be directly affected.

 Section 2.2 - Indirectly Affected Industries. Identifies the industries that may be 

indirectly affected by the CCR rule. This RIA evaluates potential indirect impacts 

on industry sectors that beneficially use CCR as raw or intermediate materials.53

 Section 2.3 - Affected Electric Utility Plants. Identifies the coal-fired electric 

utility plants affected by the CCR rule. Based on 2012 EIA data, EPA identified 

478 coal-fired electric utility plants as potentially affected by the CCR rule.

The remaining section (Section 2.4) outlines several key analytic principles that constitute the 

analytic framework for this RIA, including constant pricing, two alternative discount rates, 

period of analysis, and projection of future trends in coal consumption by the electric utility 

industry.

2.1 Directly Affected Industries

This section identifies the industries (by name and NAICS code) associated with directly 

affected entities that are subject to the requirements of the final regulation, which pertains to 

disposal of CCRs by coal-fired electric utility plants.54 Because CCR is transported off-site from 

some electric utility plants for disposal, the off-site commercial waste transport and offsite 

 

53 EPA’s IPM analysis will also examine effects on energy producers using other fuel sources. These impacts are not addressed in 

this RIA. The IPM analysis is available as a separate report (December 2014) from the docket for the CCR final rule (docket nr. 

EPA-HQ-RCRA-2009-0640 at http://www.regulations.gov).

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

Development Series, Nov 2006, Footnote 14 at: http://www.epa.gov/sbrefa/documents/rfaguidance11-00-06.pdf
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commercial waste disposal industries are also directly affected, as are the owners of sand and 

gravel pits and quarries that the CCR rule affects. Each of these four industries is described 

below.

2.1.1 Coal-Fired Electric Utility Industry

The scope of industrial plants directly affected by the CCR final rule is classifiable according to 

at least two different glossary systems.

 NAICS classification. The first glossary system of relevance is the North 

American Industrial Classification System (NAICS) code 221112. The scope of 

industrial plants is classifiable as “coal-fired electric utility plants” under the U.S. 

Census Bureau’s NAICS 22 Utilities sector, as a subgroup of the 1,248 

establishments (as of 2007) within the NAICS 221112 “Fossil Fuel Electric 

Power Generation” industry.55,56

 EIA classification. The second relevant glossary system is the U.S. Department 

of Energy’s Energy Information Administration (EIA) classification, which 

includes facilities classified as “electric utilities and independent power 

producers” in its categorization system for coal combustion electric power sector 

statistics.57

This RIA has identified a total of 478 coal-fired electric utility plants that operate in 2012 and 

use a total of 1,045 waste management units (735 surface impoundments and 310 landfills). A 

complete list of the 478 plants is included in Appendix A to this RIA, and the universe is 

discussed in more detail in Section 2.3 and Chapter 3.

It is also important to identify inactive or abandoned CCR surface impoundments at coal-fired 

utility plants in the regulatory universe because these units are within the scope of the regulatory 

 

55 NAICS, which replaced the Standard Industrial Classification (SIC) system in 1997, groups establishments into industries 

according to similarity in the processes used to produce goods or services. Each establishment that falls within a larger business 

enterprise (e.g., a single physical location such as a factory, mill, store, hotel, movie theater, mine, farm, airline terminal, sales 

office, warehouse, or central administrative office) is assigned a NAICS code based on its own primary business activity. A 

larger enterprise, on the other hand, may consist of more than one location performing the same or different types of economic

activities. Source: U.S. Census Bureau, North American Industry Classification System Frequently Asked Questions (FAQSs) at 

https://www.census.gov/eos/www/naics/faqs/faqs.html. 

56 NAICS 221112 states,: “This U.S. industry comprises establishments primarily engaged in operating fossil fuel powered 

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

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

is provided to electric power transmission systems or to electric power distribution systems.” NAICS codes are defined at: 

http://www.census.gov/cgi-bin/sssd/naics/naicsrch?chart=2007

57 EIA defines an electric utility as: “Any entity that generates, transmits, or distributes electricity and recovers the cost of its 

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

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

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

municipalities, rural electric cooperatives, and State and Federal agencies.” It further defines an independent power producer as, 

“A corporation, person, agency, authority, or other legal entity or instrumentality that owns or operates facilities for the 

generation of electricity for use primarily by the public, and that is not an electric utility.” The EIA glossary of terms is available 

online at at: http://www.eia.doe.gov/glossary/index.html
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requirements of the final regulation.58 Inactive CCR impoundments are not currently in operation 

or not receiving CCR, but are not fully closed (i.e., not fully dewatered and capped). These 

impoundments could potentially receive CCR in the future. This RIA estimates that as of 2012, 

coal-fired electric utility plants in the universe had 310 active CCR landfills, 735 active CCR 

impoundments, and 111 inactive CCR impoundments.59

 CCR landfills (as of 2012):

o Active = 310

o Inactive = N/A

 CCR surface impoundments (as of 2012):

o Active = 735

o Inactive = 111

This RIA assumes that entities subject to the requirements of the CCR final rule do not include 

non-utility coal-fired electricity plants. This RIA estimates that between 164 and 759 nonutility electricity plants either currently burn coal, or have the capacity to burn coal, and thus 

may generate CCR in addition to the 478 utility plants. This range is based on two data sources:

1. 2012 DOE EIA-923 database.

60 As displayed below in Exhibit 2-A, the EIA 

database identifies 164 non-utility coal-fired electricity plants in eight industrial 

economic sectors (spanning 25 industries) outside of NAICS economic sector 22. 

Appendix B of this RIA contains a list of plants in these other industries 

operating coal-fired electricity plants. These plants burn 5.3 million tons per year 

(as of 2012) of coal as fuel, which is 0.6% of the 819.2 million tons of coal 

burned by electric utility plants in 2012 (Appendix A presents reported/estimated 

annual tons of coal burned). The DOEBased on the EIA-923 databasedata this 

RIA estimates 2012 annual CCR generation by these other 25 industries at 0.5 

million tons CCR per year.

2. 2001 Council of Industrial Boiler Owners (CIBO) Voluntary Survey.

61 An 

analysis of the results of the 2001 CIBO Voluntary Survey of non-utility CCR 

generation identified 759 non-utility coal-fired electricity plants “with the 

capacity to burn coal, and therefore, generate CCR.” This RIA does not provide a 

list of these 759 non-utility plants from this second data source. The estimated 

CCR generation for these non-utility plants was 7.8 million tons in 2000, which is 

 

58 Inactive and/or abandoned CCR landfills are not subject to the CCR final regulationrule.

59 This reflects a combination of data from one or more of the following sources: (a) Impoundment data from ORCR's 2009-2012 

impoundment site inspections (http://www.epa.gov/waste/nonhaz/industrial/special/fossil/surveys2/index.htm); (b) Impoundment 

data from ORCR's 2009 mail survey to plants with impoundments: 

(http://www.epa.gov/waste/nonhaz/industrial/special/fossil/coalashletter.htm); (c) Landfill data from EPA Office of Water's 2010 

mail survey to power plants for the Steam Electric Power Generating Effluent Guidelines 

(http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm#point6); and (d) 2009 DOE EIA-923 data reporting other onsite 

landfill or onsite impoundment disposal (http://www.eia.gov/cneaf/electricity/page/eia906_920.html).

60 2012 EIA-923 data source = U.S. Department of Energy, Energy Information Administration (EIA),. 2012,. “Form EIA-923 

January - December Final, Nonutility Energy Balance and Annual Environmental Information Data, 2012,” Available online at: 

http://www.eia.gov/cneaf/electricity/page/eia906_920.html

61 2001 CIBO data source = “Analysis of Non-Utility Coal Combustion Waste Generation and Management Based on the 2001 

CIBO Voluntary Survey,” prepared for EPA-OSWER by Science Applications International Corp (SAIC) Engineering and 

Environmental Management Group (Reston VA) under subcontract to Eastern Research Group (Arlington VA), April 2002, EPA 

contract No. 68-W-02-036, WA 12.
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6.5% of the 120.4 million tons CCR generated by electric utility plants in 2012 as 

estimated in Exhibit 2-H of this RIA.
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Exhibit 2-A

Industries Operating Coal-Fired Electricity Plants Not Covered by the CCR Rulea

Industry 

Count

NAICS 

Sectorb

NAICS 

Industryb NAICS Description

Coal-based Fuel 

Total (short tons)

Implied CCR 

Generationc

Plant 

Countd

1 31 311 Food Manufacturing 2,138,585 215,997 36

2 31 312 Beverage and Tobacco Product 

Manufacturing 61,989 6,261 3

3 31 314 Textile Product Mills 23,897 2,414 1

4 32 321 Wood Product Manufacturing 2,286 231 1

5 32 322 Paper Manufacturing 86,892 8,776 9

6 32 322122 Newsprint Millse 916,956 92,613 44

7 32 32213 Paperboard Mills 261,700 26,432 17

8 32 324 Petroleum and Coal Products 

Manufacturing 0 0 1

9 32 325 Chemical Manufacturing 458,031 46,261 6

10 32 325188 All Other Basic Inorganic Chemical 

Manufacturing 112,307 11,343 2

11 32 325211 Plastics Material And Resin 

Manufacturing 6,903 697 2

12 32 3253 Pesticide, Fertilizer, And Other 

Agricultural Chemical Manufacturing 14,265 1,441 1

13 32 327 Nonmetallic Mineral Product 

Manufacturing 307,302 31,038 4

14 33 331 Primary Metal Manufacturing 501,840 50,686 2

15 33 331111 Iron And Steel Mills 0 0 3

16 33 333 Machinery Manufacturing 2,225 225 2

17 33 336 Transportation Equipment Manufacturing 123 12 1

18 33 339 Miscellaneous Manufacturing 79,017 7,981 2

19 48 482 Rail Transportation 316 32 1

20 54 541 Professional, Scientific, And Technical 

Services 19,231 1,942 1

21 61 611 Educational Services 186,730 18,860 18

22 62 623 Nursing And Residential Care Facilities 14,000 1,414 1

23 62 624 Social Assistance 659 67 2

24 92 92 Public Administration 58,631 5,922 3

25 92 928 National Security And International 

Affairs 27,030 2,730 1

Counts N = 8 N = 25 Totals = 5,280,915 533,372 164

a EIA, 2012, “Form EIA-923 January - December Final, Nonutility Energy Balance and Annual Environmental Information Data, 2012,” at 

http://www.eia.gov/cneaf/electricity/page/eia906_920.html

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

industry group, the fifth digit designates the NAICS industry, and the sixth digit designates the national industry. The five-digit NAICS 

code is the level at which there is comparability in code and definitions for most of the NAICS sectors across the three countries 

participating in NAICS (the United States, Canada, and Mexico). The six-digit level allows for the United States, Canada, and Mexico 

each to have country-specific detail. A complete and valid NAICS code contains six digits. In this column, five-digit and six-digit NAICS 

codes rows are distinct from their upper-level, three-digit NAICS codes, such that each row provides a distinct volume of implied CCR 

generation with no double-counting. Source: http://www.census.gov/eos/www/naics/faqs/faqs.html#q5

cFrom Exhibit 2-I, 82.612million tons of non-FGD CCR were generated at electric utility plants. From Appendix A, 819.16 million tons 

of coal was burned by electric utility plants in 2009. The average number of tons of fly ash and bottom ash generated per ton of coal 

burned is 82.612 million tons of ash divided by 819.16 million tons of coal, or 0.101 tons of ash per ton of coal burned. This RIA applies 

this rate of ash generation to non-utility numbers for the amount of coal burned to derive an implied CCR ash generation amount.

d24 plants reported use of coal-based fuel by generators at the plant, but the reported quantity used in 2012 was zero short tons.

eOne plant submitted DOE EIA-860 data in 2012 reporting generators that use coal-based fuel (Riverwood International Macon Mill); this 

plant did not submit DOE EIA-923 data in 2012, so fuel and electricity quantities are not available. See Appendix B.
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2.1.2 Commercial Waste Transportation Industry

Industries involved in the transportation of waste may be affected by the CCR final rule because 

some electric utility plants transport CCR to company-owned or commercial off-site landfills. 

This RIA anticipates that trucking will be the predominant mode of CCR transport to offsite 

disposal. This assumption is consistent with transport practices for municipal solid waste, as well 

as a recent study regarding the transportation of hazardous materials by the Department of 

Commerce.62 The transportation-related industry most likely to be affected by the final 

regulation is NAICS 484230; Specialized Freight (except Used Goods) Trucking, LongDistance. This industry includes establishments primarily engaged in providing long-distance 

specialized trucking. These establishments provide trucking between metropolitan areas that may 

cross North American country borders. According to the 2007 U.S. Census, 320 establishments 

provided service code 44130, “Transportation of waste by road.”

63

2.1.3 Commercial Waste Disposal Industry

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

off-site landfills, and because the final regulation may trigger RCRA unit-level corrective action 

at coal-fired power plants, the final regulation may also affect at least three other environmental 

industries with the following NAICS codes:

 NAICS 562212. Solid waste landfill industry that receives CCR waste from coal 

combustion units that currently transport waste for off-site disposal.

 NAICS 562219. Other non-hazardous waste treatment and disposal industry that 

receives CCR waste from coal combustion units that currently transport waste for 

off-site disposal.

 NAICS 562910. Environmental cleanup/remediation services.

2.1.4 Sand and Gravel Pits and Quarries

Depending upon the extent of their current (baseline) CCR management and CCR pollution 

control practices, owners of some sand and gravel pits and quarries may be affected by the CCR 

rule because CCR is currently transported off-site from electric utility plants for disposal by 

these operations. The corresponding NAICS industry codes are:

 NAICS 212. Establishments in the mining subsector, except oil and gas. NAICS 

212 includes establishments that bear complete responsibility for operating mines 

 

62 U.S. Department of Commerce, 2007 Economic Census. “Transportation 2007 Commodity Flow Survey: Hazardous 

Materials,” EC07TCF-US(HM), July 2010, available at: http://www.bts.gov/publications/commodity_flow_survey/index.html

63 2007 Economic Census, Sector 48: Transportation and Warehousing: Industry Series: Preliminary Product Lines Statistics by 

Kind of Business for the United States: 2007. http://factfinder.census.gov/servlet/IBQTable?_bm=y&-geo_id=&-

fds_name=EC0700A1&-_skip=100&-ds_name=EC0748I3&-_lang=en
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and quarries (except oil and gas wells) and those that operate mines and quarries 

for others on a contract or fee basis.

This RIA does not have data on the count of pits and quarries and associated annual tonnage of 

CCR which they receive for disposal. However this RIA indirectly estimates the potential costs 

and benefits to pits and quarries to comply with the CCR rule, via use of “offsite disposal” CCR 

tonnage which this RIA models as offsite landfills, which is consistent with the CCR rule’s 

definition of “landfills” which includes sand and gravel pits and quarries. Thus the landfill 

related costs and benefits estimated in this RIA indirectly include the costs and benefits to pits 

and quarries, although not separately itemized in this RIA.

In addition to disposal in sand and gravel pits and quarries, CCR is currently disposed in mines 

(aka “mine filling”). However, the CCR final rule does not regulate CCR mine filling because the 

Office of Surface Mining, Reclamation and Enforcement (OSMRE) of the US Department of 

Interior plans to regulate mine filling under a separate upcoming rulemaking.64 Consequently, 

this RIA does not estimate impacts on CCR mine filling.

2.2 Indirectly Affected Industries

This section identifies the types of industries associated with entities that may be indirectly 

affected by the CCR final rule. This indirect effect category is defined and required for RIAs by 

the OMB Circular A-4 Regulatory Analysis guidance.65

Exhibit 2-B below lists 15 industrial applications which beneficially use CCR according to the 

American Coal Ash Association (ACAA) as of 201266 (with corresponding NAICS codes 

identified by EPA for purpose of this RIA). These industries are not directly affected by the CCR 

rule because the CCR rule leaves the existing Bevill exclusion for CCR beneficial uses in place, 

and does not regulate beneficial use. However, Chapter 5 of this RIA estimates a potential 

future increase in annual tonnage of CCR beneficial use according to the “avoided disposal cost” 

business practice of the electric utility industry as defined by the ACAA.

67

 

64 In March 2007 OSMRE published an advanced notice of proposed rulenaking titled “Placement of Coal Combustion

Byproducts in Active and Abandoned Coal Mines” (Federal Register, Vol. 72, No. 49, March 14, 2007, pages 12026 to 12030).

Information about OSMRE’s rulemaking concerning CCR mine filling is available on OSMRE’s website at 

http://www.osmre.gov/programs/TDT/ccrs.shtm

65

 The full text from OMB Circular A-4 reads:

“Your analysis should look beyond the direct benefits and direct costs of your rulemaking and consider any important 

ancillary benefits and countervailing risks. An ancillary benefit is a favorable impact of the rule that is typically 

unrelated or secondary to the statutory purpose of the rulemaking (e.g., reduced refinery emissions due to more 

stringent fuel economy standards for light trucks) while a countervailing risk is an adverse economic, health, safety, or 

environmental consequence that occurs due to a rule and is not already accounted for in the direct cost of the rule 

(e.g., adverse safety impacts from more stringent fuel-economy standards for light trucks). You should begin by 

considering and perhaps listing the possible ancillary benefits and countervailing risks. However, highly speculative or 

minor consequences may not be worth further formal analysis. Analytic priority should be given to those ancillary 

benefits and countervailing risks that are important enough to potentially change the rank ordering of the main 

alternatives in the analysis.” Source: OMB Circular A-4, Regulatory Analysis, 2003, p.26. Available online at: 

http://www.whitehouse.gov/omb/circulars_a004_a-4/

66 Source: American Coal Ash Association (ACAA) “2012 Coal Combustion Product (CCP) Production & Use Survey Report” at 

http://www.acaa-usa.org/Portals/9/Files/PDFs/revisedFINAL2012CCPSurveyReport.pdf

67 Source: The ACAA provides a definition of “avoided disposal cost” on its frequently asked questions (FAQ) webpage at 

http://www.acaa-usa.org/About-Coal-Ash/CCP-FAQs#Q14
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Exhibit 2-B

Industries that Beneficially Use CCR as Raw or Intermediate Ingredient (2012)

Industrial Application* Affiliated NAICS Code**

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

2. Blended cement/raw feed for 

clinker NAICS 3273 Cement and Concrete Product Manufacturing

3. Flowable fill NAICS 23 Construction

4. Structural fills/embankments NAICS 23 Construction

NAICS 21231 and 21232 Sand and Gravel Mining

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

6. Soil modification/stabilization NAICS 23 Construction

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

Manufacturing

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

Transportation

9. Blasting grit/Roofing granules

NAICS 212319 Other Crushed and Broken Stone Mining and 

Quarrying

NAICS 324122 Asphalt Shingle and Coating Materials 

Manufacturing

10. Mining applications NAICS 212 Mining

11. Gypsum panel products (e.g., 

wallboard) NAICS 327420 Gypsum Product Manufacturing

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

13. Agriculture NAICS 111 Crop Production

14. Aggregate NAICS 23 Construction

15. Miscellaneous (unidentified 

industries) NAICS not identified

Sources:

* 15 industrial applications listed above according to the American Coal Ash Association (ACAA) “2012 Coal 

Combustion Product (CCP) Production & Use Survey Report” at http://www.acaausa.org/Portals/9/Files/PDFs/revisedFINAL2012CCPSurveyReport.pdf

** NAICS codes assigned by EPA for purpose of this RIA.

Although EPA proposed to restrict large-scale CCR structural fill operations (e.g., large structural 

fill uses in construction and landscaping projects) in the 2010 CCR proposed rule, the CCR final 

rule does not contain such regulatory restrictions, but instead reinforces the use of existing 

engineering design and environmental protection best practices in CCR fill operations. This RIA 

does not estimate impacts on CCR structural fill.
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2.3 Affected Electric Utility Plants

Note: EPA has updated the universe to reflect 61 actual and projected plant retirements

occurring after 2012 according to the National Electric Energy Data System (NEEDS) v.5.13 

dataset; see Section 9.2.1 in Chapter 9 for a description of the relevant updates. Exhibits in 

this chapter have not been updated to reflect the revisions described in Section 9.2.1.

This section provides an overview of the electric utility plants affected by the CCR rule.

2.3.1 Sources for Identifying Coal-Fired Electric Utility Plants

Based on data from the 2012 DOE EIA-923 database, EPA identified 478 coal-fired electric 

utility plants as potentially affected by the CCR rule.68 To identify facilities potentially affected 

by the CCR rule, EPA applied three filters to the DOE EIA-923 database.

1. NAICS 22. EPA sorted the DOE EIA-923 database by NAICS industrial codes, 

and included only plants assigned to utility sector NAICS code 22.69

2. Coal used as a primary or secondary energy source. EPA includes only plants 

using coal as either a primary or secondary energy source. This includes utility 

sector plants in the DOE EIA-923 database using any of the following types of 

coal:

 Anthracite Coal, Bituminous Coal (BIT);

 Lignite Coal (LIG);

 Sub-bituminous Coal (SUB);

 Waste/Other Coal (Anthracite Culm, Bituminous Gob, Fine Coal, Lignite 

Waste, Waste Coal) (WC); and

 Coal Synfuel (SC), coal-based solid fuel that has been processed by a coal 

synfuel plant, and coal-based fuels such as briquettes, pellets, or 

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

materials.70

 

68 RTI International, EPA’s risk assessment contractor for the CCR rule, initially identified the list of 507 coal-fired electric 

utility plants used in this RIA; this RIA updated the universe to 478 plants to reflect newer EIA data.

69 The U.S. Bureau of Census defines NAICS 22 as follows:

“The Utilities sector comprises establishments engaged in the provision of the following utility services: electric power, 

natural gas, steam supply, water supply, and sewage removal. Within this sector, the specific activities associated with 

the utility services provided vary by utility: electric power includes generation, transmission, and distribution; natural 

gas includes distribution; steam supply includes provision and/or distribution; water supply includes treatment and 

distribution; and sewage removal includes collection, treatment, and disposal of waste through sewer systems and 

sewage treatment facilities.” (Source: http://www.census.gov/eos/www/naics/. Note that only two-digit NAICS codes 

are provided within the DOE EIA-923 database).

70 In addition to these five categories of coal, examples of other primary or secondary energy sources reported by coal burning 

electric utility plants are agriculture byproducts, distillate fuel oil, natural gas, petroleum coke, propane, and wood and waste 

solids.
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3. Removal of other non-qualifying power plants. The total number of NAICS 22 

power plants listing coal as a primary or secondary fuel is 550 plants. EPA 

conducted additional Internet research and removed 72 plants from the universe 

that were identified as one or more of the following:, resulting in 478 plants (i.e., 

550 – 72 = 478 plants):

 Inactive, out-of-service, or closed utility plants;

 Duplicate records with other utility plants on the list;

 Coal transfer/storage facility;

 Converted to natural gas or other non-coal fuel types;

 A user of a non-coal fuel type, contrary to energy source reported in the 

DOE EIA-923 database; and

 Not in NAICS 22.71

The total plant population of 478 coal-fired electric utility plants potentially affected by the CCR 

rule has a combined electricity generation nameplate capacity provided by 1,309 boilers (aka 

electricity generator units or EGUs) of 375,638 megawatts (MW), or roughly 30% of the 1.2 

million MW total 2012 U.S. electricity generation. Individual plants range in capacity size from 

6 MW to 4,008 MW, with an average size of 786 MW and a median size of 539 MW in 2012.72

The average count of boilers (EGUs) is 2.74 per plant (i.e., 1,309 boilers / 478 plants). Appendix 

A presents the list of 478 plants.

2.3.2 Coal-Fired Electric Utility Plants by Size and Ownership Type

To identify the types and business size classifications of the owner entities associated with these 

plants, this RIA initially used the utility code reported in the 2012 DOE EIA-860 database to 

identify plants owned by the same company.73 EPA then conducted Internet and company 

database research on plant and company name to verify company owner classifications. This 

research sometimes revealed corporate ownership structures and relationships. As summarized in 

 

71 Additional research conducted by EPA identified that in other contexts (e.g., other public databases) the facilities reported 

NAICS codes other than 22, or did not meet the definition of NAICS 22.

72 See the DOE EIA website at http://www.eia.gov/cneaf/electricity/epa/epa_sprdshts.html.

73 EIA maintains a set of overlapping databases that are updated on different schedules, two of which are EIA-923 and EIA-860

databases. While the DOE EIA-923 database is the primary data source for annual CCR disposition (i.e., type of CCR disposal 

and beneficial use) for electricity plants with generation capacity greater than 100 MW, this RIA used EIA-860 to supplement the 

analysis where the data describing facilityelectricity plant operations were incomplete or unavailable in the EIA-923 database.

Limitation: According to its Section 257.50(e), the scope of the CCR final rule does not apply to 

CCR generated at electric utility plants unless coal as a fuel comprises more than 50% of the fuel 

burned. However, at the CCR rule doesdate of this analysis EPA had not indicatedetermined

whether this 50% threshold should be calculated relative to individual coal-fired boilers or relative 

to an average across all coal-fired and other fuel type boilers at each individual electric utility 

plant. ThisConsequently, this RIA did not apply this threshold as a filter to the EIA data.
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Exhibit 2-C and Exhibit 2-D below, the 478 coal-fired electric utility plants are owned and 

operated by 244 entities; Appendix C provides ownership information. In Exhibits 2-C and 2-

D, EPA categorized entities as small and non-small according to numerical threshold criteria 

consistent with EPA’s November 2006 guidance for Regulatory Flexibility Act (RFA) Small 

Business Regulatory Enforcement Fairness Act (SBREFA) compliance:

 Small non-government entity. Determined based on the U.S. Small Business 

Administration (SBA) NAICS code 22112 small business size standard of fewer 

than 750 employees across all plants owned by the entity.74 Total company-wide 

generation exceeding four million megawatt hours is not considered small.

 Small government entity. Size class determined based on the RFA’s definition 

of “small government jurisdiction” as the government of a city, county, town, 

township, village, school district, or special district with a population of less than 

50,000.75 Jurisdictions exceeding 50,000 in population are not considered small.

Note: The exhibits and text in this section do not reflect the revisions described in Section 

9.2.1 removing 61 additional plants from the universe of plants affected by the CCR final rule.

 

74 On December 23, 2013 the Small Business Administration (SBA) published a final rule in the Federal Register (Vol. 78, No. 

246, pages 77343 to 77351) which changed the basis for measuring business size from megawatt hours to number of employees 

for 10 of the 13 industries classified under the NAICS code 22 utility sector (i.e., electric power generation, transmission, and 

distribution industries). SBA’s business size standards by industry NAICS code are available at 

http://www.sba.gov/content/table-small-business-size-standards. 

75 5 U.S. Code Section 601(5).

Exhibit 2-C

Summary Classification of Coal-Fired Electric Utility Plants by Type/Size of Owner Entities (2012)

Type of Owner Entitya

Entity Size 

Classb

Coal-Fired Electric 

Utility Plant Count

Owner Entity 

Count

1. Federal government Non-small 11 (2%) 1 (<1%)

2. State government jurisdictions (authorities, districts)

(AZ, CO, NE, OK, SC, TX) Non-small 12 (3%) 7 (3%)

3. Medium and large population municipal government 

jurisdictions Non-small 25 (5%) 18 (7%)

4. Medium and large companies Non-small 325 (68%) 133 (55%)

5. Medium and large cooperatives (this RIA assumes all 

privately-owned) Non-small 6 (1%) 2 (<1%)

6. Small county government jurisdictions (commission) Small 1 (<1%) 1 (<1%)

7. Small municipal government jurisdictions (agencies, 

commissions) Small 32 (7%) 32 (13%)

8. Small companies Small 46 (10%) 33 (14%)

9. Small cooperatives (this RIA assumes all privatelyowned) Small 20 (4%) 15 (6%)

Summary

Totals 478 242

Private sector sub-total [4+5+8+9] 397 (83%) 183 (76%)

State/local government sub-total [2+3+6+7] 70 (15%) 58 (24%)

Small entity sub-total [6+7+8+9] 99 (21%) 81 (33%)

a Type of owner entity estimated and assigned based on owner name or internet research on type of ownership.
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Exhibit 2-D

State-by-State Count of Coal-Fired Electric Utility Plants by Type/Size of Owner Entity

State

Plants Owned by Non-Small 

Entities Plants Owned by Small Entities

FederalGovernmentStateGovernmentNon

Total Plants

-small

MunicipalNon-smallCompanyNon-smallCooperativeCountyGovernmentSmallMunicipalSmallCompanySmallCooperativeTotal Owned by Small Entities

1 AK 2 2 2

2 AL 2 7 1 1 10

3 AR 3 2 2 5

4 AZ 2 3 1 1 6

5 CA 5 3 3 8

6 CO 1 2 10 1 1 14

7 CT 1 1

8 DC 0

9 DE 2 2

10 FL 5 7 1 1 2 14

11 GA 9 1 1 2 11

12 HI 2 2

13 IA 1 12 3 1 4 17

14 ID 0

15 IL 1 18 1 2 3 22

16 IN 19 5 2 7 26

17 KS 2 4 2 2 8

18 KY 2 1 9 5 3 8 20

19 LA 4 4

20 MA 3 3

21 MD 8 8

22 ME 1 1

23 MI 2 13 5 2 7 22

24 MN 1 9 4 4 14

25 MO 5 9 2 1 3 6 20

26 MS 3 1 1 2 5

27 MT 3 2 2 5

28 NC 15 4 4 19

29 ND 2 4 1 1 7

30 NE 4 3 3 7

31 NH 2 2

32 NJ 1 2 3 3 6

33 NM 3 1 1 4

34 NV 3 3

35 NY 6 1 2 3 9

36 OH 1 19 4 1 5 25

37 OK 1 4 1 1 6

38 OR 1 1

39 PA 22 9 9 31

40 PR 1 1

41 RI 0

b Size class determined according to the following numerical threshold criteria consistent with EPA’s Nov 2006 guidance for 

Regulatory Flexibility Act (RFA) Small Business Regulatory Enforcement Fairness Act (SBREFA) compliance (see text).
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Exhibit 2-D

State-by-State Count of Coal-Fired Electric Utility Plants by Type/Size of Owner Entity

State

Plants Owned by Non-Small 

Entities Plants Owned by Small Entities

FederalGovernmentStateGovernmentNon

Total Plants

-small

MunicipalNon-smallCompanyNon-smallCooperativeCountyGovernmentSmallMunicipalSmallCompanySmallCooperativeTotal Owned by Small Entities

42 SC 3 9 12

43 SD 2 2

44 TN 7 7

45 TX 1 2 14 1 1 2 19

46 UT 1 4 1 1 6

47 VA 14 2 2 16

48 VT 0

49 WA 1 1

50 WI 11 1 1 3 5 16

51 WV 17 17

52 WY 9 2 11

Column totals 

=

11 12 25 325 6 1 32 46 20 99 478

2.3.3 Coal-Fired Electric Utility Plants by Coal Fuel Type and State 

Note: The exhibits and text in this section do not reflect the revisions described in Section 

9.2.1 removing 61 additional plants from the universe of plants affected by the CCR final rule.

The 2012 DOE EIA-923 database indicates that the 478 plants in the universe burn 820 million 

tons of coal on an annual basis. Exhibit 2-E summarizes the type of coal fuel burned across 

plants. Appendix A presents the quantity and types of coal burned for the list of 478 plants.

Exhibit 2-E

Summary Classification of 478 Coal-Fired Electric Utility Plants by Type of Coal Fuel (2012)

Type of Coal Fuel Burned

Count of Coal-Fired 

Electric Utility Plants*

Percentage of All Coal-Fired Electric 

Utility Plants*

1. Anthracite coal (ANT) 1 0.2%

2. Bituminous coal (BIT) 325 64.1%

3. Lignite coal (LIG) 19 3.7%

4. Coal-based synthetic fuel (SC) 8 1.6%

5. Sub-bituminous coal (SUB) 232 45.8%

6. Waste/other coal 23 4.5%

*Because some electric utility plants can burn more than one type of coal fuel in any given year, these columns add to more 

than 478 total plants and to more than 100%, respectively.
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Coal-fired electric utility plants are located in 47 states and Puerto Rico.76 Exhibit 2-F highlights 

the nine states with the largest coal-fired electric utility plant counts, while Exhibit 2-G 

summarizes the count of electric utility plants and their associated CCR generation across the 

nation, which totaled 120.4 million tons per year in 2012.77

Exhibit 2-F

States With Highest Count of NAICS Code 22 Electric Utility Plants 

and Associated CCR Generation (2012)

State Plants

Percent of 

Plants

Annual CCR 

Generation

Percent of CCR 

Generation

PA 31 6.49% 12,711,355 10.56%

IN 26 5.44% 7,500,320 6.23%

OH 25 5.23% 8,813,980 7.32%

IL 22 4.60% 3,166,395 2.63%

MI 22 4.60% 1,804,587 1.50%

KY 20 4.18% 10,304,006 8.56%

MO 20 4.18% 2,778,246 2.31%

NC 19 3.97% 4,709,276 3.91%

TX 19 3.97% 12,197,600 10.13%

 

76 Idaho, Rhode Island, Vermont, and the District of Columbia do not have any electric utility plants.

77 This RIA’s CCR generation estimate of 120.4 million tons is 11% lower than the 134.7 million tons (2009) annual CCR 

generation estimate published by the ACAA. This discrepancy is due to different data sources used by EPA and ACAA (EIA and 

ACAA’s annual utility survey, respectively) and different universes considered by EPA and ACAA in extrapolating data from 

EIA and the ACAA survey. The ACAA’s annual CCR tonnage data is available from the “Production & Use Reports” webpage 

is within the ACAA’s website at http://acaa.affiniscape.com/ 

associations/8003/files/2009_CCP_Production_Use_Survey_Corrected_020811.pdf.http://www.acaausa.org/Publications/Production-Use-Reports
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0

2

4

6

8

10

12

14

0

5

10

15

20

25

30

35

PA

IN

OH

IL

MI

KY

MO

NC

TX

IA

WV

VA

WI

CO

FL

MN

SC

GA

WY

AL

NY

CA

KS

MD

ND

NETNAZ

NJ

OK

UT

AR

MS

MT

LA

NMMA

NVAK

DE

HI

NH

SDCT

ME

OR

PR

WA

Count of Coal

Annual CCR Generation (millions of tons)

-Fired Electric Utility Plants

Exhibit 2-G

State-by-State Count of NAICS Code 22 Coal-Fired Electric Utility Plants and 

Associated Annual CCR Generation (2012)

# of Plants

Annual CCR Generation

0

2

4

6

8

10

12

14

0

5

10

15

20

25

30

35

PA

IN

OH

IL

MI

KY

MO

NC

TX

IA

WV

VA

WI

CO

FL

MN

SC

GA

WY

AL

NY

CA

KS

MD

ND

NETNAZ

NJ

OK

UT

AR

MS

MT

LA

NMMA

NVAK

DE

HI

NH

SDCT

ME

OR

PR

WA

Count of Coal

Annual CCR Generation (millions of tons)

-Fired Electric Utility Plants

Exhibit 2-G

State-by-State Count of NAICS Code 22 Coal-Fired Electric Utility Plants and 

Associated Annual CCR Generation (2012)

# of Plants

Annual CCR Generation
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Exhibit 2-H below presents state-by-state counts of the 478 coal-fired electric utility plants and 

their associated annual CCR generation tonnages for 2012. Noteworthy is that four states (DC, 

ID, RI, VT) do not have operating coal-fired electric utility plants (although they may have nonutility coal-fired plants not affected by the CCR rule), and the state list includes the non-states of 

DC and the U.S. territory of Puerto Rico (PR).

To identify baseline CCR generation for active CCR management units operated by plants with 

generation capacity greater than 100 MW (i.e., medium- and large-size plants), this RIA uses 

data from Schedule 8, Part A of the Form DOE EIA-923 (Power Plant Operations Report) 

database.78 This database is also the primary data source for annual CCR disposition (i.e., type of 

disposal and beneficial use) for plants with generation capacity greater than 100 MW.79 The 372 

electric utility plants with generation capacity greater than 100 MW reporting CCR management

information in the 2012 DOE EIA-923 database generate 114.8 million tons of CCR annually. 

For data reporting purposes, the DOE EIA-923 (Schedule 8) database defines the following eight 

CCR management categories and eight CCR generation categories:

 CCR Generation Categories (DOE EIA-923):

o Bottom (bed) ash from fluidized bed combustion (FBC) units

o Bottom ash from standard boiler units (includes boiler slag from slagging 

combustors)

o FGD gypsum (defined as byproducts that are greater than 75% CaSO4-

2H20 by weight)

o Fly ash from FBC units

o Fly ash from standard boiler/pollution control device (PCD) units 

(includes those with no FGD system or with FGD systems located 

downstream of the PCD)

o Fly ash from units with dry FGD

o Other FGD byproducts (includes all FGD byproducts not reported in 

above categories along with additives used to stabilize the FGD 

byproducts)

o Other

 

78 The EIA-923 database includes annual data from organic-fueled or combustible renewable steam-electric plants with a 

generator nameplate rating of 10 or more megawatts (MW) regardless of current ownership and/or operation. However, it 

contains annual tonnage CCR generation, CCR disposal, and CCR beneficial use data only for plants over 100MW in size. 

http://www.eia.gov/cneaf/electricity/page/eia906_920.html.

79 Plants with generation capacity less than 100 MW are not required to report CCR tonnage and disposition data to the EIA-923 

database.
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Exhibit 2-H

State-by-State Count of 478 Coal-Fired Electric Utility Plants and CCR Generation (2012)

All Plant Sizes (<100MW small plants + >100MW medium and large plants)

State Count of Plants % of Plants CCR Generated (tons) % of CCR Generation

1 AK 2 0.42% 46,461 0.04%

2 AL 10 2.09% 2,716,574 2.26%

3 AR 5 1.05% 978,377 0.81%

4 AZ 6 1.26% 3,308,300 2.75%

5 CA 8 1.67% 102,578 0.09%

6 CO 14 2.93% 1,626,538 1.35%

7 CT 1 0.21% 700 0.00%

8 DC 0 0.00% 0 0%

9 DE 2 0.42% 210,158 0.17%

10 FL 14 2.93% 4,446,054 3.69%

11 GA 11 2.30% 2,350,252 1.95%

12 HI 2 0.42% 127,064 0.11%

13 IA 17 3.56% 1,932,687 1.60%

14 ID 0 0.00% 0 0%

15 IL 22 4.60% 3,166,395 2.63%

16 IN 26 5.44% 7,500,320 6.23%

17 KS 8 1.67% 1,204,076 1.00%

18 KY 20 4.18% 10,304,006 8.56%

19 LA 4 0.84% 2,492,400 2.07%

20 MA 3 0.63% 108,800 0.09%

21 MD 8 1.67% 1,681,700 1.40%

22 ME 1 0.21% 6,800 0.01%

23 MI 22 4.60% 1,804,587 1.50%

24 MN 14 2.93% 894,001 0.74%

25 MO 20 4.18% 2,778,246 2.31%

26 MS 5 1.05% 846,483 0.70%

27 MT 5 1.05% 981,666 0.82%

28 NC 19 3.97% 4,709,276 3.91%

29 ND 7 1.46% 3,057,400 2.54%

30 NE 7 1.46% 859,004 0.71%

31 NH 2 0.42% 60,000 0.05%

32 NJ 6 1.26% 217,192 0.18%

33 NM 4 0.84% 3,778,858 3.14%

34 NV 3 0.63% 212,100 0.18%

35 NY 9 1.88% 423,339 0.35%

36 OH 25 5.23% 8,813,980 7.32%

37 OK 6 1.26% 1,203,700 1.00%

38 OR 1 0.21% 75,700 0.06%

39 PA 31 6.49% 12,711,355 10.56%

40 PR 1 0.21% 105,435 0.09%

41 RI 0 0.00% 0 0%

42 SC 12 2.51% 2,191,994 1.82%

43 SD 2 0.42% 109,407 0.09%

44 TN 7 1.46% 2,210,900 1.84%

45 TX 19 3.97% 12,197,600 10.13%

46 UT 6 1.26% 2,087,188 1.73%

47 VA 16 3.35% 1,815,709 1.51%

48 VT 0 0.00% 0 0%

49 WA 1 0.21% 414,200 0.34%

50 WI 16 3.35% 1,347,876 1.12%

51 WV 17 3.56% 8,220,749 6.83%

52 WY 11 2.30% 1,979,046 1.64%

Column totals = 478 100% 120.4 million 100%
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 CCR Management Categories (DOE EIA-923):

o On-site landfill

o On-site pond (i.e., surface impoundment)

o Off-site disposal (assumed to be an off-site commercial landfill)80

o Sold for beneficial use

o Used on-site for beneficial use

o Used off-site for beneficial use

o Stored on-site (assumed to be stored for later sale or beneficial use)

o Stored off-site (assumed to store for later sale or beneficial use)

For active CCR management units operated by plants with generation capacity less than 100 

MW (i.e., small plants), this RIA also uses the DOE EIA-923 database. However, these plants 

are not required to report their CCR tonnage and disposition data.81 Instead, this RIA bases 

estimates for annual CCR generation for these plants on reported coal usage quantities and ash 

content percentages reported in the DOE EIA-923 database.82 This RIA estimates that the 106 

electric utility plants with generation capacity less than 100 MW generated a total of 5.7 million 

tons of CCR in 2012.

This section describes the baseline disposal practices at the 478 coal-fired electric utility plants in 

the universe of affected facilities. All coal-fired electric utility plants must use or dispose of CCR 

in some way, whether by disposing in on-site or off-site units, or repurposing it for beneficial use 

(in some cases also identified as recycling).

The final CCR rule addresses active CCR management units, including landfills and 

impoundments, as well as inactive CCR impoundments.83 Due to different data sources and data 

availability, estimates for plants with generation capacity greater than 100 MW (i.e., mediumand large-size plants) and estimates for plants with generation capacity less than 100 MW (i.e., 

small plants) are calculated separately and then added together.84

 

80 This RIA assumes that off-site disposal means off-site commercial landfill. See Appendix D for further details.

81 The EIA-923 database includes annual data from organic-fueled or combustible renewable steam-electric plants with a 

generator nameplate rating of 10 or more megawatts (MW) regardless of current ownership and/or operation. However, it 

contains annual tonnage CCR generation, CCR disposal, and CCR beneficial use data only for plants over 100MW in size. 

http://www.eia.gov/cneaf/electricity/page/eia906_920.html

82 To estimate total CCR tonnages for 106 plants with less than 100 MW in generation capacity, this RIA uses coal use and 

percent coal ash content data from the 2012 EIA-923 database and nameplate capacity rating data from the 2012 EIA-860, or 

else 2009 EIA-860 if 2012 EIA-860 data were not available (this is the case for seven plants). This RIA does not estimate FGD 

gypsum or other FGD byproduct generation quantities for these plants.

83 For additional information on the universe of active and inactive CCR management units addressed by this RIA, see Chapter 

2.

84 For a complete description of the EIA databases used for disposition quantities, see Appendix E.
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2.3.4 CCR Management Practices by Power Plant Count

Note: The exhibits and text in this section do not reflect the revisions described in Section 

9.2.1 removing 61 additional plants from the universe of plants affected by the CCR final rule.

The 2012 DOE EIA databases contain annual CCR management practice data for the 478 coalfired electric utility plants potentially affected by the final CCR rule, including use of on-site 

landfills, off-site landfills, on-site impoundments, and transfer of materials for CCR beneficial 

useuses.

85 Exhibit 2-I presents the number of plants using each disposal practice; some facilities 

use more than one practice.

Of the 478 coal-fired electric utility plants, this RIA estimates that 432 plants (90%) disposed 

CCR, consisting of 201 plants (42%) disposing in on-site landfills, 169 (35%) disposing in onsite ponds, and 197 (41%) disposing in off-site landfills (some plants used more than one 

disposal method). A total of 293 plants (61%) direct CCR to beneficial uses, including 19 plants 

that solely managed their CCR for beneficial use (in this RIA, beneficial use is based on the 

DOE EIA-923 data categories for “sale,” “on-site use,” “off-site use,” “on-site storage,” and 

“off-site storage” of CCR).

 

85 Data on CCR supplied for beneficial use are available only from the 2012 DOE EIA-923 database, which contains annual CCR 

management practice data only for the 372 plants with annual electrical generation capacity greater than 100 MW. Data on CCR 

supplied for beneficial use are not available for the remaining 106 plants, and are not included in the counts above. This likely 

understates beneficial use. For these 106 plants, this RIA estimates CCR management practices by analyzing various data sources 

to identify CCR landfill and surface impoundments:

 Impoundment data from ORCR’s 2009-2012 CCR impoundment site inspections 

(http://www.epa.gov/waste/nonhaz/industrial/special/fossil/surveys2/index.htm);

 Impoundment data from ORCR's 2009 mail survey to plants with CCR impoundments 

(http://www.epa.gov/waste/nonhaz/industrial/special/fossil/coalashletter.htm);

 Landfill and impoundment data from EPA Office of Water's 2010 mail survey to power plants for the Steam Electric 

Power Generating Effluent Limit Guidelines (http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm#point6); 

and

 The 2012 DOE EIA-923 data reporting on-site CCR landfill or on-site CCR impoundment disposal that was not 

included in the above sources.

This analysis was initially conducted by RTI International and reflects a method using Internet satellite photos to help determine 

the presence and number of units at many of the coal-fired electric utility plants in 2010, and updated for this RIA to reflect the 

universe of affected coal-fired electric utility plants as per the DOE EIA-923 database. For these 106 plants, if the analysis 

identified either on-site landfills or on-site surface impoundments at these plants, this RIA assumes that these plants dispose of 

their CCR in the on-site units. Otherwise, this RIA assumes that these plants use off-site disposal in commercial landfills.
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Exhibit 2-I

2012 Count of Coal-Fired Electric Utility Plants by CCR Disposition Method

CCR Generation 

Category

Disposal Beneficial Useb

Total 

Plantsc

On-site 

Landfill

Onsite 

Ponds

Off-site 

Disposal 

(Landfill) Sold

Used

On-site

Used 

Off-site

Stored 

Onsite

Stored 

Offsite

Bottom (bed) ash from 

FBC units 14 5 11 14 4 11 4 3 31

Bottom ash from 

standard boiler units 116 113 69 144 58 66 77 29 334

Bottom ash (plants < 

100 MW only) a 12 26 74 - - - - - 106

Fly ash from FBC units 12 3 7 12 2 9 3 1 22

Fly ash from standard 

boiler/PCD units 151 96 86 180 35 79 52 23 320

Fly ash from units with 

dry FGD 20 9 17 18 9 13 8 6 41

Fly ash (plants < 100 

MW only) a 12 26 74 - - - - - 106

FGD gypsum 46 22 20 61 9 17 20 4 113

Other FGD byproducts 38 9 22 9 8 8 5 5 62

Other 6 3 2 4 0 0 1 0 15

Total plants (unique)c 201 169 197 251 69 120 104 35 478

Percentages = 42.1% 35.4% 41.2% 52.5% 14.4% 25.1% 21.8% 7.3% 100%

Disposal vs. Beneficial 

Use Subtotals (unique) 432 plants (90%) 293 plants (61%)

Notes:

a These rows represent small plant counts only (generation capacity <100 MW). Small plant counts in these categories 

indicate a potentially active on-site unit at a small plant that reported burning coal-based fuel.

b The five columns labeled “Sold” and “Used” and “Stored” are all counted in this RIA as CCR beneficial use.

c Because a single plant may utilize multiple disposition methods for the same type of CCR, or may dispose of multiple types 

of CCR in the same disposition method, total values are not the sum of row or column entries, but instead represent the nonduplicative count of unique plants.

Exhibit 2-J below presents CCR management practices tonnages. Of the 120.4 million tons 

CCR generated in 2012, electric utility plants disposed 71.2 million tons (59% of generation), 

consisting of 41.7 million tons disposed in on-site landfills, 14.7 million tons disposed in on-site 

impoundments (ponds), and 14.8 million tons disposed in off-site landfills. The remaining 49.2 

million tons (41% of generation) are destined for beneficial uses.86

Exhibit 2-K below presents CCR management tonnages on a state-by-state basis.

 

86 This RIA assumes that the EIA-923 data categories of CCR sold, used on-site, used off-site, stored on-site, and stored off-site 

are destined for beneficial use. This assumption is supported by DOE’s August 2006 report “Coal Combustion Waste 

Management at Landfills and Surface Impoundments 1994-2004” which interpreted the entire "on-site use and storage" quantity 

as beneficial use, and by the ACAA’s estimate that 55.6 million tons of coal ash were beneficially used in 2009. See 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.
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Exhibit 2-J

Annual CCR Disposition Quantity for NAICS 22 Electric Utility Plants

(thousands of short tons unless noted otherwise)

CCR Category

Disposal Beneficial Use

Total 

Quantity

Ash 

Type 

SubtotalsOn-site 

Landfill

On-site 

Impoundments 

(Ponds)

Off-site 

Disposal

(Landfill) Sold

Used 

On-site

Used 

Off-site

Stored 

On-site

Stored 

Off-site

1. Bottom (bed) ash from FBC units 895.7 158.7 197.1 278.1 0.9 1,228.1 34.6 0.0 2,793.2 20,974.7

(17.4%) 2. Bottom ash from standard boiler units 5,408.4 2,981.1 1,577.5 3,685.3 1,389.5 565.1 1,150.1 1.4 16,758.4

3. Bottom Ash* (plants < 100 MW only) 181.7 160.9 1,080.4 - - - - - 1,423.1

4. Fly ash from FBC units 2,286.7 18.4 360.2 353.2 0.0 1,877.9 63.1 0.0 4,959.5

61,637.2

(51.2%)

5. Fly ash from standard boiler/PCD units 15,893.7 5,793.8 4,199.2 14,599.4 2,854.6 2,152.2 2,023.3 53.2 47,569.4

6. Fly ash from units with dry FGD 1,821.6 669.3 1,078.1 335.8 473.8 408.5 80.3 0.0 4,867.4

7. Fly Ash* (plants < 100 MW only) 541.6 479.6 3,219.7 - - - - - 4,240.9

8. FGD Gypsum 7,397.1 3,766.2 2,587.3 9,149.1 1,073.3 2,717.3 1,012.7 0.0 27,703.0 37,344.5

9. Other FGD byproducts 7,063.1 435.5 513.7 523.2 886.8 117.3 101.2 0.7 9,641.5 (31.0%)

10. Other 164.1 274.7 2.6 19.9 0.0 0.0 2.3 0.0 463.6

Totals (millions short tons) 41.7 14.7 14.8 28.9 6.7 9.1 4.5 0.1 120.4

Percentages = 34.6% 12.2% 12.3% 24.0% 5.5% 7.5% 3.7% 0.0% 100%

Disposal and beneficial use sub-totals 71.2 million (59%) 48.1 million (39%)

*These categories represent CCR disposition quantities for plants with generation capacity less than 100 MW. Tonnages for these categories are disposed at potentially active on-site units at plants 

reporting burning coal-based fuel. These tonnages are calculated from coal burned or nameplate capacity and percent ash content of coal (see Exhibit 2-K). See Appendix A for specific sources 

for individual plants.
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Exhibit 2-K

State-by-State Summary of CCR Management Tonnages

<100MW Small Plants (disposal only) and >100MW Medium + Large Size Plants (disposal + beneficial use); 1,000 Tons in 2012)

State

A B C D E F G H I (A+...H) J (A+C) K (B+J) L

Disposal Beneficial Use

2012 EIA 

total CCR 

managed

Subtotal 

landfill 

(onsite+ 

offsite)

Subtotal disposal

Landfills 

(onsite)

Ponds 

(this RIA 

assumes 

onsite)

Offsite

(RIA 

assumes 

landfill) Sold

Used

Onsite

Used

Offsite

Stored

Onsite

Stored

Offsite Tons %

1 AK 0 27 19 0 0 0 0 0 46 19 46 0.1%

2 AL 635 1,420 2 614 0 34 12 0 2,717 637 2,057 2.9%

3 AR 609 31 4 301 33 0 0 0 978 612 644 0.9%

4 AZ 2,061 373 3 870 0 2 0 0 3,308 2,064 2,437 3.4%

5 CA 48 0 36 0 0 18 0 0 103 84 84 0.1%

6 CO 709 27 325 284 0 274 7 0 1,627 1,034 1,061 1.5%

7 CT 0 0 0 0 0 1 0 0 1 0 0 0.0%

8 DC 0 0 0 0 0 0 0 0 0 0 0 0.0%

9 DE 208 2 0 0 0 0 0 0 210 208 210 0.3%

10 FL 815 0 603 2,680 1 257 91 0 4,446 1,418 1,418 2.0%

11 GA 84 1,204 123 924 0 0 15 0 2,350 207 1,411 2.0%

12 HI 0 0 4 7 0 116 0 0 127 4 4 0.0%

13 IA 599 57 35 485 0 15 743 0 1,933 634 690 1.0%

14 ID 0 0 0 0 0 0 0 0 0 0 0 0.0%

15 IL 222 412 1,229 972 0 39 292 1 3,166 1,451 1,863 2.6%

16 IN 2,072 878 601 1,597 1,531 805 18 0 7,500 2,672 3,550 5.0%

17 KS 637 11 17 460 0 56 22 0 1,204 654 666 0.9%

18 KY 4,991 2,842 64 981 18 703 706 0 10,304 5,055 7,897 11.1%

19 LA 1,597 132 0 676 0 0 87 0 2,492 1,597 1,729 2.4%

20 MA 0 0 21 84 0 3 1 0 109 21 21 0.0%

21 MD 7 0 564 1,062 0 0 50 0 1,682 570 570 0.8%

22 ME 5 0 0 0 0 2 0 0 7 5 5 0.0%

23 MI 191 716 113 744 0 0 37 3 1,805 305 1,020 1.4%

24 MN 32 570 130 78 72 12 0 0 894 162 732 1.0%

25 MO 527 55 27 919 0 384 865 0 2,778 554 609 0.9%

26 MS 103 15 11 113 0 566 40 0 846 114 129 0.2%

27 MT 36 861 43 17 1 0 24 0 982 79 940 1.3%

28 NC 814 364 319 2,074 419 37 681 1 4,709 1,133 1,498 2.1%

29 ND 638 303 744 709 417 145 103 0 3,057 1,382 1,685 2.4%

30 NE 464 48 0 305 5 38 1 0 862 464 512 0.7%

31 NH 1 0 27 24 0 1 8 0 60 28 28 0.0%

32 NJ 0 0 146 7 0 56 8 0 217 146 146 0.2%

33 NM 978 403 1,544 416 372 0 66 0 3,779 2,522 2,925 4.1%

34 NV 162 0 0 36 0 14 0 0 212 162 162 0.2%

35 NY 275 17 55 51 0 16 9 0 423 330 347 0.5%

36 OH 2,195 1,695 1,638 1,137 1,651 494 5 0 8,814 3,832 5,527 7.8%

37 OK 73 47 97 754 8 214 11 0 1,204 170 216 0.3%

38 OR 38 0 0 38 0 0 0 0 76 38 38 0.1%

39 PA 3,494 0 3,248 1,557 1,245 3,137 31 0 12,711 6,742 6,742 9.5%

40 PR 0 0 105 0 0 0 0 0 105 105 105 0.1%

41 RI 0 0 0 0 0 0 0 0 0 0 0 0.0%

42 SC 440 270 105 1,376 0 0 0 0 2,192 546 816 1.1%

43 SD 66 4 0 22 0 17 0 0 109 66 70 0.1%

44 TN 763 418 87 838 0 105 0 0 2,211 850 1,268 1.8%

45 TX 5,786 528 1,468 3,770 466 0 179 0 12,198 7,254 7,783 10.9%

46 UT 1,860 87 0 140 0 0 0 0 2,087 1,860 1,947 2.7%

47 VA 1,006 143 196 186 239 4 41 0 1,816 1,202 1,345 1.9%

48 VT 0 0 0 0 0 0 0 0 0 0 0 0.0%

49 WA 0 0 0 216 0 0 149 49 414 0 0 0.0%

50 WI 112 39 70 298 74 586 167 2 1,348 182 221 0.3%

51 WV 5,122 674 820 609 77 918 0 0 8,221 5,942 6,617 9.3%

52 WY 1,178 65 172 514 51 0 0 0 1,979 1,350 1,415 2.0%

Totals = 41,654 14,738 14,816 28,944 6,679 9,066 4,468 55 120,420 56,470 71,208 100%
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2.3.5 Counts of On-Site CCR Management Units

Note: The exhibits and text in this section do not reflect the revisions described in Section 

9.2.1 removing 61 additional plants from the universe of plants affected by the CCR final rule.

As described in more detail in Section 3.1.1, EPA conducted research to identify the number of 

CCR landfills and CCR surface impoundments located at each of the 478 coal-fired electric 

utility plants. The names for some on-site units contain descriptors that this RIA assumes 

indicate surface impoundments, such as “pond,” “impoundment,” “dam,” “dike” and “basin.”87

In addition, unit names indicate a variety of uses, including:

 Primary, secondary, auxiliary, emergency, or overflow;

 Skimmer, settling, sedimentation, clarification, or polishing;

 Evaporation, decant, or dewatering;

 Ash, fly ash, bottom ash, slag, gypsum, FGD, wastewater, storm water, runoff, or 

leachate;

 Treatment, disposal, holding, storage, retention, recycle, or recovery; and

 Equalization, stilling, or surge.

This RIA distinguishes identified impoundments (ponds) between disposal impoundments where 

CCR is left in place in perpetuity and storage impoundments, which are periodically dredged and 

have their CCR quantities disposed elsewhere. To identify an impoundment as a CCR disposal 

impoundment or a CCR storage impoundment, this RIA used the following algorithm:

 If EIA reporteddata indicated active wet CCR disposal in one or more 

impoundments for a utility plant:

o The largest impoundment (in terms of capacity) at the plant is considered a 

CCR disposal impoundment;88

o All other impoundments at that plant are considered CCR storage 

impoundments.

 If EIA data did not reportindicate any active wet CCR disposal in impoundments 

for a plant:

o All impoundments at the plant are considered CCR storage 

impoundments.

 

87 The full list of common descriptors includes pond, impoundment, dam, dike, basin, reservoir, pit, channel, cell, and sump.

88 As a conservatism, this RIA makes this assumption to ensure that estimated CCR rule compliance costs at other impoundments 

are not understated.
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Using this algorithm, this RIA identifies 142 CCR disposal impoundments and 593 CCR storage 

impoundments, for a total of 735 active, on-site CCR impoundments.

The exhibits below summarize counts of on-site CCR management units associated with the 

plants identified in the 2012 DOE EIA-923 database. In addition, across the set of identified 

impoundments, EPA identified impoundments managing de minimis CCR quantities that were 

removed from the analysis, and used the Office of Water’s 2010 mail survey to power plants for 

the “Steam Electric Power Generating Effluent Limitations Guidelines” June 2013 proposed rule 

to identify and reclassify several inactive impoundments. Adjustments to the initial counts of 

impoundments to arrive at the final count of 735 active and 111 inactive on-site impoundments 

were as follows:

 Initial count: 831 active on-site impoundments and 19 inactive impoundments 

across 299 of the 478 coal-fired electric utility plants;

 De minimus impoundments: 55 active on-site impoundments removed by EPA;

 Inactive impoundments (reclassified): 41 active on-site impoundments 

reclassified as inactive, consistent with Office of Water survey data; and

 Inactive impoundments (new: 51 inactive impoundments added to universe 

consistent with Office of Water survey data.

Exhibit 2-L presents the number of active on-site CCR landfills and active on-site CCR surface 

impoundments identified at the 478 coal-fired electric utility plants affected by the final CCR 

rule, sorted by the different waste streams that they manage. A total of 1,156 on-site CCR 

management units (310 active on-site CCR landfills, 735 active on-site CCR surface 

impoundments, and 111 inactive on-site CCR surface impoundments) exist across these 478

utility plants.89,90

For the 326 plants with generating capacities in excess of 100 MW with on-site CCR landfills 

and/or surface impoundments, Exhibit 2-L provides CCR management unit information by 

specific waste stream (e.g., bottom ash from FBC units, bottom ash from standard boiler units, 

etc.). EPA identified a total of 986 on-site CCR management units (296 active on-site landfills 

and 690 active on-site surface impoundments) across these 326 plants. At these 326 plants, 470 

on-site CCR management units reportedly received zero tons of CCR waste for final disposal 

(these include 86 on-site landfills and 384 on-site surface impoundments) in the 2012 DOE EIA923 database. That is, approximately 45% of active on-site CCR management units reported

receiving zero tons of CCR in 2012 for final disposal. These units are categorized as “unknown” 

in Exhibit 2-L, but could be either receiving de minimis waste quantities (e.g., as stormwater 

 

89 This RIA refers to “on-site” CCR landfills and to “on-site” CCR surface impoundments, although some may be located nearby 

off plant property.

90 The unit counts exceed those in the February-March 2009 ASTSWMO survey of 42 states, which estimates a total of 484 

electric utility plant CCR management units, including 227 landfills in 41 states and 257 impoundments in 33 states. See 

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

Director, EPA Office of Resource Conservation and Recovery: 

http://www.astswmo.org/files/publications/Positionpapers/ASTSWMO-CCB-letter-attachments.pdf.
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runoff), or could be storage impoundments (treatment units that are regularly dredged, with the 

CCR reported as disposed in other units). 

For the remaining plants with generating capacities less than 100 MW, Exhibit 2-L includes 

information by generalized waste stream (e.g., bottom ash, fly ash) only. While the EIA 

identifiesdatabase indicates 106 such plants, EPA identified active on-site CCR management 

units at only 32 of these plants. Across these plants, EPA identified a total of 59 on-site CCR 

management units (14 landfills and 45 surface impoundments). Because waste stream-specific 

data are not available for these plants, this RIA assumes that these plants dispose both bottom 

ash and fly ash in quantities based on each plant’s reported coal use and nameplate capacity.

In total, EPA identified 1,045 active on-site CCR management units (310 landfills and 735 

surface impoundments) at 358 of the 478 coal-fired electric utility plants. The remaining 120 

plants without on-site CCR management units use off-site landfills and/or beneficial use 

practices to manage their CCR.

Exhibit 2-M below presents a state-by-state count of CCR management units.

Exhibit 2-L

Counts of On-Site CCR Management Units for NAICS 22 Electric Utility Plantsa

CCR Generation Category

On-site 

Landfills

On-site 

Impoundments

Total on-site CCR 

Management Units

A. Bottom Ash:

Bottom (bed) ash from FBC units 9 3 12

Bottom ash from standard boiler units 120 276 396

Bottom Ash (plants < 100 MW only)b 14 45 59

B. Fly Ash:

Fly ash from FBC units 8 6 14

Fly ash from standard boiler/PCD units 176 242 418

Fly ash from units with dry FGD 17 14 31

Fly Ash (plants < 100 MW only)b 14 45 59

C. FGD:

FGD Gypsum 55 61 116

Other FGD byproducts 45 22 67

D. Other CCR:

Other 9 4 13

Zero-Waste (unknown) c 86 384 470

Total Active On-Site Units (unique) 310

735

(142 disposal + 

593 storage)

1,045

Total Inactive On-Site Units (unique) 0 111 111

Total On-Site Units (unique) 310 846 1,156

a Counts include small (<100MW) plants as well as medium and large (>100MW) plants.

bThese rows include only CCR management units at small plants (generation capacity <100 MW). All small plants with 

estimated tonnages based on coal use or nameplate ratings are assumed to dispose both bottom ash and fly ash.

cCCR management units identified as having zero CCR disposition quantities in the 2012 DOE EIA-923 database. 

Quantities are reported by these plants for other final dispositions (e.g., off-site landfill, sold, used on-site).
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Exhibit 2-M

State-by-State Count of Active and Inactive CCR Management Units (2012)

Row State

Count of CCR Landfills (LFs) Count of Active CCR Impoundments

Inactive 

SIs

Total Count

Lined Unlined Unknown

Total

LFs Lined Unlined Unknown

Total 

SIs

LFs+

SIs

% of 

U.S.

1 AK 0 0 0 0 0 1 0 1 0 1 0.1%

2 AL 0 1 2 3 1 18 7 26 5 34 2.9%

3 AR 3 0 0 3 0 0 2 2 0 5 0.4%

4 AZ 0 4 0 4 8 3 2 13 1 18 1.6%

5 CA 0 0 1 1 0 0 0 0 0 1 0.1%

6 CO 0 7 2 9 0 4 27 31 2 42 3.6%

7 CT 0 0 0 0 0 0 0 0 0 0 0.0%

8 DC 0 0 0 0 0 0 0 0 0 0 0.0%

9 DE 1 0 0 1 0 0 2 2 0 3 0.3%

10 FL 6 6 0 12 5 7 4 16 1 29 2.5%

11 GA 3 2 1 6 2 20 3 25 8 39 3.4%

12 HI 0 0 0 0 0 0 0 0 0 0 0.0%

13 IA 4 5 2 11 2 18 15 35 0 46 4.0%

14 ID 0 0 0 0 0 0 0 0 0 0 0.0%

15 IL 6 1 2 9 7 14 15 36 10 55 4.8%

16 IN 10 1 6 17 4 47 16 67 8 92 8.0%

17 KS 4 6 1 11 4 8 1 13 0 24 2.1%

18 KY 3 7 3 13 7 26 16 49 4 66 5.7%

19 LA 4 0 0 4 12 1 0 13 0 17 1.5%

20 MA 1 0 0 1 3 0 0 3 5 9 0.8%

21 MD 6 0 0 6 3 1 0 4 0 10 0.9%

22 ME 0 0 0 0 0 0 0 0 0 0 0.0%

23 MI 6 2 2 10 4 8 9 21 3 34 2.9%

24 MN 6 4 0 10 7 1 2 10 2 22 1.9%

25 MO 5 2 1 8 10 16 12 38 4 50 4.3%

26 MS 5 0 2 7 0 1 4 5 0 12 1.0%

27 MT 0 2 0 2 7 2 4 13 2 17 1.5%

28 NC 4 1 0 5 4 18 2 24 9 38 3.3%

29 ND 11 3 0 14 3 3 8 14 2 30 2.6%

30 NE 4 3 0 7 2 3 0 5 0 12 1.0%

31 NH 1 0 0 1 0 2 0 2 0 3 0.3%

32 NJ 0 2 0 2 0 0 0 0 4 6 0.5%

33 NM 2 1 0 3 2 0 7 9 0 12 1.0%

34 NV 0 2 1 3 6 0 0 6 2 11 1.0%

35 NY 5 0 0 5 0 2 6 8 0 13 1.1%

36 OH 11 0 2 13 3 26 3 32 8 53 4.6%

37 OK 3 0 0 3 7 2 1 10 0 13 1.1%

38 OR 0 1 0 1 0 0 0 0 0 1 0.1%

39 PA 11 4 1 16 12 12 19 43 7 66 5.7%

40 PR 0 0 0 0 0 0 0 0 0 0 0.0%

41 RI 0 0 0 0 0 0 0 0 0 0 0.0%

42 SC 3 4 4 11 3 17 2 22 1 34 2.9%

43 SD 0 1 0 1 1 1 0 2 0 3 0.3%

44 TN 1 2 1 4 0 1 17 18 2 24 2.1%

45 TX 17 8 2 27 21 9 10 40 16 83 7.2%

46 UT 0 7 0 7 7 5 0 12 2 21 1.8%

47 VA 5 0 0 5 2 9 0 11 1 17 1.5%

48 VT 0 0 0 0 0 0 0 0 0 0 0.0%

49 WA 1 0 0 1 0 0 0 0 0 1 0.1%

50 WI 8 0 3 11 5 5 12 22 0 33 2.9%

51 WV 9 7 1 17 4 11 3 18 0 35 3.0%

52 WY 0 3 2 5 7 7 0 14 2 21 1.8%

Column totals 169 99 42 310 175 329 231 735 111 1,156 100%

Percentages = 55% 32% 14% 100% 19% 45% 35% 100% N/A

Note: Because the CCR final rule requires that synthetic/composite and clay liners meet a standard that includes a liner of at least 36 inches in thickness, the 

values in the “lined” surface impoundment column in this table are adjusted to reflect only those existing surface impoundments with sufficiently thick liners. 

There are five such existing surface impoundments with synthetic/composite liners (i.e., 85 existing impoundments have synthetic/composite liners, but only 

80 have liners of sufficient thickness), and there are 14 such impoundments with clay liners (i.e., 90 existing impoundments have clay liners, but only 76 have 

liners of sufficient thickness). Correspondingly, the RIA categorizes these 19 impoundments into the “unknown” category for modeling purposes. Note also, 

total count of 846 impoundments includes 735 active impoundments and 111 inactive impoundments. 
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2.3.6 Summary of CCR Management Practices

Note: The exhibits and text in this section do not reflect the revisions described in Section

9.2.1 removing 61 additional plants from the universe of plants affected by the CCR final rule.

Exhibit 2-N summarizes plant counts, annual tons of CCR disposed, and electricity generation 

nameplate capacity for the 478 coal-fired electric utility plants that dispose of CCR for each 

CCR management method. Because some plants report using more than one CCR management 

method, the sum of the plants across each disposal method exceeds the total count of 478 plants.

Exhibit 2-N

Summary of Electric Utility Plant Size and CCR Disposal Estimated in this RIA

Characterizing Metrics

Plants Using CCR Landfills

(dry disposal)

Plants Using CCR 

Impoundments

(wet disposal)b

Metric 

Totals On c-Site Off-Sitea

Plant Counts

2012 Count of Coal-Fired Electric Utility 

Plants that Dispose of CCR (478 total) 188 177d 144 459e

Percent of total plant count 39% 37% 30% 96%

CCR Disposal

Annual CCR disposal (millions of tons) 41.7 14.8 14.7 71.2

Percent of total CCR disposed 59% 21% 21% 100%

Minimum per plant (tons) 59 6 3 3

Maximum per plant (tons) 1,701,500 1,542,000 1,193,100 1,701,500

Mean per plant (tons) 221,563 83,705 102,349 164,833

Median per plant (tons) 89,550 15,792 36,300 44,000

Electricity Generation

Nameplate capacity (MW)f 160,907 76,029 139,740 375,638

Percent of total nameplate capacity 43% 20% 37% 100%

Minimum per plant (MW) 50 6 16 6

Maximum per plant (MW) 4,008 2,911 3,540 4,008

Mean per plant (MW) 1,087 667 1,100 786

Median per plant (MW) 795 432 868 539

a This RIA assumes all reported “off-site disposal” in the EIA-923 database involves off-site landfill dry disposal, because it 

is expensive to transport large volumes of wet (i.e., watery) CCR long distances.

b Surface impoundments are reported in the EIA-923 database as “disposal ponds.” As described in this chapter, this RIA does

not assume that all impoundments identified are disposal impoundments.

c Totals are non-duplicative; therefore rows do not sum.

d 93 plants use solely off-site landfills.

e The 19 remaining plants use their CCR solely for beneficial uses.

f Nameplate capacity is the electricity generation output potential in megawatts (MW). Nameplate values are from 2012 EIA860, or else 2009 EIA-860 if not available (7 plants).
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2.4 Analytic Framework for the RIA 

The analytic framework of this RIA includes four key components:

1. 2013 constant prices (i.e., this RIA does not project future price inflation);

2. Two alternative discount rates of 7% and 3%;

3. 100-year period of analysis (2015 to 2114); and

4. Future projection factorsForecast of future annual coal consumption for annual 

coal-fired electricity generation (as a proxy forbasis estimating in this RIA future 

annual CCR generation tonnage), and annual U.S. population growth.).

This framework is consistent throughout the analysis of CCR management regulatory 

compliance costs (Chapter 4) and human health and environmental benefits and beneficial use 

impacts (Chapter 5), though it differs for the market impacts estimated via the Integrated 

Planning Model (IPM).

2.4.1 Constant Prices

Consistent with OMB Circular A-4, this RIA applies a year 2013 constant price level to all future 

annual monetary values of costs and benefits.91 However, not all dollar-monetized benefits and 

costs in this RIA are based on actual market prices of goods or services. Some monetary values 

of benefits and costs are based on actual past market price data (i.e., prior to 2013), and in those 

instances, this RIA has updated the prices to 2013 by multiplying them by appropriate indexes, 

or specific sub-components of these general indexes (index-updated prices).92 Some benefits and 

costs, meanwhile, are based on consumer or household “willingness-to-pay” surveys, such as the 

value of statistical life (VSL) applied in this RIA for monetizing population risks associated with 

cancer. This RIA references updated values for these non-market prices, or updates them as 

needed using appropriate indexes.

This RIA also uses historical data for years prior to 2014 to analyze 49 historical release 

incidents which occurred prior to 2014 (between 1995 and 2009) associated with CCR 

impoundments.

 

91 “In presenting the stream of benefits and costs, it is important to measure them in constant dollars to avoid the misleading 

effects of inflation in your estimates.” OMB, 2003, Circular A-4, Regulatory Analysis, p. 32.

92 These price update indexes include:

 U.S. Department of Labor, Bureau of Labor Statistics “Employment Cost Index” 

(http://www.bls.gov/news.release/eci.t02.htm)

 Engineering News-Record “Construction Cost Index” (CCI) (http://enr.construction.com/economics/)

 U.S. Department of Labor, Bureau of Labor Statistics “Producer Price Index” (PPI) 

(http://www.bls.gov/web/ppi/ppitable06.pdf)

 U.S. Department of Labor, Bureau of Labor Statistics “Consumer Price Index” (CPI) (http://www.bls.gov/cpi/tables.htm)

 U.S. Department of Commerce, Bureau of Economic Analysis “Implicit Price Deflator for Gross Domestic Product” 

(http://www.bea.gov/national/nipaweb/TableView.asp?SelectedTable=13&Freq=Qtr&FirstYear=2009&LastYear=2011].
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2.4.2 Discount Rate

Consistent with guidance in OMB Circular A-4 and EPA’s Guidelines for Preparing Economic 

Analyses, this RIA also applies two alternative discount rates of 7% and 3%. OMB recommends 

that 7% be used in RIAs evaluating a regulation that will mainly displace or alter the use of 

capital in the private sector, and 3% be used when a regulation instead affects private 

consumption.93 The lower discount rate is also appropriate for policies with long time horizons, 

in which benefits affect a different generation than the costs do, as in the case of the CCR rule.94

2.4.3 Period of Analysis

OMB Circular A-4 indicates that RIAs should evaluate benefits and costs “far enough in the 

future to encompass all the significant benefits and costs likely to result from the [CCR] rule.”95

The onset and duration of many of the human health and environmental benefits of the CCR final 

rule may extend at least 100 years or more into the future, because of three time factors:

 Disposal unit lifespans. This RIA uses an average historical operating lifespan 

for CCR landfills of 80 years (40 years prior to vertical expansion, and 40 years 

following vertical expansion) and CCR impoundments of 40 years.96 However, 

some of the longest operating CCR impoundments date back to the 1940s, 

reflecting operating lifespans of 70 or more years (the oldest active CCR 

impoundment is reportedly 84 years old as of 2014 in Michigan).

 Groundwater migration. Underground CCR management unit leachate 

migration distance to groundwater drinking wells prior to human exposure, which 

for arsenic the arrival leachate migration concentration peaks at 75 years 

according to the CCR risk assessment.

 Illness latency. Latency periods for onset of illness after exposure, which for 

cancers can average 20 years after exposure.

Consequently, this RIA applies a 100-year future period of analysis extending from 2015 to 

2114. On the other hand, as Exhibit 2-O below illustrates, extending the period of analysis 

beyond 100 years is not necessarily productive for discount rates of 3% and higher, because the 

discounted present value of future benefits and costs 100 years into the future is only a tiny 

fraction of its future monetary value at both a 3% and a 7% discount rate.

 

93 OMB Circular A-4, p. 33-34.

94 EPA, Guidelines for Preparing Economic Analyses, p. 6-19.

95 The RIA “should present the annual time stream of benefits and costs expected to result from the rule, clearly identifying when 

the benefits and costs are expected to occur. The beginning point for your stream of estimates should be the year in which the 

final rule will begin to have effects, even if that is expected to be some time in the future. The ending point should be far enough 

in the future to encompass all the significant benefits and costs likely to result from the rule.” OMB. 2003. Circular A4 

“Regulatory Analysis” guidance p. 31.

96 CCR storage impoundments are presumed to operate in perpetuity as they are dredged out with regularity and thus do not reach 

capacity.
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Exhibit 2-O

Effect of Alternative Interest Rates on Future Monetary Values

The year 2015 is assumed to represent the first full year after publication of the CCR final rule in 

the Federal Register, although it is not necessarily the first year that all of the rule’s CCR 

pollution controls are in effect. To compute the present values of future benefit and cost streams 

over the 100-year period of analysis, 2013 is used as the reference year to compute discounted 

present values to be consistent with the 2013 price level applied in this RIA. Thus, the analysis 

assumes rule implementation beginning one year after completion of the analysis, and calculates 

two years of discounting by 2015.97

To project costs and benefits across the 100-year future period of analysis, and to establish an 

analytic baseline for the benefits estimation (Chapter 5), this RIA applies historical data and 

calculations. For example, this RIA uses historical data on damage cases associated with CCR 

landfills and impoundments in operation prior to 2014 to assess future benefits associated with 

avoided damage.

2.4.4 Future Annual Change in Coal Consumption

Note: EPA has updated the projections in this section of the RIA to reflect the Base Case 

forecasts in the Integrated Planning Model. See Section 9.2.2 in Chapter 9 of this RIA for a 

description of the relevant modifications and updates to this section.

Key CCR quantity data supporting the estimates in this RIA are based on a recent (i.e., 2012) 

single data year “snapshot.” To account for future expected changes in these annual physical 

quantities, this RIA projects future annual coal consumption (measuring in quadrillion Btu of 

 

97 The cost modeling in this RIA applies costs beginning in 2015, the effective date of the CCR rule. As this RIA presents costs in 

2013 dollars, the cost modeling calculations discount the first costs incurred under CCR rule by two years (2015 to 2013), and all 

subsequent costs by the appropriate number of years relative to how far in the future the cost takes place.
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coal energy) for U.S. coal-fired electricity generation (as a proxy indicator for future annual 

tonnage CCR generation) over the period of analysis of this RIA.

To estimate potential future changes in coal-based electricity generation, this RIA uses the 2015

to 2040 forecast of coal consumption for electricity generation from EIA’s 2014 Annual Energy 

Outlook (AEO).98 This RIA applies the “Reference caseCase” presented in the 2014 AEO; this 

Referencereference case is based on EIA’s evaluation of environmental legislation and 

environmental regulations as of September 2013, as well as other factors such as energy 

technology and energy markets.

This RIA applies this projection as an index multiplier to estimated costs for each future year of 

the analysis., as a numerical proxy in this RIA for potential future annual changes in CCR 

generation (which affect the future cost and benefit estimates of this RIA for both the baseline 

(Chapter 3) and for the CCR final rule (Chapters 4 & 5)). Appendix F of this RIA displays this 

forecast factor and the associated numerical index multipliers (2012 = 1.000) over the period of 

analysis (2015 to 2114) of this RIA.

Though the 2014 AEO report was not available at the time of this analysis, one key factor noted 

in the prior-year (2013) published AEO report for the 2013 Reference case is the projection of 

the future relative share of coal versus natural gas as fuels for electricity generation:

“Relatively low natural gas prices, maintained by growing shale gas production, spur 

increased use in the industrial and electric power sectors, particularly over the next 

decade. In the Reference case, natural gas use in the industrial sector increases by 16 

percent, from 6.8 trillion cubic feet per year in 2011 to 7.8 trillion cubic feet per year in 

2025. After 2025, the growth of natural gas consumption in the industrial sector slows, 

while total U.S. consumption continues to grow. This additional growth is mostly for use 

in the electric power sector. Although natural gas continues to capture a growing share 

of total electricity generation, natural gas consumption by power plants does not 

increase as sharply as generation because new plants are very efficient (needing less fuel 

per unit of power output). The natural gas share of generation rose from 16 percent of 

generation in 2000 to 24 percent in 2011 and increases to 27 percent in 2025 and 30 

percent in 2040. Natural gas use in the residential and commercial sectors remains 

nearly constant, as increasing end-use demand is balanced by increasing end-use 

efficiency.” (Source: EIA 2013 AEO, page 5)

Exhibit 2-P below displays the 2014 AEO projection caseof future coal consumption for 

electricity generation applied in this RIA, (as a basis for estimating in this RIA future CCR 

generation by electric utility plants), which grows 1.9% between 2012 (15.8158 quadrillion Btus) 

and 2040 (17.2693 quadrillion Btus). Because the 2014 AEO projection extends only through 

year 2040, this RIA applies the 2040 value to years 2041 through 2114.

 

98 U.S. Department of Energy, Energy Information Administration (EIA), Annual Energy Outlook (AEO) 2014 With Projections 

to 2040 (Reference Case), Staged Release, April 2014, Year-by-Year Reference Case Tables, Table 2. Energy Consumption by 

Sector and Source, at http://www.eia.gov/forecasts/aeo/
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Exhibit 2-P

DOE-EIA Projection of Coal ConsumptionsConsumption for U.S. Electricity Generation to 2040

 Note: Data and references provided in Appendix F.

0

2

4

6

8

10

12

14

16

18

20

20112015201920232027203120352039204320472051205520592063206720712075207920832087209120952099210321072111

Quadrillion Btu Coal Consumption for 

Electricity Generation

14.5

15

15.5

16

16.5

17

17.5

18

18.5

20112015201920232027203120352039204320472051205520592063206720712075207920832087209120952099210321072111

Quadrillion Btu Coal Consumption for 

Electricity Generation
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2.4.5 Recent Trends Affecting Coal-Fired Electric Utility Plants

The base case coal consumption forecast for electricity generation from EIA’s 2014 Annual 

Energy Outlook (AEO) predicts the impacts on coal consumption for electricity generation based 

on an evaluation of:

99

 Current federal regulations affecting the electric utility industry, including:

o EPA’s June 2011 Cross-State Air Pollution Final Rule (CSAPR); and

o EPA’s December 2011 Mercury and Air Toxics Standards Final Rule 

(MATS);

 State programs that may affect statewide demand for electricity;

 Changes in technologies for the generation, transmission, and use of electricity in 

the market;

 Revised outlooks for industrial production to reflect changes in shale gas 

production and natural gas prices;

 Changes in spot fuel prices allowing plants to convert to other fuel types or utilize 

different mixes of fuel types; and

 Land constraints for siting CCR management units on site.

As electric utility companies face a range of regulatory, technological, and market changes, they 

are likely to reconsider the specifics of plant operation in great detail, including which fuels they 

use and how they may manage CCR in the future if they continue to burn coal. For example, 

some electric utility companies over the last few years have already announced actual or 

planned:

 EGU closures. Closures of a number of coal-fired electric generator units.

 Fuel switching. Switching of single electricity generating units or of entire 

electric utility plants from coal to other fuels such as natural gas in the face of 

anticipated market shifts (e.g., changes in relative price of fuels).

 Wet CCR phase-out. Continued burning of coal as a fuel but phase-out of wet 

CCR (i.e., surface impoundments) in favor of dry CCR management (i.e., on-site 

or off-site landfills). The RIA for EPA’s June 2010 CCR proposed rule 

 

99 http://www.eia.gov/forecasts/aeo/sector_electric_power.cfm. The specific forecast used is the base case of the AEO 2014. 

However, as the full AEO 2014 report has not been published, the list of items evaluated in this section was obtained from the 

AEO base cases for 2012 and 2013.
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documented the recent wet CCR phase-out trend, which has continued up to the 

2012 DOE EIA-923 data year of this RIA:100

Data year =

Wet CCR disposal =

% of CCR generation =

1996

25.2 mill. tons

25%

2005

22.5 mill. tons

18%

2012

14.7 mill. tons

12%

It is reasonable to assume that the wet CCR phase-out trend will continue into the future, as state 

regulations phase in in the baseline. Exhibit 2-Q presents a sample of such recent (2006-2012) 

announcements. As electric utilities reevaluate their operations, they will likely reconsider the 

ways in which their plants handle and/or dispose of CCR. Furthermore, future air pollution 

regulations are likely to result in additional reassessments of the viability of electricity plants 

with older and less efficient air emission particulate control devices and air pollution scrubbers. 

As the market and regulatory environment in which plants operate evolves, utilities will 

emphasize flexible, adaptable operations.

The cost estimates in this RIA acknowledge this pattern by incorporating these requirements into

utility plants decisions on siting CCR impoundments in the future, and by incorporating overall 

trends in energy productionfuture annual projection of coal consumption for electricy generation

from EIA’s AEO 2014 AEO projection case thatwhich reflects recently-enacted state 

government and EPA environmental regulations. However, the cost estimates in the RIA do not 

separately project a trend of wet-to-dry CCR handling conversion; instead this RIA accounts for 

wet-to-dry CCR conversion on a CCR management unit-by-unit basis based on the relative cost 

of various CCR management options available to utility plant owners/operators.

 

100 1996 and 2005 wet CCR disposal tonnages and percentages of CCR generation from page 93 of EPA’s RIA for the June 2010 

CCR proposed rule, available as document ID nr. EPA-HQ-RCRA-2009-0640-0003 at http://www.regulations.gov
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Exhibit 2-Q

Announced Changes in Coal-Fired Electricity Generation by Electric Utilities (2006-2012)

Electric Utility Entity

Count of Affected 

Electric Utility Plants Announced Change

1. Tennessee Valley Authority 

(TVA) 9 Planned conversion from wet to dry CCRa

2. Duke Energy Company

5 Planned conversion from wet to dry CCRb

2 Conversion away from coal as a fuel sourcec

3. Hoosier Energy REC Inc. 1 Planned conversion from wet to dry CCRb

4. Vectren Southern Indiana Gas 

and Electric Company 2 Planned conversion from wet to dry CCRb

5. Westar Energy Company 1 Planned conversion from wet to dry CCRb

6. Progress Energy 4 Conversion away from coal as a fuel sourcec

7. Xcel Energy 2 Converted to natural gasc

Column total plant count = 26

Note:

This table is not necessarily a comprehensive complete listing of all such electric utility industry announcements made publicly 

during the 2006 to 2012 period.

Sources:

f TVA’s 20 August 2009 news release “TVA Coal Combustion Products Remediation Plan Proposed” announced that TVA 

plans “to convert all TVA wet ash and gypsum storage to dry...over eight to 10 years.”

g Planned “wet-dry” conversions at plants:

 The Duke Energy Company, the Hoosier Electric Cooperative, and Vectren Southern Indiana Gas and Electric 

Company were reported 24 October 2009 by Mark Wilson of the Courier Press “Coal Ash Disposal Varies From 

Company to Company” (http://btop.courierpress.com/news/2009/oct/24/coal-ash-disposal-varies-from-companytocompany/?print=1).

 The January 17, 2012 news about Duke Energy’s announcement to close old coal-fired electric utility plants located 

in North Carolina (totaling 1,660 megawatts) was published after the baseline modeling for this RIA was already 

complete. http://www.myrtlebeachonline.com/2012/01/17/2607592/duke-agrees-to-pollution-controls.html. It is 

unclear whether EIA’s April 2011 AEO projections account for these particular closures.

 Westar Energy apparently converted to dry fly ash management in 2006 according to “Coal Plant O&M: Retrofit Fly 

ash-Handling System Pays Dividends,” Douglas J. Smith, Contributing Editor, Coal Power magazine, 01 Nov 2007 

(http://www.coalpowermag.com/transportation/Coal-Plant-O-and-M-Retrofit-Flyash-Handling-System-PaysDividends_79.html)

h EPA identified the 8 plants switching from coal from Source Watch websites:

 http://www.sourcewatch.org/index.php?title=Coal_plant_conversion_projects

 http://www.sourcewatch.org/index.php?title=Existing_U.S._Coal_Plants

 Source Watch indicated that the Xcel Energy High Bridge Plant converted natural gas in 2008: 

http://www.sourcewatch.org/index.php?title=High_Bridge_Generating_Plant.
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Chapter 3

Baseline CCR Management in the Electric Utility Industry

Note: EPA has updated the baseline cost calculations presented in this chapter to conform 

with changes to the universe of plants affected by the rule and the analytic framework. These 

updats are not reflected in the text and exhibits in this chapter. See Sections 9.2 and 9.4 in 

Chapter 9 of this RIA for a description of the relevant modifications and the resultant reestimated costs, respectively.

This chapter characterizes baseline CCR management practices and costs within the electric 

utility industry. For this RIA, the baseline consists of two time periods:

 Current conditions without the CCR rule. Due to publication lag times for key 

data sources, this RIA characterizes baseline conditions using 2009 to 2012 data, 

depending on the data source used.

 Projected future conditions without the CCR final rule over this RIA’s 100-year 

period of analysis (2015-2114).101 This second timeframe serves two purposes:

o To capture the baseline impact of the CCR pollution control requirements that 

some state regulations apply to new (future) CCR units (i.e., some states 

require more stringent design and operating standards on new CCR units than 

on existing units).

o To support estimation of long-term benefits and costs of the CCR rule’s

regulatory requirements that affect future new or expanded CCR units, in 

addition to near-term benefits and costs of requirements affecting existing 

units.

Development of this baseline is consistent with OMB Circular A-4, which requires RIAs to 

measure the benefits and costs of regulation incremental to a baseline without the regulation in 

place.102 This chapter consists of three sections. The first, Section 3.1, presents an evaluation of 

baseline operating conditions (i.e., CCR pollution controls mandated by state regulations) for 

CCR management units, and Section 3.2 summarizes the unit costs of these controls. Finally, 

Section 3.3 details the methodology used within this RIA to estimate baseline costs associated 

with CCR management and summarizes the total baseline cost to the electric utility industry 

associated with existing CCR pollution controls.

3.1 Baseline CCR Management Practices and CCR Regulations

This section identifies data that support estimates of the costs to the electric utility industry, and 

to government, for baseline industry CCR pollution controls associated with CCR management. 

This section first outlines the types of management costs that are applicable in the baseline, and 

then characterizes existing pollution controls at CCR units.

 

101 Consistent with the analytic framework and regulatory implantation assumptions described in Chapter 2, this RIA assumes 

2014 represents the earliest first year when the CCR rule could take effect.

102 OMB Circular A-4 defines the baseline as “the best assessment of the way the world would look absent the rule.”
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As noted in the introduction to this chapter, this RIA defines the baseline as consisting of 

existing conditions as well as the projection of future conditions over the 100-year future period 

of analysis (2015 to 2114) applied in this RIA.103

To identify baseline practices and costs, this RIA uses the most recent available data, relying 

solely on publicly available data used in prior studies and reports and updated using empiricallyjustifiable factors. This RIA considers 12 categories of potential baseline costs associated with 

state government regulation of CCR management that are related to CCR pollution controls and 

other possible CCR management requirements. Nine cost categories are “unit-level” costs that 

accrue to individual CCR management units (i.e., CCR landfills and impoundments):

1. Groundwater monitoring to detect CCR contamination;

2. Bottom (composite) liner installation;

3. Leachate collection system installation and management;

4. Fugitive CCR dust controls;

5. Rain and surface water run-on/run-off controls;

6. CCR landfill and impoundment location restrictions (including water tables, 

floodplains, wetlands, fault areas, seismic zones, and karst terrain);

7. Closure capping to cover units;

8. Post-closure groundwater monitoring requirements (30 years); and

9. Structural integrity requirements (applicable to CCR impoundments only).

The remaining three cost categories listed below accrue at the plant level. While some costs may 

vary based on the size or number of CCR management units associated with a plant, these costs 

generally pertain to pollution controls with a scope broader than individual management units. 

These categories include:

10. State corrective actions (i.e., CCR contaminated groundwater clean-up);

11. State paperwork reporting/recordkeeping; and

12. State induced CCR impoundment closures and conversion to dry CCR 

handling.104

 

103 This RIA assumes 2015 represents the first year when the final rule will take effect.

104 This RIA models this cost at the unit level, but costs can be thought to accrue at a plant level. This designation 

notwithstanding, the cost estimation model used in this RIA determines whether or not a given impoundment closes and 

undergoes wet-dry conversion on a unit-by-unit basis, rather than on a plant-by-plant basis, where each plant decides how to 
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For each of the 478 operating coal-fired electric utility plants in the universe, this RIA estimates 

baseline CCR pollution controls at CCR management units for each type of unit including:105

 242 plants operating 310 active on-site CCR landfills;

 142 plants operating 142 active on-site CCR disposal surface impoundments; and

 239 plants operating 593 active on-site CCR storage impoundments.106

In general, EPA used available survey data and state regulatory requirements (references 

provided below) for existing and newly-constructed units to assign baseline CCR pollution 

controls to each unit. The following sections characterize the industry baseline for specific 

pollution controls.

3.1.1 Data Sources Used to Characterize Baseline Practices

This RIA relies on publicly available data, including integration of data from multiple sources, to 

identify baseline pollution control practices for CCR management. This section briefly 

summarizes key data sources and methods for unit-level practices such as liners, monitoring, and 

capping. 

3.1.1.1 Liners and Bottom Liners

EPA identified the baseline use of bottom liners by CCR landfills and surface impoundments 

using the following sources:

 Impoundment data from ORCR’s 2009-2012 CCR impoundment site 

inspections;107

 Impoundment data from ORCR’s 2009 mail survey to plants with CCR 

impoundments;108 and

 Landfill and impoundment data from EPA Office of Water’s 2010 mail survey to 

power plants for the Steam Electric Power Generating Effluent Limitation 

Guidelines.109

 

change its CCR management regime for multiple CCR management units at the same time. See Chapter 4 for additional 

information. 

105 The sum of electric utility plant counts for each CCR management category below exceeds 478 because some plants use more 

than one CCR management method. Inactive ponds are modeled separately and discussed later in this chapter.

106 While EIA data indicate that 197 of the 478 plants also dispose of CCR off-site (assumed to be off-site landfills in this RIA), 

this RIA does not evaluate any incremental costs associated with off-site landfill disposal, nor does it make assumptions that 

plants currently using off-site disposal for some or all of their CCR will change management of that CCR tonnage in response to 

the rule. 

107 http://www.epa.gov/waste/nonhaz/industrial/special/fossil/surveys2/index.htm.

108 http://www.epa.gov/waste/nonhaz/industrial/special/fossil/coalashletter.htm.

109 http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm#point6.
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For 268 of the 310 existing active on-site landfills (86%), EPA was able to determine whether a 

bottom liner was present. For 127 of these 268 landfills, however, EPA was unable to determine 

the type of bottom liner. For the purpose of estimating costs associated with these 127 landfills, 

this RIA assigns a weighted-average cost based on the reported percentage of composite and clay 

liners for landfills with known liners types.110 Then, for the remaining 42 existing active-onsite 

landfills where EPA was unable to determine whether or not a bottom liner was present, this RIA 

assigns a weighted-average cost based on the reported percentage of landfills with composite 

liners, clay liners, or no bottom liner.111 

For 504 of the 735 existing active on-site surface impoundments (69%), EPA was able to 

determine whether a bottom liner was present and whether the liner was composite or clay. For 

the purpose of estimating costs associated with the remaining 231 surface impoundments, this 

RIA assigns a weighted-average cost based on the reported percentage of surface impoundments 

with composite liners, clay liners, or no bottom liner.112,113

The weighted approach used for surface impoundments and landfills with unknown liner types or 

unknown liner status is consisted with the modeling approach conducted for EPA’s risk 

assessment for the CCR rule.

3.1.1.2 Leachate Collection Systems

EPA obtained data on leachate collection systems for 260 of 310 active CCR landfills (84%) in 

the universe from the 2010 Office of Water Mail Survey; these data were then carried forward to 

the remaining universe of active landfills based on 2012 EIA data.114 For the remaining landfills, 

this RIA uses the applicable state regulatory requirements for those units. Information on 

leachate collection systems at existing impoundments is addressed in Section 3.2.2.3.

3.1.1.3 Closure Capping

EPA obtained new data on caps for landfills, including 104 of the 310 existing active on-site 

CCR landfills (34%).115 For the remaining landfills, this RIA assumes that units conform to 

applicable state regulatory requirements. Information on closure capping at existing 

impoundments is addressed in Section 3.2.2.8.

3.1.1.4 Other Unit-Level Pollution Controls

 

110 62% of landfills with liners have composite bottom liners while 38% have clay bottom liners.

111 For landfills, 18% have composite bottom liners, 11% have clay bottom liners, and 70% do not have a bottom liner.

112 For surface impoundments, 17% have composite bottom liners, 18% have clay bottom liners, and 65% do not have a bottom 

liner.

113 While this methodology is used for existing surface impoundments for cost estimation, the analysis in later chapters 

probabilistically assigns each surface impoundment a “lined” or “unlined” status as part of the modeling of the costs associated 

with the CCR final rule, based on the existing proportion of CCR surface impoundments lined either sufficiently or insufficiently. 

For additional information, see Chapter 4.

114 This process matched EPA-OW survey data with the ORCR-defined universe to be affect by the CCR rule. Data for a subset 

of entities from the EPA-OW survey responses were applied for this analysis. For more information on the EPA-OW survey data, 

see http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm#point6.

115 http://www.epa.gov/waste/nonhaz/industrial/special/fossil/surveys2/index.htm.
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For all other unit-level controls, including groundwater monitoring, fugitive CCR dust control,

stormwater run-on/run-off control, site location restrictions, and post-closure groundwater 

monitoring, this RIA assumes that unit practices and costs reflect state-specific regulatory 

requirements for CCR landfills and surface impoundments.116 This RIA assigns no controls 

under the baseline for units that are not described in any of the aforementioned surveys, and for 

which state CCR pollution control requirement data are not available. This creates a relatively 

high-cost assumption for estimating CCR rule costs because it does not account for baseline 

requirements in 17 states, and for any utility plants that voluntarily employ pollution controls in 

the baseline; many of these utility plants would face lower costs under the CCR rule.

Exhibit 3-A below provides a summary of the methodology used to characterize the baseline, by 

CCR management unit type and CCR pollution control.

Exhibit 3-A

Summary of Methodology Used in Characterizing Baseline CCR Pollution Controls

CCR Unit Type Liner Type Closure Cap Type

Leachate Collection 

System

Other Unit-Level 

Controls

Existing active/open 

landfillsa Survey data

Survey data if 

available; if not, state 

regulations data

Survey data; if 

unknown, state 

regulations data

State regulations data

New future/replacement 

landfills

Survey data if 

available; if not, 

state regulations 

data

Survey data if 

available; if not, state 

regulations data

Survey data if

available; if not, state 

regulations data

State regulations data 

for newly-constructed 

units

Inactive landfillsb Survey data Survey data Survey data No controls assigned

Existing active/open 

impoundmentsa Survey data State regulations data State regulations data State regulations data

New future/replacement 

impoundments

Survey data if 

available; if not, 

state regulations 

data

State regulations data 

for newly-constructed 

units

State regulations data 

for newly-constructed 

units

State regulations data 

for newly-constructed 

units

Inactive impoundmentsb Survey data No controls assigned No controls assigned No controls assigned

a Where relevant, this RIA applies state regulatory requirements for either newly-constructed units or existing units, based on unit age 

relative to the effective date of the state regulation.

b This RIA assumes that CCR management unit operations pre-date the effective date of current state regulations. If no survey 

information is available, this RIA assumes these units have no liner, closure cap, leachate collection system, as well as lack all other 

unit-level pollution controls. 

3.1.2 Baseline State Government CCR Pollution Control Requirements for CCR 

Landfills and Impoundments (based on 2011 data)

This section summarizes baseline state government CCR pollution control requirements (i.e., 

regulations) for CCR management units. Several states have already established certain CCR 

unit design and operating requirements that must be implemented either upon the effective date 

of the regulation at existing units (e.g., groundwater monitoring), upon retirement of the 

management unit (e.g., post-closure monitoring), or for newly-constructed units only. 

 

116 These controls include groundwater monitoring, fugitive dust controls, run-on/run-off controls, financial assurance (Subtitle C 

option only), disposal unit site location restrictions, capping for impoundments, leachate collection systems for impoundments, 

and post-closure groundwater monitoring.
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To formulate a baseline, this RIA presents a review of state government CCR regulations in 

effect as of 2011 related to pollution controls at CCR landfills and impoundments. The review 

addressed 34 states with coal-fired electric utility plants.117 The plants in these states account for 

98% of the annual quantity of CCR generated as of 2012.118 The following sections provide a 

summary of the baseline state regulatory requirements for the nine unit-level pollution control 

categories discussed earlier in this chapter. Appendix G provides a more detailed summary of 

the state government requirements for both CCR landfills and impoundments.

In the baseline, some state governments may require a particular pollution control for all active 

operating CCR management units, whereas other states may require particular pollution controls 

only for future newly-constructed units. Thus, baseline costs associated with state requirements 

as estimated in this RIA change over the 100-year period of analysis (2015 to 2114) in this RIA, 

according to: (a) the timing of bottom liner implementation requirements under the state 

regulations (i.e., for existing or only for future new units), and (b) the age of the units. In other 

words, the baseline in this RIA is “dynamic,” rather than a “static” snapshot of current 

conditions.

Some states have granted waivers from certain existing regulations, or in other instances have 

added extra CCR pollution control requirements above existing regulatory requirements to some 

specific permits issued to electric utility plants for operating CCR management units. For 

example, a 2006 survey study involving a sample of 16 state governments indicated that six of 

the 16 states had granted waivers from existing state government regulations for CCR 

management over the 1994-2004 study period.119 EPA’s review of existing state regulatory 

requirements presented in this RIA does not include such a permit-by-permit level of detail; the 

review only constitutes a generalized review of state regulatory requirements for the purpose of 

formulating a baseline in this RIA. This review does not constitute an evaluation or judgment in 

this RIA about the adequacy of existing state government regulatory requirements.

3.1.2.1 Groundwater Monitoring Requirements

Groundwater monitoring requirements vary among states based on a number of criteria, 

including:

 Point of compliance. Two options for point-of-compliance include either 

installing monitoring wells at the unit boundary or installing monitoring wells

 

117 This RIA uses information on existing (baseline) state government regulatory programs collected by EPA-ORCR as of 

January 11, 2012, as supplied by Patrick Kelly, EPA-ORCR Environmental Engineer and Jesse Miller, EPA-ORCR Chemical 

Engineer. The data reflect information from Earth Justice and EPA-ORCR’s Notice of Data Availability (NODA) published 

October 12, 2011, which announced and invited public comment on five categories of additional information obtained by EPA in 

conjunction with the June 21, 2010 proposed CCR rule: (a) chemical constituent data from CCRs; (b) power plant and CCR 

management unit data; (c) information on additional alleged damage cases; (d) existing state government regulatory requirements 

applicable to CCR management units; and € CCR beneficial use.

118 The 34 states include Alabama, Arizona, Colorado, Florida, Georgia, Iowa, Illinois, Indiana, Kansas, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, Mississippi, Missouri, Montana, Nevada, New Mexico, New York, North Carolina, North 

Dakota, Ohio, Oklahoma, Pennsylvania, South Carolina, Tennessee, Texas, Utah, Virginia, Washington, West Virginia, 

Wisconsin, and Wyoming.

119 See Tables J.1, K.1, and G.1 of Coal Combustion Waste Management at Landfills and Surface Impoundments 1994-2004, 

joint report by the U.S. Department of Energy and EPA, August 2006, report nr. DOE/PI-0004.
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within 150 meters of the unit boundary. Recent changes to state regulations 

suggest that states typically require unit boundary monitoring.

 Number of wells. A number of states specify a minimum number of monitoring 

wells. EPA also reviewed well spacing design criteria for landfill boundary 

detection wells for Florida, Iowa, and Kansas. Well requirements for 

impoundments range from three wells (Florida) to 21 wells (Michigan); well 

requirements for landfills range from one well (Iowa) to four wells (Missouri). In 

addition, certain states specify well requirements for both landfills and 

impoundments, ranging from three wells for both unit types (Louisiana) to four 

wells for both unit types (Pennsylvania, Washington, and West Virginia).

 Monitoring parameters. Two options for sampling include testing for chemical 

indicators and testing for RCRA hazardous waste Appendix VIII constituents (40 

CFR 261 Appendix VIII). Of the 34 states reviewed by EPA, six require chemical 

indicator monitoring for surface impoundments, and 15 require chemical indicator 

monitoring for landfills. Meanwhile, two states require RCRA Appendix VIII 

constituent monitoring for impoundments, and 13 states require this monitoring 

for landfills.

 Monitoring frequency. Three options for groundwater sampling frequency 

include quarterly, semi-annual, and annual. Of the 34 states reviewed, four require 

quarterly sampling for surface impoundments and five require quarterly sampling 

for landfills. Five states require semi-annual sampling for surface impoundments, 

and 16 require semi-annual sampling for landfills. Finally, two states require 

annual sampling for surface impoundments and six require annual sampling for 

landfills.

 Timing of state regulation implementation. In the baseline, some states require 

groundwater monitoring for all active operating units, while others require 

monitoring only for units newly-constructed after effective date of the state rule. 

These differences have a material impact on costs, because this RIA’s CCR 

pollution control cost estimation model calculates different future baseline cost 

streams depending on the timing of groundwater monitoring implementation in 

each state. Of the 34 states reviewed by EPA, nine require monitoring for existing 

impoundments and 25 require monitoring for existing landfills. Meanwhile, 12 

states require groundwater monitoring at newly-constructed impoundments, and 

29 require groundwater monitoring at newly-constructed landfills. In these counts, 

some states are listed twice because they require monitoring for both existing and 

newly-constructed units.

3.1.2.2 Bottom Liner Requirements

Of the 34 states whose regulations EPA reviewed, four require liners for existing surface 

impoundments, and seven require liners for existing landfills. Eleven states require liners at 

newly-constructed surface impoundments, and 24 states require liners at newly-constructed 
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landfills. In the counts of states above, states are listed twice if they require bottom liners for 

both existing and newly-constructed units.

States requiring liners vary in the liner types they require for different CCR management unit 

types. For example, Washington requires clay liners for both existing and newly-constructed 

impoundments, while Nevada and Oklahoma require composite liners for existing units, and five 

additional states require composite liners for newly-constructed units. For baseline cost 

estimation, this RIA considers the specific liner requirements for existing and newly-constructed 

units in each state.

3.1.2.3 Leachate Collection System Requirements

Of the 34 states reviewed by EPA, two require leachate collection systems for existing surface 

impoundments, and eight require leachate collection systems for existing landfills. Nine states 

require leachate collection systems at newly-constructed surface impoundments, and 26 require 

leachate collection systems at new landfills. In the counts of states above, states are listed twice 

if they require leachate collection systems on both existing and new units.

3.1.2.4 Fugitive Dust Control Requirements 

Of the 34 states whose regulations EPA reviewed, 21 states require immediate compliance with 

fugitive dust control requirements for CCR landfills, and 24 states require dust control at newlyconstructed CCR landfills. In the counts of states above, states are listed twice if they require 

fugitive dust control for both existing and new units.

States requiring fugitive dust controls vary in the dust control types they require. Some states 

require only wetting and truck covers, while other states require only CCR landfill compaction; 

some states require both. For estimating baseline costs in states requiring fugitive dust controls, 

this RIA applies a generalized, simplified assumption that landfill operators:

 Compact CCR to maximize available landfill capacity;

 Use water wetting to facilitate compaction and for dust control; and

 Spray water on unpaved roads. 

Note that while this RIA estimates CCR final rule compliance costs associated with CCR dust 

controls for surface impoundments in Chapter 4, review of state government regulations did not 

indicate CCR dust control requirements for surface impoundments. Correspondingly, baseline 

costs estimated in this chapter do not reflect any costs associated with dust controls currently 

implemented at surface impoundments.

3.1.2.5 Storm Water Run-On/Run-Off Control Requirements

Of the 34 states reviewed, 22 require storm water run-on/run-off control for existing landfills, 

and 25 states require run-on/run-off control at newly-constructed landfills. In the counts of states 
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above, states are listed twice if they require run-on/run-off control for both existing and new 

units.

Note that while this RIA estimates CCR final rule compliance costs associated with run-on/runoff controls for surface impoundments in Chapter 4, review of state regulations did not indicate 

run-on/run-off control requirements for surface impoundments. Correspondingly, baseline costs 

estimated in this chapter do not reflect any costs associated with run-on/run-off control 

requirements currently implemented at surface impoundments.

3.1.2.6 CCR Landfill and Impoundment Location Restrictions

In 2000, EPA reviewed regulations in the 25 states with the highest coal usage for electricity in 

year 2000 to identify applicable location restrictions on CCR management. This RIA uses that 

research, and may therefore understate or overstate baseline costs if recent changes to state 

regulations have changed location restrictions.120 The following summarizes state restrictions on 

locating CCR surface impoundments and landfills, focusing on six location restriction categories.

 Natural water table. Of the 25 states whose regulations were reviewed, five 

states restrict surface impoundments to be located above the natural water table, 

and eight restrict landfills to be located above the natural water table.121

 Floodplains. Existing CCR landfills and impoundments are already subject to the 

open dumping floodplains location restriction criteria contained in 40 CFR part 

257, subpart A criteria, in effect since 1979. Of the 25 states whose regulations 

were reviewed, eight states restrict surface impoundments in floodplains, and 20 

restrict landfills.122

 

120 One example of recent changes to state CCR location restrictions is the 2009 - 2011 effort by the Minnesota Pollution Control 

Agency to develop new regulations requiring safer locations for future landfills in Minnesota. The new regulations, which still 

need final approvals as of October 2011, would more tightly restrict the location of industrial and municipal landfills and would 

limit taxpayer exposure for potential remediation costs. The new rules would prohibit new landfills in areas where groundwater 

could move contaminants quickly, and would limit placement in karst areas. The new rules would also prohibit landfills from 

being built where contaminants could reach property boundaries within 100 days. The new rules don't apply to existing landfills. 

See "Stricter pollution rules for state's landfills could kill Xcel Energy's plan for fly-ash site in West Lakeland Township," by 

Dennis Lien, TwinCities.com Pioneer Press, October 2, 2011, available at: 

http://www.twincities.com/news/ci_19027012?source=rss

121 Natural water table restrictions:

 For impoundments, these states include: North Carolina (four feet above seasonal water table); North Dakota (within 

aquifer); Oklahoma (if less than 15 feet above groundwater table); and Wyoming.

 For landfills, these states include: Florida; Iowa and Minnesota (five feet above groundwater); Michigan (four feet above 

groundwater); North Carolina (four feet above seasonal water table); North Dakota (within aquifer); Ohio (five feet above 

water table for wastes with higher leachate concentrations); and Tennessee (if less than five feet above water table).

122 Floodplain restrictions:

 For impoundments, these states include: Kentucky, North Carolina, North Dakota, Pennsylvania, and West Virginia; Kansas 

(under permit); Missouri (if closed with water in place); and Oklahoma (if dike is not at least one foot above 100-year flood 

elevation levels).

 For landfills, these states include: Arizona, Colorado, Florida, Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, 

Minnesota, Missouri, North Carolina, North Dakota, Ohio, Oklahoma, Pennsylvania, Tennessee, West Virginia, Wisconsin, 

and Wyoming.
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 Wetlands. Of the 25 states reviewed, five restrict siting of surface impoundments 

in wetlands and 17 restrict siting of landfills in wetlands.123

 Fault areas. Two of the 25 states reviewed restrict surface impoundments siting 

in fault areas, and seven restrict landfills.124

 Seismic zones. Two of the 25 states reviewed restrict surface impoundments in 

seismic zones, and eight restrict landfills.125

 Karst areas. Five of the 25 states reviewed restrict surface impoundments in 

karst areas, and 12 restrict landfills.126

3.1.2.7 Closure Capping

Of the 34 states reviewed by EPA, six require closure capping for existing surface 

impoundments, and 24 require closure capping for existing landfills. Ten states require closure 

capping at newly-constructed surface impoundments, and 28 require closure capping at newlyconstructed landfills. In the counts above, states are listed twice if they closure capping for both 

existing and newly-constructed units.

States requiring closure capping vary in the cap types they require for different CCR 

management unit types. For example, Virginia requires soil caps for existing impoundments and 

clay caps for newly-constructed impoundments, while Nevada requires synthetic caps for 

existing impoundments and clay or synthetic caps for newly-constructed impoundments. For 

baseline cost estimation, this RIA considers the specific capping requirements for existing and 

newly-constructed units in each state.

3.1.2.8 Post-Closure Monitoring Requirements

Of the 34 states whose regulations EPA reviewed, 11 states require immediate compliance with 

post-closure monitoring for surface impoundments, and 22 states require immediate compliance 

with post-closure monitoring requirements for landfills, and 13 states require post-closure 

 

123 Wetland restrictions:

 For impoundments, these states include: Kentucky, North Dakota, Pennsylvania, and West Virginia; and Missouri (if closed 

with waste in place).

 For landfills, these states include: Arizona, Colorado, Florida, Illinois, Indiana, Iowa, Kentucky, Michigan, Minnesota, 

Missouri, North Dakota, Oklahoma, Pennsylvania, Tennessee, West Virginia, Wisconsin, and Wyoming.

124 Fault area restrictions:

 For impoundments, these states include West Virginia and Missouri (if closed with waste in place).

 For landfills, these states include: Arizona, Colorado, Missouri, Ohio, Tennessee, West Virginia, and Wisconsin.

125 Seismic zone restrictions:

 For impoundments, these states include West Virginia and Missouri (if closed with waste in place).

 For landfills, these states include: Arizona, Colorado, Illinois, Missouri, Tennessee, West Virginia, and Wisconsin; and 

Oklahoma (if within five miles of the epicenter of 4.0 earthquakes).

126 Karst area restrictions:

 For impoundments, these states include: Kentucky, North Dakota, and Pennsylvania; Missouri (if closed with waste in 

place); and West Virginia (1,000 feet away).

 For landfills, these states include: Arizona, Colorado, Indiana, Iowa, Kentucky, Minnesota, Missouri, North Dakota, 

Pennsylvania, Tennessee, and Wisconsin; and West Virginia (1,000 feet away).
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monitoring at newly-constructed surface impoundments, and eight states require post-closure 

monitoring at newly-constructed landfills. In the counts above, states are listed twice if they 

require post-closure monitoring for both existing and newly-constructed units.

3.1.2.9 Structural Integrity Inspections for Surface Impoundments

This RIA estimates that 62.5% of CCR impoundments in the universe are evaluated for structural 

integrity in the baseline.127 Unlike the CCR pollution control requirements applicable in the 

baseline described above, this estimate was not obtained through EPA’s direct review of existing 

state government regulations. Rather than applying baseline costs associated with surface 

impoundments located in certain states, this RIA assumes that in the baseline, structural integrity 

inspections are currently required for 62.5% of all surface impoundments, but does not directly 

specify which impoundments these costs apply to. Rather, the costs for these inspections 

described in Section 3.2.5.10 are scaled down to account for the estimate that 37.5% of surface 

impoundments are not subject to structural integrity inspections in the baseline.

3.1.3 Summary of Baseline State Government CCR Pollution Control Requirements

Note: EPA has updated the baseline cost calculations presented in this chapter to conform 

with changes to the universe of plants affected by the rule and the analytic framework. This 

section does not reflect these updates. See Sections 9.2 and 9.4 in Chapter 9 of this RIA for a 

description of the relevant modifications and the resultant re-estimated costs, respectively.

Appendix H of this RIA presents, on a unit-by-unit basis, the baseline CCR pollution controls 

assumed using the methodology in the previous section for each of the 310 active on-site CCR 

landfills and 735 active on-site CCR impoundments. Exhibits 3-B and 3-C summarize the 

assignment of baseline conditions in this RIA for these landfills and impoundments, respectively, 

for both existing units as well as new units constructed in the future over the 100-year period of 

analysis (2015 to 2114) applied in this RIA.

 

127 See page 36 of joint DOE/EPA report “Coal Combustion Waste Management at Landfills and Surface Impoundments, 1994-

2004,” report nr. DOE/PI-0004, Aug 2006 at: http://nepis.epa.gov/Exe/ZyPDF.cgi/600004O8.PDF?Dockey=600004O8.PDF. 
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Exhibit 3-B

Baseline Compliance with State Government CCR Pollution Control Requirements:

310 On-Site CCR Landfills

CCR Pollution 

Control 

Category

Subcategory 

Description

Required for Future New CCR Landfillsa Required for Existing CCR Landfillsa

Unit Count

Percent of 

Existing 

LFs

CCR Total 

(tons)

Percent of 

CCR Totalb

Unit 

Count

Percent 

of 

Existing 

LFs

CCR Total 

(tons)

Percent of 

CCR 

Totalb

Groundwater Monitoring 214 78% 27,826,896 73% 213 69% 22,651,346 60%

Bottom Liner

Synth./Comp. 130 42% 14,082,050 37% 26 8% 5,273,000 14%

Clay 45 15% 4,116,009 11% 16 5% 4,289,625 11%

Yes (unk. type) 80 25% 10,420,150 28% 127 41% 14,578,930 38%

Unknown (if exists) 8 3% 886,050 2% 42 14% 2,149,779 6%

None 47 15% 8,373,796 22% 99 32% 11,586,721 31%

Leachate Collection System 237 76% 24,566,284 65% 162 52% 19,808,721 52%

Fugitive Dust Controls 211 68% 21,892,452 58% 181 58% 16,776,043 44%

Run-on/Run-off Controls 202 65% 21,284,877 56% 175 56% 16,274,746 43%

Site Restrictionsc

Water Table ND ND ND 18% ND ND ND ND

Floodplains 310 100% 37,878,055 100% 310 100% 37,878,055 100%

Wetlands ND ND ND 59% ND ND ND ND

Fault Areas 1 < 1% 7,500 < 1% ND ND ND ND

Seismic Zone 3 1% 114,000 < 1% ND ND ND ND

Karst Areas 5 2% 200,300 1% ND ND ND ND

Cap

Synth./Comp. 104 34% 12,569,016 33% 61 20% 7,505,662 20%

Clay 103 33% 12,596,544 33% 80 26% 9,056,935 24%

Soil 46 15% 4,133,896 11% 73 24% 9,396,762 25%

None 57 18% 8,578,600 23% 97 31% 11,918,696 31%

Post Closure Monitoring 225 73% 24,603,792 65% 186 60% 19,316,383 51%

ND – Not determined.

a This exhibit does not account for the possibility of existing CCR landfill closure and replacement with a disposal method other than construction of a new CCR landfill. Figures in these columns 

represent the requirements that would be applicable if each existing on-site landfill were replaced by a newly-constructed on-site landfill only.

b Total CCR tons disposed in on-site landfills is 37.9 million tons. While analysis of EIA data (see Chapter 2) reportsindicate that 41.7 million tons of CCR are disposed into on-site landfills, this RIA 

identified 18 plants reporting on-site CCR disposal in landfills where no CCR landfills were previously identified. This RIA addresses the potential impact of the cost estimation for both the baseline 

and final CCR rule as a sensitivity analysis in Chapter 7.

c This RIA does not compare effective date of the site restriction regulation and the date of existing landfill construction for each plant. For existing CCR landfills, this RIA does not account that any 

landfills would be affected by location restrictions because the landfills are currently still operating (and thus not required to close). For new CCR landfills, this exhibit presents only those potential 

new landfills that would be impacted by a given site restriction requirement, rather than all potential new landfills in a state with such a site restriction requirement in place, except for floodplains, 

where no new data were collected. Given that all new and existing CCR landfills must already comply with floodplains site restriction requirements, no new CCR landfills can be sited such that they 

are impacted by this site restriction. While considerably more potential new landfills are located in states that have site restrictions in place, these site restrictions do not apply to the geographic areas 

in which most of these facilities are located.
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Exhibit 3-C

Baseline Compliance with State Government CCR Pollution Control Requirements:

735 Active On-Site CCR Surface Impoundments

CCR Pollution Control 

Categorya

Subcategory 

Description

Required for Future New CCR Impoundmentsb Required for Existing CCR Impoundmentsb

Unit 

Count

Percent of 

Existing 

SIs

CCR Total 

(tons)

Percent of 

CCR 

Totalc

Unit 

Count

Percent of 

Existing 

SIs

CCR Total 

(tons)

Percent 

of CCR 

Totalc

Groundwater Monitoring 194 26% 2,023,774 14% 139 19% 1,456,921 10%

Bottom Liner

Synthetic/Composite 193 26% 2,191,406 15% 80d 11% 956,262 6%

Clay 96 13% 3,312,608 22% 76d 10% 2,566,362 17%

Unknown 183 25% 3,431,050 23% 250 d 34% 4,244,457 29%

None 263 36% 5,795,446 39% 329 45% 6,963,428 47%

Leachate Collection System 176 24% 2,244,162 15% 31 4% 437,703 3%

Site Restrictionse

Water Table ND ND ND 33% ND ND ND ND

Floodplains 735 100% 14,730,510 100% 735 100% 14,730,510 100%

Wetlands ND ND ND 49% ND ND ND ND

Fault Areas 0 0% 0 0% ND ND ND ND

Seismic Zone 6 1% 14,500 < 1% ND ND ND ND

Karst Areas 17 2% 137,418 1% ND ND ND ND

Cap

Synthetic/Composite 153 21% 1,722,119 12% 62 8% 46,900 <1%

Clay 27 4% 435,200 3% 27 4% 435,200 3%

Soil 24 3% 364,400 2% 13 2% 142,761 1%

None 531 72% 12,208,791 83% 633 86% 14,105,649 96%

Post Closure Monitoring 214 29% 2,719,462 18% 172 23% 2,152,945 15%

Structural Integrity Inspectionsf ND 63% ND ND ND 63% ND ND

ND – Not determined.

a This RIA assumes that fugitive dust controls and run-on/run-off controls are not required for surface impoundments under any state regulatory baseline. 

b This exhibit does not account for the possibility of existing CCR surface impoundment closure and replacement with a disposal method other than construction of a new CCR surface impoundment. 

Figures in these columns represent the requirements that would be applicable if each existing on-site surface impoundment were replaced by a newly-constructed on-site surface impoundment only.

c Total CCR tons disposed in on-site impoundments is 14.7 million tons. Note that due to the assignment by this RIA of CCR tonnage to disposal impoundments rather than storage impoundments, the 

total tonnages and percentages in this table are entirely weighted towards disposal impoundments with the given pollution control required to be in place by state regulations.

d Because the CCR final rule requires that synthetic/composite and clay liners be at least 36 inches in thickness, these values are adjusted downward to reflect only those existing surface 

impoundments with sufficiently thick liners. There are five such existing surface impoundments with synthetic/composite liners (i.e., 85 existing impoundments have synthetic/composite liners, but 

only 80 have liners of sufficient thickness), and there are 14 such impoundments with clay liners (i.e., 90 existing impoundments have clay liners, but only 76 have liners of sufficient thickness). 

Correspondingly, the RIA categorizes these 19 impoundments into the “unknown” category for modeling purposes.

e This RIA does not compare effective date of the site restriction regulation and the date of existing impoundment construction for each plant. For existing CCR impoundments, this RIA does not 

account that any impoundments would be affected by location restrictions because the impoundments are currently still operating (and thus not required to close). For new CCR impoundments, this 

exhibit presents only those potential new impoundments that would be impacted by a given site restriction requirement, rather than all potential new impoundments in a state with such a site 

restriction requirement in place, except for floodplains, where no new data were collected. Given that all new and existing CCR impoundments must already comply with floodplains site restriction 

requirements, no new CCR impoundments can be sited such that they are impacted by this site restriction. While considerably more potential new impoundments are located in states that have site 

restrictions in place, these site restrictions do not apply to the geographic areas in which most of these facilities are located.

f Unlike the other pollution control requirements in this table, the estimate of the percent of existing SIs subject to structural integrity inspection requirements in the baseline was not obtained though 

EPA’s direct review of existing state regulations. Rather than applying baseline costs associated with surface impoundments located in certain states, this RIA assumes that in the baseline, structural 

integrity inspections are currently required for 62.5% of all surface impoundments, but does not directly specify which impoundments these costs apply to. Rather, the costs for these inspections are 

scaled down to account for the estimate that 37.5% of surface impoundments are not subject to structural integrity inspections in the baseline.
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3.2 Baseline CCR Management Cost Estimation

Note: EPA has updated the baseline cost calculations presented in this chapter to conform 

with changes to the universe of plants affected by the rule and the analytic framework. This 

section does nto reflect these updates. See Sections 9.2 and 9.4 in Chapter 9 of this RIA for a 

description of the relevant modifications and the resultant re-estimated costs, respectively.

This section presents baseline cost estimates for both on-site CCR management units for the 459 

coal-fired electric utility plants that dispose of CCR.128 It first provides a discussion of the 

functions of the CCR cost estimation model to calculate baseline costs, then follows with a 

summary of baseline costs by CCR pollution control requirement. Finally, it provides a detailed 

listing of unit costs used to model total costs in the baseline.

3.2.1 Size and Lifespan of CCR Management Units

CCR management units range in size from modest to very large, with some impoundments 

covering 1,500 acres or more. To develop cost estimates, this RIA bases the size of the CCR 

management units on the annual tonnage of CCR placed in the unit. Exhibit 3-D summarizes the 

key assumptions regarding CCR management unit dimensions.129 The cost model considers two 

landfill designs; a “combination landfill” that includes some excavation and disposal of 50% of 

CCRs below ground level, and a “pile landfill” at which 95% of CCRs are disposed at or above 

ground level.

In sizing the excavation, this RIA assumes that ash is disposed 300 days per year, with an initial 

unit operating life (capacity) of 40 years for both landfills and surface impoundments. Given that 

the data indicate that landfills and impoundments beyond 40 years of age are continuing to 

operate at some coal-fired electric utility plants, this RIA incorporates these possibilities by 

modeling landfills as vertically expanding after their initial 40 year operational period and 

continuing to operate for an additional 40 years, and models storage impoundments as continuing

 

128 Of the 478 coal-fired electric utility plants, 19 plants direct their CCR solely to beneficial uses.

129 RTI International collected unit area and unit depth information for a number of CCR landfills and CCR surface 

impoundments. See ORCR’s 2009 mail survey to electric utility plants with impoundments; ORCR’s 2009-2012 impoundment 

site inspections; and, OW’s 2010 mail survey to power plants for the Steam Electric Power Generating Effluent Guidelines and 

the sources noted in Section 2.3.1.
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to operate in perpetuity in the baseline.

130 This RIA assumes that utility plants add an additional 

“cell” to a disposal CCR impoundment once it reaches the end of its operating life. This means 

that this RIA effectively assumes that only a certain area (consistent with 40 years of disposal) is 

capped and closed, rather than the entirety of the impoundment, and allows for the possibility 

that impoundments are adjacent or connected to one another. Other factors considered for unit 

size estimates include waste densities, depths of fill below grade, and below grade side slopes.131

This RIA assumes that units have one construction phase (i.e., one large cell or monofill) as a 

simplifying assumption.132

 

130 For the 30 Nov 2005 DPRA report (“Estimation of Costs for Regulating Fossil Fuel Combustion Ash Management at Large 

Electric Utilities Under Part 258,” docket document ID nr. EPA-HQ-RCRA-2006-0796-0469), EPA asked utility industry 

representatives for typical lifespan years of CCR landfills and impoundments. Industry representatives provided a 40-year 

estimate for both. This estimate is supported by data provided by industry in the 1995 EPRI Co-management Survey. In the EPRI 

Survey, data describing six CCR landfills noted the year the unit was opened and the estimated date of closure. The average life 

expectancy is 34 years and the median life expectancy is 38 years. Similarly, data provided for 18 CCR impoundments indicate 

an average life expectancy of 45 years and a median life expectancy of 46 years. In addition, RTI International collected data on 

the ages of impoundment and landfills still operating; the results are as follows:

Surface impoundment age data indicates approximately 38% of the impoundments exceed 40 years of age currently (513 CCR 

surface impoundments with age data):

 Mean age = 37 years

 Median age = 37 years

 75th percentile age = 45 years

 80th percentile range = 47 years

 90th percentile age = 54 years

 95th percentile age = 59 years

 99th percentile age = 65 years

 Maximum age = 67 years

Landfill age data indicates approximately 7% of the landfills exceed 40 years of age currently (255 CCR landfills with age data):

 Mean age = 26 years

 Median age = 28 years

 90th percentile age = 38 years

 95th percentile age = 44 years

 99th percentile age = 60 years

 Maximum age = 63 years

EPA engineering judgment indicates that there is no operational reason not to continue to use storage impoundments in perpetuity 

so long as they are regularly dredged. (Confirmed by communication with engineering experts at GZA Geoenvironmental, Inc.)

131 This RIA assumes the following: a compacted dry waste density of 1,190 kg/m3

; in-situ wet waste density of 900 kg/m3; a 

compaction factor of 1.25 to convert bulk waste volumes to compacted waste volumes; depth of fill below grade at 15 feet for 

combination fill landfills and surface impoundments; depth of fill below grade at 1 foot for “pile fill” landfills; and, a below 

grade side slope of 3:1 (rise:run).

132 Technically, the landfill controls (as opposed to a surface impoundment) likely are constructed in several phases (e.g., one cell 

per year, three years, five years, etc.).
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Exhibit 3-D

Key Assumptions for Sizing of CCR Management Units

Dimension Category

Landfills Surface 

Combination Landfill Pile Landfill Impoundments

Capacity excavated below grade 50% 5% 100%

Deptha,b 15 1 15

Height and depth combined 30 30 N/A

Per-unit surface area (acres)c,d

10,000 tons per year 12 16 30

50,000 tons per year 55 78 140

200,000 tons per year 212 310 500

500,000 tons per year 525 773 1,400

2,000,000 tons per year 2,080 3,092 5,500

a Depth assumed in this RIA is roughly consistent with median depth of a review of 110 landfills (minimum depth of 0.03 feet, median 

depth of 35 feet, mean depth of 121 feet, and maximum depth of 7,574 feet). 

b Reflects median unit depth consistent with review of 520 surface impoundments (minimum depth of 0.05 feet, median depth of 15 feet, 

average depth of 24 feet, and maximum depth of 546 feet).

c Consistent with range of areas identified in review of unit area information for 116 landfills (minimum area of 2.5 acres, median area of 71 

acres, mean area of 121 acres, and maximum area of 900 acres).

d Consistent with range of areas identified in review of unit area information for 646 surface impoundments (minimum area of 0.01 acres, 

median area of 18 acres, mean area of 52 acres, and maximum area of 2,400 acres).

Sources: ORCR’s 2009 mail survey to electric utility plants with impoundments; ORCR’s 2009-2012 impoundment site inspections; and, 

EPA-OW’s 2010 mail survey to power plants for the Steam Electric Power Generating Effluent Guidelines.

This RIA assumes that after an initial 40-year lifespan, landfills (either pile landfills or 

combination fill landfills) are vertically expanded to provide an additional 40 years of disposal 

capacity. The costs of base management of a vertically-expanded landfill differ somewhat, but 

not substantially, from the costs of base management of either a pile landfill or a combination fill 

landfill prior to vertical expansion; this RIA assumes that incremental costs associated with CCR 

pollution controls at a given landfill remain identical before and after vertical expansion. After 

40 years of either pile or combination fill landfilling and a subsequent 40 years of verticallyexpanded landfilling, this RIA assumes that landfills reach capacity and the end of their 

operating life and close; new landfills constructed in their place would undergo the same total 

operating life of 80 years (40 as either pile or combination fill, followed by 40 as a verticallyexpanded landfill).

Furthermore, while CCR disposal impoundments are assumed to operate for 40 years before 

reaching capacity and closing, CCR storage impoundments are assumed to operate indefinitely 

as they are routinely dredged out and do not reach capacity.133

3.2.2 Cost Estimation Framework

This RIA contains three types of inputs used to estimate baseline costs: data-based estimates, 

assumption-based estimates, and scenario-based estimates. This section presents the three types 

of inputs in order of decreasing expected accuracy.

 

133 EPA’s experts from the Office of Water confirmed that storage impoundments would likely to be repurposed, rather than 

closed, and that even wet-dry conversion may focus on a particular type of ash, e.g., fly ash, and result in other types of ash, e.g., 

bottom ash, remaining wet-managed.
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3.2.2.1 Data-Based Cost Estimates

Data-based estimates involve the use of relatively robust and recent data inputs (2009 or newer) 

in a cost estimation model that calculates costs for CCR pollution controls associated with coalfired electric utility plants and their CCR units. EPA first developed the cost estimation model in 

1988 to support EPA’s 1991 criteria for municipal solid waste (MSW) RCRA Subtitle D 

landfills, and EPA’s 1999 proposed cement kiln dust landfill rule requirements.134 The cost 

model consists of two distinct software components, summarized below. Appendix D provides 

additional details about the model.

Unit cost component. This component consists of a Fortran computer-programmed cost model 

originally developed by EPA in 1988 for a different rulemaking. This model specifies the various 

steps and physical units (e.g., square footage sizes and associated quantities of labor, equipment, 

and materials for each specified size) involved in designing, constructing, operating, and closing 

a landfill or surface impoundment. The model then combines these steps and physical 

components with input data on their associated prices, costs, or fees to estimate model outputs 

(e.g., unit-level CCR pollution control costs).135 The model further breaks down output by 

separately calculating the capital costs and annual operations and maintenance (O&M) costs 

accruing to each specified unit size and type.

This RIA used the cost model to generate individual cost estimates for a set of five differentlysized CCR landfills and CCR surface impoundments with varying types of CCR pollution 

controls across the affected universe of 478 electric utility plants:

 10,000 tons CCR disposed per year;

 50,000 tons per year;

 

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

prepared for EPA’s Office of Solid Waste by DPRA Inc, Sept 1988, 129 pages and 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 seven 

publications spanning 1988 to 1998:

 Draft Regulatory Impact Analysis for Proposed Revisions to Subtitle D Criteria for Municipal Solid Waste Landfills, 

prepared for U.S. EPA Office of Solid Waste by Temple, Barker and Sloane, Inc., ICF Incorporated, Pope-Reid Associates 

(now DPRA Inc.) and American Management Systems, Inc., 05 Aug 1988 (this document includes about a 4-page summary 

of the cost model).

 40 CFR Parts 257 and 258 Solid Waste Disposal Facility Criteria: Rule, Federal Register, Vol.53, No.168, pp.33314-33422, 

30 Aug 1988.

 Regulatory Impact Analysis for the Final Criteria for Municipal Solid Waste Landfills, prepared for U.S. EPA Office of 

Solid Waste by Temple, Barker and Sloane/Clayton Environmental Consultants, ICF Inc., DPRA Inc., and American 

Management Systems, Inc., Dec 1990. (this document includes about a 4-page summary of the cost model).

 Addendum to the Regulatory Impact Analysis for the Final Criteria for Municipal Solid Waste Landfills, prepared for U.S. 

EPA, Office of Solid Waste by Temple, Barker and Sloane/Clayton Environmental Consultants and ICF Inc., August 1991.

 Revised Criteria for Municipal Solid Waste Landfills, Federal Register Volume 56, pp. 50978, 09 Oct 1991.

 Technical Background Document: Compliance Cost Estimated for the Proposed Land Management Regulation of Cement 

Kiln Dust, prepared for the U.S. EPA, Office of Solid Waste by DPRA Inc., 10 April 1998.

 40 CFR Parts 259, 261, 266, and 270 Standards for the Management of Cement Kiln Dust; Proposed Rule, Federal Register 

Vol.64, No.161, pp. 45632-45697, 20 Aug 1999.

135 Unit prices, costs, or fees used as input data include a wide range of items, such as clearing, excavation, labor, bottom liner 

materials, cover materials, and the per-acre cost of land.
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 200,000 tons per year;

 500,000 tons per year; and

 2,000,000 tons per year.

For these five size category cost model runs, EPA calibrated the model to assume that each CCR 

landfill or surface impoundment operates 300 days per year, consistent with information in the 

2005 DOE EIA-767 database on boiler operation. Generally, unit size is the primary determinant 

of overall cost; however, landfills and surface impoundments exhibit increasing returns to scale, 

in that larger units accrue lower per-ton CCR management costs.

The input data for this model are updated as new estimates of labor input costs, materials costs, 

and certain indirect costs (i.e., engineering, testing, quality assurance, etc.) become available. 

While changes in these input costs modify the outputs calculated by the model, design-level 

decisions, such as unit dimensions, waste characteristics, containment and cover designs, and 

groundwater monitoring options function as the primary drivers of costs associated with a given 

CCR pollution control. Although the relationships between each design-level decision and the 

calculated unit-level costs are complex and not necessarily linear, they exhibit stability in that the 

relative importance of individual design-level decisions and input costs does not appear to 

change over time. Furthermore, model runs for this RIA constrained many potential user inputs 

to focus on design-level variables impacted by the CCR rule, removing the model’s sensitivity to 

design specifications and pollution controls not pertinent to requirements discussed in this RIA.

This RIA used the individual cost estimates generated by these model runs as inputs to calculate 

a set of unique landfill and impoundment cost equations based on unit size and combination of 

pollution controls, such that a different cost estimate could be assigned to each of the 478 electric 

utility plants according to each plant’s unique annual CCR disposal tonnage. The landfill cost 

equations are presented in Appendix D, Exhibits H-1 and H-2. The surface impoundment cost 

equations are presented in Appendix D, Exhibit H-3.

This RIA estimates costs associated with two CCR management unit specifications not covered 

by the Fortran model runs: vertically-expanded landfills and storage impoundments. For 

vertically-expanded landfills, CCR pollution control costs for landfills from the Fortran model 

runs were still used; however, the base construction, management, and disposal costs associated 

with vertically-expanded landfills were obtained by consultation with engineering experts.136 For 

storage impoundments, CCR pollution control costs for CCR disposal impoundments from the 

Fortran model runs were still used; however, the base construction, management, dredging, and 

 

136 Engineers from GZA Geoenvironmental provided inputs that reflected expert judgment and institutional knowledge based on 

the company’s extensive experience with the electric power industry. For CCR pollution control costs applied at verticallyexpanded landfills, the cost estimation methodology applied an average of the individual incremental pollution control costs at 

pile landfills and combination fill (dug) landfills for a given pollution control. This methodology was undertaken in order to not 

underestimate costs given that elsewhere, the cost estimation algorithm compares costs associated with pile landfills and dug 

landfills and assigns the lower of the two costs to a given existing on-site landfill. If this average were not taken, costs may be

artificially low because, for a given pollution control with a higher incremental cost for that pollution control, taking the lower 

(non-average) of the available incremental pollution control costs could pair a pollution control cost for a pile landfill with the 

implementation of the pollution control at a vertically-expanded dug landfill.
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dewatering costs associated with CCR storage impoundments were obtained by consultation 

with engineering experts.137

Plant-by-plant and aggregate cost component. This component consists of STATA-based cost 

calculations to estimate unique costs for each coal-fired electric utility plant based on baseline 

(i.e., current) CCR pollution control requirements, as well as pollution control requirements 

under the CCR final CCR rule. The STATA model contains a database populated with plant-byplant data including plant location, known disposal and beneficial use practices, known or 

estimated baseline pollution controls on CCR management units, annual CCR tonnages, and 

known or estimated CCR landfill and impoundment future closure years. This database file also 

contains the cost equations generated by the Fortran cost model for the various unit-level 

pollution controls (e.g., groundwater monitoring) and for off-site landfill disposal costs, as well 

as any other cost estimates and inputs necessary to model CCR management unit-level behavior 

at each of the CCR management units across 478 coal-fired electric utility plants. 

Consistent with the analytic framework outlined in Chapter 2 of this RIA, the STATA model 

estimates CCR pollution control costs for both the baseline (i.e., pre-rule) and post-rule over a 

100-year future period of analysis (i.e., 2015 to 2114). The plant-by-plant estimated costs can 

then be aggregated and presented on an average annualized or present value basis, as well as 

based on alternative discount rates.

3.2.2.2 Assumption-Based Estimates

In some cases, this RIA bases cost estimates on relatively limited data, older data (e.g., older 

than 2005), meta-analysis transfer of results from other studies, data from case studies, or 

professional judgment. This RIA factors such estimates into cost calculations only when more 

accurate or recent data were not available, or as simplifying assumptions given the absence of 

detailed information regarding entities or units affected by the CCR rule. 

3.2.2.3 Scenario-Based Estimates

In the absence of both detailed recent data and case studies allowing for direct estimation of 

costs, this RIA applies scenario-based estimates. EPA typically defines scenarios as qualitative 

projections of possible future conditions (i.e., a futures analysis method) to support bounding 

analyses that will examine the relative importance of key variables. 

Scenario-based estimates and bounding analyses also allow EPA to examine key drivers of 

change, including social, technological, economic, and institutional drivers. Scenario-based 

estimates do not strive to predict the future with absolutely certainty, but to explore uncertainties, 

possible consequences, and possible outcomes.138 This RIA uses scenario-based estimates, where 

 

137 Engineers from GZA Geoenvironmental provided inputs that reflected expert judgment and institutional knowledge based on 

the company’s extensive experience with the electric power industry. In cases where disposal impoundments convert to storage 

impoundments, the cost estimation model does not apply the full cost associated with constructing and managing the storage 

impoundment, as this RIA assumes that many upfront costs associated with impoundment construction are unnecessary for 

impoundment conversion from disposal to storage (e.g., siting, permitting, initial excavation, etc.).

138 “EPA Office of Science Policy, “Shaping Our Environmental Future: Foresight in the Office of Research and Development,” 

report nr. EPA 600/R-06/150, 2006 at: http://www.epa.gov/osp/futures/FuturesHandbook.pdf.
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appropriate, to present bounding analyses where a lack of other information prevents more 

accurate estimation methods.

3.2.3 Additional Assumptions for Calculating Baseline Costs

In addition to cost estimate inputs, this RIA relies on a number of other projections and 

assumptions in calculating baseline costs. These include:

 Before-tax costs. This RIA estimates disposal costs on a before-tax basis to 

approximate the total economic cost (i.e., real resource allocation for the economy 

as a whole). In contrast, an after-tax estimate approximates a narrower financial 

cost to the electric utility industry, because these costs reflect tax deductions for 

business expenses and the depreciation of capital expenditures for CCR pollution 

control equipment.

 Beneficial use. If reported in the baseline by any particular plant, this RIA 

assumes a constant beneficial use by that plant in the future under the baseline 

projection over the 100-year period of analysis for the probabilistic cost analaysis.

However, the analysis of beneficial use, presented in Chapter 5 of this RIA,

evaluates potential changes to beneficial use under both the baseline and final 

CCR rule scenarios.

 Off-site disposal. If reported in the baseline by any particular plant, this RIA 

assumes that off-site disposal continues in the future by that plant. Furthermore, 

the STATA model calculates that some utility plants will switch some or all CCR 

management from on-site units to off-site units after existing on-site units close. 

Cost modeling done for this RIA estimates off-site disposal landfill costs under 

the baseline as well as under the CCR final rule; truck operating costs were 

estimated separately outside of the models. See Appendix I for the list of statespecific off-site commercial landfill prices used in the cost analysis.

 Existing CCR management unit closure. This RIA assumes one set of years for 

the opening and closing of CCR units for each utility plant. EPA used three data 

sources to determine the age of each landfill and impoundment, including 

research by RTI International, the 1995 Electric Power Research Institute (EPRI) 

Co-management Survey, and the DOE EIA-860 database. If no CCR unit or 

power plant boiler installation year data were available across any of these 

sources, this RIA assumes an installation year of 1991, as 20 years of age is the 

midpoint of the average 40-year lifespan of the unit.139

 

139 Specifically, RTI International collected data on the age of each unit from the surveys listed earlier in this chapter. These data 

were used to determine age, if available, because they use recent data sources. If unit age data was not available from these 

surveys, data for initial year of operation according to the 1995 EPRI Co-management Survey were used. If neither of these 

sources had unit age data, the earliest reported boiler installation year reported in the DOE EIA-860 database is used for the unit’s 

age. Note that this methodology was first applied to the universe of known impoundments identified in 2009 and analyzed in 

2011; correspondingly, for the CCR management units with no age data available from any source, the assumed age was not 

updated in this analysis and these units are assumed to be 23 years of age as of 2014.
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In addition, as discussed in Section 2.4, baseline costs incorporate the following methods:

 2013 state-adjusted price levels. This RIA normalizes costs to 2013 dollars and 

applies state factors to account for the variability between states in site work and 

landscape construction costs.140

 100-year period of analysis. This RIA applies a 100-year future time horizon of 

2015 to 2114 to capture long-term patterns of cost, risk, and exposure. 

 Alternate discount rates. As its base case thisThis RIA applies both a 73% and a 

37% discount rate for calculating both net present value costs and average 

annualized costs, consistent with OMB and EPA recommendationsCircular A-4

(see Section 2.4.2).141

 CCR generation forecast. Based onAs indicated in Section 2.4.4, this RIA uses

the base case“Reference Case” forecast of future annual 2015-2040 coal 

consumption for electricity generation published in the EIA’s 2014 by EIAAnnual 

Energy Outlook (AEO) to formulate a numerical multiplier index for use in this 

RIA as a proxy indicator for future annual CCR generation tonnage. Using this 

numerical index, this RIA projects baseline annual CCR generation tonnages to 

increase by 9.2% from 2012 through 2040 and then remain constant for the 

remainder of the 100-year period of analysis (2041 to 2114).142 This projection 

reflects EIA’s forecasted future annual growth in electricity generation by coalfired electric utility plants, which stands as a proxy in this RIA for future annual 

growth in the annual tonnage of CCR generation needing disposal.

3.2.4 Baseline Cost Estimation Modeling

The STATA-based cost estimation for all 478 electric utility plants uses a set of decision logic 

rules for determining future plant behavior with regard to CCR management and disposal. This 

section provides a brief explanation of the logic used to estimate baseline unit-level costs.

3.2.4.1 Landfills

All active CCR landfills are mapped to a set of Fortran cost equations that represent specific 

CCR management and disposal costs for the combination of CCR pollution controls present at 

each landfill, incorporating the state regulatory baseline information presented earlier in this 

chapter. These cost equations are then adjusted to reflect state-specific costs via state-specific 

cost factors obtained from the Engineering News Record Construction Cost Index for each state.

 

140 This RIA normalizes costs to 2013 dollars using inflation factors developed by:

 Engineering News-Record (ENR) Construction Cost Index, and

 State-by-state specific cost adjustment factors applied to each plant’s on-site landfill or impoundment cost estimate. See 

Appendix J for the list of state cost adjustment factors. State cost adjustment factors are derived from the Means Building 

Construction Costs Year 2010 city factors. To derive a statewide average, all the cities for each state were averaged together.

141 See OMB Circular A-4 (page 33): http://www.whitehouse.gov/omb/circulars_a004_a-4/, 1992 OMB Circular A-94 (page 8): 

http://www.whitehouse.gov/omb/circulars_a094/, and EPA Guidelines for Preparing Economic Analyses (page 6-18).

142 EIA’s April 2014 Annual Energy Outlook base case projections are available at http://www.eia.gov/forecasts/aeo/. 
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The STATA model maps two equations to each landfill: one assumes that the landfill is a 

combination fill (“dug”) landfill, and another assumes that the landfill is a pile landfill. The 

model projects costs associated with each of these options for the suite of CCR pollution controls 

required at the landfill (reflecting the state regulatory baseline), and assigns the lower-cost 

option, consistent with the assumption that utility plants use the least-costly disposal method 

available in the baseline.143

Each landfill thus incurs a disposal cost in each year based on the state-adjusted Fortran cost 

equation chosen, with year-to-year costs varying due to future annual changes in CCR tonnage 

disposed in a given year based on(which this RIA estimates in relation to the EIA AEO 2014 

projectionsprojection of future coal consumption for CCRelectricity generation in that year.). For 

example, AEO 2014 projects that coal consumption for electricity generation will be 2.434% 

higher in tons in 2017 than in 2016; correspondingly, costs for a given landfill will be higher in 

2017 than in 2016, though this increase will be less than 2.434% because the Fortran cost 

equations include certain fixed costs for CCR management and disposal that do not scale with 

the CCR tonnage volume disposed.

This process continues, with a cost equation-determined and state-adjusted cost based partially 

on CCR generation and disposal projections applied in each year, until the landfill turns 40 years 

of age. At this point, the model assumes that the landfill undergoes vertical expansion, and a 

different cost equation is assigned. The vertical expansion cost equation adapts the previous 

Fortran-based cost equations and maintains its state-adjusted nature. This vertical expansion cost 

equation is then applied for the next 40 years, until the landfill turns 80 years of age, at which 

point it is assumed to close and incur closure costs. As part of the cost estimation, the STATA 

model assigns annualized capping and post-closure monitoring costs from the Fortran model 

over each year of the 40-year period following landfill closure, if capping and/or post-closure 

monitoring are required by the state regulatory baseline. 

At closure, the model compares a number of distinct CCR management and disposal options on a 

going-forward basis:

 CCR management and disposal in a new on-site dug landfill for 40 years, which 

will be vertically-expanded at age 40 for another 40 years;

 CCR management and disposal in a new on-site pile landfill for 40 years, which 

will be vertically-expanded at age 40 for another 40 years; and

 Off-site disposal (assumed to be in off-site commercial industrial landfills).

144

 

143 Due to a lack of information regarding the landfill type (dug versus pile) for existing landfills as well as new landfills, the 

STATA model chooses the least-costly method across the two landfill types for all existing landfills as well as for any new 

landfills that are constructed in out years.

144 Initial modeling of CCR management and disposal associated with landfills indicated that plants closing landfills would never 

opt to open a new surface impoundment to manage CCR previously disposed of in a landfill. Correspondingly, the final cost 

estimation model does not consider this variant when determining going-forward CCR management options for closing landfills.

The model does not consider the option to manage the CCR through beneficial use. Beneficial use is considered separately in 

Chapter 5.
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The cost equations for the first two choices listed above reflect similar Fortran cost equations. 

However, since the initial, existing landfill has closed, the applicable state regulatory baseline for 

these units reflects requirements for new units, rather than existing units. Most states require 

more stringent controls on new landfills than on existing landfills; as a result, disposal costs for 

plants in these states increase after the existing landfill closes and a new landfill opens in its 

place. Off-site disposal costs are driven by state-specific cost equations reflecting tipping fees 

and transport costs.

The STATA model projects these three cost scenarios forward, compares them, and selects the 

lowest-cost option for each plant. The cost equation associated with the chosen option is then 

applied for the remainder of the 100-year period of analysis.145

3.2.4.2 Disposal Impoundments

Disposal and storage impoundments are identified by the STATA model as follows:

 At a plant where EIA reportsdata indicate wet CCR disposal with at least one onsite, existing surface impoundment, the model assigns the largest surface 

impoundment (according to capacity) as a disposal impoundment and maps all 

wet disposal tonnage associated with the plant to that impoundment (n=142).

 All other impoundments are assumed to be storage impoundments (n=593), 

including:

o All impoundments at plants where EIA reportsdata indicate zero wet CCR

disposal (n=384); 

o All impoundments that are not the largest impoundment at a plant where 

EIA reportsdata indicate wet CCR disposal (n=209).

The STATA model maps all impoundments identified as CCR disposal impoundments to a set of 

Fortran cost equations that represent specific CCR management and disposal costs for the 

combination of CCR pollution controls present at each impoundment, reflecting baseline state 

regulatory information, adjusted to reflect state-specific costs.

 

145 The STATA model is cognizant of landfill age, even as choices are made and different cost equations are applied. 

Specifically, landfills currently above 40 years of age will begin in 2015 as vertically-expanded landfills with all attendant cost 

equations within the model. Furthermore, if a landfill closes, chooses a new landfill, and that new landfill is vertically expanded 

and closes before the period of analysis ends, the subsequent costs applied will be associated with a pre-vertical expansion new 

landfill. Note, however, that the STATA model only makes a choice once; after an initial landfill closure. Moreover, the STATA 

model assumes all subsequent choices will be the same, consistent with the fact that EIA AEO projections doprojection of future 

coal consumption for electricity generation does not project changes in CCR generation and disposal past 2040, and as such any 

option determined to be the lowest-cost option past 2040 would remain the lowest-cost option in any subsequent year. Landfill 

capping and post-closure monitoring costs are applied in the 40-year period following landfill closure only for existing landfills; 

these costs are assumed to be pre-paid, and are rolled into the cost equations for new landfills in order to avoid underestimating 

costs, as the 40-year period following closure of a new landfill will fall outside the 100-year period of analysis for nearly all 

landfills in the universe.
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Similar to landfills, each disposal impoundment incurs a baseline operating cost in each year 

based on its mapped state-adjusted Fortran-based cost equation, with year-to-year costs varying 

due to future annual changes in CCR tonnage disposed (based on EIA AEO 2014 projections for 

CCR generation in that year),, combined with fixed costs reflected in the Fortran equations. of 

the cost model for this RIA.

This cost stream continues until the disposal impoundment turns 40 years of age, or the next 

multiple of 40, if it began in 2015 with an age above 40.146 At this point, the model assumes the 

impoundment closes and incurs closure costs. The STATA model assigns annualized capping 

and post-closure monitoring costs from the Fortran model over each year of the 40-year period 

following impoundment closure if capping and/or post-closure monitoring are required by the 

state in the regulatory baseline.

At closure, the model compares a number of distinct CCR management and disposal options on a 

going-forward basis:

 Choice 1: Conversion to a storage impoundment and subsequent disposal of CCR 

in:

o 1A: An off-site landfill (Note: Section 7.1.6 of this RIA presents an 

analysis of recent 2010 capacity data on off-site commercial industrial 

landfills, in comparison to annual CCR tonnages which are simulated in 

this RIA as possibly switching to off-site landfills);

o 1B: An on-site existing landfill at the plant;

o 1C: A new dug landfill built on-site at the plant; or

o 1D: A new pile landfill built on-site at the plant;

 Choice 2: Impoundment closure, wet-dry conversion, and subsequent disposal of 

dry-handled CCR in:

o 2A: An off-site landfill;

o 2B: An on-site existing landfill at the plant;

o 2C: A new dug landfill built on-site at the plant; or

o 2D: A new pile landfill built on-site at the plant;

 

146 This assumption is consistent with the “impoundment” cell assumption reported earlier, and avoids a model situation where 

many impoundments close as soon as the model run begins. As a result of this assumptions, all impoundments in excess of 40 

years of age in 2015 will not close and reach a decision point until they reach 80 years of age.
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 Choice 3: Impoundment closure, wet-dry conversion, and subsequent disposal of 

dry-handled CCR in a new dug pile landfill built on top of the closed disposal 

impoundment; or

 Choice 4: Opening a new on-site disposal impoundment for CCR management 

and disposal.

Each of the above choices reflects a unique set of cost equations:

 Choice 1 includes the capital (one-time) cost of converting a disposal 

impoundment to a storage impoundment, from which waste is then landfilled. The 

model then applies the impoundment-specific, state-adjusted cost equation based 

on the state regulatory baseline for existing surface impoundments, plus the leastcost option among the following:147

o 1A: the state-specific cost equation for off-site disposal;

o 1B: the cost equation associated with disposal of CCR in an existing, onsite landfill at the same plant (this choice is unavailable if the plant does 

not report on-site landfill disposal to EIA, or if the existing landfill has 

closed and shifted to off-site disposal);148

o 1C: the cost equation for disposal of CCR in a new on-site dug landfill at 

the same plant, subject to state regulatory baseline requirements for new 

landfills, and assumed to undergo vertical expansion after 40 years; or

o 1D: the cost equation for disposal of CCR in a new on-site pile landfill, 

subject to the state regulatory baseline requirements for new landfills, and 

assumed to undergo vertical expansion after 40 years.

 Choice 2 includes the cost of closure (annualized capping and post-closure 

monitoring costs applied annually for 40 years after closure) and the cost of wetdry conversion,149 plus the same additional cost equations for 2A through 2D as 

for 1A through 1D above, respectively.

 

147 Costs for conversion from a disposal impoundment to a storage impoundment are assumed by this RIA to be $12.20 per ton of 

dry-handled CCR waste (or $16.13 on a wet-tonnage basis, multiplying by the 1.322 scaling factor), plus $2.98 per ton of dryhandled CCR (or $3.94 on a wet-tonnage basis) for annual dredging costs. Costs associated with broader wet-to-dry conversion 

costs are not factored into this set of equations; these are considered separately. Any incremental CCR pollution control costs 

remain present and continue to incur annual costs after conversion; this RIA assumes CCR pollution control costs are identical 

across disposal impoundments and storage impoundments. This RIA does not apply “base” storage impoundment management 

costs described below to converted disposal impoundments because these base costs annualize construction and siting costs 

which are not necessary for converted units. 

148 Note that in all cases where a disposal impoundment is replaced by a final disposal option that includes dry handling, the wet 

tonnage is converted to dry tonnage by dividing by a factor of 1.322 in order to accurately reflect disposal costs for the two 

management types.

149 Wet-dry conversion costs are discussed later in this chapter and are based on national average estimates for wet-dry 

conversion costs across all plant sizes. Due to specific modeling considerations, this RIA models wet-dry conversion on a 

disposal unit basis rather than on a plant basis, with wet-dry conversion costs heavily driven by the disposal tonnage that will be 
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 Choice 3 includes the cost of wet-dry conversion plus the same additional cost 

equation as in 1D above, though closure costs are not included because the 

capping and post-closure monitoring costs are assumed to be subsumed in the 

construction of the new landfill on top of the impoundment.150

 Choice 4 applies the costs associated with the Fortran-based, state-adjusted cost 

equations for new disposal impoundments according to the state regulatory 

baseline requirements for new impoundments, and includes the cost of closure 

(annualized capping and post-closure monitoring applied annually for 40 years 

after closure) if required by the state regulatory baseline.

The STATA model compares each of these sets of costs on a going-forward basisin any 

subsequent future year and chooses the lowest-cost option. Each plant is assumed to employ the 

chosen option as its form of CCR management and disposal on a going-forward basis. The cost 

equation associated with the chosen option is then applied for the remainder of the 100-year 

period of analysis.151

3.2.4.3 Storage Impoundments

Note: EPA has updated this section of the RIA to reflect data gathered by EPA Office of 

Water to better reflect costs associated with storage impoundments. The text and exhibits 

below do not reflect this update. See Section 9.2.3 in Chapter 9 of this RIA for a description 

of the relevant modifications and updates to this section. 

All impoundments not identified as disposal impoundments according to the algorithm above are 

considered storage impoundments. This RIA assumes that storage impoundments are dredged 

annually to remove solids, and thus are able to operate indefinitely. As a result, storage 

impoundments do not reach “decision points” in the model, nor do their cost equations vary over 

time. Instead, the STATA model assigns each storage impoundment a state-adjusted cost 

equation reflecting baseline state regulatory requirements; these costs are applied every year 

throughout the period of analysis.

The Fortran-based cost equations do not address storage impoundment management or dredging. 

Therefore, this RIA separately estimates the cost of managing a storage impoundment with no 

CCR pollution controls at $57.06 per annual ton of dry CCR waste (i.e., each ton of CCR waste 

that enters and is stored in the impoundment per year), plus an additional dredging cost of $2.98 

 

wet-dry converted. Wet-dry conversion costs are calculated on an annualized basis and applied for 20 years following unit 

closure and conversion based on an assumed capital improvement amortization period of 20 years.

150 This assumption results in Choice 3 always being a lower-cost option relative to Choice 2D, but the STATA model considers 

both choices for completeness.

151 Note that the STATA model only makes a choice once; after an initial impoundment closure and choice, the STATA model 

assumes all subsequent choices will be the same, consistent with the fact that EIA AEO projections doprojection of future coal 

consumption for electricity generation does not project changes in CCR generation and disposal past 2040, and as such any 

option determined be the lowest-cost option past 2040 would remain the lowest-cost option in any subsequent year. 

Impoundment capping and post-closure monitoring costs are applied in the 40-year period following closure only for existing 

impoundments and landfills; these costs are assumed to be pre-paid, and are rolled into the cost equations for new landfills and 

impoundments in order to avoid underestimating costs, as the 40-year period following closure of a new impoundment or landfill 

will fall outside the 100-year period of analysis for nearly all impoundments in the universe.
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per ton of dry CCR waste taken from the impoundment, assuming that dredging occurs 

annually.152 The total estimated management cost is $60.04 per ton of dry CCR waste. This RIA 

assumes that CCR tonnage reported as handled in storage impoundments is wet, and uses a 1.322 

conversion factor from wet-handled tonnage to dry-handled tonnage, which results in base CCR 

storage impoundment costs of approximately $79.37 annually.153 This cost is roughly 20% 

higher on a per-ton basis than the Fortran-based cost equation for base management of a disposal 

impoundment (the Fortran-based equations also include relatively small non-per-ton costs), and 

is consistent with the opinion of engineering experts that storage impoundments are generally 

built to a higher standard than disposal impoundments because they are more actively managed 

and subject to regular access and use.

In addition to assumptions about the base management cost of a storage impoundment, this RIA 

must also assign a “tonnage handled” volume to each storage impoundment. Using EIA data and 

the disposal impoundment/storage impoundment algorithm described earlier in this chapter, this 

RIA was able to map all wet-handled CCR tonnage reported byindicated in the EIA data, to a 

disposal impoundment at a plant reporting wet disposal of CCR. To derive storage 

impoundment costs based on “tonnage handled” estimates, this RIA employs the following 

methodology:

 First, all wet-handled CCR tonnage reported byindicated in the EIA data

associated with a plant is evenly divided across all storage impoundments 

identified at the plant;

 In cases where no wet-handled CCR tonnage was reported byindicated in the EIA

data, this RIA uses the dimensions of a given storage impoundment (if available) 

to calculate a potential storage capacity for the impoundment, or uses average 

dimensions for all impoundments with available dimensions to calculate an 

average potential storage capacity otherwise; and

 For each impoundment, the analysis multiplies either the proportionally-applied 

CCR tonnage mapped to the storage impoundment (i.e., wet CCR tonnage) or the 

potential tonnage capacity (calculated using unit (dimensions) by 25%, to reflect 

the assumption

154 that plants will, at most, manage 25% of wet CCR tonnage

waste stream) initially in storage impoundments; other waste streams will move 

directly to their final disposal.

This 25% scaling factor reflects a key assumption in this RIA’s modeling of costs; it is unlikely 

that plants would “double-manage” all or a majority of its CCR tonnage first in a storage 

impoundment and then in a landfill. Instead, plants are likely to use storage impoundments either 

for a single, smaller CCR stream, or to manage a subset of the solids destined for disposal 

impoundments. Therefore, this RIA uses the 25% scaling factor as an estimate of the high-end 

 

152 Engineers from GZA Geoenvironmental provided inputs that reflected expert judgment and institutional knowledge based on 

the company’s extensive experience with the electric power industry.

153 The 1.322 factor represents the ratio of densities between the two types of CCR (dry versus wet).

154 Source: This 25% assumption was formulated for this RIA by engineers from GZA Geoenvironmental based on expert 

judgment and institutional knowledge from the company’s extensive experience with the electric power industry.
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quantity of CCRs that would be managed in two stages. This is consistent with the ratio of 

bottom ash tonnage to combined fly ash and bottom ash tonnage according to this RIA’s analysis 

of EIA data, or 20.9 million / (20.9 million plus 61.6 million) from Exhibit 2-J.

155

It is possible that plants do not “double-manage” any wet-handled CCR via storage 

impoundments. However, in this case, the storage impoundments identified would not be 

designed “for the accumulation of CCRs” and thus not subject to the final CCR rule; this RIA 

does not make this assumption and thus applies costs to each storage impoundment identified. As 

a sensitivity analysis (see Chapter 7), this RIA also examines alternative scaling assumptions of 

0% and 5% for CCR tonnage in storage impoundments.

This RIA assumes that all CCR pollution control costs are identical for disposal impoundments 

and storage impoundments, such that the incremental costs of implementing a given pollution 

control are the same across the two impoundment types. Correspondingly, the annual cost for a 

storage impoundment in the baseline is the base cost of managing and dredging the storage 

impoundment, calculated as $60.04 x 1.322 times the tonnage or potential tonnage of the 

impoundment, plus the application of the Fortran-based incremental pollution control cost for 

each pollution control at a storage impoundment required by the state regulatory baseline. The 

per-ton components of the Fortran-based cost equations for incremental pollution controls 

similarly use the tonnage or potential tonnage used in the base management cost calculations.

Because, in the baseline, storage impoundments are assumed to exist in perpetuity, the year-toyear costs associated with storage impoundments do not change, except to reflect changes in 

year-to-year CCR generation. Storage impoundments do not incur costs associated with closure 

(capping and post-closure monitoring) in the baseline according to the cost estimation 

methodology used in this RIA.

3.2.4.4 Other Modeling Considerations 

Because each linear cost equation has both a fixed and variable component and thus varies with 

unit tonnage, the choice of future type of new CCR management unit construction also varies by 

unit tonnage. For example, under a certain set of CCR pollution control requirements, pile 

landfills may have lower fixed costs but a higher variable cost coefficient than combination 

landfills. In this case, at low tonnage amounts, pile landfills are cheaper, but as tonnage 

increases, combination landfills become relatively more cost effective.

Typically, the STATA-based calculations reveal that future new CCR landfills are more 

economical to construct than future new CCR impoundments, assuming equivalent waste 

quantities and baseline regulatory requirements. However, another cost associated with landfills 

for some utility plants is the capital cost to convert CCR management from wet to dry if plants 

with existing on-site CCR impoundments wish to switch disposal methods to dry disposal in onor off-site commercial industrial landfills. This cost is modeled as a capitial investment 

“financial hurdle” and in some cases may lead utility plants to continue using impoundments 

 

155 This is consistent with the assumption that, at most, one CCR waste stream would be double-managed.
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even if the unit cost of managing waste in a landfill is lower.156 This modeling adjustment is 

done to ensure that, given uncertainty from the use of national-average wet-dry conversion costs, 

the model does not assign any disposal impoundment to wet-dry convert if the cost difference 

between wet-dry conversion (Choice 2 or 3) is marginal compared to a non-conversion 

management option (Choice 1 or 4). From a functional perspective, when making the 

comparison between choices after reaching a decision point, the STATA-based model uses the 

hurdle cost rather than the wet-dry conversion cost. However, if the model’s calculations indicate 

that despite use of the hurdle rate, wet-dry conversion is the most cost-effective (i.e., lowest cost) 

option, the wet-dry conversion cost, rather than the hurdle rate cost, is applied.

To the extent that states have regulations in place affecting utility plants, the model also applies 

other non-unit level CCR pollution controls (e.g., structural integrity inspections for 

impoundments, corrective action costs) to each unit annually over the 100-year period of 

analysis. Where these costs are substantial enough to change the optimal management strategy 

for a given CCR management unit at a utility plant, these costs factor into the choice modeling 

described above. However, in cases where the costs apply regardless of the decision made (unitlevel corrective action costs), or if costs are nominal and highly unlikely to drive decisions 

except in extreme cases (reporting and recordkeeping costs), these costs are applied subsequently 

and do not factor into the model logic.

In addition to the methodology and algorithms described above, the model applies two key 

functions to ensure that costs are not understated:

 “Financial Hurdle” for wet-dry conversion. As discussed above, the model 

incorporates a financial hurdle in addition to costs for dry disposal for each 

impoundment located at utility plants that operate CCR impoundments. This 

hurdle rate consists of:

157

o Small plants (500 MW or less): $10.4 million

o Medium plants (500 to 1200 MW): $22.8 million

o Large plants (>1200 MW): $40 million

This cost is annualized over 20 years when used in the model’s decision logic, 

though in reality utility plants may amortize the cost of wet-dry conversion over a 

 

156 As simulated in this RIA, the use of capital investment financial hurdles (aka “hurdle rates” or “cutoff rates”) is a common 

business planning and capital investment decision-making practice, for example, as documented in Chapter 20 of “The Capital 

Budgeting Handbook,” edited by Mike Kaufman, Dow Jones-Irwin, 1986. In this reference (page 443), a financial “hurdle rate” 

is defined as “the rate of return that must be generated by a capital spending project for it to be a desirable economic undertaking. 

In theory, this is the point where marginal revenue is just equal to marginal cost.” In this RIA, the dry conversion hurdle rate is 

not applied according to the reference example definition but is applied as an order-of-magnitude cost method which this RIA 

uses to compare to the potential cost of dry converstion to the costs of other alterantive CCR management options, for purpose of 

simulating capital investment decision-making regarding this aspect of the CCR final rule.

157 Source: Estimates are based on EPA Office of Water’s 2010 survey data from electric power plants, based on aggregating 

actual wet-dry conversion costs across a range of facilities with a given nameplate capacity and then dividing by the number of 

facilities within that range. See “Questionnaire for the steam electric power generating effluent guidelines” at

http://water.epa.gov/scitech/wastetech/guide/steam-electric/questionnaire.cfm
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longer period representing the 40-year average operating life of the newlyconstructed unit, or may incur higher or lower costs as they retrofit depending on 

the age, size, and specific technologies and topography of each utility plant and 

impoundment.158 The financial hurdle serves as a proxy for the capital cost of 

wet-dry conversion. It renders the model’s decision logic less sensitive to 

disposal options that are marginally less expensive on a per ton basis, but would 

not justify significant capital outlay. In some cases the proxy cost in the model 

prevents a utility plant from switching from a new impoundment to a disposal 

option with lower costs per ton.

 25-mile average one-way trucking distance to off-site landfill. Because many 

electric utility plants are located closer than 25 miles from the nearest off-site 

landfill, and yet operate impoundments, this assumption attempts to mimic this 

practical reality by ensuring that CCR surface impoundments will not switch to 

off-site disposal where the model calculates surface impoundment disposal costs 

as just above off-site landfill disposal costs. This assumption is critical in creating 

a modeling environment where baseline costs for on-site disposal are not 

substantially higher than baseline costs for off-site disposal; the assumption of 

average one-way trucking distances below 25 miles may result in model runs 

where the main driver of costs is the arrival of decision points allowing plants to 

choose relatively low-cost off-site disposal, rather than having to choose between 

relatively more expensive CCR management and disposal options once existing 

units close and management decisions must be made.

3.2.5 Baseline CCR Pollution Control Cost Estimates

This section presents a summary and discussion of the Fortran-based computer cost calculations 

for the fixed and per-ton estimates of the costs associated with individual CCR pollution controls 

and individual CCR units. This RIA simulates these costs as accruing only to those units located 

in states requiring the specific pollution controls; the baseline cost methodology presented below 

does not uniformly assign baseline costs to each CCR unit potentially affected by the CCR rule.

The cost equations discussed above and presented in Appendix D reflect standardized 

assumptions for the list of CCR pollution controls that enable them to be subtracted in various 

combinations to determine the annual cost equation for each pollution control. While this allows 

Exhibit 3-E below to display the relative per-ton and per-unit (i.e, “constant”) costs associated 

with unit-level pollution controls, the STATA cost estimation model cannot use a similar 

methodology to calculate individual costs associated with a pollution control requirement. 

Because off-site landfill costs vary less with changes to pollution control requirements, they 

remain relatively stable. In contrast, new on-site CCR unit construction costs vary widely 

 

158 For purpose of comparison to this RIA’s 20-year cost annualization assumption and this RIA’s 40-year average operating life 

assumption of newly constructed CCR management units, although not necessarily reflecting equipment physical lifespans, the 

Internal Revenue Service (IRS) publishes a “class life” (in years) for certain types of industrial equipment. The IRS class life 

represents equipment depreciation periods for taxation purposes. Although IRS class lifes may be accelerated relative to physical 

operational lifespans, the IRS class life for (a) asset class 49.11 “Electric, gas, water & steam utility services” is 50 years, and (b) 

asset class 49.13 “Electric utility steam production plant” is 28 years. Averaged together, these values indicate a class life of 39 

years. Source: Page 110 of IRS Publication 946 “How to Depreciate Property,” June 28, 2014.
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depending on unit size and on which pollution controls are required by state regulations for the 

future new unit. As a result, estimating total baseline costs using the methodology in Exhibit 3-

K would yield incorrect results.

When few CCR pollution controls are required, electric utility plants would be expected to opt 

for on-site disposal, but as the pollution control requirements increase, off-site disposal may 

become relatively more cost-effective. As a result, impacts on total costs become an artifact of 

the order in which pollution controls are applied, because it is only the total pollution-control 

cost uniquely estimated for each disposal unit which informs decision logic within the cost 

calculations. In addition, though Exhibit 3-E provides the relative costs of unit-level pollution 

controls as calculated by the Fortran model, it does not serve as a good indicator for total 

baseline costs because it does not factor in the variance in the extent to which individual 

pollution controls are required in the baseline for existing or future new disposal units.

Within Exhibit 3-E, the cost equations for each additional CCR pollution control are added to 

the “no controls” cost equation. “No controls” represents the baseline amortization (at a 7% 

discount rate) of capital costs for constructing CCR management units and associated operational 

equipment (i.e., in-plant equipment for extracting CCR from boilers, CCR storage equipment, 

CCR conveyance equipment such as slurry pipelines for wet CCR, or trucks and mechanical 

conveyor belts for dry CCR, and the disposal units themselves), plus annual expenditures for 

operation, maintenance and replacement/expansion of this equipment over the 40-year operating 

lifespanlifespans.

The remainder of this section presents the assumptions used to develop the cost estimates for 

constructing landfills and impoundments with the referenced CCR pollution controls in the 

Fortran model. In addition, this section presents a discussion regarding costs for plant-level 

pollution controls (i.e., pollution controls not associated with construction of landfills or 

impoundments), which this RIA calculates separately outside of the Fortran model.

Exhibit 3-E

Fortran-Based Baseline CCR Pollution Control Linear Regression Annualized Cost Equations 

(2013$)

Current or 

State Regulated

CCR Pollution 

Control

Subcategory 

Description

Combination Landfill

Linear Annual Cost 

($/year)a

Pile Landfill

Linear Annual Cost 

Equation ($/year)a

Disposal 

Impoundment

Linear Annual Cost 

Equation ($/year)a

Rate 

($/ton)

Constant 

($/yr)

Rate 

($/ton)

Constant 

($/yr)

Rate 

($/ton)

Constant 

($/yr)

No Controls $24.02 $83,476 $6.04 $86,070 $44.90 $68,772

Groundwater Monitoring $0.10 $52,407 $0.12 $60.091 $0.12 $76,362

Bottom Liner

Synthetic/ 

Composite $25.57 $115,129 $38.00 $33,464 $50.85 $161,674

Clay $20.47 $84,399 $30.41 $17,329 $40.80 $131,071

Leachate Collection/ Detection System $6.78 $53,374 $10.07 $32,592 $11.24 $70,410

Fugitive Dust Controls $0.27 $209 $0.27 $224 N/Eb N/Eb

Run-on/Run-off Controls $0.06 $7,296 $0.09 $9,315 N/Eb N/Eb

Water Table Not Estimated Not Estimated Not Estimated
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Exhibit 3-E

Fortran-Based Baseline CCR Pollution Control Linear Regression Annualized Cost Equations 

(2013$)

Current or 

State Regulated

CCR Pollution 

Control

Subcategory 

Description

Combination Landfill

Linear Annual Cost 

($/year)a

Pile Landfill

Linear Annual Cost 

Equation ($/year)a

Disposal 

Impoundment

Linear Annual Cost 

Equation ($/year)a

Rate 

($/ton)

Constant 

($/yr)

Rate 

($/ton)

Constant 

($/yr)

Rate 

($/ton)

Constant 

($/yr)

Site 

Restrictionsc

Floodplains Not Estimated Not Estimated Not Estimated

Wetlands Not Estimated Not Estimated Not Estimated

Fault Areas Off-site Landfill Off-site Landfill Off-site Landfill

Seismic Zone Off-site Landfill Off-site Landfill Off-site Landfill

Karst Areas Off-site Landfill Off-site Landfill Off-site Landfill

Capd

Synthetic $1.10 $5,407 $1.63 $2,274 $2.18 $7,655

Clay $1.80 $8,448 $2.69 $3,404 $3.60 $12,784

Soil $0.78 $4,167 $1.16 $1,871 $1.55 $6,371

Post Closure Monitoringe

$0.01 $2,944 $0.01 $3,386 $0.01 $4,047

a Calculated as: Rate x (DRY tons CCR/year) + Constant

b These costs are not estimated by the Fortran-based model. Estimates for these costs are obtained from other sources.

c Only affects new unit construction. New units located in significant fault, seismic zone, and karst areas must use off-site disposal.

d Annual costs reflect discounting back 40 years from time of expense to present value before annualizing over 40-year life of unit.

e Annual costs reflect discounting the 30-year post-closure period of costs back 40 years to present value before annualizing over 

40-year life of unit.

In addition to the costs applied in Exhibit 3-E, the cost estimation model includes costs 

associated with vertically-expanded landfills and storage impoundments. For vertically-expanded 

landfills, the base “no controls” cost is a rate cost of $10.12 (2013$), while individual 

incremental CCR pollution control costs remain unchanged from their pre-vertical expansion 

combination fill and/or pile variants.159 To avoid underestimating costs, this RIA assumes that a 

vertically-expanded landfill incurs a cost of $10.12 per ton, and an additional cost for each 

pollution control equal to the average incremental cost of that CCR pollution control across 

combination fill landfills and pile landfills (e.g., the average annual dust control cost for a 

vertically-expanded landfill is $0.27 as the rate and $217 as the constant, where $217 is equal to 

$209 plus $224 from Exhibit 3-E divided by two). This RIA does not take the lower-cost 

incremental pollution control cost as this may result in cases where a CCR pollution control cost 

associated with a combination fill landfill is assigned to a pile landfill that has been vertically 

expanded.

Storage impoundments are not assumed to permanently contain CCRs, and as a result, this RIA 

does not assign any tonnage to these CCR management units. Rather, the per-ton costs for 

storage impoundments are estimated at $79.37 and the tonnage assumed to be temporarily 

handled in these CCR storage impoundments is assigned through the process described in 

Section 3.2.4 above. 

 

159 This RIA does not apply any constant cost for vertically-expanded landfills; the constant cost represents certain fixed costs 

associated with landfills that do not vary with disposal tonnage such as permitting and land acquisition; these costs do not apply 

to landfill vertical expansions. 
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3.2.5.1 Baseline Groundwater Monitoring Cost Estimates

To estimate groundwater monitoring costs, this RIA uses the Remedial Action Cost Engineering 

and Requirements (RACER) cost estimating software (2002) with costs based on the R.S. 

Means, Environmental Cost Handling Options and Solutions (ECHOS), Environmental 

Remediation Cost Data (2002). These costs assume:

 Groundwater monitoring requirements are the same for both landfills and 

impoundments;

 Monitoring occurs at the unit boundary;160

 Monitoring includes a minimum of two down-gradient wells for the first 800 feet 

of length along two sides of the unit (which is assumed to be square), and 

additional wells spaced every 400 feet, with one additional up-gradient well;161

 Monitoring addresses chemical indicators and metals;162 and

 Costs reflect semi-annual sampling only.163,164

3.2.5.2 Baseline Bottom Liner Cost Estimates

This RIA assumes the same baseline bottom liner requirements for both new CCR landfills and 

new CCR impoundments, reflecting state requirements and existing technology. Where state 

regulations require composite liners in the baseline, this RIA calculates the costs associated with 

a two-foot, compacted, clay-synthetic liner (composite linter), representing a relatively stringent 

liner design. In addition, this RIA also calculates costs associated with less-stringent liner 

 

160 Unit boundary point-of-compliance monitoring complies with the “within 150 meter point-of-compliance” criterion. Plants 

monitoring at the unit boundary will incur no additional costs under the within 150 meter placement criteria.

161 EPA’s March 1985 “Ground Water Technical Enforcement Guidance” Document (pages 2-8 to 2-16) recommends a 

maximum of 150 feet of spacing between down-gradient wells. EPA’s December 1980 SW-611 “Procedures Manual for 

Groundwater Monitoring at Solid Waste Disposal Facilities” (pages 40 to 43) recommends a maximum of 250 feet spacing 

between down-gradient wells. Assuming the technical documents are the most stringent and the state regulation minimums are 

the least stringent, a middle ground within the range is anticipated and used in the cost estimates. This RIA does not evaluate the 

cost differences between the upper and lower bounds of well spacing.

162 These cost estimates represent a reasonable “likely-case” scenario between monitoring for indicators only and RCRA 40 CFR 

261 Appendix VIII constituent monitoring. Monitoring for chemical indicators includes monitoring based on EPA’s 1999 cement 

kiln dust proposed rule parameters (i.e., pH, conductivity, total dissolved solids, potassium, chloride, sodium, and sulfate) as a 

cost proxy. Monitoring for metals includes those metals with primary and secondary Maximum Contaminant Levels (MCLs) 

(i.e., Al, Cu, Fe, Mn, Ag, Zn, Sb, As, Ba, Be, Cd, Cr, Pb, Hg, Se, Tl).

163 This is analogous to EPA’s 1999 cement kiln dust proposed rule and to many current state regulations, even if some states 

require a quarterly or annual basis.

164 EPA calculates an average annual per-plant cost estimate of groundwater monitoring by dividing the average annual cost 

estimate displayed in Row 1 of Exhibit 3-O by the count of CCR management units at electric utility plants that conduct that 

activity under state government requirements. This cost equals $46,700. In comparison, EPA’s (2008) Information Collection 

Request (ICR) No. 0959.13 “Ground-Water Monitoring Requirements” (renewal) for the RCRA Subtitle C 40 CFR 264.92 and 

265.92 TSDF groundwater protection standard estimates an annual per-plant cost of $28,130. The $46,700 cost for groundwater 

monitoring calculated by EPA is 55% larger when accounting for inflation and more appropriate to this RIA because it reflects 

groundwater monitoring for CCR management units, which require more wells owing to their larger sizes relative to most other 

types of industrial waste disposal units.
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designs, including two-foot compacted clay liners, single-synthetic liners, and two-foot 

compacted ash liners. This RIA assigns liner costs to existing and newly-constructed units based 

on the specific state regulatory requirements for liners affecting those units.

3.2.5.3 Baseline Leachate Collection System Cost Estimates

This RIA assumes that CCR landfills and impoundments have leachate collection and leachate 

detection systems, respectively.165 Cost estimates for leachate collection include the costs for 

perforated pipes spaced approximately 300 feet apart along the base of the units, a wet well for 

leachate collection, and off-site treatment of leachate via truck shipping. Finally, this RIA 

assumes that on average landfill leachate collection systems collect three inches of leachate per 

year. This RIA assigns leachate collection costs to existing and newly-constructed units based on 

the specific state regulatory requirements for leachate collection affecting those units.

3.2.5.4 Baseline Fugitive CCR Dust Control Cost Estimates

In general, baseline fugitive dust controls for CCR landfills during their operating life include 

CCR compaction equipment, water trucks for spraying CCR during compaction and for spraying 

unpaved landfill roads, and covers for trucks. This RIA assumes that all landfill operators 

compact their ash to maximize available capacity, and spray unpaved roads. Therefore, the cost 

of this CCR pollution control is limited to placing covers on trucks transporting CCR. While the 

following sections provide additional details on RIA assumptions regarding baseline dust control 

cost estimates, see Appendix K for specific derivations of the estimates of dust control costs in 

this RIA. This RIA assigns fugitive dust control costs to existing and newly-constructed landfills 

based on the specific state regulatory requirements for dust controls affecting those landfills. 

Compaction equipment. This RIA assumes that CCR is compacted in landfills by self-propelled 

rollers involving four passes made by the roller in six-inch lifts, compacting approximately 1,300 

cubic yards of CCR per day. This RIA assumes an operating life of purchased compaction 

equipment of five years. Formulas for the number of rollers required are located in Appendix K.

The cost of a roller is assumed to be $75,000 in 1995 dollars, then inflated to 2013 dollars. This 

RIA assumes that plants incur annual costs for equipment operation ($0.63 per cubic yard in 

1995 dollars, then inflated to 2013 dollars) and maintenance costs are assumed to be 5% of 

capital costs. Formulas for annual compaction costs are located in Appendix K.

Water truck for compaction. This RIA assumes that CCR is wetted in landfills by water trucks to 

facilitate compaction and to control dust. Furthermore, this RIA assumes that plants currently use 

water trucks for 50% of the operational day to control dust on roads (see below, estimated 

separately), as the same water trucks are used for roads and landfills at a given plant, and an 

existing water truck would be available to facilitate compaction for half of the operational day. 

This RIA also assumes that additional water trucks are necessary to facilitate compaction for 

large plants. The costs of tarps, tarp mechanics, and installation of these mechanisms, as well as 

 

165 This RIA does not assume any leachate collection from beneath impoundment liners. However, for purposes of consistency 

and parallelism, this requirement is generally referred to as the “leachate collection system” requirement for both landfills and 

surface impoundments.
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the life of each tarp were estimated by ICF in “Cost Functions for Alternative CKD Control 

Technologies” (Draft), July 19, 1996. This RIA assumes that a water truck will be necessary for 

compaction for 50% of the time required by the compaction equipment. Formulas for total water 

truck time for compaction are located in Appendix K.

This RIA assumes one existing water truck for compaction and water spray on roads is sufficient 

for electric utility plants managing less than 391,000 tons per year of CCR, while plants 

managing between 391,000 and 1,173,000 tons CCR per year purchase one additional water 

truck. This RIA assumes that plants managing between 1,173,000 and 1,955,000 tons CCR per 

year purchase two additional water trucks, and plants managing more than 1,955,000 tons per 

year to the maximum facilityplant size modeled of 2,000,000 tons CCR per year purchase three 

additional water trucks.

This RIA assumes a cost of a water truck of $101,000 (in 1995 dollars, then inflated to 2013 

dollars), and an operating life of five years.166 This RIA estimates operating costs for water spray 

for compaction assuming that the truck travels approximately five miles per day, for each day 

used, with a fuel consumption of five miles per gallon and a fuel cost of $1.15 per gallon. This 

RIA further assumes that the truck operates for 50% of the hours required for compact, with a 

daily water volume of 10,000 gallons, at a cost of $2 per 1,000 gallons. Formulas for costs 

associated with water applied during compaction are located in Appendix K.

Water spray on roads. This RIA assumes that plants currently have water trucks and use water 

spray on roads as a baseline practice. For cost estimation, this RIA assumes that dust control is 

required for an average road length of 1.5 miles (three miles for a round trip), with a road width 

of 10 meters. This RIA assumes a water truck capacity of 5,000 gallons, which requires 

approximately one hour to fill. The water truck can spray a width of five meters at an assumed 

speed of 10 miles per hour, and the entire water volume of 5,000 gallons will be sprayed on each 

pass of the truck along one side of the road (i.e., 1.5 miles x 5 meters).167 The resulting water 

volume per road area, averaged over the 1.25 hours required to spray the road and refill the truck, 

is approximately 2.5 times that of the average hourly daytime evaporation rate. Therefore, water 

spray on roads will be required three times per day. Formulas for the water volume sprayed per 

road area, the time for the water truck to be filled, spray along both sides of the road, and return 

for refilling, the total time for one pass (1.25 hours), and the average rate of water spray are 

located in Appendix K.

The average hourly daytime evaporation rate is approximately 0.25 mm per hour. Therefore, the 

water spray rate is approximately 2.5 times the evaporation rate. Since the total time required for 

water spray (1.25 hours) times 2.5 is approximately 3, this RIA assumes that water spray on 

 

166 For purpose of comparison to this RIA’s 5-year operating life assumption for CCR dust control water trucks, 

although not necessarily reflecting equipment physical lifespans, the Internal Revenue Service (IRS) publishes a 

“class life” (in years) for certain types of industrial equipment. The IRS class life represents equipment depreciation 

periods for taxation purposes. Although IRS class lifes may be accelerated relative to physical operational lifespans, 

the IRS class life for (a) asset class 00.241 “Light general purpose trucks” is four years, and (b) asset class 00.242 

“Heavy general purpose trucks” is six years. Averaged together, these values produce an average class life of five 

years. Source: Page 102 of IRS Publication 946 “How to Depreciate Property,” June 28, 2014.

167 Water truck capacity, refill time, and spray width are estimated in ICF, Inc., “Cost Functions for Alternative CKD Control 

Technologies,” (Draft) July 19, 1996.
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roads is required approximately every three hours. In order to coordinate the water truck use for 

road spray and CCR compaction, this RIA assumes that the truck alternates between these two

requirements during the day. Therefore, over a nine-hour day (eight working hours plus one hour 

for lunch), roads are sprayed three times, requiring a total of approximately four hours, or 50%

of the operational day.

As previously indicated, this RIA assumes that dust controls for surface impoundments are not 

required under any state regulatory baseline. Correspondingly, surface impoundments do not 

incur any baseline costs associated with this pollution control requirement. This is a conservative 

assumption that may overstate the costs of requiring dust controls for surface impoundments 

under the rule.

3.2.5.5 Baseline Rain and Surface Water Run-On/Run-Off Control Cost Estimates

This RIA assumes that stormwater run-on/run-off controls are comprised of a ditch surrounding 

the active area of a landfill and an excavated bermed basin for water collection. This RIA assigns 

run-on/run-off control costs to existing and newly-constructed landfills based on the specific 

state regulatory requirements for run-on/run-off controls affecting those landfills.

As previously indicated, this RIA assumes that run-on/run-off controls for surface impoundments 

are not required under any state regulatory baseline. 

3.2.5.6 Baseline Disposal Unit Location Restriction Cost Estimates

In the baseline, if a plant is located in a restricted area under state regulations, CCR management

must be rerouted off site when the existing CCR management unit reaches its 40-year life 

expectancy, although in some cases plants may be able to make sufficient demonstrations to 

allow continued on-site CCR management. This RIA evaluates the impacts of location 

restrictions for fault, seismic impact, and karst areas. See Appendix L for plant-specific data.168

Fault areas. The CCR rule would ban the location of new CCR landfills and any surface 

impoundment within 200 feet (60 meters) of faults that have experienced displacement during 

the past 11,000 years (i.e. in the Holocene Epoch) unless sufficient demonstration can be made 

regarding the safety and appropriateness of design of the CCR management unit.169 This RIA 

uses the U.S. Geological Survey (USGS) Quaternary Fault and Fold Database of the United 

States170 to determine the distance of the nearest fault to the CCR plant centroids, although this 

 

168 Data obtained from attachments to “Vulnerability Criteria Information for Coal Combustion Residuals Plants Revised 

Technical Directive 4-3, WA 1-02, EPA Contract # EP-W-09-004,” memorandum from Robert Truesdale, RTI International, to 

Becky Cuthbertson, EPA Office of Resource Conservation and Recovery, December 31, 2010.

169 The CCR rule defines a fault to include a zone or zones of rock fracturing in any geologic material along which there has been 

an observable amount of displacement of the sides relative to each other. Faulting does not always occur along a single plane of 

movement (a ‘‘fault’’), but rather along a zone of movement (a ‘‘fault zone’’). Therefore, ‘‘zone of fracturing,’’ which means a 

fault zone in the context of the definition, is included as part of the definition of fault, and thus the 200-foot setback distance will 

apply to the outermost boundary of a fault or fault zone.

170 USGS source at http://earthquake.usgs.gov/hazards/qfaults/
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centroid may be one or two kilometers from on-site CCR management units.,171 Only seven 

plants have active faults within two miles of their centroids; all six of these plants are located in 

western states.172

This RIA does not evaluate state-specific set-back distance standards. In the baseline, this RIA 

assumes that states with fault area regulations have a 200-foot setback standard. Given that a 

plant’s centroid may be one or two kilometers away from the on-site unit, this RIA uses a twomile standard to identify which plants located in fault zone areas may be forced to dispose waste 

off site when their current CCR disposal units reach capacity.

Seismic impact areas. This RIA defines a seismic impact area as “an area with a 2% or greater 

probability that the maximum horizontal acceleration in lithified earth material, expressed as a 

percentage of the earth’s gravitational pull (g), will exceed 0.10 g in 250 years.”173 In the 

baseline, this RIA assumes that plants located in seismic impact zones would be forced to 

dispose of CCR off-site when their current CCR disposal units reach capacity, as opposed to 

making modifications to the design of the unit, unless sufficient demonstration can be made 

regarding the safety and appropriateness of design of the CCR management unit.174 As a 

representative cut-off point, this RIA assumes that all plants located in areas with a 2% per 50-

year probability of exceedence and a peak ground acceleration greater than 0.5 g will shift to offsite landfill disposal when their current units reach capacity.

Karst areas. This RIA defines karst as areas underlain by soluble bedrock, generally limestone or 

dolomite, and may contain extensive subterranean drainage systems and relatively large 

 

171 EPA conducted this analysis in 2009 prior to identifying 12 additional electric utility plants potentially affected by the CCR 

rule.

172 “Vulnerability Criteria Information for Coal Combustion Residuals Plants Revised Technical Directive 4-3, WA 1-02, EPA 

Contract # EP-W-09-004,” memorandum from Robert Truesdale, RTI International, to Becky Cuthbertson, EPA Office of 

Resource Conservation and Recovery, December 31, 2010.

173 The regulatory standard (which has not been compared to the individual state standards in this RIA) is that any unit in seismic 

impact zones must be designed to resist the maximum horizontal acceleration in lithified earth material for the site. The design 

features to be protected include all containment structures (i.e., liners, leachate collection systems, and surface water control 

systems). The demonstration must be certified by an independent registered professional engineer and the owner or operator must 

notify the state that the demonstration has been placed in the operating record and on the company’s internet site. 

174 Data have been collected based on 50 years instead of 250 years. For 473 of the 478 electric utility plants, data were collected 

from USGS National Seismic Hazard Maps (http://earthquake.usgs.gov/hazards/products/conterminous/2008/update_201001) to 

determine which plants are located in areas with peak ground acceleration (PGA) that has a 2% probability of occurring in 50 

years. Of these 473 plants:

 146 have a PGA 2% per 50 year probability of exceedence (PE) greater than 0.1 g

 55 are greater than 0.2 g.

 11 plants with a 2% per 50 year PE PGA greater than 0.5 g are located mainly in the vicinity of the New Madrid, MO, and 

Charleston, SC, earthquake centers.

See also “Vulnerability Criteria Information for Coal Combustion Residuals Plants Revised Technical Directive 4-3, WA 1-02, 

EPA Contract # EP-W-09-004,” memorandum from Robert Truesdale, RTI International, to Becky Cuthbertson, EPA Office of 

Resource Conservation and Recovery, December 31, 2010.
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subsurface voids whose presence can lead to the rapid development of sinkholes.175,176 In the 

baseline, this RIA estimates the number of plants located in karst areas that would be forced to 

seek off-site disposal when current units reach capacity, as opposed to making modifications to 

the design of the unit, unless sufficient demonstration can be made regarding the safety and 

appropriateness of design of the CCR management unit.177

This RIA probabilistically assesses whether or not a given CCR management unit will have to 

shift to off-site disposal due to a location restriction, or whether a plant will be able to provide 

adequate demonstrations and certifications to continue using on-site disposal of CCR. As a 

simplifying assumption that allows for the greatest distributional variance, this RIA assumes that 

in half of all cases, an adequate demonstration will be made, while in the other half, disposal will 

have to shift off-site once the CCR management unit closes. Because, in the baseline, CCR 

storage impoundments are not modeled as closing, these restrictions apply only to landfills and 

disposal impoundments. Given that only five disposal impoundments and nine landfills are 

identified as subject to baseline site restriction requirements (for fault areas, seismic zones, and 

unstable areas only), this RIA models that on average, seven CCR disposal units will shift to offsite disposal in the baseline as a result of location restrictions. For additional information on the 

probabilistic modeling approach applied in this RIA, see Chapter 4. 

In cases where an adequate certification is deemed to be made, the cost model applies a nominal 

certification cost to the cost equation; for more information on this certification cost, see the 

discussion of recordkeeping and reporting costs in Chapter 4. Relative to other CCR 

management costs, this certification cost is very low and does not drive the decision logic of the 

model in those cases where an adequate certification is deemed to be made. 

3.2.5.7 Baseline Closure Capping to Cover Unit Cost Estimates

Capping costs represent a significant capital cost that begins in the last year of unit life, and this 

RIA applies this expenditure in annualized form over the operating life of the new CCR 

 

175 The regulatory standard (which has not been compared to the individual state standards in this RIA) is to allow the 

construction of new CCR units, and the continued operation of existing CCR landfills and surface impoundments in karst terraces 

where the owner or operator can demonstrate that engineering measures have been incorporated into the landfill, surface 

impoundment, or lateral expansion design to ensure that the integrity of the structural components of the landfill or surface 

impoundment will not be disrupted. The demonstration must be certified by an independent registered professional engineer, and 

the owner or operator must notify the state that the demonstration has been placed in the operating record and on the company’s 

internet site.

176 This RIA estimates that uses a 2 km radius around each plant centroid, and determined that about 29% of the 478 electric 

utility plants examined are within the karst polygons defined in the USGS map developed by Davies et al. (1984) 

(http://pubs.usgs.gov/of/2004/1352/)

See also “Vulnerability Criteria Information for Coal Combustion Residuals Plants Revised Technical Directive 4-3, WA 1-02, 

EPA Contract # EP-W-09-004,” memorandum from Robert Truesdale, RTI International, to Becky Cuthbertson, EPA Office of 

Resource Conservation and Recovery, December 31, 2010.

177 In this case, high relative karst likelihood includes “long-2” and “long-3” karst:

 Long-2 karst includes fissures, tubes, and caves over 1,000 ft (300 m) long; 50 ft (15 m) to over 250 ft (75 m) vertical 

extent; in moderately to steeply dipping beds of carbonate rock.

 Long-3 karst includes fissures, tubes, and caves over 1,000 ft (300 m) long; 50 ft (15 m) to over 250 ft (75 m) vertical 

extent; in gently dipping to flat-lying beds of carbonate rock.
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management unit.178 This RIA assumes the same requirements for both landfill and 

impoundment capping:

 Synthetic cap with a drainage layer, including a perforated pipe for drainage 

collection;179

 Synthetic cap without drainage layer;180

 Clay cap;181

 Soil/clay cover;182 or

 Soil cap.183

This RIA assigns costs associated with the above cap types to existing and new units based on 

specific state regulatory requirements for capping. In the baseline, these costs do not apply to 

storage impoundments, as they are assumed to operate indefinitely. 

As a simplifying assumption, closure capping costs for disposal impoundments are annualized 

over 40 years regardless of the type of CCR management that a plant chooses to employ after 

unit closure. In addition, capping costs are only applied after unit closure for existing on-site 

landfills and disposal impoundments; for new on-site landfills and disposal impoundments, 

capping costs are included as part of the cost equation applied to these units while they are active 

and receiving CCRs. This is a conservative assumption that ensures that these costs are captured 

by the cost model rather than shifting capping costs to out-years beyond the 100-year period of 

analysis in this RIA. While this assumption slightly increases baseline costs, it has a greater 

impact on the post-rule costs discussed in Chapter 4 because, as shown in Exhibits 3-B and 3-

C, most state regulatory baselines do not require closure capping for either landfills or 

impoundments.184

3.2.5.8 Baseline Post-Closure Groundwater Monitoring Requirement Cost Estimates

This RIA assumes the same requirements for both CCR landfills and impoundments, entailing 30 

years of groundwater monitoring and surface water monitoring on a semi-annual basis. This RIA 

assumes physical parameters and unit costs identical to those for groundwater monitoring, as 

 

178 The cost estimate for this pollution control does not include the closure plan cost or closure certification costs, which are

included in the reporting and recordkeeping costs described in Chapter 4. 

179 This closure cap is comprised of a 60 mil HDPE synthetic liner, 1 foot sand, filter fabric, 1.5 foot slope and earth fill, 0.5 foot 

topsoil, and vegetation.

180 This closure cap is comprised of a 60 mil HDPE synthetic liner, 1.5 foot slope and earth fill, 0.5 foot topsoil, and vegetation.

181 This closure cap is comprised of 2 feet of off-site clay, 0.5 foot topsoil, and vegetation. Cover costs would be lower if on-site 

clay is available.

182 This closure cover is comprised of 0.5 foot clay, 0.5 foot earth fill, and 0.5 foot topsoil, and vegetation. Cover costs would be 

lower if on-site clay is available.

183 This closure cap is comprised of a 1.5 foot slope and earth fill, 0.5 foot topsoil, and vegetation. The slope of the cap is 

assumed to be 0.02:1 (rise:run) with a cover toe slope of 4:1 (run:rise).

184 As indicated in Chapter 4, closure capping and post-closure monitoring costs have a relatively low impact (less than 3%) on 

total incremental costs. Removing this conservative assumption and shifting closure and post-closure costs for newly-constructed 

units to the timeframes consistent with closure and post-closure for these newly-constructed units would have minimal impacts 

on total incremental costs, on the order of less than 2% of total incremental costs.
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defined in Section 3.2.5.1. This RIA assigns the post-closure monitoring costs to existing and 

newly-constructed units in states with relevant regulatory requirements. In the baseline, these 

costs do not apply to storage impoundments, as they are assumed to operate indefinitely. 

As a simplifying assumption, post-closure monitoring costs for disposal impoundments are 

annualized over 40 years regardless of the type of CCR management that a plant chooses to 

employ after unit closure. In addition, post-closure monitoring costs are only applied after unit 

closure for existing on-site landfills and disposal impoundments; for new on-site landfills and 

disposal impoundments, post-closure monitoring costs are included as part of the cost equation 

applied to these units while they are active and receiving CCRs. This is a conservative 

assumption that ensures that these costs are captured by the cost model rather than shifting postclosure monitoring costs to out-years beyond the 100-year period of analysis in this RIA. While 

this assumption slightly increases baseline costs, it has a greater impact on the post-rule costs 

discussed in Chapter 4 because, as shown in Exhibit 3-C, most state regulatory baselines do not 

require post-closure monitoring for impoundments, and many states do not require them for 

landfills.

3.2.5.9 Baseline Structural Integrity Evaluation Cost Estimates

This RIA estimates that 62.5% of CCR impoundments in the universe are evaluated for structural 

integrity in the baseline.185 Exhibit 3-F shows estimated per-plant costs for structural integrity 

evaluations, which this RIA assumes includes geotechnical, hydrologic, hydraulic and other 

engineering factors to construct or improve surface impoundment structures to avoid 

impoundment releases. This assumption reflects the use of the Mine Health and Safety 

Administration (MHSA) coal mining refuse surface impoundment structural integrity evaluation 

requirements as a proxy for baseline state requirements for structural integrity evaluation of CCR 

impoundments. Estimated costs are $12,858 per year to utilities per impoundment, and $711 per 

year in state government costs per impoundment.

 

185 See page 36 of joint DOE/EPA report “Coal Combustion Waste Management at Landfills and Surface Impoundments, 1994-

2004,” report nr. DOE/PI-0004, Aug 2006 at: http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=2008. At the time during which 

state regulatory baseline data were collected, data on state regulatory baseline applications of SI inspections were not available. 

This RIA therefore uses a more generic estimate based on a surveyed subset of impoundments.
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Exhibit 3-F

Baseline Cost to Industry and State Governments for Impoundment Structural Integrity Evaluations

Paperwork Burden Elementa Labor hours Cost

(2006$)

Cost per 

Plant

Annualized Cost 

per Plantb

Industry Costs

Purpose: Prepare 10-year evaluation plan, 

involving evaluation of geotechnical, 

hydrologic, hydraulic and other engineering 

factors to construct or improve surface 

impoundment structures to avoid 

impoundment releases

1,300 $70.07/hour $91,091 $9,109

Revisions to Impoundment Safety Plan 

prepared by mining company engineerc 40 $70.07/hour $2,803 $280

Fire Extinguishing Plan prepared by mining 

company engineer or supervisor 20 $70.07/hour $1,401 $140

Annual Status Report and Annual Certification 

prepared by company engineer

Purpose: To determine whether impoundments 

are operated and maintained according to 

approved engineering safety plan

2 $70.07/hour $140 $140

Recordkeeping and weekly inspections.d

Purpose: To determine whether any signs of 

instability have developed

42.5 $30.27/hour $1,286 $1,286

Subtotal Industry Costs (2006$) $10,829

Subtotal Industry Costs (2013$)e $12,858

State Government Costs

Review of Impoundment Safety Plans

160 hours 

tech review +

2 hours 

admin review

$30.27/hour $4,952 $495

Review of revisions to Impoundment Safety 

Plans

30 hours tech 

review +

2 hours 

admin review

$30.27/hour $978 $98

Review and prepare responses for 

impoundment abandonment plans 1 $30.27/hour $31 per plan $3

Review of annual inspection Status Reports 

and Certifications 1 $30.27/hour $31 per report $3

Subtotal State Government Costs (2006$) $599

Subtotal State Government Costs (2011$)e $711

a Elements, labor hours, and labor costs are based on the “Supporting Statement” for the March 2008 DOL/MSHA ICR 12-19-0015, 

“Refuse Piles and Impounding Structures, Recordkeeping, and Reporting Requirements” at: 

http://www.msha.gov/regs/fedreg/paperwork/2004/04-24046.pdf

b Assumes plans are valid for 10-years similar to the length of RCRA permits.

c Assumes one revision to the plan will be made during 10-years.

d Average labor hours per inspection between inspections at sites with monitoring instruments (3 hours) and at sites without 

monitoring instruments (2 hours). Labor hours calculated as 2.5 hours per inspection x 17 inspections per year.

e

Inflated to 2013 dollars: 124.2 December 2013 BLS Employment Cost Index for professional, scientific and technical 

workers/104.6 December 2006 index = 1.1874
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3.2.5.10 Baseline Corrective Action Remediation Cost Estimates

State corrective action requirements differ widely across states.186 According to information 

collected by EPA for 33 states, 21 states have regulatory baseline corrective action requirements 

for CCR management units. For the baseline, this RIA assumes that the facilities in these 21 

states incur corrective action costs in the baseline equivalent to those estimated in this RIA under 

the CCR final rule.187 For additional information on these costs, see Section 4.3.10. To the extent 

that the baseline corrective action requirements in these states are not as stringent as those 

required under the CCR final rule, this assumption may overstate baseline costs and thus 

understate the impact of the CCR final rule for this cost element. However, to the extent that 

some of the remaining 17 states also have regulatory baseline corrective action requirements for 

CCR management units, this assumption may understate baseline costs and thus overstate the 

impact of the CCR final rule for this cost element. Of the 478 coal-fired electric utility plants 

examined in this RIA, 252 (53%) are located in states assumed to be requiring corrective action 

similar to that required under the CCR final rule. 

3.2.5.11 Baseline Administrative Reporting and Recordkeeping Cost Estimates

This RIA assumes this cost to be effectively $0 in the baseline because it assumes that all 

baseline CCR management units used by electric utility plants are not regulated under RCRA 

Subtitle D, and are subject to minimal reporting and recordkeeping requirements. See Appendix 

M for calculations. To the extent that some CCR management units are subject to some of the 

reporting and recordkeeping costs required by the CCR final rule, this is a conservative 

assumption that could overstate the cost of the rule. However, reporting and recordkeeping costs 

represent a small portion of both the baseline costs associated with CCR management and the 

incremental compliance costs associated with the CCR final rule.

 

186 EPA reviewed state corrective action requirements for 25 of the top coal usage states (for electricity) in 2000. Of the 25 states, 

21 required correction action:

 For surface impoundments: Arizona, Indiana, and Iowa establish a corrective action alert level and response action in sitespecific state permits; Colorado requires corrective action for new units; Florida, Georgia, Kentucky, Michigan, North 

Carolina, North Dakota, Pennsylvania, Utah, and Wisconsin require corrective action; Illinois, Minnesota, Texas, West 

Virginia and Wyoming do not allow groundwater degradation, but specific enforcement mechanisms are not specified in 

state regulations; Missouri requires corrective action for units closed with waste in place, otherwise corrective action may be 

established under a permit; New Mexico requires an abatement plan.

 For landfills: Arizona establishes a corrective action alert level and response action in site-specific state permits; Colorado, 

Florida, Georgia, Illinois, Kentucky, Michigan, North Carolina, North Dakota, Ohio, Oklahoma, Pennsylvania, Utah, West 

Virginia, Wisconsin, and Wyoming require corrective action; Minnesota and Texas do not allow groundwater degradation, 

but specific enforcement mechanisms are not specified in state regulations; Missouri and Tennessee require assessment 

only; and New Mexico requires an abatement plan.

187 Data on state government corrective action requirements for CCR management units (landfills or impoundments) are based on 

limited information for 33 states prepared by Patrick Kelly, Environmental Engineer, EPA-ORCR Energy Recovery and Waste 

Disposal Branch, September 2011. A “no” for each state either indicates: (a) the state does not require corrective action, or (b) 

EPA has no data for that state. “Yes” for a state indicates EPA has information that the state requirements some sort of corrective 

action as of 2011, although the corrective action could be a relatively narrow requirement, rather than a broad one.

 Yes: AZ, CO, FL, GA, IL, IN, IA, KS, KY, MI, MN, MO, NC, ND, NM, PA, TX, UT, WI, WV, WY (21)

 No: AL, AR, LA, MD, MT, NE, NV, NY, OH, SC, TN, VA (12)
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3.2.5.12 Baseline Impoundment Closure and Conversion to Dry Handling Cost Estimates

Impoundment closures are not required in the baseline, although, as noted, there has been a 

recent trend (1995 to 2009) toward dry management among electric utility companies. To 

account for business decisions that would not be affected by the regulation, this RIA calculates 

both baseline and post-rule costs associated with wet-dry conversion, and considers only the 

incremental costs to be related to the rule. This assumption that business decisions are driving 

wet-dry conversions is consistent with the recent (20091996 to 20112012) declining trend in wet 

handling of CCR tonnage for disposal documented inas revealed by analysis of EIA data. for 

those years (see Section 2.4.5 of this RIA).

188

To calculate incremental compliance costs in Chapter 4, this RIA subtracts the costs associated 

with wet-dry conversion in the baseline from the costs associated with wet-dry conversion under 

the CCR final rule. Detailed information on calculations used to estimate wet-dry conversion 

costs can be found in Section 4.3.12.

3.2.5.13 Baseline Off-Site Disposal Cost Estimates

For units engaging in off-site CCR disposal, this RIA assumes that the baseline off-site disposal 

cost includes truck transport from the electric utility plant to the off-site landfill, and tipping fees. 

The cost estimate employs the following data and assumptions:

 The average one-way trucking distance to an off-site landfill is 25 miles;

 $17.41 per-ton cost for loading and hauling CCR to an off-site landfill;189 and

 Commercial landfill tipping fees for construction and debris waste to represent 

off-site CCR landfill disposal costs, varying by state. See Appendix I for a list of 

landfill tipping fees used for each state.190

 

188 For example, according to 2012comparison of EIA-923 data, CCR “pond disposal” tonnage declined by 27% between 2009 

and 2012. This 27 % decline is the difference between the aggregate annual EIA-923 data (i.e., not filtered only for NAICS 22: 

utilities) for years 2009 (19.429 million tons) and 2012 (14.136 million tons). The EIA-923 data are available at: 

http://www.eia.gov/electricity/data/eia923.

189 This cost is based on a RACER estimate: $3.60 per ton for loading and $5.63 per ton, or $0.11 per two-way mile for hauling, 

in 2011 dollars. These costs are scaled to accommodate a 25-mile one-way trucking distance and inflated to 2013 dollars using 

the GDP implicit price deflator, for a 2011 to 2013 scaling factor of approximately 1.0329.

190 This RIA applies landfill tipping fees from construction and debris landfills rather than fees from municipal waste or other 

types of landfills, because the category of “debris waste” includes non-hazardous waste common to building construction and 

demolition, including asbestos and contaminated soil that are more similar in physical form (i.e., granular solids) to CCR than 

other waste types.
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3.3 Baseline CCR Disposal Cost Estimation Results

Note: EPA has updated the baseline cost calculations presented in this chapter to conform 

with changes to the universe of plants affected by the rule and the analytic framework. This 

section does not reflect these updated calculations. See Sections 9.2 and 9.4 in Chapter 9 of 

this RIA for a description of the relevant modifications and the resultant re-estimated costs, 

respectively.

3.3.1 Baseline Cost Results for this RIA

Exhibit 3-G below display average annualized costs for each of the baseline cost components 

under a 7% discount rate for landfills, disposal impoundments, and storage impoundments, 

respectively.

191,192 Appendix N provides plant-by-plant and owner entity-by-entity estimates of 

baseline costs. Exhibit 3-H then aggregates costs across the three types of CCR management 

units. This RIA assumes that state agency burden costs are 2% of the total costs incurred for 

CCR pollution control requirements and other costs with analogous state agency activities. In the 

baseline, state agency burden costs are assessed only for structural integrity inspections and 

corrective action, because this RIA conservatively assumes that no RCRA Subtitle D-related 

reporting and recordkeeping is currently occurring at coal-fired electric utility plants in the 

baseline. The state agency burden costs are aggregated in Exhibit 3-H rather than separately 

listed in Exhibit 3-G.

In the baseline, because surface impoundments will not undergo changes in CCR management as 

a result of groundwater contamination events, this RIA does not display a range for total baseline 

costs. Rather, where other probabilistic considerations (e.g., location restrictions, impoundment 

size for integrity inspections) come into play, this RIA presents the expected value, which can be 

thought of as average of the costs for each outcome, weighted by the likelihood of that outcome 

occurring, as the central estimate. This RIA does not display ranges associated with these 

probabilistic components in order to focus more on the items driving CCR management costs in 

 

191 In this RIA, costs are attributed to the original unit type, rather than spread across potential future unit types that the unit may 

switch management methods to. For example, if a landfill is constructed as a result of a facilityplant with an impoundment that 

switches to dry handling and undergoes wet-dry conversion, all costs (including the liner, etc.) for this new unit are attributed to 

the disposal impoundment table. Specifically, the “landfills” tables in this chapter and Chapter 4 indicate the cost of future CCR 

management of the CCR that is currently in landfills and current CCR management in landfills (before those existing landfills 

close), and the “disposal impoundment” tables in these chapters indicate the cost of current CCR management in disposal 

impoundments as well as the cost of future CCR management of the CCR that is currently in disposal impoundments. Because 

the cost estimating modeling does nto contain possibilities for storage impoundments to be replaced with anything other than new 

storage impoundments (and even then, this only occurs if an unlined storage impoundment incurs a groundwater contamination 

event, see Chapter 4), the “storage impoundment” tables always reflect costs associated with the CCR management in storage 

impoundments. However, given that some disposal impiundments convert to storage impoundments, even the “storage 

impoundment” tables do not contain the full set of costs incurred by storage impoundments, as they do not account for these 

disposal-converted-to-storage impoundment instances.

192 The pollution-control specific line items in the summary costs tables across this chapter and Chapter 4 represent a breakdown 

for illustrative purposes only that reflects the relative contribution of each pollution control to overall costs of CCR management 

for all CCR currently being managed in a given management unit type. This RIA cannot definitively attribute a specific dollar 

amount to a given pollution control, because the incremental additional and/or removal of individual pollution controls will alter 

unit behavior. This is applicable to the line items for groundwater monitoring, liners, leachate collection systems, dust controls, 

run-on/run-off controls, closure capping, and post-closure monitoring. The other requirements, such as structural integrity 

inspections, corrective action, recordkeeping, and wet-dry conversion are able to be estimated separately and distinctly because 

their costs are additive to the Fortran-based pollution control cost equations, and represent actual costs incurred for these 

requirements, as opposed to estimated, illustrative-only cost breakdowns.
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both the baseline and the CCR final rule scenarios. For additional information on the uncertainty 

and variability to total costs contributed by these probabilistic components, see Chapter 7. 

Exhibit 3-G

Baseline CCR Management Costs – Central Estimates (Expected Values) 

Annualized Values @ 7% Discount Rate (millions of 2013$)

CCR Pollution Control Landfills

Disposal 

Impoundments

Storage 

Impoundments

A. Unit-level pollution control costs*

1. Groundwater monitoring $11.7 $2.70 $2.05

2. Bottom liners $1,080 $772 $585

3. Leachate collection systems $228 $13.3 $10.0

4. Dust controls $20.1 $0 $0

5. Run-on/run-off controls $4.31 $0 $0

6. Location restrictions** $1.97 $20.6 N/A

7. Closure capping $26.3 $12.7 $0

8. Post-closure monitoring $0.134 $0.048 $0

9. Structural integrity inspections N/A $0.829 $4.05

B. Other costs

10. Corrective action $9.71 $4.56 $12.7

11. Reporting and recordkeeping $0 $0 $0

12. Conversion to dry handling N/A $85.5 N/A

Column Totals = $1,380 $913 $614

Notes:

* Except for location restrictions, all unit-level CCR pollution control costs cannot be dissociated due to nonlinearity in the cost estimation 

modeling process. See Section 4.2 for additional information. As a result, relative costs for unit-level pollution controls are assigned based on the 

relative unit cost of these requirements and weighted by the number of existing and new landfills subject to these requirements.

** Despite a probabilistic component inherent in the application of this cost component, this Exhibit presents an expected value cost rather than a 

range of costs in order to focus on the drivers of overall CCR management costs. Sensitivity analyses associated with the probabilistic component 

of modeling this requirement can be found in Chapter 7.

NOTE: EPA has updated or otherwise modified this exhibit of the RIA; 

see Exhibits 9-F to 9-I in Section 9.4.1 of this RIA for updated exhibits.

NOTE: EPA has updated or otherwise modified this exhibit of the RIA; 

see Exhibits 9-F to 9-I in Section 9.4.1 of this RIA for updated exhibits.
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Exhibit 3-H

Baseline CCR Management Costs for All CCR Management Units

Annualized Values @ 7% Discount Rate (millions of 2013$)

CCR Pollution Control Central Estimate

(Expected Value)

A. Unit-level pollution control costs*

1. Groundwater monitoring $16.5

2. Bottom liners $2,440

3. Leachate collection systems $252

4. CCR fugitive dust controls $20.1

5. Run-on/run-off controls $4.3

6. Location restrictions** $22.6

7. Closure capping $39.0

8. Post-closure groundwater monitoring (30 years) $0.2

9. CCR impoundment structural integrity inspections** $4.9

B. Other costs

10. Corrective action for CCR contaminated groundwater $27.0

11. Reporting and recordkeeping $0

12. Conversion to CCR dry handling $85.5

Subtotal – Baseline Industry Costs $2,910

C. State Agency Administrative/Paperwork Burden Costs

13. CCR impoundment structural integrity inspections** $0.1

14. Corrective action for CCR contaminated groundwater $0.54

15. Reporting and recordkeeping $0

Subtotal – Baseline State Agency Burden Costs $0.64

Column Total = $2,910

Notes:

* Except for location restrictions, all unit-level CCR pollution control costs cannot be dissociated due to 

nonlinearity in the cost estimation modeling process. See Section 4.2 for additional information. As a 

result, relative costs for unit-level pollution controls are assigned based on the relative unit cost of these 

requirements and weighted by the number of existing and new landfills subject to these requirements.

** Despite a probabilistic component inherent in the application of this cost component, this Exhibit 

presents an expected value cost rather than a range of costs in order to focus on the drivers of overall CCR 

management costs. Sensitivity analyses associated with the probabilistic component of modeling this 

requirement can be found in Chapter 7.

3.3.2 Comparison of Baseline Cost Estimate in this RIA with Other Published Estimates

This section compares the baseline costs estimated in this RIA to two sources of published data 

on baseline CCR disposal costs incurred by the electric utility industry.

Comparison #1 of 2: ACAA Published Estimate of Average CCR Disposal Cost

As Exhibit 3-H shows, the estimated baseline annualized cost to the 478 coal-fired electric 

utility plants for CCR pollution control costs is $2.9 billion per year under a 7% discount rate 

NOTE: EPA has updated or otherwise modified this exhibit of the 

RIA; see Exhibit 9-I in Section 9.4.1 of this RIA for an updated 

exhibit.

NOTE: EPA has updated or othwise modified this exhibit of the RIA; 

see Exhibit 9-I in Section 9.4.1 of this RIA for an updated 

exhibit.
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(2013$).193 This cost includes amortization of capital costs for constructing CCR management 

units and associated equipment (i.e., in-plant equipment for extracting CCR from boilers, CCR 

storage equipment, CCR conveyance equipment such as slurry pipelines for wet CCR or trucks 

and mechanical conveyor belts for dry CCR, and the disposal units themselves) and annual 

expenditures for operation, maintenance and replacement/expansion of this equipment and CCR 

management units.

On a per-ton basis, the estimated baseline cost is $55 per ton under a 7% discount rate. This 

estimate is calculated by dividing the annualized baseline cost of $2.9 billion by the estimated 

52.6 million tons of CCR disposed in on-site landfills and on-site surface impoundments (as of 

2012).

194 This per-ton estimate does not include the growth factor in CCR generation, meaning 

that it annualizes costs over a 100-year period of analysis but does not account for increases in 

CCR tonnage disposed over that same period.

In comparison, the ACAA estimates that the average unit cost (per ton) for baseline disposal of 

CCR by coal-fired electric utility plants ranges as low as $3 per ton to over $40 per ton.195 The 

average annualized baseline CCR disposal cost of $55 per ton in this RIA exceeds the baseline 

cost range of $3 to more than $40 reported by the ACAA. The ACAA estimates reflect the 

following assumptions:

 Low-end cost. The low end of the ACAA’s reported cost range is $3 to $5 per ton. If a 

low-cost surface impoundment does not include a liner and leachate collection costs, the 

baseline cost for disposal may be as low as $3 per ton, based on the cost elements applied 

in this RIA. This low-end cost may be derived from the disposal impoundment cost of 

Exhibit 3-G by subtracting from the total cost across all unit-level CCR pollution 

controls the costs associated with the highest cost line items such as wet-dry conversion, 

bottom liners and leachate collection systems.

 High-end cost. The upper end of the ACAA’s reported cost range is $20 to $40 per ton, 

which applies to off-site disposal. The cost estimation of this RIA incorporates off-site 

commercial disposal costs on a state-by-state specific basis according to electricity power 

plant location and commercial landfill tipping fees for construction and debris waste. 

 

193 See Chapter 9 for present-value and annualized estimates of CCR management costs associated with the baseline scenario 

under both 3% and 7% discount rates as prescribed by OMB Circular A-4.

194 This estimate does not include the 14.8 million tons of CCR disposed in off-site landfills, because off-site CCR disposal does 

not incur incremental costs associated with the final CCR rule and is thus not examined under the baseline for this RIA. 

Furthermore, this estimate includes only 37.8 million tons of CCR disposed in on-site landfills, rather than the 41.7 million tons 

reported in Chapter 2, because this RIA identified 18 plants reporting on-site CCR disposal in landfills where no CCR landfills 

were previously identified (see Exhibit 3-C). This RIA addresses the potential impact of the cost estimation for both the baseline 

and final CCR rule as a sensitivity analysis in Chapter 7.

195 See the ACAA webpage containing Frequently Asked Question nr. 13 at 

http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=5#Q13 where the ACAA notes:

“As one can see, a variety of factors enter into determining disposal costs. The lowest cost occurs when a disposal site 

is located near the power plant and the material being disposed can be easily handled. If the material can be piped, 

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

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

volume, costs could range from $20 to $40 per ton. In some areas, the costs are even higher. If new sites are required 

and extensive permitting processes take place, the total cost of the facility may be increased, resulting in higher 

disposal costs over time."
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These costs range from $21 to $145 per-ton, with a national average of $50 per-ton.196

The baseline cost estimation method in this RIA also adds a CCR off-site transportation 

and loading cost of approximately $17 per ton, based on the RACER cost estimation tool. 

It is unknown what cost elements the ACAA includes in the high end of its reported cost 

range (e.g., transportation costs and/or landfill tipping fees). In addition, electric utility 

companies may have annual or multi-year contracts with off-site landfill operators that 

offer tipping fees lower than the state-average off-site construction and debris tipping 

fees used in this RIA. Note that because the final CCR rule does not apply incremental 

costs to offsite disposal, baseline costs associated with offsite CCR disposal are not 

assessed in this chapter.

Comparison #2 of 2: CCR Disposal Cost Data Contained in the EIA-767 Database

The 2005 EIA-767 database (Schedule 3, Part B) indicates that steam electric plants with 

nameplate capacity of 100 MW or greater reported $5,890 million in total annual capital and 

O&M costs. These costs include $0.314 million per year for water pollution controls, $0.193 

million per year for solid waste disposal, $0.185 million per year for other pollution controls, 

$3,627 million per year for capital expenses for air pollution abatement, and $1,546 million per 

year for collection and disposal O&M costs for fly ash, bottom ash, and FGD. This last cost 

element, $1,546 million per year for CCR disposal, is only 53% of the $2.9 billion per year 

estimate displayed in Exhibit 3-H above.197

However, the 2005 DOE EIA-767 cost data reflect only 179 coal-fired electric utility plants, 

roughly 37% of the 478 coal-fired electric utility plants addressed by this RIA. If the $1.546 

billion per year cost estimated by aggregation of cost data from the EIA Form 767 database is 

extrapolated to the 359 plants that dispose of CCR on-site (the only ones for which baseline costs 

are assessed in this RIA) by multiplying by approximately 2, the estimated cost for the on-site 

disposal plant universe would be $3.092 billion per year. This extrapolated cost is approximately 

6% higher than the $2.910 billion annual baseline cost estimated in this RIA.198

The above comparisons of the baseline cost estimated in this RIA to two other published cost 

estimates indicate the baseline cost estimate of this RIA falls within the range of baseline CCR 

disposal costs indicated in reference to data from two other organizations. Given the large 

potential variability stemming from cost modeling assumptions, such as baseline state regulatory 

requirements and costs associated with individual unit-level CCR pollution controls, the baseline 

costs in this RIA appear to suitably estimate the costs of CCR disposal currently incurred by 

coal-fired electric utility plants.

 

196 For example, commercial landfill tipping fees for construction and demolition waste for some of the high coal usage states 

include: Tennessee, $33.72 per ton; Indiana, $37.10 per ton; Ohio, $35.97 per ton; and Pennsylvania, $66.33 per ton. See 

Appendix I for a list of prices used for all states.

197 Note that the EIA-767 costs have not been adjusted to bring them in line with the 2013$ estimates in Exhibit 3-O. If such an 

adjustment were made, $1,546 million annually would become $1,791, or 62% of total baseline costs in Exhibit 3-O.

198 If year-dollars were kept constant by inflating the EIA-767 cost estimates to 2013$, the extrapolated cost would be $3.582 

billion per year, or approximately 23% higher than the total baseline cost estimated in the RIA.
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Chapter 4

Estimated Costs for the CCR Rule

Note: EPA has updated the methods and calculations in this chapter of the RIA to reflect 

changes to the universe of plants affected by the rule, changes to the analytic framework, 

and revisions to the rule requirements. These updates are not reflected in this chapter. See 

Sections 9.2, 9.3, and 9.4 in Chapter 9 of this RIA for a description of the relevant 

modifications and the resultant re-estimated costs for the CCR final rule.

This chapter provides a detailed summary of the estimated costs of the CCR final rule. The rule 

requirements are outlined below. This chapter first describes the rule and the cost estimation 

methods used in this RIA and explains its relationship to the 2010 RIA methodology. This 

chapter then describes the disposal unit-level CCR pollution control costs (i.e., landfill-level and 

surface impoundment-level costs) and the electric utility plant-level CCR pollution control costs 

estimated, and summarizes compliance cost estimates across the different types of CCR 

management units and two different discount rates. The chapter concludes with a discussion of 

additional key cost assumptions, caveats, and limitations to the cost estimation approach in this 

RIA. 

4.1 Description of the Final CCR Rule and Cost Estimation Methodology

Note: EPA has updated this section of the RIA to reflect revisions to the rule requirements. 

These updates are not reflected in this section. See Section 9.3 in Chapter 9 of this RIA for a 

description of the relevant modifications and updates to this section. 

On June 21, 2010, EPA co-proposed two alternative regulatory options for the CCR rule, 

consisting of a Subtitle C “special waste” option and a Subtitle D “non-hazardous waste” option. 

Concurrently, EPA solicited public comment on EPA’s consideration of a “D-prime” regulatory 

approach:

199

 Subtitle C option: This option would list CCR as a new category of “special 

waste” under RCRA Subtitle C hazardous waste regulatory authority, thereby 

regulating CCRs from the point of their generation to the point of their final 

disposition, including during and after closure of any CCR landfill or CCR 

surface impoundment. This would include the generator and transporter 

requirements and the requirements for facilities managing CCRs, such as siting, 

liners (with modification), storm water run-on and run-off controls, groundwater 

monitoring, fugitive CCR dust controls, financial assurance, corrective action,

(i.e., cleanup of CCR contaminated groundwater), including facility-wide 

corrective action, closure of CCR units, and post-closure care (with certain 

modifications), dam safety structural stability for CCR impoundments that by the 

effective date of the final rule have not closed consistent with the requirements, 

and land disposal restrictions and treatment standards for CCR. In addition, 

 

199 CCR proposed rule: Federal Register, Vol. 75, No. 118, June 21, 2010, pages 35128 to 35264. EPA presented the D-prime 

regulatory approach on pages 35134, 35149, and 35210 of this Federal Register notice.
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facilities that dispose of, treat, or, in many cases, store, CCR also would be 

required to obtain permits for the units in which such materials are disposed, 

treated, and stored. Under Subtitle C authority EPA could enforce these 

requirements.

 Subtitle D option: This option would establish national criteria to ensure the safe 

disposal of CCR in landfills and surface impoundments by subjecting such units 

to, among other things, location standards, composite liner requirements (new 

landfills and impoundments would require composite liners; existing unlined 

impoundments would have to retrofit within five years or cease receiving CCR 

and close); groundwater monitoring and corrective action standards for CCR 

releases (leaching) from the unit; closure and post-closure care requirements; and 

requirements to address the structural stability of impoundments. The option 

would not regulate the generation, storage or treatment of CCR prior to disposal. 

Because of the limited scope of Subtitle D authority, this option would not require 

permits, nor could EPA enforce the requirements. Instead, states or citizens could 

enforce the requirements under RCRA citizen suit authority. The states could also 

enforce any state regulation under their independent state enforcement authority.

 D-prime regulatory approach: This alternative approach presented in the June 

2010 proposed rule for public comment, represents a modification to the Subtitle 

D option in which existing CCR surface impoundments would not have to close 

or install composite liners but could continue to operate for their useful life. 

Otherwise the other requirements of this option would be identical to the Subtitle 

D option.

The CCR final rule is founded on the RCRA Subtitle D solid waste regulatory authority, and is a 

modified version of the June 2010 proposed D-prime approach (the CCR final rule is referred to 

in this RIA as a Modified D-prime approach). The CCR final rule establishes minimum national 

criteria regulating the accumulation of CCR in landfills and surface impoundments at coal-fired 

electric utility plants operating as of its effective date. In this rule, EPA is establishing the 

minimum requirements necessary to ensure the safe accumulation of CCRs in these units.

Under the final CCR rule, existing and future new CCR landfills, existing and future new CCR 

surface impoundments, and all future lateral expansions of both types of units will be subject to, 

among other things, location restrictions, design and operating criteria, groundwater monitoring, 

closure requirements, and post-closure care. Specifically:

 CCR Landfills:

o Every new CCR landfill and every lateral expansion of existing and future 

new CCR landfill is required to install either a composite (geosynthetic) 

liner or an equivalent alternative, as well as a leachate collection and 

removal system.

o Existing landfills that continue to receive CCRs after the effective date of 

the CCR rule may continue to operate, and are not required to be 
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retrofitted with the new minimum-technology liner and leachate collection 

and removal systems. However, these units are required to comply with, 

among other things, all applicable location restrictions, groundwater 

monitoring, corrective action, and closure and post-closure care 

requirements specified in the CCR rule. 

o Inactive CCR landfills are not subject to the CCR final rule.

 CCR impoundments (including both storage and disposal impoundments):

o Every new CCR surface impoundment, and every lateral expansion of an 

existing CCR surface impoundment, is required to install a composite liner 

or an equivalent alternative.200

o Existing composite-lined or clay-lined CCR surface impoundments may 

continue to operate under the final rule.

201 (EPA’s Risk Assessment results 

for the CCR rule indicated that both composite-lined and clay-lined CCR 

impoundments appear to effectively reduce risks from all groundwater 

leachate pathways and groundwater chemical constituent concentrations 

below the risk criteria).

o Existing unlined CCR surface impoundments (i.e., without either an 

adequate composite liner or an adequate clay liner) may continue to 

operate for their useful life, and will not be required to retrofit with a 

composite liner, subject to the following regulatory condition: an existing 

unlined CCR impoundment must retrofit or close if its chemical 

constituent sampling analysis (required as part of the groundwater 

monitoring requirements of the CCR final rule) exceeds health-based 

thresholds established in the rule. 

o If an impoundment’s chemical constituent sampling analysis is found to 

exceed health-based thresholds at any point following the effective date of 

the rule, unlined CCR impoundments are required to retrofit to install a 

composite liner, or to close within five years of the publication date of the 

CCR rule. Unlined CCR impoundments found to exceed health-based 

thresholds in out years beyond a point within five years of the publication 

date of the rule must retrofit or close immediately; the grace period 

 

200 Throughout this chapter, This RIA uses “lined” and “unlined” as shorthand for “having an existing liner that meets sufficient

liner criteria as described in the final CCR rule.” While the majority of existing surface impoundments with composite or clay 

liners have liners of sufficient thickness to meet this criterion, not all do. For the purposes of cost estimation and other numbers 

and exhibits presented in this chapter, surface impoundments with clay or composite liners of less than 36 inches in thickness are 

considered “unlined” because these liners do not meet the sufficient thickness criteria of the final CCR rule. Of the 175 existing 

surface impoundments with clay or composite liners, 19 liners have been identified that may not meet these sufficient thickness 

requirements.

201 EPA’s Risk Assessment for the CCR rule indicates that composite-lined and clay-lined CCR impoundments appear to 

effectively reduce risks from all groundwater leachate pathways as well as groundwater chemical constituent concentrations 

below the risk criteria. Correspondingly, probabilities of groundwater contamination are not modeled for clay-lined and 

composite-lined impoundments and thus groundwater contamination incidents do not prompt early unit closure for lined 

impoundments.
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pertaining to closure within five years of the rule’s publication date 

applies only to those impoundments found to exceed health-based 

thresholds prior to the end of this five-years-after-publication-date period.

o As with existing CCR landfills, all existing and new CCR impoundments 

are required to comply with, among other things, applicable location 

restrictions, groundwater monitoring, reporting, corrective action, closure, 

and post-closure care requirements specified in the CCR rule. 

o Inactive CCR impoundments located at operating electric utility plants are 

regulated by the CCR rule: facilities have the option to either de-water and 

cap the impoundment without any other requirements, or to comply with 

the same requirements applicable to active CCR impoundments. Inactive 

CCR impoundments located at utility plants which have ceased operating 

are not subject to the CCR rule.

Because of the scope of RCRA Subtitle D authority, the CCR rule does not require permits to 

operate CCR landfills or CCR impoundments, nor can EPA enforce the requirements of the CCR 

final rule. Instead, state governments or citizens can enforce the requirements of the rule under 

RCRA citizen suit authority. The states can also enforce any state regulation under their 

independent state enforcement authority.

As discussed in Chapter 3, this RIA uses a STATA-based model to calculate costs accruing to 

each CCR management unit under the baseline as well as under the CCR final rule. The cost 

model relies on some of the cost modeling assumptions in the model EPA used to support the 

RIA for the June 2010 proposed CCR rule. The model applies unit-level CCR pollution control 

costs and simulates plants’ management decisions at the future dates of end-of-lifespan closure 

for existing CCR management units. At the end of each disposal unit lifespan cycle over the 100-

year future period of analysis of this RIA (2015 to 2114), the model simulates comparative cost 

options across several CCR management options (i.e., off-site disposal versus creation of a new 

on-site impoundment) and assumes that plants select the most cost-effective management option. 

The sections below summarize the cost estimation methodology for the CCR final rule for each 

type of CCR management unit. The methods are generally similar to those described in Chapter 

3, except that different decision points are prompted by the rule for unlined impoundments, and 

costs associated with the requirements vary in some cases from baseline costs. 

4.1.1 Landfills

In general, the post-rule cost estimation methodology for landfills is similar to that for landfills in 

the baseline, with two exceptions:

 If a CCR pollution control requirement is not present at a given existing landfill in 

the baseline, the landfill must still comply with this requirement (except for liners 

and leachate collection systems, which are not required for existing units under 

the rule); and
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 New CCR landfills are subject to all the requirements of the final CCR rule, rather 

than just the state regulatory baseline requirements for new landfills.

More specifically, the paragraphs below describe the cost estimation process for landfills under 

the post-rule scenario.

The model maps each active CCR landfill to a Fortran cost equation that represents specific CCR 

management and disposal costs for the combination of CCR pollution controls present at that

landfill, reflecting baseline unit controls and/or state regulatory information and adjusted to 

reflect state-specific costs.

Each landfill is mapped to two cost equations: one assuming that the landfill is a combination fill 

(“dug”) landfill, and another assuming that the landfill is a pile landfill; the model projects the 

costs associated with each of these options for the suite of CCR pollution controls required at the 

landfill according to the state regulatory baseline, and assigns the lower-cost option, consistent 

with the assumption that utility plants use the least-costly disposal method available.

Beginning in Year 1 of the period of analysis (i.e., 2015), the model assigns the following 

incremental CCR pollution control costs to each existing landfill, if these CCR pollution controls 

are not already present at the landfill due to the state regulatory baseline:

 Groundwater monitoring (applied only in Year 3 and on, per the implementation 

delay for this pollution control requirement in the final CCR rule);

 Fugitive CCR dust controls; and

 Storm water run-on/run-off controls.

The incremental CCR pollution control costs associated with these three cost items are Fortranbased cost equations that are also state-adjusted, as all other applicable Fortran-based costs in the 

cost model for this RIA.

The model applies these costs (consisting of both the state regulatory baseline costs and the 

incremental pollution control compliance costs) annually until the landfill turns 40 years of age. 

At this point, the model assumes that the landfill undergoes vertical expansion, and assigns a 

different cost equation, also based on state-adjusted, Fortran-based cost equations. This vertical 

expansion cost equation applies annually for the subsequent 40 years, until the landfill reaches 

80 years of age, at which point it is assumed to close and incur closure costs. Incremental 

pollution-control costs due to the rule remain unchanged during vertical expansion and apply 

each year. As part of the cost estimation, the STATA model assigns annualized capping and 

post-closure monitoring costs from the Fortran model over each year of the 40-year period 

following landfill closure, such that each landfill incurs capping and post-closure costs following 

closure, accounting for cases in which these requirements exist under state regulatory baselines.

At closure, the model compares a number of distinct CCR management and disposal options on a 

going-forward basis:
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 CCR management and disposal in a new on-site dug landfill for 40 years, which 

will be vertically-expanded at age 40 for another 40 years;

 CCR management and disposal in a new on-site pile landfill for 40 years, which 

will be vertically-expanded at age 40 for another 40 years; and

 Offsite disposal.

The cost equations for the first two choices listed above use Fortran model-based inputs. 

However, the model applies the same new, post-rule landfill cost equation to all new landfills 

built after closure of the existing landfills; this equation incorporates compliance with all CCR 

pollution controls required by the final CCR rule, and is state-adjusted. For offsite disposal, the 

model uses a different set of state-specific cost equations based on tipping fees transportation 

costs.

The STATA model compares each of these three sets of costs on a going-forward basis and 

chooses the lowest-cost option: the plant is assumed to employ the chosen option as its form of 

CCR management and disposal on a going-forward basis. The cost equation associated with the 

chosen option is then applied for the remainder of the 100-year period of analysis.202

Note that in the post-rule scenario, as in the baseline, costs associated with existing and new 

CCR landfills are largely deterministic: the STATA model does not rely on probabilistic 

simulation to estimate most costs associated with CCR landfills.203 This is in contrast to the postrule costs for CCR impoundments, as discussed below.

 

202 The STATA model is cognizant of landfill age, even as choices are made and different cost equations are applied. 

Specifically, landfills currently above 40 years of age will begin in 2015 as vertically-expanded landfills with all attendant cost 

equations within the model. Furthermore, if a landfill closes, chooses a new landfill, and that new landfill is vertically expanded 

and closes before the period of analysis ends, the subsequent costs applied will be associated with a pre-vertical expansion new 

landfill. Note, however, that the STATA model only makes a choice once; after an initial landfill closure and choice, the STATA 

model assumes all subsequent choices will be the same, consistent with the fact that EIA AEO projections doprojection of future 

coal consumption for electricity generation does not project changes in CCR generation and disposal past 2040, and as such any 

option determined be the lowest-cost option past 2040 would remain the lowest-cost option in any subsequent year. Landfill 

capping and post-closure monitoring costs are applied in the 40-year period following landfill closure only for existing landfills; 

these costs are assumed to be pre-paid, and are rolled into the cost equations for new landfills in order to avoid underestimating 

costs, as the 40-year period following closure of a new landfill will fall outside the 100-year period of analysis for nearly all 

landfills in the universe.

203 As discussed in Chapter 3 and further in this chapter with regard to location restrictions, the STATA model does employ 

probabilistic simulations to determine whether certain plants must shift their landfill-based CCR disposal to offsite, though this 

occurs in relatively few cases and does not drive the post-rule costs associated with CCR landfills. 
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4.1.2 Disposal Impoundments

Note: EPA has updated or otherwise modified this section of the RIA. These updates are not 

reflected in the text and exhibits in this section. See Section 9.3 in Chapter 9 of this RIA for a 

description of the relevant modifications and updates to this section. In particular, Section 

9.3 describes alternative closure requirements of the CCR Final Rule not reflected in the text 

and exhibits in this section.
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Disposal and storage impoundments are identified by the STATA model in the post-rule scenario 

in the same way as in the baseline scenario (see Chapter 3).

In general, the post-rule cost estimation methodology for disposal impoundments is similar to 

that for disposal impoundments in the baseline, with a few exceptions:

 If a CCR pollution control requirement is not present at a given existing disposal 

impoundment in the baseline, the disposal impoundment must still comply with 

this requirement (except for liners and leachate collection systems, which are not 

required for existing units under the rule); and

 New CCR impoundments are subject to all the requirements of the final CCR 

rule, rather than just the state regulatory baseline requirements for new 

impoundments.

 The STATA-based model sorts disposal impoundments into “lined,” “unlined,” 

and “unknown” categories. For all impoundments deemed to be “unknown,” the 

model then probabilistically determines whether or not each impoundment is 

lined, based on the proportion of “lined” to “unlined” impoundments for all 

impoundments with known liner status. Then, for each “unlined” disposal 

impoundment (whether initially determined or probabilistically assigned to be an 

“unlined” disposal impoundment), a decision point can be reached not only when 

the impoundment reaches the end of its operational life, but also when the 

impoundment is probabilistically determined to experience a groundwater 

contamination event. When such an event occurs, the disposal impoundment 

reaches a similar decision point as in the baseline, though it cannot choose the 

“convert to storage impoundment” option in this case.

The paragraphs below describe more specifically the cost estimation process for disposal 

impoundments under the post-rule scenario.

The STATA model maps each impoundment identified as disposal impoundments to a Fortran 

cost equation that represents specific CCR management and disposal costs for the combination 

of CCR pollution controls present at that impoundment, reflecting state-cost-adjusted state 

regulatory baseline. 

Each disposal impoundment incurs a disposal cost in each future year based on its mapped stateadjusted Fortran-based cost equation, with year-to-year costs varying due to changes in future 

annual CCR tonnage disposed in a given year based on(which this RIA estimates in relation to 

the EIA AEO 2014 projectionsprojection of future coal consumption for CCRelectricity

generation in that year.). In addition, beginning in Year 1 of the period of analysis (i.e., 2015), 

the model assigns the following incremental CCR pollution control costs to each existing 

disposal impoundment, if these pollution controls are not already present at the impoundment in 

the state regulatory baseline:

 Groundwater monitoring (applied only in Year 3 and on, per the implementation 

delay for this pollution control requirement in the final CCR rule);
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 Fugitive CCR dust controls; and

 Storm water run-on/run-off controls.

This process continues, with a cost equation-determined and state-adjusted cost based partially 

on CCR generation and disposal projections applied in each year, until the disposal 

impoundment is determined to have a groundwater contamination event (see below), or turns 40 

years of age, or the next multiple of 40, if its age in 2015 is greater than 40.204 At this point, the 

model assumes the impoundment closes and incurs closure costs. The STATA model assigns 

annualized capping and post-closure monitoring costs from the Fortran model over each year of 

the 40-year period following impoundment closure, adjusted to account for state regulatory 

baselines that already require post-closure management.

The determination of groundwater contamination event incidence is based on an incidence 

probability distribution developed by RTI International for the Risk Assessment for the CCR 

final rule. This probability distribution consists of a function expressing the chance that a given 

impoundment has incurred a groundwater contamination event measured at one-meter from the 

perimeter of the impoundment, based on the impoundment’s age. The STATA-based model uses 

this probability distribution in two ways:

 First, the model checks whether a given unlined disposal impoundment has 

already incurred groundwater contamination prior to the period of analysis, based 

on the impoundment’s age in 2014 (Year 0 of the analysis). If it has, the model 

enforces a decision point on the impoundment, but this decision point occurs in 

2020 (because the final CCR rule does not require impoundment closure or 

retrofit until five years after the publication date of the rule (i.e., 2019, or Year 6

of the analysis).205

 If the model determines probabilistically that a given unlined disposal 

impoundment has not incurred a groundwater contamination event as of 2014, it 

uses an out-year probability for each subsequent year prior to a decision point. 

Out-year probabilities are relatively low, especially after an impoundment is 

approximately 11 years of age, and as a result, disposal impoundments are much 

more likely to be probabilistically determined to have incurred an event in Year 0 

of the analysis, as opposed to any later year. If, using this out-year probability, the 

unlined disposal impoundment is determined to have incurred a groundwater 

contamination event in an out year, a decision point is prompted (unless, again, 

 

204 This assumption is consistent with the “impoundment” cell assumption reported earlier, and avoids a model situation where 

many impoundments close as soon as the model run begins. As a result, the model assumes that all impoundments in excess of 40

years of age in 2015 will not close and reach a decision point until they reach 80 years of age.

205 Note that in the case that an unlined disposal impoundment turns 40 (or a multiple of 40) years of age prior to Year 6, but has 

been determined to leak, the decision point is moved up accordingly, as the groundwater contamination event is not the trigger 

for the decision point in this case.
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the out-year event is incurred prior to 2020, or Year 6 of the analysis, in which 

case the decision point is pushed out to 2020 within the model).206

Exhibit 4-A showcases the cumulative probability of a groundwater contamination event as well 

as the out-year, individual year probability of such an event, based on unit age. Given the 100-

year period of analysis applied in this RIA, even the oldest unlined impoundments have a 

roughly 57% chance of incurring a groundwater contamination event; for relatively new 

impoundments, the cumulative probability approaches 57% as the period of analysis progresses, 

though probabilities for individual out years are very low.207

Exhibit 4-A

Cumulative and Out-Year Probabilities of Groundwater 

Contamination Events for Unlined CCR Impoundments based on 

Impoundment Age (1-meter from impoundment perimeter)

 

206 The STATA-based model, as well as this RIA refer to “decision points” and “unit closure” as the first year in which a coalfired electric utility plant must take steps to change CCR management method (including closing an existing unit and opening a 

new unit of the same type). This RIA is agnostic as to the specific schedule over which closure activities are completed and all 

CCR management previously associated with a given unit is transferred to a different management method. For cost estimation 

modeling purposes, the stream of costs associated with the new CCR management unit/method begins in the year of the “decision

point,” which is also the year termed as “unit closure.” However, it is possible that in reality, closure of an existing CCR 

management unit takes longer than one calendar year, though this does not affect the layering of cost streams assessed by the

model, because planning/siting costs for new units are included in the cost calculus, as are closure costs for existing units.

207 For the purposes of probabilistically determining whether a groundwater contamination event has occurred or will occur, the 

STATA model uses the current impoundment age rather than the adjusted age (i.e., the nearest multiple of 40) used to determine 

age-based decision points. This is consistent with the assumption that impoundments above 40 years of age represent newlycreated “cells” of older existing impoundments; however, to the extent that those older impoundments incurred a contamination 

event undiscovered until the implementation of the rule, the contamination associated with that event would still be present and 

would prompt unit closure or retrofit under the rule.

0%

10%

20%

30%

40%

50%

60%

0%

2%

4%

6%

8%

10%

12%

1 6 11 16 21 26 31 36 41 46 51 56 61 66 71 76 81 86 91 96

Cumulative Probability of Groundwater 

Contamination Event (applied in Year 0 )

Individual Out-Year Probability of Groundwater 

Contamination Event

Impoundment Age

Individual Out-Year Probability

Cumulative Probability (applied in Year 0)
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Once a decision point has been reached, either due to a groundwater contamination event or 

because the impoundment turned 40 years of age (or the next multiple of 40), the following 

choices are compared, similar to the baseline scenario, with the lowest-cost option on a goingforward basis chosen as the subsequent form of CCR management:

 Choice 1: Conversion to a storage impoundment and subsequent disposal of CCR 

in: (this choice is not available if a groundwater contamination event 

prompted the decision, because this choice does not include retrofit with a 

liner to meet the requirements of the rule)

o 1A: An offsite landfill;

o 1B: An on-site existing landfill at the plant;

o 1C: A new dug landfill built on-site at the plant; or

o 1D: A new pile landfill built on-site at the plant;

 Choice 2: Impoundment closure, wet-dry conversion, and subsequent disposal of 

dry-handled CCR in:

o 2A: An offsite landfill;

o 2B: An on-site existing landfill at the plant;

o 2C: A new dug landfill built on-site at the plant; or

o 2D: A new pile landfill built on-site at the plant;

0%

10%

20%

30%

40%

50%

60%

0%

2%

4%

6%

8%

10%

12%

1 6 11 16 21 26 31 36 41 46 51 56 61 66 71 76 81 86 91 96

Cumulative Probability of Groundwater 

Contamination Event (applied in Year 0 )

Individual Out-Year Probability of Groundwater 

Contamination Event

Impoundment Age

Individual Out-Year Probability

Cumulative Probability (applied in Year 0)
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 Choice 3: Impoundment closure, wet-dry conversion, and subsequent disposal of 

dry-handled CCR in a new dug pile landfill built on top of the closed disposal 

impoundment; or

 Choice 4: Opening a new on-site disposal impoundment for CCR management 

and disposal.

Each of the above choices includes the mapping of its own unique set of cost equations:

 Choice 1 includes the capital (one-time) cost of converting a disposal 

impoundment to a storage impoundment, from which waste is then landfilled. The 

model then applies the impoundment-specific state-adjusted cost equation based 

on the state regulatory baseline for existing surface impoundments as well as all 

applicable CCR pollution control requirement costs not present in the state 

regulatory baseline (i.e., groundwater monitoring, dust controls, and run-on/runoff controls) plus the least-cost option among the following:208

o 1A: the state-specific cost equation for offsite disposal;

o 1B: the cost equation associated with disposal of CCR in an existing, onsite landfill at the same plant (this choice is unavailable if there are no onsite landfills at the same plant, or if the existing landfill has closed and 

shifted to off-site disposal in commercial industrial landfills), plus all 

applicable post-rule CCR pollution control costs for that landfill, to the 

extent that they are not required by the state regulatory baseline;209

o 1C: the cost equation associated with disposal of CCR in a new on-site 

dug landfill at the same plant, subject to the rule’s CCR pollution control 

requirements for new landfills, and also assumed to undergo vertical 

expansion after 40 years; or

o 1D: the cost equation associated with disposal of CCR in a new on-site 

pile landfill at the same plant, subject to rule’s CCR pollution control 

requirements for new landfills, and also assumed to undergo vertical 

expansion after 40 years.

 Choice 2 includes the cost of closure (annualized capping and post-closure 

monitoring costs applied annually for 40 years after closure) and the cost of wet-

 

208 See Chapter 3 for information on the costs of converting from a disposal impoundment to a storage impoundment. Given that 

this option is available both in the baseline and CCR final rule scenario, these costs do not vary by scenario, though converted 

disposal impoundments may incur higher costs in the CCR final rule scenario because additional pollution controls at the 

converted unit may be required, depending on the presence of pollution controls at the unit due to the state regulatory baseline. 

Total conversion costs are approximately $20.07 per ton. Costs associated with broader wet-to-dry conversion costs are not 

factored into this set of equations; these are considered separately. 

209 Note that in all cases where a disposal impoundment is replaced by a final disposal option that includes dry handling, the wet 

tonnage is converted to dry tonnage by dividing by a factor of 1.322 in order to accurately reflect disposal costs for the two 

management types.
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dry conversion,210 plus the same additional cost equations for 2A through 2D as 

for 1A through 1D above, respectively.

 Choice 3 includes the cost of wet-dry conversion plus the same additional cost 

equation as in 1D above, though closure costs are not included because the 

capping and post-closure monitoring costs are assumed to be subsumed in the 

construction of the new landfill on top of the impoundment.211

 Choice 4 applies the costs associated with the Fortran-based, state-adjusted cost 

equations for new disposal impoundments according to the final rule’s CCR 

pollution control requirements for new impoundments and includes the cost of 

closure (the capping cost and 30-year post-closure monitoring cost are amortized 

over 40 years after closure).

The STATA model compares each of these sets of costs on a going-forward basis and chooses 

the lowest-cost option: the plant is assumed to employ the chosen option as its form of CCR 

management and disposal on a going-forward basis. The cost equation associated with the 

chosen option is then applied for the remainder of the 100-year period of analysis.212

The only additional exception to this logic occurs when an unlined disposal impoundment 

reaches 40 years of age and chooses Choice 1, but is later determined to incur a groundwater 

contamination event in an out year. In this case, and only in this case, is a second decision point 

reached, and in this case, the decision point contains the exact same choices as the first decision 

point, except that Choice 1 is no longer a as available as a management option. 

4.1.3 Storage Impoundments

Note: EPA has updated this section of the RIA with regard to management assumptions for 

storage impoundments. These updates are not reflected in the text and exhibits in this 

section. See Section 9.2.3 in Chapter 9 of this RIA for a description of the relevant 

modifications and updates to this section. 

 

210 Wet-dry conversion costs are discussed later in this chapter and are based on national average estimates for wet-dry 

conversion costs across all plant sizes. Due to specific modeling considerations, this RIA models wet-dry conversion on a 

disposal unit basis rather than on a plant basis, with wet-dry conversion costs heavily driven by the disposal tonnage that will be 

wet-dry converted. Wet-dry conversion costs are calculated on an annualized basis and applied for 20 years following unit 

closure and conversion based on an assumed capital improvement amortization period of 20 years.

211 This assumption results in Choice 3 always being a lower-cost option relative to Choice 2D, but the STATA model considers 

both choices for completeness.

212 Note that the STATA model only makes a choice once; after an initial impoundment closure and choice, the STATA model 

assumes all subsequent choices will be the same, consistent with the fact that EIA AEO projections do2014 projection of future 

coal consumption for electricity generation does not project changes in CCR generation and disposal past 2040, and as such any 

option determined be the lowest-cost option past 2040 would remain the lowest-cost option in any subsequent year. 

Impoundment capping and post-closure monitoring costs are applied in the 40-year period following closure only for existing 

impoundments and landfills; these costs are assumed to be pre-paid, and are rolled into the cost equations for new landfills and 

impoundments in order to avoid underestimating costs, as the 40-year period following closure of a new impoundment or landfill 

will fall outside the 100-year period of analysis for nearly all impoundments in the universe. The only exception, as noted above, 

is in cases where an unlined disposal impoundment reaches 40 years of age and chooses Choice 1, but is later determined to incur 

a groundwater contamination event in an out year.
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All impoundments not identified as disposal impoundments are considered storage 

impoundments, identical to the algorithm for sorting disposal and storage impoundments in the 

baseline. Storage impoundments are modeled similarly in the post-rule scenario relative to the 

baseline scenario, with these exceptions:

 If a CCR pollution control requirement is not present in at a given existing storage 

impoundment in the baseline, the storage impoundment must still comply with 

this requirement (except for liners and leachate collection systems, which are not 

required for existing units under the rule); and

 New CCR storage impoundments are subject to all the requirements of the final 

CCR rule, rather than just the state regulatory baseline requirements for new 

impoundments.

 The STATA-based model sorts storage impoundments into “lined,” “unlined,” 

and “unknown” categories. For all impoundments deemed to be “unknown,” the 

model then probabilistically determines whether or not each impoundment is 

lined, based on the proportion of “lined” to “unlined” impoundments for all 

impoundments with known liner status. Then, for each “unlined” storage 

impoundment (whether initially determined or probabilistically assigned to be an 

“unlined” storage impoundment), the current storage impoundment must undergo 

closure and a new storage impoundment, subject to the requirements of the CCR 

final rule for new impoundments, must open in its place when the storage 

impoundment is probabilistically determined to experience a groundwater 

contamination event.

 If a storage impoundment is found to close due to a groundwater contamination 

event, closure costs (the capping cost and 30-year post-closure monitoring cost 

are amortized over a 40 year period after closure) are added to the calculus.

This RIA assumes that storage impoundments are dredged annually and can therefore continue to 

operate indefinitely, but must close and be replaced with a new storage impoundment when a 

groundwater contamination event occurs. The probabilities for assessing the groundwater 

contamination occurrence are the same as those indicated for disposal impoundments and in 

Exhibit 4-A above. 

Prior to (and in the absence of) a groundwater contamination event, each storage impoundment is 

mapped to a cost equation based on applicable state-adjusted, state regulatory baseline 

requirements, in addition to costs for incremental CCR pollution controls for groundwater 

monitoring, dust controls, and run-on/run-off controls (to the extent that these are not present in 

the state regulatory baseline). The costs associated with these equations are applied every year 

throughout the period of analysis until a groundwater contamination event occurs. At that point, 

the cost equation for a new storage impoundment reflects the costs of constructing and managing 

a storage impoundment with all the CCR pollution control requirements mandated by the final 

CCR rule in place. Closure costs (capping and post-closure monitoring) are also applied for a 40-
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year period following the closure of an existing storage impoundment, as these are required by 

the CCR final rule.213

For information on the base costs of storage impoundments, see Chapter 3. For storage 

impoundments, the baseline and final CCR rule scenario differ in that additional CCR pollution 

controls are required in the rule scenario, and the rule scenario may result in closure of unlined 

storage impoundments and the corresponding opening of new storage impoundments to take 

their place. However, these variations do not affect the base management costs for storage 

impoundments used in this RIA, nor assumptions about the capacity and tonnage of these 

impoundments. Relative to base storage impoundment management costs, assuming no CCR 

pollution controls, of approximately $79.37 per ton or potential ton of CCR, the per-ton cost of a 

new storage impoundment inclusive of all pollution controls required by the CCR final rule is 

approximately $172.06 per ton or potential ton, plus approximately $349,000. However, given 

the presence of various pollution controls in place at many storage impoundments owing to state 

regulatory baselines, this incremental cost is not fully incurred upon closure of an unlined 

storage impoundment because the original storage impoundment may have been incurring costs 

above $79.37 per ton.

As described in Chapter 3, the same modeling considerations apply to the post-rule cost 

estimation methodology, including the financial hurdle for wet-dry conversion and the 25-mile 

one-way trucking distance to an off-site commercial industrial landfill. Lastly, the model applies 

non-unit level CCR pollution controls, such as structural integrity inspections for impoundments, 

corrective action costs, and reporting and recordkeeping costs to each unit annually over the 100-

year period of analysis.214 Where these costs are substantial enough to change the optimal 

management strategy for a given CCR management unit at a utility plant, these costs factor into 

the choice modeling described above. However, in cases where the costs apply regardless of the 

decision made (unit-level corrective action costs), or if costs are nominal and highly unlikely to 

drive decisions except in extreme cases (reporting and recordkeeping costs), these costs are 

applied subsequently and do not factor into the model logic.

The model applies the same forecast factors, discount rates, calculation methods, and other 

assumptions for the regulatory scenario as it does for the baseline, as discussed in Chapter 2 and 

Chapter 3. For the regulatory scenario, as for the baseline, this RIA presents costs on an 

 

213 While the rule also allows for the possibility of retrofit with a sufficient liner, this RIA does not model this outcome. 

Engineering information indicates that the relationship between costs for liner retrofit versus closure and new impoundment 

creation (with a liner in place at the new unit) is relatively competitive due to the necessity that existing impoundments be fully 

dredged and their contents stored elsewhere while the to-be-retrofitted liner is installed. Under the assumption that costs are 

equivalent across these two options, modeling storage impoundments as always retrofitting, rather than always closing, after a 

groundwater contamination event would have the effect of removing the need for closure capping and post-closure monitoring 

for these units, as they would not effectively be closing. However, closure capping and post-closure monitoring represent a small 

fraction of total incremental costs both for storage impoundments and for the CCR final rule as a whole: these requriements 

represent only about 3% of total storage impoundment incremental costs, or less than 2% of total incremental costs. Given this 

small impact and the uncertainty associated with costs for liner retrofit for storage impoundments relative to closure and creation

of a new storage impoundment with a liner, this RIA makes a simplifying assumption that all storage impoundments 

experiencing groundwater contamination events undergo closure, due to the lack of specific available data regarding liner retrofit 

costs for storage impoundments.

214 Structural integrity inspections for surface impoundments are not considered a unit-level cost because their costs are affected 

based on economies of scale for conducting multiple inspections at one facilityplant. See Section 4.3.10 for more information.
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annualized basis, consistent with OMB Circular A-4. Equivalent present value calculations are 

presented in Chapter 9.

This chapter presents incremental costs, rather than total costs, for the final CCR rule. 

Incremental costs are those costs incurred under the post-rule scenario that are beyond costs 

incurred in the baseline (Chapter 3). In other words, cost estimates in this chapter isolate the 

incremental burden to the electric utility industry due only to the CCR rule, not including the 

burden for meeting baseline (i.e., existing) state regulations.

As mentioned in Chapter 2, no parts of the CCR final rule have direct regulatory requirements 

that would require industries other than the coal-fired electric utility industry to incur compliance 

costs. To the extent that other industries, such as the commercial waste transportation industry, 

the commercial waste disposal industry are affected by the CCR final rule, impacts on these 

industries are expected to be positive, based on an increased demand for transportation and offsite disposal of CCR. This RIA addresses the potential impacts associated with increases in offsite disposal of CCR in Section 7.1.6 by comparing the future annual tonnages of CCR which 

may switch from on-site surface impoundments to offsite landfill disposal, compared to the 

recent 2010 capacities of off-site commercial industrial landfills.

4.2 CCR Pollution Control Cost Elements 

Central to this RIA’s cost estimate are the incremental costs to the electric utility industry to 

comply with 10 CCR pollution controls and compliance actions specified under the final CCR 

rule. In addition to the industry costs, this RIA also estimates the incremental costs to state 

governments to administer the CCR final rule. The CCR pollution control requirements include 

both “unit-level” actions that vary directly with the size and type of CCR management unit (e.g., 

groundwater monitoring, leachate collection, and fugitive dust control) and also “plant-level” 

requirements (e.g., corrective action and recordkeeping). The 10 separate CCR pollution control 

requirements and compliance actions that contribute to the cost estimate are listed below, along 

with administrative costs and the costs to convert to dry management of CCRs.

The remainder of this section describes the assumptions and cost estimates for each of these 

requirements. For unit-level costs that are included in the baseline cost estimates in Chapter 3, 

this section briefly summarizes the cost assumptions for the CCR final rule. Estimation of these 

costs employs the same data sources and methodology used to estimate baseline costs. For unitlevel costs not included in the baseline cost estimates in Chapter 3, this section provides more 

detailed information on the derivation of the cost inputs used in the STATA-based model to 

estimate compliance costs of the CCR final rule.

Unit-level costs are described in Sections 4.2.1 through 4.2.9. They include: 

1. Groundwater monitoring;

2. Composite liners;

3. Leachate collection systems;
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4. Fugitive dust controls;

5. Rain and surface water run-on/run-off controls;

6. Disposal unit location restrictions – water tables, floodplains, wetlands, fault 

areas, seismic zones, and karst terrain;

7. Closure capping to cover unit; and

8. Post-closure groundwater monitoring; 

Plant-level costs and compliance actions (e.g., conversion to dry handling) associated with the 

final CCR rule are described in Sections 4.2.10 through 4.2.12. They include:

9. Structural integrity requirements (surface impoundments only);

10. Remediation costs for corrective action;

11. Reporting and recordkeeping; and

12. Impoundment closures and conversion to dry handling to meet the landfill 

disposal restriction (LDR) CCR dewatering treatment.

4.2.1 General Cost and Regulatory Requirement Assumptions

Note: EPA has updated this section of the RIA with regard to assumptions for CCR 

management in storage impoundments. These updates are not reflected in the text and 

exhibits in this section. See Section 9.2.3 in Chapter 9 of this RIA for a description of the 

relevant modifications and updates to this section. 

This RIA applies the following general cost and regulatory assumptions as described:

 RCRA design requirements. This RIA assumes that the CCR final rule requires 

the same set of CCR management unit design and CCR pollution controls, as 

enumerated in items 1 through 8 of the above list, and employs the same cost 

estimation formulas described in Chapter 3 for the estimation of baseline CCR 

pollution control costs where possible.215 This approach relies on many of the 

same engineering assumptions used in EPA’s cement kiln dust proposed rule from 

August 20, 1999.216

 Unit Cost Distribution. The decision logic used in the cost modeling compares 

costs across CCR management strategies. The cost for a given CCR management

 

215 In a few cases (e.g., location restrictions, dust controls for surface impoundments, run-on/run-off controls for surface 

impoundments and structural integrity inspections), costs for these items are derived from the cost estimation methodology 

applied to the estimation of baseline costs described in Chapter 3.

216 Federal Register, Vol.64, No.161, 20 Aug 1999, pp.45632-45697. Use of these secondary assumptions from another study 

introduces uncertainty into the cost estimates because not all costs are explicitly and uniquely estimated in relation to the electric 

utility industry. Cost uncertainties are addressed briefly in more detail in Chapter 7.
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unit with a given set of CCR pollution controls and baseline requirements is based 

on a set of Fortran equations averaged across a set of model units to create a cost 

equation unique to that CCR management unit and the specific group of pollution 

controls in place. The costs associated with each CCR pollution requirement are 

not linear, and interact with the other pollution control requirements in the set. As 

a result, this RIA cannot model costs for each unit-level pollution control 

separately and add these together to arrive at a simple total incremental cost that is 

the same as the incremental cost driven by the Fortran cost equations that consider 

all relevant unit-level pollution controls together.217

To try to isolate the relative contribution of different CCR pollution controls to 

cost, this RIA performed a separate cost modeling analysis applying each 

pollution control separately, and noting the value of the resulting costs.218 This 

RIA then used the relative values for each unit level pollution control as weights 

to apportion the total unit-level costs estimated when using the model to calculate 

incremental costs for all pollution controls across the individual pollution 

controls.

As an example, consider a simplified model with three CCR pollution controls. 

Running the model with all three pollution controls yields a total unit-level cost of 

$25 in the baseline and $50 under the CCR rule, or an incremental cost of $25. 

Running the model with the first pollution control only yields a baseline cost of 

$1 and a cost of $4 under the CCR rule, or an incremental cost of $3. For the 

second and third pollution controls, the model yields baseline costs of $14 and 

costs of $20 each under the CCR rule, or incremental costs of $6. This 

methodology would then apportion approximately 20% (i.e., $3 divided $15, the 

sum of $3, $6, and $6) of the total incremental cost of $25, or approximately $5, 

to the first pollution control, and approximately 40% (i.e., $6 divided by $15) of 

$25, or approximately $10 to each of the other pollution controls. Total 

incremental costs across these three pollution controls would then add to $25, or 

the total incremental cost.

While this method allows for fair apportionment of costs across unit-level 

pollution controls, it does not directly estimate the costs associated with each 

 

217 One example of this limitation is as follows: a given disposal impoundment may cost $5 per ton to operate with no CCR 

pollution controls, and $10 per ton if it were to “switch” to off-site disposal. Adding one pollution control with a cost of $1 per 

ton will add the total cost of the impoundment to $6 per ton. However, adding a second pollution control with a cost of $5 per ton 

will add only $4 to the total cost of the unit, as it would “switch” to off-site disposal upon reaching a decision point (closure due 

to reaching the end of its operating life or experiencing a groundwater contamination event in an out-year if the impoundment 

was unlined). After that point, additional unit-level pollution controls would not change the cost in all years after the unit 

“switches,” as that decision has already been made once total impoundment costs increased above $10 per ton. As a result, cost 

modeling in this manner is sensitive to the order the pollution controls are added, which does not reflect a reality where all 

pollution controls are required simultaneously. It is possible that simultaneous pollution control supply bottlenecks could increase 

costs above those estimated in this RIA, though in most cases pollution controls reflect standard technologies and materials.

218 In these modeling runs, the pollution control was assumed to be present if required by state regulatory requirements in the 

baseline, and added to newly-constructed units under the CCR final rule.
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control given the nonlinear relationship between the addition of a control and the 

resulting unit-level cost.219

 Liner requirements and retrofits. This RIA assumes that liner requirements 

apply to future new CCR landfills and to future new impoundments and to new 

future lateral expansions of existing disposal units, while leachate collection 

system requirements apply to future new CCR landfills but not CCR 

impoundments.

220, The analysis conducted for this RIA determined that the cost 

to retrofit an existing disposal impoundment with a remaining disposal capacity of 

less than 40 years is generally prohibitive compared to the cost to construct a new 

on-site landfill or disposal impoundment with a full 40-year capacity.

 Disposal and storage. As noted in Chapter Section 2.3.5, this RIA assumes that 

the universe of 735 active, on-site surface impoundments is broken down into 142 

disposal impoundments and 593 storage impoundments. Given that storage 

impoundments are not the final destination for CCRs but are dredged out 

regularly, this RIA assumes that a portion (25%) of the wet-disposed CCR 

associated with each plant is handled in storage impoundments in order to derive 

costs for storage impoundments (where storage impoundments are present but 

EIA reportsdata indicate no wet CCR disposal at a plant, this RIA uses 

impoundment capacity as a proxy for the potential tonnage that could be managed 

for cost estimation).221 This RIA assumes that off-site CCR disposal units are 

commercially-owned landfills (i.e., owned by the waste management industry), 

and that they comply with applicable CCR pollution controls in the baseline such 

that adequate off-site disposal capacity is available.

 100% compliance. Under the CCR final rule, plants must comply with RCRA 

Subtitle D criteria regardless of existing state standards. This RIA assumes 100% 

compliance under all options. See Section 7.3 for additional discussion regarding 

alternative compliance assumptions.

 Economies of scale. This RIA does not account for any economies of scale 

resulting from co-located (adjacent) CCR management units. For example, colocated units can share groundwater monitoring wells to meet groundwater 

monitoring requirements, rather than requiring separate sets of wells for each unit. 

However, to avoid understating costs, this RIA accrues CCR pollution control 

costs to each applicable unit. The only exception to this is the cost estimation 

applied for post-rule structural integrity inspections for surface impoundments; 

 

219 Unit-level pollution controls to which this RIA applies this methodology include groundwater monitoring, liners, leachate 

collection systems, dust controls, run-on/run-off controls, closure capping, and post-closure monitoring. For location restrictions, 

the cost modeling assessed baseline and final rule costs directly by considering those disposal units affected by location 

restrictions in the baseline and under the CCR rule.

220 The language under the CCR final rule for surface impoundments allows liners to be retrofitted onto existing units. However, 

investigation into this issue indicated that creation of a new surface impoundment is more cost effective than retrofit of an 

existing surface impoundment with a bottom liner.

221 In these cases, this RIA applies the 25% storage impoundment tonnage scaling factor to this estimated impoundment capacity 

tonnage.
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see Section 4.3.10. In this one case, economies of scale arise from the ease of 

conducting multiple inspections at one plant.

 Use of probabilistic analysis costs to counter uncertainty regarding various 

components of the cost estimation process. Where applicable, this RIA applies 

probabilistic analysis of underlying probability distributions in order to estimate a 

distribution of potential compliance costs associated with the CCR rule. The latter 

parts of this chapter present a median estimate obtained via the probabilistic 

simulations performed by the STATA-based model. Items handled via 

probabilistic analysis include:

o Whether disposal and storage impoundments are considered lined or 

unlined if their current liner status is unknown, where the proportion 

mapped as lined or unlined is based on the underlying distribution of lined 

and unlined impoundments across those for which liner status is known;

o When a groundwater contamination event occurs for unlined 

impoundments and prompts impoundment closure, based on a probability 

distribution that maps the likelihood of a groundwater contamination event 

to impoundment age;

o Whether landfills and surface impoundments subject to location 

restrictions will be able to demonstrate and continue operating, or whether 

disposal associated with those units must shift off-site; and

o The type of structural integrity inspection that certain impoundments are 

subject to following the implementation of the final CCR rule, if certain 

impoundment characteristics are not otherwise known, where the 

probabilistic distribution is based on the breakdown of impoundments 

with known characteristics (see below).

In addition, this RIA applies a number of probabilistic analyses to estimate the sensitivity of its 

results to variation in certain inputs, described in more detail in Chapter 7.

The following sections summarize the unit-level and plant-level CCR pollution control costs 

applied in this RIA under the final CCR rule. Again, some unit-level CCR pollution control costs 

do not differ from baseline CCR pollution control costs discussed in Chapter 3. The incremental 

costs for these requirements reflect the number of existing and newly-constructed CCR 

management units that must incur each cost under the rule. Costs differ for structural integrity 

inspections, dust controls for surface impoundments, and run-on/run-off controls for surface 

impoundments either in basis or in usage within the STATA-based model from the baseline 

scenario. Thus, this chapter presents detailed calculation and usage information for these cost 

components.

The Fortran-based model annualizes the unit-level pollution control cost components over an 

assumed lifespan of 40 years for a disposal impoundment. In cases where the cost estimation 

modeling determines that an impoundment must close prior to this 40-year assumed lifespan, 
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these costs continue to be applied for the 40-year period to capture the sunk costs associated with 

the construction of the impoundment. This is done to ensure that facilities do not incur an 

inadvertent cost savings when their impoundments are determined to have a groundwater 

contamination event and must close.

4.2.2 Groundwater Monitoring Cost Estimates

This RIA uses the Fortran-based equations applied in Chapter 3 to estimate new unit 

construction for units with 40-year capacities. In addition, consistent with the implementation 

date for the CCR final rule, this RIA applies annualized groundwater monitoring costs to existing 

units over the remaining lifespan of the unit, if groundwater monitoring was not already present 

at the unit according to the state regulatory baseline. For example, if the disposal unit is 10 years 

old in 2015, costs are annualized over the remaining 27 years of the unit’s life beginning in 2015 

(the remaining life is reduced by two years because the groundwater monitoring requirement 

does not take effect until one year following the effective date of the rule, i.e., 2017. (The 

effective date of the rule is 6 months after publication in the Federal Register), and the unit is not 

assumed to incur costs at the end of Year 40 of its operating life because it has undergone 

closure). This RIA applies groundwater monitoring costs under the CCR final rule to all existing 

and newly-constructed on-site disposal units. Groundwater monitoring costs vary with unit size 

and design, and are not constant across affected units.

4.2.3 Bottom Liner Cost Estimates

This RIA uses the formula applied in Chapter 3 to estimate the costs of bottom liners for 

construction of a new CCR management unit, assumed to have a 40-year capacity as a central 

estimate. Existing landfills are not required to retrofit under the CCR final rule. Under the CCR 

final rule, unlined disposal impoundments have the option of closure and opening of a new, lined 

disposal impoundment if a groundwater contamination event occurs; this RIA’s analysis 

determined that retrofitting existing impoundments is not typically cost-effective compared with

closure. The CCR final rule requires bottom liners for newly-constructed on-site CCR landfills 

and impoundments. Bottom liner costs vary with unit size and design, and are not constant across 

affected units.

4.2.4 Leachate Collection System Cost Estimates

This RIA uses the cost estimation formula applied in Chapter 3 to estimate leachate collection 

system costs for construction of new CCR management unit, assumed to have a 40-year capacity 

as a central estimate. The CCR final rule requires leachate collection systems for all newlyconstructed on-site landfills, but not surface impoundments. Leachate collection system costs 

vary with unit size and design, and are not constant across affected units.

4.2.5 Fugitive Dust Control Cost Estimates
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4.2.5.1 Landfill Dust Control

As formulated and applied in this RIA to all of the relevant annual on-site and off-site CCR 

disposal tonnage, the cost estimate associated with the CCR dust control requirement for the 

CCR final rule represents an additional cost above the existing (baseline) RCRA 40 CFR 258.21 

blowing liter control requirements222 for municipal solid waste landfills (MSWLFs).

This RIA uses the formula applied in Chapter 3 to estimate dust-control costs for construction 

of new landfills with 40-year capacities. In addition, this RIA adds annualized fugitive dust 

control costs to management costs for existing units over the remaining lifespan of the unit (i.e., 

landfill).

The CCR final rule requires the following five fugitive CCR dust control requirements:

 Control measures: Electric utility plants must control fugitive CCR dust at CCR 

landfills, CCR surface impoundments, lateral expansions of CCR landfills and 

CCR surface impoundments, and associated disposal operations including 

conveying equipment, storage systems, and transfer and loading systems. Utility 

plants must manage CCR in a manner that prevents emissions of CCR fugitive 

dust by controlling wind dispersal through the implementation of at least one of 

the following eight control measures, as appropriate:

1. Locating the CCR inside an enclosure or partial enclosure;

2. Reducing fall distances at material drop points;

3. Installing and operating a water spray or fogging system (where 

appropriate, utility plants may select chemical dust suppression agents 

instead of water as a measure to control wind dispersal);

4. Applying appropriate dust suppression agents on the source;

5. Using wind barriers, compaction; or vegetative cover;

6. Lowering and/or enforcing vehicle speed limits on unpaved roads;

7. Covering all CCR hauling trucks; and/or

8. Applying a daily cover.

 Control plan: Furthermore, utility plants must document in a CCR fugitive dust 

control plan all control measures taken to minimize CCR fugitive dust. The CCR 

fugitive dust control plan must be reviewed, and if necessary, revised every year 

 

222 40 CFR 258.21 of EPA’s 40 CFR Part 258 Criteria for Municipal Solid Waste Landfills is titled Cover material requirements

and addresses the control of disease vectors, fires, odors, and scavenging, in addition to blowing litter; it does not specifically 

address dust control as MSWLFs.
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that the facilityelectric utility plant is in operation or in closure or post-closure 

care.

 Plan updates: Utility plants must notify the state government if/when the CCR 

fugitive dust control plan has been updated and a copy has been placed in the 

operating record and on the owner’s or operator’s publicly accessible internet site. 

The updated plan must contain all of the following:

o A report of the efficacy of the measures taken pursuant to the plan during 

the preceding year including any incidents involving CCR fugitive dust; 

and

o Additional measures to be used to suppress the emission of any CCR dust 

during the current year.

 Certification: The requirements specified above must be certified by an 

independent qualified professional engineer.

 Substantive action: In the event of visible CCR fugitive dust emissions, the plant 

must take substantive action within 12 hours to ensure the health and safety of 

local residents and employees of the facilityplant. The plant must also notify the 

state government within five days of the event, and identify the steps taken to 

alleviate the condition. A copy of the notification must also be placed in the 

operating record and on the plant’s publicly available internet site.

As indicated in Chapter 3, this RIA assumes that all utility plants currently compact CCR in 

landfills, apply water during the compaction to facilitate compaction as well as to control dust, 

and spray water on unpaved roads, as a generalized and simplified representation of the 

assortment of baseline state government dust control requirements. This baseline practice 

constitutes two of eight dust control measures required under the CCR final rule. Although only 

one of the eight control measures is a requirement under the rule, for the purpose of estimating 

compliance costs, this RIA estimates the cost of placing covers on trucks transporting CCR at 

utility plants as an additional dust control requirement, in addition to the costs for five other 

requirements listed above. A detailed explanation of these requirements and their attendant costs 

can be found in Appendix K.

 Dust control covers on trucks. Capital costs for this dust control technology include the 

cost of the roll-on tarp mechanism and the installation of this mechanism. Detailed 

formulas for these capital costs can be found in Appendix K. Annual costs for this dust 

control technology include the cost of the tarps and the cost to replace the tarps. This RIA 

estimates that tarps are replaced every 150 loads, and that tarp replacement requirements 

15 minutes. Detailed formulas for these annual costs can be found in Appendix K.

 Dust control plan. This RIA assumes that a dust control plan would require eight hours of 

technical labor, 0.5 hours of clerical labor, and $5,000 in operations and maintenance 

costs to complete. This cost would occur, at most, three times over the period of analysis 

covered by this RIA, as at most, three dust control plans would need to be created for a 
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given disposal unit (given a 40 year CCR management unit lifespan). Correspondingly, 

the per-unit cost of this requirement is approximately $425 under a 7% discount rate, and 

$251 under a 3% discount rate. Because this cost pertains to recordkeeping and 

paperwork requirements, its total costs are attributed to the recordkeeping and paperwork 

requirements discussed below, rather than to the individual dust control unit level cost 

discussed in this section. For additional information on the plant-level recordkeeping and 

paperwork requirements and their estimations, see Appendix M.

 Dust control plan updates. This RIA assumes the same cost for updates to the dust 

control plan as the initial creation of the dust control plan. This RIA also assumes that 

each dust control plan would be modified once over its lifespan. Because this cost 

pertains to recordkeeping and paperwork requirements, its total costs are attributed to the 

recordkeeping and paperwork requirements discussed below, rather than to the individual 

dust control unit level cost discussed in this section. For additional information on the 

plant-level recordkeeping and paperwork requirements and their estimations, see 

Appendix M.

 Dust control certification. This RIA assumes that a dust control certification would 

require three hours of technical labor, 0.5 hours of clerical labor, and $340 in operations 

and maintenance costs to complete. This cost would occur, at most, three times over the 

period of analysis covered by this RIA, as at most, three dust control plans would need to 

be created for a given disposal unit (given a 40 year CCR management unit lifespan). 

Correspondingly, the per-unit cost of this requirement is approximately $41 under a 7% 

discount rate, and $24 under a 3% discount rate. Because this cost pertains to 

recordkeeping and paperwork requirements, its total costs are attributed to the 

recordkeeping and paperwork requirements discussed below, rather than to the individual 

dust control unit level cost discussed in this section. For additional information on the 

plant-level recordkeeping and paperwork requirements and their estimations, see 

Appendix M.

 Dust control notification. This RIA assumes that dust control notification would require 

0.5 hours of managerial labor and $3 in operations and maintenance costs to complete. As 

a conservative assumption, this RIA assumes that such a notification must be completed 

annually. Correspondingly, the per-unit cost of this requirement is approximately $61. 

Because this cost pertains to recordkeeping and paperwork requirements, its total costs 

are attributed to the recordkeeping and paperwork requirements discussed below, rather 

than to the individual dust control unit level cost discussed in this section. For additional 

information on the plant-level recordkeeping and paperwork requirements and their 

estimations, see Appendix M.

4.2.5.2 Surface Impoundment Dust Control

As noted in Chapter 3, this RIA assumes that dust control for surface impoundments is not 

required under any state regulatory baseline; correspondingly, dust control costs resulting from 

the CCR final rule are fully incremental. This RIA estimates dust control costs for 

impoundments as follows, noting that it includes a number of dust control technologies as a 
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conservative estimate in order to avoid underestimating costs associated with dust controls (all 

costs below in 2013$):

 $30,688 per acre for topsoil and seeding, annualized over 40 years as an assumed 

lifespan;

 $944 per day for a water spray truck, applied only for half the days in a given year 

based on the assumption that water spraying is not required daily;

 $2,700 per acre for a long-term Posi-Shell treatment assumed to last for one year;

 $1,000 per week for a stationary sprayer (dust boss); and

 $1,600 per acre for soil “sement,” applied semiannually.223

In general, however, this RIA assumes that for surface impoundments, ash is sluiced from the 

boiler or air pollution control device to the pond, and never handled as “dry” ash. This RIA also 

assumes that all surface impoundments undergo closure as landfills, meaning that surface 

impoundments are not excavated, nor is their ash trucked off-site. In summary, dust controls are 

generally unnecessary for surface impoundments, except in cases where frozen wet ash (due to 

low temperatures) combines with high wind speeds to lead to fugitive dust associated with frozen 

wet ash from surface impoundments.224

In order to scale down the dust control costs given that dust controls may not be needed in most 

cases, this RIA collected historical data on the number of freezing, high-wind days in each state; 

on average, states have experienced fewer than two freezing, high-wind days a year. For each 

surface impoundment, this RIA scales down the dust control costs above by the number of 

freezing, high-wind days in the state in which the impoundment is located. As a result, these 

scaled-down annual costs for dust controls for surface impoundments are relatively low and 

average no more than $3,000 per year, depending on impoundment acreage and the state.225

These costs are consistent with assumptions regarding the need for dust controls at 

impoundments and the associated dust control costs for landfills, which are approximately 

$30,000 per year.

4.2.6 Rain and Surface Water Run-On/Run-Off Control Cost Estimates

This RIA uses the formula applied in Chapter 3 to estimate run-on/run-off control costs for 

construction of new landfills with 40-year capacities. In addition, this RIA adds run-on/run-off 

control costs to existing landfill annualized over the remaining lifespan of the landfill. 

 

223 Engineers from GZA Geoenvironmental provided inputs that reflected expert judgment and institutional knowledge based on 

the company’s extensive experience with the electric power industry.

224 Some very large surface impoundments or impoundments in dry, desert-like areas may also have portions of their CCR and/or 

periods of time when their contents may become dry enough to require CCR dust controls. This RIA uses the frozen, high-wind 

days scenario as a proxy for these cases as well.

225 In cases where impoundment acreage was not available from the impoundment identification and survey data discussed in 

Chapter 2, this RIA applied equations based on average impoundment dimensions if other dimensions (e.g., impoundment 

capacity, impoundment depth, etc.) were available. In cases where no impoundment dimension data were available, this RIA 

maps each impoundment to the average acreage among all impoundments.
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For surface impoundments, research conducted by this RIA indicated that run-on/run-off controls 

are site-specific and attendant costs either to retrofit existing impoundments with appropriate 

run-on/run-off controls or to build appropriate run-on/run-off controls as part of new 

impoundment constructions are difficult to generalize. In addition, prior research indicated that 

surface impoundments can be constructed with a type of elevated earthen berm (freeboard to 

prevent wave overtopping) surrounding the unit as part of the impoundment structure. This 

earthen berm would prevent any storm water run-on into the impoundment, as well as storm 

water and pond water run-off from the impoundment. However, to ensure that cost of runon/run-off controls at surface impoundments are not understated, this RIA applies a central 

estimate cost of $340,000 per impoundment in capital costs, which is then annualized over a 40-

year assumed lifespan.226 The resulting costs are generally similar to run-on/run-off control costs 

for landfills (less than $0.07 per ton, plus $5,000 to $7,000).

4.2.7 Disposal Unit Location Restriction Cost Estimates

The CCR final rule contains six site location restrictions (i.e., water table, floodplain, wetlands, 

fault area, seismic zone, and unstable areas such as karst areas). However, this RIA specifically 

evaluates the impacts of three of these restrictions: fault areas, seismic zones, and karst areas. 

The RIA assumes that the open dumping floodplains restriction applies to all disposal units in the 

baseline, and does not estimate costs associated with the remaining two restrictions due to a lack 

of data regarding applicability of these restrictions to existing CCR management units. Exhibit 

4-B lists location standards for the final CCR rule. This RIA uses the following methodology to 

estimate regulatory disposal unit location restriction costs:

Under the CCR final rule, if a plant is located in a restricted area, CCR disposal must be rerouted 

off site when the existing CCR disposal unit reaches its 40-year life expectancy, although in 

some cases plants may be able to make sufficient demonstrations to allow continued on-site CCR 

disposal. This RIA evaluates the impacts of location restrictions for fault, seismic impact, and 

karst areas. See Appendix L for plant-specific data.227

 Fault areas. The CCR rule would ban the location of new CCR landfills and any surface 

impoundment within 200 feet (60 meters) of faults that have experienced displacement 

during the past 11,000 years (i.e. in the Holocene Epoch) unless sufficient demonstration 

can be made regarding the safety and appropriateness of design of the CCR management 

unit.228 This RIA uses the U.S. Geological Survey (USGS) Quaternary Fault and Fold 

 

226 Engineers from GZA Geoenvironmental provided inputs that reflected expert judgment and institutional knowledge based on 

the company’s extensive experience with the electric power industry.

227 Data obtained from attachments to “Vulnerability Criteria Information for Coal Combustion Residuals Plants Revised 

Technical Directive 4-3, WA 1-02, EPA Contract # EP-W-09-004,” memorandum from Robert Truesdale, RTI International, to 

Becky Cuthbertson, EPA Office of Resource Conservation and Recovery, December 31, 2010.

228 The CCR rule defines a fault to include a zone or zones of rock fracturing in any geologic material along which there has been 

an observable amount of displacement of the sides relative to each other. Faulting does not always occur along a single plane of 

movement (a ‘‘fault’’), but rather along a zone of movement (a ‘‘fault zone’’). Therefore, ‘‘zone of fracturing,’’ which means a 

fault zone in the context of the definition, is included as part of the definition of fault, and thus the 200-foot setback distance will 

apply to the outermost boundary of a fault or fault zone. 
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Database of the United States229 to determine the distance of the nearest fault to the CCR 

plant centroids, although this centroid may be one or two kilometers from on-site CCR 

disposal units.,230 Only seven plants have active faults within two miles of their centroids; 

six of these plants are located in western states.231

This RIA does not evaluate state-specific set-back distance standards. Under the final 

rule, this RIA assumes a 200-foot setback standard. Given that a plant’s centroid may be 

one or two miles away from the on-site unit, this RIA uses a two-mile standard to identify 

which plants located in fault zone areas may be forced to dispose waste off site when 

their current CCR disposal units reach capacity. 

Overall, this RIA identifies only nine CCR management units (two landfills and seven 

disposal impoundments) that are affected by the fault area location restriction beyond 

those CCR management units already affected by state regulatory baseline fault area 

location restrictions. Only one landfill was determined by this RIA to be subject to fault 

area site restrictions in the baseline.

 Seismic impact areas. This RIA defines a seismic impact area as “an area with a 2% or 

greater probability that the maximum horizontal acceleration in lithified earth material, 

expressed as a percentage of the earth’s gravitational pull (g), will exceed 0.10 g in 250 

years.”232 Under the final CCR rule, this RIA assumes that plants located in seismic 

impact zones would be required to dispose of CCR off-site when their current CCR 

disposal units reach capacity, as opposed to making modifications to the design of the 

unit, unless sufficient demonstration can be made regarding the safety and 

appropriateness of design of the CCR management unit.233 As a representative cut-off 

point, this RIA assumes that all plants located in areas with a 2% per 50-year probability 

of exceedence and a peak ground acceleration greater than 0.5 g will shift to off-site 

landfill disposal when their current units reach capacity.

 

229 USGS source at http://earthquake.usgs.gov/hazards/qfaults/

230 EPA conducted this analysis in 2009 prior to identifying 12 additional electric utility plants potentially affected by the CCR 

rule.

231 “Vulnerability Criteria Information for Coal Combustion Residuals Plants Revised Technical Directive 4-3, WA 1-02, EPA 

Contract # EP-W-09-004,” memorandum from Robert Truesdale, RTI International, to Becky Cuthbertson, EPA Office of 

Resource Conservation and Recovery, December 31, 2010.

232 The regulatory standard (which has not been compared to the individual state standards in this RIA) is that any unit in seismic 

impact zones must be designed to resist the maximum horizontal acceleration in lithified earth material for the site. The design 

features to be protected include all containment structures (i.e., liners, leachate collection systems, and surface water control 

systems). The demonstration must be certified by an independent registered professional engineer and the owner or operator must 

notify the state that the demonstration has been placed in the operating record and on the company’s internet site. 

233 Data have been collected based on 50 years instead of 250 years. For 473 of the 478 electric utility plants, data were collected 

from USGS National Seismic Hazard Maps (http://earthquake.usgs.gov/hazards/products/conterminous/2008/update_201001) to 

determine which plants are located in areas with peak ground acceleration (PGA) that has a 2% probability of occurring in 50 

years. Of these 473 plants:

 146 have a PGA 2% per 50 year probability of exceedence (PE) greater than 0.1 g

 55 are greater than 0.2 g.

 11 plants with a 2% per 50 year PE PGA greater than 0.5 g are located mainly in the vicinity of the New Madrid, MO, and 

Charleston, SC, earthquake centers.

See also “Vulnerability Criteria Information for Coal Combustion Residuals Plants Revised Technical Directive 4-3, WA 1-02, 

EPA Contract # EP-W-09-004,” memorandum from Robert Truesdale, RTI International, to Becky Cuthbertson, EPA Office of 

Resource Conservation and Recovery, December 31, 2010.
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Overall, this RIA identifies only 13 CCR management units (nine landfills and four 

disposal impoundments) that are affected by the seismic impact area location restriction 

beyond those CCR management units already affected by state regulatory baseline 

seismic impact area location restrictions. Only three landfills and two disposal 

impoundments were determined by this RIA to be subject to seismic impact area site 

restrictions in the baseline.

 Karst areas. This RIA defines karst as areas underlain by soluble bedrock, generally 

limestone or dolomite, and may contain extensive subterranean drainage systems and 

relatively large subsurface voids whose presence can lead to the rapid development of 

sinkholes.234,235 Under the final rule, this RIA estimates the number of plants located in 

karst areas that would be required to seek off-site disposal in Year 4 of the analysis (when 

this location restriction goes into effect), as opposed to making modifications to the 

design of the unit, unless sufficient demonstration can be made regarding the safety and 

appropriateness of design of the CCR management unit.236

Overall, this RIA identifies 21 CCR management units (nine landfills and 12 disposal 

impoundments) that are affected by the unstable areas location restriction beyond those 

CCR management units already affected by state regulatory baseline unstable area 

location restrictions. Only five landfills and three disposal impoundments were 

determined by this RIA to be subject to unstable area site restrictions in the baseline.

As in the baseline, this RIA probabilistically assesses whether or not a given CCR management 

unit will have to shift to offsite disposal due to a location restriction, or whether a plant will be 

able to provide adequate demonstrations and certifications to continue using on-site disposal of 

CCR. As a simplifying assumption that allows for the greatest distributional variance, this RIA 

assumes that in half of all cases, an adequate demonstration will be made, while in the other half, 

disposal will have to shift off-site once the CCR management unit closes. Because, in the 

baseline, CCR storage impoundments are not modeled as closing, these restrictions apply only to 

landfills and disposal impoundments. Given that only 22 disposal impoundments and 29 landfills 

are identified as subject to CCR final rule site restriction requirements (for fault areas, seismic 

 

234 The regulatory standard (which has not been compared to the individual state standards in this RIA) is to allow the 

construction of new CCR units, and the continued operation of existing CCR landfills and surface impoundments in karst terraces 

where the owner or operator can demonstrate that engineering measures have been incorporated into the landfill, surface 

impoundment, or lateral expansion design to ensure that the integrity of the structural components of the landfill or surface 

impoundment will not be disrupted. The demonstration must be certified by an independent registered professional engineer, and 

the owner or operator must notify the state that the demonstration has been placed in the operating record and on the company’s 

internet site.

235 This RIA estimates that uses a 2 km radius around each plant centroid, and determined that about 29% of the 478 electric 

utility plants examined are within the karst polygons defined in the USGS map developed by Davies et al. (1984) at 

http://pubs.usgs.gov/of/2004/1352/ see also “Vulnerability Criteria Information for Coal Combustion Residuals Plants Revised 

Technical Directive 4-3, WA 1-02, EPA Contract # EP-W-09-004,” memorandum from Robert Truesdale, RTI International, to 

Becky Cuthbertson, EPA Office of Resource Conservation and Recovery, December 31, 2010.

236 In this case, high relative karst likelihood includes “long-2” and “long-3” karst:

 Long-2 karst includes fissures, tubes, and caves over 1,000 ft (300 m) long; 50 ft (15 m) to over 250 ft (75 m) vertical 

extent; in moderately to steeply dipping beds of carbonate rock.

 Long-3 karst includes fissures, tubes, and caves over 1,000 ft (300 m) long; 50 ft (15 m) to over 250 ft (75 m) vertical 

extent; in gently dipping to flat-lying beds of carbonate rock.
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zones, and unstable areas only), this RIA models that on average, 26 CCR disposal units will 

shift to off-site disposal in the baseline as a result of location restrictions, which is only 19 units 

beyond those modeled to shift to offsite in the baseline as a result of location restrictions.237

In cases where an adequate certification is deemed to be made, the cost model applies a nominal 

certification cost to the cost equation; for more information on this certification cost, see the 

discussion of recordkeeping and reporting costs in Chapter 3. Relative to other CCR 

management costs, this certification cost is very low and does not drive the decision logic of the 

model in those cases where an adequate certification is deemed to be made. 

Appendix L presents site location data for each coal-fired electric utility plant for fault areas, 

seismic zones, and unstable areas.

Exhibit 4-B

CCR Disposal Unit Location Standards

(location standards at 40 CFR 257.6)

Placement above the 

seasonal water table

New CCR landfills, existing and new CCR surface 

impoundments, and lateral expansions

Wetlands New CCR landfills, existing and new CCR surface 

impoundments, and lateral expansions

Fault Areas New CCR landfills, existing and new CCR surface 

impoundments, and lateral expansions

Seismic Impact Zones New CCR landfills, existing and new CCR surface 

impoundments, and lateral expansions

Unstable Areas New or existing CCR landfills, new or existing CCR 

surface impoundments and lateral expansions

4.2.8 Closure Capping to Cover Unit Cost Estimates

This RIA uses the formula applied in Chapter 3 to estimate closure capping costs for 

construction of new units with 40-year capacities. In addition, this RIA adds closure capping 

costs to existing units. This RIA annualizes closure capping costs over a 40-year period and 

applies these costs in the 40 years following unit closure. All options require closure capping for 

all existing and newly-constructed on-site disposal units.

4.2.9 Post-Closure Groundwater Monitoring Requirement Cost Estimates

This RIA uses the formula applied in Chapter 3 to estimate post-closure monitoring costs for 

construction of new units with 40-year capacities. This RIA annualizes post-closure monitoring 

costs over a 40-year period and applies these costs in the 40 years following unit closure. All 

options require post-closure monitoring for all existing and newly-constructed on-site disposal 

units.

4.2.10 Structural Integrity Evaluation Cost Estimates

 

237 However, it is worth noting that the unstable areas location restriction affects existing units under the CCR final rule, whereas 

in the baseline, it affects only new CCR units. This is the only of the location restrictions modeled that can prompt a decision 

point and unit closure, as opposed to only forcing offsite disposal once a unit has already closed.
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As discussed in Chapter 3, this RIA applies a generic structural integrity evaluation cost to 

62.5% of all existing CCR impoundments. Under the CCR final rule, however, this RIA assumes 

that surface impoundments will be subject to more detailed and comprehensive evaluations, and 

that inspection length and cost may differ from impoundment to impoundment.

Specifically, for the CCR final rule scenario, this RIA attempts to classify impoundments as 

subject to relatively less stringent structural integrity inspections or relatively more stringent 

structural integrity inspections, based on impoundment size:238

 Subject to “more stringent” structural integrity inspections:

o An impoundment height of 20 feet or more; or

o An impoundment height of 5 feet or more and an impoundment capacity 

of 20 acre-feet or more.

 Subject to “less stringent” structural integrity inspections:

o All impoundments not meeting the criteria for “more stringent” 

inspections above.

Using the impoundment characterization data described in Chapter 2, this RIA was able to 

classify 665 of the 735 existing surface impoundments. Of these 665, 445 (70%) had sufficient 

height and/or capacity to be classified as subject to the “more stringent” structural integrity 

inspections, and the remaining 220 (30%) were classified as subject to the “less stringent” 

structural integrity inspections. The remaining 70 impoundments are then probabilistically 

classified as subject to either the “more stringent” structural integrity inspections (70% 

probability) or the “less stringent” inspections (30% probability).

This RIA reflects information on typical inspection costs in order to construct profiles of “more 

stringent” and “less stringent” structural stability inspections. This RIA currently assumes that 

“more stringent” inspections simply add additional cost components related to the inspection on 

and above those components included in the “less stringent” inspection regime. Because 

structural stability inspections costs include some economies of scale (e.g., travel by surveyors 

and engineers to and from the site) for co-located impoundments, the costs are not expressed on 

a unit-by-unit basis, though the STATA-based model calculates them as such.239 Specifically:

 “Less stringent” inspections (all costs 2013$):

 

238 Impoundment dimensions for this analysis (height and acre-feet of capacity) were initially obtained from the ORCR 2009-

2012 impoundment surveys. If data were not available for an impoundment via these surveys, this RIA attempted to obtain 

additional dimension data from an impoundment characterization of 732 surface impoundments performed by RTI International. 

If sufficient height and capacity data from neither source were available for an impoundment, this RIA assigns an impoundment 

to one type of inspection or the other based on the proportion of impoundments with available data that meet the criteria for one 

type of inspection versus another.

239 Engineers from GZA Geoenvironmental provided inputs that reflected expert judgment and institutional knowledge based on 

the company’s extensive experience with the electric power industry.
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o $18,000 for every plant with an existing surface impoundment for a visual 

inspection of the site and all impoundments therein;

o $10,000 for the first surface impoundment at a plant for a hydrologic and 

hydraulic analysis of the impoundment, attributed to a disposal 

impoundment at the plant if the plant has any disposal impoundments, or a 

storage impoundment chosen at random otherwise; and

o $5,000 for each surface impoundment beyond the first at a plant for 

additional hydrologic and hydraulic analyses, with economies of scale for 

additional impoundments factored in (since each plant has at most one 

disposal impoundment, this means either each storage impoundment at a 

plant incurs a $5,000 cost, or one storage impoundment incurs a $10,000 

cost and the rest incur a $5,000 cost).

 “More stringent” inspections (all costs 2013$):

o $12,000 for each surface impoundment for subsurface explorations;

o Another $12,000 for the first surface impoundment meeting the “more 

stringent” inspection criteria at a plant for slope stability analyses and any 

required remediation or corrective action (again, applied either to the 

disposal impoundment at the plant, or a storage impoundment at the plant 

if the plant has no disposal impoundments); and

o $6,000 for each surface impoundment beyond the first at a plant meeting 

the “more stringent” inspection criteria at a plant for additional slope 

stability analyses and any required remediation or corrective action, with 

economies of scale for additional impoundments factored in.

Under both the CCR final rule and the baseline, plants may shift disposal from existing on-site 

disposal impoundments towards on-site or off-site landfills that do not have structural integrity 

inspection requirements. Because these costs apply only to surface impoundments, for any 

disposal impoundment that is estimated to under either the baseline or the final CCR rule 

scenario, this RIA does not accrue the costs of structural integrity inspections upon closure. In 

other words, the RIA does not account for integrity inspection costs for surface impoundments 

that are modeled to close.

4.2.11 Corrective Action Remediation Cost Estimates

Under the CCR final rule, unit-level correction action will be required.240 To estimate the 

average cost to utility plants for complying with the unit-level corrective action requirement, this 

RIA uses an average corrective action cost based on an 2004 EPA report, “Cleaning up the 

Nation’s Waste Sites: Markets and Technology Trends” that provides RCRA corrective action 

 

240 For RCRA corrective action requirements under Subtitle D, see 40 CFR 257.21–257.28.
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costs. 241 This report includes a sample of over 3,800 sites likely to require corrective actions, 

with attendant costs for each one. Given that RCRA facility-wide corrective action (under 

Subtitle C) is more costly than RCRA waste management unit-level corrective action (under 

Subtitle D), this RIA excludes the highest tier of costs included in this report (345 sites, or 9% of 

sites, with per-site costs above $50 million) and uses the remaining 3,500 sites with per-site costs 

below $50 million as the basis for the unit-level corrective action costs associated with the rule. 

Exhibit 4-C recreates the distribution of sites and attendant costs found in the report.

 

241 See p. 4-16 of the 2004 EPA report, Cleaning up the Nation’s Waste Sites: Markets and Technology Trends, http://www.cluin.org/download/market/2004market.pdf. This report cites this number as derived in an EPA survey published in 2002, titled the 

RCRA Corrective Action Implementation Database, RCAID of EPA regional offices and of state government RCRA regulations 

responsible for RCRA Corrective Action program implementation by regulated industries. The survey was nationwide, based on 

a statistically-representative sample of 84 facilities among 889 corrective action sites that ahd final remedies selected or 

stabilization measures in place as of 1997. The report further indicates that relative to the $11.4 million average cost ($2003), 

over 50% of industrial facilities involved in RCRA corrective action projects had remediation costs under $5 million ($2003) and 

at the upper end, 9% of affected facilities had costs over $50 million ($2003).
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Exhibit 4-C

Estimated RCRA Corrective Action Costs from “Cleaning up the Nation’s Wastes: Markets and 

Technology Trends” (EPA 2004 Report)

Cost 

($millions)

% of 

Sites

Cost per Site ($millions) No. of 

Sites

Total Cost ($millions) Average Cost 

Low High Low High ($millions)

< $1.0 32% $0.2 $1 1,225 $245 $1,225 $735

$1 - $5 24% $1 $5 919 $919 $4,595 $2,57

$5 - $10 13% $5 $10 498 $2,489 $4,978 $3,734

$10 - $25 20% $10 $25 766 $7,658 $19,145 $13,402

$25 - $50 2% $25 $50 77 $1,915 $3,829 $2,872

> $50 9% $51 $70 345 $17,575 $24,123 $20,849

Total 100% 3,829 $30,800 $57,895 $44,347

Total (excl. 

>$50M) 91% 3,484 $13,225 $33,772 $23,499

Source: http://www.clu-in.org/download/market/2004market.pdf

Note: The $0.2 million and $70 million endpoints of ranges are made as conservative estimates.

As shown in Exhibit 4-C, this RIA uses the assumes that unit-level corrective action costs do not 

include any costs characterized as the highest-tier corrective action costs in excess of $50 million 

per site. Excluding this tier of costs yields an average per-site (i.e., per-unit, in this case) 

corrective action cost of $6.7 million (2003$), based on the total cost of $23,499 million divided 

by 3,484 sites.242 Inflating this cost to 2013$ from 2003$ yields a total per-site cost of 

approximately $8.3 million. This RIA assumes that a plant will have at most one corrective 

action in the 100-year period of analysis, and correspondingly annualizes this cost over 50 

years.243 The resulting annualized cost is $0.6 million under a 7% discount rate, and $0.3 million 

under a 3% discount rate.

As of 2008, the RCRA Subtitle C corrective action applied to 3,800 sites nationwide.244 Relative 

to the RCRA-regulated universe of 17,500 facilities subject to corrective action, applying RCRA 

corrective action to 3,800 sites implies a relative incidence of occurrence of 21.71%.245

Multiplying this relative incidence of occurrence by the annualized corrective action cost yields a 

probability-weighted industry cost of $0.13 million annually per plant under a 7% discount rate 

and $0.07 million annually per plant under a 3% discount rate.

This RIA estimates government agency oversight average costs at 2% of the $683 million capital 

costs associated with corrective action based on 3,800 sites.246 When annualized over 50 years 

government agency oversight costs for corrective action come to $12,000 per plant per year 

under a 7% discount rate, or approximately $6,000 under a 3% discount rate. The probability-

 

242 This cost is calculated by taking the average total cost of $23,498,573,000 on p. 4-16 of the report, which excludes the average 

cost of the “greater than $50 million per site” category, and dividing it by the 3,484 facilities that do not fall within the “greater 

than $50 million per site” category.

243 The annualization over 50 years is made as a conservative estimate. If a plant experiences once corrective action under the 

100-year period of analysis, annualizing the cost over a 100-year period would potentially remove a large proportion of the cost 

from the period of analysis if the corrective action occurred in a relatively late year.

244 3,800 corrective action cases represents EPA’s “2020 Corrective Action Universe” as identified on EPA Hazardous Waste 

Corrective Action Facility Information website at: http://www.epa.gov/waste/hazard/correctiveaction/facility/index.htm#2020

245 The RCRA-regulated universe consists of about 16,000 hazardous waste large quantity generators (LQGs), about 200,000 

hazardous waste small quantity generators (SQGs), and about 1,500 hazardous waste treatment, storage, disposal facilities 

(TSDFs). However, SQGs are not subject to RCRA Subtitle C corrective action, meaning that 3,800 of 17,500 (16,000 plus 

1,500) sites are subject to RCRA Subtitle C corrective action.

246 See U.S. Environmental Protection Agency, Cost Analyses for Selected Groundwater Cleanup Projects: Pump and Treat 

Systems and Permeable Reactive Barriers, Exhibit 3, 2001
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weighted annual costs are then $2,600 under a 7% discount rate and $1,400 under a 3% discount 

rate.

This RIA does not intertwine the corrective action costs potentially required under the CCR final 

rule with the STATA-based decision point modeling for two reasons. First, RCRA unit-level 

corrective actions at coal-fired electric utility plants and/or their CCR management units are not 

necessarily related to groundwater contamination events, though they may be. Correspondingly, 

intertwining RCRA corrective action costs with groundwater contamination events may result in 

either substantial overestimation or underestimation of RCRA corrective action costs, depending 

on the manner in which they are modeled. Second, the annualized, probability-weighted costs 

associated with RCRA corrective action described in this section are relatively low compared to 

overall compliance costs associated with other unit-level CCR pollution controls at CCR 

management units. Given that not all RCRA corrective action costs resulting from the CCR final 

rule will necessarily take place at the CCR management unit level, ascribing these costs to 

specific CCR management units introduces unnecessary uncertainty to the analysis.

With that said, the STATA-based model does accrue RCRA corrective action costs on a unitbased level; however, these costs are scaled such that plants with varying amounts of CCR 

management units incur the same corrective action costs, and that closure of CCR management 

units does not reduce the corrective action cost burden faced by these plants. 

4.2.12 Administrative Reporting and Recordkeeping Costs 

Under the CCR final rule all affected facilities in the universe must comply with 61 reporting and 

recordkeeping requirements. These requirements include the following categories:

 Demonstrations regarding unit locations in location-restricted areas (n = 9);

 Engineering certifications and recordkeeping for disposal unit and/or CCR 

pollution control designs (n = 30);

 Reporting regarding all required inspections and instrumentation monitoring (n = 7);

 Documentation regarding sampling and analysis of groundwater monitoring (n = 13);

 Reporting regarding corrective measures assessments and corrective action 

activities (n = 7); and

 Closure and post-closure plans and certifications (n = 9).247

This RIA used two ICRs to calculate the costs associated with each of the requirements. 

Appendix M provides a detailed breakdown of the individual recordkeeping requirements 

applicable under the final CCR rule. Some requirements apply annually while others recur only a 

limited number of times over the period of analysis. Similarly, some requirements apply to all 

 

247 As some reporting/recordkeeping requirements fall into multiple of these categories, the sum of these items will total greater 

than the 61 distinct requirements. Exhibit M-13 of Appendix M contains the unique list of the 61 reporting/recordkeeping 

requirements included in this category.
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on-site disposal units, while others pertain solely to surface impoundments. Overall, under a 7% 

discount rate, these reporting and recordkeeping costs sum to $24,636 per existing, on-site CCR 

management unit (regardless of whether it is a surface impoundment or landfill), an additional 

$7,235 for each existing, on-site surface impoundment, and an additional $91 for each existing, 

on-site landfill at a utility plant. As a conservatism, this RIA does not scale down recordkeeping 

costs associated with on-site CCR management units even if the cost estimation model predicts 

closure of the unit and a shift to off-site disposal. Because closure and off-site disposal is not 

predicted to be the dominant future CCR management option, and because closures generally 

happen in out-years that are more heavily discounted, this conservative measure has a negligible 

impact on overall incremental costs associated with the final CCR rule, especially because 

reporting and recordkeeping costs constitute only a small fraction of the rule’s total compliance 

costs.

4.2.13 Impoundment Closure and Conversion to Dry Handling Cost Estimates

In the baseline, disposal impoundments will close and result in a conversion to dry handling only 

when reaching the end of their operational life, and if the STATA-based cost estimation model 

determines that conversion to dry handling and disposal in an off-site or on-site landfill will 

result in lower future CCR management and disposal costs relative to opening another on-site 

disposal impoundment. Similarly, under the CCR final CCR rule, disposal impoundments may 

close and convert to dry handling. In addition, under the CCR final rule, impoundments may 

close and convert to dry handling if they are unlined and experience a groundwater 

contamination event, though in all these cases a facilityan may still choose to open a new lined 

on-site surface impoundment if that is determined to be the most cost-effective option.

If disposal impoundments close and the STATA-based model’s decision logic indicates that 

conversion to dry handling and disposal in an on-site or off-site landfill represents the least-cost 

option on a going-forward basis, the plants associated with these disposal impoundments must 

retrofit their systems to handle dry waste (i.e., they must incur wet-to-dry conversion costs). 

The cost of converting CCR management to dry handling is a key factor in the decision to 

retrofit or close impoundments both the baseline as well as the CCR final rule. However, these 

costs are highly uncertain, and actual costs vary widely depending on existing technology, age, 

and size of each plant. Ideally this RIA would use plant-specific data to estimate all costs, but 

limited information is available about specific plant costs in part because plants responding to the 

recent Office of Water survey chose to restrict access to the wet-to-dry handling conversion costs 

to preserve confidentiality. Data for this critical part of the closure conversion process are 

available only on an average cost per ton of waste basis, and it is not clear to what extent the 

costs in these data may overlap with other steps in the process laid out above (e.g., wastewater 

treatment tank systems and construction of replacement ponds).

As a result, this RIA relies on general, average cost estimates of typical technologies. Moreover, 

while the total national-level cost per ton for conversion to dry handling is calculated at a plant 

level in the model, the actual cost of wet-to-dry handling conversion is not related to tonnage in a 

linear fashion, and plant level conversion costs based on these data do not accurately reflect the 

cost of conversion.
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Plants closing impoundment systems must reconstruct their ash handling systems to shift from a 

water-based (wet) system to a dry handling system. Dry bottom handling systems can include a 

clinker grinder, slurry transfer piping, dewatering bins, clarifier, water tank, sluice pump, and 

truck loading area. Dry fly ash handling systems beginning at the electro-static precipitator (ESP) 

collectors can include pressure or vacuum pneumatic ash transport lines, storage silos, and a 

truck loading area. FGD handling systems may include hydrocyclones for primary dewatering, 

horizontal vacuum belts for secondary dewatering, a belt conveyor to a storage area, a gypsum 

storage area, and a truck loading area.

Examples of CCR dewatering methods. Dry CCR management may involve different methods of 

dry ash handling for any given plant. The following list presents example descriptions of dry 

CCR management practices at existing or planned coal-fired electric utility plants:

 Tanks and chain drag. Basin Electric Power Cooperative presented this 

technology in 2009.248 Bottom ash is dewatered in tanks and water is recirculated 

to transport additional bottom ash. Bottom ash is removed using a chain drag, and 

is hauled by truck to a landfill. Fly ash is conveyed in a dry state to a landfill.

 Pressure squeeze conveyor. The coal mining industry manages waste using a 

tank-based method similar to the tanks and chain drag method developed by the 

Phoenix Process Equipment company. This process involves a thickening tank, 

porous conveyor belt, and pressure to squeeze water out of coal washings, 

producing a dewatered cake that is scraped off the conveyor belt and stacked like 

a pile of sand. One source reports the cost for this process at $0.50 per ton of coal 

waste processed.249

 Horizontal belt filters. According to a May 2009 technical paper, dewatering 

gypsum using horizontal belt filters is common in the electric utility industry, and 

a new modified horizontal belt filter method involving two feedboxes allows fly 

ash and FGD (gypsum) to be dewatered simultaneously.250

 Storage silos and rail system. In June 2009 Detroit Edison’s Monroe Michigan 

Power Plant used this method for a $10 million conversion project.251 This 

method includes equipment to collect ash in a dry state, dry ash storage facilities 

(silos) and truck or rail loading equipment for distribution of the dry ash to 

concrete producers.

 Integrated silo system. This system, integrated with precipitators, vacuum 

pumps, and bag filter/receivers, has been described in an engineering report about 

the 1997 dry fly ash system conversion of Northern Indiana Public Service 

Company’s Michigan City plant.252

 

248 http://www.basinelectric.com/News_Center/Feature_Articles/Coal_ash_handling.html

249 Dave Cooper, “Better, Safer Ways to Handle Coal Slurry Do Exist,” page 14 of the Nov 2001 “E”-Notes Newsletter of the 

Ohio Valley Environmental Coalition at http://www.ohvec.org/newsletters/enotes_97-01_pdf/enotes_2001_11.pdf 

250 See the May 2009 horizontal belt filter technical paper by Alex Hohne at http://www.flyash.info/2009/036-hohne2009.pdf

251 June 2009 Detroit Edison Monroe Power Plant example at 

http://www.thefreelibrary.com/Headwaters+Resources+Completes+Conversion+of+Wet-Handled+Coal+Ash...-a0202658744

252 See Dec 1997 NIPSC conversion report at http://www.babcockpower.com/pdf/rst-145.pdf
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FGD gypsum tank system costs. Consultation with engineering experts and EPA-OW indicates 

that coal-fired electric utility plants currently wet-handling FGD gypsum would not be able to 

implement wet-dry conversion for this CCR stream, and would instead need to design and 

implement a tank system to manage the wet-handled FGD gypsum in the case of all on-site 

impoundment units closing. Because EIA data indicate that only 22 plants affected by the CCR 

final rule wet-handle FGD gypsum and might potentially require the implementation of a tank 

system, this RIA does not separately model this requirement. According to data from EPA-OW’s 

SPEGELG proposed rule, 18 of these 22 plants discharge wastewater. 

This RIA initially compared the cost estimates for wet-dry conversion (described immediately 

below) for these 18 plants, assuming a standard wet-dry conversion process that did not involve 

tank systems for managing wet-handled FGD gypsum, to estimated compliance costs for these 

plants from EPA-OW’s SPGELG proposed rule. The EPA-OW data indicate that the RIA’s wetdry conversion cost (also obtained from EPA-OW Survey Data) exceeds the compliance costs 

estimated in the SPGELG proposed rule for ten of the 18 plants, and is lower than EPA-OW’s 

estimated compliance costs for the SPGELG proposed rule for the remaining eight plants. Given 

the high degree of uncertainty in costs associated with implementing a tank system, as well as 

indications from EPA-OW data that differences between average wet-dry conversion costs and 

tank system implementation costs vary on a site-by-site basis, this RIA does not make any 

adjustments to wet-dry conversion costs for the 22 plants wet-handling FGD gypsum. This 

assumption is highly likely to be conservative, because both median and average costs for the 18 

plants with available compliance cost data from the SPGELG proposed rule indicate that general 

wet-dry conversion costs are higher than tank system implementation costs.

Costs of conversion to dry ash handling. To estimate the cost of conversion to dry ash handling, 

this RIA uses average capital and O&M costs from nationwide aggregated wet-to-dry conversion 

cost data from a survey of power plants conducted by the EPA Office of Water for the proposed 

steam electric effluent guidelines, in combination with 2012 EIA data for the volume of CCR 

disposed in onsite surface impoundments.

253 These conversion cost and CCR disposal data 

resulted in median capital costs of $66.23 per ton and $918.74 per ton, and average O&M costs 

of $5.41 per ton and $81.34 per ton for fly ash and bottom ash, respectively. To estimate total 

conversion costs for the CCR rule, this RIA used weighted average capital and O&M costs of 

$340.44 and $29.83 per ton, reflecting the proportion of fly ash to bottom ash, and inflates the 

costs to 2013$.254

To calculate wet-dry conversion costs, this RIA applies the tonnage associated with each unit 

prompting a wet-dry conversion to the per-ton O&M and capital costs described above and 

multiplies them together. These costs are then annualized over the following 20 years and 

applied for each of the 20 years following the wet-dry conversion event. Note that because both 

 

253 Wet-to-dry conversion costs applied in this RIA represent national averages that likely approximate overall national costs of 

wet-to-dry conversion, but do not account for regional variations in costs, or for plant-specific features and processes that may 

increase or reduce costs. The EPA Office of Water aggregated wet-to-dry conversion cost data (as applied in this RIA) to 

preserve confidential business information (CBI); however, individual plants may have unique cost structures or challenges that 

may significantly impact the wet-to-dry conversion costs and decision making about the type of CCR management unit used 

modeled in this RIA. Source: “Questionnaire for the steam electric power generating effluent guidelines” 

http://water.epa.gov/scitech/wastetech/guide/steam-electric/questionnaire.cfm. 

254 Roughly 20.9 million tons of fly ash were generated in 2012 according to EIA data, relative to 61.6 million tons of bottom 

ash. 
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the capital costs and O&M costs provided by the EPA-OW data are per-ton costs that speak to 

large capital retrofits, this RIA aggregates these costs together and applies them on a per-ton 

basis before annualizing them over a 20-year period.

Incremental wet-dry conversion costs consist of the difference between baseline wet-dry 

conversion costs and wet-dry conversion costs in the CCR final rule scenario. While it is 

theoretically possible for more disposal impoundments to undergo wet-dry conversion in the 

baseline relative to the rule scenario given a certain combination of input costs, this outcome 

does not occur because the post-rule scenario results in unlined impoundments reaching a 

decision point as a result of incurring groundwater contamination events, and these unlined 

impoundments cannot choose to convert to storage impoundments when this occurs. As a result, 

a greater proportion of disposal impoundments undergoes wet-dry conversion and incurs the 

associated costs in the CCR final rule scenario.255

4.2.13.1 Financial Hurdle Costs for Wet-dry Conversion

As indicated in this chapter and in Chapter 3, however, the STATA-based model does not use 

wet-dry conversion costs as part of its determination regarding the future management of the 

CCR associated with a disposal impoundment. Rather, the model applies the “hurdle rate” cost 

based on an overall capital cost for wet-dry conversion and retrofit. The rationale for this 

bifurcation of the model decision logic and the costs later applied within the model are discussed 

in Chapter 3.

This RIA applies the following financial hurdle amounts for coal-fired electricity utility plants of 

differing generating capacities (nameplates), based on EPA-OW survey data on total wet-dry 

conversion costs for plants of different sizes (all costs 2013$):

256

 Nameplate capacity less than or equal to 500 MW: financial hurdle of $10.4 million, 

annualized over 20 years and applied to each year following the potential wet-dry 

conversion for 20 years;

 Nameplate capacity between 500 MW and 1200 MW: financial hurdle of $22.8 

million, annualized over 20 years and applied to each year following the potential 

wet-dry conversion for 20 years; and

 

255 Wet-dry conversion costs applied in this RIA do not include any additional costs for CCR wastewater treatment systems 

associated with FGD gypsum systems. However, the hurdle rates obtained via OW survey data described in Chapter 3 do 

encapsulate actual wet-dry conversion costs for facilities, including facilities that currently dispose of FGD gypsum. As a result, 

while the model logic that determines which disposal impoundments will undergo wet-dry conversion is cognizant of additional 

FGD gypsum-related costs, the actual applied wet-dry conversion costs may be understated at plants which would require 

additional capital outlays to install or alter their FGD gypsum management systems (e.g., tank systems) and/or CCR wastewater 

treatment systems.

256 The difference between the per-ton wet-dry conversion costs applied in the RIA and the hurdle costs applied in the decision 

logic is that the wet-dry conversion costs are a broad aggregate across all facilities in the OW Survey Data, where the hurdle 

costs are relatively plant-specific in that a different hurdle cost is applied to a plant based on its nameplate capacity, rather than 

its CCR tonnage to be converted. “Questionnaire for the steam electric power generating effluent guidelines” 

http://water.epa.gov/scitech/wastetech/guide/steam-electric/questionnaire.cfm.
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 Nameplate over 1200 MW: financial hurdle of $40.0 million, annualized over 20 

years and applied to each year following the potential wet-dry conversion for 20 

years.

Again, while these financial hurdles are used by the model in determining the future 

management of CCRs associated with disposal impoundments, the actual costs applied are those 

associated with the wet-dry conversion costs described earlier in this section. 

4.2.14 Temporal Cost Adjustments – Forgone Sunk Costs

Forgone sunk costs. An electric utility plant that closes an impoundment early loses the full use 

of capital resources that are effectively “sunk” in the construction of the impoundment. This RIA 

assumes that under the CCR rule, the plant will be forced to absorb remaining capital costs as 

though it were making annual payments on borrowed capital (debt) over the remainder of the 40-

year life of the unit. Plants incur sunk costs under the CCR final rule scenario if the model 

determines they will choose to close an existing impoundment before it reaches 40 years of age. 

Because plants initially made the payments associated with these sunk costs to cover the 

expenses associated with the construction, installation, or maintenance of disposal units and their 

associated CCR pollution controls, this RIA does not factor sunk costs into the costs associated 

with impoundment closure and the conversion to dry handling. Rather, this RIA includes these 

costs as part of each of the unit-level pollution controls for which the plants initially made 

payments, in proportion to the dollar value estimated for each of these cost elements.

4.2.15 Inactive CCR Surface Impoundments 

This RIA identified a total of 111 inactive CCR surface impoundments. Given the requirements 

of the final CCR rule, these 111 units can either dewater, breach, and undergo closure capping, 

or remain subject to all other components of the CCR rule. Given that costs with dewatering,

breaching, and capping are relatively nominal when compared to costs associated with 

implementing all other CCR pollution controls, this RIA assesses the cost of dewatering and 

capping for each of these 111 inactive surface impoundments rather than dynamically modeling 

the results of a comparison between dewater-and-cap costs and full CCR rule compliance costs. 

This RIA estimates one-time dewater-and-cap costs at $12,200 per acre-foot of capacity for an 

inactive impoundment. Closure capping costs are Fortran-based costs as described in Chapter 3.

However, capacity and dimension information is available for only three of the 111 inactive 

surface impoundments. For the remaining impoundments, this RIA assumes a capacity of 182 

acre feet, the average capacity among all surface impoundments identified with available 

dimension data. This RIA annualizes the costs associated with dewatering and capping these 

inactive impoundments over 40 years. 

Similarly, closure capping costs per the Fortran-based model require CCR tonnage as an input to 

the linear estimation equation; however, inactive impoundments are not currently receiving CCR 

tonnage. To estimate closure capping costs associated with these inactive units, this RIA applies 

an estimated, hypothetical tonnage based on unit dimensions (i.e., size). In cases where sufficient 

dimension data were not available, an average impoundment size was assigned in order to 
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estimate closure capping costs. Given that Fortran-based model closure capping costs are already 

annualized over 40 years, these costs are applied for on an annual basis for 40 years.

4.2.16 State and Local Government Agency Burden Costs

State and local government agency burden costs include government regulatory costs incurred 

due to a number of CCR pollution control components described in Section 4.3, including:

 Surface impoundment structural integrity inspections; 

 RCRA corrective action; and

 Receipt and processing of certain reporting and recordkeeping requirements.

Appendix M of this RIA describes the specific calculations for these state and local government 

cost items. Exhibit 4-F presents the estimates of these costs. This RIA estimates total agency 

burden costs of $1.4 million per year for the CCR rule. When considered along with the industry 

costs, agency burden costs represent considerably less than 1% of total costs imposed by the rule. 

Agency burden costs also constitute only a small fraction of each individual CCR pollution 

control to which they apply. Agency burden costs associated with recordkeeping and corrective 

action represent the largest fractions of the total costs associated with the pollution control 

requirement to which they correspond, at 0.08% and 0.06% of costs, respectively.257

4.3 Summary of CCR Final Rule Regulatory Costs

Note: EPA has updated the methods and calculations in this chapter of the RIA to reflect 

changes to the universe of plants affected by the rule, changes to the analytic framework, 

and revisions to the rule requirements. These updates are not reflected in the text and 

exhibits in this section. See Sections 9.2, 9.3, and 9.4 in Chapter 9 of this RIA for a description 

of the relevant modifications and the resultant re-estimated costs for the CCR final rule.

Exhibit 4-D below displays total incremental average annualized costs for each of the CCR final

CCR rule’s cost components under a 7% discount rate for landfills, disposal impoundments, and 

storage impoundments. Appendix N provides plant-by-plant and owner entity-by-entity 

estimates of total incremental costs. Exhibit 4-E then aggregates costs across the three types of 

CCR management units. This RIA assumes that state government agency paperwork burden 

costs are 2% of the costs incurred for a given CCR pollution control requirement that has

analogous state agency activities (i.e., reporting and recordkeeping, corrective action, and 

structural integrity inspections only). The state agency burden costs are aggregated in Exhibit 4-

E rather than separately listed in Exhibit 4-D. Present value estimates of total incremental costs 

associated with the CCR rule, as well as rule cost estimates under a 3% discount rate, can be 

found in Chapter 9. (which also includes modified cost estimates at a 7% discount rate).

 

257 Note that the state government agency burden for a specific requirement (e.g., recordkeeping) is 2% of the private industry 

compliance costs associated with the requirement, and is correspondingly a much smaller fraction of the overall compliance costs 

of the final CCR rule.
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Unlike the baseline costs discussed in Section 3.5, this RIA applies a probabilistic component to 

the assessment of incremental costs associated with the CCR rule, based on the probability that 

unlined disposal and storage impoundments may experience groundwater contamination events 

that prompt changes in CCR management. Correspondingly, Exhibit 4-D characterizes the 

variability inherent in this probabilistic component by displaying total incremental costs under a 

central estimate scenario, which presents an expected value associated with the final CCR rule.

This estimate is achieved by holistically considering the probabilities associated with the 

occurrence of a groundwater contamination event for each unlined surface impoundment in each 

year, and weighting the incremental costs associated with each occurrence or non-occurrence of 

a groundwater contamination event by the likelihood of the occurrence or non-occurrence. Note 

that this RIA does not disaggregate the probabilities associated with other probabilistic 

components of the analysis, such as location restrictions or impoundment size for assessment of 

structural integrity inspection costs; the variability in total incremental costs associated with 

these components is examined in Chapter 7.
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Exhibit 4-D

Total Incremental CCR Management Costs – Central Estimates (Expected Values)

Annualized Values @ 7% Discount Rate (millions of 2013$)

CCR Pollution Control Landfills Disposal Impoundments Storage Impoundments

A. Unit-level pollution control costs*

1. Groundwater monitoring for CCR contamiation $0.665 $1.03 $2.80

2. Bottom liners $57.5 $115 $313

3. Leachate collection systems $19.6 N/A N/A

4. DustCCR fugitive dust controls $1.81 $0.789 $2.15

5. Run-on/run-off controls $0.430 $5.99 $16.3

6. Location restrictions** $8.78 $14.6 N/A

7. Closure capping $2.52 $4.55 $12.4

8. Post-closure monitoring (30 years) $0.012 $0.015 $0.041

9. Structural integrity inspections N/A $3.30 $10.1

B. Other costs

10. Corrective action (i.e., cleanup of CCR 

contaminated groundwater) $4.37 $2.43 $16.9

11. Reporting and recordkeeping $7.67 $4.53 $18.9

12. Conversion from wet to dry CCR handling N/A $62.9 N/A

13. Column Total Costs = $103 $215 $393

Notes:

 For reason explained in Section 5.3.4 of this RIA, row 13 above (total costs) does not subtract the “cost offset” which is displayed in row 3 of 

Exhibit 5-O. Instead, this RIA includes the “cost offset” within the CCR beneficial use benefit category rather than as a negative cost.

 * Except for location restrictions, all unit-level pollution control costs cannot be dissociated due to nonlinearity in the cost estimation modeling 

process. See Section 4.2 for additional information. As a result, relative costs for unit-level pollution controls are assigned based on the relative 

unit cost of these requirements and weighted by the number of existing and new disposal units subject to these requirements.

 ** Despite a probabilistic component inherent in the application of this cost component, this Exhibit presents an expected value cost rather than 

a range of costs in order to focus on the drivers of overall CCR management costs. Sensitivity analyses associated with the probabilistic 

component of modeling this requirement can be found in Chapter 7.

NOTE: EPA has updated this exhibit of the RIA; 

see Exhibits 9-J to 9-L in Section 9.4.2 of this RIA for updated exhibits.

NOTE: EPA has updated this exhibit of the RIA; 

see Exhibits 9-J to 9-L in Section 9.4.2 of this RIA for updated exhibits.
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Exhibit 4-E

Total Incremental CCR Management Costs – All CCR Management Units

Annualized Values @ 7% Discount Rate (millions of 2013$)

CCR Pollution Control Central Estimate

(Expected Value)

A. Unit-level pollution control costs*

1. Groundwater monitoring for CCR contamination $4.49

2. Bottom liners $485

3. Leachate collection systems $19.6

4. DustFugitive CCR dust controls $4.74

5. Run-Storm water run-on/run-off controls $22.8

6. Location restrictions $23.3

7. Closure capping $19.5

8. Post-closure monitoring $0.068

9. Structural integrity inspections** $13.4

B. Other costs

10. Corrective action (i.e., cleanup of CCR contaminated groundwater) $23.7

11. Reporting and recordkeeping $31.1

12. Conversion from wet to dry CCR handling $62.9

13. Costs for inactiveInactive impoundments (dewater and closure cap) $26.7

Subtotal – Total Incremental Industry Costs $738

C. State Agency Burden Costs

14. Structural integrity inspections** $0.267

15. Corrective action $0.473

16. Reporting and recordkeeping $0.622

Subtotal – State Agency Burden Costs $1.36

Total Incremental Rule Costs $739

Note: The total rule cost displayed in Exhibit 4-E above has not been adjusted (i.e., reduced) for 

the potential future “cost offset” which is calculated in Section 5.3.4 of Chapter 5. As simulated 

in this RIA, the cost offset represents a potential reduction in the total rule cost associated with 

an anticipated future increase in CCR beneficial use. Such future increase could result from the 

CCR final rule inducing some electric utility plants to divert future CCR annual tonnages away 

from disposal to beneficial uses. This possibility conforms to the “avoided disposal cost” 

business behavior of electric utility plants as defined by the American Coal Ash Assocation 

(ACAA) and presented in Section 5.3. Consequently, the total rule cost estimate displayed in 

Exhibit 4-E above represents an upper-bound central estimate in this RIA with respect to this 

expected cost offset factor.

NOTE: EPA has updated this exhibit of the RIA; see Exhibit 9-M in Section 

9.4.2 of this RIA for an updated exhibit.

NOTE: EPA has updated this exhibit of the RIA; see Exhibit 9-M in Section 

9.4.2 of this RIA for an updated exhibit.
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4.3.1 Summary of Largest and Smallest Percentage Components of Regulatory Costs

Note: EPA has updated or otherwise modified this section of the RIA; see Sections 9.2, 9.3, and 

9.4 in Chapter 9 of this RIA for a description of the relevant modifications and updates to this 

section. Exhibit and figures in this section have not been updated to reflect revisions described in 

Sections 9.2, 9.3, and 9.4 in Chapter 9 of this RIA.

As shown in Exhibit 4-E above, the largest components of total incremental regulatory cost 

associated with the final CCR rule are:

 Conversion to dry CCR management – this requirement represents 9% of total rule costs

as a central estimate. While wet-dry conversion costs amount to less than 10% of total 

costs, they do represent approximately 29% of all incremental compliance costs 

associated with disposal impoundments. 

 Costs associated with liners represent the bulk of incremental compliance costs of the 

CCR rule. This occurs because on a unit cost basis, liners are considerably more 

expensive relative to other unit-level costs such as groundwater monitoring and dust 

controls. As a result, the majority of rule costs (over 65% for liners in the central 

estimate) reflect the new liner (and leachate collection system) requirements for CCR 

management units that lack these pollution controls in the baseline.

 The smallest individual compliance cost categories are associated with other unit-level 

pollution controls, such as groundwater monitoring, post-closure monitoring, and dust 

controls. Unit costs for these requirements are low relative to other CCR pollution 

controls, and these requirements are only incremental costs to the extent that they are not 

already required in the baseline for a given CCR management unit. While unit costs for 

closure capping do not fall into this category and are more substantial than unit costs for 

groundwater monitoring, closure capping generally takes place in out years and is more 

heavily discounted as a result.

o The six lowest-cost requirements of the final CCR rule, using the central estimate, 

amount to just 8% of total incremental costs associated with the rule (groundwater 

monitoring, dust controls, capping, post-closure monitoring, structural integrity 

inspections, and leachate collection systems at landfills.)

Section 7.1.6 of this RIA presents an analysis of recent 2010 capacity data on off-site 

commercial industrial landfills, in comparison to annual CCR tonnages which are simulated in 

this RIA as possibly switching to off-site landfills.

4.3.2 Summary of Probabilistic Variability in Total Incremental Costs

Note: EPA has updated or otherwise modified this section of the RIA; see Sections 9.2, 9.3, and 

9.4 in Chapter 9 of this RIA for a description of the relevant modifications and updates to this 

section. Exhibit and figures in this section have not been updated to reflect revisions described in 

Sections 9.2, 9.3, and 9.4 in Chapter 9 of this RIA.
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In Chapter 7, this RIA provides estimates for the variability associated with the multiple 

probabilistic components modeled to affect total incremental costs in this RIA. However, it is 

possible to characterize the total variability associated across each of these components by 

arraying each potential total incremental cost against the likelihood of its occurrence. Below, this 

RIA presents a set of cumulative probability functions: each curve indicates the relative 

likelihood of incurring a total cost, in present value terms, less than or equal to the corresponding 

value on the y-axis. 

Exhibit 4-F below is intended to illustrate the overall probabilistic variability of total costs in the 

post-rule scenario (not total incremental costs). In each chart below, the x-axis, from left to right, 

represents the relative likelihood of incurring a total post-rule present value cost (as a sum of 

costs across all CCR management units of that type).

 A separate function chart for landfills is not included: probabilistic variability for landfills 

is minimal due to the lack of any modeling of groundwater contamination events 

prompting decision points and CCR management method changes for unlined landfills. 

However, total post-rule landfill costs on a present value basis are included in the “total” 

function.

 State agency burden costs, recordkeeping costs, and costs associated with inactive 

impoundments are not included in the functions below, either because they do not vary 

probabilistically or because the resulting variance is too minimal to be highlighted in 

these functions.

 Cumulative probability functions of total costs for the baseline are not included due to the 

low probabilistic variability in the baseline scenario, which would yield flat or nearly-flat 

lines across the CCR management unit types. As a result, shapes of total incremental cost

functions would appear similar to those displayed below, but shifted vertically down to 

subtract the relatively static baseline costs.

Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

Exhibit 4-F

Cumulative Probability Functions of Total Post-Rule Costs

Present Values at 7% Discount Rate (2013$)

Disposal Impoundments – Total Post-Rule Costs
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Storage Impoundments – Total Post-Rule Costs

Landfills, Disposal Impoundments, and Storage Impoundments – Total Post-Rule Costs

4.3.3 Time-Trend of Total Incremental Costs

Note: EPA has updated the methods and calculations in this section to reflect changes to the 

universe of plants affected by the rule, changes to the analytic framework, and revisions to 

the rule requirements. These updates are not reflected in the text and exhibits in this 

section. See Sections 9.2, 9.3, and 9.4 in Chapter 9 of this RIA for a description of the 

relevant modifications and the resultant re-estimated costs for the CCR final rule.

The CCR final rule and the cost estimation modeling in this RIA include a variety of temporal 

components that drive the occurrence of costs across different out-years. While the costs in 

Exhibits 4-D and 4-E are presented on a discounted and annualized basis (under a 7% discount 

rate), the actual incidence of costs is not even or roughly equivalent over time. In general, two 

timing considerations drive costs:
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 CCR management unit age. As units age over time, costs initially increase for two 

distinct reasons. First, as units age, they approach the end of their lifespans. Given 

that liners are required for new units only, a substantial cost impact occurs when an 

existing unit closes and is replaced by a new unit with a liner in place. To the extent 

that this unit, in the baseline, would not be required to have a liner, this represents a 

substantial incremental cost. Correspondingly, the temporal array of costs includes 

places where costs increase relative to prior years because one or more units have 

reached the ends of their operating lifespans and have been replaced with newly-lined 

units. Second, for unlined impoundments, age is a probabilistic input into the 

likelihood of a groundwater contamination event occurring. Given that these events 

prompt decision points which result in CCR management method change, and new 

options for CCR management generally involve lined units, this represents a similar 

increase in a given year’s incremental costs. To the extent that wet-dry conversion 

also occurs as a result of either a unit reaching the end of its useful life, or 

experiencing a groundwater contamination event, costs in a given out-year are further 

increased.

 Implementation dates and deadlines of the CCR final rule. The CCR final rule 

indicates that Year 6, or 2020, is the first year in which groundwater contamination 

events at unlined impoundments may be discovered and prompt decision points 

leading to CCR management method changes. In addition, as described earlier in this 

chapter, given the probabilistic relationship between unit age and the occurrence of a 

groundwater contamination event, many unlined impoundments will be modeled as 

having a groundwater contamination event already occurring prior to Year 6, and will 

experience the decision point prompted by this event in Year 6. As a result, costs 

increase significantly in this year.

In addition to these considerations, some costs, namely wet-dry conversion, are annualized over 

a period that does not equal the lifespan of the CCR management unit and applied over a multiyear period following a particular event or CCR management method change. Correspondingly, 

many of the temporal cost swings result from the beginning or ending of these arrays of wet-dry 

conversion costs over time.

Exhibit 4-G displays the total incremental cost streams over time for landfills, disposal 

impoundments, and storage impoundments. These costs are not discounted back to 2013; rather, 

they are nominal dollars. Note, however, that for the purposes of calculating annualized and 

present value costs as presented in this RIA, two years with equivalent costs as shown in Exhibit 

4-G will not have equivalent present value costs, nor contribute an equivalent amount to an 

annualized cost estimate, because the timing differences will lead to the costs associated with 

one year to be more heavily discounted than the costs associated with another year that came 

before it.

In addition, Exhibit 4-H presents a total incremental cost stream that captures the individual cost 

streams presented in Exhibit 4-G, and also adds costs associated with inactive impoundments. 

Inactive impoundment costs are annualized over the first 40 years of the analysis and applied 

over this same period.
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 $-

 $200

 $400

 $600

 $800

 $1,000

 $1,200

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Total Incremental Costs ($millions)

Year

Exhibit 4-G

Total Incremental Costs by Year: Landfills, Disposal Impoundments, and 

Storage Impoundments

Landfills

Disposal Impoundments

Storage Impoundments

 $-

 $200

 $400

 $600

 $800

 $1,000

 $1,200

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Total Incremental Costs ($millions)

Year

Exhibit 4-G

Total Incremental Costs by Year: Landfills, Disposal Impoundments, and 

Storage Impoundments

Landfills

Disposal Impoundments

Storage Impoundments

Note: This exhibit has not been updated to reflect the revisions described in 

Section 9.2, 9.3 and 9.4 in Chapter 9 of this RIA.
October 2014 EPA Interagency Review Draft: Do Not Circulate or Cite

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4-50

The patterns shown in Exhibits 4-F and 4-G are directly indicative of the temporal cost structure 

assigned in the STATA-based cost estimation model. Landfill costs are generally low until 

approximately 2055; this occurs because landfills vertically expand and do not close until 

reaching 80 years of age; as such, any high-cost differentials between the post-rule and baseline 

scenarios attributable to the addition of liners and leachate collection systems at new landfills 

 $-

 $200

 $400

 $600

 $800

 $1,000

 $1,200

 $1,400

 $1,600

 $1,800

 $2,000

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110

Total Incremental Costs ($millions)

Year

Exhibit 4-H

Total Incremental Costs by Year: All Active and Inactive CCR Management 

Units (Non-Discounted)

 $-

 $200

 $400

 $600

 $800

 $1,000

 $1,200

 $1,400

 $1,600

 $1,800

 $2,000

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110

Total Incremental Costs ($millions)

Year

Exhibit 4-H

Total Incremental Costs by Year: All Active and Inactive CCR Management 

Units (Non-Discounted)

Note: This exhibit has been updated to reflect the revisions described in 

Section 9.2, 9.3 and 9.4 in Chapter 9 of this RIA. See Exhibit 9-O for the 

updated exhibit.
October 2014 EPA Interagency Review Draft: Do Not Circulate or Cite

Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

4-51

generally do not occur until later in the period of analysis. While costs appear very high after 

2070, owing to large landfills without required liners or leachate collection systems in the 

baseline, these costs are heavily discounted in the present value and annualized cost estimates.

Disposal impoundment costs increase sharply in 2020 due to the modeled discovery of 

groundwater contamination events in this year. Costs then remain at this high level, decreasing 

gradually due to baseline end of operating life occurrences that reduce incremental costs, until 

2040, at which point the wet-dry conversion cost streams for all units undergoing wet-dry 

converson in 2020 end. The remaining incremental costs for disposal impoundments after 2040 

generally reflect the cost differences between baseline CCR management and post-rule CCR 

management with all required CCR pollution controls, including liners.

Storage impoundment costs are generally similar to disposal impoundment costs, in that the main 

cost driver is the cost difference associated with unlined impoundments discovering groundwater 

contamination events in 2020 and transitioning to new, lined storage impoundments as a result. 

Because storage impoundments do not undergo behavior change in the baseline but remain 

existing storage impoundments indefinitely, incremental costs are steady year-over-year, with 

only slight variations due to thefuture annual changes in CCR tonnage year-over-year (from the 

EIA AEO forward-looking projections)generated, as well as probabilistic considerations for 

certain unlined storage impoundments with outside probabilities to incur groundwater 

contamination events in years other than 2020 based on their ages.

4.3.4 Changes in Universe Composition over Time

Note: EPA has updated the methods and calculations in this section to reflect changes to the 

universe of plants affected by the rule, changes to the analytic framework, and revisions to 

the rule requirements. These updates are not reflected in the text and exhibits of this 

section. See Sections 9.2, 9.3, and 9.4 in Chapter 9 of this RIA for a description of the 

relevant modifications and the resultant re-estimated costs for the CCR final rule.

In addition to differential patterns in cost streams over time, decision points reached by landfills 

and disposal impoundments result in changes in CCR management methods from their baseline 

compositions. Similarly, in the post-rule scenario only, storage impoundments are replaced by 

new storage impoundments if they are unlined and experience a groundwater contamination 

event. Exhibits 4-K through 4-O below show the differential CCR management unit universe 

composition in the baseline and post-rule scenarios. 

Note that all unit counts displayed below are cognizant of the probabilistic nature of the cost 

estimation modeling: if a given existing unit has an 18% chance to switch management method 

in a given year, it is counted as 0.82 existing units of the given type, and 0.18 units of whatever 

management method there is an 18% chance of this unit switching to. For example, consider an 

unlined disposal impoundment that will switch to dry disposal and wet-dry conversion whenever 

it is prompted with a decision point, whether that decision point occurs due to the end of its 

operating life or encountering a groundwater contamination event. If the chance of this 

impoundment incurring a groundwater contamination event in Year X is 45%, this unit will 

constitute 0.45 “closure and conversion to dry handling” units in Year X, and 0.55 “existing SI” 

units in that year. 
October 2014 EPA Interagency Review Draft: Do Not Circulate or Cite

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4-52

Note: The exhibits on this page have not been updated to reflect the revisions described in 

Section 9.2, 9.3 and 9.4 in Chapter 9 of this RIA. 

The majority of existing landfills are eventually replaced by new landfills. By the end of the 

period of analysis (2114), in the baseline scenario, only 13% shift to offsite disposal in the 

baseline scenario.

0

50

100

150

200

250

300

350

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Count of Existing and New Units 

Managing CCR originally managed by 

LFs

Exhibit 4-I

Change in CCR Management Universe Composition over Time: Landfills 

and their Successor CCR Management Methods: Baseline

Existing LF

New LF

Offsite LF

0

50

100

150

200

250

300

350

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Count of Existing and New Units 

Managing CCR originally managed by 

LFs

Exhibit 4-I

Change in CCR Management Universe Composition over Time: Landfills 

and their Successor CCR Management Methods: Baseline

Existing LF

New LF

Offsite LF
October 2014 EPA Interagency Review Draft: Do Not Circulate or Cite

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4-53

In the post-rule scenario, offsite landfills are more prominent because new on-site landfills are 

required to comply with a suite of CCR pollution control requirements. However, a new on-site 

landfill with all pollution control requirements is still the most cost-effective option for future 

dry CCR management in 68%, or 212, of the 310 existing landfill cases.

Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

0

50

100

150

200

250

300

350

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Count of Existing and New Units 

Managing CCR originally managed by 

LFs

Exhibit 4-J

Change in CCR Management Universe Composition over Time: Landfills and 

their Successor CCR Management Methods: Post-Rule

Existing LF

New LF

Offsite LF

0

50

100

150

200

250

300

350

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Count of Existing and New Units 

Managing CCR originally managed by 

LFs

Exhibit 4-J

Change in CCR Management Universe Composition over Time: Landfills and 

their Successor CCR Management Methods: Post-Rule

Existing LF

New LF

Offsite LF
October 2014 EPA Interagency Review Draft: Do Not Circulate or Cite

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4-54

In the baseline scenario, the universe of the 142 disposal impoundments diverges into a variety 

of CCR management options once each impoundment reaches the end of its operating life. The 

most common outcome is conversion to a storage impoundment, with annual dredging and 

disposal in either an on-site or off-site landfill, which does not include wet-dry conversion. 

Slightly over half of all disposal impoundments in the baseline (73, or 51%) choose this option 

for future CCR management. Impoundment closure, conversion to dry handling, and subsequent 

disposal in an on-site or off-site landfill is the next most commonly-chosen future CCR 

management method for disposal impoundments in the baseline: 48 impoundments, or 

approximately one-third of the universe, choose this variant according to the cost estimation 

modeling. The remaining 21 impoundments (15%) opt to open a new disposal impoundment 

once the existing impoundment reaches the end of its operating life.

0

20

40

60

80

100

120

140

160

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Count of Existing and New Units 

Managing CCR originally managed 

by Disposal SIs

Exhibit 4-K

Change in CCR Management Universe Composition over Time: Disposal 

Impoundments and their Successor CCR Management Methods: Baseline

Existing Disposal SI

New Disposal SI

Closure and Conversion to Dry Handling

Conversion to Storage SI

0

20

40

60

80

100

120

140

160

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Count of Existing and New Units 

Managing CCR originally managed 

by Disposal SIs

Exhibit 4-K

Change in CCR Management Universe Composition over Time: Disposal 

Impoundments and their Successor CCR Management Methods: Baseline

Existing Disposal SI

New Disposal SI

Closure and Conversion to Dry Handling

Conversion to Storage SI
October 2014 EPA Interagency Review Draft: Do Not Circulate or Cite

Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

4-55

Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

The probabilistic calculus figures substantially into the post-rule scenario for disposal SIs. 

Because a number of existing SIs, based on their ages, are likely to already be experiencing 

groundwater contamination events (or will by 2020), the number of existing SIs falls by over 

35% (50 out of 120) on a probability-weighted basis in that year. (Prior to 2020, 22 disposal 

impoundments reached the end of their operating lives and transitioned to a different CCR 

management method; only two of these units opted for a new disposal impoundment.)

Overall, on a probability-weighted basis, closure and conversion to dry handling with further 

disposal in an on-site or off-site landfill is the most common option for disposal impoundments 

in the post-rule scenario: by the end of the period of analysis, on a probability-weighted basis, 98 

disposal impoundments (69%) opt for this form of future CCR management. While conversion to 

a storage impoundment and subsequent disposal in an on-site and off-site landfill was the most 

popular management choice once the disposal impoundment had reached the end of its useful life 

in the baseline scenario, only a probability-weighted 13 units (less than 10%) use this method in 

0

20

40

60

80

100

120

140

160

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Count of Existing and New Units 

Managing CCR originally managed 

by Disposal SIs

Exhibit 4-L

Change in CCR Management Universe Composition over Time: Disposal 

Impoundments and their Successor CCR Management Methods: Post-Rule

Existing Disposal SI

New Disposal SI

Closure and Conversion to Dry Handling

Conversion to Storage SI

0

20

40

60

80

100

120

140

160

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Count of Existing and New Units 

Managing CCR originally managed 

by Disposal SIs

Exhibit 4-L

Change in CCR Management Universe Composition over Time: Disposal 

Impoundments and their Successor CCR Management Methods: Post-Rule

Existing Disposal SI

New Disposal SI

Closure and Conversion to Dry Handling

Conversion to Storage SI
October 2014 EPA Interagency Review Draft: Do Not Circulate or Cite

Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

4-56

the post-rule scenario. This occurs because the storage impoundment conversion option is costeffective when avoiding large capital costs such as liner installation or wet-dry conversion, 

especially for unlined impoundments. However, given that unlined impoundments have a high 

probability of eventually incurring a groundwater contamination event, other CCR management 

options become more cost-effective after a groundwater contamination event occurs and closure 

of the unlined impoundment is necessary. As Exhibit 4-L indicates, even with wet-dry 

conversion in the calculus (via the hurdle rate), closure, conversion to dry handling, and on-site 

or off-site disposal is more cost-effective for most facilities with disposal impoundments relative 

to CCR management in a new disposal impoundment subject to all pollution control 

requirements of the CCR final rule.

Exhibit 4-M below displays the post-rule universe composition for storage impoundments. As 

described earlier in this chapter and in Chapter 3, the cost estimation model does consider 

changes to CCR management for CCR storage impoundments in the baseline: in the baseline, 

storage impoundments do not arrive at decision points but continue operating indefinitely; in the 

post-rule scenario, unlined storage impoundments are replaced with new, lined storage 

impoundments when they experience a groundwater contamination event. Exhibit 4-M captures 

this variability on a probability-weighted basis: the majority of unlined storage impoundments 

experience a groundwater contamination event in the first year that groundwater monitoring 

would capture this event, or 2020. In subsequent out-years, the individual probability of a given 

unlined storage impoundment experiencing a groundwater contamination event is relatively low, 

such that, on a probability-weighted basis, less than 5% of all storage impoundments that 

experience a groundwater contamination event do so in years other than 2020. Overall, 

approximately 62% of storage impoundments do not experience a groundwater contamination 

event and do not switch to new impoundments: this occurs either because the impoundments 

were already lined, or because the groundwater contamination event probability allows for a 

substantial chance that a given unlined impoundment will not experience such an event over the 

period of analysis.

Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

0

100

200

300

400

500

600

700

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Count of Existing and New 

Storage SIs

Exhibit 4-M

Change in CCR Management Universe Composition over Time: Storage 

Impoundments: Post-Rule

Existing Storage SI New Storage SI
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4-57

Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

Given the trendlines above, it is possible to summarize unit behaviors on a total universe basis 

under both the baseline and post-rule scenarios. In Exhibits 4-N and 4-O below, this RIA 

provides total trendlines for probability-weighted unit counts of the following CCR management 

methods:

 Existing landfills (n = 310 in 2014, plus impoundments that shift disposal to existing 

landfills either after wet-dry conversion or after conversion to a storage impoundment);

 Existing disposal impoundments (n = 142 in 2014);258

 Existing storage impoundments (n = 593 in 2014);

 Existing units shifting disposal to offsite (both landfills and disposal impoundments that 

wet-dry converted or those that converted to storage impoundments and send the dredged 

material offsite);

 Existing units shifting disposal to new on-site landfills (both landfills and disposal 

impoundments that wet-dry converted or those that converted to storage impoundments 

and send the dredged material to an on-site landfill);

 New disposal impoundments; 

 New storage impoundments; and

 Disposal impoundments that converted to storage impoundments.

Note that the vertical summation of all trendlines in Exhibits 4-N and 4-O would sum to the 

total of 1,045 existing, on-site CCR management units, but for one exception: the category of 

 

258 In the cost estimation model, a disposal impoundment that shifts disposal to an on-site existing landfill will appropriately 

continue to incur the costs associated with that activity even as the on-site existing landfill closes and a new landfill is opened in 

its place. In Exhibits 4-N and 4-O below, this instance continues to be aggregated into the “existing LF” line, even though at that 

point in time, the once-existing on-site landfill may have already been replaced with a new on-site landfill. By 2091, all existing 

on-site landfills have closed due to reaching the end of their operating lifespans; the “existing LF” line after this point in time 

reflects solely the disposal impoundments that have shifted their disposal to on-site landfills that were, at one point, existing 

landfills (rather than having a new landfill constructed for this disposal).

0

100

200

300

400

500

600

700

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Count of Existing and New 

Storage SIs

Exhibit 4-M

Change in CCR Management Universe Composition over Time: Storage 

Impoundments: Post-Rule

Existing Storage SI New Storage SI
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Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

4-58

disposal impoundments that convert to storage impoundments adds double-counting into the 

calculus, because each such converted impoundment represents both its own management unit as 

well as an additional unit of CCR management in terms of the final destination of the CCRs 

dredged out of that unit.

Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

0

100

200

300

400

500

600

700

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110

Probability-Weighted Count of CCR 

Management Unit Types

Exhibit 4-N

Change in Total CCR Management Unit Universe by Unit Type: Baseline 

Scenario 

Existing LFs

Existing disposal SIs

Existing storage SIs

Off-site disposal

0

100

200

300

400

500

600

700

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110

Probability-Weighted Count of CCR 

Management Unit Types

Exhibit 4-N

Change in Total CCR Management Unit Universe by Unit Type: Baseline 

Scenario 

Existing LFs

Existing disposal SIs

Existing storage SIs

Off-site disposal
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4-59

Note: The exhibits on this page have not been updated to reflect the revisions described in 

Section 9.2, 9.3 and 9.4 in Chapter 9 of this RIA. 

Lastly, Exhibits 4-P through 4-S present tracking of the total CCR tonnages associated with 

each existing and future CCR management method for landfills and disposal impoundments 

across the baseline and post-rule scenarios. Each of these exhibits corresponds to Exhibits 4-I

through 4-L, respectively. Note that the figures in these exhibits represent baseline (2012) CCR 

tonnages consistent with those presented in Chapter 2; they are not altered to reflect expected 

changes in coal consumption for electricity generation and the resulting effects on CCR 

generation over time, though the cost estimation model does take this factor into account.

0

100

200

300

400

500

600

700

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110

Probability-Weighted Count of CCR 

Management Unit Types

Exhibit 4-O

Change in Total CCR Management Unit Universe by Unit Type: Post-Rule Scenario 

Existing LFs

Existing disposal SIs

Existing storage SIs

Off-site disposal

0

100

200

300

400

500

600

700

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110

Probability-Weighted Count of CCR 

Management Unit Types

Exhibit 4-O

Change in Total CCR Management Unit Universe by Unit Type: Post-Rule Scenario 

Existing LFs

Existing disposal SIs

Existing storage SIs

Off-site disposal
October 2014 EPA Interagency Review Draft: Do Not Circulate or Cite

Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

4-60

0

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

30,000,000

35,000,000

40,000,000

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Tons of CCR Managed

Exhibit 4-P

Change in CCR Tonnage by Management Method over Time: CCR Tonnage 

Originally Managed in Landfills: Baseline

Existing LF

New LF

Offsite LF
October 2014 EPA Interagency Review Draft: Do Not Circulate or Cite

Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

4-61

Note: The exhibits on this page have not been updated to reflect the revisions described in 

Section 9.2, 9.3 and 9.4 in Chapter 9 of this RIA. 

0

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

30,000,000

35,000,000

40,000,000

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Tons of CCR Managed

Exhibit 4-P

Change in CCR Tonnage by Management Method over Time: CCR Tonnage 

Originally Managed in Landfills: Baseline

Existing LF

New LF

Offsite LF

0

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

30,000,000

35,000,000

40,000,000

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Tons of CCR Managed

Exhibit 4-Q

Change in CCR Tonnage by Management Method over Time: CCR Tonnage 

Originally Managed in Landfills: Post-Rule

Existing LF

New LF

Offsite LF
October 2014 EPA Interagency Review Draft: Do Not Circulate or Cite

Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

4-62

Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

0

2,000,000

4,000,000

6,000,000

8,000,000

10,000,000

12,000,000

14,000,000

16,000,000

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Tons of CCR Managed

Exhibit 4-R

Change in CCR Tonnage by Management Method over Time: CCR Tonnage 

Originally Managed in Disposal Impoundments: Baseline

Existing Disposal SI

New Disposal SI

Closure and Conversion to Dry Handling

Conversion to Storage SI

0

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

30,000,000

35,000,000

40,000,000

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Tons of CCR Managed

Exhibit 4-Q

Change in CCR Tonnage by Management Method over Time: CCR Tonnage 

Originally Managed in Landfills: Post-Rule

Existing LF

New LF

Offsite LF
October 2014 EPA Interagency Review Draft: Do Not Circulate or Cite

Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

4-63

0

2,000,000

4,000,000

6,000,000

8,000,000

10,000,000

12,000,000

14,000,000

16,000,000

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Tons of CCR Managed

Exhibit 4-R

Change in CCR Tonnage by Management Method over Time: CCR Tonnage 

Originally Managed in Disposal Impoundments: Baseline

Existing Disposal SI

New Disposal SI

Closure and Conversion to Dry Handling

Conversion to Storage SI

0

2,000,000

4,000,000

6,000,000

8,000,000

10,000,000

12,000,000

14,000,000

16,000,000

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Tons of CCR Managed

Exhibit 4-S

Change in CCR Tonnage by Management Method over Time: CCR Tonnage 

Originally Managed in Disposal Impoundments: Post-Rule

Existing Disposal SI

New Disposal SI

Closure and Conversion to Dry Handling

Conversion to Storage SI
October 2014 EPA Interagency Review Draft: Do Not Circulate or Cite

Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

4-64

Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

In general, the trends found when examining changes in CCR management method by tonnage 

mirror those seen when examining the changing universe composition of CCR management units 

over time, in both the baseline and post-rule scenarios. The most noteworthy differences include:

 While less than a quarter of all disposal impoundments opt to open new impoundments 

over any other CCR management method, these impoundments constitute approximately 

just 1% of total CCR tonnage currently managed in disposal impoundments. 

Correspondingly, very little of the total incremental cost associated with disposal 

impoundments is directly attributable to the creation and management of new disposal 

impoundments, as nearly all CCR tonnage associated with disposal impoundments 

transitions to another method of CCR management, and most is eventually handled as dry 

after wet-dry conversion operations. 

 In the post-rule scenario, considerably more landfills are replaced with new on-site 

landfills than switch to off-site disposal. However, on a tonnage basis, the total tonnage 

eventually managed in new landfills is similar to that managed via off-site disposal. This 

indicates that relatively larger landfills opt to transition to off-site disposal in out-years 

(or, conversely, that relatively smaller landfills are those that opt to transition to new onsite landfills).

0

2,000,000

4,000,000

6,000,000

8,000,000

10,000,000

12,000,000

14,000,000

16,000,000

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Tons of CCR Managed

Exhibit 4-S

Change in CCR Tonnage by Management Method over Time: CCR Tonnage 

Originally Managed in Disposal Impoundments: Post-Rule

Existing Disposal SI

New Disposal SI

Closure and Conversion to Dry Handling

Conversion to Storage SI
October 2014 EPA Interagency Review Draft: Do Not Circulate or Cite

Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

5-1

Chapter 5

Monetized Benefits

Note: EPA has updated the methods and calculations in this section to reflect changes to the 

universe of plants affected by the rule, changes to the analytic framework, and revisions to 

the rule requirements. These updates are not reflected in the text and exhibits in this 

chapter. See Sections 9.2, 9.3, and 9.4 in Chapter 9 of this RIA for a description of the 

relevant modifications and the resultant re-estimated benefits for the CCR final rule.

Chapter 5 of EPA’s RIA for the June 21, 2010 CCR proposed rule monetized four human health, 

environmental, and economic benefit categories expected for that rule:259

1. Future human cancer risk avoided

2. Future groundwater contamination and remediation costs avoided

3. Future CCR surface impoundment (pond) structural failure remediation costs 

avoided

4. Induced increase in future annual CCR beneficial uses260

In comparison, EPA Office of Water’s (EPA-OW) RIA for the June 7, 2013 Effluent Limitations 

Guidelines and Standards for the Steam Electric Power Generating Point Source Category

proposed rule (78 FR 34432) (SPGELG) monetized ten human health, environmental, and 

economic benefit categories associated with future reduction in pollutant discharges from CCR 

ponds and other sources at electric utility plants.261 Although the industrial scope (i.e., types of 

power plants and types of power plant wastes) of the 2013 SPGELG proposed rule is broader 

than the scope of the CCR rule, the SPGELG rulemaking would affect the same universe of CCR 

ponds as the CCR rule. Under current operations, facilities engaged in the wet handling of fly ash 

and bottom ash dispose of or store CCR in surface impoundments. These CCR surface 

impoundments directly discharge to surface water bodies through outfalls as seen in the figure 

below. As a result of the CCR rule requirements, some facilities will make the decision to close 

their surface impoundments, and will therefore no longer directly discharge to surface water 

bodies. Because the CCR and SPELG rules regulate the same entities, EPA has tried to estimate 

the potential benefits attributable to those impoundments projected to close under the CCR 

rule. The human health and ecological risks associated with these discharges were evaluated in 

the Environmental Assessment for the proposed SPGELG. 

 

259 Source: Regulatory Impact Analysis for EPA’s Proposed RCRA Regulation of Coal Combustion Residues (CCR) Generated by 

the Electric Utility Industry, EPA Office of Resource Conservation and Recovery, 30 April 2010, 242 pages, available as 

document ID nr. EPA-HQ-RCRA-2009-0640-0003 at http://www.regulations.gov

260 This benefit category was relevant to the Subtitle D option and the D-prime regulatory approach as defined in the 2010 

proposed CCR rule only; not for the 2010 Subtitle C option.

261 Source: The 10 monetized benefits are listed in “Table 2-1. Benefits of Reduced Pollutant Discharges from Steam Electric 

Power Plants” in Benefit and Cost Analysis for the Proposed Effluent Limitations Guidelines and Standards for the Steam 

Electric Power Generating Point Source Category, EPA Office of Water, EPA report nr. EPA 821-R-13-004, April 2013, 

available from the Federal regulatory docket as document ID nr. EPA-HQ-OW-2009-0819-2238 at http://www.regulations.gov.
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The ELG rule proposal estimated human health and ecological benefits attributable to reduced 

discharges from CCR impoundments to surface water as a result of a rule option that would 

impose a zero discharge requirement on surface impoundments. Elimination of these discharges 

to surface water will result in human health and ecological benefits. To estimate these benefits 

attributable to the impoundments that would close as a result of the CCR rule, EPA has 

developed a multiplier to scale the surface water benefits modeled for the ELG rule to 

correspond to the surface impoundments projected to close under the CCR rule. Under current 

operations, facilities engaged in the wet handling of fly ash and bottom ash dispose of or store 

CCR in surface impoundments. These CCR surface impoundments directly discharge to surface 

water bodies through outfalls. As a result of the CCR rule requirements, some facilities will 

make the decision to close their surface impoundments, and will therefore no longer directly 

discharge to surface water bodies. Elimination of these discharges to surface water will result in 

human health and ecological benefits. 

The ELG rule proposal estimated human health and ecological benefits attributable to reduced 

discharges from CCR impoundments to surface water as a result of a rule option that would 

impose a zero discharge requirement on surface impoundments. To estimate these benefits 

attributable to the impoundments that would close as a result of the CCR rule, EPA has scaled 

the surface water benefits modeled for the ELG rule to correspond to the surface impoundments 

Fabric

Filter

Boiler

(Furnace)

Fly Ash

Bottom Ash

ESP or

Fabric

Filter

Groundwater

Groundwater

Ash Pond River

(or POTW)

FGD

ACI

FGD Wastewater

Sluiced Fly

Ash

Sluiced

Hg Control

Wastes

Fly Ash

Hg Control

Waste

Sluiced Bottom Ash

Stack

ACI: Activated carbon injection
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anticipated to close under the CCR rule. Additionally, all benefit categories are directly or 

indirectly correlated with pollutant removal quantities. For these reasons, the benefits in this RIA 

are harmonized with the benefit categories of EPA-OW’s RIA for the 2013 SPGELG proposed 

rule.262 This harmonization:

 Broadens the scope of benefits in this RIA compared to the smaller set of four 

benefits categories monetized in the RIA for the June 2010 CCR proposed rule.

 Provides analytic consistency in the RIAs for both the CCR rule and the SPGELG 

rule.

 Leverages the EPA-OW’s more extensive benefit analysis by applying it to more 

than one EPA rulemaking.

 Provides a common platform to evaluate the extent to which the independently 

estimated costs and benefits in the RIAs for both the CCR rule and the SPGELG 

rule overlap.

 Provides a basis to evaluate how overlapping costs and benefits should be 

attributed to each rule to resolve overlap between RIAs.

This harmonization is accomplished in this RIA by scaling eight of the 10 monetized benefits 

from the SPGELG proposed rule to the CCR rule. The remaining twothree benefit categories, 

prevention of --- reduction in CCR impoundment releases and prevention of, reduction in CCR

groundwater contamination, and increase in CCR beneficial uses --- are estimated using 

alternative methods specific to this RIA, although the methods and data used have been 

coordinated with EPA-OW. This RIA also monetizes benefits associated with induced increases 

in CCR beneficial use that were not included in the RIA for the SPGELG rule, resulting in a total 

of 11 monetized benefit categories, summarized in Exhibit 5-A. The specific inputs associated 

with each surface impoundment used in the four analyses specific to this RIA for monetizing 

benefits are listed in Appendix O. The following sections of this chapter discuss each of these 

11 benefit categories. The remainder of this section describes the methodology by which this 

RIA adopts and harmonizes eight of these 11 benefit categories.

Exhibit 5-A

Summary of Monetized Benefit Categories 

Benefit Category Physical Foundation of Benefit Estimation Methodology

1. Prevention ofReduced future CCR

impoundment releases (leaks & 

structural failures)

Reduced risk of impoundment failures due to

requirement for structural integrity inspections of 

rule-induced closing of impoundments and 

conversion too dry handling of CCR

impoundments

Average annual historical 

release rate

2. Prevention ofReduced future CCR

groundwater contamination

Groundwater pollution prevention controls Groundwater contamination 

rates by liner type

3. IncreaseInduced future annual 

increase in CCR beneficial useuses

Increased cost of CCR disposal provides an 

incentive for power plants to find alternative ways 

of managing their CCR, including beneficial use

Linear programming model

minimizing CCR disposal cost

4. Reduced incidence of cancer Reduced exposure to arsenic from fish 

consumption

Scaled from EPA-OW estimates

5. Avoided IQ losses from mercury Reduced in-utero mercury exposure from 

maternal fish consumption

Scaled from EPA-OW estimates

 

262 To the extent that EPA-OW’s analyses change in the SPGELG final rule, the results in this RIA would move accordingly.
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Exhibit 5-A

Summary of Monetized Benefit Categories 

Benefit Category Physical Foundation of Benefit Estimation Methodology

6. Avoided IQ losses from lead Reduced childhood exposure to lead from fish 

consumption

Scaled from EPA-OW estimates

7. Reduced need for specialized 

education

Reduced childhood exposure to lead from fish 

consumption

Scaled from EPA-OW estimates

8. Non-market surface water quality 

benefits, including: improved aquatic 

and wildlife habitat; enhanced waterbased recreation; aesthetic surface 

water improvements; non-use 

ecosystem services; and reduced 

risks to aquatic wildlife

Improved ambient water quality in receiving 

reaches, including improved designated use 

attainment and ecosystem health

Scaled from EPA-OW estimates

9. Protection of threatened and 

endangered species in vicinity of 

CCR units

Habitat improvements leading to potential 

increases in threatened and endangered species’ 

populations

Scaled from EPA-OW estimates

10. Improved air quality from 

electricy plant emissions, including 

reduced air pollutant emissions of 

NOx, SO2, particulate matter, and&

CO2

Reduced mortality and morbidity from exposure 

to air pollutants; avoided climate change impacts

Scaled from EPA-OW estimates

11. Reduced groundwater 

withdrawals (after conversion from 

wet to dry CCR handling)

Increased availability of groundwater resources Scaled from EPA-OW estimates

To apply benefits of the SPGELG rule to the CCR rule, this RIA uses the monetized annual 

benefits associated with EPA-OW’s ELG4 regulatory option because that option requires (a) dry 

handling for the two largest CCR categories (bottom ash and fly ash), and (b) tank systems for 

the third largest CCR category (FGD).263 On an annual CCR disposal tonnage basis, these three 

categories of CCR constitute almost 100% of the four main CCR type categories (i.e., bottom 

ash, fly ash, FGD, and “other” CCR) evaluated in this RIA for the CCR rule. In addition, these 

three CCR categories are also affected to varying degrees under the CCR final rule for (a) 

possible conversion to dry handling in lieu of retrofitting CCR ponds with liners (fly ash and 

bottom ash), and (b) conversion from FGD impoundments to FGD tank systems. This RIA scales 

values for the monetized benefits from the SPGELG proposed rule using the following three-step 

method:

264

Step 1: Determine the Fraction of EPA-OW’s Total Monetized Benefits Associated with 

Bottom Ash, Fly Ash, and FGD Pollutant Removals

The monetized benefits estimated in EPA-OW’s benefit-cost analysis for the 2013 SPGELG 

proposed rule are physically founded on anticipated future annual reductions in current (baseline) 

pollutant discharges (aka “loadings”) at coal-fired electric utility plants. The 2013 SPGELG 

proposed rule is broader in scope than the CCR rule because it regulates four other types of 

 

263 Source: The compliance technology requirements for each regulatory option of EPA-OW’s June 7, 2013 “Steam Power 

Generating Effluent Limitations Guidelines” proposed rule are displayed in “Table 1-1. Steam Electric Regulatory Options” of 

“Benefit and Cost Analysis for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category,” EPA Office of Water, EPA report nr. EPA 821-R-13-004, April 2013, available from the 

Federal regulatory docket as document ID nr. EPA-HQ-OW-2009-0819-2238 at http://www.regulations.gov

264 In creating and applying this scaling factor, this RIA employs the assumption that a linear relationship exists between 

pollution inputs and benefits. If this relationship takes a different functional form, the scaling factor may result in an 

understatement or overstatement of benefits. Additionally, this RIA assumes that plant management and closure behavior are 

similar under SPGELG and the CCR final rule.
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electric utility plants (oil-fired plants, gas-fired plants, petroleum coke-fired plants, and nuclear 

plants), and three other types of power plant wastes (flue gas mercury control wastewaters, 

gasification system wastewaters, and non-chemical metal cleaning wastes).

Because it is broader in scope, the first step in adopting EPA-OW’s monetized benefits for the 

CCR rule is to reduce EPA-OW’s aggregate benefits to fit the scope of the CCR rule. One of 

EPA-OW’s technical documents in support of the 2013 SPGELG provides a breakdown of 

estimated reduction in pollutant discharges for each of its regulatory options for four of the seven 

wastes the SPGELG rule proposes to regulate.265, 266 The estimated pollutant removals for the 

ELG4 regulatory option are:

 

265 Source: Table 10-13 (FGD), Table 10-17 (fly ash and bottom ash), and Table 10-21 (landfill leachate) pollutant removals from 

Chapter 10 of “Incremental Costs and Pollutant Removals for the Proposed Effluent Limitations Guidelines and Standards for the 

Steam Electric Power Generating Point Source Category,” EPA Office of Water, April 2013, available as document ID nr. EPAHQ-OW-2009-0819-2256 at http://www.regulations.gov

266 As explained on pages 10-1 and 10-2 of EPA-OW’s “Incremental Costs and Pollutant Removals for the Proposed Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category” (April 2013, document 

ID nr. EPA-HQ-OW-2009-0819-2256 available at http://www.regulations.gov) for the June 2013 SPGELG proposed rule, EPAOW’s pollutant removal analysis only evaluated four of the seven wastes covered by the SPGELG proposed rule (i.e., FDG, fly 

ash, bottom ash, and landfill leachate) because EPA-OW determined that baseline pollutant discharges (aka “loadings”) would 

equal post-compliance discharges for the other three wastes covered by the rule (i.e., flue gas mercury control wastewaters, 

gasification system wastewaters, and non-chemical metal cleaning wastes) relative to current (baseline) technologies installed at 

power plants for management of those three wastes.
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Waste Type

Pollutant removals estimated for

EPA-OW’s ELG4 option (pounds/year)

 FGD pollutant removals 1,160,000,000 34.6%

 Fly ash pollutant removals 478,000,000 14.3%

 Bottom ash pollutant removals 1,700,000,000 50.8%

 Landfill leachate pollutant removals 8,900,000 0.3%

Column total = 3,346,900,000 100%

Because the CCR rule exempts existing CCR landfills from CCR pollution control requirements, 

including exemption from the leachate collection system requirement, this RIA subtracts EPAOW’s landfill leachate pollutant removals displayed above. This step results in an aggregate 

benefit reduction multiplier of 99.7% (i.e., 100% - 0.3%).

Step 2: Calculate the Percentage of Annual CCR Pond Tonnage Associated with EPAOW’s Benefits

This step calculates a second scaling factor in relation to the percentage of baseline annual CCR 

pond disposal tonnage affected by EPA-OW’s ELG4 option. As displayed in Exhibit 2-I of this 

RIA, the 2009 EIA-923 CCR management data delineates four main categories of CCR: bottom 

ash, fly ash, FGD, and other. Using the “On-site Ponds” tonnages from the second column of 

Exhibit 2-I, the respective annual pond tonnage percentages for each CCR category are:

CCR Type Category Annual Tons CCR Disposal in Ponds

 Bottom ash 3.301 million tons/year 22%

 Fly ash 6.961 million tons/year 47%

 FGD 4.202 million tons/year 29%

 Other CCR 0.275 million tons/year 2%

 Column total = 14.7 million tons/year 100%

This RIA estimates that the ELG4 dry handling technology requirement affects 93% of baseline 

annual CCR pond disposal tonnage, based on the following assumptions:

 ELG4 dry handling technology: The ELG4 dry handling technology requirement 

applies to both bottom ash (22% of tonnage) and fly ash (47%). This RIA 

assumes the ELG4 dry handling requirement for FGMC wastewater falls under 

the “other” CCR category of this RIA and thus does not add to this 69% subtotal.

 ELG4 closed loop technology: The ELG4 option also allows for closed loop 

technology for bottom ash in lieu of dry handling. To simulate that possibility, 

this RIA assumes that a small percentage (5%) of annual bottom ash pond 

tonnage will choose closed loop technology rather than dry handling to be in 

compliance with ELG4. The RIA therefore adjusts the 69% subtotal by five 

percentage points to generate an adjusted subtotal of 64% of CCR pond tonnage 

associated with the ELG4 dry handling requirement.

 ELG4 tank system requirement: The ELG4 option requires ponded FGD to be 

managed in tank systems. This step therefore adds the 29% FGD pond tonnage to 
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the 64% adjusted subtotal from above. As a result, this step estimates that 93% of 

annual CCR pond tonnage would be affected under ELG4.

In order to apply benefits to all of the annual CCR pond tonnage, this RIA adjusts the scaling 

factor upward to account for the additional CCR pond tonnage not associated with ELG4 

benefits.

Step 3: Calculate the Overall Benefits Scaling Multiplier

Note: EPA has updated the the assumptions in calculating this multiplier. These updates are 

not reflected in the text and exhibits in this section. See Sections 9.2.5 and 9.4 in Chapter 9

of this RIA for a description of the relevant modifications and the resultant re-estimated 

benefits for the CCR final rule.

This RIA thus adapts the monetized benefits estimates of the ELG4 option to the CCR rule by 

scaling for the CCR types affected by the CCR rule (Step 1: 99.7%) and for the percentage of 

annual CCR pond tonnage affected by the ELG4 option (Step 2: 93%). These two scaling factors 

are applied to the expected future percentage of CCR tonnage associated with impoundments 

that this RIA estimates might close and convert to dry handling under the CCR rule. Such 

transfer of tonnage results in the expected benefits this RIA applies from the SPGELG rule. The 

resultant multiplier is displayed in Exhibit 5-B.

Note: This exhibit has not been updated to reflect the revisions described in Section 9.2.6 in 

Chapter 9 of this RIA.

Exhibit 5-B

Scaling Multiplier for Applying EPA-OW’s Monetized SPGELG Rule Benefits to this RIA

Pond tonnage conversion 

to dry handling

Resultant benefits scaling 

multiplier relative to EPA-OW’s 

ELG4 option

Baseline 45% (45% x 99.7%)/93% = 0.49

CCR final rule 64% (64% x 99.7%)/93% = 0.69

Note: The percentages shown here differ somewhat from those shown in Exhibits 4-T and 4-U. This discrepancy occurs 

because the calculation of the scaling multiplier for applying EPA-OW’s monetized SPGELG rule benefits to this RIA takes 

into account the closure of disposal impoundments as well as storage impoundments by considering both the actual tonnage 

associated with each closing disposal impoundment and the estimated tonnage associated with each eventually-closing 

storage impoundment (even though closing storage impoundments in the post-rule scenario are assumed to be replaced with 

new, lined storage impoundments), whereas the exhibits in Chapter 4 consider the actual tonnage associated with disposal 

impoundments only. This results in a more conservative scaling multiplier than considering only the actual tonnage, and 

serves as a more reasonably proxy for the CCR pond pollutant volume affected by the CCR rule by taking storage 

impoundment wastes and capacities into account.

This method of adapting benefits estimates from the SPGELG proposed rule to the CCR rule is 

appropriate because the physical foundations of all benefits are either directly or indirectly 

related to the CCR pond pollutant loadings evaluated in Step 1 above. The benefits estimated by 

the proposed SPGELG rule that apply to surface water and that are associated with controls on 

discharges from power plants will not accrue to SPGELG. Instead, because the CCR final rule 

requirements will be effective first, these benefits will occur due to removal of surface water 

pollutants under the CCR final rule. Furthermore, this scaling method is analytically consistent 

with EPA-OW’s linear interpolation method for estimating these same benefits for the other 
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regulatory options not explicitly analyzed in EPA-OW’s RIA for the 2013 SPGELG proposed 

rule. This method is described in Section 10.3 Inferred Benefits for Regulatory Options Not 

Analyzed Explicitly of EPA-OW’s April 2013 RIA.

The following sections discuss each of the 11 monetized benefit categories in detail, beginning 

with the three benefit categories monetized using methodologies specific to this RIA, followed 

by the remaining eight benefits that are scaled from EPA-OW’s RIA for the SPGELG rule.

5.1 Avoided CCR Impoundment Releases

On December 22, 2008, the failure of a CCR impoundment at the Tennessee Valley Authority 

(TVA) Kingston Fossil Plant in TN resulted in the environmental release of 5.4 million cubic 

yards of CCR. This failure illustrates the potential severity of environmental damages resulting 

from CCR impoundment structural failures. This section of the RIA estimates the benefit 

category consisting of avoided costs associated with the preventionreduction of future releases, 

including those from structural failures.267 Avoided costs are determined on a per-gallon of spill 

basis and are calculated by applying per gallon costs to the volume of avoided spills, according 

to the following expression:

Number of open surface impoundments in the baseline

× Reduced overall annual probability of failure

× Gallons released per failure (capacity factor)

× Cost per gallon released

The first variable of this expression is derived from the RIA’s cost estimation, and reflects the 

probabilities of surface impoundment closure over the timeframe of the analysis. Estimation of 

the reduced annual probability of release and the capacity factor are explained below. This RIA 

estimates the cost per gallon spilled due to impoundment releases as consisting of three 

components:

1. Remediation cost: Cost of cleanup and response activities following a 

release.

2. NRD cost: Natural resource damages (NRD) that occur despite 

remediation efforts.

3. Transaction cost: Transaction costs are those costs associated with

initiating and coordinating the cleanup. To estimate 

them, this RIA relies on a proxy consisting of legal 

costs, including the legal determination of party 

responsibility and the settlement of claims, not 

including settlement values.

 

267 Avoided costs are from the expected future avoidance of multiple types of CCR impoundment release events, including major 

structural failures such as wall breaches, as well as relatively smaller releases from wall seepage, overtopping, embankment 

sloughing, and miscellaneous failures to impoundment appurtenant structures (e.g., pumps, discharge structures, decant weirs, 

and hydraulic piping).
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This section begins broadly with a discussion of the risk factors driving impoundment release, 

and then presents the selected methodologies for estimating these components of this benefit 

category.

5.1.1 Risk Factors and Methodology

Many factors may contribute to releases from CCR impoundments. Ideally, this RIA would 

incorporate each of these into the development of a risk profile for each impoundment. For 

example, the following seven factors, based on factors affecting water levee structural failure 

risk, are important in determining CCR impoundment release risk:268

1. Hydrologic factors. Flood frequency and volume (or depth) of the impoundment, 

which may depend on CCR generation and sluicing rates, as well as on weatherrelated factors such as snow melt, rainfall, and rainfall–runoff characteristics 

around the impoundment, spatial and temporal distributions of the precipitation, 

variations in soil moisture, rain interception, and surrounding land use.

2. Hydraulic factors. Geometry of the impoundment—for example, the roughness 

and slope of the embankment walls and bed. Hydraulic factors also include the 

effects of hydraulic structures in the impoundment such as weirs, sluices, gates, 

valves, bridges, intakes, and other diversion structures; the effects of CCR and 

other sediments contained in the impoundment, including effects of erosion, 

scour, and deposition; and for larger impoundments, the effects of wind and 

waves.

3. Structural and geotechnical factors. Geologic properties of the impoundment 

foundation; seepage through and cutoff beneath impoundment walls; internal 

erosion or piping of impounded materials; strength instabilities in impoundment 

walls (embankments) or the subsurface; deep seepage failure away from the 

impoundment; and other soil mechanics issues.

4. Seismic factors. Frequency and magnitude of earthquakes; fault and tectonic 

characteristics; earthquake-induced ground motion at the impoundment site and 

liquefaction of impoundment foundation soil; and flooding probability (i.e.,

waterborne CCR release) associated with earthquake-induced impoundment 

failure.

5. Materials and construction factors. Age, type and quality of materials used to 

construct the impoundment; thermal and moisture variations affecting 

impoundment quality during construction and its service period; and construction 

quality control.

6. Other geophysical factors. Ice action within the impoundment or in surrounding 

(e.g., riparian) areas; possible flash flooding of the impoundment from failure of 

nearby dams, levees, or other riparian or coastal facilities; thunder/lightning 

destruction; and tornadoes or other weather-related impacts.

 

268 "Risk Analysis and Uncertainty in Flood Damage Reduction Studies," Committee on Risk-Based Analysis for Flood Damage 

Reduction, Water Science and Technology Board, Commission on Geosciences, Environment, and Resources, National Research 

Council, National Academy Press, Washington, D.C., 2000.
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7. Operational and maintenance factors. Operational procedures for water 

diversion and release prior to and during flooding; operational procedures when 

an incident occurs; safety inspections of the impoundment and nearby river or 

coastal sites; repair and maintenance rules; other nearby land use controls; and 

embankment vegetation cover.

Because the above risk factors cannot be incorporated directly, this RIA relies on information 

collected in survey letters mailed by EPA in March and April 2009 to electric utility companies 

to specifically assess the integrity of CCR impoundments.269 These surveys include data on 

variables that reflect the above risk factors, such as the unit age, capacity, involvement of a 

professional engineer in design, construction, and monitoring of the unit, frequency of site 

evaluations (i.e., frequency of site inspections, geo-tech tests, hydraulic tests), and the occurrence 

of previous structural failures.

5.1.2 Avoided Impoundment Release Remediation Costs

Note: EPA has updated this section of the RIA to reflect revised assumptions about failure 

probabilities and capacity factors. See Section 9.2.6 in Chapter 9 of this RIA for a description 

of the relevant modifications and updates.

This section describes the methods used to evaluate benefits of preventingreducing future 

impoundment releases. These benefits are the direct result of impoundment closures and 

impoundment structural integrity requirements, including regular inspections and other 

safeguards. These structural integrity requirements achieve benefits by reducing risk and 

preventingreducing costly remediation, but also lead to increases in costs related to additional 

inspections (addressed in Chapter 4). This section first discusses estimation of the risk of release

at each impoundment, and then presents the remediation costs applied to expected impoundment 

releases. Finally, this section discusses key assumptions applied to the baseline and each option. 

Quantifying Probability of Impoundment Structural Failure and Release Volume

Number of open surface impoundments

× Reduced overall annual probability of failure

× Gallons released per failure (capacity factor)

× Cost per gallon released

To characterize the risk of impoundment release, this RIA relies on information collected in 

survey letters mailed by EPA in early 2009 to electric utilities to request descriptive information 

about CCR impoundments.270 These surveys include data on risk factors, such as unit age, 

capacity, involvement of a professional engineer in design, construction, and monitoring of the 

unit, frequency of site evaluations (i.e., frequency of site inspections, geo-tech tests, hydraulic 

tests), and the occurrence of previous structural failures. This RIA uses these data to assign an 

 

269 Additional information about EPA’s March and April 2009 information request letters mailed to electric utility companies is 

available at http://www.epa.gov/waste/nonhaz/industrial/special/fossil/coalashletter.htm#letter

270 Additional information about EPA’s March and April 2009 information request letters mailed to electric utility companies is 

available at http://www.epa.gov/waste/nonhaz/industrial/special/fossil/coalashletter.htm#letter.
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average annual probability of release and an average capacity factor based on impoundment size 

(big or small) and release type (wall breach or other release). 271 Appendix P presents the 

derivations of the values in detail as well as the assumptions governing these derivations.

In March and April of 2009, EPA collected survey data from 162 individual electric utility plants 

and 61 electric utility corporate headquarters under the authority of CERCLA Section 104(e). 

EPA identified these plants and offices from DOE’s 2005 Energy Information Agency F767 

database, which provides information on the disposition of coal ash from coal burning electricity 

producers. EPA also sent letters to the corporate offices of electric utilities to ensure that all 

utility plants had been identified. Based on information received in response to these letters, EPA 

sent information requests to an additional 48 plants on April 27, 2009. Responses were received 

from 240 electric utility companies, providing information on 676 surface impoundments. Of 

these, 20 represented types of impoundments other than CCR impoundments (e.g., coal pile 

sumps, metal cleaning waste impoundments, wastewater treatment impoundments), reducing the 

total survey count of CCR impoundments to 656. The surveys reported 47 historical CCR 

impoundment release cases over the ten year time frame of the survey (i.e., 1999 to 2008) and 

one release each in two of the years prior to study start year (1995 and 1998). Exhibit 5-C

provides summary statistics of the physical characteristics and timing of the 49 release events. 

Exhibit 1 in Appendix P provides additional information for each of these 49 release cases.

Exhibit 5-C

Summary Statistics for the 49 CCR Impoundment Release Events 

1995-2009

Capacity

(acre-feet)

Height

(feet)

CCR gallons 

released

Year of

release

Observations 48 49 18 45

Minimum = 2 0 50 1995

Median = 2,201 42 6,102 2006

Maximum = 84,300 400 1,100,000,000 2009

Because the EPA survey only requested information about events occurring during the previous 

10 years (2000-2009), additional information provided voluntarily on releases occurring between 

1995 and 2000 is likely to be incomplete. However, the releases reported between 1995 and 2000 

likely encompass all major failures occurring during that time period, assuming that EPA would 

already have been aware of any “catastrophic” failures. Therefore, although these five years of 

data probably exclude smaller releases, the largest failures – which contribute most significantly 

to the benefits of the CCR rule – are likely captured. Furthermore, the probability of release 

analysis presented in Appendix P controls for the number of years for those observations that 

were noted prior to 2000 in determining annual release risks. Utilities were not required to report 

releases prior to the 2009 survey, so release data for years before 1995 are not available. 

The pre-rule baseline probabilities of CCR impoundment failure releases were calculated using 

the survey data set. Of the 49 historical releases, 8% were wall breach releases and the remaining 

92% were other types of releases, including wall seepage and overtopping. Release probabilities 

 

271 Capacity factor refers to the percentage of impoundment capacity released during a spill event. For example, if an 

impoundment has a capacity of 2,000 acre-feet and the capacity factor for a wall breach event is 27%, the size of a wall breach 

spill event would be 540 acre-feet ((2,000 * 0.27).
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for each type of release were calculated separately for two impoundment size categories: big and 

small. Big is defined based on two size criteria applicable to the impoundment “factors of safety” 

design criteria structural integrity requirements of the CCR final rule: height and storage volume 

Specifically, big impoundments meet the following criteria:

 Height (impounding elevation) of 

five feet or more above the upstream 

toe, and

 Storage volume of 20 acre-feet or 

more

 Height (impounding elevation) of 20 

feet or more above the upstream 

totoe

The probabilities were calculated assuming that each year of an impoundment over the time 

frame of the survey represents an observation. The ratio of the total number of releases of a 

certain type from an impoundment of a given size to the appropriate number of observations 

related to the scenario provides the release probability. Exhibit 5-D illustrates the calculated 

probabilities for the dataset. To understand the size of a given release, all spill volumes reported 

in the survey (18 of the 49 releases) were compared to the respective impoundment capacity. 

That is, spills as a percent of impoundment capacity, or capacity factors, were calculated to 

understand average release volumes under different factors (i.e., wall breach releases from big 

impoundments). Capacity factors are applied to the overall impoundment capacities to derive the 

volume of a spill from the ponds. From this volume estimate, costs are calculated from per gallon 

cost estimates for various categories. Exhibit 5-D displays the average capacity factors for the 

historical releases overall and for the two types of releases at the two different sizes of 

impoundments.

This RIA averages the upper-bound and lower-bound estimates (0.044% and 0.023% 

respectively) and applies a post-rule wall breach failure rate of 0.034%. The changes in the 

probability of “other release” events for active CCR impoundments, both big and small, and the 

changes in capacity factors associated with these events is described in detail in Exhibit 4 in 

Appendix P. 

This RIA assumes that under the CCR rule, location restrictions, stormwater run-on/run-off 

controls, and impoundment structural integrity requirements may prevent and thereby reduce 

future CCR impoundment release events. The post-rule release rates and capacity factors are 

shown in Exhibit 5-E. Although the elements of the CCR rule are designed to preventreduce as 

close to 100% of impoundment wall breach failures from active, large impoundments as 

possible, there will always be a risk of failures due to circumstances beyond reasonable control, 

such as extreme precipitation events, seismic activity, and other natural events that exceed the 

design criteria for impoundments. Furthermore, due to human error and latent defects that may 

not be detected, some risk of wall breach failure will always exist. Rico et al (2008)272 evaluated 

 

272 M. Rico, G. Benito, A.R. Salquerio, A. Diez-Herrero, H.G. Pereira, “Reported Tailings Dam Failures: A Review of the 

European Incidents in the Worldwide Context,” Journal of Hazardous Materials, Vol. 152, 2008, pp. 846-852; 

http://www.elsevier.com/locate/jhazmat

or
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historical mine tailings dam failures and determined a post-rule wall breach failure rate of 

0.044%. In analyzing historical CCR wall breach failure events, at least one of four such events 

from 1999-2008 was due to human error. Therefore, assuming that the CCR rule requirement 

would be 75% effective, the post-rule release rate would be expected to decline from 0.09% to 

0.023%. 
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Note: EPA has updated this exhibit; see Section 9.2.6 and Exhibit 9-D in Chapter 9 of this RIA 

for a description of the relevant modifications and updates to this exhibit.

Exhibit 5-D

Future Pre-Rule Baseline Probabilities of CCR Impoundment Failure Releases Based on Analysis 

of 49 Historical Failure Events 1995-2008

Notes:

(1) “Other” releases include wall seepage and overtopping.

To determine the post-rule values, assumptions are made regarding the potential efficacy of the 

CCR final CCRrule requirements to have preventedreduce these types of historical release 

events. These non-wall breach releases include wall seepage, overtopping from severe rainfall or 

adjacent riparian flood event, pump failure, and liner holes. Release rates at inactive 

impoundments of all sizes are assumed to be driven to 0% under the final CCR rule.
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Note: EPA has updated this exhibit of the RIA; see Section 9.2.6 and Exhibit 9-D in Chapter 9

of this RIA for a description of the relevant modifications and updates to this exhibit.

Exhibit 5-E.

Summary of Post-Rule Future Probabilities and Capacity Factors for Different Impoundment 

Sizes, Types, and Release Events

Exhibit 5-F below summarizes the future CCR impoundment release scenarios for the baseline 

and under the CCR final rule. Compared to the future average annual release rate of 0.09% in the 

baseline (without the CCR rule), the 0.034% residual annual rate, combined with future closures, 

represents a 68% reduction in future wall breach events.
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Note: This exhibit has not been updated to reflect the revisions described in Section 9.2.6 in 

Chapter 9 of this RIA.

Exhibit 5-F

Estimate of Future CCR Impoundment Releasesa

Baseline Scenario (w/out Rule) CCR Final Rule Scenario

Predicted count of operating 

impoundments, year 2114 687 637

Release Type Wall Breach “Other” Release Wall Breach “Other” Release

Impoundment Status Active Future 

Closure Active Future Closure Active Future Closure Active Future Closure

Predicted cumulative releases 

(2015-2114) 44 3 489 31 15 0 91 0

% reduction in cumulative 

releases n/a n/a n/a n/a 66% 100% 81% 100%

Total predicted cumulative 

releases

(2015-2114)

47 520 15 91

Total % reduction in cumulative 

releases n/a n/a 68% 83%

a

Impoundment closure probabilities over the analysis period are as predicted by the cost model.

It should be noted that the data set from which these probabilities and capacity factors were 

calculated involves repeat releases involving the same CCR impoundment (17 of the failure 

cases involve an impoundment involved in at least one other failure). These second (and in a few 

cases, third) releases raise uncertainty about whether the releases are unique events, as opposed 

to the same event recorded in two different years. These data may suggest that some 

impoundments have a relatively higher probability of release because the impoundments are 

poorly maintained or the operator failed to repair structural deficiencies. Including these repeat 

releases in the historical rate may overestimate the future probability of release for separate 

impoundments.

The most significant limitation of the data, as used in this analysis, is the short time frame for 

which complete data are available. This 10-year (2000-2009) history of releases, along with the 

two additional reported releases prior to this time frame, limits the ability of this RIA to evaluate 

the risks of release over time (i.e., impoundment age). Intuitively, time should contribute to the 

risk of release, both through the degradation of impoundments and increasing loads of CCR. 

Unlike dams, which face nearly constant pressure over time from the water contained behind the 

structure, CCR impoundments face increasing pressure as additional CCR is generated and 

added to the impoundment each year. Additionally, the years of available data show little 

variation in age among impoundments, many of which were commissioned around the same 

year. The data therefore lack important information on changes in rates of release occurring 

throughout the lifetimes of these impoundments. Although the lack of data is a significant 

challenge for this analysis, supplementing or amending the data set is not considered a 

reasonable approach. For example, this analysis could have investigated historical failure rates of 

dams, but for the reasons described above, the change in risk of dam failure over time may differ 

significantly from the risk at impoundments. Sensitivity analyses discussed in Chapter 7

evaluate changes in probability of release and fluctuations in the capacity factors.
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Assigning Impoundment Release Remediation Costs

Number of open surface impoundments

× Reduced overall annual probability of failure

× Gallons released per failure (capacity factor)

× Cost per gallon released

To estimate remediation costs associated with the average annual rate of impoundment releases, 

this RIA relies on the results of a literature review conducted in 2014 for EPA by Abt Associates

(attached as Appendix Q).

273 This review compiles and summarizes the remediation costs from 

five historical impoundment failures for which cleanup costs were available. The remediation

costs from these historical releases are summarized in Exhibit 1 in Appendix Q and reproduced 

here as Exhibit 5-G. The average remediation costs from the examined release events was 

determined to be $1.35 per gallon spilled.

Exhibit 5-G

Documented Remediation Costs from Impoundment Releases

Incident A B C (B/A)

Incident

Volume Spilled

(million gallons)

Remediation Costs

(millions; 2013$)

UnitUnitized

Remediation Costs 

(dollars2013$ per 

gallon)

(2013$)

1. Oak Creek WI 5 $13 $2.83

2. TVA Widows Creek AL 6 $10 $1.64

3. Martins Creek PA 100 $62 $0.62

4. Massey KY 230 $89 $0.39

5. TVA Kingston TN 1,100 $1,379 $1.25

Column Average = 288 $311 $1.35

Column Median = 100 $62 $1.25

While this methodology for determining impoundment release remediation costs relies on actual 

data from historical release events, it is important to note several limitations to this approach. 

First, by assigning one average value to all events, less granularity exists in capturing the drivers 

of remediation costs for each release. Factors influencing the remediation costs are averaged 

across all impoundments rather than identified and applied individually to each impoundment. 

Additionally, by relying on a unit remediation cost, the division between fixed and variable costs 

is blurred. For a spill of any size, there is likely to be a certain minimum cost to be incurred to 

undergo cleanup procedures. Increases in the spill volume on the margin may have little 

influence on the per gallon cost, until an additional threshold is reached (i.e., the spill is 

sufficiently large to reach downstream populations). By averaging per gallon remediation costs, 

such nuances may be lost.

 

273 Previously, thresholds for population densities surrounding impoundments and impoundment capacities were utilized to bin 

CCR impound ments into one of nine cost categories. Each cost category was assigned one of three cost values, representing low, 

medium, and high costs, derived from three of the documented CCR impoundment releases included in Exhibit 5-E.
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For each year of the analysis, this RIA estimates future remediation cost as the sum of the 

probability that an impoundment is active and fails, resulting in either a wall breach or an “other” 

release, at an individual impoundment multiplied by its assigned expected remediation cost. This 

RIA sums remediation, NRD, and transaction costs (see following sections) to obtain the 

estimated overall cost per year under the CCR final rule, as well as under the baseline.

5.1.3 Avoided Natural Resource Damages from CCR Impoundment Releases

Number of open surface impoundments

× Reduced overall annual probability of failure

× Gallons released per failure (capacity factor)

× Cost per gallon released

If a release occurs, natural resource damages (NRD) would be expected to be incurred in 

addition to remediation costs. Whereas remediation costs are spent to clean up contamination, 

NRD reflect the costs to society of lost and damaged ecological resources. NRD are typically 

measured as the cost of restoring ecosystems to their pre-contamination state and compensating 

the public for interim losses of natural resource services between the time of contamination and 

time of full restoration to baseline. NRD costs are recoverable under CERCLA, and this RIA 

assumes that for any release event, such damages will be pursued. The avoided NRD costs 

represent savings to the potential responsible party, in these cases the power-generating 

facilityelectric utility plant owner. To estimate NRD costs avoided as a result of 

preventedreduced releases, this RIA employs available literature.274 A summary of this literature 

review of NRD costs prepared by Abt Associates is found in Appendix R. The review compares 

total NRD costs to total impoundment release remediation costs for the included cases and

determines that the mean NRD assessments represent 4% of mean impoundment release 

remediation costs.

The mean NRD costs were obtained from the most comprehensive, single source of published 

information describing the magnitude of NRD at U.S. sites prepared by the law firm Arnold and 

Porter. 275 This information results in a universe of 137 site-specific NRD values and is included 

in Appendix R. In calculating the mean NRD costs, several types of cases were excluded that 

represent types of damage different than those expected with CCR impoundment releases. 

Specifically, cases affecting only groundwater or marine water or cases associated with 

Superfund sites were excluded from the analysis.

Assumptions and Caveats

Many factors influence the scale of NRD associated with a particular event, such that two release 

events of exactly the same substance (e.g., coal ash) and size, but at two different locations and 

points in time, could easily produce very different claims. Thus, even if a large sample of NRD 

cases associated with coal ash releases were available, it could only serve to bound the likely 

order of magnitude of damages for any particular event. In the absence of a directly analogous 

sample, a large sample of settled or otherwise resolved damage claims representing a wide 

 

274 The previous methodology determined thresholds for two factors: habitat density and capacity. NRD costs were assigned to 

each of the nine bins created from these two factors. The total NRD costs were determined by reviewing historical NRD 

settlements and selecting the average costs within each of three natural bins of costs.

275 Israel, Brian D. State-by-State Guide to NRD Programs in All 50 States. Arnold and Porter LLP. November 12, 2009. 
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variety of release event types provides the soundest basis for establishing the order of magnitude 

of damages for releases of different sizes.

As with the remediation costs, this RIA’s methodology of averaging all available values masks 

nuances in the data and does not recognize key drivers of the costs. For example, NRD costs are 

primarily based on the value of the affected resource rather than the magnitude of the damage 

event. By indirectly linking NRD costs to the size of the CCR impoundment release, the 

variation in costs is attributable to spill size rather than to potentially affected natural resources.

Ideally, this analysis would use GIS data to build a location-specific habitat description for each 

of the impoundments in the universe. However, habitat factors that drive NRD values vary 

widely with location, reflecting altitude, geology, local climatic conditions, and combinations of 

terrestrial and aquatic species with differing values. The value of habitat is also linked to the 

location-specific recreational opportunities it provides. While detailed, high-resolution spatial 

data are available to characterize site-specific features, the scope of the impoundment universe is 

too broad to allow a detailed assessment of site-specific habitat.

This RIA considers NRD settlement values to be additive to remediation costs. While CERCLA 

allows for the recovery of remediation costs as part of the damages to natural resources, case 

studies suggest that NRD settlements typically include costs to restore natural resources and 

compensation for interim loss of natural resource services separate from remediation costs. Often 

this occurs because remediation costs are more straightforward in their estimation and are known 

earlier than other NRD damage categories. For example, information on response costs 

associated with the Kingston spill suggests that remediation costs are identified separately from 

interim loss and restoration costs. In the TVA Quarterly Report dated August 11, 2011, TVA 

states that the estimated range of remediation costs of $1.1 to $1.2 billion does not include costs 

associated with “natural resources damages [...], outcomes of lawsuits, future claims, [and] 

long-term environmental impact costs.”

276 TVA suggests that for the Kingston failure these costs 

may not be reasonably estimated at this time.

Using the methodology for remediation costs, for each year of the analysis, this RIA calculates 

expected NRD costs as the sum of the probability of an impoundment being active and 

experiencing a release (i.e., accounting for the effects of structural integrity requirements) 

multiplied by its assigned potential NRD cost.

5.1.4 Avoided Transaction Costs from Releases

Number of open surface impoundments

× Reduced overall annual probability of failure

× Gallons released per failure (capacity factor)

× Cost per gallon released

In addition to remediation costs and NRD, transaction costs as a result of impoundment releases 

can be significant. Transaction costs include litigation costs incurred in the process of negotiating 

NRD, determining responsibility of individual parties, and litigating details regarding settlements 

and remediation. To use the 2008 Kingston failure as an example, litigation costs incurred by 

 

276 TVA Form 10-Q for the period ending June 30, 2011, page 17.
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TVA and paid to the Shook Hardy and Bacon law firm were reported at $11 million as of 

December 2011.277 These costs are reported to occur “on top of TVA’s $1.2 billion spill 

cleanup.”278 Because these costs are ongoing and do not include expenses incurred by parties 

other than TVA, the Kingston $11 million value is not considered representative of typical 

litigation costs. 

To estimate transaction costs associated with impoundment releases, this RIA relies on a review 

of the economic literature on litigation and transaction costs. Four publications present a range of 

typical litigation costs as a percentage of total expenditures on remediation at Superfund sites.279

Although Superfund remediation may not be a perfect proxy for CCR impoundment failures, the 

share of litigation costs incurred should provide a reasonable estimate of the potential magnitude 

of transaction costs. Based on these four studies, the average transaction costs represent 37% of 

remediation costs. This RIA therefore adopts the average value of litigation costs equal to $0.50

per gallon released (in 2013 dollars). This RIA estimates transaction costs as additional to the 

remediation costs and NRD costs for each impoundment in each year of the analysis. Total costs, 

including remediation, NRD, and transaction costs, are shown by capacity and density categories 

in Exhibit 5-H.

Exhibit 5-H

Total Impoundment Release Costs

Cost Category

$/Gallon of Release

(2013$)

Percentage of 

Remediation Costs

Remediation $1.35 ---

Natural Resource 

Damages $0.05 4%

Transaction $0.50 37%

Total Impoundment 

Release $1.90 ---

5.2 Avoided Groundwater Contamination by CCR Surface Impoundments

This section estimates the potential future benefits associated with controlling arsenic from 

onsite landfills and surface impoundments. These benefits include avoided costs of groundwater 

corrective action (remediation), the value of avoided NRD, and avoided transaction (proxied by

litigation) costs. The benefits estimated in this section stem from impoundment closures, the 

addition of impoundment liners, and groundwater monitoring requirements established under the 

 

277 “TVA says legal costs have reached almost $11 million for the Kingston Plant coal ash spill.” Associated Press. December 16, 

2011. Accessed through the Chattanooga Times Free Press at: http://www.timesfreepress.com/news/2011/dec/16/tva-says-legalcosts-have-reached-almost-11-millio/

278 “TVA says legal costs have reached almost $11 million for the Kingston Plant coal ash spill.” Associated Press. December 16, 

2011. Accessed through the Chattanooga Times Free Press at: http://www.timesfreepress.com/news/2011/dec/16/tva-says-legalcosts-have-reached-almost-11-millio/ 

279 These four sources include:

1. Acton, Jan Paul, and Lloyd S. Dixon. "Superfund and transaction costs: the experiences of insurers and very large 

industrial firms." RAND (1992).

2. Congressional Budget Office Testimony. Statement of Jan Paul Acton. April 27, 1995.

3. Dixon, Lloyd S., Deborah S. Drezner, and James K. Hammitt. "Private-sector cleanup expenditures and transaction 

costs at 18 Superfund sites." RAND (1993).

4. General Accounting Office. "Superfund: Legal expenses for cleanup-related activities of major U.S. corporations." 

Report to Congressional Requesters. December 23, 1994.
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CCR final rule. Because the CCR rule requires groundwater monitoring wells to be installed one 

year after the effective date of the final rule, compliance with the groundwater monitoring 

requirements addresses much of the baseline groundwater contamination.

5.2.1 Avoided Groundwater Remediation Costs

The baseline for this analysis includes some groundwater monitoring. As a result, benefits stem 

from whether and when baseline monitoring would have identified contamination. Under the 

CCR rule, monitoring will lead to quicker discovery, compared to the baseline, at most CCR 

impoundments as well as to remediation of releases that had remained un-remediated in the 

baseline. As a result, monitoring requirements achieve benefits by eliminating risk and 

preventingreducing costly remediation, but these requirements also lead to increases in costs 

related to additional remediation. This analysis employs modeled probabilities of leaking to 

determine if an impoundment will leak. A leaking impoundment is assumed to result in 

groundwater contamination and require remediation.280

To estimate the timing and cost of groundwater remediation under the baseline and under the 

CCR rule, this RIA first examines the differences across states in groundwater monitoring 

requirements pertaining to CCR impoundments. This RIA focuses on groundwater monitoring 

requirements because adequate monitoring is needed to determine that a release has occurred. 

This RIA assumes that, where contamination is identified, drinking water pathways will be cut 

off at the time of identification of risk, and alternative drinking water will be provided. As a 

result, this RIA assumes that health risks are eliminated at the time the groundwater 

contamination is discovered, and does not separately monetize these risks.

Baseline Assumptions

To establish a baseline for the discovery and remediation of groundwater contamination, this 

RIA identifies three levels of baseline groundwater monitoring for each CCR impoundment, 

based on the state in which the facilityelectric utility plant is located:

 High 

Level:

States have groundwater monitoring requirements for both new and 

existing CCR impoundments.

 Low 

Level:

States have monitoring requirements for newly constructed CCR 

impoundments only.

 None: States do not have any groundwater monitoring requirements.

Under the baseline, this RIA assumes that utility plants in states with the high level of 

monitoring requirements identify groundwater contamination early, in the year of release. In 

contrast, utility plants in states with the low level of monitoring requirements identify 

contamination relatively late, six years after the release. This time between the release and the 

 

280 Because of variability in hydrologic paramters, these assumptions may over- or underestimate groundwater contamination 

damages. For example, an impoundment may leak in an area that derives its water from deep aquifers that may not become 

contaminated or from surface water. In such cases, the damages would be overestimated.
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assumed identification represents the time from release at an unlined impoundment to peak 

groundwater concentration at nearby drinking water wells. Specifically, this time was estimated 

as the first percentile time from release to peak groundwater concentrations.

281 Utility plants in 

states with no monitoring requirements do not discover the contamination, and no remediation 

occurs. For these utility plants, contamination may result in longer-term exposures and higher 

risk of health impacts. 

Assumptions under the CCR final rule

This RIA assumes that groundwater monitoring requirements will be upgraded to be nationally 

consistent under CCR rule, according to the requirements described in Chapter 4. Because the 

CCR rule requires groundwater monitoring within one year of its implementation, this RIA 

assumes that groundwater contamination from CCR impoundments will always be detected 

early. Furthermore, this RIA assumes that closure and capping of an impoundment prevents any 

residual risk from liners. Thus, when impoundments close, risk of contamination goes to zero. 

Under the CCR rule, closures would occur as a result of location standards and state regulatory 

costs.

In addition to closures, this RIA also considers the effect of liner retrofits and the addition of 

liners to new CCR units. Under the rule, when leakage to groundwater is detected, CCR units

may be retrofit with composite liners. In the event that a new CCR unit is constructed following 

the promulgation of the CCR final rule, the unit must be outfitted with a composite liner.

Below are the assumptions applied in this RIA to create a scenario of the future count and type of 

CCR-contaminated groundwater remediation events which may occur under the CCR final rule:

 This RIA assumes that no releases at any CCR units, either impoundments or 

landfills, will be detected, through 2017, the year in which groundwater 

monitoring is required under the CCR final rule. From 2018 onward, all 

remaining units will detect contamination early.

 For CCR management units, the RIA multiplies the probability that an

impoundment or landfill is operating by the risk of leakage to estimate the 

combined probability that a unit is both operating and leaks. Landfills are 

assumed to remain operating or be replaced with a new landfill for the duration of 

the period of analysis.

 The risk of groundwater contamination for CCR impoundments is the probabilityweighted liner status multiplied by the annual leak probability associated with 

each liner type.

 

281 Time to peak groundwater concentrations is provided in the 2009 EPA risk assessment. This value was selected as a proxy for 

groundwater monitoring behavior. Because information on monitoring behavior and time between release and detection is not 

available, this RIA assumes that late remediation does not begin until the arrival of the first percentile peak groundwater 

concentration. Although time to peak groundwater concentrations is not a perfect proxy for detection, this assumption will 

generally result in the intuitive consequence of large contamination plumes forming in locations without stringent monitoring 

standards. 
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 For CCR landfills, a decision year is generated by the cost model in which the 

liner type is changed, either due to liner retrofitting or due to new construction. At 

the decision year, the residual risk is changed to match the new composite liner 

type for these units.

Risk of CCR Contaminant Release into Soil and Groundwater

This RIA categorizes the universe of landfills and impoundments by state, type of liner, and 

monitoring requirements. These state-by-state monitoring requirements are listed in Appendix 

G. This RIA assigns a risk of contamination to each CCR impoundment in each future year 

based on the lifetime risk estimates of liner and unit types displayed below in Exhibit 5-I. This 

RIA assumes that the lifetime of a unit is equal to 70 years (i.e., 40-year operating life and 30-

year post-closure monitoring) and adjusts accordingly for the 100-year analysis period.282 In the 

absence of a more detailed risk assessment, this RIA assumes that risk is evenly distributed 

across the 100-year analysis period.

Exhibit 5-I

283

Groundwater Contamination Risk Estimates

by Type of CCR Management Unit

(within 1-mile drinking water well radius from impoundments)*)*

CCR Management Unit Type

Lifetime Risk of Groundwater 

Contamination

1. Unlined Landfill 12.2%

2. Clay Lined Landfill 12.0%

3. Composite Lined Landfill 0.1%

4. Unlined Surface Impoundment 36.2%

5. Clay Lined Surface Impoundment 9.1%

6. Composite Lined Surface Impoundment 0.1%

*Risk estimates provided by RTI International, 2012; see EPA’s Risk Assessment in the 

docket for the CCR final rule (docket nr. EPA-HQ-RCRA-2009-0640 at 

http://www.regulations.gov).

Groundwater Remediation Costs

Although groundwater remediation can be accomplished using either pump-and-treat (P&T) 

systems or permeable reactive barriers (PRB), this RIA uses cost data for P&T systems only due 

to the detailed nature of available data for these systems and their widespread use. Because PRB 

costs are generally lower than those for P&T systems, this analysis may overestimate 

remediation costs to the extent that utility plants are able to choose less costly remediation 

methods. Conversely, if contamination is extensive or if geology is porous, then these estimates 

 

282 RTI International identifies the lifetime of an average unit as 70 years and provided lifetime risk estimates based on 2010 data.

283 The percentages displayed in Exhibit 5-J represent groundwater contamination risks as measured at drinking water wells 

within a one-mile radius of CCR landfills and impoundments with a given liner type. Meanwhile, the groundwater contamination 

event occurrence probabilities used in the cost estimation modeling and discussed in Chapters 3 and 4 represent the likelihood of 

an MCL exceedance for arsenic for unlined impoundments for a one-meter distance from the perimeter of the impoundment only. 

Due to the mechanics of pollutant migration, it is expected that higher contamination probabilities occur at lower distances (i.e., 

one meter) relative to greater distances (i.e., one-mile radii).
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may understate costs.

 Early Groundwater Remediation: To estimate the cost of groundwater remediation, 

this RIA assumes that contamination detected early requires less remediation. Thus, 

releases occurring in states with early detection are assigned the 25th percentile 

remediation costs displayed in Exhibit 5-J below, representing the midpoint of the lower 

end of the cost range. This RIA further assumes that corrective action at early sites will 

occur in the same year as the release, after allowing for an initial compliance period of 

three years (including two years for state adoption and one for implementation of 

groundwater monitoring), as allowed by the CCR rule [see Chapter 3]). 

 Late Groundwater Remediation: For events in states where detection is expected to 

occur late, this RIA assumes that the later discovery allows CCR contamination to 

migrate farther, resulting in more extensive remediation. This RIA assigns these events 

the 75th percentile remediation costs in Exhibit 5-J, representing the midpoint of the 

upper half of the cost range. Additionally, late remediation is assumed to occur six years 

after the release. This RIA adopts this six-year period as the first percentile number of 

years to peak groundwater concentrations at unlined surface impoundments.284

Exhibit 5-J

Per-Site Groundwater Remediation Pump and Treat Costs (2013$)*

Cost category 25th percentile Median 75th percentile Average

Total capital cost $2,380,000 $2,808,000 $8,260,000 $6,970,000

Average operating cost per year $252,000 $368,000 $1,022,000 $1,040,000

*Values based on 32 case study sites.

This RIA identifies those units that add liners in each year, and reduces risk at those facilities to 

the residual risk associated with composite liners. Then, this RIA multiplies the sum of the risk 

of release at active impoundments and landfills by the associated total capital and annual 

operating costs. Capital costs are assumed to occur in the first year of corrective action, while 

operating costs continue for six years.285 Because groundwater monitoring requirements result in 

two opposite effects – the cost savings of shifting units from late detection to early detection, and 

the additional cost of requiring remediation at units that were not monitored in the baseline – this 

RIA further breaks down groundwater monitoring benefits into these two categories. 

One key source of uncertainty is the use of state groundwater monitoring requirements as a 

proxy for impoundment management to determine when contamination is detected. State-level 

requirements may not perfectly predict impoundment operations, and as a result, this analysis 

may either overestimate or underestimate benefits associated with avoided groundwater 

contamination.

5.2.2 Avoided Natural Resource Damages from Groundwater Contamination

 

284 See 2009 EPA risk assessment.

285 This RIA uses data on “Total capital cost ($)” and “Average operating cost per year ($ per year)” from the 2001 EPA report, 

Cost Analyses for Selected Groundwater Cleanup Projects: Pump and Treat Systems and Permeable Reactive Barriers. This 

report indicates an average of six years of system operation for the 32 P&T sites analyzed.
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Groundwater contamination also results in damages to natural resources, which may be large 

relative to remediation costs. Groundwater NRD is typically calculated as the cost of setting 

aside land to protect groundwater recharge equal to the amount of land currently unavailable as a 

result of contamination. However, this approach is necessarily site-specific. Detailed information 

on the local groundwater recharge rate is necessary to estimate the amount of land to set aside, 

and local land values are necessary to calculate costs. Land values in particular have been shown 

to vary widely across geographic areas. Because this RIA was unable to obtain unit-specific 

information on the quantity of groundwater and land likely to be affected, such an approach 

could not be applied. 

This RIA also reviewed six historical groundwater NRD settlements involving a number of 

contaminants to attempt to generate an average value estimate. These settlements were selected 

from a state-by-state summary of over 100 NRD settlements as cases that valued groundwater 

separately from other damages, because information on groundwater NRD from CCR-specific 

events was not available.286 The value of these settlements varied widely, from $20,000 to over 

$40 million, with an average of approximately $7 million per site. However, these cases did not 

include complete information on the quantity of groundwater contaminated or the source of 

contamination. As a result, this RIA could not generate a reliable estimate of groundwater NRD 

to apply to CCR impoundment releases.

This RIA therefore selects four of these historical groundwater NRD settlements in which the 

remediation cost is also known, and calculates the average ratio of total costs (groundwater NRD 

plus remediation costs) to remediation costs.287 These cases were chosen because of both data 

availability as well as relevancy to CCR groundwater contamination. Although the events differ 

in contaminants, they have a common injured resource (groundwater) and affect areas consistent 

with those that might be expected to be impacted from CCR groundwater contamination cases. 

The ratios of total costs to remediation costs for these four instances ranged from 1.2 to 1.6, with 

an average of 1.34. This RIA applies the 1.34 multiplier to estimated remediation costs to 

calculate the benefit of avoided groundwater NRD and remediation.

5.2.3 Avoided Transaction Costs from Groundwater Contamination

As with impoundment releases, transaction costs as a result of groundwater contamination 

present real economic impacts. This RIA estimates transaction costs associated with groundwater 

contamination using the same methodology described in Section 5.1.4; that is, transaction costs 

equal 37% of total remediation costs. The literature used to develop this ratio considers costs 

incurred at Superfund sites, which may involve groundwater.

 

286 Israel, Brian D. State-by-State Guide to NRD Programs in All 50 States. Arnold and Porter LLP. November 12, 2009.

287 These four cases include contamination events at:

 The Verona Well Field site contamination included volatiles organic compounds and impacted three aquifers over an area of 

approximately 160 acres.

 The South Valley Superfund Site involves groundwater contamination resulting from various manufacturing and industrial 

processes occurring at the Albuquerque site.

 The Ensign-Bickford Trojan Facility incident involved discharges from an explosives manufacturing facility that created a 

groundwater plume extending approximately three miles from the plant.

 The Southwest Jordan Valley incident involved groundwater and surface water injuries occurring as a result of historical 

mining activities in the Salt Lake Valley in Utah.
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5.3 Induced Increased in Future Annual CCR Beneficial Use

Note: EPA has updated this section of the RIA to reflect revisions to valuation of avoided 

emissions and to reflect changes in the electric utility power plant universe; see Sections

9.2.4, 9.2.7, and 9.4 in Chapter 9 of this RIA for a description of the relevant modifications 

and updates to this section and updated benefit estimates, respectively.

This section summarizes the potential impacts of the CCR final rule on the future beneficial use 

of CCR. Of the 120.4 million short tons of CCR generated by coal-fired electric power plants in 

2012 (from Chapter 2 of this RIA), approximately 52 million tons (43%) were beneficially used 

in place of virgin materials in 2012 in 15 different industrial applications.

288 Major CCR 

beneficial use applications include using fly ash as a substitute for portland cement in concrete 

production, as a substitute for virgin sand and gravel in structural fill applications, and using

FGD gypsum as a substitute for raw gypsum in wallboard production. Focusing on only these 

three industrial market applications, this RIA conducted a detailedan assessment of the beneficial 

usepotential future impacts of the CCR rule, on these beneficial uses (i.e., induced future 

increase), as documented in Appendix S. This section summarizes the results of that analysis, 

and also estimates the “avoided disposal costsassociated future potential “cost offset” associated 

with changesthe potential induced increase in beneficial use under the CCR final rule.

5.3.1 Background and Methods

This section summarizes a linear programming (LP) modeling effort to assess the beneficial use 

impacts of the CCR final rule. The analysis is described in detail in Appendix S. The beneficial 

use impacts of the CCR final rule itself were not modeled separately in this chapter, as EPA’s 

beneficial use modeling was completed prior to EPA’s selection and specification of the CCR 

final rule. Instead, this chapter presents the beneficial use impacts of a regulatory option 

considered by EPA that shares many similarities with the CCR final rule.

This RIA assumes that the estimated beneficial use impacts for this option (the “analyzed 

option”) are a reasonable approximation of the beneficial use impacts associated with the CCR 

final rule.289 The main difference between the CCR final rule and the analyzed option relates to 

their requirements for liners. More specifically, the analyzed option would require that only new

CCR impoundments install composite liners that meet the rule specifications; existing CCR 

impoundments would be allowed to continue operating until they reached terminal age under the 

analyzed option. In contrast, the final rule would require any unlined CCR impoundment either 

to retrofit or close if it leaks. Similar to the analyzed option, the final rule would also require 

composite liners for new CCR impoundments. 

Any bias associated with these regulatory specifications in terms of their effect on the final rule’s 

CCR beneficial use impact is unclear. The increased stringency of the CCR final rule with 

respect to liners would, all else equal, lead to increased compliance costs, encouraging more 

 

288 Source: American Coal Ash Association (ACAA) “2012 Coal Combustion Product (CCP) Production & Use Survey Report” 

at http://www.acaa-usa.org/Portals/9/Files/PDFs/revisedFINAL2012CCPSurveyReport.pdf.

289 By “analyzed option”, this RIA refers to the option presented in this chapter, as opposed to the set of regulatory requirements 

that make up the CCR final rule. As described in this paragraph, this analyzed option differs from both the CCR final rule and 

the regulatory scenarios examined in Appendix S.
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beneficial use. However, there have been other modifications to the cost estimation 

methodology of this RIA since specification of the analyzed option that offset this effect. In 

addition, the lifting of restrictions on large-scale CCR fill may create greater opportunities for 

beneficial use in fill applications, which could divert CCR from disposal (increasing the 

estimated benefits of the final rule) and from other beneficial use applications that yield a greater 

benefit to society (reducing the estimated benefits of the rule).

As noted above, Appendix S includes additional details on the beneficial use analysis presented 

in this section. Of the options presented in Appendix S, the option analyzed in this chapter most 

closely resembles the option called Subtitle D prime in Appendix S. The only difference 

between the two is that the option analyzed in this chapter reflects no restrictions on large-scale 

fill applications of CCR, whereas option Subtitle D prime in Appendix S includes these 

restrictions. Both the analyzed option and Subtitle D prime were analyzed independently using 

the LP approach briefly described in this chapter and explained in greater detail in Appendix S. 

The LP approach of this RIA estimates the extent to which the increase in CCR disposal costs 

associated with the CCR final rule (as estimated in Chapter 4) may induce coal-fired power 

plants to manage more of their CCR through beneficial use rather than disposal. This is a current 

business incentive identified by the American Coal Ash Association (ACAA).290 For each ton of 

CCR generated by a coal-fired power plant, the LP analysis determines whether beneficial use or 

disposal is the most economical management option, based on both the benefits and costs of 

beneficial use. For CCRs such as fly ash that may be used in multiple beneficial use applications, 

the analysis considers the relative costs and benefits of each beneficial use option and chooses 

the most economical of these options. In doing so, the analysis makes the simplifying assumption 

that avoided virgin material costs represent proxies for the prices that utilities will get for their 

dry CCR when they recycle it.291 The LP methodology also accounts for regional capacity 

constraints for different beneficial use applications. For example, although much of the CCR 

available for beneficial use is generated by coal-fired power plants in the Midwest, concrete 

producers and other potential users of CCR in this region have limited capacity to use CCR, 

relative to the amount of CCR available in this region. Some of this CCR must therefore be 

shipped to other regions if it is to be beneficially used.

 

290 The ACAA defines “avoided disposal cost” as follows:

“What are “avoided disposal costs?”

If a plant markets its CCPs into commercial applications, then disposal of this coal ash is not required. Not only is a 

revenue stream created for the producer but also the need to dispose of the ash is avoided. As discussed above, 

disposal is not just the transportation and placement of ash in a disposal site. The need for future space is a concern. 

If CCPs are marketed, then the need to develop future sites (including land acquisition, permitting, design and 

construction costs) is avoided.

If a utility is unable to market or otherwise sell the CCPs produced at a plant, disposal is normally the final 

destination for the CCPs. The inability to sell fly ash, for example, is determined by physical characteristics (too high 

in carbon or the presence of air emission additives) or competition of other products in the market place. However, the 

ash may still have purpose for lower value uses, such as in structural fills or reclamation activities. It is not uncommon 

for a company to help offset the costs of transportation or placement at construction sites by providing the contractor 

or trucking firm a payment of some sort. For example, if the cost of disposal at a plant is normally four dollars a ton, 

then the company may arrange a payment of four dollars or less to the contractors to cover transportation and 

placement costs. The difference between the amount of this payment and the cost of disposal is also referred to as 

“avoided disposal costs.”” (Source: ACAA’s frequently asked questions (FAQ) webpage at http://www.acaausa.org/About-Coal-Ash/CCP-FAQs#Q14 )

291 The fact that power plants receive revenue for their CCR is based on personal communication with David Goss of the 

American Coal Ash Association (ACAA), June 18, 2008.
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5.3.2 Estimated ChangesFuture Induced Increase in CCR Beneficial Use

Exhibit 5-K shows the estimated percentage change in beneficial use by application and in 

aggregate.292 As indicated in the exhibit, the change in beneficial use associated with the CCR 

rule is projected to vary by beneficial use application. In particular, while beneficial use for fill 

applications is expected to increase significantly, this RIA estimates that beneficial use for 

wallboard will remain relatively flat. This disparity in impacts, in part, reflects differences in the 

magnitude and geographic distribution of CCR demand for these applications. While the 

potential demand for CCR in fill applications is significant and distributed widely across the 

U.S., demand for CCR in wallboard is more limited and constrained to those wallboard plants 

equipped to use FGD gypsum rather than raw gypsum. 

Exhibit 5-K also shows that beneficial use is projected to increase in 2020 relative to prior years. 

This is due to the increase in CCR available for beneficial use at this time under the analyzed 

option. A significant portion of CCR is wet-handled in the baseline and is therefore not available 

for beneficial use, as CCR must be dry-handled to be beneficially used. Under the analyzed 

option, this RIA expects that more than 33% of plants that wet handle their CCR in the baseline 

will convert to dry handling in or around 2020. This will lead to an increase in the tonnage of 

CCR available for beneficial use in 2020 and, by extension, result in an increase in beneficial use 

in 2020 relative to prior years. This RIA expects a similar pattern under the final rule, as the 

requirement that impoundments with leaks close (by 2019) is expected to lead to widespread 

impoundment closures, necessitating conversion from wet handling to dry handling.

Exhibit 5-K

Percentage ChangeIncrease In Future CCR Beneficial Use By Application

 

292 The exhibits presented in this section show constant beneficial use impacts from 2035 through 2112 because of this RIA’s 

assumption that post-2035 beneficial use under the baseline and the regulatory scenarios remains constant at 2035 levels. The 

year 2035 corresponds to the end of the forecast horizon in the Energy Information Administration’s Annual Energy Outlook, 

which is the basis for this RIA’s projections of CCR demand and supply. Because of the significant uncertainty associated with 

projecting beyond 2035, this RIA assumes that post-2035 beneficial use impacts remain constant at levels projected for 2035.

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

2013 2018 2023 2028 2033 2100

Concrete Wallboard Fill Applications Total Beneficial Use

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

2013 2018 2023 2028 2033 2100

Concrete Wallboard Fill Applications Total Beneficial Use
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Complementing the percentage changes in beneficial use shown in Exhibit 5-K, Exhibit 5-L

presents the absolute changeincrease in beneficial use expected under the CCR final rule. As 

indicated in the exhibit, structural fill applications account for the vast majority of the changes in 

beneficial use under the final rule, due largely to the high capacity for fill-related uses relative to 

other applications (see the discussion on maximum CCR demand in Appendix S).

Exhibit 5-L

Three-Year Rolling Average of the Future Annual Change inIncrease in CCR Beneficial Use by Option 

and Application 

(millions of tons)

Year Fly Ash in Concrete FGD Gypsum in Wallboard

CCR 

inStructural Fill Total

2015 0.06 0.08 0.43 0.57

2020 0.17 0.00 2.00 2.18

2025 0.26 0.00 5.65 5.91

2030 0.21 0.07 6.93 7.20

2035-2112* 0.03 0.36 8.39 8.77

Note: *Annual beneficial use impacts from 2036 through 2112 are assumed to be constant at 2035 levels. 

5.3.3 Valuation of Changes inFuture Induced Increase in CCR Beneficial Use

Note: EPA has updated this section of the RIA to reflect revisions to valuation of avoided 

emissions and to reflect changes in the universe; see Sections 9.2.4, 9.2.7, and 9.4 in Chapter 

9 of this RIA for a description of the relevant modifications and updates to this section and 

updated benefit estimates, respectively.

The changes in beneficial use summarized in Exhibit 5-K and Exhibit 5-L will lead to changes 

in the demand for cement, sand and gravel, and raw gypsum (i.e., the materials displaced by 

CCRs). Using the life cycle approach outlined in Appendix S, this RIA estimates the 

environmental impacts associated with these changes in demand. These impacts include changes 

in energy consumption, water consumption, and air pollutant emissions. To estimate the 

monetary value of these impacts, this RIA uses values obtained from the empirical literature. 

Exhibit 5-M below presents the estimated resource and environmental impacts associated with 

the changesincrease in beneficial use under the analyzed option. The positive values in the 

exhibit represent the avoidance of impacts relative to the baseline. As indicated in the exhibit, 

such reductions in impacts are expected across all impact categories and peak in 2025. This 

timing is consistent with the increase in CCR beneficial use summarized in Exhibits 5-K and

Exhibit 5-L. An important assumption implicit in Exhibit 5-M is that using CCR in place of 

virgin materials saves 100% of the resource use from the virgin materials displaced. In addition, 

the results in Exhibit 5-M reflect only the resource and environmental impacts associated with 

the virgin materials displaced by CCR. They do not reflect the avoided emissions associated 

with CCR management in the baseline or any environmental impacts associated with 

beneficiation.
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Exhibit 5-N shows the monetized benefits, in both present value and annualized terms, of the 

resource and environmental impacts shown in Exhibits 5-M for each of the three beneficial use 

applications specified above. As indicated in the exhibit, benefits associated with the beneficial 

use of CCR in wallboard and concrete applications are similar in magnitude to the monetized 

benefits associated with the increased use of CCR in fill applications, despite the fact that 

wallboard and concrete applications account for a small fraction of the projected increase in 

beneficial use. This reflects the high environmental impacts per ton of raw gypsum and cement 

production relative to the impacts associated with producing one ton of fill.

It is important to note that for SOx, where there exists a cap and trade permit program, firms must 

pay to emit SOx. A portion of the SOx emissions avoided from beneficially using CCR is from 

the energy sector. Under the presumption that the marginal costs of abatement equal the value of 

marginal damages, the value of the portion of SOx emissions from the energy sector could be 

reflected in the energy cost savings. In other words, under the SOx cap and trade system, a 

reduction in SOx from one source could lead to increased emissions from other sources so long 

as the national cap is not exceeded. Whether such an outcome would occur would depend on a 

number of factors, including the banking of allowances, state regulations that require lower 

emissions than Federal regulations, and whether power plants located in non-attainment areas 

would be constrained from increasing their emissions.

Note: EPA has updated this section of the RIA to reflect revisions to valuation of avoided 

emissions and to reflect changes in the universe; see Sections 9.2.4, 9.2.7, and 9.4 in Chapter 

9 of this RIA for a description of the relevant modifications and updates to this section and 

updated benefit estimates, respectively. The tables on this page do not reflect the updates.

Exhibit 5-M

Three-Year Rolling Average of Avoided Resource and Environmental Impacts 

Associated with Future ChangesInduced Incraseease in CCR Beneficial Use

Year

Energy 

(MMBtu)

Water 

(Million 

Gal)

Greenhouse 

Gases 

(Tons)

NOx

(Tons)

PM2.5

(Tons)

PM10

(Tons)

SOx

(Tons)

Hg 

(Pounds)

Pb 

(Pounds)

CO 

(Tons)

2015 340,000 9,800 64,000 140 10 47 35 3 17 54

2020 700,000 23,000 160,000 380 7 33 59 7 34 150

2025 1,200,000 38,000 250,000 640 17 47 110 11 52 250

2030 1,100,000 36,000 220,000 600 26 71 120 9 48 220

2035-

2112 910,000 21,000 75,000 310 59 190 160 2 30 83

Exhibit 5-N

Monetized Value of Beneficial Use byEnvironmental Benefits from Induced Increase in CCR 

Beneficial Use Application

(7% and 3% discount rates in millions, 2013$)

CCR Beneficial Use Application

Baseline

Impacts Relative to the 

Baseline

7% discount 

rate

3% discount 

rate

7% discount 

rate

3% discount 

rate

A. Annualized:

1. FGD Gypsum in Wallboard $860 $910 $9.8 $17.0
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2. Fly Ash as a Cement Substitute in Concrete $1,300 $1,300 $8.7 $6.1

3. Structural Fill (construction) $130 $140 $12.0 $15.0

Column totals = $2,300 $2,400 $30.0 $38.0

B. Present Value:

1. FGD Gypsum in Wallboard $12,000 $29,000 $140 $520

2. Fly Ash as a Cement Substitute in Concrete $18,000 $43,000 $120 $190

3. Structural Fill (construction) $1,800 $4,400 $170 $490

Column totals = $33,000 $76,000 $430 $1,200

5.3.4 Avoided Disposal CostsCCR Rule “Cost Offset” Associated with Increased CCR 

Beneficial Use

Note: EPA has updated this section of the RIA to reflect changes in the universe; see Sections

9.2.4, 9.2.7, and 9.4 in Chapter 9 of this RIA for a description of the relevant modifications 

and updates to this section and updated benefit estimates, respectively.

The projected increase in CCR beneficial use presented earlier in this chapter represents a 

diversion of CCR away from disposal to management methods that arebeneficial use which is

not directly affectedregulated by the 2015 CCR final rule (e.g., using fly ash as a substitute for 

portland cement in concrete production).. The CCR rule cost resultsestimates presented in 

Chapter 4, however, assume that all CCR currently managed through disposal will continue to 

be disposed of following promulgation of the final rule, thus overestimating the CCR rule’s true 

cost impacts. To account for the expected reduction in future annual CCR disposal resulting 

from the rule, this RIA estimates thean expected future CCR rule compliance costs avoided as a 

result of increased“cost offset” associated with the expected future increase in CCR beneficial 

use. To estimate these avoided compliance coststhis cost offset, this RIA applies the approach 

represented by Equation 1:

(1) A = ∑(Bt × Ct)

100

t=1

Where A = the present value of the disposal costs avoided“cost offset” as a result of the 

induced future increase in CCR beneficial use associated with the CCR final rule;

Bt = the increase in CCR beneficial use in year t (measured in tons); and 

Ct = present value of the CCR rule incremental compliance cost per ton of CCR in year 

t (based on 7% discount rate). In undiscounted terms, the annual average value across 

all coal-fired power plants ranges from $2.13 per ton in the early years of the rule’s 

implementation to $31 per ton.

Applying this approach and the per-ton cost values derived from the cost analysis presented in 

Chapter 4, this RIA estimates avoided disposal costs of approximately $1.3 billion in present 
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value terms, based on a 7% discount rate. On an annualized basis, this represents a potential 

future annual “cost savingsoffset” of approximately $92 million per year (based on a 77% 

discount rate) and $125 million per year (3% discount rate) over this RIA’s 100-year analytic 

time horizon.as displayed in row A2 of Exhibit 5-O below. It is important to note that these 

avoided costs represent this cost offset represents only the avoided incremental compliance costs 

of the CCR rule that were assigned to the relevant tonnage in the cost analysis in Chapter 4. 

They do not reflect the total avoided cost of managing this waste in the baseline. Becase these 

incremental compliancethis cost savings areoffset is not reflected in any of the other benefits 

categories presented in this RIA and are not netted out of the compliance costs presented in 

Chapter 4, they are identified here.

5.3.5 Aggregate Environmental Benefits Related to Increased CCR Beneficial Use 

Note: EPA has updated this section of the RIA to reflect revisions to valuation of avoided 

emissions and to reflect changes in the universe; see Sections 9.2.4, 9.2.7, and 9.4 in Chapter 

9 of this RIA for a description of the relevant modifications and updates to this section and 

updated benefit estimates, respectively. This section does not reflect those updates.

Aggregating the results presented in the previous two sub-sections, Exhibit 5-O presents the 

estimated monetized value of the beneficial use benefits associated with the final rule. In 

aggregate, these benefits are more than $1.7 billion in present value terms and $122 million on 

an annualized basis (both values based on a 7% discount rate). In addition, as indicated in the 

exhibit, the avoided compliance cost benefit described above represents approximately threefourths of the estimated benefits associated with beneficial use.environmental benefits of the 

expected future induced increase in CCR beneficial use, plus the associated CCR rule “cost 

offset.”

Exhibit 5-O

Summary of CCR Beneficial Use Environmental Benefits & Associated CCR Rule “Cost Offset”

(7% and 3% discount rates in millions, 2013$)

CCR Beneficial Use Application 7% discount rate 3% discount rate

A. Annualized:

1A1. Environmental Benefits of Increased CCR Beneficial Use $30.0 $38.0

2. Avoided Compliance CostsA2. CCR Rule “Cost Offset”

Associated with Increased CCR Beneficial Use $92.0 $125

Column totals = $122.0 $163

B. Present Value:

1B1. Environmental Benefits of Increased CCR Beneficial Use $430 $1,200

2. Avoided Compliance CostsB2. CCR Rule “Cost Offset”

Associated with Increased CCR Beneficial Use $1,300 $3,900

Column totals = $1,730 $5,100

As noted in Section 4.3 of Chapter 4, the total rule cost estimate displayed in Exhibit 4-E has 

not been adjusted (i.e., reduced) for the potential future “cost offset” which is calculated above. 

Consequently, the total rule cost estimate displayed in Exhibit 4-E represents an upper-bound 

central estimate in this RIA with respect to this cost offset factor.
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5.4 Reduced Incidence of Cancer

Note: EPA has updated this section of the RIA; see Section 9.2.5 in Chapter 9 of this RIA for a 

description of the relevant modifications and updates to this section. This section does not 

reflect those updates.

The human health benefit of reduced incidence of cancer is the monetary value that society is 

willing to pay to reduce the number of cancer cases from the baseline scenario to the postcompliance scenario. This benefit category is associated with reduced effluent discharges to 

surface waters and as a result, ambient pollutant concentrations in receiving reaches. 

Specifically, reduced pollutant exposure from consumption of recreationally caught fish 

contaminated by CCR within the affected waterways is expected to drive the cancer reduction 

benefits. To monetize this benefit category, EPA relied on the scaling approach described above 

to apply benefits from EPA-OW’s analysis of the SPGELG regulation.293 The remainder of this 

section describes EPA-OW’s methodology.294

To calculate this benefit, EPA-OW first identified the affected population of recreational anglers 

and subsistence fishers who fish reaches receiving pollutant discharges and their household 

members, and therefore may be exposed to pollutants through consumption of contaminated fish 

tissue. In order to identify the potentially affected population, EPA-OW considered four factors: 

(1) typical travel distances to a fishing site, (2) presence of substitute fishing locations, (3) data 

on the locations and status of fish consumption advisories (FCAs) for receiving reaches, and (4) 

information on angler’s awareness and adherence to FCAs. Based on these factors, EPA-OW

developed an equation to calculate the affected population for each potentially affected water 

body, resulting in a total affected population of 137,476.

For the baseline and each regulatory option of the SPGELG proposed rule, EPA-OW then 

developed lifetime average daily dose (LADD) estimates of arsenic for seven age cohorts each 

for recreational anglers and subsistence fishers. Based on these data, EPA-OW then calculated 

the total number for cancer cases for each cohort, for each receiving reach under the baseline and 

for each regulatory option. The number of avoided cancer cases under each SPGELG regulatory 

option is equal to the difference between the estimated number of cancer cases under each 

regulatory option as compared to the baseline. EPA-OW translated the reduced incidence of 

cancer into an expected number of avoided mortality events, and then monetized the benefits 

associated with avoided cancer cases using the value of a statistical life (VSL) approach. The 

VSL is based on estimates of society’s willingness-to-pay to avoid the risk of premature 

 

293 This RIA scales this benefit category from the estimates in the SPGELG proposed rule. This method assumes a linear 

relationship between pollution inputs and benefits, and is not able to take into account that human health benefits may be site 

specific due to characteristics of the affected waterbody, presence of substitute sites, and population of fishers.

294 For a full methodology description, see “Benefit and Cost Analysis for the Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category,” EPA Office of Water, EPA report nr. EPA 821-R13-004, April 2013, available from the Federal regulatory docket as document ID nr. EPA-HQ-OW-2009-0819-2238.
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mortality.295 EPA-OW calculated this annualized benefit to range from $0 to $0.1 million (7% 

discount rate) across the different regulatory options. For the ELG4 option, the annualized 

benefit was found to be $0.1 million at a 7% discount rate ($0.2 at a 3% discount rate).

 

295 As an alternative approach, this RIA uses the results of a screening level risk assessment conducted by RTI International for

the CCR rule to estimate cancer benefits. The risk assessment focuses on skin cancer risks associated with arsenic(III) 

concentrations in groundwater. Not included in this estimate are risks of bladder, lung, or other cancers, or non-cancer risks. 

Benefits associated with human cancer risks avoided reflect individual and population-level excess lifetime cancer probabilities 

for each CCR landfill and CCR surface impoundment, provided for adult and child receptors for every year through 2112. 

This RIA adjusts these values for the average latency period of skin cancer from ingested arsenic (21 years), as 

determined by a review of five publications. These five studies include: (1) Levine, Tina, et al. "Special report on ingested 

inorganic arsenic." Risk Assessment Forum. U.S. Environmental Protection Agency. 1988; (2) National Research Council 

Subcommittee on Arsenic in Drinking Water. "Arsenic in drinking water: 2001 update." (2001). 61-65; (3) O'Connor, John T. 

and Thomas L. O'Connor. "Arsenic in Drinking Water." H2O'C Engineering, LLC (2001); (4) Yu, Winston H., Charles M. 

Harvey, and Charles F. Harvey. "Arsenic in groundwater in Bangladesh: A geostatistical and epidemiological framework for 

evaluating health effects and potential remedies." Water Resources Research 39, No. 6 (2003); and (5) Zaldivar, Robert, Luis 

Prunes, and Gauri L. Ghai. "Arsenic dose in patients with cutaneous carcinomata and hepatic haemangio-endothelioma after 

environmental and occupational exposure." Arch Toxicol (1981) 47: 145-154.

The RIA then values avoided cancer risk using the VSL. Because this RIA estimates less than 100% reduction in 

groundwater contamination, this RIA applies these same percentage reductions to baseline cancer risks. The RIA then scales the 

results from the earlier universe of facilities to match the current universe of 315 active landfills and 873 active surface 

impoundments. In addition, to estimate the magnitude of non-cancer risks avoided, this RIA calculates a ratio of non-cancer-tocancer impacts from four previous EPA studies of 6.3%, and applies this ratio to the benefits estimate. [The four rules include: 

“Regulatory Impact Analysis for the Final Clean Air Visibility Rule or the Guidelines for Best Available Retrofit Technology 

(BART) Determinations under Regional Haze Regulations,” EPA Office of Air, June 2005; “Human Health Benefits from 

Sulfate Reductions under Title IV of the 1990 Clean Air Act Amendments,” EPA Office of Air, November 10, 1995; “Final 

Heavy Duty Engine/Diesel Fuel Rule: Air Quality Estimation, Selected Health and Welfare Benefits Methods, and Benefit 

Analysis Results,” EPA Office of Air, December 2000; and Final Tier 2 Rule: Air Quality, Estimation, Selected Health and 

Welfare Benefits Methods and Benefit Analysis Results,” EPA Office of Air, December 1999.] The results of this analysis 

suggest that benefits for the CCR rule are approximately $0.7 million, annualized at a 7% discount rate.
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5.5 Mitigated IQ Losses from Mercury

Note: EPA has updated this section of the RIA; see Section 9.2.5 in Chapter 9 of this RIA for a 

description of the relevant modifications and updates to this section. This section does not 

reflect those updates.

Similar to lead, mercury can have a variety of adverse health effects on adults and children 

through consumption of fish contaminated by CCR. One benefit of reducing exposure to mercury 

is the mitigation of IQ losses. To monetize this benefit category, EPA relied on the scaling 

approach described above to apply benefits from EPA-OW’s analysis of the June 2013 proposed 

SPGELG rule. The remainder of this section describes EPA-OW’s methodology.296 Due to data 

limitations, EPA-OW estimated only the benefits from reduced IQ losses among children 

exposed to mercury in-utero as a result of maternal consumption of contaminated fish. In order 

to obtain the population of children affected, EPA-OW started with the reach-specific affected 

population as described in Section 5.5. Using these data, EPA-OW then further limited the 

population by estimating the number of women between the ages of 15 and 50 – considered to be 

of child-bearing age - that are potentially exposed to contaminated fish caught from affected 

water bodies. EPA-OW then multiplied this population number by the state-specific average 

fertility rate (ranging from 10.7 to 20.6 babies per year, per 1,000 people), arriving at an estimate 

of 1,932 births in the affected population. 

EPA-OW used a linear dose-response relationship between maternal mercury hair content and 

subsequent childhood IQ loss from Axelrad et al. (2007). Available economic literature provides 

little empirical data on society‘s overall willingness-to-pay to avoid a reduction in an infant’s IQ; 

therefore, to determine the value of avoided IQ losses, EPA-OW used an estimate of the 

reduction in the present value of the infant’s future expected lifetime earnings per one IQ point 

reduction minus the cost of avoided education. Avoided education is subtracted out because 

decreased IQ results in less education and therefore reduced education costs.

At a 3% discount rate, the estimated annual benefits of avoided IQ losses from reduced maternal 

exposure to mercury for the ELG3 option range between $4.1 million and $5.8 million and range 

from between $8.4 million and $12.1 million for the ELG4 option of the proposed SPGELG rule. 

This benefit monetization method represents only one component of society’s willingness-to-pay 

to avoid IQ decreases, and thus underestimates the total value of benefits to children from 

reduced exposure to mercury.

 

296 For a full methodology description, see “Benefit and Cost Analysis for the Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category,” EPA Office of Water, EPA report nr. EPA 821-R13-004, April 2013, available from the Federal regulatory docket as document ID nr. EPA-HQ-OW-2009-0819-2238 at 

http://www.regulations.gov.
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5.6 Reduced Lead Exposure

Note: EPA has updated this section of the RIA; see Section 9.2.5 in Chapter 9 of this RIA for a 

description of the relevant modifications and updates to this section. This section does not 

reflect those updates.

Exposure to lead (a component of CCR) can cause a variety of adverse health effects in adults 

and children, and one benefit of reducing exposure to lead is the mitigation of IQ losses. To 

monetize this benefit category, EPA relied on the scaling approach described above to apply 

benefits from EPA-OW’s analysis of the June 2013 proposed SPGELG rule. The remainder of 

this section describes EPA-OW’s methodology.297

Because of data limitations, EPA-OW estimates only the benefits to pre-school (ages 0 to 7) 

children from reduced lead exposure via consumption of contaminated fish tissue. The Agency 

identified the affected population of pre-school children as children who live in recreational 

angler and subsistence fisher households and are potentially exposed to lead via consumption of 

contaminated fish tissue, equal to an affected population of approximately 12,478 children 

between the ages of 0 to 7.

Using blood lead concentration as a biomarker of lead exposure, EPA-OW modeled blood lead 

concentration under the baseline and post-compliance scenarios. The Agency then used a dose 

response relationship between blood lead concentration and IQ loss to estimate avoided IQ losses 

in the affected population of children. EPA relied on a study by Lamphear et al. (2005) which 

suggests that, for PbB concentrations below 7.5 μg/dL, a decrease of 2.94 IQ points can be 

expected for every 1 g/dL increase in PbB. EPA-OW also used this dose response relationship 

to estimate reduced incidence of extremely low IQ scores (less than 70) because children with 

IQs less than 70 require compensatory education that is tailored to their specific needs. 

The available economic literature provides little empirical data on society’s overall willingnessto-pay to avoid a decrease in children’s IQ. To determine the value of avoided IQ losses, EPA–

OW used estimates of the changes in a child’s future expected lifetime earnings per one IQ point 

reduction. Salkever (1995) and Schwartz (1994) estimate that a one point IQ reduction reduces 

expected lifetime earnings by between 2.38% or $14,631 and 1.76% or $10,819 , respectively.

For the ELG3 option EPA-OW estimates annual benefits of avoided IQ losses range between 

$2.2 and 3.2 million, assuming a 3% discount rate. The annual benefits of the ELG4 option are 

between $5.6 and $7.9 million, assuming a 3% discount rate. This benefit monetization method 

represents only one component of society’s willingness-to-pay to avoid IQ reductions, and thus 

underestimates the total value of benefits to children from reduced exposure to lead.

 

297 For a full methodology description, see “Benefit and Cost Analysis for the Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category,” EPA Office of Water, EPA report nr. EPA 821-R13-004, April 2013, available from the Federal regulatory docket as document ID nr. EPA-HQ-OW-2009-0819-2238 at 

http://www.regulations.gov.
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5.7 Reduced Need for Specialized Education

Note: EPA has updated this section of the RIA; see Section 9.2.5 in Chapter 9 of this RIA for a 

description of the relevant modifications and updates to this section. This section does not 

reflect those updates.

In addition to the expected reduction in lifetime earnings associated with IQ losses from 

exposure to lead, benefits may also be associated with the avoided cost of compensatory 

education for children with learning disabilities. To monetize this benefit category, EPA-OW

relied on the scaling approach described above to apply benefits from EPA-OW’s analysis of the 

SPGELG regulation. EPA-OW relied on information from the U.S. Department of Education to 

estimate additional expenditures on specialized education that could be avoided as a result of 

reduced lead contamination. Specifically, EPA-OW assumed that 20% of children with PbB 

concentrations above 20 ug/dL would have IQs less than 70 and require compensatory education. 

Using data from the U.S. Department of Commerce, adjusted to 2010 dollars and discounting 

future costs using a 3% discount rate, EPA-OW estimates the total compensatory education cost 

of approximately $157,327 per child with an IQ less than 70. EPA-OW values the annual cost 

savings from reduced compensatory education requirements at $0.02 million and $0.07 million, 

for the ELG3 and ELG4 options, respectively, assuming a 3% discount rate. As noted above, this 

benefit monetization method represents only one component of society’s willingness-to-pay to 

avoid IQ reductions, and thus underestimates the total value of benefits to children from reduced 

exposure to lead.

5.8 Non-Market Benefits from Water Quality Improvements

Note: EPA has updated this section of the RIA; see Section 9.2.5 in Chapter 9 of this RIA for a 

description of the relevant modifications and updates to this section. This section does not 

reflect those updates.

Heavy metals, nutrients, and other pollutants found in CCR can have a wide range of effects on 

water resources. These environmental changes affect environmental goods and services valued 

by humans, including, among others: 

 Improved aquatic and wildlife habitat;

 Enhanced water-based recreation;

 Aesthetic improvements of surface water;

 Increased non-use ecosystem value; and

 Reduced risks to aquatic wildlife. 

Some environmental goods and services, such as commercially-caught fish, are traded in markets 

and thus their value can be directly observed. Other environmental goods and services (e.g., 

recreation and support of aquatic life) are not bought or sold directly and thus do not have 
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observable market values. These types of environmental goods and services are classified as 

“non-market”. The expected changes in non-market values of the water resources affected by the 

CCR rule are additive to the benefits from avoided groundwater contamination estimated earlier 

in this chapter.

To monetize this benefit category, EPA relied on the scaling approach described above to apply 

benefits from EPA-OW’s analysis of the SPGELG regulation.298,299 EPA-OW’s approach to 

estimating the non-market benefits from surface water quality improvements involves 

characterizing baseline and post-compliance water quality using a water quality index (WQI). 

The WQI translates water quality measurements, gathered for multiple parameters indicative of 

various aspects of water quality, into a single numerical indicator. Based on a scale from 0 to 

100, this numerical indicator reflects varying water quality, with 0 for poor quality and 100 for 

excellent. The Agency then monetized changes in the non-market value of affected water 

resources using a meta-analysis of surface water valuation studies that provide data on the 

public’s willingness-to-pay for water quality improvements. In order to estimate total WTP 

(WTP) for water quality improvements in a given state, EPA-OW then multiplied the per 

household WTP values for the estimated water quality improvement by the number of 

households within each state in a given year. At a 3% discount rate, EPA-OW found annualized 

benefits over the five options to range from $8 million to $83 million. Option 4 of the SPGELG 

proposed rule RIA was estimated to result in annualized benefits of $82.8 million per year at a 

3% discount rate ($69.2 million with a 7% discount rate).

5.9 Protection of Threatened and Endangered Species

Note: EPA has updated this section of the RIA; see Section 9.2.5 in Chapter 9 of this RIA for a 

description of the relevant modifications and updates to this section. This section does not 

reflect those updates.

Threatened and endangered species are species vulnerable to future extinction or at risk of 

extinction in the near future, respectively. Certain chemicals, pollutants, and even nutrients found 

in CCR and permitted discharges can pose serious threats to ecological health due to 

bioaccumulation, high concentrations, high loadings, and eutrophication. For species vulnerable 

to future extinction, even minor changes to growth and reproductive rates and small levels of 

mortality may represent a substantial portion of annual population growth.

From an economic perspective, threatened and endangered species may have both use and nonuse values. However, given the protected nature of threatened and endangered species and the 

 

298 This benefit category is scaled from the estimates in the SPGELG proposed rule. As with human health benefits, this method 

assumes a linear relationship between pollution inputs and benefits, and is not able to take into account that water quality 

improvement benefits may be site specific due to characteristics of the affected waterbody, affected population, and presence of 

substitute sites.

299 For a full methodology description, see “Benefit and Cost Analysis for the Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category,” EPA Office of Water, EPA report nr. EPA 821-R13-004, April 2013, available from the Federal regulatory docket as document ID nr. EPA-HQ-OW-2009-0819-2238 at 

http://www.regulations.gov.
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fact that the majority of threatened and endangered species do not have direct uses, the majority 

of the economic value for threatened and endangered species comes from non-use values. 

To monetize this benefit category, EPA relied on the scaling approach described above to apply 

benefits from EPA-OW’s analysis of the SPGELG regulation.300 The remainder of this section 

describes EPA-OW’s methodology.301

Developing species-specific estimates of non-use values for the protection of threatened and 

endangered species can be costly, burdensome, and time-intensive. As a result, EPA-OW 

considered a benefit transfer approach that relies on information from existing studies. The 

Agency first explored the current status of major freshwater taxa by reviewing studies that 

examined the cumulative stressors on freshwater aquatic ecosystems. EPA-OW then identified 

the extent to which the proposed compliance measures can be expected to benefit species 

protected by the Endangered Species Act. This was done by compiling data on locations of steam 

electric plants and receiving waterbodies, examining their respective water qualities and 

comparing these factors to locations of potentially affected habitats. In order to monetize 

potential economic benefits, EPA-OW applied economic valuation methods from the existing 

literature to estimate willingness-to-pay for these non-use benefits of threatened and endangered 

species. Depending on the SPGELG regulatory option and estimated relative population changes, 

EPA-OW estimated annualized benefits across five SPGELG regulatory options between $3.9 

million to $47.3 million, assuming a 3% discount rate ($3.2 million to $39.5 million assuming a 

7% discount rate).

5.10 Improved Air Quality from Reduced Power Plant Air Pollution

Note: EPA has updated this section of the RIA; see Section 9.2.5 in Chapter 9 of this RIA for a 

description of the relevant modifications and updates to this section. This section does not 

reflect those updates.

Reducing air pollutants such as nitrogen oxides (NOx), sulfur oxides (SOx), and carbon dioxide 

(CO2) can provide human health and other benefits. NOx and SOx are known precursors to fine 

particulate matter (PM2.5), a criteria air pollutant that has been associated with a variety of 

adverse health effects, the most notable of which is premature mortality. CO2 is an important 

greenhouse gas that is linked to climate change effects. The expected economic losses from 

climate change include reduced agricultural yields, human health risks, property damages from 

increased flood frequencies, and the loss of ecosystem services, among other sources of 

economic loss. Increased CO2 levels also affect biological systems independent of climate 

change, such as ocean acidification.

 

300 As with other benefits in this RIA scaled from the SPGELG benefits estimates, this scaling method may introduce bias and 

uncertainty. This method assumes a linear relationship between pollution inputs and benefits, and is not able to take into account 

that benefits to threatened and endangered species are driven by the geographic locations affected, which do not overlap perfectly 

between between the CCR and SPGELG rules.

301 For a full methodology description, see “Benefit and Cost Analysis for the Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category,” EPA Office of Water, EPA report nr. EPA 821-R13-004, April 2013, available from the Federal regulatory docket as document ID nr. EPA-HQ-OW-2009-0819-2238 at 

http://www.regulations.gov.
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The CCR rule may have both positive and negative effects on these types of emissions by 

changing ash handling systems, waste trucking, or potentially the profile of electricity 

generation. 

To monetize this benefit category,EPA relied on the scaling approach described above to apply 

benefits from EPA-OW’s analysis of the SPGELG regulation. The remainder of this section 

describes EPA-OW’s methodology.302 Additional values for this benefit category are in 

Appendix X to this RIAwill be forthcoming in an addendum reporting output from IPM.

EPA-OW compared the estimates of NOx, SOx, and CO2 in the baseline scenario to the postcompliance scenarios to find the changes in air emissions. EPA-OW assumes that changes in 

emissions result from changes in electricity generation, and are not directly related to ash 

management. For purposes of applying these benefits to the CCR rule, this RIA assumes that 

similar changes in generation will result from the CCR rule and that market impacts can be 

scaled linearly. For NOx and SOx, EPA-OW then developed estimates of national monetized 

benefits per ton of emissions avoided. Because the benefits per ton of emissions depend on both 

the type of emissions and the geographic distribution of the emitting sources, benefits per ton 

emitted are specific to a combination of emission type and source category. Thus, the Agency 

developed benefits per ton estimates for specific combinations of emission source categories and 

PM2.5 precursors. On the other hand, EPA-OW estimated the benefits per ton of CO2 emitted 

using estimates of the social cost of carbon obtained from the Interagency Working Group on 

Social Cost of Carbon.303 The social cost of carbon is an estimate of the monetized damages 

associated with an incremental increase in carbon emissions in a given year. 

EPA-OW calculated the monetized air-related benefits in any given year by multiplying the tons 

of emissions avoided for a given emissions type/source category combination in that year by the 

benefits per ton for that emissions type/source category combination for that year, and then 

summing the benefits across all emissions type/source category combinations. The annualized 

benefits from reducing emissions of NOx, SOx and CO2 are $127.6 million and $170.5 million, 

for the SPGELG proposed rule ELG3 and ELG4 options respectively, assuming a 3% discount 

rate.

5.11 Reduced Groundwater Withdrawals

Note: EPA has updated this section of the RIA; see Section 9.2.5 in Chapter 9 of this RIA for a 

description of the relevant modifications and updates to this section. This section does not 

reflect those updates.

 

302 For a full methodology description, see “Benefit and Cost Analysis for the Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category,” EPA Office of Water, EPA report nr. EPA 821-R13-004, April 2013, available from the Federal regulatory docket as document ID nr. EPA-HQ-OW-2009-0819-2238 at 

http://www.regulations.gov.

303 The interagency group included EPA, the Department of Transportation, and other executive branch entities. This group 

selected four values of the social cost of carbon for use in regulatory impact analyses. These values are estimated for 5-year 

intervals spanning 2010 through 2050.
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Coal-fired electric utility plants can use large quantities of water for ash transport and for 

operating wet FGD scrubbers. By reducing water intake through the conversion from wet to dry 

ash handling, the CCR rule could result in increased availability of groundwater for local 

municipalities that rely on groundwater aquifers for drinking water supplies. These 

municipalities could then avoid the cost of supplementing drinking water supplies through 

alternative means, such as bulk drinking water purchases. To monetize this benefit category, 

EPA relied on the scaling approach described above to apply benefits from EPA-OW’s analysis 

of the SPGELG regulation.304,305 EPA-OW estimated the benefits of reduced groundwater 

withdrawals based on the avoided cost of purchasing drinking water during periods of shortages 

in groundwater supply. In order to obtain a monetary value for reduced groundwater 

withdrawals, EPA-OW utilized current state-specific water prices ($730.94 per acre/foot for 

Florida and $1,169.53 per acre/foot for Nebraska). Then, for each affected plant and SPGELG 

regulatory option, EPA-OW multiplied the reduction in groundwater withdrawals (expressed in 

gallons per year) by the estimated price of drinking water per gallon. Based on this approach, 

EPA-OW estimated the annual benefits from reduced groundwater withdrawals as $0.03 million 

and $0.13 million for ELG3 and ELG4 options, respectively, assuming a 3% discount rate.

5.12 Conclusion

Note: EPA has updated this section of the RIA; see Sections 9.2, 9.3 and 9.4 in Chapter 9 of 

this RIA for a description of the relevant modifications and the resultant re-estimated 

benefits for the CCR final rule. This section does not reflect those updates.

The analysis of benefits in this RIA reflects several significant data availability limitations. First, 

the impoundment release risk analysis simulated future possible failures based only on 

impoundment age and capacity. A broader data set including information for the entire universe 

on the frequency of structural integrity evaluations and involvement of professional engineers in 

site design and construction could lead to more robust simulations. This RIA also developed 

impoundment release remediation cost and groundwater NRD estimates based on a small number 

of case studies. Additionally, these costs may vary significantly based on site-specific 

characteristics, but the scope of the universe is too broad to allow site-specific analysis. Finally, 

more detailed risk assessment could improve the estimation of benefits associated with 

preventedreduced groundwater contamination and associated health risks, including cumulative 

impacts.

5.12.1 Summary of Regulatory Benefits 

Exhibit 5-O below summarizes the monetized benefits at 7% and 3% discount rates, 

respectively. On an annualized basis, assuming a 7% discount rate, this RIA estimates that $376

million of baseline monetized harm could be avoided as a result of the CCR final rule. Assuming 

 

304 As with other benefits in this RIA scaled from estimates in the SPGELG proposed rule, the scaling method assumes a linear 

relationship between pollutants and benefits and that plant characteristics and behavior are similar in the affected universe of each 

rule. These scaled benefits may not match results derived from impoundment-specific information.

305 For a full methodology description, see “Benefit and Cost Analysis for the Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category,” EPA Office of Water, EPA report nr. EPA 821-R13-004, April 2013, available from the Federal regulatory docket as document ID nr. EPA-HQ-OW-2009-0819-2238 at 

http://www.regulations.gov.
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a 3% discount rate, this RIA estimates that $420 million could be avoided as a result of the CCR 

final rule. In addition, the CCR rule may generate ancillary benefits that could not be fully 

quantified but are discussed in Chapter 6. To calculate the annualized estimates of benefit 

categories estimated using EPA-OW’s rule, this RIA employs the base benefit at either 3% or 

7% and then adjusts the value for inflation as well as for the factors discussed in the first section 

of this chapter.
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Exhibit 5-O

Annualized Environmental & Human Health Benefits for the CCR Final Rule

(millions of 2013$)

Benefit Category

7% discount 

rate

3% discount 

rate

1. Prevention ofReduced CCR impoundment releases $208 $220

2. Prevention ofReduced CCR groundwater contamination $9.8 $13.4

Closures $0.83 $1.45

Liners $5.410 $7.000

Monitoring $3.52 $4.91

3. IncreaseInduced future annual increase in CCR beneficial useuses $122 $163

Reduced air emissions & resource consumption $30 $38

CCR rule “cost offset” (alternatively could be subtracted from Exhibit 4-E total 

cost estimate)

$92 $125

4. Reduced incidence of cancerb $0.021 $0.015

5. Avoided IQ losses from mercuryb $0.187 $0.783

6. Avoided IQ losses from leadb $0.125 $0.522

7. Reduced need for specialized educationb $0.000 $0.008

8. Non-market surface water quality benefitsb, c

Improved aquatic and wildlife habitat

Enhanced water-based recreation

Aesthetic improvements of surface water

Increased non-use ecosystem value

Reduced risks to aquatic wildlife

$14.4 $6.4

9. Protection of threatened and endangered speciesb $5.8 $2.6

10. Improved air qualitybquality of electric utility plantsb, c

Reduced air emissions of NOx, SO2

Reduced air emissions of CO2

$15.5 $13.1

11. Reduced groundwater withdrawalsbwithdrawals (after conversion from wet 

to dry CCR handling)b

$0 $0

TotalColumn Totals = $375 $420

Notes: 

a Benefits are scaled based on EPA-OW's proposed SPGELG rule. Annualized values of benefits assuming a 3% and 7% 

discount rate were obtained from SPGELG RIA documents and adjusted to 2013 dollars before scaling.

b Non-market surface water quality benefits and air quality benefits are estimated in aggregate only.

5.12.2 Regulatory Benefits for Inactive CCR Management Units

As discussed in Chapter 4, this RIA identified a total of 111 inactive CCR surface 

impoundments. Under the CCR final rule, these inactive CCR impoundments are required to 

dewater and install an engineered cap, plus conduct 30 years of post-closure groundwater 

monitoring and groundwater cleanup corrective action as needed. Because these benefits accrue 

separately from the costs and benefits associated with active units, they are not incorporated into 

the total estimate of benefits in Exhibit 5-O.

For the 111 inactive CCR impoundments, this RIA assumes that closure capping and postclosure groundwater monitoring will provide an additional benefit of $1.48 million per year, 

assuming a 7% discount rate, consisting of both cancer preventionreduction and reduction in 

future groundwater contamination costs. This benefit is approximated in absence of data by 

assuming the 111 inactive impoundments are of similar size and regional distribution compared 

to the active on-site landfills, and by simple linear extrapolation of the benefit estimates 

presented in Exhibit 5-O for the universe of 735 active on-site CCR management units, using a 
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multiplier of 0.151 (i.e., 111/735). Using a 3% discount rate, this additional benefit is estimated 

at $2.03 million per year. 
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Chapter 6

Non-Monetized (Qualitative) Benefits

This chapter presents ten additional benefits of the CCR final rule.306 These represent both direct 

and indirect benefits that are presented qualitatively due to data and/or methodology limitations.

 Direct benefits: Involve protecting human health and the environment from CCR 

contamination of groundwater, reducing the inhalation of fugitive CCR dust, and 

preventingreducing CCR impoundment releases.

 Indirect benefits: Associated with otherOther expected physical outcomes of the 

CCR rule.

Because they are not monetized, the benefits in this chapter are not included in the calculation of 

net benefits and benefit-cost ratios for the CCR rule presented in Chapter 9. The qualitative 

benefits described in this chapter are (not necessarily listed in order of potential impact 

magnitude):

1. DustCCR fugitive dust health and nuisance benefits. Reduce community 

nuisance from fugitive CCR dust...

2. Financial investment benefit. Reduce investment risk and information 

asymmetry in financial markets for the electric utility industry. 

3. Dread reduction benefit. Reduce fear, stress, and anxiety (i.e., hazard dread) of 

citizens residing near CCR impoundments. 

4. Cancer and non-cancer human health benefit. from reduced health effects of 

fish consumption. Reduce cancer and non-cancer health effects resulting from 

fish consumption. This is a separate benefit from the avoided cancer risks 

monetized in Chapter 5. 

5. Cancer and non-cancer human health benefit. from reduced health effects 

from recreational water use. Reduce cancer and non-cancer health effects 

resulting from recreational water use. This is a separate benefit from the human 

health benefit from reduction in fish consumption, which is estimated in Chapter 

5.

6. Avoided sediment contamination. Reduce sediment contamination from reduced 

deposition of toxic pollutants.

7. Water quality benefit. Reduce water treatment costs for drinking and irrigation 

water.

8. Commercial fisheries benefit. Improve commercial fishing yields and harvest 

quality due to aquatic habitat improvements.

9. Tourism benefit. Increase participation in water-based recreation due to water 

quality improvements.

 

306 This RIA harmonized the non-monetized benefits presented in this chapter with the EPA Office of Water’s benefits analysis 

for its June 2003 “Steam Electric Power Generator Effluent Guidelines Limitations” proposed rule.
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10. Avoided impingement and entrainment mortality. Reduce fish impingement 

and entrainment mortality from CCR handling surface water intake.

11. Increased property values surrounding electric utility plants. Increase 

property value of neighborhing properties due to an improvement in the aesthetic 

conditions of the local landscape.

Description of these benefits is consistent with the OMB Circular A-4 guidance “to look beyond 

the direct benefits and direct costs of regulations and consider any important ancillary benefits 

and countervailing risks.”307 This chapter uses readily available information to describe these 

expected benefits based on limited details, data, and methods. The analysis is also consistent 

with OMB’s guidance recommending that RIAs use both quantitative and qualitative estimates 

when evaluating benefits.308

6.1 Reduce Community Nuisance and Human Health Impacts from 

Fugitive CCR Dust 

The CCR rule may reduce CCR dust inhalation by humans, as well as reduce the adverse 

aesthetic and nuisance effects of CCR dust. In addition to written comments about the nuisance 

effects of CCR dust submitted to the docket for the June 2010 proposed CCR rule, a number of 

citizens testifying at the eight EPA public hearings also complained about the nuisance aspects of 

CCR fugitive dust. Citizens reported CCR dust on windows and outdoor equipment, as well as 

damage to chrome plating on vehicles and bicycles, damage to the exteriors of buildings and 

homes, and harmful effects on landscape vegetation and ecological assets, such as beehives. 

The final CCR rule includes provisions to limit airborne dust from CCR landfills and vehicles 

transporting CCR. The specific dust control requirements set forth include:

 Compaction of CCR deposited in landfills.

 Placing covers on trucks transporting CCR.

 Watering roads at CCR landfills.

CCR dust may also be generated during winter months at frozen CCR impoundments. EPA is 

aware of at least three documented cases of CCR dust generated by frozen impoundments during 

subfreezing temperatures: two cases at First Energy's Bruce Mansfield power plant in 

Shippingport, PA, in March 1993 and March 2009, and one in January 2009 at Progress Energy's 

Asheville plant in Arden, NC. In all three instances, the respective state government 

environmental agencies issued notices of violations to the power companies.

 

307 The OMB Circular A-4 is available at: http://www.whitehouse.gov/OMB/Circulars/a004/a-4.pdf. See page 26.

308 The full text reads: “Sound quantitative estimates of benefits and costs, where feasible, are preferable to qualitative

descriptions of benefits and costs.... However, some important benefits and costs (e.g., privacy protection) may be inherently too 

difficult to quantify or monetize given current data and methods... You should monetize quantitative estimates whenever 

possible. Use sound ad defensible values or procedures to monetize benefits and costs, and ensure that key analytical 

assumptions are defensible. If monetization is impossible, explain why and present all available quantitative information...” 

(OMB Circular A-4, Sept 17, 2003, pp. 26-27).
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The value of this benefit would be to reduce future expenses and time associated with mitigating 

the impacts of CCR fugitive dust and avoid human health impacts from CCR dust inhalation. 

Data linking specific dust-related costs and the anticipated reduction in fugitive dust under the 

CCR rule are not available, but the public comments suggest that improved management of CCR 

dust might have benefits in addition to the health impacts associated with reduced CCR dust 

inhalation.

6.2 Financial Investment Benefit for the Electric Utility Industry

Ideally, this RIA would quantify the capital market effects of the CCR rule, but the current 

literature does not support a robust quantitative assessment. Therefore, this section summarizes 

studies that examine the relationship between the disclosure of environmental liabilities and 

firms’ market valuation (or the cost of capital). While not specific to the CCR rule, this literature 

review may provide insights into the potential magnitude of the CCR rule’s potential future 

capital market effects, because disclosure reduces uncertainty in capital markets.

This impact is not duplicative of the reduced impoundment release clean-up benefit and reduced 

groundwater remediation benefit monetized in Chapter 5, because the monetary value of future 

increases or decreases in some electric utility company stock valuations induced by the CCR rule 

for the reasons presented below, may not necessarily equal cleanup and remediation cost 

liabilities. Furthermore, cleanup and remediation costs represent deployment and expenditure of 

real resources (i.e., labor, energy, materials) whereas stock valuations represent market values of 

assets.

Although not monetized, the potential magnitude of this benefit in any single liability instance 

may be indicated by the cost data presented elsewhere in this RIA: (a) the TVA estimated for its 

December 2008 Kingston TN CCR impoundment structural failure event a range of remediation 

costs of $1.1 to $1.2 billion, and the remediation costs associated with four other historical 

industrial impoundment release events ranged from $13 million to $89 million each (see Section 

5.1 and Appendix Q), (b) historical data indicate groundwater remediation (pump and treat) 

costs average $7 million per case (see Exhibit 5-J), and (c) Appendix R of this RIA indicates a 

historical average $13.7 million in natural resource settlement damage costs.

6.2.1 Liability Uncertainty and Market Valuation

The CCR pollution control requirements of the CCR rule could potentially reduce uncertainty 

surrounding the electric utility industry’s environmental liabilities, enabling financial markets to 

value electric utility companies more accurately. While it is not clear from the literature review 

that such a potential change in uncertainty would have an appreciable effect on firms’ market 

valuation, at least two studies show a statistically significant relationship between a firm’s 

environmental liabilities and its market valuation.

The first, Campbell et al. (1998), analyzes the relationship between uncertainty specific to a 

firm’s Superfund environmental liabilities and the market value of the firm’s common stock. 

This study finds that the magnitude and significance of this relationship varies across industries 

but that overall environmental uncertainty negatively impacts the market’s perception of a firm, 
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therefore decreasing the firm’s market value.309 More specifically, the study finds that significant 

uncertainty surrounding a firm’s Superfund liabilities can decrease its market value by more than 

$4 per share per Superfund site.310

Second, Barth and McNichols examine the relationship between disclosures of estimated 

Superfund environmental cleanup costs and investors’ assessments of firms’ unrecognized 

environmental liabilities as part of a 1994 study. The study concludes that investors’ average 

assessment of firms’ liabilities was 28.6% of equity (i.e., environmental liabilities are 28.6% of 

market value).311

These results demonstrate that uncertainty can impact market value, and by extension the 

efficiency of financial markets, and suggest that inaccurate assessment of a firm’s liabilities may 

lead markets to over- or under-value the firm. These studies imply that reductions in uncertainty 

similar to the reduction in environmental liability uncertainty likely to result from the CCR rule 

may positively affect (i.e., increase) the financial investment valuation of electric utility 

companies. These potential future changes in valuation would reflect investors’ expectations of 

future profitability, which may lead investors to reallocate capital to be more efficiently deployed 

across the economy. To the extent that capital is reallocated to investments yielding a higher 

return, the productive capacity of the economy would likely increase.312 In the absence of 

complete and actuarially fair insurance markets, reducing liability uncertainty should improve 

market efficiency since investors will be better able to identify the best use of resources.

6.2.2 Disclosure and Market Valuation

While the literature examining the relationship between market valuation and environmental 

liability uncertainty is limited, several peer-reviewed studies quantify the impact of disclosing 

environmental liabilities on a firm’s market valuation. Both the environmental safeguards and 

the information disclosure required by the CCR final rule, should improve information available 

to the public regarding potential environmental liability. The CCR final rule will increase the 

public availability of information about actual and potential CCR contamination risks to 

households and communities by multiple requirements:

 The CCR rule contains a number of provisions requiring electric utility companies to 

document their compliance with the CCR rule’s technical requirements.

 To post those documents on a publically available website in a timely and transparent 

manner.

 The rule also requires utility companies to notify state government environmental 

agencies of numerous actions, including that certified CCR pollution control and safety 

 

309 Campbell, Katherine, Stephan E. Sefcik and Naomi S. Soderstrom. “Site uncertainty, allocation uncertainty, and superfund 

liability valuation.” Journal of Accounting and Public Policy 17: 331-366. 1998.

310 This was the average across the entire sample. For the chemical industry, the study found that the impact of significant 

uncertainty could decrease a firm’s market value by more than $19 per share.

311 Barth, Mary E., and Maureen F. McNichols. “Estimation and Market Valuation of Environmental Liabilities Relating to 

Superfund Sites.” Journal of Accounting Research 32: 177-209. 1994.

312 Solow, Robert M. "A Contribution to the Theory of Economic Growth." Quarterly Journal of Economics 70, no. 1: 65-

94.1956.
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demonstrations have been completed. This transparency will facilitate citizen and state 

government oversight and overall enforcement of the CCR rule.

 Finally, the rule establishes specific time frames by which these actions must occur, 

including time frames by which facilities must document compliance with the various 

technical requirements in the rule. Time frames have been established for: (1) technical 

compliance demonstrations made by the owner or operator; (2) certifications made by a 

qualified professional engineer verifying the technical accuracy and veracity of the 

compliance demonstration; (3) notifications made to the State Director; (4) submittals 

(e.g., data, reports and other documentation) to the operating record; and (5) postings to 

the owner or operator’s publicly accessible internet site.

If the CCR rule results in future disclosure of additional environmental liability of some electric 

utility companies (e.g., from the publicly available results of additional future groundwater 

monitoring for CCR contamination), their stock valuations could decrease, which would be a disbenefit to investors. On the other hand, from a broader market efficiency perspective, the lower 

valuation would represent internalization of liabilities, thereby improving efficiency of investor 

decision-making and helping ensure that resources move to their highest best use.

Campbell et al. (2001) find that financial disclosures related to Superfund environmental 

liabilities provide the market with additional information, thus reducing the uncertainty 

surrounding the value of a company and allowing for a more informed valuation of liabilities. In 

some cases, disclosure positively affects firms’ market value because of reduced uncertainty.313

Blacconiere and Patten (1994) find that more extensive environmental disclosures partially 

mitigate negative share price impacts after a chemical leak to the environment, and suggest that 

environmental disclosures enable the market to value companies’ risks more accurately by 

reducing the uncertainty of financial implications of an environmental event.314

Aerts et al. (2006) find that in general, increased environmental liability disclosures decrease the 

variation of analysts’ earnings forecasts for the specified company, suggesting that increased 

environmental disclosure decreases uncertainty and enables the market to value firms more 

accurately. This allows investment capital to be allocated more efficiently.315

Finally, Comier et al. (2009) find that an increase in paper-based (rather than web-based) 

disclosure is correlated with a decrease in share price volatility, suggesting that a decrease in 

market uncertainty may enable financial markets to operate more efficiently.316 Other studies 

evaluate the effects of the type of disclosure on a company’s market valuation or performance. 

 

313 Campbell, Katherine, Stephan E. Sefcik, and Naomi S. Soderstrom. “Disclosure of Private Information and Reduction of 

Uncertainty: Environmental Liabilities in the Chemical Industry.” Review of Quantitative Finance and Accounting 21: 349–378. 

2001.

314 Blacconiere, W.G., and D.M. Patten. “Environmental disclosures, regulatory costs and changes in share value.” Journal of 

Accounting and Economics. 18: 357-377. 1994.

315 Aerts, Walter, Denis Cormier, and Michel Magnan. “Corporate Environmental Disclosure, Financial Markets and the Media: 

An International Perspective.” 2006.

316 Cormier, Denis, Marie-Josee Ledoux and Michel Magnan, “The Informational Contribution of Social and Environmental 

Disclosures for Investors.” 2009.
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Cox and Douthett (2009) analyze the relationship between GAAP environmental disclosures in 

companies’ 10-K reports; the study finds that confirmatory disclosures, which are designed to 

confirm that the company’s profits are not at the expense of the environment, result in an 

increase in profits, while non-confirmatory disclosures, which convey information without 

context, result in a reduction in profits.317

Moneva and Cuellar (2009) find that, in Spain, financial environmental disclosures impact a 

company’s market value, but non-financial environmental disclosures do not.318 The authors 

explain that disclosures became more significant to market valuation after the introduction of 

reporting regulations. Although the results of this study cannot be generalized for firms in the 

United States, the basic relationship is important to note.

6.2.3 Impact of Disclosure on Cost of Capital

Several papers analyze the effects of environmental disclosures on a firm’s cost of capital.

Focusing on firms in five major U.S. industries, Plumlee et al. (2009) find that the quality of 

voluntary environmental disclosure is positively related to the cost of capital.319 In contrast, 

Clarkson et al. (2010) analyze the impact of voluntary environmental disclosures and find that 

voluntary environmental disclosures are not associated with a firm’s cost of capital.320 Thus, 

unlike most of the other studies reviewed in this section, this paper suggests that disclosure 

would not significantly affect the efficiency of financial markets.

Botosan (1997) examines the relationship between voluntary environmental disclosures and the 

cost of capital based on a disclosure index and finds a negative relationship between disclosures 

and the cost of capital for firms without a close analyst following, but no such relationship for 

firms with such a following.321 The study concludes that this result reflects the fact that firms 

with a high analyst following make information available to analysts that is not available in 

annual reports. As a result, this information may preempt or negate any cost-of-capital effect that 

would otherwise result from the annual report disclosures.

Similarly, Richardson and Welker (2001) assess the impacts of both disclosure and a firm’s 

analyst following on the cost of capital.322 The authors find that, consistent with Botosan (1997), 

an increase in the index score for financial disclosures reduces the cost of capital for firms with a 

low analyst following.323 In contrast, however, Richardson and Welker find that an increase in 

the index score for social disclosures increases the cost of capital.

 

317 Cox, Carol A., and Edward B. Douthett, Jr. “Further Evidence on the Factors and Valuation Associated with the Level of 

Environmental Liability Disclosures,” Academy of Accounting and Financial Studies Journal 13 (3): 2009.

318 Moneva, Jose M., and Beatriz Cuellar. “The Value Relevance of Financial and Non-Financial environmental reporting.” 

Environmental and Resource Economics, 44 (3): 441-456. 2009

319 Plumlee, M., D. Brown, and S. Marshall. “Voluntary environmental disclosure quality and firm value: the role of venue and 

industry type.” Working Paper. University of Utah. 2009.

320 Clarkson, Peter M., Xiao Hua Fang, Yue Li, and Gordon Richardson. “The Relevance of Environmental Disclosures for 

Investors and Other Stakeholder Groups: Which Audience are Firms Speaking to?” working paper. 2010.

321Botosan, C. “Disclosure level and the cost of equity capital.” The Accounting Review. 72: 323-349. 1997.

322 Richardson, Alan J., and Michael Welker. “Social disclosure, financial disclosure and the cost of equity capital.” Accounting, 

Organizations and Society 26: 597-616. 2001.

323 Financial disclosures include information pertaining to a firm’s financial performance. Social disclosures include information 

pertaining to a firm’s social performance (i.e. dedication to environmental practices or donations to a charity)
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Finally, Dhaliwal et al. (2009) examine the relationship between the cost of capital and voluntary 

non-financial social corporate disclosures (Corporate Social Responsibility, or CSR), and find 

that firms with CSR performance superior to their industry peers experience a negative 

relationship between CSR disclosure and the cost of capital.324 However, the study does not find 

a significant relationship between CSR disclosure and the cost of capital for firms with lower 

CSR performance.

6.3 Reduce Hazard Dread of Citizens Residing Near CCR Impoundments

Discomfort and stress can also materially reduce quality of life for anxious residents. A 2003 US 

Food and Drug Administration (FDA) benefit-cost analysis argued that fear and anxiety could be 

measured as welfare setbacks, and thus could reasonably be used in cost-benefit analyses. The 

FDA benefit-cost analysis suggested that the benefits of avoided fear could, with a specific and 

tailored analysis, be measured in fear-days. It cites one example that estimates the cost of one 

fear-day as ranging from $49 to $123 for a variety of non-lethal ailments.325 These are 

quantitative factors that, while not estimated in this RIA, could constitute an additional benefit to 

those monetized in this RIA (Chapter 5).

EPA heard evidence of public fear concerning CCR impoundments from 113 citizens in written 

comments to the federal regulatory docket for the June 2010 rule, and in verbal statements at 

EPA’s eight public hearings held in the second half of 2010, as cited in Chapter 1 of this RIA.

326

Citizens who expressed concern to EPA lived within 1.5 miles of CCR management units. 

According to 2000 Census Bureau data approximately 253,500 people reside within one mile of 

the CCR management units considered in this RIA (Appendix U to this RIA presents one-mile 

population data for CCR landfills and impoundments). The residents expressed concern over 

contamination of groundwater and nearby surface water, both with regard to drinking water and 

residential use (e.g., watering gardens). Other residents also referenced fear of air pollution, and 

increased rates of diseases such as cancer and neurological damage. Others worried about the 

effects of CCR impoundments on wildlife, or about property value losses in the vicinity of coal 

plants.The value of reducing these fears and concerns may be reflected to some extent in 

quantified air and water quality benefits, and would be difficult to separate. But it is likely that 

those estimates do include the full value of decreasingor eliminating this fear so regulationt that

improves CCR management through groundwater controls, structural integrity inspections, and 

fugitive dust controls would have some additional benefit in this regard.

6.4 Reduce Cancer and Non-Cancer Health Effects Resulting from 

Recreational Water Use

 

324 Dhaliwal, Dan, and Albert Tsang. “Voluntary Non-Financial Disclosure and the Cost of Equity Capital: The Case of 

Corporate Social Responsibility Reporting.” 2009. The paper uses a CSR strength ranking score that accounts for a company’s: 

community involvement, corporate governance, diversity, employee relations, environment, human rights, and product.

325 The 2003 FDA benefit-cost analysis is discussed in Matthew D. Adler, “Fear Assessment: Cost-Benefit Analysis and the 

Pricing of Fear and Anxiety,” Chicago-Kent Law Review, Vol. 79, 2004, pp. 977 to 1053. The FDA benefit-cost analysis pertains 

to the FDA’s March 31, 2003 proposed rule “Medical Devices: Patient Examination and Surgeon’s Gloves; Test Procedures and 

Acceptance Criteria,” Federal Register, Vol. 68, March 31, 2003 (the FDA benefit-cost analysis is summaried on pages 15408 to 

15413 of the FR notice).

326 Eight public hearings were held between August and October 2010 in Colorado, Illinois, Kentucky, North Carolina, 

Pennsylvania, Tennessee, Texas, and Virginia.
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The CCR rule may also result in reduced human health effects (both cancer and non-cancer) to 

recreational water users. For example, by closing some CCR surface impoundments and 

reducing permitted discharges to surface waters, the CCR rule may result in a reduction in the 

number of surface water receiving reaches that exceed human health-based aquatic water quality 

criteria (AWQC) limits. AWQC are set at levels to protect human health through ingestion of 

water and aquatic organisms. Accordingly, reducing the frequency at which human health-based 

AWQC are exceeded should translate into reduced risk to human health. Comparing AWQC 

exceedences in the baseline to exceedences under the CCR rule could be used as an indirect 

indicator of reduced risk to human health. Alternatively, detailed risk analysis could estimate the 

expected human health benefit. However, data limitations do not allow for quantification or 

monetization of this benefit in this RIA.

6.4.1 Reduce Cancer and Non-Cancer Health Effects Resulting from Fish Consumption

Recreational anglers and subsistence fishers (and their household members) who consume fish 

caught in the reaches receiving CCR surface impoundment discharges are expected to benefit 

from reduced pollutant concentrations in fish tissue resulting from some CCR impoundments 

closing as a result of the CCR rule. EPA analyzed the following four direct measures of change 

in risk to human health from exposure to contaminated fish tissue:

1. Incidence of cancer from fish consumption;

2. Neurological effects to children ages 0 to 7 from exposure to lead;

3. Neurological effects to infants from in-utero exposure to mercury; and

4. Other cancer and non-cancer toxic effects from fish consumption. 327

EPA monetized the first three of these four measures in Chapter 5. However, quantified human 

health benefits represent only a subset of the potential health benefits expected to result from the 

CCR rule. Due to the lack of data on the dose-response relationship between ingestion rates and 

potential other adverse health effects, this RIA is not able to quantify these other cancer and noncancer toxic effects from fish consumption.328 The types of potential adverse effects that could 

be avoided as a result of the CCR rule include kidney damage from cadmium or selenium 

exposure, cardiovascular impacts from lead exposure, gastrointestinal problems from zinc, 

thallium, or boron exposure, and others.329

6.5 Reduce Sediment Contamination

CCR impoundment effluent discharges from coal-fired electric utility plants can contaminate 

surface water sediments. For example, adsorption of arsenic, selenium, and other pollutants 

found in CCR impoundment discharges can result in accumulation of contaminated sediment on 

 

327 For some types of cancer known to be associated with pollutants, EPA did not have adequate cancer slope factors to conduct

quantitative analyses of risk.

328 A dose-response relationship is an increase in incidences of an adverse health outcome per unit increase in exposure to a toxin.

329 See “Benefit and Cost Analysis for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category,” EPA Office of Water, EPA report nr. EPA 821-R-13-004, April 2013, available from the 

Federal regulatory docket as document ID nr. EPA-HQ-OW-2009-0819-2238 at http://www.regulations.gov.
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stream and lake beds, posing a particular threat to benthic (i.e., bottom-dwelling) organisms.330

These pollutants can later be re-released into the water column and can enter organisms at 

different trophic levels. Concentrations of selenium and other pollutants in fish tissue of 

organisms of lower trophic levels can bio-magnify through higher trophic levels, posing a threat 

to the food chain at large.331

By reducing discharges of CCR pollutants to receiving reaches through the closure of CCR 

surface impoundments, the CCR rule would reduce the future contamination of sediments. As a 

result, the CCR rule would avoid impacts to benthic organisms and would reduce the probability 

that the pollutants would later be released into the water column, affecting surface water quality 

and the food chain. Due to data limitations, this RIA did not quantify or monetize this benefit.

While there might be some overlap, for the impacts of sediment contamination that are not 

overlapping with non-market effects and the health and well-being impacts of consuming 

contaminated fish, these non-overlapping benefits are also additional to those quantified in 

Chapter 5 of this RIA.

6.6 Reduce Water Treatment Costs for Drinking and Irrigation Water

The CCR rule is expected to reduce permitted pollutant discharges to surface waters through the 

closure of some CCR surface impoundments. As a result, the rule may enhance the use of these 

waters for drinking water supply or agriculture. This RIA did not quantify or monetize benefits 

from enhanced quality of drinking and agricultural water sources due to data limitations.

The closure of some CCR surface impoundments and resulting reductions in CCR pollutant 

loadings to surface waters may reduce the costs of drinking water treatment (e.g., filtration and 

chemical treatment) by reducing metal concentrations and eutrophication in source waters. 

Eutrophication is one of the main causes of taste and odor impairment in drinking water, which 

has a major negative impact on public perceptions of drinking water safety. Additional treatment 

to address foul tastes and odors can significantly increase the cost of public water supply.

Further, public drinking water sources do not always effectively remove bromides (a pollutant in 

wastewater from coal-fired electric utility plants) from raw surface waters. Elevated bromide 

concentrations in source waters result in increased trihalomethanes (THMs) in drinking water.332

Drinking water utilities downstream of bromide sources are increasingly finding it difficult to 

meet drinking water standards for THMs. If water treatment is not sufficient, an alternate water 

source needs to be substituted, if available. Long-term solutions could require the development 

of new water supplies, which would involve costs for the acquisition of land, regulatory review 

and permitting, development of infrastructure (dams, pumps, pipes), and watershed protection.

 

330 Ruhl, L., A. Vengosh, G.S. Dwyer, H. Hsu-Kim, G. Schwartz, A. Romanski, S.D. Smith. 2012. The Impact of Coal

Combustion Residue Effluent on Water Resources: A North Carolina Example. Environmental Science and Technology 2012 Oct 

15.

331 Ibid.

332 Pittsburgh Water and Sewer Authority/University of Pittsburgh School of Engineering. 2012. Bromides, TDS, and 

Radionuclides in the Allegheny River: A Possible Link with Marcellus Shale Operations.
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Reducing CCR pollutant discharges can improve agricultural productivity by improving water 

quality used for irrigation and livestock watering.333 Although elevated nutrient concentrations in 

irrigation water would not adversely affect its usefulness for plants, concerns exist for potential 

residual effects of pollutants entering the food chain. Further, eutrophication promotes 

cyanobacteria blooms that can kill livestock and wildlife that drink the contaminated surface 

water.

6.7 Improve Commercial Fishing Yields and Harvest Quality

CCR pollutant discharges from CCR impoundments to surface waters can reduce fish 

populations by inhibiting the reproduction and survival of aquatic species. These changes may 

negatively affect commercial fishing industries as well as consumers of fish, shellfish, and fish 

and seafood products. Estuaries are particularly important breeding and nursery areas for 

commercial fish and shellfish species. In some cases, excessive pollutant loadings can lead to the 

closure of shellfish beds, thereby reducing shellfish harvests.

Improved water quality due to reduced CCR pollutant discharges associated with the closure of 

some CCR surface impoundments would be expected to enhance aquatic habitat and, as a result, 

contribute to the reproduction and survival of commercially harvested species, potentially 

leading to a larger fish and shellfish harvest. Increases in harvest would result in an increase in 

producer and consumer surplus.

This RIA did not quantify or monetize expected future benefits to commercial fisheries from the 

CCR rule. However, the Environmental Assessment conducted for the EPA Office of Water’s 

Steam Electric Power Generator Effluent Limitations Guidelines June 2013 proposed rule shows 

that a small number of steam electric plants, which include coal-fired plants covered by the CCR 

rule, discharge to estuaries or marine waters.334 As a result, the benefits to commercial fisheries 

associated with the CCR rule are likely to be relatively small.

6.8 Increased Participation in Water-Based Recreation

The CCR rule may also have a beneficial impact on local economies by contributing to tourism 

(e.g., sales of fishing equipment) in the areas surrounding affected waters. Reductions in CCR 

impoundment discharges to surface waters resulting from some CCR impoundments closing as a 

result of the CCR rule may lead to improved recreational opportunities. The effects of water 

quality on tourism are likely to be highly localized. Moreover, since substitute tourism locations 

may be available, increased tourism in the vicinity of coal-fired electric utility plants may lead to 

a reduction in tourism in other locations. Due to these factors, it is probably that any future 

potential benefit from an increase in tourism would be limited to communities in the vicinity of 

CCR surface impoundments; although tourism revenue is potentially important to these 

communities, the overall societal benefits are likely to be small. Therefore, this RIA did not 

 

333 Clark, E., J.A. Haverkamp, and W.Chapman. 1985. ―Eroding Soils: The Off-Farm Impacts.‖ Washington, DC: The 

Conservation Foundation.

334 United States Environmental Protection Agency (U.S. EPA). 2013. Environmental Assessment for the Proposed Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (40 CFR 423). EPA-821-

R-13-003.
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quantify or monetize this benefit category. This category of benefits is additional to the waterbased recreation consumer surplus associated with water quality improvements considered in 

Chapter 5. This benefit represents a direct economic impact whereas the non-market valuation 

of water improvements considers willingness-to-pay to avoid contaminating an aquatic 

recreational area.

6.9 Reduce Fish Impingement and Entrainment Mortality

Coal-fired electric utility plants can use large quantities of water for on-site CCR transport (i.e., 

CCR sluicing from the boilers to impoundments) and for operating wet FGD scrubbers. Water 

intake from surface water bodies (i.e., rivers, lakes, and reservoirs) by coal-fired power plants 

likely results in harm to fish populations from impingement or entrainment mortality.335

By increasing conversions at some utility plants from wet CCR to dry CCR handling, the CCR 

rule is expected to reduce demand on surface water bodies, which is expected to result in an 

associated reduction in impingement and entrainment mortality.

Furthermore for some power plants, the CCR rule could reduce demand on groundwater aquifer 

withdrawals by coal-fired electric utility plants that rely on groundwater sources for water intake. 

Due to data limitations, this RIA did not quantify or monetize either of these benefits.

6.10 Increased Property Values Surrounding Electric Utility Plants

The induced closure of impoundments and the associated capping and revegetation requirement 

of the CCR rule may improve aesthetic conditions of the local landscape. As a result, property 

values of neighboring properties located within sight of these impoundments may increase, with 

benefits proportional to the number of impoundments closing under the CCR rule. Such 

revegetation of closed industrial waste sites is a standard practice according to EPA Office of 

Superfund Remediation and Technology Innovation (OSRTI). (However, the CCR rule may 

create a partially offsetting reduction in surrounding property values from the expansion or 

creation of new landfills to compensate for the closure of CCR impoundments.)

A substantial body of literature attempts to quantify the value of open space through contingent 

valuation and property value studies. These studies estimate property values as a function of 

housing and neighborhood characteristics, including proximity to open space. This RIA would 

ideally use site-specific information on surrounding property values and neighborhood 

characteristics to apply hedonic methods or case-by-case benefit transfer to monetize the benefits 

of revegetating closed surface impoundments. However, given the large number of 

impoundments in the universe, assembling such a dataset is not feasible.

A 2005 meta-analysis by McConnell and Walls of Resources for the Future analyzes more than 

60 studies published between 1967 and 2003 that quantify the benefit of open spaces, including 

 

335 Impingement occurs when fish are trapped against water intake screens and often leads to fish mortality as a result of injuries 

(such as damage to the gills). Entrainment occurs when fish are drawn into the facilityplant, and may result in fish mortality due 

to the high temperatures and pressure changes inside the facilityplant. 
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parks, natural areas, greenbelts, wetlands, forest preserves, and agricultural lands.336 Considering 

only those studies evaluating the effects of “general open space, parks, and natural areas,” 

McConnell and Walls find that the value of open space in terms of distance (i.e., being located 

200 meters closer to a given open space area) ranges from negative for some urban parks to 2.8% 

of the average house price.337 However, this value may not be directly comparable to the 

revegetation of closed surface impoundments, which are located on private property and are not 

expected to be redeveloped into public parks. As a result, this RIA does not attempt to monetize 

the aesthetic benefit of the CCR rule using estimates reported by McConnell and Walls. 

McConnell and Walls provide valuable discussion of the importance of controlling for location 

when evaluating open space. For example, one key study by Anderson and West (2003) included 

in the meta-analysis finds that proximity to open space increases urban housing prices but has no 

effect in the suburbs, where open space may be less scarce. 338 Because many surface 

impoundments are located away from urban areas, this finding suggests that the open space 

benefit may be small.

In addition to studies examining the impact of open space on property values, studies have also 

explored the effect of site clean-up on nearby property values, a relationship that may be more 

applicable to the closing and capping of leaking surface impoundments.339 CCR surface 

impoundments. However, it should be noted that once one goes beyond the impact of open 

space and examines the effect of site clean-up, the estimated effects on property values include 

many of the benefits discussed elsewhere in this RIA, such as recreation improvements and 

reduced cancer risks.

Gamper-Rabindran and Timmins (2012) found that hazardous site cleanup resulted in a 14.7% 

increase in the median census block-level housing values. This paper, however, uses Superfund 

sites as the hazardous sites which are cleaned up. As such, applying this relationship to leaking 

CCR surface impoundment closures may overstate benefits due to impoundment closures.

A 2012 study by Haninger et al. used property value hedonics to estimate the increase in 

property values accompanying brownfield cleanup. Brownfield cleanup is more similar to the

closing and capping of CCR pondsimpoundments. This study conservatively estimates that 

brownfield cleanup leads to a 5.12% increase in property values for properties within 1 kilometer 

of the cleanup site.

 

336 McConnell, Virginia and Margaret Walls. “The Value of Open Space: Evidence from Studies of Nonmarket Benefits.” 

Resources for the Future. January 2005.

337 Urban parks may have a negative effect due to the associated effects of crowding, noise, and traffic.

338 Findings differed across the studies included in McConnell and Walls meta-analysis, primarily because of the different 

methods employed and the specific context in which each study was conducted. In this particular paper, urban housing prices in 

the Minneapolis-St. Paul metropolitan area were found to increase from the presence of open space; Shultz and King (2001), 

however, found a negative correlation between urban parks and property value in Tucson, Arizona.

339 Previous versions of the RIA employed findings from Earnhart (2006) that related the enhancement value of a permanently 

protected prairie for property owners to the increase in property values due to newly created open space from impoundment 

closures. The characterisitics of these land uses differ to a greater extent than those between cleaned-up sites and closed 

impoundments. As such, the revised methodology applies a more appropriate relationship.
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Chapter 7 

Evaluation of Uncertainty for Cost and Benefit Estimates

Note: EPA has updated the analysis in this RIA; see Chapter 9 of this RIA for a description of 

the relevant modifications and the resultant recalculations. The sensitivity analyses in this 

chapter present non-modified calculations and totals in accordance with Chapters 4 and 5 of 

this RIA. Because the modifications made in Chapter 9 do not directly affect the uncertainties 

and parameters examined in this chapter, the relative impacts displayed in each sensitivity 

analysis presented in this chapter do not differ substantially between the figures presented in 

this chapter and the corresponding potential impacts of these sensitivity analyses on the 

modified, recalculated results presented in Chapter 9. Note that Chapter 9 separately 

considers three additional sensitivity analyses associated with specific changes to the 

updated parameters.

This chapter discusses key areas of uncertainty associated with the cost and benefit analyses 

presented in the preceding chapters. In general, the estimates in prior chapters represent best 

estimate ranges or the most appropriate point estimates, where relevant, and reflect an approach 

designed to ensure that both costs and benefits of the rule are not over- or understated. 

A number of different sources of uncertainty affect different areas of the analysis. This chapter 

identifies and considers each source of uncertainty separately, to provide insights into the 

uncertainty sources that are most significant. 

This chapter addresses the following 11 sources of uncertainty:

 Uncertainties affecting cost estimates. (n=4). Wet-dry conversion costs, 

potential for plants to comply through fuel switching, tonnage assumed to be 

handled in storage impoundments, and uncertainty related to transportation to offsite disposal facilities. In addition, uncertainties related to aspects of the cost 

estimates treated probabilistically within the analysis are characterized via 

bounding analyses in this section. 

 Uncertainties affecting benefit estimates. (n=2). Differing assumptions 

underlying the prediction of the probability of impoundment failures and 

variations in capacity factors of impoundment releases.

 Summary measures of uncertainty. (n=5). Uncertainty associated with 

compliance assumptions (affecting both costs and benefits), and estimation 

uncertainty related to costs and benefits, and a summary of overall uncertainty 

related to both costs and benefits.

This chapter also briefly notes in the following sections several additional sensitivity analyses or 

consideration of limited uncertainties that have been addressed in other chapters and are not 

likely to affect overall results.
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7.1 Key Cost Uncertainties

This section identifies a number of uncertainties relating to inputs used within the Fortran and 

STATA-based models to calculate incremental compliance costs. For each input with a 

significant uncertainty identified, this section describes the potential variation caused by altering 

model inputs to reflect the uncertainty inherent in the input chosen to present the costs in 

Chapter 4. Specifically, this section examines the uncertainty of several key cost inputs:

1. Estimation of wet-dry conversion costs. The cost of wet-dry CCR handling 

conversion is large and highly variable depending on facilityplant design. Due to 

data limitations, this RIA applies a wet-dry conversion cost on a per-ton basis to 

facilities that convert, based on nationwide, aggregated data from a survey of 

power plants conducted by EPA’s Office of Water (see Section 3.1.1 for a 

description of the survey, or Section 4.3.13 for a description of the relevant 

costs). This per-ton estimate, while likely appropriate for estimating total national 

costs of wet-dry conversion, does not capture facilityplant-level capital costs in 

the planning stage. Therefore, the cost model incorporates a separate “financial 

hurdle” to approximate capital costs of wet-dry conversion, and applies this cost, 

rather than the wet-dry conversion cost, when decision points are reached and 

various CCR management options are compared with the model. To examine the 

uncertainty associated with the use of this financial hurdle, Section 7.1.1 below 

examines the results of the cost modeling if the financial hurdle were not applied.

2. Fuel switching to natural gas. Very recent developments in the energy market 

may, for the first time in history, provide some plants with the option to costeffectively switch from coal to natural gas as a potential method of complying 

with the CCR rule. The cost model used for this RIA predates this recent market 

shift, and does not include the detailed electricity market model or the specific 

facilityplant information (e.g., age and technology of coal boilers) that would be 

necessary to incorporate fuel-switching as a compliance option. Section 7.1.2

below discusses in more detail the potential impacts on cost associated with this 

market shift. 

3. As described in Chapter 3 and Chapter 4, this RIA assumes that storage 

impoundments do not handle 100% of a plant’s wet-handled CCR before 

transferring it to a disposal impoundment, but rather that approximately 25% of a 

plant’s wet-handled CCR also incurs costs in storage impoundments prior to final 

disposition in a disposal impoundment (see Section 3.3.4.3). Section 7.1.3

examines the impact of changes in this assumption via sensitivity analyses by 

examining some lower-cost scenarios where plants manage only 5% of wethandled CCR in storage impoundments, and a lower-bound scenario where plants 

are assumed to manage no CCR tonnage in storage impoundments (fixed costs 

associated with storage impoundments are still incurred, however). Given that 

managing CCR in storage impoundments reflects a “double-management” with 

additional costs, this RIA does not assume that factors above 25% of wet-handled 

tonnage at a given plant reflect realistic possibilities for CCR management in 

storage impoundments.
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4. Transport distances for off-site disposal. This RIA uses a one-way distance of 

25 miles to the nearest off-site landfill to estimate costs associated with off-site 

disposal under the final CCR rule based on model calibration that ensures that offsite disposal costs do not widely undercut on-site CCR management costs in the 

baseline. Section 7.1.4 summarizes the impact of using another one-way distance 

as an illustration of the potential variability associated with this assumption.

In addition, the cost modeling for this RIA includes a number of probabilistic elements. In 

Chapters 3 and 4, cost estimation results are generally presented as an expected value or central 

estimate, even if probabilistic components factor into their calculation. In Section 7.1.5 below, 

this RIA presents bounding analyses based on the minimum and maximum values of various 

probabilistic elements applied in the cost model, as follows:

 Overall cost variability, mainly driven by the probability of an unlined 

impoundment incurring a groundwater contamination event in a given year: 

this section characterizes the entire range of potential variability in the costs of the 

CCR final rule, as shown graphically in Section 4.4.2. While this analysis bounds 

the entirety of the costs and presents minimum and maximum cost estimates, the 

majority of this variation is driven by the likelihood that an unlined impoundment 

will incur a groundwater contamination event and thus reach a decision point in a 

given year. The three items below contribute a relatively small amount to overall 

cost variation, though this RIA captures the individual variability associated with 

each item for illustrative purposes.

 Lined/unlined impoundments: whether or not existing surface impoundments 

have liners meeting the criteria of the CCR final rule drives a substantial element 

of the cost estimation decision logic, in that impoundments lacking sufficient 

liners are subject to decision points, including closure and potentially wet-dry 

conversion when a groundwater contamination event occurs. The current cost 

estimation process probabilistically assigns impoundments of unknown liner 

status either a “lined” or “unlined” status; this section examines the overall cost 

impacts of assuming that all impoundments of unknown status are mapped as 

either “lined” or “unlined.” 

 Demonstrations for units affected by location restrictions: as described in 

Chapters 3 and 4, units subject to location restrictions are assumed to have a 50% 

probability of being able to demonstrate sufficiently and continue on-site disposal, 

and a 50% probability of failing to demonstrate and shifting disposal off-site; this 

section examines the impact of assuming all units affected by location restrictions 

either successfully demonstrate or fail to do so as a bounding analysis on the 

overall cost effects of location restrictions. 

 Structural integrity inspections: 70 of the 735 surface impoundments did not 

have available dimensionality data (i.e., impoundment area, capacity, depth, 

height, etc.) upon which their mapping to “more stringent” or “less stringent” 

structural integrity inspections could be completed; this section examines the 

impact of assuming all of these ponds were mapped either to “less stringent” or 

“more stringent” inspections.
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In addition, this RIA assumes full (100%) compliance with all CCR pollution control 

requirements, both under state regulations as well as under the CCR final rule, consistent with 

EPA policy; evaluating uncertainty requires estimation of costs relaxing this full compliance 

assumption by assuming a lower rate of compliance. The impact of compliance assumptions on 

costs is discussed below in Section 7.3.

7.1.1 Impact of Uncertainty Related to Wet-to-Dry Conversion Costs and Use of the 

Financial Hurdle for Wet-to-Dry Conversion

The cost of wet-dry conversion is large and highly variable depending on facilityplant design. 

Due to data limitations, this RIA applies a wet-dry conversion cost on a per-ton basis to facilities 

that convert, based on nationwide, aggregated data from a survey of power plants conducted by 

EPA’s Office of Water. This per-ton estimate, while likely appropriate for estimating total 

national costs of wet-dry conversion, does not capture facilityplant-level capital costs in the 

planning stage. Therefore, the cost model incorporates a separate “financial hurdle” to 

approximate capital costs of wet-dry conversion, and applies this cost, rather than the wet-dry 

conversion cost, when decision points are reached and various CCR management options are 

compared with the model (see Section 3.3.4.4 for additional information on the hurdle rates for 

wet-dry conversion used in this RIA). 

The net effect of using a hurdle rate for the comparison purposes, rather than the actual wet-dry 

conversion cost, is to prevent modeling wet-dry conversion at a CCR impoundment if the 

difference in dry versus wet management is marginal. In other words, use of a hurdle rate 

calibrates the cost estimation model by preventing cases where the model predicts that wet-dry 

conversion would occur despite incurring only a modest cost savings. The use of the hurdle rate 

addresses the cases where the model indicates a possibility for wet-dry conversion, and this wetdry conversion results in a substantial cost savings relative to wet CCR management options 

available to the facilityutility plant in question.

To examine the uncertainty associated with the use of this financial hurdle, this RIA applies a 

sensitivity analysis that simulates a model run where no hurdle rate is applied. Rather, the results 

of this sensitivity analysis indicate the central estimate costs if the model used the actual wet-dry 

conversion cost (i.e., assumed that costs were linear with respect to tonnage converted) in its 

calculations for determining the lowest-cost future CCR management option, rather than the 

hurdle rate.340

 

340 Note that despite the use of the hurdle rate for comparison purposes in the cost estimation model, the actual costs assigned to 

wet-dry conversion and shown in the latter parts of Chapters 3 and 4 are wet-dry conversion costs and not the associated hurdle 

rate costs.
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Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

Exhibit 7-A

Sensitivity Analysis: Impact of Use of Wet-Dry Conversion Costs in lieu of Hurdle Rate

Annualized Costs at 7% Discount Rate (millions of 2013$)

Category

Central Estimate of Total Incremental Cost of Final CCR Rule

Hurdle Rate No Hurdle Rate Used

CCR Impoundments $215 $265

Total Costs $739 $789

As shown in Exhibit 7-A above, the removal of the hurdle rate results in an increase in the

central estimate or expected value costs of roughly $50 million in annualized terms. This 

represents an increase of approximately 23% for overall costs associated with disposal 

impoundments, or an overall increase of approximately 6.8% for the incremental costs associated 

with the final CCR rule as a whole.

Costs increase in this sensitivity analysis due to the interplay between the static hurdle rates 

provided by the EPA Office of Water for electric utility plants of various sizes and the per-ton 

wet-dry CCR conversion costs provided by the EPA Office of Water. While these two sets of 

inputs are generally comparable, by using the per-ton cost estimate for wet-dry conversion, 

plants managing very large quantities of CCRs in disposal impoundments would, in effect, incur 

wet-dry conversion costs in excess of the hurdle rate (average capital cost for large facilityplant) 

identified by Office of Water. Because these large plants also incur a substantial portion of the 

cost associated with the final CCR rule, especially where disposal impoundments are concerned, 

the removal of the use of a relatively lower hurdle rate (compared to wet-dry conversion costs on 

a per-ton basis at large plants) in these cases results in a scenario where the higher wet-dry 

conversion cost dissuades the plant from wet-dry converting and choosing a less costly dry CCR 

management option in the future, instead leading to a decision to avoid wet-dry conversion and 

its attendant costs and continue to use a relatively more costly wet CCR management option.

Any cost savings associated with a lower wet-dry conversion cost used for comparisons for 

smaller plants is eroded by this phenomenon for the largest plants, largely because most costs 

applied in the cost estimation model are per-ton costs and considerably larger for plants 

managing high volumes of CCR tonnage in disposal impoundments.

Finally, the net impacts of this uncertainty are relatively small: a variability of less than 10% 

arising from this particular modeling assumption is well contained within the overall bounds of 

modeling uncertainty shown in Exhibit 7-E at the end of this section. The minimum cost in 

Exhibit 7-E is approximately 61% less than the central estimate, and the maximum cost is 

approximately 79% more than the central estimate of total annualized incremental compliance 

costs of the final CCR rule, a considerably larger span of variability relative to the uncertainty 

associated with this assumption.341 

 

341 Furthermore, for disposal SIs only, the minimum estimate represents a reduction of approximately 73% in costs relative to the 

central estimate, while the maximum estimate is an increase of approximately 71%. Even when only disposal SIs are considered,

the uncertainty associated with this one modeling assumption does not supersede the range of possible uncertainty associated 

with other assumptions and modeling considerations.
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7.1.2 Discussion of Uncertainty Related to Fuel Switching

Recent changes in U.S. energy production markets have implications for the costs and benefits 

estimated in this RIA. Specifically, the unprecedented emergence of natural gas as a low-cost 

alternative to coal may provide an economically viable (i.e., low-cost) option of switching 

energy production from coal to natural gas in order to comply with CCR regulations. This RIA 

does not consider fuel switching, which can encompass an owner’s decision to (a) retrofit an 

existing coal plant for gas, (b) build new gas plants in place of coal plants, or (c) switch to gas 

for base load generation. To the extent that fuel switching becomes a viable compliance option as 

compliance option as a result of thisthe CCR rule, this RIA may overestimate the costs and 

underestimate the benefits associated with the CCR rule.342 The IPM model runanalysis

described in Chapter 8 does capturesimulate potential future fuel switching by electric utilty 

plants.

Recent Developments in the Natural Gas Production Market

Over the last 12 months, developmentsDevelopments in the domestic energy market have 

affected long-term energy production planning, as newfound domestic reserves of natural gas 

have decreased the price of natural gas to the point that coal is in some cases no longer the least 

expensive fuel option. According to EIA’s 2012 AEO, the U.S. electric power sector’s historical 

reliance on coal-fired power plants has declined in recent years due to increased domestic 

production of natural gas. This increase is largely a result of increased shale gas production made 

possible by technology advances. Shale gas provided only a tiny fraction of total U.S. gas 

production before 2005, but now representsrepresented almost 25%.% in 2010. EIA expects 

production of shale gas to increase dramatically by 2035, with only a small decrease in each of 

the other methods (offshore, tight gas, coalbed methane, etc.).343 This production boom, coupled 

with consistently high coal prices and weak electricity demand, has created a market where 

natural gas can be an attractive alternative to coal for energy producers.344

These recent developments accelerate a trend that was already occurring. Over the past 

decade,Between 2000 and 2010?, electricity generated by natural gas has risen by more than 

half, although coal continues to dominate the industry in terms of kilowatt-hours.345 Consistent 

with this market shift, EIA’s 2012 energy forecasts predict that the share of coal in the overall 

production of electricity will fall to 39% over the next 25 years, down from its high of almost 

50% as recently as 2007. EIA attributes this decline to slow growth in electricity demand, new 

 

342 This RIA also does not consider explicitly fuel switching in the baseline, although some of the plants included in the analysis 

are intended for closure or conversion. Therefore, baseline costs may also be overstated. While considerations of fuel switching

are taken into account by the EIA AEO estimates2014 projection of future coal consumption for electricity generation, that drive 

CCR growth in this RIA, those estimates doprojection is a national aggregation which does not explicitly indicate closure or fuel 

switching of specific electric utility plants. If more fuel switching occurs in the baseline than thethis analysis assumes, both costs 

and benefits in this RIA will be overstated simply because there are fewer CCR-generating plants, but incremental rule costs 

could be generally similar on a per-facilityplant basis. In cases where rule-related cost increases make fuel-switching costeffective, then the incremental costs of the rule would be lower.

343 DOE EIA, AEO 2012 Early Release Overview. Available at: http://www.eia.gov/forecasts/aeo/er/pdf/0383er(2012).pdf.

344 Susan F. Tierney, 2012, Why Coal Plants Retire: Power Market Fundamentals as of 2012, Analysis Group, Inc. Available at: 

http://www.analysisgroup.com/uploadedFiles/News_and_Events/News/2012_Tierney_WhyCoalPlantsRetire.pdf

345 Richmond Times-Dispatch, January 2012, “Electric plants shift from coal to natural gas.” Available at: 

http://www2.timesdispatch.com/business/state-news/2012/jan/17/tdbiz01-electric-plants-shift-from-coal-to-natural-ar-1616116/
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environmental regulations, and increased competition from natural gas and renewable plants. By 

2035, EIAEIA’s 2012 AEO expects natural gas to provide 27% of U.S. electricity generation, up 

from 24% in 2010. The potentially enormous domestic reserves of shale gas may keep the price 

of natural gas down, preventing the price spikes that have made it an unreliable energy source in 

the past.

Methodological Considerations for Fuel Switching

This RIA examines only the relative cost of managing consistent quantities of CCR under the 

CCR rule and, other than the IPM analysis referenced in Chapter 8, does not consider the 

possibility that electric utility plants or their owner entities may decide to move awayswitch from 

coal as a fuel sourceto other fuels. The market shifts outlined above post-date the development 

of the cost model used in this RIA; the cost model therefore reflects the historical reality that 

coal has been the least expensive fuel source for electricity generators. To the extent that plants 

in the affected universe can comply with the CCR regulation by fuel switching at a lower cost 

than continuing to manage CCR, this RIA will tend to overstate costs.

Physically converting individual coal-burning facilities to natural gas also involves a number of 

short- and long-term cost considerations. To examine whether fuel switching is a low-cost option 

for responding to the regulatory requirements, it would be necessary to consider a wide array of 

energy market variables for each plant, the most important of which are detailed in Exhibit 7-B. 

In addition, future gas and coal prices are uncertain, as is future supply, particularly of natural 

gas, which has to be transported and stored. 

Exhibit 7-B

Plant-Level Considerations for Fuel Switching

Location Considerations Plants’ proximity to gas and coal supplies

Regional wholesale and retail prices for fuel and electricity

Constraints in regional energy distribution

Presence or absence of alternative fuels in region

Cost Considerations Age of the plant and boiler technology

O&M costs for natural gas and coal (beyond retrofit costs)

Local price of natural gas and coal

Regulatory Considerations Incremental costs of state and federal regulations

Relative benefit of avoiding waste management costs

State regulations related to recovery of capital costs

Additionally, companies’ planning for long-term energy production can affect the decision to 

switch to natural gas at an entity level, rather than a plant level. Energy companies that own 

multiple plants in a region are likely to try to optimize those plants over the long-term, based on 

any or all of the above considerations. For example, currently most entities use coal or nuclear 

plants for base load generation, because they have high fixed-costs but low operating costs, while 

gas plants are used for generation during peak demand periods. However, if natural gas prices 

were to remain low and stable, a regional entity might decide, based on the above factors, to 

switch certain plants to natural gas for base load capacity. In general, on an entity level, plant 
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owners would compare individual plants against one another, rather than an absolute cost 

standard, to decide which coal-burning plants, if any, should be converted to natural gas. 

A comprehensive energy market analysis is not included in this RIA, but it is likely that if gas 

prices continue to be competitive with coal, fuel switching will likely represent a low-cost option 

for complying with the CCR rule at some plants, particularly older and less efficient facilities in 

regions where natural gas is readily available. 

Potential Impacts of Fuel Switching on Regulatory Costs and Benefits

Market developments are likely to change both baseline and regulatory costs, as firms consider 

both future regulatory costs and future fuel supplies and prices in their market decisions. Both 

regulatory costs and market forces have been cited in several recent decisions by companies to 

switch from coal to natural gas, whether by converting existing generation facilities or building 

new ones.346 For example, Dominion Power, Virginia’s largest utility, plans to convert three of 

the state’s coal-fired units to natural gas, as well as three smaller units from coal to biomass.347 

Xcel Energy also plans to convert four units at a Denver plant to natural gas, which the company 

says will cost $1.3 billion, a sum that is still $225 million cheaper than upgrading the old and 

inefficient coal units to comply with new environmental regulations.348 Costs for converting to 

natural gas, whether through retrofitting existing plants or building new ones, can fall anywhere 

from $38 million to $769 million.349

The facilities that could decide to switch to natural gas rather than continue burning coal include 

plants that already have gas boilers, and plants that are owned by parent companies that already 

own gas plants. According to the 2009 DOE EIA-923 database, 187 of the 478 electric utility 

plants identified for this RIA are already outfitted with natural gas boilers. These facilities, which 

make up 39% of the universe, could potentially find that converting to natural gas and away from 

coal would be the most cost-effective way to respond to new requirements and costs under the 

CCR rule. For example, Xcel Energy’s Black Dog plant in Minnesota, one of the plants 

considered in the cost model, already has two natural gas boilers, and the company now plans to 

convert the station entirely to natural gas by 2016, pending state approval.350

Additionally, large parent companies are deciding to close old coal plants and convert an 

increasing number of plants to natural gas, which could potentially affect many of the plants 

considered in the cost model. Dominion Resources plans to close two coal-fired units in 

Hammond, Indiana, and three in Salem, Massachusetts by 2014.351 At least a dozen of the 478 

 

346 Wall Street Journal, n.d., “Turning Away from Coal.” Available at: 

http://online.wsj.com/article/SB20001424052748703579804575441683910246338.html

347 Richmond Times-Dispatch, January 2012, “Electric plants shift from coal to natural gas.”

348 Wall Street Journal, n.d., “Turning Away from Coal.”

349 “Natural Gas Conversions of Existing Coal-Fired Boilers,” White Paper MS-14, Babcock and Wilcox Power Generation 

Group, Inc. Barberton, Ohio, 2010, http://www.babcock.com/library/pdf/MS-14.pdf; “Progress Energy Gives up on Coal Plants,” 

John Murawski, News and Observer Publishing Company, December 2, 2009 

http://www.newsobserver.com/2009/12/02/221241/progress-energy-gives-up-on-coal.html; “Breaking Away From Coal,” 

Clifford Krauss, New York Times, November 29, 2010, http://www.nytimes.com/2010/11/30/business/energyenvironment/30utilities.html?pagewanted=all. 

350 Minneapolis-St. Paul Business Journal, “Xcel wants to convert Black Dog plant from coal to gas.” Available at: 

http://www.bizjournals.com/twincities/news/2011/03/15/xcel-asks-to-turn-black-dog-plant-to-gas.html

351 Richmond Times-Dispatch, January 2012, “Electric plants shift from coal to natural gas.”
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plants considered in this RIA have already or are planning to convert to natural gas.352 The 

Tennessee Valley Authority, which operates some of the southeast states’ oldest coal plants, is 

planning to convert some of them to natural gas.

To the extent that facilities adopt fuel switching approaches as a low-cost compliance strategy, 

conversion to natural gas would reduce costs associated with the rule. Moreover, a switch to 

natural gas could increase the benefits associated with the rule. In addition to avoiding risks and 

disamenities associated with CCR management, gas-fired plants are generally more efficient to 

run than coal-fired plants, and have lower air pollution impacts.353 Therefore, to the extent this 

rule causes facilities to use gas instead of coal, any air-related benefits would subsequently 

accrue, as would any benefits associated with substituting extraction and transport of natural gas 

for extraction and transport of coal. Because conversion to natural gas is an expensive process, 

and because the dramatic changes in the energy market are recent and uncertain (as is future 

demand for natural gas), it is not clear whether a significant number of plant-owners will opt to 

convert to gas in the short term as a result of this rule, but the cost estimates in this RIA may be 

overstated. 

7.1.3 CCR Tonnage Managed in Storage Impoundments

As described in Chapters 3 and 4, this RIA assumes that storage impoundments do not handle 

100% of a plant’s wet-handled CCR before transferring it to a disposal impoundment, but rather 

that approximately 25% of a plant’s wet-handled CCR also incurs costs in storage impoundments 

prior to final disposition in a disposal impoundment (see Section 3.32.4.3). This section 

examines the impact of changes in this assumption via sensitivity analyses by examining some 

lower-cost scenarios where plants manage only 5% of wet-handled CCR in storage 

impoundments, and a lower-bound scenario where plants are assumed to manage no CCR 

tonnage in storage impoundments (fixed costs associated with storage impoundments are still 

incurred, however).

Exhibit 7-C displays the total incremental compliance costs associated with storage 

impoundments under these two distinct sensitivity analyses. Note that due to the high 

incremental costs associated with storage impoundments as shown in Chapter 4, this RIA does 

not evaluate an upper-bound analysis where plants are assumed to handle 100% of their wethandled CCR in storage impoundments prior to transferring it to a disposal impoundment, as this 

would represent an extreme upper bound that does not reflect reality.

 

352 See, for example: Chattanooga Times Press, “TVA May Shutter Aging Coal-Fired Plants” at 

http://www.timesfreepress.com/news/2009/aug/24/tva-may-shutter-aging-coal-fired-plants/?local; Western Resource Advocates, 

“Clean Energy Accomplishments” at http://www.westernresourceadvocates.org/energy/coal/cleanenergyaccomplishments.php; 

Press of Atlantic City, “New Jersey's coal-fired power plants come clean ahead of pollution crackdown” at 

http://www.pressofatlanticcity.com/news/press/new_jersey/new-jersey-s-coal-fired-power-plants-come-cleanahead/article_b0b1782f-28f2-5eaa-bf21-74f0b5b1817a.html; and Wisconsin State Journal, “In March, Blount Street plant to 

make gas its primary fuel” at http://host.madison.com/wsj/business/article_28618898-0489-11df-8a48-001cc4c002e0.html.

353 Stan M. Kaplan, 2010, Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants, Congressional 

Research Service. Available at: http://www.anga.us/media/41047/congressional research service - ng in power generation.pdf
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Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

Exhibit 7-C

Storage Impoundment Costs under Alternative Tons Managed Assumptions

Incremental Annualized Costs at 7% Discount Rate (millions of 2013$)

Category

Primary Analysis 

(25% of wet CCR 

managed in storage)

5% of wet CCR managed in 

storage

0% of wet CCR managed in 

storage (no per-ton costs; fixed 

costs only)

Storage Impoundments $393 $186 $135

Total Costs $739 $532 $481

As evidenced above, assumptions regarding the amount of wet-handled CCR that is handled in 

storage impoundments prior to its final disposal in disposal impoundments has substantial cost 

implications for the compliance costs associated with the final CCR rule. By changing the 

assumption from 25% of wet-handled CCR placed in storage impoundments on an interim basis 

to 5%, incremental compliance costs associated with storage impoundments fall by over 52%, 

and total incremental compliance costs of the rule decrease by over 28%.354 Similarly, the lowerbound assumption that no wet-handled CCR tonnage is placed in storage impoundments on an 

interim basis, which includes only the fixed or “constant” costs associated with storage 

impoundments, results in storage impoundment compliance costs of $135 million annually, or a 

decline of approximately two-thirds relative to the central estimate of the primary analysis. 

Under this lower-bound assumption, total incremental compliance costs fall to $481 million as a 

central estimate, or a decline of approximately 35% relative to the central estimate under an 

assumption that 25% of wet-handled CCR tonnage is managed in storage impoundments prior to 

final disposal.

7.1.4 Transport Distances for Off-Site Disposal

This RIA uses a one-way distance of 25 miles to the nearest off-site landfill to estimate costs 

associated with off-site disposal under the final CCR rule. This assumption was derived as part 

of model calibration in order to create a baseline scenario where the majority of CCR disposal 

units did not incur cost savings by shifting to offsite disposal as soon as possible. If this scenario 

were not the case, the cost model would provide certain counterintuitive results by allowing 

certain disposal units to incur cost savings upon CCR management change, which would lead to 

the post-rule scenario resulting in cost savings if it prompted CCR management change prior to 

the unit reaching a similar decision point in the baseline.

Correspondingly, the 25-mile one-way transport distance is a key input to ensure that the cost 

model does not return results that imply that currently, electric utility plants are not managing 

their CCR in the most cost-effective ways available to them. Changes to this assumption should 

be made only in concert with changes to other inputs to ensure that the relationship between 

offsite versus on-site CCR management costs remain relatively steady. However, with that said, 

 

354 Because of the assumption that storage impoundments cannot switch to dry handling and must be replaced with a new lined 

storage impoundment, and because liner costs are calculated in large part by the tonnage of CCR, the cost changes that 

accompany decreased storage tonnage are very large.
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Exhibit 7-D examines the impact of revising the one-way transport distance to 12.5 miles, as an 

illustration of the potential cost impacts from altering this input.

Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

Exhibit 7-D

CCR Disposal Costs under Alternative Offsite One-Way Transport Distances

Incremental Annualized Costs at 7% Discount Rate (millions of 2013$)

Category Primary Analysis: 25-Mile One-Way Distance 12.5-Mile One-Way Distance

CCR Landfills $103 $94.6

CCR Impoundments $215 $208

Total Costs $739 $725

As shown above, changing the transport distance from 25 miles to 12.5 miles has only a marginal 

impact on both landfills and disposal impoundments: landfill costs decrease by approximately 

8%, while disposal impoundment costs fall by approximately 3%. Overall, total compliance costs 

fall by approximately 2%. While this assumption does not appear to have a major impact on 

overall compliance costs of the CCR rule when comparing 25-mile and 12.5-mile transport 

distances, additional changes to this input may hit the tipping point where the counterintuitive 

model results discussed earlier in this section occur with greater frequency, leading to a 

substantial underestimation of baseline and post-rule costs.

7.1.5 Bounding Analyses for Probabilistic Elements of the Cost Estimation Model

In addition to the modeling assumptions described above, this section provides additional detail 

on the four probabilistic elements of the cost estimation model and the inherent uncertainty and 

variability of total incremental costs associated with these elements:

 Occurrence of groundwater contamination events for unlined disposal and storage 

impoundments;

 Whether surface impoundments of unknown liner type are considered to be lined 

or unlined, and at what frequency;

 Whether CCR landfills and disposal impoundments subject to location restrictions 

are able to demonstrate and begin/continue operating or whether they fail to do 

and the plant must shift CCR disposal offsite, and at what frequency these 

outcomes occur; and

 For the purposes of estimating costs associated with structural integrity 

inspections, whether disposal and storage impoundments where size could not be 

directly ascertained using the data sources relied on by this RIA are to be 

considered subject to more stringent or less stringent structural integrity 

inspections, and at what frequency.
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Overall variability and groundwater contamination

Combining all four elements together produces overall variability in the cost estimates. Exhibit 

7-E below shows the minimum and maximum bounds for total incremental costs of the CCR 

final rule:

 The minimum estimate represents the lowest total incremental cost for the final CCR rule 

possible, given each impoundment’s probability of experiencing a groundwater 

contamination event in a given year. This estimate is assembled by considering the 

minimum possible incremental cost associated with each impoundment, and summing 

these minimum possible costs together. Correspondingly, this estimate represents an 

extreme lower bound; if this RIA were to use a simulated approach to probabilistic 

analysis, this outcome would have an infinitesimally small chance of occurring, because 

it would require each unlined impoundment to simultaneously incur its lowest-cost 

scenario over the entire 100-year period of analysis.

 The maximum estimate represents the highest total incremental cost for the final CCR 

rule possible, given each impoundment’s probability of experiencing a groundwater 

contamination event in a given year. Similar to the minimum estimate, this estimate is 

assembled by considering the maximum possible incremental cost associated with each 

impoundment, and summing these maximum possible costs together. Correspondingly, 

this estimate represents an extreme upper bound; if this RIA were to use a simulated 

approach to probabilistic analysis, this outcome would have an infinitesimally small 

chance of occurring, because it would require each unlined impoundment to 

simultaneously incur its highest-cost scenario over the entire 100-year period of analysis.

As evident from Exhibit 7-E below, the probabilistic aspect of the cost estimation analysis 

introduces substantial variability into the potential compliance costs associated with the final 

CCR rule. While the central estimate represents this RIA’s best estimate of the expected 

compliance costs given the full suite of probabilities considered as described in this chapter, 

incremental costs of the final CCR rule may be substantially higher or substantially lower as 

shown below. The figures below track with those presented in Section 4.4.2, though the charts 

therein are presented in present value, rather than annualized terms and do not include costs 

associated with inactive impoundments or state agency burden costs.
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Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

Exhibit 7-E

Bounding Analysis of Total Uncertainty associated with Total Costs of the CCR final rule

Incremental Annualized Costs for Surface Impoundments at 7% Discount Rate (millions of 2013$)

Category

Central Estimate

(Expected Value)

Minimum Estimate

(Lower Bound)

Maximum Estimate

(Upper Bound)

Landfills $103 $103 $103

Disposal Impoundments $215 $58.5 $368

Storage Impoundments $393 $96.7 $819

Inactive impoundments $26.7 $26.7 $26.7

Subtotal – Industry Costs $738 $285 $1,320

State Agency Burden Costs $1.36 $1.33 $1.37

Total Costs $739 $286 $1,320

Note that unlike the sensitivity analyses and uncertainty described in previous sections, the 

uncertainty associated with groundwater contamination incident occurrence, as well as with the 

three elements below is explicitly captured in Exhibit 7-E, as the minimum cost estimate and the 

maximum cost estimate assume the appropriate combination of assignments and 

characterizations to yield the minimum and maximum cost for each CCR management unit. 

Correspondingly, the three uncertainties described below should not be thought of as additive to 

the range of costs shown in Exhibit 7-E, but rather clarifications indicating the extent to which 

these elements contribute to that range. Note that because a large portion of the cost variability 

shown in Exhibit 7-E pertains to the probabilistic likelihood of an unlined impoundment 

experiencing a groundwater contamination event in a given year; the probabilistic elements 

discussed below are of secondary concern to overall incremental costs relative to this 

consideration.

Specifically, the variability of the three probabilistic elements below adds an uncertainty range of 

approximately -17% to +10%. As shown above, the overall range of total incremental costs 

between the lower and upper bounds of potential costs is approximately a range of -61% to 

+79%. Correspondingly, the variation resulting from the incidence of groundwater contamination 

events at unlined impoundments can be thought to be responsible for an uncertainty range of -

44% to +69%, with the other three cost elements contributing the remainder of the overall 

uncertainty. Note that these calculations are not exact, as the interrelationships between multiple 

uncertain parameters in a probabilistic analysis may result in nonlinearities that do not reflect 

linear characterizations of ranges of uncertainty.

Impoundments of Unknown Liner Type

As indicated in Chapters 3 and 4, a number of surface impoundments are currently of unknown 

liner status. For these impoundments, this RIA probabilistically assigns either a lined or an 

unlined status, based on the overall distribution of lined and unlined impoundments among all 

impoundments with known liner status. This section performs a bounding analysis by examining 

the cost impact with assuming that each of these impoundments is lined, and also with assuming 
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that each of these impoundments is unlined. Exhibit 7-F below indicates the range of cost 

impacts stemming from these assumptions.

Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

Exhibit 7-F

Uncertainty associated with Liner Status for Impoundments with Unknown Liner Status

Incremental Annualized Costs for Surface Impoundments at 7% Discount Rate (millions of 2013$)

Category Central Estimate

Low-Cost Assumption

Unknown Liner = Lined

High-Cost Assumption

Unknown Liner = Unlined

Disposal Impoundments $215 $175 $234

Storage Impoundments $393 $325 $425

Total Costs $739 $631 $790

In total, changing the assumptions associated with the 250 impoundments with unknown liner 

status results in cost impacts of -19% to 9% for disposal impoundments and -17% to 8% for 

storage impoundments. In terms of impacts to overall compliance costs associated with the rule, 

the lower bound of assuming each of these 250 impoundments is sufficiently lined leads to 

totalincremental costs of $631 million annually, or a reduction of approximately 15%; on the 

other hand, the upper bound of assuming each of the 250 impoundments lacks a sufficient liner 

leads to total incremental costs of $790 million annually, or an increase of approximately 7% 

over the central estimate.

355

Demonstrations for Location Restrictions

As described in Chapters 3 and 4, this RIA uses a simplifying assumption that CCR 

management units subject to location restrictions related to karst, flood plains, and seismic zones

have a 50% chance of sufficiently demonstrating and avoiding having to switch to off-site 

disposal when subject to a location restriction, and a 50% chance of failing to sufficiently 

demonstrate and thus being forced to switch to off-site disposal instead. This section examines 

the impact of this simplifying assumption via a bounding analysis by considering the impact on 

total costs if all CCR management units subject to location restrictions either sufficiently 

demonstrated or failed to do so, and switched to offsite disposal. Exhibit 7-G contains the results 

of these two bounding analyses.

 

355 For the purposes of creating an apples-to-apples comparison, the figures in Exhibit 7-F reflect the minimum and maximum 

cost estimates under a central estimate (expected value) regime. Note that the variability inherent in the probability of each 

impoundment of unknown liner status being unlined or sufficiently lined is already accounted for in the minimum and maximum 

cost estimates presented in Exhibit 7-E; the uncertainty associated with this assumption and characterized in Exhibit 7-F reflects 

a part of the broader probabilistic variability shown in Exhibit 7-E.
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Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

Exhibit 7-G

Uncertainty associated with Successful Demonstrations for Location Restrictions

Incremental Annualized Costs for CCR Disposal Units at 7% Discount Rate (millions of 2013$)

Category

Central 

Estimate

Low-Cost Assumption

Always Demonstrate Successfully

High-Cost Assumption

Never Demonstrate Successfully

Landfills $103 $103 $112

Disposal Impoundments $215 $202 $227

Total Costs $739 $727 $760

Note: This RIA does not evaluate storage impoundments as currently subject to location restrictions because they 

are not management units serving as final disposition places of CCR.

In general, costs associated with these bounding analyses do not vary substantially from the 

central estimate, because relatively few disposal units are affected by location restrictions. 

Furthermore, a substantial proportion of location restrictions apply only to new units, rather than 

existing units (only the unstable areas restriction applies to existing units as well as new units), 

meaning that any cost impacts associated with location restrictions are heavily discounted. 

Overall, the assumptions regarding the successful demonstration for CCR management units 

subject to location restrictions, or lack thereof, can result in a cost decrease relative to the central 

estimate of up to 2%, and a cost increase relative to the central estimate of up to 3%. 

Impoundment Size for Structural Integrity Inspections

As described in Section 4.3.10, this RIA classifies all disposal and storage impoundments as 

either subject to “more stringent” structural integrity inspections (i.e., larger surface 

impoundments) or “less stringent” structural integrity inspections (i.e., smaller surface 

impoundments). However, for 70 of the 735 surface impoundments examined in this RIA, 

sufficient dimension data were not available to classify the impoundment as definitively subject 

to either the “more stringent” or “less stringent” inspection variant. In its primary analysis, this 

RIA probabilistically assigns each of these 70 impoundments to one category or the other: a 70% 

chance of being subject to “more stringent” inspections and a 30% chance of being subject to 

“less stringent” inspections, based on the breakdown of the remaining 665 impoundments whose 

dimensions are sufficiently known to allow for direct categorization.

To examine the impact of this probabilistic assignment, this RIA conducted sensitivity analyses 

involving running the cost estimation model twice: once to assign each of these 70 

impoundments to the “more stringent” category, and again to assign them to the “less stringent” 

category. Exhibit 7-H below characterizes the results of these analyses.
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Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

Exhibit 7-H

Uncertainty associated with Structural Integrity Inspection Costs for Impoundments of Unknown Dimensionality

Incremental Annualized Costs for Structural Integrity Inspections at 7% Discount Rate (millions of 2013$)

Category Central Estimate

Minimum Cost Estimate

(all unknown = less stringent)

Maximum Cost Estimate

(all unknown = more stringent)

Disposal Impoundments $3.30 $2.41 $3.39

Storage Impoundments $10.1 $9.06 $9.93

Subtotal Costs –

Structural Integrity 

Inspections

$13.4 $11.5 $13.3

Total Costs $739 $737 $739

In general, the variability associated with this probabilistic elemental is quite small: the 

minimum cost associated with structural integrity inspections represents a decrease in the cost 

associated with the requirement by approximately 14%, while the maximum cost is essentially 

the same asthe central estimate. Overall, this probabilistic element has a minimal impact (less 

than half of 1%) on overall compliance costs associated with the rule.

One noteworthy aspect is that the maximum cost estimate actually represents a decrease in the 

overall costs associated with storage impoundments, and as a result, a slight decrease with 

overall inspection costs associated with the rule. This occurs because the model assigns different 

costs for the “first” CCR impoundment subject to “more stringent” inspections at a given 

facilityelectricity plant: with assignment of additional impoundments as subject to “more 

stringent” inspections, it is possible that a previously unknown disposal impoundment is 

definitively assigned as subject to “more stringent” inspections under this scenario, thus reducing 

the costs associated with a storage impoundment previously considered the “first” impoundment 

subject to “more stringent” inspections at the plant. In addition, “first” disposal impoundments 

now subject to “more stringent” inspections may be marginally more likely to switch to a nonimpoundment CCR management option as a result of the slightly higher costs. At the margin, 

this increased cost may drive the decision to switch to a non-impoundment CCR management 

option, although this is unlikely. These two factors, in combination, result in the maximum cost 

estimate shown in Exhibit 7-H to be slightly lower than the central estimate for structural 

integrity inspection costs.356

 

356 In fact, the combination of these factors, as evidenced by the “maximum cost estimate” for this bounding analysis exceeding 

the central estimate, actually results in a number of cases where the increased cost, at the margin, for a disposal impoundment 

now considered subject to the “more stringent” inspections to the point where they opt for a non-impoundment CCR management 

option, thus resulting in an overall slight cost decrease under this option. Correspondingly, the highest-cost option by varying this 

parameter of uncertainty likely rests at an equilibrium point where enough impoundments of unknown dimensions are considered 

large and hence more subject to stringent inspections to increase costs, but not enough to push the subset of units that would 

choose a non-impoundment method of CCR management into these decisions that end up lowering the overall structural integrity 

inspection cost.
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Uncertainty in Overall Cost Estimates

Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

Exhibit 7-I

Cumulative Probability Functions of Total Post-Rule Costs

Present Values at 7% Discount Rate (2013$)

The previous discussions analyzed the implications of uncertainty in specific parameters. Here, 

this analysis bounds the overall uncertainty associated with total cost estimates presented in this 

RIA. This analysis is similar to those described in Chapter 4.

As indicated by the curve above, total post-rule costs feature a minimum of roughly $50.9 billion 

in present value terms, and a maximum of roughly $54.3 billion in present value terms, with the 

variability occurring between these two endpoints. An analysis of the concavity of the 

cumulative probability function in Exhibit 7-I indicates that the majority of costs occur between 

the 30th and 80th percentiles: these are the approximate points between which the costs are 

smoothest (i.e., percentile-to-percentile changes in costs are smallest and steadiest within this 

range). Correspondingly, according to the probabilistic weighting analysis applied, the expected 

total post-rule costs are most commonly between $52.1 billion and $53.0 billion in present value 

terms. Given that baseline costs feature little variability, this translates to total incremental costs 

of between $9.36 billion and $10.3 billion in present value terms under a seven percent7%

discount rate, or total annualized costs between $656 million and $724 million. By adding in the 

combined total of approximately $58 million in recordkeeping and inactive impoundment costs, 

not included in the curve shown above, this yields a range between $714 million and $782 

million in annualized 2013$ at a seven percent7% discount discount rate. Exhibit 7-J

summarizes these bounds.
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Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

Exhibit 7-J

Summary of Likely Cost Range for Total Incremental Costs of CCR Final Rule

(millions of 2013$, annualized at 7% discount rate)

Category Percentile Total Post-Rule Cost Total Incremental Cost

Lower bound of likely cost range 30th $3,570 $714

Central estimate of total incremental costs 

(expected value) N/A $3,590 $738

Upper bound of likely cost range 80th $3,630 $782

Note: Likely cost range represents the range of costs in which total post-rule costs change least drastically (i.e., most 

smoothly) from percentile to percentile. That is, costs within the 30th to 80th percentile range represent less overall variability 

than costs between the minimum value and the 30th percentile, and the costs between the 80th percentile and the maximum 

value.

7.1.6 Capacity of Off-Site Commercial Industrial Landfills

In addition to the sensitivity analyses above, this RIA also examines the possibility of potential 

cost impacts associated with increases in off-site disposal of CCR as a result of the CCR final 

rule. This analysis, included as Appendix T, compares the future annual tonnages of CCR which 

may switch from on-site CCR management units (landfills and surface impoundments) to off-site 

landfill disposal to recent (2010) capacities of off-site commercial industrial landfills. Increases 

in off-site disposal tonnage modeled in this RIA do not appear to have substantial, immediate 

cost impacts on off-site disposal availability or cost, based on facilities’ disposal behavior as 

modeled in this RIA and the available off-site industrial landfill capacity as of 2010.

7.2 Key Benefit Uncertainties

This RIA identifies two key areas of uncertainty associated with the benefits analysis.

 Capacity factors for impoundment release volumes. Capacity factors describe the 

percent of the impoundment capacity equivalent to the volume of release material. 

Because several benefits categories are driven by the quantity of waste released (i.e., 

avoided costs are in terms of dollars per gallon) and capacity factor values are derived 

using a limited data set, Section 7.2.1 addresses the uncertainty surrounding this metric in 

a bounding analysis.

 Probability of release for impoundments. Some uncertainty, primarily resulting from 

data limitations, surrounds the analysis predicting impoundment probability of 

impoundment release. Section 7.2.2 examines alternative pre-rule and post-rule failure 

rates. This section then describes the impact of the selected release rates on benefits 

estimates.
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7.2.1 Bounding Analysis for Capacity Factors for Impoundment Release Volumes

Note: EPA has updated this section of the RIA; see Section 9.2.6 in Chapter 9 of this RIA for a 

description of the relevant modifications. Exhibits and figures in this section have not been 

updated to reflect the revisions described in Section 9.2.6 in Chapter 9 of this RIA.

As described in Chapter 5, capacity factors are derived using a limited set of historical data: a 

total of 18 release events as reported in the 2009 EPA-ORCR survey.

357 These capacity factors 

assign avoided spill volumes to impoundments as part of the impoundment releases benefits 

analysis. These values express a release volume as a percentage of the impoundment capacity. 

Available historical data were employed to calculate spill volumes as a percent of impoundment 

capacity. The resulting values were averaged as appropriate to determine a mean capacity factor 

for a specific type of release (wall breach or other) and a specific size impoundment (big or 

small). Capacity factors by each release scenario are presented in Exhibit 5-D in Chapter 5.

Because capacity factors for each spill type and each impoundment type rely on limited data, and 

because spill volumes directly drive the benefits of avoided spills, this RIA undertakes a 

bounding analysis to examine the impact of uncertainty related to this metric. Exhibit 7-K

presents the average capacity factors used in the benefits analysis and identifies bounding 

capacity factors, minimums and maximums, to support this sensitivity analysis. Exhibit 7-L

characterizes the results of these analyses. Capacity factors for the bounding analysis were 

derived from the historical dataset and represent the maximum or minimum capacity factor 

calculated for a particular spill type (i.e., a specific combination of impoundment type and 

release type).

Exhibit 7-K

Capacity Factors for Bounding Analysis

Impoundment 

Size Release Type Capacity Factor(Average)a

Capacity Factor

(Maximum)

Capacity Factor

(Minimum)

Big Wall Breach 27.42% 37.90% 22.18%

Other 2.65% 28.28% 0.00%

Small Other 0.41% 1.47% 0.00%

a The average capacity factors were used to generate the results presented in Chapter 5. The capacity 

factors for “other” release events decreases to 0.13% and 0.02% for big and small impoundments, 

respectively post-rule. For this sensitivity analysis, the RIA assumes pre- and post-rule capacity 

factors remain the same in the maximum and minimum scenarios.

Exhibit 7-L

Uncertainty associated with Capacity Factors

Avoided Impoundment Release Costs at 7% Discount Rate (Millions of 2013$)

Capacity Factor

(Average)

Capacity Factor

(Maximum)

Capacity Factor

(Minimum)

Present Value (millions) $2,962 $18,104 $1,036

Annualized $208 $1,269 $73

 

357 The 2009 survey questionnaire and the survey responses from electric utility plants are available on EPA-ORCRs website at 

http://www.epa.gov/waste/nonhaz/industrial/special/fossil/surveys/index.htm
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In total, changing the assumptions associated with the capacity factors results in avoided release

costs of 511% to -65%. In terms of the total impoundment release costs avoided from this rule, 

the lower bound assumptions regarding capacity factors leads to total incremental avoided costs 

of $73 million annually (at a 7% discount rate), on the other hand, the upper bound assumption

leads to total incremental benefits of $1,269 million annually, compared to the base case estimate 

of $208 million annually. 

7.2.2 Probability of Release for Impoundments

Note: EPA has updated this section of the RIA; see Section 9.2.6 in Chapter 9 of this RIA for a 

description of the relevant modifications. Exhibits and figures in this section have not been 

updated to reflect the revisions described in Section 9.2.6 in Chapter 9 of this RIA.

In this section, the RIA discusses alternative probabilities of impoundment release, which is a 

key driver of benefits. Appendix R outlines the calculations undertaken to derive release

probabilities using survey data collected from power plant companies for the ten year period 

1999-2008.358 Limitations with this approach are described in Section 5.1.2, but the Base Case 

used in the analysis in Chapter 5 was designed as a conservative proxy to ensure that the 

residual release rate captures releases resulting from compliance failure, human error, and natural 

disasters. To examine the impact of this selection, this sensitivity analysis examines two 

alternative scenarios: an aggressive, or high-end, case and a middle case. These two alternatives 

reflect the fact that the RIA base case may underestimate risk due to the uncertainties 

surrounding human error and natural disaster hazards. Exhibit 7-M compares the pre-rule and 

post-rule release probabilities from this RIA analysis with the two proposed sensitivity scenarios.

Exhibit 7-N characterizes the results of these analyses.

Exhibit 7-M

Alternative Probability of Releasea Scenarios for Sensitivity Analysis

Scenario Pre-Rule Post-Rule

RIA Analysis Base Casea 0.09% 0.034%

Aggressive Case 0.13% 0.0625%

Middle Case 0.1075% 0.04%

a Probabilities of release are presented here for large impoundment wall breach events only as 

it is this change that drives the benefits of the CCR final rule. Post-rule release rates for 

“other” release types are held constant between the sensitivity scenarios ( i.e., the decrease to 

0.11% and 0.21% for large and small active impoundments, respectively occurs in all 

scenarios).

b The RIA Analysis Base Case scenario refers to the release probabilities applied to derive the 

results presented in Chapter 5.

Exhibit 7-N

Uncertainty associated with Probability of Release for Impoundments

Avoided Impoundment Release Costs at 7% Discount Rate (2013$)

Base Case Aggressive Case Middle Case

Present Value (millions) $2,962 $3,332 $3,221

Annualized $208 $234 $226

 

358 As noted in Chapter 5 and Appendix P, the survey data also includes two reported releases from years before the start of the 

survey time frame: one in 1995 and one in 1998. These failure events are included in the probability calculations, making 

necessary adjustments to appropriately calculate per year release probabilities.
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In total, changing the assumptions associated with the probability of release results in avoided 

release costs of 12% to 9%. In terms of the total impoundment release costs avoided from this 

rule, the aggressive case assumption regarding the probability of impoundment release leads to 

total incremental avoided costs of $234 million annually (at a 7% discount rate), on the other 

hand, the middle case assumption leads to total incremental benefits of $226 million annually, 

compared to the base case estimate of $208 annually. 

7.3 General Uncertainties: Compliance and Cost Data Limitations

7.3.1 Impact of Compliance Assumptions on Costs and Benefits

EPA’s RIA for the June 2010 proposed CCR rule evaluated the two co-proposed regulatory 

options (i.e., Subtitle C “special waste” option and Subtitle D “non-hazardous waste” option), 

and the alternative “D Prime” regulatory approached considered for public comment. For the 

Subtitle C option, the 2010 RIA assumed 100% nationwide implementation of that option (i.e., 

100% industry compliance), because RCRA Subtitle C hazardous waste regulations establish 

federally-enforceable national standards.359,360

However, the 2010 RIA examined alternative, lower compliance rate assumptions for the 

Subtitle D option and the D Prime regulatory approach, to reflect the fact that EPA’s statutory 

authority under RCRA Subtitle D is limited to providing solid waste management financial 

assistance to state and local governments, establishing waste management guidelines and 

technical criteria to be implemented by state government regulations, and enforcement through 

citizen law suits rather than EPA enforcement.361

To simulate the possibility of less than 100% nationwide implementation (i.e., less than 100% 

industry compliance) under the June 2010 proposed Subtitle D option and D Prime approach, the 

2010 RIA applied numerical scaling factors in the range of 40% to 48% for the Subtitle D option, 

and in the range of 16% to 48% for the D Prime approach. The 2010 RIA applied these scaling 

 

359 Additional information about RCRA enforcement --- including RCRA enforcement programs, enforcement initiatives, 

enforceable requirements, enforcement process, enforcement authorities, enforcement cases and settlements, enforcement legal 

decisions, and enforcement policy and guidance --- is available at http://www.epa.gov/compliance/civil/rcra/index.html

360 “[W] whenever on the basis of any information the Administrator determines that any person has violated or is in violation of

any requirement of this subchapter [i.e., RCRA Subtitle C], the [EPA] Administrator may issue an order assessing a civil penalty 

for any past or current violation, requiring compliance immediately or within a specified time period, or both, or the [EPA] 

Administrator may commence a civil action in the United States district court in the district in which the violation occurred for 

appropriate relief, including a temporary or permanent injunction.” (Source: Section 3008(a) of RCRA Subtitle C.) RCRA 

Subtitle C Section 3008 is codified in Federal law under “SUBCHAPTER III—HAZARDOUS WASTE MANAGEMENT (§§ 

6921–6939f)” at http://www.law.cornell.edu/uscode/text/42/chapter-82

361 “[A]ny person may commence a civil action on his own behalf— (1) (A) against any person (including (a) the United States, 

and (b) any other governmental instrumentality or agency, to the extent permitted by the eleventh amendment to the Constitution) 

who is alleged to be in violation of any permit, standard, regulation, condition, requirement, prohibition, or order which has 

become effective pursuant to this chapter [i.e. RCRA Subtitle D]; or (B) against any person, including the United States and any 

other governmental instrumentality or agency, to the extent permitted by the eleventh amendment to the Constitution, and 

including any past or present generator, past or present transporter, or past or present owner or operator of a treatment, 

storage, or disposal facility, who has contributed or who is contributing to the past or present handling, storage, treatment, 

transportation, or disposal of any solid or hazardous waste which may present an imminent and substantial endangerment to 

health or the environment;” (Source: Section 7002 (a) of the RCRA statute.) Section 7002 citizen suit enforceability for RCRA 

Subtitle D is codified in Federal law under “SUBCHAPTER VII—MISCELLANEOUS PROVISIONS (§§ 6971–6979b)” at 

http://www.law.cornell.edu/uscode/text/42/chapter-82
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factors in relation to the dollar value of the cost and benefit elements estimated for the 100% full 

implementation Subtitle C option.

This RIA takes a different approach. The cost and benefit estimates (Chapters 4 and 5) in this 

RIA assume 100% nationwide implementation equally for the CCR final rule. For purpose of 

illustrating the potential reduction in costs and benefits under less-than-full implementation, 

Exhibit 7-O below displays the benefits and costs under two alternative lower implementation 

assumptions of 50% and 75% for the final CCR rule. The lower benefit and cost estimates 

displayed in the exhibit are formulated by multiplying the 100% compliance values (i.e., costs 

and benefits) by each alternative compliance assumption percentage. This calculation assumes 

that the impacts of non-compliance are uniform across all regulatory requirements.

However, differing compliance with different CCR pollution control requirements (e.g., 

groundwater monitoring, CCR landfill and/or CCR impoundment liners and leachate collection 

systems, CCR impoundment annual structural integrity evaluations) might differentially affect 

costs and benefits. For example, the largest benefit category estimated under all options is 

preventionis reduction of future impoundment releases, which is attributed to the relatively low 

cost pollution control requirement of annual impoundment structural integrity evaluations. Thus, 

50% or 75% lower compliance with the other pollution control requirements but 100% 

compliance with this one requirement (i.e., integrity evaluations) would only reduce benefits by a 

small fraction, not by 50% or 75%. In the absence of data suggesting different compliance rates 

for different requirements under the rule, however, this RIA employs a linear adjustment to 

approximate impacts. Uncertainty in compliance modeled this way will not change the sign of 

net benefits of any options, and the benefit-cost ratio of the rule is unaffected.

Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

Exhibit 7-O

Benefit and Cost Estimates Under Alternate Implementation (Compliance) Assumptions

(Present value, Billions of 2013$)

Alternative

Implementation 

Assumptions

Benefits

(Present Value)

Costs 

(Present Value) Net Benefits Benefit-cost Ratio

CCR final rule

100% $3.6 $11.9 -$8.3 0.30

75% $2.7 $8.9 -$6.2 0.30

50% $1.8 $5.9 -$4.1 0.30

All costs calculated with a 7% discount rate over 100-years 2013 to 2112 and presented in billions of dollars.

7.3.2 Analysis of Lower Implementation due to State Government Waivers

The third lower nationwide implementation scenario of this RIA is based on actual data 

concerning state government implementation of current (baseline) state regulations for CCR 

management. Based on the results displayed in Exhibit 7-P below from a 2006 joint DOE/EPA 

study of 85 CCR management regulatory permit variances granted between 1994-2004 in 16 

states for operation of new or expanded CCR landfills and CCR impoundments, 6 of the 16 

states (38%) have granted 30 waivers (aka exemptions) from 11 certain types of CCR 
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management regulatory requirements. Relative to the 2006 DOE/EPA survey sample size of 85 

state regulatory permit variance requests evaluated, 30 waivers granted represent a 35% rate. The 

2006 DOE/EPA study (page 20) indicates the 16 states surveyed represented 71% survey 

coverage of the nationwide coal-fired electricity generation at the date of the analysis.

Exhibit 7-P

A Sample of States Which Have Granted Waivers Between 1994-2004

From Existing State Government Regulations of CCR Management

States granting 

waivers (of 16 states 

surveyed)

Count 

of 

waivers 

granted

Types and Counts of State Waivers Granted

A B C D E F G

Liners

Closure/ 

postclosureDust 

controls

Leachate 

collection

Location 

and presiting

Solid waste 

management 

plan

Other 

types of 

waivers (n 

= 5)*

1 GA 6 0 1 1 1 0 0 3

2 IN 3 0 0 3 0 0 0 0

3 MN 3 0 0 0 0 0 1 2

4 VA 4 0 0 0 0 1 0 3

5 WI 3 1 0 0 1 0 0 1

6 WV 11 2 0 4 0 2 0 3

Column total waivers = 30 3 1 8 2 3 1 12

% of total waivers = 100% 10% 3% 27% 7% 10% 3% 40%

% of 16 survey states 

granting waivers = 38% 13% 6% 19% 13% 13% 6% 31%

% of 85 state permits 

issued = 35% 4% 1% 9% 2% 4% 1% 14%

Notes:

Source: EPA-ORCR (Mark Eads, Economist) analysis of data provided in three tables from the joint DOE/EPA report “Coal 

Combustion Waste Management at Landfills and Surface Impoundments 1994-2004,” August 2006, report nr. DOE/PI-0004.

 Table J.1 Variance Requests by State and Category of Requirements: This table presents a matrix listing the 9 states (table 

rows) and 52 CCR management permit variance requests across 14 types (table columns) of CCR regulatory requirements 

(i.e., liners, groundwater monitoring, leachate collection, dust control, etc.), which the DOE/EPA study evaluated. According

to Table K.1 not all of the 47 state government CCR regulatory variances that were granted involved waivers (aka 

exemptions) but also involved granting alternative requirements rather than dropping (i.e., waiving or exempting) regulatory 

requirements.

 Table K.1 Variance Request Descriptions and Regulatory Summaries: This table indicates that 17 of the CCR regulatory 47 

variances request granted by the 9 states involved alternative requirements, and the remainder 30 of the of the 47 variances 

granted involved waivers/exemptions from certain types of CCR regulatory requirements (the 30 waivers are summarized 

above in this Exhibit).

 Table G.1 Permits Issued for Survey Units: This table identifies a total of 85 state government CCR disposal regulatory 

permits issued between 1994-2004 by the 16 states surveyed in the 2006 DOE/EPA study, for operation of 51 new or 

expanded CCR landfills and 34 new or expanded CCR impoundments. The data about variances in Table J.1 and Table K.1 

are based on this survey sample of 85 permits.

* Column G: The five other types of waivers from state CCR regulations involve waivers from: (1) groundwater protection 

standards, (2) CCR landfill methane gas monitoring, (3) CCR disposal unit daily cell height limits, (4) fire protection standards at 

CCR disposal units, and (5) directional and informational signs near CCR disposal units.

Because the 2006 DOE/EPA study concluded that state government regulators did not issue 

variances/waivers unless a sound scientific basis362 supported the variance/waiver, this RIA only 

 

362 The 2006 DOE/EPA study indicates that state government variances and waivers to state CCR regulations were generally 

granted by state regulators only for two reasons:

 When the underlying state regulation was developed for settings unlike those of CCR units (e.g., a municipal solid waste or 

commercial landfill where landfill methane gas or vectors (e.g., rats, birds) are issues), or

 When the CCR unit operator demonstrated that an alternative approach or material will achieve the same objective as 

intended by the state regulation.
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evaluates the potential reduction in regulatory compliance costs for the scenario in which states 

would also grant the same percentage and types of waivers. This RIA does not apply the waiver 

percentages to estimate corresponding reductions in benefits; this assumes that future state 

waivers in this scenario would also be scientifically-based and largely protective of human health 

and the environment. Exhibit 7-Q below displays the potential 2.6% reduction in the annualized 

cost estimates (@7% discount rate) from Chapter 4 of this RIA, according to the percentage of 

permits which received the six types of waivers overlapping with the CCR final rule pollution 

control requirements.

Note: This exhibit has not been updated to reflect the revisions described in Section 9.2, 9.3 

and 9.4 in Chapter 9 of this RIA. 

Exhibit 7-Q

Scenario 3: Reduction in CCR Final Rule Cost from State Government Waivers

Total Incremental Annualized Values at 7% Discount Rate (millions of 2013$)

CCR Pollution Control

Percentage cost reduction 

from state waivers*

Central Estimate

(Expected Value)

A. Unit-level pollution control costs*

1. Groundwater monitoring 0% $4.49

2. Bottom liners 4% $466

3. Leachate collection systems 2% $19.2

4. Dust controls 9% $4.32

5. Run-on/run-off controls 0% $22.8

6. Location restrictions 4% $22.4

7. Closure capping 1% $19.3

8. Post-closure monitoring 1% $0.0672

9. Structural integrity inspections 0% $13.4

B. Other costs

10. Corrective action 0% $23.7

11. Reporting and recordkeeping 1% $30.8

12. Conversion to dry handling 0% $62.9

13. Dewater and cap costs for inactive impoundments 0% $26.7

Subtotal – Total Incremental Industry Costs N/A $716

C. State Agency Burden Costs

14. Structural integrity inspections** 0% $0.267

15. Corrective action 0% $0.473

16. Reporting and recordkeeping 1% $0.616

Subtotal – State Agency Burden Costs N/A $1.36

Total Incremental Rule Costs N/A $717

* Note: Percentage reductions in this table based on the percentages displayed in the bottom row of 

columns A to F of Exhibit 7-N.
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7.4 Specific Data Uncertainty Factors in this RIA

This section identifies three specific examples of uncertainty factors related to the data used in 

this RIA. These factors, listed below, describe uncertainty in the data on the annual tonnage of 

CCR disposed. These data underlie both the regulatory cost estimates and some of the benefit 

estimates (i.e., the human health benefit and the beneficial use benefit).

1. CCR tonnage data definition: The baseline and regulatory cost estimates in this 

RIA are based on the annual CCR management tonnages reported by electric 

utility plants to the 2012 EIA-923 database. However, the CCR tonnage reporting 

section of the EIA-923 data reporting form (Schedule 8, Part A) does not provide 

data respondents with a definition for “tons” collected.363 Because there are three 

numerical definitions of “ton” commonly used in the U.S. (i.e., short-ton, 2,000 

pounds; long-ton, 2,200 pounds; and metric ton, 2,205 pounds), this factor 

potentially introduces a -10% to +10% uncertainty range. For purpose of 

consistency with most EPA RCRA program reports, this RIA interprets all 

reported CCR tons to be short-tons.364

2. CCR tonnage data sources: This RIA cites multiple published sources for CCR 

tonnage data.

i. For example, one source (ACAA365) provides an industry survey-based 

estimate of CCR generation by electric utility plants in 2012 of 109.8

million tons. This RIA estimates 120.4 million tons CCR generation in 

2012 based on data from the 2012 EIA-923 database for medium- and 

large-size plants (>100 megawatts (MW) nameplate capacity) plus 

supplemental estimates made in this RIA for small plants (<100 MW 

capacity). This inconsistency in data sources represents -9% to +10%

uncertainty (i.e., [(109.8 - 120.4) / (120.4) = -9%] to [(120.4 - 109.8) / 

(109.8) = +10%]).

ii. Furthermore, as noted in Exhibit 3-C, total CCR tons disposed in landfills 

amount to 37.9 million tons, but analysis of EIA data indicate that 41.7 

million tons of CCR are disposed into on-site landfills. This discrepancy 

occurs because this RIA identified 18 plants reporting on-site CCR 

disposal in landfills where no CCR landfills were previously identified. 

This discrepancy thus represents an additional 9% uncertainty with regard 

to the landfill disposal estimate, or another 3% uncertainty with regard to 

total CCR disposal figures.

3. Data years: Information and data used to evaluate and estimate the cost of 

baseline CCR disposal practices are from various sources published as far back as 

1996. Furthermore, this RIA takes unit costs for CCR pollution controls from 

 

363 Instructions to the 2009 EIA-923 data reporting questionnaire (46 pages) are available at 

http://www.eia.gov/cneaf/electricity/forms/eia923.pdf

364 One example of the standardized use of “short-tons” in EPA RCRA program reports is the RCRA Biennial Hazardous Waste 

Reports archived at http://www.epa.gov/waste/inforesources/data/biennialreport/index.htm

365 Source: American Coal Ash Association (ACAA) “2012 Coal Combustion Product (CCP) Production & Use Survey Report” 

at http://www.acaa-usa.org/Portals/9/Files/PDFs/revisedFINAL2012CCPSurveyReport.pdf
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data reported throughout the last decade (e.g., back to year 2000). This RIA 

updated historical data to 2013 price levels using various indexes, including some 

specific to a particular cost and others more general, such as the GDP Price 

Deflator. The uncertainty in the accuracy of pollution control costs introduced by 

use of historical data is not quantified.

7.5 Summary of Uncertainty Factors

This section presents an overview of the uncertainties discussed in this chapter. Exhibit 7-R

summarizes the uncertainties identified, their potential effects on cost or benefit conclusions, and 

the likely significance of the uncertainty on those conclusions. These uncertainty factors are not 

additive because in some cases they interact with one another (e.g., changes in the cost of wetdry conversions would likely change the cost-effectiveness of fuel substitution). To show these 

links, the table includes a column detailing which uncertainties are likely to affect or be affected 

by another.

Exhibit 7-R

Summary of 11 Sources of Uncertainty in this RIA

Assumption/Source Of 

Uncertainty

Direction of 

Potential Bias

Likely Significance With 

Respect To Estimated 

Impacts

Links to Other 

Uncertainties

Overall Probabilistic Uncertainties

1. Uncertainties related to 

probabilistic assumptions in 

model, including groundwater 

incident rates, liner types, location 

restrictions, and size relative to 

structural integrity inspections.

Unknown. May 

overstate or 

understate costs. 

Possibly major. Quantified 

in Chapter 4 and in Exhibit 

7-E. 

Range in Exhibit 7-E

captures all 

uncertainties associated 

with probabilistic 

modeling.

Cost Uncertainties

2. Financial hurdle for wet-dry 

conversion costs.

Unknown. May 

overstate or 

understate costs. 

Probably minor. Cost 

model calculations indicate 

that total costs will not 

change by more than 7% 

given removal of hurdle. 

Affects relative costs of 

all options, including 

fuel substitution.

3. Cost model does not include 

fuel-switching to natural gas or

other non-coal fuel as part of its 

decision logic.

May overstate

costs.

Unknown. Likely affects a 

limited number of plants, but 

cost savings and benefits 

could be significant.

Fewer coal plants 

would result in 

additional benefits.

4. Assumptions about quantity of 

waste managed in storage 

impoundments.

May overstate

costs.

Possibly major. Cost model 

suggests that total rule costs 

could decrease by over 30% 

depending on quantities.

No significant 

interactions.

5. RIA uses a one-way distance of 

25 miles to the nearest off-site 

landfill to estimate costs 

associated with off-site disposal

Unknown. May 

overstate or 

understate costs.

Probably minor. Cost 

model calculations also 

indicate that varying the oneway transport distance does 

not substantially affect costs.

Affects relative costs of 

all options, including 

fuel substitution.
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Exhibit 7-R

Summary of 11 Sources of Uncertainty in this RIA

Assumption/Source Of 

Uncertainty

Direction of 

Potential Bias

Likely Significance With 

Respect To Estimated 

Impacts

Links to Other 

Uncertainties

Benefit Uncertainties

6. Capacity factors reflect a small 

number of data points

Unknown. May 

overstate or 

understate benefits.

Possibly major. Avoided 

costs of impoundment 

releases account for the 

majority of estimated 

benefits. This assumption 

represents -85% to +295% 

uncertainty.

None.

7. Release probabilities reflect 

limited data, assumptions about 

baseline failures that may be 

conservative.

May understate

benefits.

Possibly major. Avoided 

costs of impoundment 

releases account for the 

majority of estimated 

benefits. This assumption 

represents +21% to +28% 

uncertainty.

Affects number of 

relesaes avoided and 

related benefits.

Compliance Assumptions

8. RIA assumes 100% industry 

compliance

May overstate both 

costs and benefits.

Unknown. Relies on level of 

voluntary compliance and 

state enforcement.

Affects all impacts.

Data Uncertainty Factors

9. Data sources do not provide a 

definition for “tons” collected in 

the data reporting form; RIA 

interprets as short-tons.

Unknown. May 

overstate or 

understate costs.

Probably minor. Represents 

-10% to +10% uncertainty. None.

10. Inconsistency in data sources 

on 2012 total CCR tonnage

generation (EIA vs ACAA)

Unknown. May 

overstate or 

understate costs.

Probably minor. Represents 

-10% to +10% uncertainty. None.

11. RIA updated historical data to 

2011 price levels using various 

indexes, including some specific 

to a particular cost and others 

more general.

Unknown. May 

overstate or 

understate costs.

Probably minor. In general, 

price levels do not vary 

substantially across indexes.

None.
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Chapter 8

Other Required Analyses

Note: EPA has updated the cost and benefit information that inform this chapter of the RIA; 

see Sections 2, 3, 4, and 9.7 in Chapter 9 for a description of the relevant modifications and 

the resultant recalculations for the CCR final rule updates to this chapter. Some sections in 

this chapter have not been directly updated because EPA confirmed that updating the 

analysis would not change the conclusions.

As required by applicable statutes and executive orders, this chapter presents other supplemental 

analyses for the CCR final rule. Specifically, the chapter considers potential impacts associated 

with the following issues:

 Electricity price and energy market impacts. EPA intends to assessd the 

potential for the rule to affect the price of electricity using the Integrated Planning 

Model (IPM).

 Impacts on small businesses and small governments. A regulatory flexibility 

screening analysis considers the potential for rule-related costs to have a 

significant impact on a substantial number of small business and governments.

 Impacts on minority and low-income populations. This RIA considers the 

potential for the rule to have disproportionate impacts on minority or low-income 

populations.

 Children’s health impacts. This RIA considers the potential for the rule to have 

a significant or disproportionate impact on the health of children.

 Federalism, unfunded mandates, and tribal impacts. This RIA considers the 

magnitude of rule costs to state, local, and tribal governments to assess its impacts 

on federalism or the potential for unfunded mandates.

8.1 Electricity Price and Energy Market Impacts

The 2001 Executive Order 13211, “Actions Concerning Regulations that Significantly Affect 

Energy Supply, Distribution, or Use,” requires federal agencies to evaluate and prepare a 

statement on any potential adverse effects of economically-significant rulemakings on energy 

supply, distribution or use, including shortfall in energy supply, energy price increases, and 

increased use of foreign energy supplies.

OMB’s July 13, 2001 Memorandum (M-01-27169) provides guidance for implementing this 

Executive Order and also identifies nine numerical indicators (thresholds) of potential adverse 

energy effects. Three are relevant for evaluation in this RIA: increases in the cost of energy 

production in excess of one percent, increases in the cost of energy distribution in excess of one 

percent, and other similarly adverse outcomes.
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To assess the impact of the final rule on electricity markets pursuant to the Executive Order and 

associated OMB guidance, EPA plans to performed a market analysis using the Integrated 

Planning Model (IPM). IPM is a linear programming model of U.S. electricity markets that uses 

optimization methods to identify the least-cost approach for power producers to meet electricity 

demand, subject to regulatory, transmission, and other constraints. For a given scenario, IPM 

simulates power sector decisions regarding investments in new capacity, plant retirements, 

environmental regulatory compliance (e.g., equipment retrofits) requirements and scenarios, and 

the dispatch of different types of plants (e.g., coal-fired plants versus natural gas combined cycle 

plants) to minimize electricity production costs. Outputs generated by the model include 

regional electricity prices, capacity by plant type, and generation by plant type. EPA plans to 

relyrelies upon the price outputs generated by IPM to gauge the impact of the final rule on 

electricity prices. IPM’s outputs related to generation by plant type may also affect the estimated 

costs of the rule. To the extent that the CCR final rule leads to substitution from coal-fired 

generation to other fuels, CCR generation will decline, potentially reducing the costs of 

complying with the CCR rule. Such a shift from coal to gas could also affect the estimated 

beneficial use impacts of the CCR rule. For further discussion of this analysis, see Appendix X.

8.2 Small Business Impact Analysis (RFA/SBREFA)

Note: EPA has updated this section of the RIA; see Sections 9.2.1 and 9.7 in Chapter 9 of this 

RIA for a description of the relevant modifications to this section. Exhibits and numbers 

contained in this section have not been updated to reflect the revisions described in Section 

9.2.1 with respect to the universe of plants affected by the CCR final rule, but the conclusions 

of the analysis are unaffected.

According to the requirements of the 1980 Regulatory Flexibility Act (RFA) as amended by the 

1996 Small Business Regulatory Enforcement Fairness Act (SBREFA), federal regulatory 

agencies are required to make initial determinations about whether proposed regulatory actions 

may have a “significant economic impact on a substantial number of small entities” (SISNOSE), 

through a Regulatory Flexibility Screening Analysis (RFSA). Small entities include small 

businesses, small organizations, and small governmental jurisdictions. This section of the RIA 

presents the methodology and findings for the RFSA conducted for the CCR rule.

Unless Agencies are able to certify that a particular regulatory action is not expected to have a 

SISNOSE, the RFA/SBREFA requires a formal analysis of the potential adverse economic 

impacts on small entities, completion of a Small Business Advocacy Review Panel (proposed 

rule stage), preparation of a Small Entity Compliance Guide (final rule stage), and Agency 

review of the rule within 10 years of promulgation.

The small business impact analysis of this RIA follows the four analytic steps described in 

EPA’s RFA/SBREFA analysis guidance.366 First, this RIA determined which small entities are 

subject to the rule’s requirements. Second, this RIA selected appropriate measures for 

 

366 EPA’s RFA/SBREFA guidance: “EPA’s Action Development Process: Final Guidance for EPA Rulewriters: Regulatory 

Flexibility Act as amended by the Small Business Regulatory Enforcement Fairness Act”, EPA Office of Policy, Economics and 

Innovation, Nov 2006, 105 pages: http://www.epa.gov/sbrefa/documents/rfaguidance11-00-06.pdf
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determining economic impacts on these small entities and estimated those impacts. Third, this 

RIA determined whether the rule may be certified as not having a SISNOSE. Finally, this RIA 

documented the screening analysis and included the appropriate RFA statements in the preamble. 

These steps are described in more detail below.

8.2.1 Identification of Small Entities

This RFA/SBREFA analysis addresses the affected coal-fired electric utility plants in NAICS 

code 221112. The cost analysis in this RIA assumes that the 478 plants in the universe will either 

upgrade their waste management units or pay current market rates for appropriate disposal. The 

analysis assumes that all commercial facilities would pass through any upgrade costs under the 

regulation to generators.367

This RIA applies size definitions for owner entities of electric utility plants consistent with 

EPA’s RFA/SBREFA guidance. Based on the U.S. Small Business size standard for NAICS 

code 221112 (fossil fuel electric utility plants), a small company is one with fewer than 750 

employees. Based on the RFA/SBREFA’s definition (5 U.S. Code section 601(5)), a small 

government jurisdiction is the government of a city, county, town, township, village, school 

district, or special district with population under 50,000. Appendix C of this RIA identifies the 

size of the owner (company or city government) for each electric utility plant as either “Small”

or “Non-small.”368

Based on the nameplate megawatt (MW) capacity for all electricity generating units (including 

those powered by non-coal fuels) from the 2009 DOE EIA-923 database, this RIA estimated 

annual megawatt-hours electricity generation capacity to further characterize these plants. To 

estimate generation capacity, the nameplate capacity was multiplified by 365 days per year and 

24 hours per day to calculate each owner entity’s annual electricity capacity. Exhibit 8-A below 

presents the resultant count and summary of the characteristics of the small electric utility 

entities as estimated in this RIA.

 

367 Not included in this analysis are offsite commercial landfills that currently receive and dispose CCR generated by electric 

utility plants. EPA’s RCRA statute only allows the Agency to collect information from RCRA-regulated hazardous waste 

management facilities (via the RCRA biennial report), not from solid waste facilities. EPA does not know the identity, company 

size, or other information about the offsite landfills currently used by the electric utility industry. However, the cost estimates 

developed for this RIA use commercial off-site tipping fees consistent with facilities that meet Subtitle D requirements.

368 Research conducted in 2011 found that some of the companies identified as small using the SBA size standard for NAICS 22 

and the utility code specification in the 2007 EIA 860 database to identify each corporate entity may be subsidiaries of a larger 

holding company (classified under a different NAICS) rather than a larger power company. In addition some of these power 

companies may have merged. For example, State Line is owned by Dominion Resources of Virginia, Northeastern Power is 

owned by Suez Energy North America, Inc. (SEGNA), Rio Bravo Poso and Rio Bravo Jasmin are owned by the North American 

Power Group, Ltd (NAPG), TES Filer City Station LP is owned by TONDU, Public Service Enterprise Group (PSEG) and 

Excelon are merged. This approach is conservative, as it likely overstates the number of small entities.
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Note: This exhibit has not been updated to reflect the revisions described in Section 9.2.1

with respect to the universe of plants affected by the CCR final rule.

Exhibit 8-A

Summary of Characteristics of Small Electric Utility Entities

Small Entity SubCategories

Coal-Fired 

Electric 

Utility 

Plants

Estimated 

Owner 

Entities

Estimated 

Annual 

Megawatt 

Hours for All 

Plants 

(2012)*

Estimated 

Annual 

Electricity Sales 

for All Plants, 

$M (2013)

Average 

Annual 

Electricity 

Sales Revenue 

per Entity, 

$M (2013)

Small County 1 1 0.16 $14.86 $14.86 

Small City 32 32 26.34 $2,233.12 $69.79 

Small Company 45 33 126.99 $10,949.05 $331.79 

Small Cooperative 20 15 99.23 $8,160.65 $544.04 

Summary

All small entities 98 81 252.73 $21,357.68 $263.68 

All non-small entities 380 161 3,038.58 $256,968.29 $1,596.08 

All entities 478 242 3,291.31 $278,325.96 $1,150.11 

Notes: 

* Annual electricity generation capacity based on all electric plants and types of electric generation units (e.g. coal-fired, 

oil-fired, hydropower, nuclear, wind, biomass, etc.) owned by these companies, not just coal-fired electricity generation 

capacity. 

8.2.2 Measures for Determining Economic Impacts on Small Entities 

According to EPA’s 2006 RFA/SBREFA small business impact analytic guidance, various tests 

can be used to determine whether small entities may be significantly impacted by a regulation. 

This RIA used a sales test, comparing small entities’ annual revenue to their compliance cost 

under the rule. To be consistent with operations and CCR tonnages used for the cost analysis, the 

small business analysis uses 2009 data. As detailed in Appendix C, for each small entity this 

RIA computed the respective sales revenue test percentages. 

To calculate the respective sales revenues for each entity, this RIA began with the average 

statewide retail price, then, because prices are reported in cents per kilowatt hour, multiplied it 

by 1,000 to convert it to megawatt hours.369 Each entity’s annual electricity generating capacity 

was then multiplied by the retail price to find the total revenue.370

 

369 Electricity price reflects the composite price charged to residential, commercial, industry and transportation sectors. DOE’s

Energy Information Administration (EIA) publishes state-by-state average retail electricity prices for four end-user sectors (i.e., 

residential, commercial, industrial, transportation) and on a composite basis at: 

http://www.eia.doe.gov/cneaf/electricity/epm/table5_6_a.html.

370 Annual million megawatt capacity data for each of the 478 electricity plants were retrieved from the EIA website (2012).
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Finally, this RIA multiplied the revenue estimate by the 86.1% average electric utility industry 

capacity utilization.371 The result was the annual revenue per small entity (see Exhibit 8-A).372

The complete data set for these calculations is presented in Appendix C.

8.2.3 Determination of SISNOSE

This RIA compared estimates of annualized regulatory compliance costs for each entity under 

the CCR rule to the respective annual revenues for each entity, and compared these compliance 

costs to annual revenues for each company against the following three impact thresholds (as 

defined in EPA’s 2006 RFA/SBREFA analytic guidance):

 Less than 1% of annual revenues

 Between 1% and 3% of annual revenues

 More than 3% of annual revenues

The cost used for each plant in this analysis reflects the central estimate (expected value) of the 

total incremental cost on an average annualized basis as presented in Exhibit 4-G. This estimate 

reflects the “most likely” level of average annualized compliance costs faced by entities owning 

coal-fired electric utility plants based on the various probabilistic components of the cost 

estimation model as described throughout Chapter 3 and Chapter 4 of this RIA.

Exhibit 8-B displays the numerical results of this analysis by entity size category and the 

suggested RFA/SBREFA impact interpretation according to the three thresholds. For none of the 

categories of small entities do costs exceed 3% of revenues, and for three of the four categories 

(cities, companies, cooperatives), costs do not exceed 1% of revenues. Furthermore, only 81

small entities are likely to be affected. Of these, only six small entities experience costs 

exceeding 1% of revenues, and only one experiences costs exceeding 3% of revenues. Appendix 

C provides more information regarding estimated impacts for particular entities. Therefore, this 

RIA concludes that the CCR rule will not have a SISNOSE.

 

371 This 1972-2103 average was reported in the April 16, 2014 Federal Reserve Statistical Release G.17 “Industrial Production 

and Capacity Utilization” data for Utilities Available online at http://www.federalreserve.gov/releases/g17/Current/default.htm.

372 The equation used for these calculations was: (ASP x 1,000) x (AEGC) x (CU) = annual sales or revenues per small entity ($).
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Exhibit 8-B

Summary of Regulatory Cost Estimates According to Electric Utility Plant Owner Entity Size/Type 

Categorya

Type of Entity Total Costs 

($M)

Total Revenue 

($M)

Cost as Percent of 

Revenue

SISNOSE 

Threshold

Small County $0.26 $14.86 1.72% < 3%

Small City $4.71 $2,233.12 0.21% < 1%

Small Company $26.26 $10,949.05 0.24% < 1%

Small Cooperative $30.25 $8,160.65 0.37% < 1%

Small Entites Total $61.49 $21,357.68 0.29% < 1%

Notes: 

a Cost figures are given in million 2013$ annualized at a 7% discount rate over 100-year period 2015 to 2114

8.2.4 Limitations of RFA/SBREFA Determination

Not included in the RFA/SBREFA analysis of this RIA are two factors unique to the electric 

utility industry which may reduce the small entity impacts associated with the regulation. First, 

according to the 2012 EIA-923 database on electric utility plants, a majority of the coal-fired 

electricity generation units at electric utility plants owned by small entities can switch to at least 

one of six other fuels, such as agricultural byproducts, distillate fuel oil, natural gas, petroleum 

coke, propane, and wood waste solids. The recent decline in natural gas prices is already having 

this impact, independent of the CCR rule (see Section 7.1.2 for additional discussion of this 

impact).373 The facilities may therefore have options to switch fuels to substitutes at a cost less 

than the full compliance costs. 

Second, the small business impact analysis in this RIA applies the full industry compliance cost 

for each plant to the revenue and sales tests. However, because consumer demand for electricity 

is highly price-inelastic, and because demand is projected to grow by around 9% by year 2025, 

electric utility plants may in some cases be able to pass-through much, if not all, of their 

regulatory costs.374 In some cases, this also depends on the regulatory framework and ratesetting 

(e.g., state government utility rate hike approvals). The next section evaluates the possibility of 

regulatory compliance cost pass-through.

8.2.4.1 Compliance Cost Pass-Through Analysis

Ability to Raise Electricity Prices

Traditionally, the electric utility industry has functioned as a regulated monopoly, providing 

essential electrical services under an exclusive franchise in exchange for having rates closely 

 

373 See “2 coal-burning plants to power down early” Chicago Tribune March 1, 2012; “Turning Away From Coal” Wall Street 

Journal; “Power Station’s Closing Could Create Problems” New York Times February 11, 2012.

374 Source: EIA AEO Forecastforecast at: http://www.eia.gov/forecasts/aeo/er/.

NOTE: EPA has updated this exhibit of the RIA; 

see Exhibit 9-V in Section 9.7 of this RIA for updated exhibits.

NOTE: EPA has updated this exhibit of the RIA; 

see Exhibit 9-V in Section 9.7 of this RIA for updated exhibits.
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regulated by state public utility commissions (PUCs) and the Federal Energy Regulatory 

Commission (FERC).375 FERC regulates rates charged for sales of bulk power between utilities, 

even within states, and regulates pricing and use of transmission for wheeling and asset transfers, 

including mergers. In most states, PUCs set allowable rates upon application by the utility, and 

by law the utility must recover its cost of service, which includes “prudently” incurred expenses 

and a “fair” return on equity.376 Therefore, it is relatively easy for utilities in regulated states to 

raise electricity prices.377 A 2008 analysis cited by EPA in the RIA for the 2010 proposed CCR 

rule identified eight rate increases covering seven individual states and the seven states served by 

the Tennessee Valley Authority; increases ranged from 6% to 37% and averaged 19%.378

Over the past 20 years, however, some state governments have deregulated their electric utility 

industries, thereby allowing multiple electric suppliers, not just a monopoly electricity supplier, 

to compete and set their own retail prices in those state markets. As of 2010, 16 states (including 

Washington, DC) had deregulated their electric utilities.379 While average prices rose 21% in 

regulated states from 2002 to 2006, prices increased 36% during the same period in deregulated 

states where rate caps expired, suggesting greater pricing flexibility in deregulated states.380

Therefore, utilities in both regulated and deregulated states may be able to pass-through at least 

some compliance costs by raising electricity prices.

Inelastic Demand for Electricity

At the wholesale level, as a result of technological and regulatory barriers, the majority of 

electricity pricing plans do not allow consumers to see and respond to the actual market value of 

their electricity consumption and conservation. At the retail level, consumer demand for 

electricity has been largely inelastic, with recent studies consistently finding income elasticities 

of 0 to -2 in both regulated and deregulated states.381 The lack of real time metering at the retail 

level means that consumers do not know how much they use or indeed how much electricity 

 

375 PUCs are sometimes referred to as “public service commissions” (PSCs).

376 “Electric Utility Regulation” by Robert J. Michaels in the Concise Encyclopedia of Economics. Available online at: 

http://www.econlib.org/library/Enc1/ElectricUtilityRegulation.html

377 Based on the electricity ratemaking process described by the Pennsylvania PUC as a case example, when an electric utility 

company seeks a price increase, it must file a request with the PUC showing the proposed new rates and effective date, and must 

prove that the increase is needed. The utility also must notify customers at least 60 days in advance. The notice must include the 

amount of the proposed rate increase, the proposed effective date, and how much more the ratepayer can expect to pay. The PUC 

evaluates each utility’s request for a rate increase based on those criteria. During the investigation, hearings are held before an 

Administrative Law Judge (ALJ) at which the evidence in support of the rate increase is examined and expert witnesses testify. In 

addition, consumers are offered an opportunity to voice their opinions and give testimony. Briefs may be submitted by the formal 

parties. A recommendation to the PUC is made by the ALJ. Finally, the matter is brought before the Commissioners for a vote 

and final decision. Together with the 60-day notice period, the rate increase process takes about nine months.

378 The Compete Coalition, 2008, “Recent Examples of Rate Increases in Vertically Integrated States” (Washington). Available 

online at: http://www.competecoalition.com/resources/recent-examples-rate-increases-vertically-integrated-states

379The most recent available data on deregulation from EIA is from 2010. EIA also notes that at that time, seven states (AR, AZ,

CA, MT, NM, NV, and VA) had formally considered deregulation but had suspended their discussions. United States Department 

of Energy, Energy Information Administration, 2010, “Status of Electric Restructuring by State” Available online at: 

http://www.eia.gov/cneaf/electricity/page/restructuring/restructure_elect.html

380 USA Today, 10 Aug 2007, “Shocking Electricity Prices Follow Deregulation.” Available online at: 

http://www.usatoday.com/money/industries/energy/2007-08-09-powerprices_n.htm

381 Nakajima and Himori, 2010. Change in consumer sensitivity to electricity prices in response to retail deregulation: a panel 

empirical analysis of the residential demand for electricity in the US. Energy Policy 38(5) 2470-2476.
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costs until after the fact. Thus, consumers cannot react to high prices easily by cutting 

consumption, and utilities will be able to pass through at least some cost increases.382

Cost Pass-Through Conclusion

Based on the ability of utilities in both regulated and unregulated states to raise prices, combined 

with the relatively inelastic consumer demand for electricity, this RIA concludes that it is likely 

that electric utility suppliers could pass-through some or all, of the future average annual 

regulatory compliance costs for the CCR rule estimated in this section. Therefore, a significant 

impact on small entities and non-small entities is unlikely to occur.

8.3 Demographic Analysis: Minority and Low-Income Population Statistics 

(Executive Order 12898)

Note: Figures and exhibits in this section have not been updated to reflect the revisions 

described in Section 9.2.1 with respect to the universe of plants affected by the CCR final 

rule. The conclusions of this analysis remain unchanged.

Executive Order 12898 (Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations) (59 FR 7629, Feb. 16, 1994) directs federal agencies, 

to the greatest extent practicable and permitted by law, to identify and address, as appropriate, 

disproportionately high and adverse human health or environmental effects of their programs, 

policies, and activities on minority populations and low-income populations in the United States.

The following sections address potential environmental justice (EJ) issues resulting from CCR 

disposal unit locations in the baseline and reductions in risk predicted as a result of the CCR rule. 

To examine whether CCR disposal units have a disproportionate impact on minority and lowincome populations, this RIA developed a geographic analysis of CCR disposal unit locations 

and their surrounding vicinities using population data from the 2000 United States Census, and 

the EPA risk assessment for the CCR rule. See Appendix X for a detailed explanation of the 

specific population, demographic, and locational data used by this section of the RIA.

8.3.1 Methodology

To evaluate the demographic characteristics of communities that may be affected by the CCR 

rule, this RIA conducts an assessment of populations comparing the demographic characteristics 

of populations surrounding CCR disposal units with broader population data. This analysis 

examines the demographic characteristics in the baseline for two geographic areas likely to be 

affected by groundwater and surface water releases, respectively:

1. One-mile radius from CCR disposal units (i.e., landfills & impoundments).

This RIA evaluates the demographic characteristics of populations within a one-

 

382 “Power Price Volatility and Risk Management: An Introduction”, Anne Ku, Sept 2000. Available online at: 

http://www.analyticalq.com/energy/volatility/default.htm
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mile radius of each CCR disposal unit. The one-mile radius approximates the 

population likely to be affected by groundwater releases from both landfills and 

impoundments.383

2. Watershed catchment areas downstream of surface impoundments.

Catchment areas in this context refer to the downstream area that receives surface 

water runoff and releases from CCR impoundments, and incurs risks from CCR 

impoundment discharges (e.g., unintentional overflows, structural failures, and 

intentional periodic discharges). Catchment areas are measured in terms of runoff 

travel time. This analysis considers populations in all catchments within 24 hours 

of downstream travel time from the plant under mean surface water flow 

conditions, to estimate populations potentially affected by impoundment failures. 

Unlike the one-mile radius used to approximate populations at risk from 

groundwater contamination, catchment areas do not include upstream populations, 

but typically encompass larger populations overall.

The two populations are not mutually exclusive, but are used to approximate populations 

affected by both groundwater and surface water releases.

Specifically, this RIA compares the baseline demographic characteristics of the potentially 

affected populations with average characteristics at the national and state levels. The remainder 

of this section examines the following EJ considerations:

 In the baseline, the characteristics of communities surrounding CCR disposal 

units, surface impoundments and catchment areas as compared to both state and 

national averages.

 Sensitivity of results to key assumptions. 

8.3.2 Baseline Demographic Analysis

8.3.2.1 National-level demographic comparison 

As described above, this RIA considers demographic characteristics for two geographic areas 

(i.e., one-mile radius and catchment areas surrounding surface impoundments) that are likely to 

be affected by groundwater and surface water releases, respectively.

 One-mile radius from CCR disposal units (i.e., landfills & impoundments). Of the 

288 coal-fired electric utility plants in the RIA universe that have CCR surface 

impoundments, population data within a one-mile radius of CCR disposal units were 

available for 270 plants. Total population within one mile of these units is 253,500 

people, of which 50,800, or 20.0%, belong to a minority group (Appendix U to this RIA 

presents one mile population data). In addition, 36,400, or 14.4%, live below the Federal 

 

383 For more information about the selection of a one-mile radius to approximate affected populations, see the 2009 

risk assessment conducted by RTI International.
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Poverty Level. Both of these proportions are roughly comparable with nationwide 

benchmarks.384 Nationally, 24.8% of the population belongs to a minority group, and 

11.3% of the population lives below the Federal Poverty Level.

 Watershed catchment areas downstream of surface impoundments. These results are 

similar when considering catchment zones (for which demographic data were available 

for disposal units at 277 of the 288 plants) instead of a one-mile radius. Catchment areas 

for these plants encompass approximately 4.9 million local inhabitants, of which 1.5 

million, or 31.1%, belong to a minority group (compared with 24.8% nationally) and 

897,200, or 18.8%, live below the Federal Poverty Level.385,386

This analysis also considers populations living near CCR landfills, which typically pose a lower 

overall human health risk than impoundments. In general, plants with existing, on-site surface 

impoundments tend to have on-site landfills as well: of 288 plants with surface impoundments, 

172 (60%) also have landfills. Furthermore, of the 242 plants with on-site landfills, only 70 

(29%) lack an on-site surface impoundment. Therefore, the populations surrounding landfills 

may not be considered additive to the population surrounding surface impoundments because 

many plants include both types of disposal units. Of the 242 plants in the RIA universe that have 

CCR landfills, population data were available for 226. Total population within one mile of these 

plants is 188,800 people, of which 27,300, or 14.5%, belong to a minority group. In addition, 

15,800, or 8.4%, live below the Federal Poverty Level. Both of these proportions fall below the 

comparable nationwide benchmarks of 24.8% minority populations and 11.3% living below the 

Federal Poverty Level.387 Therefore, although populations surrounding plants with surface 

impoundments appear to have percentages of minority and low-income residents roughly 

comparable to the nationwide average, populations surrounding plants with landfills do not.388

Because landfills are less likely than impoundments to experience surface water runoff and 

releases, catchment areas are not considered.

8.3.2.2 State-level Demographic Comparison 

This analysis also considers baseline demographics relative to state populations. Of the 270 

plants with surface impoundments and available population data within a one-mile radius, 63 

 

384 Of the 270 plants evaluated, 50 plants have minority populations that exceed the comparable nationwide benchmark; only 

seven of these plants have minority populations equal to 50% or more of the surrounding population. With respect to poverty 

levels, of the 270 plants evaluated, 112 plants have surrounding populations living below the Federal Poverty Level that exceeds 

the national benchmark; 32 of these plants have impoverished populations equal to 20% or more of the surrounding population.

385 Poverty estimates surrounding surface impoundments may overstate the total number of residents living below the Federal 

Poverty Level as a result of not excluding persons living in institutional group quarters, such as dormitories and military bases, 

where the poverty metric does not apply. Estimates surrounding landfills do exclude these persons.

386 Of the 277 plants evaluated, 74 plants have surrounding minority populations that exceed the national benchmark; 22 of these 

plants have minority populations equal to 50% or more of the surrounding population. With respect to poverty, of the 277 plants 

evaluated, 168 plants have surrounding populations living below the Federal Poverty Level that exceeds the national benchmark; 

52 of these plants have impoverished populations equal to 20% or more of the surrounding population.

387 Of the 242 plants evaluated, 38 plants have surrounding minority populations that exceed the national percentage; 14 of these 

plants have minority populations equal to 50% or more of the surrounding population. With respect to poverty, of the 242 plants 

evaluated, 78 plants have surrounding populations living below the Federal Poverty Level that exceed the national benchmark; 24 

of these plants have impoverished populations equal to 20% or more of the surrounding population.

388 This discrepancy may result from the exclusion of persons living in institutional group quarters from landfill data but not from 

surface impoundment data.
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plants have proportions of minority populations that exceed the comparable state-wide 

percentage of minority populations; for example, 10 of these plants exceed the comparable statewide percentage by more than 20 points. Additionally, 107 plants have proportions of residents 

living below the Federal Poverty Level that exceed the comparable state-wide percentage; for 

example, 18 of these plants exceed the comparable state-wide percentage by more than 20 

percentage points. Using catchment areas for impoundments instead, 106 of the 277 plants with 

surface impoundments for which catchment population data were available have proportions of 

minority populations exceeding that of the state in which the plant is located (e.g., 27 plants 

exceed the comparable state-wide percentage by more than 20 percentage points), and 168 plants 

have proportions of residents living below the Federal Poverty Level that exceed the comparable 

state-wide percentage (e.g.,15 plants exceed the comparable state-wide percentage by more than 

20 percentage points). Of the 226 plants with landfills and available population data, 49 plants 

have proportions of minority populations exceeding that of the state in which the plant is located. 

Additionally, 79 plants with CCR landfills have proportions of residents living below the Federal 

Poverty Level that exceeds the comparable state proportion.

Exhibits 8-C presents the results of this baseline analysis. Overall, it appears that minority and 

low-income populations around coal-fired electric utility plants appear in concentrations that are 

generally similar to, but higher than, national demographic distributions in the baseline. This 

suggests that minority and low-income populations may have slightly higher baseline risks.389

Because the CCR rule reduces risk, and because reductions in risk will occur largely within the

surface water catchment zones around and groundwater beneath coal-fired electric utility plants, 

the rule will not increase risks for minority or low-income populations. Depending on the 

distribution of facilities that close their impoundments as a result of the rule, however, the rule 

could either increase or decrease the disproportionate distribution of baseline risks. That is, 

although absolute risk will not increase for any population as a result of the CCR rule, the 

closure of certain impoundments could lead to an increase in the percentage of impoundments 

located near minority or low-income populations.

The closure of surface impoundments under the rule will affect human health and environmental 

risk through two distinct pathways (i.e., groundwater and surface water/structural failure), and 

represents the primary source of risk reduction under the rule. However, because the cost 

analysis relies on probability of releases in the future, combined with assumptions about average 

costs for compliance and wet-dry conversion, this RIA’s predictions of specific impoundment 

closure are uncertain. This analysis therefore cannot draw precise conclusions about the effect of 

the CCR rule on the distribution of risk across different demographic groups, but the anticipated 

closures and monitoring and management of CCR under the rule will reduce risk across the 

universe of facilities. Since the communities surrounding CCR units have similar or higher 

 

389 Additionally, of 3,253,500 people within one mile of the 288 plants with impoundments, approximately 1,800 people, or 

0.70%, belong to tribal populations. Of the 188,800 people within one mile of the 242 plants with landfills, approximately 1,256 

people, or 0.58%, belong to tribal populations. These percentages are slightly lower than the 0.90% of the population classified as 

Native American according to census data. However, at 32 of the plants with impoundments and 28 of the plants with landfills, 

the tribal population in the catchment zone is greater than or equal to 1% of the total population. Total populations within one 

mile of three plants include tribal populations in excess of 30%. In addition, tribal populations may include subsistence fishers. 

This distinct subpopulation could be expected to face higher risks than the recreational fishers for whom EPA present results. To 

the extent that the rule reduces releases into water bodies fished by this subpopulation, the rule would reduce this disparate 

impact. Appendix U to this RIA presents one-mile population data for CCR landfilla and impoundments..
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percentages of minority and low-income populations as compared to national averages, these 

populations will also see reductions in risk as a result of the rule. 

Note: This exhibit has not been updated to reflect the revisions described in Section 9.2.1

with respect to the universe of plants affected by the CCR final rule.

Exhibit 8-C

Baseline Demographic Analysis for Minority and Low-Income Populations

Geography Considered

Population Surrounding CCR Units National Population

Minority Population

Low-income 

Population

Minority 

Population

Low-income 

Population

National Baseline

Surface impoundment catchment 

areas

1.5 million

(31.1%)

897,200

(18.8%)

Surface impoundment one-mile radius 24.8% 11.3% 50,800

(20.0%)

36,400

(14.4%)

Landfill one-mile radius 27,300

(14.5%)

15,800

(8.4%)

Number and Percentage of Facilities Exceeding National Percentage

Surface impoundment catchment 

areas

74

(26.7%)

168

(60.6%)

Surface impoundment one-mile radius n/a n/a 50

(18.5%)

112

(41.5%)

Landfill one-mile radius 38

(16.8%)

78

(34.5%)

Number and Percentage of Facilities Exceeding State-wide Percentage

Surface impoundment catchment 

areas

106

(38.3%)

168

(60.6%)

Surface impoundment one-mile radius n/a n/a 63

(23.3%)

107

(39.6%)

Landfill one-mile radius 49

(21.7%)

79

(35.0%)

Additionally, while specific surface impoundment closures are uncertain, examination of the 

facilities currently with impoundments suggests that these plants have a similar distribution of 

minority and low-income populations as the plants without impoundments. Therefore, the 

distribution of risk across demographics is not likely to change significantly as a result of the 

rule. 

8.4 Child Population Statistics (Executive Order 13045)

Note: The figures and exhibits in this section have not been updated to reflect the revisions 

described in Section 9.2.1 with respect to the universe of plants affected by the CCR final rule. 

However, the policy conclusions of this analysis are unaffected by the change.

This RIA uses a geographic analysis of CCR disposal unit locations and their surrounding 

vicinities, using the same methodology as described in Section 8.3. This analysis finds that the 

population within one mile of utility plants does not include an increased frequency of children 

(i.e., residents under 18), compared with the national proportion of residents under 18. 
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The remainder of this section examines the following children’s health considerations:

 Existence of human health impacts of CCR disposal unit locations on children in 

the baseline;

 CCR rule induced impacts of CCR impoundment closures on children; and

 Sensitivity of analysis results to key assumptions. 

8.4.1 Baseline Demographic Analysis

To evaluate baseline risks to children, this analysis considers the one-mile radius around each 

unit.390 While catchment zones could also be used to identify the populations at risk of human 

health and environmental impacts associated with the CCR disposal units, catchment zones 

generally approximate the populations at risk of surface water releases. Using the one-mile 

radius is more consistent with the groundwater-based exposures to arsenic that might present a 

disproportionate risk to children.

Of the 288 coal-fired electric utility plants with existing on-site surfacing impoundments, onemile radius population data were available for 270. The radii for these 270 plants encompass 

approximately 253,500 people, of which 62,500, or 24.6%, are younger than 18 years of age

(Appendix U to this RIA presents one mile population data). This proportion slightly exceeds 

the national proportion of 24.0%. Of these 270 plants, 104 have proportions of children that 

exceed the national proportion. At the state level, 108 plants have proportions of children under 

18 that exceed the comparable state proportion. However, only 40 plants (or 14.8%) have 

proportions of children that exceed 30%, with the highest proportion of children being 46.2%. 

Thus, the majority of plants with impoundments that will be affected by the CCR rule are located 

in areas with proportions of children under 18 that are generally similar to the national average. 

The rule will reduce risk at these impoundments, and benefits are likely to accrue primarily to 

children within the areas immediately surrounding the coal-fired electric utility plants affected by 

the rule. The following section presents a screening analysis investigating the extent to which 

these risk reductions impact children. For more information on the health risks to children of 

exposure to CCR constituents of potential concern, please see the Human and Ecological Risk 

Assessment of Coal Combustion Wastes available in the docket for today’s action.

8.4.2 Evaluation of Impact of CCR Final Rule on Children’s Demographic

While the actual changes in facility operationutility plant operations, including CCR 

impoundment closures, predicted by the cost analysis of this RIA are uncertain, examination of 

the facilitiesplants with CCR surface impoundments suggests that these plants have a similar 

distribution of children as the rest of the universe. Therefore, the distribution of risk across the 

children’s demographic is not likely to change significantly as a result of the CCR final rule. 

 

390 Specifically, the analysis considers a one-mile radius from the centroid of the impoundment at each plant with the 

largest surrounding population. That is, the analysis compares the populations within one mile of each impoundment 

at a given plant, and selects the largest of those populations as the basis for these calculations.
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The percent of all plants with impoundments that exceed the national proportion of children is 

38.5% (104 of 270 plants for which population data are available), suggesting that reductions in 

risk at these plants would benefit children. Moreover, requirements under the rule will reduce 

risks at all plants. The CCR rule is therefore not expected to create additional or new risk to 

children.

Exhibit 8-D summarizes the results of this screening-level analysis.

Note: This exhibit has not been updated to reflect the revisions described in Section 9.2.1

with respect to the universe of plants affected by the CCR final rule.

Exhibit 8-D

Baseline Demographic Analysis for Children’s Health

Description

Population Surrounding 

CCR Units National Population

Population under 18 years of age 62,500

(24.6%) 24.0%

Number of facilities exceeding national 

percentage 104 n/a

Number of facilities exceeding state 

percentage 108 n/a

Percent of all plants with impoundments 

that exceed national percentage 38.5% n/a

Percent of all plants with impoundments 

that exceed state percentage 40.0% n/a

Note: Populations are presented for the one mile radius surrounding plants with surface impoundments.

8.5 Unfunded Mandate Reform Act (UMRA) and Federalism Implications 

Analysis (Executive Order 13132) 

Note: EPA has updated this section of the RIA; see Section 9.7.1 in Chapter 9 of this RIA for a 

description of the relevant modifications and updates to this section.

These threshold analyses evaluate the CCR rule impacts relative to requirements under the 

Unfunded Mandates Reform Act and Executive Order 13132, Federalism Implications Analysis.

8.5.1 Unfunded Mandate Reform Act (UMRA)

Among its other purposes and federal agency rulemaking requirements, the Unfunded Mandates 

Reform Act (UMRA) requires federal agencies, unless otherwise prohibited by law, to assess the 

effects of their regulatory actions on state, local, and tribal governments and on the private 

sector, to determine whether any proposed rulemaking may result in “any Federal mandate that 

may result in the expenditure by State, local, and tribal governments, in the aggregate, or by the 

private sector, of $100 million or more in any one year.”
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Section 202 of UMRA requires federal agencies that propose rules that are likely to exceed this 

expenditure threshold to prepare a “Written Statement” containing the following five 

components, supply the statement to OMB, and summarize it in the Federal Register notice for 

the CCR rule: 

1. Identification of the applicable authorizing federal law;

2. Qualitative and quantitative assessment of the anticipated costs and benefits of the 

rule including the costs and benefits to state, local, and tribal governments or the 

private sector, and an analysis of whether federal resources may be available to 

pay these costs;

3. Estimates of future compliance costs and any disproportionate budgetary effects;

4. Estimates of effects on the national economy such as productivity, economic 

growth, employment, job creation, international competitiveness; and

5. Description and summary of agency’s prior consultation with elected 

representatives of the affected state, local and tribal governments.

The private sector and the state/local/tribal government shares of direct compliance costs under 

each option are displayed in Exhibit 8-E. The final CCR rule is expected to result in average 

annual expenditures of $100 million or more in the aggregate for both the private sector and for 

state/local/tribal governments. As identified in Appendix C, there are 58 state and local 

government owner entities, and one federal owner entity, and no known tribal owner entities.

EPA has prepared an “UMRA Written Statement” regarding the private sector and state/local 

government test findings, which can be found in Appendix V.

8.5.2 Federalism (Executive Order 13132)

Note: EPA has updated this section of the RIA; see Section 9.7.1 in Chapter 9 of this RIA for a 

description of the relevant modifications and updates to this section.

The 1999 Federalism Executive Order 13132 furthers the policies of UMRA by establishing 

federalism principles, federalism policymaking criteria, and a state and local government 

consultation process for the development of federal regulations with implications for federalism. 

These include regulations and other federal policies and actions that have substantial direct 

effects on states, on the relationship between the federal government and the states, or on the 

distribution of power and responsibilities among the various levels of government.

For purpose of complying with the consultation process of Executive Order 13132, this section 

evaluates whether the CCR final rule may “impose substantial direct compliance costs” on state 

and local governments. As summarized in Exhibit 8-E, the rule might impose four types of 

direct costs on the plants owned by 58 state and local government entities.
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For state and local government owned electric utility plants:

1. Engineering control costs for CCR management units located at electric utility 

plants owned by state/local governments.

2. Additional costs for CCR management units located at electric utility plants 

owned by state/local governments.

3. Conversion to dry disposal costs for CCR disposal units located at electricity 

utility plants owned by state/local governments.

For state government environmental agencies:

4. Regulatory implementation, administration, and enforcement costs to RCRA 

authorized state government programs/agencies.

EPA’s 2008 guidance for compliance with Executive Order 13132 describes two numerical 

methods for evaluating whether an EPA rule may have federalism implications with respect to 

“substantial direct compliance costs”:391

1. The $25 million test. Annualized direct compliance cost expenditures to state and 

local governments in aggregate of $25 million or more.392

2. The 1% test. Annualized direct compliance costs faced by state and local 

governments are likely to equal or exceed 1% of their annual revenues.393

Based on estimated regulatory costs on state and local governments displayed in Appendix C of 

this RIA, Exhibit 8-E displays the results of the UMRA and Federalism threshold tests defined 

above. For the former, the results suggest that the rule is likely to exceed $100 million in direct 

costs to the private sector, but not to state and local governments. The results of the Federalism 

tests are inconclusive; while the direct compliance costs are likely to be well above $25 million, 

they do not exceed 1% of government electric utility sales.

 

391 The two methods are from “EPA’s Action Development Process -- Guidance on Executive Order 13132: Federalism,” OPEI 

Regulatory Development Series, Nov 2008, at http://intranet.epa.gov/adplibrary/documents/federalismguide11-00-08.pdf.

392 Although one of the stated purposes of EO 13132 in its first paragraph is “to further the policies of the 1995 Unfunded 

Mandates Reform Act (UMRA), EPA’s $25 million annual direct cost trigger is 75% lower than the $100 million annual direct 

cost trigger prescribed in Section 202 of UMRA.

393 “Attachment A: Guidance for Implementing the Federalism 1% Test” to EPA’s Nov 2008 “Guidance on Executive Order 

13132: Federalism” defines small government “general revenue” as “made up of intergovernmental revenue plus revenue from 

their own sources and excludes utility, liquor store and employee retirement revenue.” However, given that the CCR rule affects 

electric utility industry, this RIA applies the “1% Test” in relation to only state/local government electric utility annual revenue.
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Exhibit 8-E

UMRA and Federalism Tests for CCR Final Rule

Type of Direct Compliance Cost Average Annualized Cost 

(millions of 2013$)a

Average annualized cost per owner entity $3.05

UMRA Test 

Private sector $100 million direct cost threshold test $617.27

State/local government $100 million direct cost threshold testb $38.73

Federalism Test

$25 million threshold test: sub-total state/local government cost $38.73

1% Test: State/local government cost as percentage of state/local government 

electric utility annual revenues 0.16%

a Average annualized costs are calculated with a 7% discount rate over 100 years from 2015 to 2114.

b Remainder Federal government costs represent costs associated with Federally-owned electric utility plants (i.e., 

Tennessee Valley Authority) which are not subject to either the UMRA or Federalism tests. Therefore, the sub-total private 

sector direct cost plus the state/local government direct cost does not add-up to the total annual cost; the remainder cost is 

for the Federally-owned plants. 

However, as described in Section 8.1 and Section 8.2, it is likely that at least some of the direct 

compliance costs under each option may be passed-through to electricity plant customers in the 

form of higher electricity prices. Therefore, the costs estimated in Exhibit 8-E may overstate the 

actual cost burden to both private and public sector.

NOTE: EPA has updated this exhibit of the RIA; 

see Exhibit 9-U in Section 9.7 of this RIA for updated exhibits.

NOTE: EPA has updated this exhibit of the RIA; 

see Exhibit 9-U in Section 9.7 of this RIA for updated exhibits.
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Chapter 9

Updates to Assumptions, Data, and Rule Requirements: Final Cost 

and Benefit Estimates for the CCR Final Rule

This chapter presents final estimates of incremental costs and benefits for EPA’s CCR final rule. 

It incorporates information that became available near the end of or after production of the 

previous chapters of the RIA and includes updates to both (a) assumptions and data and (b) CCR 

final rule requirements. The updates are described in detail, and re-estimated costs and benefits 

are presented. EPA’s court-ordered deadline for the CCR final rule precluded revising the entire 

RIA and its Appendices (which are over 700 pages). Except for the modifications specifically 

described in this chapter (and their associated results), the data, assumptions, and methods 

described in the RIA remain accurate.

This chapter also presents sensitivity analyses related to the updated assumptions. Sensitivity of 

the benefit and cost estimates to assumptions about the number of plants closing coal-fired 

boilers before and after the rule takes effect is analyzed under a number of alternative 

assumptions.

This chapter concludes by updating four supplemental analyses in Chapter 8 of the RIA, 

specifically the Federalism analysis, the small business impacts analysis, the demographic 

analysis of low-income and minority populations, and the demographic analysis of child 

populations. The chapter closes with state-by-state incremental costs and benefits of the CCR 

final rule.

9.1 Overview of Modifications to the RIA

Specifically, this chapter describes nine (9) updates to the cost and benefit modeling for the RIA. 

The sub-set of seven modifications listed below involve refinements to assumptions or data, and 

do not otherwise involve changes to the methodology or modeling approach described in prior 

chapters of this RIA:

1. Affected universe: An update to the universe of coal-fired electric utility plants affected 

by the CCR final rule to account for plants identified as already retired or planning to 

retire in the National Electric Energy Data System (NEEDS) v.5.13 dataset.

2. Future annual change in coal consumption: Adoption of EPA’s power sector modeling 

platform v.5.13 (developed for application of the Integrated Planning Model (IPM)) as 

the Base Case projection of future 20142015-2050 coal consumption for electricity 

generation for future estimates of CCR tonnage generation over time, replacing the 

Energy Information Administration (EIA) 2014 Annual Energy Outlook (AEO) 

Reference caseCase forecast described in Chapter 2.

3. Scaling factor for CCR quantities managed in storage impoundments: A revision to the 

estimated tonnage of CCR managed in storage (dredged) impoundments, reflecting 
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updated information from EPA’s Office of Water RIA for its Steam Electric Power 

Generation Effluent Limitation Guidelines (SPGELG) June 2013 proposed rule about the 

distribution of CCR impoundments receiving and treating different types of coal ash.

4. CCR beneficial use: An adjustment to the CCR beneficial use impacts to reflect the 

changes in annual CCR disposal tonnage associated with the revisions to the universe of 

coal-fired electric utility plants. In addition, this chapter updates the CCR beneficial use 

impacts associated with reductions in the use of virgin materials by updating the per-ton 

benefits related to health impacts avoided per ton of avoided criteria pollutant emission. 

5. Harmonization of benefits with EPA-OW’s RIA for the 2013 SPGELG proposed rule: A 

revision to the adjustment factors used to scale and harmonize the common subset of 

environmental benefits (pertaining to surface water) from the EPA Office of Water’s RIA 

for the June 2013 SPGELG proposed rule to estimate common benefits for the CCR final 

rule.

6. CCR impoundment releases: Revisions to some pre-rule and post-rule probabilities 

assigned to future CCR impoundment releases and to environmental release capacity 

factors.

7. Social cost of carbon: Adoption of the Federal interagency November 2013 revised social 

cost of carbon (SCC) applied to the CCR beneficial use benefit monetization, in place of 

the May 2013 version of the SCC applied in Chapter 5.

In addition to the seven modifications outlined above, this chapter addresses substantive changes 

in the CCR final rule which provide two compliance alternative closure requirements for certain 

subsets of electric utility plants with leaking unlined CCR impoundments. These two alternative 

closure requirements require modifications to the decision logic of the cost estimation model 

(and related benefits estimates) to reflect two different business decision options available to

eligible electric utility plants.394 The alternative closure requirements apply both to landfills and 

surface impoundments that do not meet location standards specified in the rule and to leaking 

unlined impoundments which exceed groundwater MCLs.Although the alternative closure 

requirements apply to different subsets of electric utility plants, both alternative closure 

requirements apply only to plants with leaking unlined CCR impoundments that exceed 

groundwater chemical contamination maximum concentration limits (MCL) standards, as well as 

plants with units that do nto comply with the location restrictions and/or factors of safety:

395

8. Alternative Closure Requirement #1: For plants that certify no alternative CCR disposal 

capacity, an extension of time to initiate closure to find or develop alternative disposal 

capacity, not to exceed 5 years from the initial certification. 10-year extension (2028) for 

initiating closure for leaking, unlined CCR impoundments, thereby delaying the date

when closure costs begin compared to the 2019 date applied in the RIA (i.e., this chapter 

 

394 Otherwise, the CCR final rule continues to represent the same “modified D prime” approach evaluated in the RIA.

395 EPA did not have the basis to estimate the number of plants that would not meet the location restrictions or factors of safety 

criteria. However, EPA expects that it would be a small number.
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shifts 10 years out to 2028 the leaking unlined impoundment closure costs estimated in 

the RIA for this sub-set of eligible plants).

8.

9. Alternative Closure Requirement #2: For plants that certify plans to permanently

cessation cease operation of a coal-fired boiler(s) by a date uncertain, an extension of 

time for completing closure for landfills and surface impoundments that do not meet the 

location restrictions in the rule and for leaking, unlined surface impoundments. 5-year 

extension (2023) for initiating closure for leaking, unlined CCR impoundments, thereby 

delaying the date when closure costs begin compared to the 2019 date applied in the RIA. 

Due to uncertainty regarding the universe of plants which may choose to cease operating 

when faced with the CCR final rule and avail themselves of this alternative closure 

requirement, this chapter presents the impact of this alternative closure requirement only 

as a sensitivity analysis, rather than including potential impacts in its primary estimates.

9.2 Seven Technical Revisions to Assumptions and Data Applied in Other 

Chapters of the RIA

This section briefly describes updates to the data and assumptions used in the other chapters of 

this RIA. The updated data and assumptions are used to re-estimate benefits and costs in this 

chapter. 

9.2.1 Revision to the Universe of Plants Affected by the CCR Final Rule

To ensure consistency between the CCR final rule cost and benefit analysis and the IPM v. 5.13 

Base Case projection of coal consumption for electricity generation, this chapter updates the 

affected universe of coal-fired electric utility plants that will be subject to the CCR final rule to 

reflect the plant closure patterns noted in the IPM National Electric Energy Data System 

(NEEDS) v.5.13 database. Specifically, the NEEDS data specifies which electric generating 

units and plants will cease operation prior to 2016, as well as which electric generating units and 

plants will cease operation after 2015.

This chapter updates the universe to reflect the NEEDS v.5.13 database for three reasons: first, 

the NEEDS v.5.13 database contains post-2012 plant-specific information about changes in 

operation. Second, the database uses a conservative method for identifying plants planning to 

close. Finally, the NEEDS v.5.13 data are used across EPA regulatory impact analyses, including 

the forthcomingEPA’s IPM analysis for the CCR final rule. (available as a separate reported 

dated December 2014 in the docket for the final rule (docket nr. EPA-HQ-RCRA-2009-0640 at 

http://www.regulations.govsee Appendix X).

As sensitivity analyses (in Section 9.6), this RIA examines the cost and benefit impacts of using 

a 2010 survey conducted by EPA’s Office of Water to identify plants likely to close. The 2010 

survey identifies self-reported electric generating unit (EGU or boiler) closure plans and third-
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party reports on planned closures of coal-fired electric utility plants, and includes a broader set of 

plants than the IPM NEEDS datadatabase.

396

9.2.1.1 Plants Ceasing Operation Prior to 2016 According to NEEDS

If, according to the NEEDS database, a given plant will have closed all of its coal-fired electric 

generating units prior to 2016, this chapter removes all costs associated with CCR management 

at that plant from both baseline and post-rule scenarios.397 Similarly, the benefits analysis 

assumes that no rule-related benefits will occur at any of these plants.

The NEEDS v.5.13 database lists 83 plants that will fully close all coal-fired units before 2016; 

of these, 64 are included in the RIA universe of 478 operating plants.398 Of these 64, 50 have onsite CCR management units, and therefore incur costs associated with the CCR final rule as 

described in for closing and capping their CCR units upon plant closure (if eligible, according to 

the RIA.“alternative closure requirement #2” addressed in Section 9.3). The remaining 14, 

according to information from the EIA, currently solely dispose of ashCCR off-site or solely sell 

it for beneficial use, and are therefore unaffected by the CCR rule. Thus, the total number of 

plants affected plants by the CCR final rule is 464 plants, of which 414 (plants are projected to 

remain operating and burning coal in the NEEDS database (i.e., 478 plants less the 64 RIA 

universe plants that will close all of their coal-fired electric generating units boilers prior to 

2016).

The 50 affected plants use a total of 123 CCR management units (11% of 1,156 total CCR 

management units at the 478 coal-fired electric utility plants in the universe identified in 

Chapter 2 as affected by the CCR final rule), including 24 landfills, 25 disposal impoundments, 

and 74 storage impoundments. These plants (and associated CCR management units) are 

excluded from the baseline and regulatory cost and benefit analyses in this chapter, again 

reflecting the assumption that the plants cease operating in 2015 or earlier, before the rule takes 

effect (according to Section 257.50(e) Scope and purpose of the CCR final rule, the rule only 

applies to operating electric utility plants, not to plants which have ceased producing electricity 

prior to the effective date of the rule).

9.2.1.2 Plants Ceasing Operation After 2015 According to NEEDS

The NEEDS v.5.13 database identifies 11 plants as undergoing full closure of all coal-fired 

boilers after 2015. Across these 11 plants, each of which occurs in the RIA’s list of 478 plants 

and each of which has at least one on-site CCR management unit, there are 33 CCR management 

units total: 13 landfills, one disposal impoundment, and 19 storage impoundments. In general, 

the full closures according to NEEDS happen soon after the beginning of the period of analysis 

 

396 EPA Office of Water’s 2010 mail survey to power plants for the Steam Electric Power Generating Effluent Guidelines, 

http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm. 

397 A plant is defined as having closed or planning to close all of its coal-fired electric generating units according to the NEEDS 

v.5.13 database if, all electric generating units defined as “steam coal” or “IGCC,” closed or will close prior to 2016. 

398 The remaining 19 were generally not included in the 478 coal-fired electric utility plants described in Chapter 2 because they 

closed prior to 2012 and were thus not included in the EIA-923 and EIA-860 databases underpinning the construction of the 

affected universe in this RIA.
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of this RIA: the average year of full closure across these 11 plants is approximately 2019, and of 

the 11 plants, only two are indicated in NEEDS v.5.13 as fully closing after 2020, with the latest 

of these having its closure year in 2026. As a result, incremental costs estimated in this chapter 

associated with the CCR rule for these plants are minimal, as most costs, even those applicable to 

existing CCR management units (as opposed to new CCR management units), are incurred for 

relatively few years.399

If, according to the NEEDS database, a given plant will have closed all of its coal-fired electric 

generating units after 2015 (i.e., in a year following the beginning of the period of analysis of 

this RIA), this chapter removes all costs associated with CCR management at that plant from 

both baseline and post-rule scenarios, beginning with the year in which the NEEDS database 

indicates complete closure of all of its operating coal-fired electric generating units.400 The latest 

year for which closure was indicated was 2026. In the baseline scenario, closure costs are 

incurred by CCR management units at these plants if they are required by state regulatory 

baselines for the specific type of CCR management unit (i.e., landfill or impoundment); in the 

post-rule scenario, closure costs are incurred by all CCR management units. These closure costs 

are applied, in annualized fashion, for a 40-year period following the year in which the 

facilityelectric utility plant ceases operating. Similarly, the benefits analysis assumes that no 

rule-related benefits will occur at any of these plants in subsequent years. 

The specific algorithm applied to model the cost impacts associated with the set of plants closing 

in years after 2015 is described below.

Any CCR management unit (including landfills) identified as meeting the following criteria is 

assumed to cease operating at the end of its operating life, or the year of facilityplant closure, 

whichever comes earlier. This algorithm is designed to prevent occurrences where plants with 

planned closures according to NEEDS incur costly changes in CCR management methods prior 

to their listed facilityplant retirement date according to NEEDS, which would overestimate costs 

by failing to acknowledge that these plants would cease CCR generation/disposal operations 

rather than construct new CCR management units, only to shutter them in the next few years. 

Specifically:

 Landfills:

o In the baseline, landfills are assumed to close permanently in either the year of 

facilityplant closure or upon reaching 80 years of age, whichever comes earliest. If 

the state regulatory baseline requires closure capping and/or post-closure monitoring, 

these costs are applied for 40 years following landfill or facilityplant closure.

 

399 As described above, this chapter does not assess whether unlined impoundments (disposal or storage) at these 11 plants incur 

groundwater contamination events that would require changes in CCR management as a simplifying assumption. Because 

NEEDS indicates that these 11 plants close early in the RIA’s period of analysis (19 of the 20 impoundments are associated with 

plants indicated in NEEDS to close in 2016, 2017, or 2018), this assumption does not substantially overstate costs (because it is 

possible that these plants would cease CCR generation/disposal earlier if faced with a costly CCR management change as a result 

of a groundwater contamination event). 

400 A plant is defined as having closed or planning to close all of its coal-fired electric generating units according to the NEEDS 

v.5.13 database if, all electric generating units defined as “steam coal” or “IGCC,” are closed as of a given year. 
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o In the post-rule scenario, landfills are assumed to close permanently in either the year 

of facilityplant closure or upon reaching 80 years of age, whichever comes earliest. 

Closure capping and post-closure monitoring costs are applied for 40 years following 

landfill or facilityplant closure. All costs applicable to existing landfills under the 

post-rule scenario (groundwater monitoring, dust controls, run-on/run-off controls, 

corrective action) are applied accordingly to the algorithms in described in Chapters 

3 and 4 prior to unit closure.

 Disposal impoundments:

o In the baseline scenario, disposal impoundments are assumed to close permanently in 

either the year of facilityplant closure or upon reaching 40 years (or the next multiple 

of 40, if the unit began the period of analysis at age over 40), whichever comes 

earliest. If the state regulatory baseline requires closure capping and/or post-closure 

monitoring, these costs are applied for 40 years following impoundment or plant

closure.

o In the post-rule scenario, disposal impoundments are assumed to close permanently in 

either the year of plant closure or upon reaching 40 years (or the next multiple of 40, 

if the unit began the period of analysis at age over 40), whichever comes earliest. If 

the state regulatory baseline requires closure capping and/or post-closure monitoring, 

these costs are applied for 40 years following impoundment or facility closure.

o In the post-rule scenario, disposal impoundments are assumed to close permanently in 

either the year of facility closure or upon reaching 40 years (or the next multiple of 

40, if the unit began the period of analysis at age over 40), whichever comes earliest. 

Closure capping and post-closure monitoring costs are applied for 40 years following 

impoundment or facilityplant closure. For unlined disposal impoundments qualifying 

for this option, no assessment of whether or not the units experience groundwater 

contamination events occurs, as the units cease operating as of the year of 

facilityplant closure or an earlier date. All costs applicable to existing disposal 

impoundments under the post-rule scenario (groundwater monitoring, fugitive CCR 

dust controls, stormwater run-on/run-off controls, corrective action, impoundment 

structural integrity inspectionsrequirements) are applied accordingly to the algorithms 

in described in Chapters 3 and 4 prior to unit closure.

 Storage impoundments:

o In the baseline scenario, storage impoundments are assumed to close permanently in 

the year of facilityplant closure. (As indicated in Chapter 3, this RIA does not 

assume that storage impoundments ever close in the baseline.)

o In the post-rule scenario, storage impoundments are assumed to close permanently in 

the year of facilityplant closure. Closure capping and post-closure monitoring costs 

are applied for 40 years following facilityplant closure. For unlined storage 

impoundments qualifying for this option, no assessment of whether or not the units 
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experience groundwater contamination events occurs, as the units cease operating as 

of the year of facilityplant closure. All costs applicable to existing storage 

impoundments under the post-rule scenario (groundwater monitoring, fugitive CCR 

dust controls, stormwater run-on/run-off controls, corrective action, impoundment 

structural integrity inspectionsrequirement) are applied accordingly to the algorithms 

in described in Chapters 3 and 4 prior to unit closure.

9.2.2 Change to Projection in Coal Consumption at Electric Utility Plants

Chapter 2 uses the Energy Information Administration’s (EIA) 2014 Annual Energy Outlook401

(AEO) electric utility steam coal consumption Reference case 2015-2040 forecast to estimate 

coal use and CCR management cost trends in future years. This chapter updates the forecast to 

be consistent with the Integrated Planning Model (IPM) v.5.13 Base Case forecast.2014-2050 

forecast, so to harmonize with IPM-based economic analyses of other EPA rules which also 

affect the electric utility industry. Exhibit 9-A below displays the IPM Base Case forecast 

relative to the EIA Reference case forecast; this adjustment has the net effect of slightly lowering

future projected coal use and associated costs, likely in part due to the fact that IPM includes 

closures of plants that have been announced since the EIA forecast was generated. However, the 

effect on total costs of the rule is small because the greatest downward adjustments in projected 

future CCR growth occur in later years, which are more heavily discounted.

Unlike EIA’s Annual Energy Outlook data, IPM data are not available for every year in the 

model’s projected time frame through 2050.402 Therefore, for years falling between those with 

IPM forecastsforecast, this chapter applies a linear interpolation to estimate annual forecasted 

CCR growth. Because the IPM data extend only out to 2050, the CCR quantities in years beyond 

2050 are assumed to be the same as that in 2050, consistent with the methodology applied in the 

RIA for CCR growth beyond 2040, the final year of the AEO 2014 projection dataof future coal 

consumption for electricity generation.

Exhibit 9-A

Comparison of EIA AEO 2014 Reference case (applied in Chapter 2)

and IPM v.5.13 Base Case (applied in Chapter 9)

 

401 The EIA AEO 2014 AEO isreport and data are available at http://www.eia.gov/forecasts/aeo/

402 Specifically, IPM base case v5.13 future coal consumption for electricity generation data are available for 2012, seven distinct 

future years (2016, 2018, 2020, 2025, 2030, 2040, and 2050), whereas. EIA AEO 2014 coal consumption forecast data are 

available for every future year through 2040.
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9.2.3 Scaling Factor for CCR Quantities Managed in Storage Impoundments

The universe of impoundments affected by the CCR rule includes two types of ponds that 

receive CCR:

 Disposal impoundments: in which CCR are placed permanently as final destination.

 Storage impoundments: in which CCR are placed for some time before being removed 

(usually by dredging) for final disposal elsewhere.

Chapters 3 and 4 describe in detail the universe, management, and cost assumptions associated 

with these impoundments.

0

2

4

6

8

10

12

14

16

18

20

20142024203420442054206420742084209421042114

Quadrillion Btu Coal Consumption by 

Electric Utility Plants for Electricity 

Generation

AEO 2014 Reference Case

IPM v.5.13 Base Case

0

2

4

6

8

10

12

14

16

18

20

20142024203420442054206420742084209421042114

Quadrillion Btu Coal Consumption by 

Electric Utility Plants for Electricity 

Generation

AEO 2014 Reference Case

IPM v.5.13 Base Case
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A key driver of the cost of managing storage impoundments is the assumption about the 

quantities of CCR that are managed. Additional data on impoundment purpose and management 

received from EPA’s Office of Water in August 2014 indicate that an adjustment of waste 

tonnage assumptions in the CCR RIA is necessary, as described below.

9.2.3.1 Industrial Purpose of CCR Storage Impoundments

This RIA assumes, absent other information, the largest impoundment at the 142 electric utility 

plants that reportreported wet CCR disposal toin the EIA-923 database, is a CCR disposal 

impoundment that is capable of managing all types of CCR. The analysis (i.e., fly ash, bottom 

ash, and FGD). This RIA further assumes that all other pondsimpoundments at those plants, as 

well as the 384 pondsimpoundments at plants that do not report wet CCR disposal, are storage 

impoundments that temporarily manage some quantity of CCR.

The analysis initially performed in Chapters 3 and 4 did not have access to any information 

about the types or quantities of CCR managed in storage impoundments. Therefore, the analysis 

conservatively assumed that all storage impoundments managed a quantity of CCR equal to 

roughly 25% of total CCR reported by the plant. This is roughly equivalent to assuming that 

these impoundments manage bottom ash by sluicing the solids to the impoundment and then 

dredging annually and disposing of the solids in other CCR management units (whether on-site 

or off-site).403 

However, in some cases CCR storage impoundments may serve other purposes, such as water 

treatment, and may handle much smaller quantities of CCR. As a result, the RIA cost estimates 

for storage impoundments in Chapters 3 and 4 likely overstate costs.

Accordingly, this chapter attempts to evaluate the following questions with respect to the 

quantity or percentage of currently active impoundments in the baseline universe: 

1. How many impoundments receive or store bottom ash (including final disposal and 

temporary storage)?

2. How many impoundments receive bottom ash but don’t dispose of it (i.e., are regularly 

dredged)?

3. How many receive and dispose of both bottom ash and fly ash?

The specific location of storage impoundments is not necessary for this analysis; it is only 

necessary to identify the actual portion of the storage impoundment universe that is likely to 

manage bottom ash, and develop a national estimate of general costs with storage impoundments 

that accounts for other management types.

9.2.3.2 Data from EPA’s Office of Water on CCR Storage Impoundments

 

403 Similarly, this RIA assumes that any power plants that wet-dry convert, if they have more than one impoundment, leave the 

remaining storage impoundments open to manage bottom ash, which is sluiced into these storage impoundments and then 

dredged and disposed of elsewhere.
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Summary data from EPA Office of Water’s (EPA-OW) 2010 survey of electric utility plants 

provides information about whether an impoundment directly receives CCR wastes from a 

process (e.g., the first impoundment in a series of impoundments) or is an indirect recipient of 

such wastes (e.g., the second or third impoundment in a series), but does not indicate whether an 

impoundment is used to dispose or store CCR wastes, as defined by this RIA.404 In addition, the 

EPA-OW survey does not indicate the quantities of solids (i.e., fly ash, bottom ash, or FGD 

solids) that are sent (i.e., water sluiced) to impoundments. 

However, it is a reasonable assumption that a primary impoundment for fly ash wastewater 

contains large quantities of solids. This may also be the case for bottom ash wastewater, though 

some plants that use dewatering bins will remove a large fraction of the bottom ash prior to

releasing wastewater to an impoundment. Many plants also use hydrocyclones to remove FGD 

solids prior to the FGD impoundment.

EPA-OW’s 2010 survey includes 885 CCR impoundments. Of these, 500 are primary CCR 

impoundments, meaning that they directly receive at least one type of CCR waste (for this 

analysis, either fly ash, bottom ash, or FGD wastewater). The remaining 385 CCR 

impoundments in the EPA-OW universe contain CCR wastewater, but these impoundments 

receive wastewater as overflow from another CCR impoundment.

In addition, nearly 90% of primary CCR impoundments and 95% of non-CCR impoundments 

also receive another type of non-CCR wastewater (such as cooling water or other non-CCR 

process wastes). This suggests that, following any wet-to-dry conversion of ash systems, plants 

would either continue to operate the impoundments to treat non-CCR wastes or would need to 

install some form of impoundment or tank-based treatment system to treat the non-CCR wastes.

Exhibit 9-B below displays a summary of primary and non-primary CCR impoundment counts

from EPA-OW’s 2010 survey, sorted by type of CCR.

9.2.3.3 Analysis and Results for Storage Impoundment Factor

This chapter employs the following adjustments to assumptions applied in the RIA to reflect the 

data in Exhibit 9-B below:

 Per the impoundment count data in Exhibit 9-B below, the universe of disposal 

impoundments in the chapter remains unchanged from the universe in Chapters 2 and 3. 

The EPA Office of Water’s primary impoundments in the Fly Ash and Bottom Ash (n = 

129) and the Fly Ash Only (n = 33) categories are roughly consistent with this RIA’s 

universe (see Chapters 2, 3, and 4) of disposal impoundments (142 disposal 

impoundments; 129+33 = 162).405

 

404 Additional background information about EPA-OW’s 2010 survey of the electric utility industry is available from EPA’s 

website at http://water.epa.gov/scitech/wastetech/guide/steam-electric/questionnaire.cfm

405 In this chapter, the total universe of CCR management units affected by the CCR Final Rulefinal rule is adjusted downward to 

account for plant closures indicated in NEEDS v.5.13, as described in Section 9.2.1. We refer to the original count of 142 

disposal impoundments from Chapters 2 through 4 because this number is comparable to the universe indicated in Exhibit 9-B

to assess average operations at coal-fired electric utility plants. 
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 The remaining primary impoundments in Exhibit 9-B (n = 253) are categorized as 

“Bottom Ash Only..” This chapter continues to employ the assumption that 25 percent%

of waste is received by, and dredged from, (i.e., double-managed in) these 

impoundments, consistent with the fact that bottom ash constitutes roughly 25 percent%

of the total CCR tonnage of fly ash and bottom ash. This 25 percent% factor is consistent 

with independent engineering estimates406 of the maximum quantity of solids that could 

be economically double-managed in storage impoundments (see Chapters 3 and 4).407

 The non-primary impoundments described in Exhibit 9-B are largely receiving CCR 

wastewaters rather than solids. This chapter assumes that non-primary impoundments 

manage (receive and dredge) a quantity equivalent to five percent5% of total tonnage at 

the plant. Again, this assumption is consistent independent engineering estimates

documented in this RIA..

408 Exhibit 9-B indicates 385 of these non-primary 

impoundments.409

To arrive at its final estimate, this chapter calculates a weighted average of CCR tonnage 

managed in storage impoundments, reflecting 253 impoundments that manage 25 percent% of 

wet-disposed CCR tonnage at plants with storage impoundments and 385 that manage five 

percent5% of wet-disposed CCR tonnage at these plants. This yields a figure of approximately 

13%, which replaces the upper bound 25% assumption used in Chapters 3 and 4. Because 

storage impoundment costs are strongly (but not perfectly) correlated with tonnage, this 

adjustment reduces the costs associated with storage impoundments by approximately half, 

exclusive of the other adjustments described in this chapter.

Exhibit 9-B

CCR Impoundment Counts in the EPA-OW 2010 Survey Impoundment Population

by CCR Type & Impoundment Type

CCR Type

Primary CCR 

Impoundments for at Least 

One of the CCRsa

Non-Primary CCR 

Impoundments

d

All CCR Impoundments

(Primary + Non-Primary)

All

Impoundments 

with other NonCCR 

Wastewater5 All

Impoundments 

with other NonCCR 

Wastewatere All

Impoundments 

with other NonCCR 

Wastewatere

Bottom Ash 

onlybOnlyb 253 230 196 188 449 418

Fly Ash Onlyb 33 25 16 16 49 41

FGD Only 85 59 80 68 165 127

Fly Ash and 

Bottom Ashb,c 129 127 93 92 222 219

 

406 25% assumption formulated by engineers from GZA Geoenvironmental based on expert judgment and institutional 

knowledge based on extensive experience with the electric power industry.

407 This analysis excludes FGD-related ponds.

408 5% assumption formulated by engineers from GZA Geoenvironmental based on expert judgment and institutional knowledge 

based on extensive experience with the electric power industry.

409 Note that this calculation includes all non-primary ponds, including FGD ponds, because the lower-bound 5% doublemanagement parameter does not require a comparison of bottom ash tonnage to total (fly ash plus bottom ash tonnage) as 

corroborating evidence.
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Total 500 441 385 364 885 805

Notes:

a) A primary CCR impoundment is identified as any impoundment that has a direct influent of any CCR wastewater from the electric 

generating unit (EGU or boiler) with or without significant levels of CCR solids.

b) EPA-OW has primarily focused this analysis on ash because that is where the bulk of the CCR solids are expected (i.e., for many plants, 

the bulk of the FGD solids are removed prior to the FGD wastewater being sent to the impoundment). Therefore, an impoundment is only 

noted as containing FGD wastewater in the cases where that is the only CCR sent to the impoundment. An impoundment listed in this table as 

“Bottom Ash only,” “Fly Ash only,” or “Fly Ash and Bottom Ash” may also, therefore, receive FGD wastewater, but contains minimal FGD 

solids (e.g., through use of dewatering bins for bottom ash or hydrocyclones for FGD).

c) For primary fly ash and bottom ash impoundments, EPA-OW classified the impoundment as primary even if only one ash transport stream 

flows directly to the impoundment. For example, a plant operates two impoundments, the first receives only bottom ash transport water and 

the overflow from this first impoundment is transferred to a second impoundment which also receives fly ash transport water. In this example, 

the first impoundment is classified as a “Bottom Ash only” impoundment and the second impoundment is classified as a “Fly Ash and 

Bottom Ash” impoundment. Additionally, both impoundments are classified as “Primary CCR Impoundments” because they both directly 

receive at least one CCR wastewater.

d) A non-primary impoundment is identified as any impoundment that only receives CCR wastewater as the overflow from another 

impoundment. In general, these impoundments are assumed to manage a very small quantity of solids.

e) Non-CCR wastewaters are any plant effluents other than bottom ash transport water, fly ash transport water, or FGD wastewater. These 

include cooling water, low-volume wastes, metal cleaning wastes, coal pile runoff, etc. Office of Water notes that landfill leachate is 

considered a CCR wastewater, but is excluded from this analysis because it does not contain significant CCR solids.

There are also 878 active impoundments that contain only non-CCR wastewater in the EPA-OW 2010 survey impoundment population. 

These impoundments are not reflected in the table.

9.2.4 Revision to Estimation of Impacts Relating to CCR Beneficial Use

This chapter makes two revisions to the estimation of impacts relating to beneficial use in the 

CCR RIA: the application of the Fann et al. (2009) impact per ton values without scaling to 

monetize reductions in criteria pollution emissions; and the application of a downward-scaling 

factor to take into account reduced beneficial use due to the universe adjustments made in this 

chapter.

 Fann et al. (2009) coefficient: Reductions in criteria pollutant emission represent a 

significant portion of the beneficial use benefits presented in the RIA. The RIA’s 

estimates of these benefits reflect monetized estimates of air quality damages per ton of 

emissions derived from Fann et al. (2009). Specifically, the RIA (in Chapter 5) scales 

the Fann et al. values to reflect the dose-response coefficient for PM mortality employed 

in EPA’s benefit-cost analysis of the 1990 Clean Air Act Amendments (CAAA).410 The 

scaled Fann et al. coefficient is approximately halfway between the coefficients estimated 

in Pope et al. (2002) and Laden et al. (2006).411 In contrast, the Fann et al. impact per ton 

values reflect the dose-response coefficient estimated in Laden et al. (2006). Rather than 

scaling the Fann et al. values as in Chapter 5 and Appendix S of the RIA, this chapter 

applies the Fann et al. values without scaling for consistency with other RIAs that 

estimate air quality impacts on a per-ton basis.

 22 percent% downward scaling factor: Consistent with the modification described in 

Section 9.2.1, this chapter adjusts the monetized value of increased CCR beneficial use 

under the CCR final rule downward by approximately 22 percent. This 22 percent%

 

410 See U.S. EPA, The Benefits and Costs of the Clean Air Act from 1990 to 2020, March 2011.

411 C.A. Pope, III, R.T. Burnett, M.J. Thun, E.E. Calle, D. Krewski, K. Ito, and G.D. Thurston, 2002. “Lung Cancer, 

Cardiopulmonary Mortality, and Long-term Exposure to Fine Particulate Air Pollution.” Journal of the American Medical 

Association 287:1132-1141 and F. Laden, J. Schwartz, F.E. Speizer, and D.W. Dockery, 2006. Reduction in Fine Particulate Air 

Pollution and Mortality. American Journal of Respiratory and Critical Care Medicine. 173: 667-672.
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scaling factor was determined by comparing the volume of CCR available for beneficial 

use generated under the revised universe assumptions described in Sections 9.2.1 and 

9.2.2 with the amount of CCR available for beneficial use per the original analysis in 

Chapter 5 (based on assumptions regarding the affected universe and growth in CCR 

generation over time described in Chapter 2).412 The scaling factor reflects multiple 

baseline adjustments made in this chapter, including the removal from the market of all 

generated CCR that could potentially be beneficially used associated with the plants 

planning to retire or close before 2016, as well as out-year adjustments for plants ceasing 

operations, according to NEEDS v.5.13, in later years. In addition, revisions to projected 

future growth of CCR generation as described in Section 9.2.2 are also factored into this 

adjustment, in order to provide an apples-to-apples comparison between the beneficial 

use impacts estimated in Chapter 5 based on EIA AEO forecasts of CCR generation and 

the CCR generation p-rojections applied in this chapter based on the IPM v.5.13 

forecast.. This chapter applies the 22 percent% downward scaling factor to all monetized 

beneficiaul use benefits described in Chapter 5 and Appendix S, including the benefits 

associated with reductions in criteria pollutant emissions based on the Fann et al. values 

described above.

9.2.5 Revisions to Harmonization of Benefits with EPA-OW’s RIA for the 

2013 SPGELG Proposed Rule

This chapter updates the parameters used to estimate the benefits of the CCR final rule. 

Specifically, Chapter 5 measured eight monetized benefits of the CCR final rule by scaling the 

benefits estimated for the EPA-OW’s June 2013 SPGELG proposed rule (ELG4 regulatory 

option), using the following three-step process:413

Step 1: Determine the fraction of EPA-OW’s total monetized benefits associated with bottom 

ash, fly ash, and FGD pollutant removals for the ELG4 regulatory option.

Step 2: Calculate the quantity of annual CCR impoundment tonnage associated with EPAOW’s benefits.

Step 3: Develop a parameter for scaling based on the above two adjustments and the quantity

of CCR tonnage associated with impoundments that are expected to close or are 

removed from the analysis.

This methodology was designed to ensure consistency between rule assumptions and methods by 

transferring benefits to the CCR final rule in the absence of more detailed information regarding 

the calculation of benefits under the SPGELG rule. The first step removes consideration of the 

portion of benefits associated with landfill leachate pollutant removals that the CCR final rule 

 

412 In other words, over the 100-year period of analysis, projections for the volume of CCR available for beneficial use per the 

updated parameters in this chapter are only 78% of the original volume estimated in Chapter 5. The majority of this decline 

results from the closure of plants, as described in Section 9.2.1, who will no longer generate CCR that could be beneficially used; 

a small portion of the decline is attributable to the decline in overall CCR generation resulting from replacing the EIA AEO 

projections of CCR growth (via estimates of future coal consumption for electricity generation) with the IPM projectionsv5.13 

base case projection, as described in Section 9.2.2.

413 EPA-OW’s 2013 SPGELG proposed rule is available at Federal Register, Vol. 78, No. 110, June 7, 2013.
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does not address. The second step scales the EPA-OW benefits upward to reflect CCR tonnage 

that is not addressed in the ELG4 benefits. In the final step, these two scaling factors are applied 

to the expected future percentage of impoundment annual tonnage that is associated with

impoundments that are expected to close and convert to dry handling as a result of the CCR rule. 

For example, because 54% of wet-managed tonnage in the CCR baseline is associated with the 

probabilistic modeled closure of impoundments, this chapter adjusts the EPA-OW benefits by 

54%. 

The primary assumptions underlying this methodology are that all SPGELG benefit categories 

are directly or indirectly correlated with pollutant removal quantities, and changes in 

impoundment management (closures and improved CCR pollution controls) and associated 

reductions in impoundment releases will result in less discharge of CCR contaminants to surface 

water.

Since completion of the analyses documented in Chapter 5 of this RIA, a more detailed 

accounting of EPA-OW benefits calculations became available, including the list of the plant 

closures that account for the majority of benefits in several key benefits categories. These data 

confirm that the SPGELG rule assumes that all impoundment types, storage and disposal, would 

be expected to convert to dry handling under the ELG4 option. In contrast, under the CCR final 

rule, only disposal impoundments are expected to convert to dry handling; storage 

impoundments continue to operate.414 To account for the continuation of storage impoundment 

operation, the analysis in this chapter reflects an additional step to the benefits scaling process: a 

downward adjustment of the EPA-OW’s ELG4 benefits values by 12% to reflect the continued 

management of the wet tonnage that is double-managed in storage impoundments, calculated as 

follows:

1 −

100% of wet disposal tonnage

100% + 13% double − managed tonnage

= 0.12

Overall, this additional adjustment provides better alignment with the benefits calculations 

technique employed in the SPGELG rule.415

9.2.6 Changes to CCR Impoundment Release Analysis

This chapter updates CCR impoundment release benefits estimates to reflect several minor 

modifications to release rate probabilities and impoundment capacity factors. These changes and 

the purposes behind them are described in detail below.

 

414 In the post-rule scenario, however, unlined storage ponds that leak must close and are assumed to be replaced with a new, 

lined storage pond.

415 This revised benefits scaling approach still assumes that benefits at each plant are proportional to the amount of CCR tonnage 

that converts to dry handling. If the SPGELG benefits are correlated with a different metric, the scaling of benefits to the CCR 

final rule may not align accurately. However, in the absence of additional information from OW, this chapter considers this a 

reasonable assumption for applying benefits at the scale predicted for the SPGELG rule.
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9.2.6.1 Changes to Post-Rule Release Rate for Wall-Breaches

This chapter applies a post-rule 0.044% wall breach release rate based on Rico et al. (2008) as 

cited in Chapter 5. and Appendix P. This replaces the 0.034% wall breach release rate that was 

derived from Rico et al. as well as based on analysis of the 2009 EPA Office of Resource 

Conservation and Recovery (ORCR) survey data,416 the 2002 National Response Center (NRC)

report,417 and the 2011 Chambers and Higman study.418 This change was made for the following 

reasons:

 The 2011 Chambers and Higman study is not peer-reviewed and only discusses residual 

failures in generalities; no firm list of entities and incidents included in the dataset is 

provided. However, the Chambers and Higman study does pull heavily from Rico et al. 

(2008) and the residual failure rates for the two methods are roughly comparable: 0.04% 

vs. 0.044%.

 The 2002 NRC report regarding Mine Safety and Health Administration (MSHA) data 

has several issues rendering it unsuitable for use in deriving a probability of release. 

Specifically:

o It is not clear how many impoundments were in existence over the 25-year period. 

This source indicates that 713 impoundments were in existence in 2001. Likely, more 

impoundments were in use in the 1970s-80s (which would further drop residual 

failure) but data are not available to quantify this.

o The source notes that “...incidents reviewed here...are not a complete list” but 

instead represent “select events.” The incidents described in the report are large-scale 

failures that resulted in significant damage and sometimes death; the source does not 

appear to contain a complete list of release events. Therefore, it is reasonable to 

assume that the four wall breach failures described in the report over the 25-year 

review period are not the only failures of this type that occurred in the timeframe.

Based on the above information, this chapter uses Rico et al. (2008) to estimate post-rule CCR 

impoundment wall breach release probability; the study is peer reviewed, contains the most 

comprehensive data set available, and delineates the cause of releases. 

This chapter further assumes that the release probability derived from EPA-ORCR’s 2010 survey 

data should not be averaged with that derived by Rico et al. (2008),., as the ORCR data set is far 

more limited than that used in Rico et al. (2008). While the ORCR data set focused on CCR 

 

416 In 2009 EPA-ORCR mailed survey questionnaires to electric utility companies requesting information about CCR 

impoundments. Additional background information about this 2009 Information Collection Request (ICR) survey is available on 

EPA’s website at http://www.epa.gov/osw/nonhaz/industrial/special/fossil/surveys/index.htm

417 National Research Council, “Coal Waste Impoundments: Risks, Responses, and Alternatives,” National Academy Press, 

2002, available at: http://www.nap.edu/catalog.php?record_id=10212

418 In 2009 EPA-ORCR mailed survey questionnaires to electric utility companies requesting information about CCR 

impoundments. Additional background information about this 2009 Information Collection Request (ICR) survey is available on 

EPA’s website at http://www.epa.gov/osw/nonhaz/industrial/special/fossil/surveys/index.htm “Long Term Risks of Tailings Dam 

Failure,” David M. Chambers & Bretwood Higman, October 2011, available at: 

http://ofmpub.epa.gov/eims/eimscomm.getfile?p_download_id=513583
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impoundments, it includes only 10 years of data and four wall breach release events, and it does 

not examine the potential contribution of natural events or latent defects to release events.

9.2.6.2 Post-Rule Release Probabilities for Non-Wall Breaches

In addition to wall breach events, the CCR final rule will help preventreduce other types of 

release events associated with CCR impoundments. The approach applied in the RIA assumed 

that benefits from reduced releases would apply to a range of other releases, including 

overtopping and wall seepage. However, the benefits estimates in this chapter reflect an updated 

assumption that not all “other release” events actually have a measurable environmental impact. 

The benefits estimates in this chapter reflect the assumption that seepage events are very small in 

release volume, and do not incur substantial cleanup costs or NRD damages. Of the 32 “other 

release” events with causation data, 13 are seepage events. This chapter makes the following

revisions to the “other releases” category:

 For calculating pre- and post-rule release probabilities, the 13 seepage events are 

removed from the list of “other releases.”

 For calculating post-rule release probabilities, the CCR final rule impoundment design 

and inspection requirements are assumed to:

o Prevent overtopping events (not associated with wall breaches),

o Have no impact on release events due to (a) human error, or (b) not easily visible 

components of impoundments. These two categories constitute four of the 11 (36%) 

miscellaneous events with causation data. In other words, this chapters assumes the 

CCR final rule prevents 64% (i.e., 100% - 36%) of the miscellaneous causes.

Exhibit 9-C below presents the re-calculated pre-rule (baseline) and post-rule probabilities 

applied in this chapter.

Exhibit 9-C

Re-Estimation of CCR Impoundment Release Probabilities for “Other Release” Events

Types of “Other release” Big impoundments (active) Small impoundments (active)

A. Historical release events 1995-2008 with causation data:

A1. Overtopping 6 2

A2. Seepage 13 0

A3. Miscellaneous causes 10 3

A4. Unknown causation 10 1

A5. Column total (A1+...+A4) = 39 6

Original and revised equations for deriving “other release” pre-rule probabilities

Chapter 5 A5/Total Observations A5/Total Observations

Chapter 9 (A5-A2)/Total Observations (A5-A2)/Total Observations

B1. RIA pre-rule baseline probability 39/4,444

= 0.88%

6/2,212

= 0.28%

B2. Revised pre-rule baseline 

probability

(39-13)/4,444

= 0.59%

(6-0)/2,212

= 0.28%
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Original and revised equations for deriving “other release” post-rule probabilities

Chapter 5 (Assumed remaining 

releases/)/)original baseline 

cases)*(original pre-rule release

rate)

(Assumed remaining 

releases/)/(original baseline 

cases)*(original pre-rule release

rate)

Chapter 9 A5-(A1+A2+0.64*(A3+A4))/ Total 

Observations

A5-(A1+A2+0.64*(A3+A4))/

Total Observations

C1. RIA post-rule probability (4/32)*(0.88)

= 0.11%

(8/32)*0.28

= 0.07%419

C2. Revised post-rule probability 39-(6+13+0.64*(10+10))/4,444 =

0.16%

6-(2+0+0.64*(3+1))/2,212 =

0.065%

 

419 Note that this value was incorrectly calculated in Chapter 5. The value was derived to be 0.21%, which assumed a 25% 

reduction in “other releases” rather than the correct 75% reduction.
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9.2.6.3 Modifications to Impoundment Release Volume Capacity Factors

The benefits estimates in this chapter reflect revisions to the capacity factor (i.e., gallons of CCR 

discharged per release event as a percentage of impoundment design capacity) assumptions

applied in Chapter 5. Specifically, for impoundments with depths greater than five feet and 

capacities greater than 20 acre-feet or with depths greater than 20 feet (“big” impoundments), the 

analyses in this chapter assume that there is no change in the 2.65% capacity factor between 

baseline and the CCR final rule. For the remaining impoundments (“small” impoundments), this 

chapter assumes a 0.41% capacity factor both under baseline and under the CCR final rule.

In other words, this chapter does not assume reductions in capacity factors under the CCR final 

rule. This assumption represents a lower bound of potential benefits; the capacity factors under 

the CCR final rule may be reduced due to more frequent inspections required under the rule, 

which may identify issues earlier and result in smaller spills. The assumption that capacity 

factors are reduced under the CCR final rule was applied in Chapter 5. The shaded boxes in 

Exhibit 9-D below summarize the changes in structural release probabilities and capacity factors 

applied in this chapter compared to the values applied in Chapter 5.
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Exhibit 9-D

Modifications to the CCR Impoundment Future Structural Release Probabilities

and Capacity Factors Assigned in this Chapter

(Modified metrics are shown in shaded boxes and changes are denoted in cross-outs and 

red font)
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9.2.7 Social Cost of Carbon (SCC)

This chapter reflects a modest change to the Social Cost of Carbon (SCC) estimates that are used 

to monetize CO2 impacts in RIAs. In November 2013, the Office of Management & Budget 

(OMB) issued updated SCC values that reflect two minor technical corrections to the prior May 

2013 SCC values:

1. The first addressed a misspecification in the FUND model’s computer code, as covered in 

an erratum to Anthoff and Tol (2013) published in October 2013 in the same journal as 

the underlying article (Climatic Change).

2. The second addressed an inadvertent misspecification of the equilibrium climate 

sensitivity distribution in the FUND model.

Both are described in detail in Appendix B of the revised SCC Technical Support Document 

(TSD).420 These technical corrections resulted in a small decrease in some of the SCC values. 

For example, the central estimated value to society in 2015 of reducing carbon emissions 

decreased from $38 per metric ton of CO2 to $37 per metric ton (in 2007$). OMB's Office of 

Information and Regulatory Affairs (OIRA) published the revised values in the TSD.421

9.3 Changes to Final CCR Rule Requirements: Compliance Alternative 

Closure Requirements for Leaking Unlined CCR Impoundments

During development of the final rule,During August 2014, EPA revised the CCR final rule 

requirements to incorporate two alternative closure requirements. to schedules and related rule 

requirements to consider issues related to the closure of leaking, unlined CCR impoundments. 

The CCR final rule provides two alternative closure requirements for two subsets of electric 

utility plants which detect they have leaking unlined CCR impoundments. Both The alternative 

closure requirements apply both to CCR landfills and surface impoundments that do not meet 

location standards specified in the rule and to only apply to leaking unlined CCR impoundments

which exceed groundwater chemical contamination maximum concentration limits (MCLs):

1. Alternative Closure Requirement #1: For plants that certify no alternative CCR disposal 

capacity, a time extension for completing the closure of leaking, unlined CCR 

impoundments and surface impoundments and landfills that do not meet the location 

 

420 Source: Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under 

Executive Order 12866, Interagency Working Group on Social Cost of Carbon, United States Government, revised Nov 2013, 

available at: http://www.whitehouse.gov/sites/default/files/omb/assets/inforeg/technical-update-social-cost-of-carbon-forregulator-impact-analysis.pdf

421 In response to public and stakeholder interest in SCC, OMB also initiated an opportunity for public comment on the updated 

estimates. The comment request, published in the Federal Register (11/26/13; 78 FR 70586), is in addition to the public 

comment opportunities already available through particular rulemakings. The comment period closed February 26, 2014. The 

year-by-year SCC values to be used in RIAs are in Table A1 of the November 2013 TSD, which this chapter adopted for 

valuation of the CCR beneficial use impacts on CO2 for the CCR final rule.
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requirements of the rule, thereby delaying the date when closure costs begin compared to 

the 2019 date applied in the RIA. 

2. Alternative Closure Requirement #2: For plants that certify plans to permanently cease 

operation of coal-fired boiler(s) by a date certain, a time extension for completing 

closure, thereby delaying the date when closure costs begin compared to the 2019 date 

applied in the RIA. Due to uncertainty regarding the universe of plants which may choose 

to cease operating when faced with the CCR final rule and avail themselves of this 

alternative closure requirement, this RIA presents the impact of this alternative closure 

requirement only as a sensitivity analysis, rather than including potential impacts in its 

primary estimates.

Alternative Closure Requirement #1: For power plants which certify no alternate CCR 

disposal capacity.

Alternative Closure Requirement #2: For power plants which certify permanent cessation 

of a coal-fired boiler(s)generating unit by a date uncertain.

Below is a description of each of the two alternative closure requirements and how this chapter 

evaluates each.422

9.3.1 Alternative Closure Requirement #1: No Alternative CCR Disposal 

Capacity

The CCR final rule addresses a technical infeasibility issue associated with the closure of 

leaking, unlined CCR disposal impoundments and landfills and surface impoundments that do 

not meet the location standards at plants that have limited alternative CCR disposal options. 

Under the CCR final rule, a leaking, unlined CCR impoundment that exceeds the MCL 

groundwater protection standards these units may continue to receive CCRs if the owner or 

operator is able to certify that the leaking impoundment unit is the only feasible option for 

disposal, due to no alternative on-site or off-site disposal capacity. The owner or operator must: 

 Comply with all other requirements of the rule, including initiating corrective action as 

required under the rule if the surface impoundment is unlined and leaking such that one 

or more MCLs are exceeded,

 Provide annual certification that alternative capacity is not available and document efforts 

to obtain additional capacity; and

 

422 In addition to these two alternative closure requirements, EPA also revised its base case compliance requirements for leaking 

unlined CCR impoundments for all other plants. The base case represents the standard compliance requirements for all plants 

under the CCR final rule, and is consistent with the costs estimated in Chapters 3 and 4. Within six months after determining 

that the MCL groundwater protection standards has been exceeded, an unlined CCR impoundment must cease receiving CCR, 

and within five years the plant must retrofit with a composite liner or complete closure of the impoundment. This requirement 

assumes that the plant has alternative CCR disposal capacity that allows a shift of management to begin within the 5-year 

window:

 Impoundments in excess of 40 acres may request up to five 2-year extensions to complete the closure of the 

impoundment (for a total window of 15 years to complete closure).

 Impoundments less than or equal to 40 acres may apply for only one 2-year extension, for a maximum of seven years to 

complete closure of the impoundment.
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 When alternative capacity is identified, obtain such capacity as soon as practicable.

Once alternative capacity is identified, the leaking unlined CCR impoundment or landfill must 

cease receiving CCR and initiate closure according to the schedule outlined in the base case (i.e., 

the requirements under the CCR rule which apply to plants not eligible for alternative closure 

requirement #1): five years for complete closure, subject to relevant extensions.

If no alternative capacity is identified within 10 years after first detecting the groundwater MCL 

exceedance, the CCR impoundment must cease receiving waste and close under the same 

timeframes as in the base case.

In estimating the costs and benefits of this alternative closure requirement, EPA did not include 

the surface impoundments and landfills that do not meet the location restrictions. However, this 

is a relatively small number of units; approximately 22 surface impoundments and 14 landfills.

Therefore, the timeline and decision logic for the model provided below only discusses this 

alternative closure requirement in terms of its applicability to leaking, unlined surface 

impoundments.

The timeline for a plant that obtains an alternative closure requirement for lack of alternative 

CCR capacity is:

August 2018 Earliest date GW monitoring shows exceedance of a GW protection standard.

February 2019 Make initial certification that alternative capacity is not available (and annually 

thereafter).

August 2028 Based on the earliest date of documenting an exceedance, deadline to develop 

alternative capacity and cease placing CCR in the impoundment.

August 2033 Date to complete the closure of the unlined impoundment, (assuming the

maximum 10 years to obtain alternative capacity).

August 2035 Date to complete closure for impoundments less than or equal to 40 acres which 

receive a two-year extension.

August 2043 Earliest date to complete closure for impoundments > 40 acres which receive 

five, two year extensions.

9.3.1.1 Decision Logic for Costs Incurred at Plants that Obtain Alternative Closure 

Requirement #1

To evaluate Alternative Closure Requirement #1, this chapter updates the decision logic in the 

RIA cost model to identify plants whose location and baseline CCR impoundments suggest that 

they might successfully seek the alternative closure requirement, and then delay by 5 10 years 

from the start date for incurring costs for closing leaking unlined CCR impoundments to simulate 

this alternative closure requirement.

423

 

423 Consistent with the base case cost methodology, the RIA cost model considers only start dates for closure-related costs (i.e., 

closure capping and post-closure groundwater monitoring) ), and applies the same standardized time frames for annualizing 

capital and closure costs. For closure capping and post-closure groundwater monitoring EPA delays these costs 10 years for 

estimating this alternative. 
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In other words, in the post-rule scenario of the RIA (as described in Chapter 4), the cost model 

estimates the probability that each unlined CCR impoundment will incur a groundwater 

contamination MCL exceedance event in each year, and estimates costs associated with closing 

those impoundments starting as early as 2020. In this chapter, plants that obtain an alternative 

closure requirementfor lack of alternative CCR disposal are assumed to incur costs beginning 10 

years later (or in 2028 at the earliest).424

9.3.1.2 Identification of Plants that May Qualify for Alternative Closure Requirement #1

To determine which plants qualify for the alternative closure requirement associated with lack of 

alternative CCR disposal capacity, the RIA cost modeling is updated in this chapter to include a 

simple algorithm. The plants eligible for the alternative closure requirement are plants that meet 

all of the following criteria:

1) ReportReported wet CCR disposal inper the 2012 EIA data per the EIA-923 and/or the 

2012 EIA-860 databases (see Chapter 2 for additional information); and

2) Report no dry CCR disposal in either on-site or off-site CCR management units in the 

2012 EIA datadatabase;

425 and

3) Have no on-site CCR landfills.426, 427

 

424 In thethis RIA, the probability of a groundwater contamination MCL exceedance event is dependent on the age of an

impoundment, with the cumulative probability of incurring such an event increasing as the impoundment’s age increases. In the 

first year where such an event can be incurred (2019 in the RIA, 2019 or 2028 in this chapter depending on whether the 

impoundment qualifies under this alternative closure requirement or not; note that impoundments incurring events prior to 2019 

are assumed to undergo closure in 2020, hence the use of 2020 in other chapters of this RIA as well as below), the cost estimation 

modeling applies the cumulative probability of incurring a groundwater contamination event based on impoundment age, though 

in subsequent years, only the incremental probability of incurring such an event is applied. Correspondingly, while Alternative 

Closure Requirement #1 delays the probability-weighted incidence of groundwater contamination events for some unlined 

impoundments, these impoundments incur a somewhat higher probability of incurring a groundwater contamination event in the 

first year where they are eligible to experience one, given that they are eight years older than they otherwise would have been. In 

addition, a number of disposal impoundments reach 40 years of age (i.e., the end of their operating lives) between 2020 and 2028, 

which prompts a decision point, regardless of whether they qualify for Alternative Closure Requirement #1.

425 This chapter considers plants without dry disposal according to 2012 EIA data but with sale/storage of CCR for beneficial use 

to qualify for the alternative closure requirement. This chapter assumes that plants are currently availing themselves of beneficial 

use opportunities for their generated CCR in accordance to prevailing market conditions; that is, it does not assume that plants 

will be able to increase sale of CCR for beneficial use in a targeted way. Correspondingly, plants with present CCR beneficial use 

options that do not have dry disposal options are considered to lack alternative disposal capacity for their wet-managed CCR, 

even if some CCR is already being sold for beneficial use at the plant.

426 Note that in some cases, plants have on-site landfills even though EIA indicates no on-site dry disposal at the plant. The cost 

model makes the conservative assumption that these plants do not qualify for the alternative closure requirement.

427 A small number of plants (seven) have a specific configuration of both lined and unlined storage and disposal impoundments, 

such that they may have alternative disposal capacity even though they appear to meet the qualifications for the alternative 

closure requirement. Specifically, it is possible than a facilityplant may shift management of CCRs from a disposal impoundment 

to an existing storage impoundment (the algorithm for selecting plants with limited disposal capacity considered only landfills as 

alternatives). However, two factors limit the use of storage impounds in most instances: first, storage impoundments are typically 

smaller than disposal impoundments, and second, they are generally a necessary part of ongoing waste management operations at

the facilityplant, some of which may be unrelated to CCRs. Finally, the cost model is consistent across all regulatory scenarios in 

disallowing plants to repurpose storage impoundments.
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Of the 478 coal-fired electric utility plants in the RIA universe, 61 meet all of the criteria listed 

above.428 Together these plants have 61 disposal impoundments (by definition, as the 

impoundment-sorting algorithm applied in the RIA restricts plants to one CCR disposal 

impoundment), and 80 storage impoundments. Also by definition, these plants have no CCR 

landfills.

Note that this algorithm identifies a set of plants which serve as proxies for the actual set of 

plants that may qualify for this alternative closure requirement under actual operating conditions 

and plant-level decisions. The evaluation of costs associated with Alternative Closure 

Requirement #1 does not aim to definitively assess the cost impacts with delayed unlined 

impoundment closure at the set of identified plants, but instead estimates the resulting cost 

impacts from a set of relatively representative plants, as identified by the algorithm described in 

this section, closing their unlined impoundments assuming that they met the conditions to qualify 

for the alternative closure requirement. Exhibit 9-E below clarifies the decision logic of the cost 

estimation model in the face of this methodological revision.

 

428 Of the 478 plants, 64 are identified in Section 9.2.1 as removed from the affected universe due to a pre-2016 closure in the 

NEEDS v.5.13 database. An additional 11 are identified as closing after 2015.Of these 61 plants, 18 are identified as closing prior 

to 2016 in NEEDS, and none are identified as closing after 2015. Correspondingly, only 43 of the 61 plants that qualify for this 

alternative closure requirement are modeled as using it, as the remainder have already closed prior to the period of analysis and 

are correspondingly not considered in the affected universe for the CCR final rule. 22 of the 80 storage impoundments associated 

with these 61 plants are associated with the 18 plants that are not in the affected universe; correspondingly, this alternative 

closure requirement results in revised costs for 43 disposal impoundments and 58 storage impoundments.
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Exhibit 9-E

Cost Estimation Algorithm Revisions for Evaluation of Alternative Closure Requirement #1

Liner 

Status

Lacks Alternative 

Disposal Capacity

Original Approach 

(Chapter 4) Revised Approach (Chapter 9)

Disposal Impoundments

Lined Yes Decision point about future operations reached at end of operating life (age 40) No

Unlined

Yes

Decision point about future disposal 

operations reached at earlier of: end of 

operating life (age 40) or when 

groundwater contamination event 

occurs (first possible year = 2020)

Decision point reached at earlier of: 

end of operating life (age 40) or when 

groundwater contamination event 

occurs adjusted for 10 years of 

alternative closure requirements (first 

possible year = 2028)

No

Decision point reached at earlier of: 

end of operating life (age 40) or when 

groundwater contamination event 

occurs (first possible year = 2020)

Storage Impoundments

Lined Yes Operates in perpetuity No

Unlined

Yes Closure and replacement with new, 

lined storage impoundment when 

groundwater contamination event 

occurs (first possible year = 2020)

Closure and replacement with new, 

lined storage impoundment when 

groundwater contamination event 

occurs adjusted for 10 years of 

alternative closure requirements (first 

possible year = 2028)

No

Closure and replacement with new, 

lined storage impoundment when 

groundwater contamination event 

occurs (first possible year = 2020)

Note: “Decision point” refers to the point at which the existing impoundment is modeled as closing, with CCR 

management transferring to a new method (on-site or off-site landfill, or new impoundment). When the decision 

point is reached, the model assesses costs for a variety of future CCR management options and selects the leastcost option to apply on a going-forward basis. Prior to the decision point (2020, 2028, or at the end of an 

impoundment’s operating life), costs applicable to existing impoundments (i.e., groundwater monitoring, costs 

associated with existing liners and leachate collection systems, dust controls, run-on/run-off controls, corrective 

action, recordkeeping, and structural integrity inspections) are applied annually.

Of the 61 disposal impoundments, eight (13%) are lined, and are therefore unaffected by the 

alternative closure requirement (because they are not modeled as leaking). Of the remaining, 35 

(57%) are unlined (the other 18 are of unknown liner status). For these 35 disposal

impoundments, the first potential year for a decision point (i.e., the first year in which closure or 

other capital costs might be incurred) related to a groundwater contamination event is 2028 in 

this chapter, rather than the 2020, as modeled in the RIA. If, however, any of these 35 disposal 

impoundments reach the end of their operating lives (age 40, or the next multiple of 40 if they 

are above 40 years of age at the beginning of the period of analysis) prior to 2028, they incur the 

decision point at that point, and do not obtain any additional change in schedule related to the 

alternative closure requirement for lack of alternative disposal capacity.

429

 

429 Some of these 35 disposal impoundments do reach the end of their operating lives prior to 2028, which lessens the overall 

impact of this alternative closure requirements relative to the costs presented in Chapter 4 had each of these 35 impoundments 

not done so.
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The remaining 18 (30%) of these 61 disposal impoundments have an unknown liner status, and 

are treated according to the methodology of the RIA: each of these 18 disposal impoundments is 

assigned a probability-weighted chance of either having a sufficient liner or no liner, based on 

the overall proportions of impoundments with known liner statuses that are sufficiently lined or 

unlined, and to the extent that they are modeled as unlined, they are modeled as qualifying for 

the alternative closure requirement.

Among the 80 storage impoundments, 8 (10%) are lined, and are therefore unaffected by the 

alternative closure requirement (as described in Exhibit 9-E above, these lined storage 

impoundments operate in perpetuity). Among the remaining, 54 (68%) are unlined and 18 (23%) 

are of unknown liner status. For these 54 unlined storage impoundments, the first potential year 

in which costs associated with closure and opening of a new, lined storage impoundment due to a 

groundwater contamination event is 2028, rather than 2020, as modeled in the RIA.

The remaining 18 (23%) storage impoundments have an unknown liner status, are handled 

according to the methodology of the RIA: each of these 18 storage impoundments is assigned a 

probability-weighted chance of either having a sufficient liner or no liner, based on the overall 

proportions of impoundments with known liner statuses that are sufficiently lined or unlined. If 

considered to be unlined, they are modeled as qualifying for the alternative closure requirement, 

and to not incur costs associated with closure and opening of new, lined impoundments until 

2028.

9.3.2 Alternative Closure Requirement #2: Permanent Cessation of a CoalFired Boiler(s) by a Date UnCcertain

A second alternative closure requirement in the CCR final rule addresses power plants that plan 

to cease burning coalto permanently cease operating a coal-fired electricity generating unit by a 

date certain. within ten years of identifying a groundwater release. The rule states that unlined, 

leaking CCR impoundments that exceed a groundwater protection standard and surface 

impoundments and landfills that fail to meet the location standards specified in the rule may 

continue to receive CCR if the coal-fired electricity generating unit (EGU or boiler) which is 

generating the CCR is going to cease operation permanently (i.e., retire). The owner or operator

must comply with all other requirements of the rule, including initiating corrective action, 

demonstrating that no alternative disposal capacity is available, and and must certifying that the 

leaking impoundment will be closing on a specific date (this certification must be updated 

annually). Once the coal-fired electricity generating boiler ceases operation and the leaking CCR 

impoundment ceases receiving CCR, owner/operator must complete closure within 5 years, but 

no later than 10 years after first detecting the exceedance of the groundwater protection standard.

The rule timeline for plants that document exceedances in 2018 and opt to use this alternative 

closure requirement is: In these cases, if the surface impoundment is 40 acres or smaller in size, 

the coal-fired boiler must cease operation and the disposal unit must have completed closure 

within 8.5 years of the publication date of the rule. For CCR surface impoundments larger thatn 

40 acres, the coal-fired boiler must cease operation and the disposal unit must have completed 

closure within 13.5 years of the publication date of the rule.
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August 2018 Earliest date GW monitoring would show an exceedance of a GW protection 

standard

February 2019 For exceedances documented in 2018, make initial certification that coal-fired 

electricity boiler will be closing (and annual recertification thereafter).

August 2023 Latest closure commencement date for exceedances documented in 2018

August 2028 Earliest date that impoundment must complete closure

The set of electric utility plants which may avail themselves of this alternative closure 

requirement is not self-evident. As described in Section 9.2.1.2, this chapter models a number of 

plants that have already announced plans to cease operating, according to the NEEDS v.5.13 

database. While these plants may or may not avail themselves of this alternative closure 

requirement, depending on whether or not their unlined impoundments experience groundwater 

contamination events, or meet the rule’s location standards, any cost impacts for these plants are 

likely to be very small, especially given that even in the baseline, these plants would have ceased 

operating early in the period of analysis.

Furthermore, any algorithm that would apply the option of selecting this alternative closure 

requirement within the cost estimation model used in this RIA would select the alternative 

closure requirement option in lieu of continued operation, not for the pre-closure extension 

offered by the alternative closure requirement, but for the ability to cease incurring costs 

associated with all CCR management. This algorithm is not designed to capture the other aspects 

of the business decision to operate or close a power plant (e.g., revenues, depreciation, specific 

technology options); the model examines only the compliance cost portion of the operations. In 

addition, it is highly uncertain which plants would exercise this alternative closure requirement 

when faced with a leaking, unlined surface impoundment. As a result, this chapter does not 

evaluate any potential cost impacts associated with this alternative closure requirement; as noted 

above, the cost impact of the 11 plants already indicated in NEEDS as planning to cease 

operations after 2015 delaying their closure costs is likely to be negligible.430

As a sensitivity analysis, however, this chapter evaluates the potential impact of removing an 

additional subset of plants from the analysis based on information about potential closures (akin 

to the methodology described in Sections 9.2.1.1 and 9.2.1.2). This subset includes several 

plants that may cease operating after 2015, and may thus avail themselves of Alternative Closure 

Requirement #2. While the cost impacts evaluated in this sensitivity analysis do not directly 

mirror the potential cost impacts of Alternative Closure Requirement #2, because the sensitivity 

analysis also evaluates cost impacts associated with numerous plants retiring prior to 2015 and 

 

430 In Section 9.2.1.2, this RIA indicates that for the 11 plants that NEEDS indicates are planning to cease operation after 2015, 

the cost estimation modeling applied in this chapter does not assess whether the unlined surface impoundments associated with

these plants experience groundwater contamination events as a simplifying assumption, because these plants will shut soon 

thereafter and assigning CCR management change costs (e.g., wet-dry conversion or opening a new, lined impoundment) would 

be inappropriate given the plant’s plans to cease operating shortly thereafter. This assumption likely covers some of the cost 

impact associated with this alternative closure requirement, because it simulates continued operation of the CCR management 

units associated with these plants and results in the delay of the accrual of closure costs until the year of facilityplant closure, as 

opposed to the year in which a groundwater contamination event is discovered. Between this simplifying assumption in Section 

9.2.1.2, the fact that a delay of closure costs, which constitute a very small portion of compliance costs assessed in this RIA, by 

just five years is likely to have little cost impact, and the uncertain nature of which plants may choose to avail themselves of this 

alternative closure requirement option, the costs presented in this chapter represent a best estimate of overall compliance costs for 

the CCR final rule, the presence of this alternative closure requirement option notwithstanding. 
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also because it does not directly evaluate the effect of a brief delay on the accrual of closure 

costs, the methodology described in Section 9.6.1.2 and the results described in Section 9.6.2

indicate that the total impact of this sensitivity analysis is less than five percent5% of total costs 

presented in this chapter without taking this alternative closure requirement into account. 

Correspondingly, it appears that Alternative Closure Requirement #2 may have a very small 

overall impact on costs of well below five percent, even if a number of plants that may plan to 

cease operating in future years use Alternative Closure Requirement #2 to delay incurring 

closure costs associated with their leaking, unlined surface impoundments.

9.4 Updated Cost & Benefit Results for CCR Final Rule

The following exhibits accord with the summary tables in Chapters 3 through 6. Exhibits 9-F

through 9-I display baseline costs, while Exhibits 9-J through 9-M display incremental 

regulatory costs of the CCR final rule. Lastly, Exhibits 9-N and 9-O summarize the monetized 

and non-monetized benefits estimated in this chapter, respectively.

Both baseline and incremental rule costs in this chapter are lower than their counterparts in 

Chapters 3 and 4, due to a variety of factors, including:

 The removal of 50 plants closing before 2016 per the NEEDS v.5.13 database in the 

baseline, which removes both baseline costs and the opportunity for CCR management 

units associated with these plants to incur costs under the CCR final rule;

 The use of a slightly lower future projection of coal consumption for electricity 

generation (which this RIA applies for estimating future annual CCR growth 

factorgeneration) from the IPM, rather than the factor from the EIA AEO, which lowers 

both baseline cost and incremental CCR final rule cost;

 Use of a revised, lower factor for estimating CCR tonnage managed in storage 

impoundments, which lowers the baseline cost and incremental CCR final rule cost 

associated with these impoundments.

 Application of an alternative closure requirement that lowers post-rule costs (for plants 

lacking alternative CCR disposal capacity); and

Benefits are also affected by some of the factors influencing costs described above, including the 

removal of the 50 closing plants and the lower factor in estimating CCR tonnage. In addition, 

these baseline revisions result in a downscaling of the overall benefits associated with beneficial 

use presented in this chapter, as described in Section 9.2.4. Overall, changes in impoundment 

behavior as a consequence of modified cost parameters additionally alter benefits. Other factors 

influencing the change in benefit values in this chapter relative to Chapter 5 include:

 The revision of structural release probabilities and release volume capacity factors for 

certain size classes of impoundments and certain types of releases; and
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 The inclusion of an additional scaling adjustment factor in adopting some of EPA Office 

of Water’s June 2013 SPGELG RIA benefits for the CCR final rule.

9.4.1 Revised Baseline Costs of the CCR Final Rule

Exhibits 9-F to 9-I below document total baseline costs of CCR management at plants in the 

RIA universe. These exhibits report costs in both present value and annualized terms, using both 

3% and 7% discount rates, and consider landfills, disposal impoundments, storage 

impoundments, and aggregate costs, respectively. All of these estimates reflect a reduction in 

baseline costs of 16% to 18%, due to the removal of plants reported as closing in the NEEDS 

v.5.13 database, in addition to the other adjustment factors described above.

Exhibit 9-F

Baseline CCR Management Costs – Landfills

(millions of 2013$)

CCR Pollution Control 3% discount rate 7% discount rate

Annualized Present value Annualized Present value

A. Unit-level pollution control costs

1. Groundwater monitoring $15.2 $480 $11.1 $158

2. Bottom liners $1,400 $44,300 $1,020 $14,600

3. Leachate collection systems $296 $9,350 $216 $3,090

4. Dust controls $26.1 $824 $19.1 $272

5. Run-on/run-off controls $5.59 $177 $4.09 $58.3

6. Location restrictions $2.56 $80.8 $1.87 $26.7

7. Closure capping $34.1 $1,080 $24.9 $356

8. Post-closure groundwater monitoring (30 years) $0.174 $5.49 $0.127 $1.81

9. Impoundment structural integrity inspections N/A N/A N/A N/A

B. Other costs

10. Groundwater corrective action $8.60 $272 $8.58 $122

11. Reporting & recordkeeping $0 $0 $0 $0

12. Conversion to dry handling N/A N/A N/A N/A

Column Totals = $1,790 $56,500 $1,310 $18,700

Exhibit 9-G

Baseline CCR Management Costs –Disposal Impoundments

(millions of 2013$)

CCR Pollution Control 3% discount rate 7% discount rate

Annualized Present value Annualized Present value

A. Unit-level pollution control costs

1. Groundwater monitoring $2.09 $66.2 $2.32 $33.1

2. Bottom liners $599 $18,900 $664 $9,480

3. Leachate collection systems $10.3 $326 $11.4 $163

4. Dust controls $0 $0 $0 $0

5. Run-on/run-off controls $0 $0 $0 $0

6. Location restrictions $16.0 $505 $17.7 $253

7. Closure capping $9.85 $311 $10.9 $156

8. Post-closure groundwater monitoring (30 years) $0.0372 $1.18 $0.0413 $0.589

9. Impoundment structural integrity inspections $0.622 $19.7 $0.666 $9.50

B. Other costs

10. Groundwater corrective action $3.82 $121 $3.72 $53.1

11. Reporting & recordkeeping $0 $0 $0 $0
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Exhibit 9-G

Baseline CCR Management Costs –Disposal Impoundments

(millions of 2013$)

CCR Pollution Control 3% discount rate 7% discount rate

Annualized Present value Annualized Present value

12. Conversion to dry handling $59.8 $1,890 $79.3 $1,130

Column Totals = $701 $22,200 $790 $11,300
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Exhibit 9-H

Baseline CCR Management Costs – Storage Impoundments

(millions of 2013$)

CCR Pollution Control 3% discount rate 7% discount rate

Annualized Present value Annualized Present value

A. Unit-level pollution control costs

1. Groundwater monitoring $1.15 $36.4 $1.10 $15.8

2. Bottom liners $329 $10,400 $315 $4,500

3. Leachate collection systems $5.62 $177 $5.39 $76.9

4. Dust controls $0 $0 $0 $0

5. Run-on/run-off controls $0 $0 $0 $0

6. Location restrictions N/A N/A N/A N/A

7. Closure capping $0 $0 $0 $0

8. Post-closure groundwater monitoring (30 years) $0 $0 $0 $0

9. Impoundment structural integrity inspections $3.67 $116 $3.54 $50.5

B. Other costs

10. Groundwater corrective action $11.5 $363 $11.1 $158

11. Reporting & recordkeeping $0 $0 $0 $0

12. Conversion to dry handling N/A N/A N/A N/A

Column Totals = $350 $11,100 $336 $4,800

Exhibit 9-I

Baseline CCR Management Costs for All CCR Management Units

(millions of 2013$)

CCR Pollution Control 3% discount rate 7% discount rate

Annualized Present value Annualized Present value

A. Unit-level pollution control costs

1. Groundwater monitoring $18.4 $582 $14.5 $207

2. Bottom liners $2,330 $73,600 $2,000 $28,600

3. Leachate collection systems $312 $9,850 $233 $3,330

4. Dust controls $26.1 $824 $19.1 $272

5. Run-on/run-off controls $5.59 $177 $4.09 $58.3

6. Location restrictions $18.5 $586 $19.6 $280

7. Closure capping $44.0 $1,390 $35.9 $512

8. Post-closure groundwater monitoring (30 years) $0.211 $6.67 $0.168 $2.40

9. Impoundment structural integrity inspections $4.30 $136 $4.20 $60.0

B. Other costs

10. Groundwater corrective action $23.9 $755 $23.4 $333

11. Reporting & recordkeeping $0 $0 $0 $0

12. Conversion to dry handling $59.8 $1,890 $79.3 $1,130

Subtotal – Baseline Industry Costs $2,840 $89,800 $2,440 $34,800

C. State Agency Paperwork Burden Costs

13. Impoundment structural integrity inspections $0.0859 $2.72 $0.0841 $1.20

14. Groundwater corrective action $0.478 $15.1 $0.467 $6.66

15. Reporting & recordkeeping $0 $0 $0 $0

Subtotal – Baseline Agency Burden Costs $0.564 $17.8 $0.551 $7.86

Column Total = $2,840 $89,800 $2,440 $34,800
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9.4.2 Revised Incremental Costs of the CCR Final Rule

Exhibits 9-J to 9-M below present revised cost estimates for the CCR final rule in both present 

value and annualized terms, using both 3% and 7% discount rates, separately for landfills, 

disposal impoundments, storage impoundments, and aggregate costs, respectively. All estimates 

reflect a reduction in total incremental costs of 26% to 31%, due to the removal of plants 

reported as closing in the NEEDS v.5.13 database, in addition to the other modifications 

described in Sections 9.2 and 9.3.

Exhibit 9-J

Incremental CCR Management Costs – Landfills

(millions of 2013$)

CCR Pollution Control 3% discount rate 7% discount rate

Annualized Present value Annualized Present value

A. Unit-level pollution control costs

1. Groundwater monitoring $1.75 $55.3 $0.624 $8.91

2. Bottom liners $151 $4,780 $54.0 $770

3. Leachate collection systems $51.6 $1,630 $18.4 $263

4. Dust controls $4.76 $150 $1.70 $24.2

5. Run-on/run-off controls $1.13 $35.8 $0.404 $5.76

6. Location restrictions $23.1 $730 $8.24 $118

7. Closure capping $6.63 $210 $2.37 $33.8

8. Post-closure groundwater monitoring (30 

years) $0.0316 $1.00 $0.0113 $0.161

9. Impoundment structural integrity inspections N/A N/A N/A N/A

B. Other costs

10. Groundwater corrective action $3.05 $96.4 $3.62 $51.6

11. Reporting & recordkeeping $5.74 $181 $6.75 $96.3

12. Conversion to dry handling N/A N/A N/A N/A

Column Totals = $249 $7,870 $96.1 $1,370

Exhibit 9-K

Incremental CCR Management Costs – Disposal Impoundments

(millions of 2013$)

CCR Pollution Control 3% discount rate 7% discount rate

Annualized Present value Annualized Present value

A. Unit-level pollution control costs

1. Groundwater monitoring $1.44 $45.6 $0.830 $11.8

2. Bottom liners $161 $5,090 $92.7 $1,320

3. Leachate collection systems N/A N/A N/A N/A

4. Dust controls $1.11 $34.9 $0.636 $9.07

5. Run-on/run-off controls $8.39 $265 $4.83 $68.9

6. Location restrictions $20.5 $646 $11.8 $168

7. Closure capping $6.38 $201 $3.67 $52.3

8. Post-closure groundwater monitoring (30 

years) $0.0210 $0.664 $0.0121 $0.172

9. Impoundment structural integrity inspections $2.24 $70.7 $2.71 $38.7

B. Other costs

10. Groundwater corrective action $1.72 $54.4 $1.76 $25.2

11. Reporting & recordkeeping $3.97 $126 $3.97 $56.6

12. Conversion to dry handling $29.0 $916 $57.3 $818

Column Totals = $236 $7,450 $180 $2,570
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Exhibit 9-L

Incremental CCR Management Costs – Storage Impoundments

(millions of 2013$)

CCR Pollution Control 3% discount rate 7% discount rate

Annualized Present value Annualized Present value

A. Unit-level pollution control costs

1. Groundwater monitoring $1.59 $50.4 $1.34 $19.1

2. Bottom liners $178 $5,630 $150 $2,140

3. Leachate collection systems N/A N/A N/A N/A

4. Dust controls $1.22 $38.7 $1.03 $14.7

5. Run-on/run-off controls $9.28 $293 $7.81 $111

6. Location restrictions N/A N/A N/A N/A

7. Closure capping $7.06 $223 $5.94 $84.7

8. Post-closure groundwater monitoring (30 

years) $0.0234 $0.738 $0.0196 $0.280

9. Impoundment structural integrity inspections $8.64 $273 $8.34 $119

B. Other costs

10. Groundwater corrective action $14.2 $449 $13.7 $196

11. Reporting & recordkeeping $16.6 $524 $16.6 $236

12. Conversion to dry handling N/A N/A N/A N/A

Column Totals = $237 $7,490 $205 $2,920
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Exhibit 9-M

Incremental CCR Management Costs – All CCR Management Units

(millions of 2013$)

CCR Pollution Control 3% discount rate 7% discount rate

Annualized Present value Annualized Present value

A. Unit-level pollution control costs

1. Groundwater monitoring $4.79 $151 $2.80 $39.9

2. Bottom liners $491 $15,500 $297 $4,230

3. Leachate collection systems $51.6 $1,630 $18.4 $263

4. Dust controls $7.09 $224 $3.36 $48.0

5. Run-on/run-off controls $18.8 $594 $13.0 $186

6. Location restrictions $43.6 $1,380 $20.0 $285

7. Closure capping $20.1 $630 $12.0 $171

8. Post-closure groundwater monitoring (30 

years) $0.0760 $2.40 $0.0430 $0.613

9. Impoundment structural integrity inspections $10.9 $344 $11.1 $158

B. Other ancillary costs

10. Groundwater corrective action $19.0 $600 $19.1 $273

11. Reporting & recordkeeping $26.3 $831 $27.3 $389

12. Conversion to dry handling $29.0 $916 $57.3 $818

13. Dewater & capping costs for inactive 

impoundments $12.0 $380 $26.7 $381*

14. Subtotal Industry Costs (1+...+13) = $734 $23,200 $508 $7,240

C. State Agency Paperwork Burden Costs

15. Impoundment structural integrity 

inspections $0.218 $6.88 $0.221 $3.16

16. Groundwater corrective action $0.380 $12.0 $0.382 $5.45

17. Reporting & recordkeeping $0.526 $16.6 $0.546 $7.78

18. Subtotal State Paperwork Burden Cost 

(15+16+17) = $1.12 $35.5 $1.15 $16.4

19. Column Total Costs (14+ 18) = $735 $23,200 $509 $7,260

Note: Notes:

 For reason explained in Section 5.3.4 of this RIA, row 19 above (total costs) does not subtract the “cost offset" which is 

displayed in row 3 of Exhibit 9-N. Instead, this RIA includes the "cost offset" within the CCR beneficial use benefit 

category rather than as a negative cost.

 Due to the revisions to the universe of affected coal-fired electric utility plants discussed below in Section 9.2.1, the 

universe of inactive impoundments may change. However, the CCR final rule considers inactive impoundments 

subject to the rule only if they are located at plants that continue to operate. Correspondingly, it is unclear to what 

extent the RIA-identified universe of 111 inactive impoundments is overstated due to plants initially identified as 

operating in Chapters 2, 3, and 4 that are indicated to close according to the NEEDS v.5.13 database; on the other 

hand, it is unclear to what extent this universe of 111 inactive impoundments is understated due to plants identified in 

NEEDS v.5.13 and discussed in Section 9.2.1 as closing all of their coal-fired boilers but continuing to operate by 

means of other fuel sources resulting in an additional subset of inactive impoundments not considered in this RIA. As 

a simplifying assumption given this uncertainty, this chapter uses the same universe of inactive impoundments 

indicated in Chapters 2, 3, and 4.

Figures are rounded to three significant digits; totals may not add due to rounding.

9.4.3 Revised Incremental Benefits of CCR Final Rule

Exhibit 9-N documents the revised total incremental benefits of the CCR Final Rule at plants. 

This exhibit reports benefits in both present value and annualized terms, using both 7% and 3% 

discount rates. These estimates represent a reduction in total incremental benefits of 31% to 38%, 

due to the adjustment factors described above at the beginning of this chapter. Following the 

summary of total incremental monetized benefits, Exhibit 9-N also summarizes non-quantified 

benefits.
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Exhibit 9-N

Expected Future Benefits for the CCR Final Rule

(millions of 2013$)

Row Benefit Category 3% discount rate 7% discount rate

Annualized Present value Annualized Present 

value

Monetized Benefits

1 Prevention ofReduction in CCR impoundment 

releases $151 $4,760 $138 $1,960

2 PreventionReduction in CCR contamination of 

groundwater contamination $12.8 $405 $9.86 $141

Closures $1.60 $50.7 $1.46 $20.9

Bottom liners $6.56 $207 $5.06 $72.2

Groundwater monitoring $4.65 $147 $3.34 $47.7

3 IncreaseInduced future increase in CCR beneficial 

useuses*

$117 $3,130 $79.0 $1,120

Avoided compliance costair pollution & resource 

consumption $8432.5 $2,670459 $57.121.9 $956164

Avoided air pollution & resource useCCR rule “cost 

offset” (alternatively could be subtracted from row 19 

of Exhibit 9-M)

$3284.5 $4592,670 $21.957.1 $164956

4 Reduced incidence of cancer $0.00546 $0.173 $0.00273 $0.0390

5 Avoided IQ losses from mercury $0.279 $8.80 $0.0246 $0.351

6 Avoided IQ losses from lead $0.186 $5.87 $0.0164 $0.234

7 Reduced need for specialized education from IQ losses $0.00273 $0.0863 $0.000 $0.000

8 Non-market surface water quality benefits

$2.26 $71.4 $1.89 $27.0

Improved aquatic and wildlife habitat

Enhanced water-based recreation

Aesthetic improvements of surface water

Increased non-use ecosystem value

Reduced risks to aquatic wildlife

9 Protection of threatened and& endangered species in 

vicinity of CCR landfills and impoundments $0.909 $28.7 $0.759 $10.8

10 Improved air quality from reduced air pollution 

emissions from power plants $4.66 $147 $2.04 $29.1 Reduced air emissions of NOx, SO2

Reduced air emissions of CO2

11 Reduced groundwater withdrawals by power plants 

(reduced water sluicing of CCR from induced 

conversions to dry CCR handling)

$0.00273 $0.0863 $0.00273 $0.0390

Column Totals = $289 $8,550 $232 $3,290

Non-Monetized Benefits

12 Financial benefit. Reduced investment risk and information asymmetry in financial markets for the electric utility industry.

13 Dread reduction benefit. Reduced fear, stress, and anxiety (i.e., hazard dread) of citizens residing near CCR impoundments.

14 Dust nuisance benefit. Reduced community nuisance from fugitive CCR dust. This is a separate benefit from the human 

health benefit from reduction in CCR dust inhalation, which is estimated in Chapter 5.

15 Non-cancer human health benefit. Reduced non-cancer health effects resulting from fish consumption. This is a separate 

benefit from the avoided cancer risks monetized in Chapter 5.

16 Cancer and non-cancer human health benefit. Reduced cancer and non-cancer health effects resulting from recreational 

water use. This is a separate benefit from the human health benefit from reduction in fish consumption, which is estimated in 

Chapter 5.

17 Avoided sediment contamination. Reduced sediment contamination from reduced deposition of toxic pollutants.

18 Water quality benefit. Reduced water treatment costs for drinking and irrigation water.

19 Commercial fisheries benefit. Improved commercial fishing yields and harvest quality due to aquatic habitat improvements.

20 Tourism benefit. Increased participation in water-based recreation due to water quality improvements.

21 Avoided impingement and entrainment mortality. Reduced fish impingement and entrainment mortality from CCR handling 

surface water intake.

22 Increased property values: Improvement of aesthetic conditions of the local landscape stemming from the induced closure of 

CCR impoundments and the associated de-watering, capping, and re-vegetation requirement of the CCR final rule.
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Notes:

* The beneficial use benefit in this RIA consists of two components. The sub-rows below display an approximate breakdown of the relative 

contribution to the total beneficial use benefit across these two components, cognizant of the downscaling factor applied to these benefits in 

this chapter, as described in Section 9.2.4.

Note: Figures are rounded to three significant digits; totals may not add due to rounding.
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9.4.4 Distribution of Incremental Final Rule Costs

The results of the main methodological differences between the analyses described in this 

chapter and Chapters 3 and 4 are evident in the Exhibit 9-O below. Overall incremental costs 

are lower, due to the lower CCR growth factor, the lower storage impoundment CCR tonnage 

factor, and the removal from the analysis of certain plants undergoing full retirement of their 

coal-fired boilers. In addition, the alternative closure requirements reflected in this chapter 

allowing certain plants with unlined CCR impoundments the possibility of closing these 

impoundments in 2028, rather than 2020, result in a shift in incremental costs from the 2020 

timeframe towards 2028 and beyond.

9.4.5 Distribution of Incremental Benefits Estimated in this Chapter

Exhibit 9-P illustrates the distribution of incremental benefits over the period of the analysis. 

These benefits are presented in undiscounted terms for the two benefits categories that permit 

annual quantification and for the total of these two categories. The graph illustrates a fairly steep 

rise in benefits from 2014 to 2024 followed by another steep growth period between 2046 and 

2051, though the increase in benefit over this later growth period is only about 16 percent% of the 

initial steep increase. Avoided groundwater costs are substantially less than the avoided 

impoundment release costs. While groundwater benefits initially increase through 2038, they then 

decrease slightly before leveling off through the remainder of the study period.

 $-

 $200

 $400

 $600

 $800

 $1,000

 $1,200

 $1,400

 $1,600

 $1,800

 $2,000

2015 2025 2035 2045 2055 2065 2075 2085 2095 2105

Total Incremental Costs ($millions)

Year

Exhibit 9-Q

Total Incremental Costs by Year: All Active & Inactive CCR Management Units

Original RIA Estimates (Chapters 3 and 4)

Revised Estimates (Chapter 9)

 $-

 $200

 $400

 $600

 $800

 $1,000

 $1,200

 $1,400

 $1,600

 $1,800

 $2,000

20152020202520302035204020452050205520602065207020752080208520902095210021052110

Total Incremental Costs ($millions)

Year

Exhibit 9-O

Total Incremental Costs by Year: All Active & Inactive CCR Management Units

Original RIA Estimates (Chapters 3 and 4)

Revised Estimates (Chapter 9)
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9.5 Summary of the Costs and Benefits of the CCR Final Rule

This section presents an overall summary of the cost and benefits of the CCR Final Rule as 

estimated in this chapter. Exhibits 9-Q presents total incremental costs in both annualized and

present value terms under discount rates of 7% and 3%, respectively. As a comparison between 

the costs and benefits estimated in Chapters 4 and 5 of this RIA and those estimated in this 

 $-

 $20.00

 $40.00

 $60.00

 $80.00

 $100.00

 $120.00

 $140.00

 $160.00

 $180.00

 $200.00

2000 2020 2040 2060 2080 2100 2120

Undiscounted Benefits (Millions 2013$)

Year

Exhibit 9-P

Undiscounted Benefits by Year

Avoided Structural Failure

Avoided Groundwater Costs

Avoided Total Costs

 $-

 $20

 $40

 $60

 $80

 $100

 $120

 $140

 $160

 $180

 $200

2015 2025 2035 2045 2055 2065 2075 2085 2095 2105

Undiscounted Benefits (Millions 2013$)

Year

Exhibit 9-R

Undiscounted Benefits by Year

Avoided Structural Failure

Avoided Groundwater Costs

Avoided Total Costs
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chapter, Exhibit 9-R presents both the original estimates of costs and benefits from those 

chapters and the revised estimates from Section 9.4 of this chapter under a 7% discount rate 

only.

Exhibit 9-Q

Incremental Costs and Benefits: Alternate Discount Rates

(millions of 2013$)

3% Discount Rate 7% Discount Rate

Present values:

Costs $23,200 $7,260

Benefits $8,550 $3,290

Net Benefits ($14,700) ($3,970)

Benefit Cost Ratio (BCR) 0.37 0.45

Annualized:

Costs $735 $509

Benefits $289 $232

Net Benefits ($446) ($277)

Benefit Cost Ratio (BCR) 0.39 0.46

Figures rounded to three significant digits. Totals may not sum due to rounding.

Exhibit 9-R below presents a comparison of the cost and benefit results in this chapter with the 

results presented in the earlier chapters of the RIA. Both sets of estimates in the table represent 

the modified D Prime regulatory approach of the CCR final rule, though the cost and benefit 

results in this chapter reflect one of the two alternative closure requirements for leaking unlined 

impoundments added to the CCR final rule that were not present in the RIA, in addition to the 

other revisions described in this chapter.431 The revisions have led to reduced costs and benefits 

and the estimated net costs of the rule have diminished by $86 million per year.

Exhibit 9-R

Comparison of Costs & Benefits Between Chapters 4 and 5 and this Chapter

(annualized values @7% discount rate in millions 2013$)

A B C

Row Cost & Benefit Items Chapters 4 & 5 Chapter 9

B. Regulatory Costs

B1 CCR Management Costs-Landfills $103 $96

B2 CCR Management Costs-Disposal Impoundments $215 $180

B3 CCR Management Costs-Storage Impoundments $393 $205

B4 Dewater & Capping Costs for Inactive Impoundments $27 $27

B8 State Agency Paperwork Burden Costs $1.36 $1.15

B9 Revised Total Costs (B7+B8) = $739 $509

C. Environmental & Economic Benefits

C1 Annualized Monetized Benefits for the CCR Final Rule $376 $232

D. Net Benefits and Benefit Cost Ratio (BCR)

D1 Net Benefits ($363) ($277)

D2 Benefit Cost Ratio (C1 / B9) 0.51 0.46

 

431 As noted above, the impacts of the second alternative closure requirement are presented solely as a sensitivity analysis due to 

uncertainty in the universe of plants that may choose to use this alternative closure requirement when faced with the CCR final 

rule.
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Note: s

 Due to the revisions to the universe of affected coal-fired electric utility plants discussed below in Section 9.2.1, the universe of 

inactive impoundments may change. However, the CCR final rule considers inactive impoundments subject to the rule only if they 

are located at plants that continue to operate. Correspondingly, it is unclear to what extent the RIA-identified universe of 111 

inactive impoundments is overstated due to plants initially identified as operating in Chapters 2, 3, and 4 that are indicated to 

close according to the NEEDS v.5.13 database; on the other hand, it is unclear to what extent this universe of 111 inactive 

impoundments is understated due to plants identified in NEEDS v.5.13 and discussed in Section 9.2.1 as closing all of their coalfired boilers but continuing to operate by means of other fuel sources resulting in an additional subset of inactive impoundments 

not considered in this RIA. As a simplifying assumption given this uncertainty, this chapter uses the same universe of inactive 

impoundments indicated in Chapters 2, 3, and 4.

 Figures are rounded to three significant digits; totals may not add due to rounding.

9.6 Sensitivity Analyses Related to Plants Fully Closing Coal-Fired Boilers 

Prior to and After 2015

Chapter 7 explores the sensitivity of the cost and benefit results in Chapters 3, 4, and 5 to 

various data and modeled uncertainties. The updates to the costs and in this chapter are not likely 

to affect the extent and patterns of uncertainty noted in Chapter 7, and this chapter does not 

update those analyses.

However, updates to data that reflect changes in the universe of operating plants, and changes to 

the compliance options for plants meeting certain criteria, present new sources of uncertainty in 

the modeling. Specifically, updated information in the NEEDS v.5.13 database and information 

released from the EPA Office of Water’s 2010 survey432 of the electric utility industry, identify a 

number of coal-fired electric utility plants expected to undergo full or partial closure in the 

coming years. This section provides three additional sensitivity analyses specific to the new 

assumptions and algorithms employed in this chapter:

 Expansion of analysis to consider plants reporting partial closure in NEEDS v.5.13: 

The impact of considering additional plants as undergoing full closure both before and 

after 2015, based on the number of plants reported as partially closing in NEEDS v.5.13.

 Inclusion of additional plants announcing full closure in the 2010 EPA Office of 

Water survey: The impact of considering additional plants as undergoing full closure 

both before and after 2015, based on the number of plants reported as fully closing in 

EPA Office of Water’s 2010 survey. As described in Section 9.3.2, the plants reported as 

fully closing after 2015 in the Office of Water survey that are not reported as doing so in 

NEEDS v.5.13 may serve as a proxy for the plants that may opt to employ Alternative 

Closure Requirement #2. 

 Combined impacts of expanding plant closures to include EPA Office of Water data 

and partial closures: The combined impacts of the methodologies applied in sensitivity 

analyses #1 and #2, by considering both full and partial closures to be full closures, 

across both the NEEDS v.5.13 and Office of Water survey data sources. 

 

432 Additional background information about EPA-OW’s 2010 survey of the electric utility industry is available from EPA’s 

website at http://water.epa.gov/scitech/wastetech/guide/steam-electric/questionnaire.cfm
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The costs and benefits presented in Section 9.4 reflect the most conservative scenario for 

expected coal-fired plant and coal-fired boiler closures, using only NEEDS v.5.13 data and only 

plants that have already announced that they are closing all coal-fired boilers. These three 

sensitivity analyses present lower cost estimates for the CCR final rule, based on an expanded set 

of plant closures both before and after 2015, the first year of the period of analysis in this RIA.

9.6.1 Description of Sensitivity Analyses

To consider the impact of the conservative (i.e., high-cost) approach taken for the primary 

estimates in this chapter, this section describes three interrelated sensitivity analyses that employ 

alternative options for identifying plants that are likely to permanently cease operating coal-fired 

generating units burning coal in the future either in the baseline or in response to regulatory 

compliance options:

9.6.1.1 Expansion of Analysis to Consider Plants Reporting Partial Closure in NEEDS 

v.5.13

This sensitivity analysis examines the potential impact on costs and benefits of partial closures at 

certain plants. Specifically, the NEEDS v.5.13 database identifies a number of plants that will 

close some, but not all, coal-fired electric generating units within the analysis period of the IPM 

model.

Because the relationship between electric generating unit (EGU or “boiler”) and CCR 

management unit is held as confidential business information and is unavailable for use in this 

chapter, it is not possible to isolate the specific CCR management units that will be affected by 

these partial closures.

To examine the extent of the impact of this uncertainty, this chapter considers a scenario in 

which those plants that a) are listed in the NEEDS v.5.13 database as closing EGUs either before 

or after 2016 and b) have on-site CCR disposal impoundments, will undergo full plant closure. If 

the EGUs are closing prior to 2016, the plants are considered fully closed prior to the period of 

analysis and removed from the analysis in both the baseline and post-rule scenarios; if the EGUs 

are closing after 2015, the plants are considered fully closed in the year that the first such EGU 

closes and treated similarly to plants fully closing all coal-fired EGUs after 2015 as described 

above in Section 9.2.1.2.

Because disposal of CCR in impoundments represents the highest-cost waste management option

for CCR, this analysis assumes that plants with CCR disposal impoundments are those that are 

most likely to undergo CCR management changes at the plant level. This approach attempts to 

reconcile the consideration that partially-closing plants may choose options other than incurring 

costs associated with CCR management change (i.e., wet-dry conversion costs) while avoiding 

the lower-cost (and less realistic) assumption that partially-closing plants would incur no 

incremental costs associated with the CCR final rule. For plants that are listed as partially closing 

but do not have disposal impoundments, the sensitivity analysis makes no changes in their 

operation or cost assumptions. 
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This sensitivity analysis results in adding nine plants and 31 CCR management units to the set of 

plants fully closing prior to 2016, and being removed from both baseline and post-rule costs. 433

Also, two plants are added to the set of plants which are modeled as fully closing after 2015.434

These two plants contain, across them, an additional four CCR management units (one landfill, 

two disposal impoundments, and one storage impoundment).435 Results for this sensitivity 

analysis are presented in Exhibit 9-S.

 

433 Overall, the NEEDS v.5.13 database identifies 24 coal-fired electric utility plants undergoing partial closure of their coal-fired 

electric generating units prior to 2016. 23 of these plants have on-site CCR management units. Across these 23 plants, there are 

89 CCR management units, including 24 landfills, nine disposal impoundments, and 56 impoundments. Correspondingly, if the 

low-cost assumption that each of these plants undergoes full closure prior to 2016 were sustained, the impact of this sensitivity

analysis would be somewhat more than double in terms of reductions relative to the main analysis presented in this chapter for 

landfill costs, and more than four times the reduction relative to the main analysis for storage impoundment costs. Disposal 

impoundment costs would remain unchanged, as all plants with disposal impoundments are considered fully closed in this 

sensitivity analysis, as described above.

434 Overall, the NEEDS v.5.13 database identifies eight coal-fired electric utility plants undergoing partial closure of their coalfired electric generating units after 2015. Seven of these plants have on-site CCR management units. Across these seven plants, 

there are 14 CCR management units, including six landfills, two disposal impoundments, and six storage impoundments. In a 

lower-bound cost scenario where all of these plants fully close all on-site management units after 2015, the reduction in costs 

under this sensitivity analysis would be approximately six times greater relative to the main analysis presented in this chapter for 

landfill costs and storage impoundment costs. 

435 Note that one of these two plants actually is listed as beginning partial closure in 2016 and ceasing all coal-related combustion 

in 2026. The sensitivity analysis revises the closing date for this plant from 2026 in the main analysis to 2016
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9.6.1.2 Inclusion of Additional Plants Announcing Full Closure in the 2010 EPA Office of 

Water Survey

This sensitivity analysis expands the number of plants closing in both the baseline and post-rule 

scenarios to include all plants that announce closure based on the 2010 mail survey of coal-fired 

electrical generating plants conducted by EPA’s Office of Water (EPA-OW); this list is more 

expansive than the list of plants identified in the NEEDS v.5.13 database.436

This sensitivity analysis employs the same methodology and assumptions that are used in the 

main analysis (i.e., the results presented in Section 9.4) and the expansion of the analysis to 

consider partial closures in NEEDS v.5.13 as full closures above. That is, plants announcing 

closure of all coal-fired electric generating units do not incur rule-related costs after the closure 

date, with the exception of closure costs and post-closure care. For the additional 15 plants that 

the EPA-OW’s 2010 survey identifies as fully closing prior to 2016, all costs are removed in 

both the baseline and the post-rule scenario. This removes all costs associated with a total of 98

plants from the baseline and post-rule scenarios that were considered in the RIA.

437 The 15 

plants that are only identified in the EPA-OW survey use a total of 31 CCR management units 

(six landfills, nine disposal impoundments, and 16 storage impoundments).

For plants expected to close after 2015 in the EPA-OW survey (again, defined as instances where 

all coal-fired electric generating units at a plant will close), this analysis ceases the calculation of 

incremental compliance costs after the closure date, with the exception of closure costs (i.e., 

capping and post-closure monitoring), and may provide a proxy for the behavior of plants that 

may obtain Alternative Closure Requirement #2 (i.e., extensions for replacement of 

impoundments due to near-term closure). An additional five plants are modeled as closing using 

this method, for a total of 16. These five plants contain, across them, an additional 18 CCR 

management units (two landfills, two disposal impoundments, and 14 storage impoundments).

Results for this sensitivity analysis are presented in Exhibit 9-S.

9.6.1.3 Combined Impacts of Expanding Plant Closures to Include EPA Office of Water 

Data and Partial Closures

This sensitivity analysis combines the impacts described in the two sensitivity analyses above: 

all plants undergoing full closure of their coal-fired electric generating units in either the NEEDS 

v.5.13 or 2010 Office of Water (EPA-OW) survey databases are removed from baseline and 

post-rule cost estimates (if closing before 2016) or close without retrofitting or replacing CCR 

management units (if closing after 2015). 

In addition, all plants with on-site disposal impoundments that are identified as undergoing 

partial closure of coal-fired electric generating units after 2015 in either the NEEDS v.5.13 or 

2010 EPA-OW survey data are modeled as fully closing those units. This is consistent with 

 

436 EPA Office of Water’s 2010 mail survey to power plants for the Steam Electric Power Generating Effluent Guidelines, 

available at http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm. The list of plants undergoing closure in the EPA-OW 

2010 survey exceeds the comparable list from the NEEDS v.5.13 database because the NEEDS database requires recognition of 

formal closure documents for a plant or EGU at a given date before including it as a closing/retiring EGU within the database.

437 13 of the additional 15 plants contain on-site CCR management units.
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Sensitivity Analysis 1, except that it includes plants identified in either NEEDS v.5.13 or EPAOW survey databases.

This sensitivity analysis adds an additional 31 plants to the list of plants fully closing prior to 

2016, bringing the total number of plants removed from the baseline and post-rule scenarios to 

114. These 31 plants contain, across them, an additional 88 CCR management units (18 landfills, 

25 disposal impoundments, and 45 storage impoundments). In addition, this sensitivity analysis 

adds 12 plants to the list of plants fully closing after 2015, resulting in a total of 23 such plants. 

These 12 additional plants contain, across them, an additional 40 CCR management units (6

landfills, 9 disposal impoundments, and 25 storage impoundments).438 Results for this 

sensitivity analysis are presented in Exhibit 9-S.

9.6.2 Results of Sensitivity Analyses

Exhibit 9-S below summarizes the results of the three sensitivity analyses outlined above. For 

reference, the exhibit includes the results of the main analysis in Exhibit 9-M.

Exhibit 9-S

Incremental CCR Management Costs – All CCR Management Units

(annualized costs: 7% discount rate; millions 2013$)

Cost Category

Main 

Analysis

Partial closures 

from NEEDS 

considered full 

closures

Full closures from 

EPA-OW survey data 

removed from 

affected universe

Full & partial 

closures from EPAOW survey data & 

NEEDS removed 

from affected 

universe

1. Landfill costs $89.3 $88.6 $82.2 $79.9

2. Disposal impoundment costs $176 $164 $169 $134

3. Storage impoundment costs $188 $183 $181 $167

4. Dewater & capping costs for inactive 

impoundments $26.7

5. Recordkeeping costs* $27.3 $26.4 $26.3 $24.6

Total Industry Costs = $508 $488 $485 $431

* Recordkeeping costs in sensitivity analyses are adjusted to account for the set of fully-closing plants prior to 2015, but not 

to account for the set of fully-closing plants that undergo closure during or after 2016. Given the low magnitude of 

recordkeeping costs and the relative dearth of plants undergoing closure after 2015, relative to the plants undergoing closure 

prior to 2016, this may slightly overestimate costs presented in this table under each sensitivity analysis.

Figures are rounded to three significant digits; totals may not add due to rounding.

In the main analysis summarized in Section 9.4, total annualized industry costs (at 7% discount 

rate) amount to $508 million. The three sensitivity analyses reduce these costs between 5% and 

15%. As noted in Section 9.2.1.2, the effect of incorporating full closures as indicated by the 

EPA-OW survey dataset is to reduce total industry costs by approximately five percent; 

correspondingly, it is highly unlikely that Alternative Closure Requirement #2, if employed by 

each of the plants indicated within the Office of Water survey database as closing after 2015 and 

 

438 As in Section 9.6.1.1, partial closure occurs before full closure for one plant identified as undergoing eventual full closure in 

the main analysis; for this plant the closure year is revised from 2026 in the main analysis to 2016 in this sensitivity analysis.
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availing themselves of Alternative Closure Requirement #2, would result in cost reductions of 

more than five percent5% relative to the results presented in Exhibit 9-M.

Benefits associated with these three sensitivity scenarios were also determined. Exhibit 9-T

illustrates the difference in benefits stemming from the situations outlined in Section 9.4. Total 

annualized benefits under the main analysis (at a 7% discount rate) were calculated to be $232

million, or $153 million net of beneficial use benefits. Results under the sensitivity analyses, net 

of beneficial use benefits vary from $133 million to $149 million annually, a reduction from the 

main analysis results of 13% to 3%, respectively (again, net of beneficial use benefits).

Exhibit 9-T

Incremental CCR Benefits, annualized @ 7% discount rate

(millions of 2013$)

Cost Category

Main Analysis

Sensitivity 1

(includes partial 

closures)

Sensitivity 2

(includes EPA-OW 

full closure data)

Sensitivity 3

(EPA-OW data & 

partial closures)

1. Impoundment release 

prevention1. Reduced CCR 

impoundment releases

$138 $133 $132 $123

2. Prevention ofReduced 

CCR groundwater 

contamination

$9.86 $10.1 $9.91 $10.3

3. IncreaseInduced future 

increase in CCR beneficial 

use1uses

1

4. Reduced incidence of 

cancer

$0.00273 $0 $0.00395 $0

5. Avoided IQ losses from 

mercury

$0.0246 $0 $0.0356 $0

6. Avoided IQ losses from 

lead $0.0164 $0 $0.0237 $0

7. Reduced need for 

specialized education $0 $0 $0 $0

8. Non-market surface water 

quality benefits $1.89 $0 $2.73 $0

9. Protection of threatened 

and endangered species $0.759 $0 $1.10 $0

10. Improved air quality from 

reduced air pollution from 

power plants (fuel switching)

$2.04 $0 $3.01 $0

11. Reduced groundwater 

withdrawals (conversion from 

wet to dry CCR handling)

$0.00273 $0 $0.00404 $0

Total Benefits2 = $153 $143 $149 $133

1 Benefits stemming from increased beneficial use were not calculated under the sensitivity analyses. We have left the value 

from the main analysis out of this table for comparison of the Total Benefits row.

2 Because benefits from increased beneficial use are not included in this table, the total benefits in this row will not match 

those presented in Exhibit 9-N.

Figures are rounded to three significant digits; totals may not add due to rounding.

It is important to note that while the sensitivity analyses in this chapter explore potential 

reductions to the CCR final rule costs estimated in Section 9.4, they do not represent lowerbound estimates of potential rule costs, because they do not consider two additional sources of 

uncertainty:
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 Plants that have not yet announced plans to permanently cease operating coal-fired 

generating units cease burning coal but may opt to (and apply for Alternative 

Closure Requirement #2) as an alternative to complying with the rule. While the 

analyses in this section may serve as a proxy for the cost-savings associated with the 

alternative closure requirement for plants that might permanently cease operating coalfired generating unitscease burning coal, by using, as a proxy for plants that might obtain 

the alternative closure requirement, plants that have already announced plans to 

permanently cease operating coal-fired generating unitscease burning coal. In effect, 

these plants are likely to cease burning coaloperations regardless of the rule. The analysis 

in this chapter does not attempt to identify additional plants that might make different 

operating decisions as a result of the rule. However, a forthcoming analysis willseparate 

EPA report, Appendix X (December 2014) reports the results of running the IPM for the 

CCR final rule and willcontains an estimate retirementsof potential future retirement of 

coal-fired boilers as a consequence of the CCR rule.

 Uncertainty related to future demand for coal. All of the analyses in the RIA and in 

this chapter consider only base casefuture coal useconsumption for electricity generation

forecasts from Department of Energy’spublished by the Energy Information 

Administration or from the IPM v.5.13, respectively. In fact, future demand for coal is 

uncertain, and alternative scenarios developed by EIA project lower (and higher) demand 

for coal in future years. The analyses in the RIA and in this chapter do not examine the 

impact of those assumptionsalternative scenarios.

9.7 Supplemental Analyses

This section briefly updates four supplemental analyses in Chapter 8 of the RIA:

1) The Federalism analysis for the CCR final rule, based on the revised cost estimates 

presented in Section 9.4 and a downward (more conservative) revision to the assumed 

utilization factor for coal-fired electric utility plants; 

2) The SBRFA analysis for the CCR final rule, based on the revised cost estimates 

presented in Section 9.4 and a downward (more conservative) revision to the assumed 

utilization factor for coal-fired electric utility plants; 

3) The demographic analysis (minority and low-income populations) for the CCR final rule, 

based on the revised affected universe described in Section 9.1.2; and

4) The child population analysis for the CCR final rule, based on the revised affected 

universe described in Section 9.1.2.

This chapter concludes with a state-by-state examination of costs and benefits associated with 

the CCR final rule as estimated in this chapter.

9.7.1 Update to Federalism Analysis of CCR Final Rule
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Based on the estimated regulatory costs for coal-fired electric utility plants owned by state and 

local governments, Chapter 8 concludes that the rule is likely to exceed $100 million in 

annualized direct costs to the private sector, and is likely to exceed $25 million in annualized 

costs to state and local governments. Exhibit 9-U below replicates Exhibit 8-E, updated to 

account for the assumption and data changes described in this chapter. The effect of the updates 

is to lower the annualized cost of the rule to state and local governments from approximately $39 

million to under $36 million.

In addition to the methodological updates discussed earlier in this chapter, the final row of 

Exhibit 9-U also incorporates an adjustment to the utilization rate used to estimate revenues for 

entities owning electric utility plants. In Section 8.2.2, an average electric utility industry 

capacity utilization factor of 86.1 percent% is applied to estimate revenues for each owner entity; 

this chapter revises this estimate downward to 56.7 percent% for consistency with EPA’s IPM 

analysis for the CCR final rule.439 While this parameter revision decreases estimated revenue for 

owner entities, and thus increases the likelihood of significant impacts, the decrease in total 

estimated costs as shown in Section 9.4 relative to Chapter 4 more than offsets this revision.

Exhibit 9-U shows that the majority of the reduction in total incremental cost for CCR 

management between Chapter 8 and this chapter accrues to the private sector; state and local 

government costs decrease by less than 8% between the RIA and this chapter. However, while 

direct annualized compliance costs to state and local governments are estimated to exceed $25 

million, they do not exceed 1% of electric utility sales from state and local governments, as 

estimated by multiplying the nameplate capacity of all plants owned by state and local 

government entities by the prevailing electric utility utilization rate and the average statewide 

price of electricity (see Chapter 8 of the RIA for additional information). While the proportion 

of compliance costs to state/local government estimated revenues increased as a result of lower 

estimated revenues from use of a lower utilization factor in this chapter, this proportion 

continues not to exceed one percent.

There are 57 State and local governments which own 68 coal-burning power plants, or 16% of 

the 414 electric utility plants expected to be affected by this rule. These 57 State and local 

governments consist of 7 State governments, 31 small municipality governments, 18 non-small 

municipal governments, and 1 (small) county government owner.

 

439 The original 86.1 percent% factor was reported reported in the April 16, 2014 Federal Reserve Statistical Release G.17 

“Industrial Production and Capacity Utilization” data for Utilities Available online at 

http://www.federalreserve.gov/releases/g17/Current/default.htm. However, this factor includes a broader universe of power 

plants,utility plants burning different types of fuel (e.g., coal, crude oil, natural gas, nuclear, biomass, hydro, wind, etc.), rather 

than solely coal-fired electric utility plants. For consistency with EPA’s IPM analysis for the CCR final rule, the 56.7 percent%

coal-fired electricity generation capacity utilization factor is based on 2012 annual data provided by EIA in the Electricity Power 

Monthly data publication “Table 6.7.A Capacity Factors for Utility Scale Generators Primarily Using Fossil Fuels, January 2008-

July 2014,” released July 2014 on EIA’s website at 

http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_6_07_a.The 2012 data year for this capacity factor 

corresponds to the same 2012 EIA data year on which the CCR tonnages in this RIA are based.
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Exhibit 9-U

UMRA and Federalism Tests for CCR Final Rule 

Annualized Costs at 7% Discount Rate (millions of 2013$)a

Type of Direct Compliance Cost Original - Chapter 8 Revised - Chapter 9

Average annualized cost per owner entity $3.05 $2.09

UMRA Test 

Private sector $100 million direct cost threshold test $617.27 $436.21

State/local government $100 million direct cost threshold 

testb 

$38.73 $35.84

Federalism Test

$25 million threshold test: sub-total state/local 

government cost $38.73 $35.84

1% Test: State/local government cost as percentage of 

state/local government electric utility annual revenues 0.16%c 0.23%c

a Average annualized costs are calculated with a 7% discount rate over 100 years from 2015 to 2114.

b Remainder Federal government costs represent costs associated with Federally-owned electric utility plants (i.e., 

Tennessee Valley Authority) which are not subject to either the UMRA or Federalism tests. Therefore, the sub-total private 

sector direct cost plus the state/local government direct cost does not add-up to the total annual cost; the remainder cost is 

for the Federally-owned plants. 

c State/local government electric utility annual revenues estimated by multiplying the nameplate capacity of each plant 

owned by a state/local government entity by the prevailing electric utility utilization rate and the average statewide price 

of electricity for the state in which the plant is located, and then summing this estimate across all plants owned by 

state/local government entities. In Chapter 8, a utilization factor of 86.1 percent% was applied; based on data for the 

NAICS 22 utilities sector (which includes all electricity generation fuel types); this chapter uses a revised factor of 56.7

percent% instead based on data only for coal-fired electric utility plants.

9.7.2 Update to SBREFA Analysis of CCR Final Rule

In accordance with the analysis in Section 9.7.1 above, Exhibit 9-V represents a revised Exhibit

8-B. The exhibit summarizes regulatory costs as a percent of revenue across the electric utility 

plant owner entities considered to be “small” entities. The net effect of a decrease in costs (as 

described throughout this chapter and shown in Section 9.4 and a decrease in the capacity 

utilization factor used to estimate entity revenues) is to somewhat increase the overall 

compliance costs as a percent of overall revenues. However, the SISNOSE threshold triggered 

by each entity type does not change as a result of the revisions in this chapter. Furthermore, 

consistent with the RIA’s original results described in Chapter 8, Section 8.2.3, of the 81 small 

entities likely to be affected, six small entities may experience costs exceeding one percent1% of 

revenues and one small entity may experience costs exceeding three percent3% of revenues, the 

revisions in this chapter do not alter these results.

The small entities directly regulated by this final rule consist of one small county, 31 small cities, 

32 small companies, and 13 small cooperative owner entities that own at least one coal-burning 

power plant. There are 91 coal-burning power plants that are owned by the 77 small owner 

entities. Those plants fall into the following categories: one small county plant, 31 small city 

plants, 42 plants owned by small companies, and 17 small cooperative plants.
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Exhibit 9-V

Summary of Regulatory Cost Estimates According to Electric Utility Plant Owner Entity 

Size/Type Categorya

Type of Entity

Total Costs 

($M)

Total Revenue 

($M)b

Cost as Percent of 

Revenue

SISNOSE 

Threshold

Small County $0.18 $9.73 1.85% < 3%

Small City $4.66 $1,462.10 0.32% < 1%

Small Company $18.09 $7,168.72 0.25% < 1%

Small Cooperative $23.01 $5,343.06 0.43% < 1%

Small Entites Total $45.93 $13,983.61 0.33% < 1%

Notes: 

a Cost figures are given in million 2013$ annualized at a seven percent7% discount rate over 100-year period 2015 to 2114 .

b This chapter applies a capacity utilization factor of 56.7 percent% based on data for coal-fired electric utility plants, relative to 

the factor of 86.1 percent% applied in Chapter 8. which is based on data for the much broader NAICS 22 utilities sector (which 

includes all electricity generation fuel types).

9.7.3 Update to Demographic Analysis: Minority and Low-Income Population 

Statistics (Executive Order 12898)

In accordance with Section 9.1.2, this chapter removes 64 plants from the universe of 478 plants 

affected by the CCR final rule as described in Chapter 2, because these 64 plants retire or close 

all of their coal-fired electric generating units prior to 2016 according to the NEEDS v.5.13 

database. Correspondingly, this section revises the count of plants and surrounding populations 

described in Section 8.3. However, the findings in Section 8.3 remain virtually unchanged: 

populations surrounding plants with surface impoundments appear to have percentages of 

minority and low-income residents roughly comparable to the nationwide average, populations 

surrounding plants with landfills do not.

For the population as a whole, 24.8% belong to a minority group and 11.3% fall below the 

Federal Poverty Level. For the population living within one mile of plants with surface 

impoundments, 16.1% belong to a minority group and 13.2% live below the Federal Poverty 

Level. These minority and low-income populations are not disproportionately high compared to 

the general population. The percentage of minority residents of the entire population living 

within the catchment areas downstream of surface impoundments is disproportionately high 

relative to the general population, i.e., 28.7% versus 24.8% for the entire population. Also, the 

percentage of the population within the catchment areas of surface impoundments that is below 

the Federal Poverty Level is disproportionately high compared with the general population, i.e., 

18.6% versus 11.3% nationally.

Comparing the population percentages of minority and low-income residents within one mile of 

landfills to those percentages in the general population, EPA found that minority and low-income 

residents make up a smaller percentage of the populations near landfills than they do in the 

general population, i.e., minorities comprised 16.6% of the population near landfills versus 

24.8% nationwide, and low-income residents comprised 8.6% of the population near landfills 

versus 11.3% nationwide. In summary, although populations within the catchment areas of plants 

with surface impoundments appear to have disproportionately high percentages of minority and 
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low-income residents relative to the nationwide averages, populations surrounding plants with 

landfills do not. Because landfills are less likely than impoundments to experience surface water 

runoff and releases, catchment areas were not considered for landfills.

9.7.4 Update to Child Population Statistics (Executive Order 13045)

In accordance with Section 9.1.2, this chapter removes 64 plants from the universe of 478 plants 

affected by the CCR final rule as described in Chapter 2, because these 64 plants retire or close 

all of their coal-fired electric generating units prior to 2016 according to the NEEDS v.5.13 

database. Correspondingly, this section revises the count of plants and surrounding populations 

described in Section 8.4. However, the findings in Section 8.4 remain virtually unchanged: the 

distribution of risk across the children’s demographic is not likely to change significantly as a 

result of the CCR final rule.

The percent of all plants operating as of 2016 according to NEEDS v.5.13 with impoundments 

that exceed the national proportion of children is 38.1% (86 of 226 plants for which population 

data are available), suggesting that reductions in risk at these plants would benefit children.

Moreover, requirements under the rule will reduce risks at all plants. The CCR rule is therefore 

not expected to create additional or new risk to children.

9.7.5 State-by-State Summary of Costs & Benefits

OMB’s 2003 Circular A-4: Regulatory Analysis guidance to Federal regulatory agencies for 

conducing cost-benefit analyses of regulations, directs agencies to describe distributional effects 

of both costs and benefits, including geographic distribution. Below is an excerpt from Circular 

A-4 (boldface added for emphasis):

Those who bear the costs of a regulation and those who enjoy its benefits often 

are not the same people. The term "distributional effect" refers to the impact of a 

regulatory action across the population and economy, divided up in various ways 

(e.g., income groups, race, sex, industrial sector, geography)........ Your 

regulatory analysis should provide a separate description of distributional effects 

(i.e., how both benefits and costs are distributed among sub-populations of 

particular concern) so that decision makers can properly consider them along 

with the effects on economic efficiency. Executive Order 12866 authorizes this 

approach.440

The RIA evaluates distributional effects in a number of ways, including consideration of impacts 

on small businesses and tribal governments, potential effects on disproportionately poor orlow 

income and minority communities, and impacts on children’s health, as well as the forthcoming. 

A separate EPA report (December 2014) presents an analysis using the IPM model to estimate 

generation and electricity pricepotential future impacts of the CCR final rule on consumers.

the U.S. electricity market on a region-by-region basis.

 

440 OMB 2003 Circular A-4, accessed at http://www.whitehouse.gov/omb/circulars_a004_a-4.
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In addition to these analyses, this chapter provides a very rough overview of the possible 

distribution of costs across states of the total annualized costs and benefits of the RIA, as 

calculated in the cost model and benefits analyses. Exhibits 9-W and 9-X below provide stateby-state subtotals of the estimated CCR final rule annualized costs and benefits at 7% and 3% 

discount rates, respectively. Total costs and benefits across all states equal the total rule costs 

presented in Section 9.4, specifically Exhibit 9-M.

This state-by-state breakout is at best a rough approximation of the potential distribution of costs 

for a number of reasons:

 Costs and benefits reflect probabilistic modeling of potential future releases from existing 

impoundments: management decisions incurring differential costs for the CCR final rule 

are modeled based on probabilistic estimates of cumulative likelihoods that unlined 

impoundments will incur groundwater contamination events in a given year. While these 

represent potentially robust national average costs, this methodology does not serve as an 

appropriate basis for assigning specific costs to specific plants, especially because the 

underlying probabilities for groundwater contamination event occurrence based on 

impoundment age were derived via national averages, rather than site-specific, plantspecific, or state-/location-specific examinations of groundwater contamination event 

likelihood. Furthermore, because benefits estimates in the RIA and this chapter are based 

on a probabilistic assessment of impoundment closure in a given year, as well as 

probabilistic rates of impoundment releases, they too do not serve as an appropriate basis 

for assigning specific benefits to specific plants.

 Costs do not fully account for plant-specific differences in operations and costs: the 

assumptions and inputs to the CCR RIA cost model use national average estimates of 

CCR pollution control costs for standard operating units, and apply these according to 

specific information about existing units and state regulatory baselines. However, the 

costs do not reflect comprehensive, plant-specific information about the design, age, and 

configuration of boilers and waste management systems. Therefore, while on a national 

average basis these costs are consistent with practice at coal-fired boilers, a given plant 

may have cost structures that differ significantly from national averages and from plants 

in other states. As a result, the state-by-state subtotal costs likely fail to capture 

significant sources of deviations in incremental regulatory costs across states.

 Inter-state CCR disposal location uncertainty: similar to average unitized costs, estimated 

industry regulatory compliance costs consider state average off-site disposal costs for 

each plant. The analysis does not include a spatial analysis or consider whether lowercost disposal options in nearby states might represent feasible alternatives to in-state 

disposal. Given the long analytic time frame and the fact that off-site disposal decisions 

are most likely to be driven by releases from impoundments if and when these occur, the 

CCR cost model (and this chapter) does not attempt to determine a least-cost function 

based on specific off-site landfill(s). Again, while in-state disposal costs represent a 

reasonable basis for future average costs in a highly uncertain environment, they may be

less appropriate in determining accurate state-by-state costs. In cases where many states 

are in relative proximity, or where one state in a region contains most of the commercial 
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industrial waste landfill capacity, the in-state cost assumption may be particularly 

misleading.

 Benefits associated with CCR impoundments: The most significant monetized benefits 

of the CCR rule are the impacts avoiding future CCR impoundment releases. These lowprobability, high-impact events are modeled using standardized assumptions about 

release risk and capacity at existing impoundments, but the actual reductions in risk 

associated with the rule may be distributed quite differently.

In total, these uncertainties limit the insights that can be gained from a state-by-state breakout of 

cost and benefit estimates, and render benefit-cost ratio particularly uninformative (even 

misleading), but Exhibits 9-W and 9-X below do provide summary information about the 

number of plants affected in each state and the potential magnitude of impacts associated with 

the regulation.
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Exhibit 9-W

State-by-State Summary of CCR Rule Costs and Benefits (7% discount rate)1

A B C D E F G H

State

2012 

count of 

coal-fired 

electric 

utility 

plants

2012 

annual 

CCR 

disposal

(LFs + 

SIs)

(1,000 

tons)

Plants 

incurring 

costs 

under 

CCR 

Final 

Rule2

Count of on-site 

CCR management 

units incurring 

costs under CCR 

Final Rule (active 

+ inactive SIs)

CCR Final Rule

Annualized 

regulatory 

costs

($millions) Notes

Annualized 

regulatory 

benefits, 

excluding 

beneficial 

use

($millions)3

1 AK 2 26,974 1 1 $1.0 $0.3

2 AL 10 1,561,900 9 34 $34.3

2 plants incur > 61% of 

costs; partially close per 

OW data

$22.4

3 AR 5 361,700 3 5 $2.0 $0.2

4 AZ 6 2,386,300 5 18 $17.2 1 plant incurs > 29% of 

costs $4.2

5 CA 8 47,700 0 0 $0 $0

6 CO 14 735,818 9 40 $5.0 $0.7

7 CT 1 0 0 0 $0 $0

8 DC 0 0 0 0 $0 $0

9 DE 2 210,158 2 3 $1.5 <$0.1

10 FL 14 815,254 12 29 $9.8

1 plant incurs > 45% of 

costs; partially closes 

per NEEDS data

$1.3

11 GA 11 1,288,452 10 34 $19.5 1 plant incurs > 29% of 

costs $13.2

12 HI 2 0 0 0 $0 $0

13 IA 17 655,366 16 46 $10.4 $1.2

14 ID 0 0 0 0 $0 $0

15 IL 22 614,992 16 52 $23.5 1 plant incurs > 29% of 

costs $7.5

16 IN 26 2,949,167 18 78 $38.3

3 plants incur > 44% of 

costs $8.6

17 KS 8 648,376 7 23 $4.6 $2.0

18 KY 20 7,336,518 16 53 $60.1

5 plants incur > 66% of 

costs; one of which 

partially closes per OW 

data

$7.0

19 LA 4 1,368,400 4 17 $3.1 <$0.1

20 MA 3 0 2 9 $1.3 <$0.1

21 MD 8 6,600 4 7 $1.2 <$0.1

22 ME 1 0 0 0 $0 $0

23 MI 22 830,318 11 24 $9.7 $6.1

24 MN 14 601,800 7 22 $10.9

1 plant incurs > 26% of 

costs $1.1

25 MO 20 582,638 18 49 $19.0 $6.5

26 MS 5 117,900 4 12 $2.2 $0.4

27 MT 5 896,766 4 17 $4.4 $4.5

28 NC 19 997,500 11 34 $14.7 $16.9

29 ND 7 941,300 7 30 $3.6 $0.8

30 NE 7 504,704 7 12 $5.4 $0.2

31 NH 2 1,100 1 3 $0.7 <$0.1

32 NJ 6 0 2 6 $1.5 <$0.1

33 NM 4 1,381,600 2 12 $13.2

1 plant incurs > 94% of 

costs; fully closes per 

OW data

<$0.1

34 NV 3 162,000 3 11 $1.3 $0.2

35 NY 9 292,510 4 10 $1.3 $0.2

36 OH 25 3,889,400 13 38 $42.0 3 plants incur > 76% of 

costs $8.5

37 OK 6 119,500 5 13 $2.6 $0.7

38 OR 1 37,500 1 1 $0.1 <$0.1

39 PA 31 3,041,950 12 49 $37.2

1 plant incurs > 83% of 

costs $10.7

40 PR 1 0 0 0 $0 $0

41 RI 0 0 0 0 $0 $0

42 SC 12 710,500 8 26 $6.1 $1.7
October 2014 EPA Interagency Review Draft: Do Not Circulate or Cite

Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

9-56

Exhibit 9-W

State-by-State Summary of CCR Rule Costs and Benefits (7% discount rate)1

A B C D E F G H

State

2012 

count of 

coal-fired 

electric 

utility 

plants

2012 

annual 

CCR 

disposal

(LFs + 

SIs)

(1,000 

tons)

Plants 

incurring 

costs 

under 

CCR 

Final 

Rule2

Count of on-site 

CCR management 

units incurring 

costs under CCR 

Final Rule (active 

+ inactive SIs)

CCR Final Rule

Annualized 

regulatory 

costs

($millions) Notes

Annualized 

regulatory 

benefits, 

excluding 

beneficial 

use

($millions)3

43 SD 2 70,407 1 2 $0.9 <$0.1

44 TN 7 899,400 5 18 $8.3 $8.7

45 TX 19 6,314,100 19 83 $37.0 2 plants incur > 37% of 

costs $4.4

46 UT 6 1,458,888 5 18 $9.1 $0.3

47 VA 16 552,361 6 12 $11.0 $2.8

48 VT 0 0 0 0 $0 $0

49 WA 1 0 1 1 <$0.1 <$0.1

50 WI 16 151,224 11 31 $5.7 $0.9

51 WV 17 5,796,225 9 25 $14.7 $8.8

52 WY 11 1,243,300 5 21 $11.3 1 plant incurs > 34% of 

costs $2.8

Summary statistics:

Minimum 0 0 0 0 $0 $0

Maximum 31 7,336,518 19 83 $60.1 $22.4

Mean 9 1,011,703 6 20 $9.7 $3.8

Median 7 567,500 5 15 $4.5 $1.2

Totals 478 52,608,565 316 1,029 $506.6 $152

1 Values may not sum to the reported totals due to rounding.

2 A plant may have appear on EIA’s list of 478 coal-fired electric utility plants but not incur any costs under the CCR final rule if: 1) the plant 

closes prior to 2016, as identified by the IPM NEEDS v.5.13 database; 2) the plant reports no on-site CCR disposal toin the EIA database and thus 

does not dispose of any CCR in on-site management units; or, 3) the plant is in full compliance with all regulatory requirements of the CCR rule as 

applicable to its CCR management units.

3 These benefits do not include the category of CCR beneficial use.
October 2014 EPA Interagency Review Draft: Do Not Circulate or Cite

Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

9-57

Exhibit 9-X

State-by-State Summary of CCR Rule Costs and Benefits (3% discount rate)1

A B C D E F G H

State

2012 

count of 

coal-fired 

electric 

utility 

plants

2012 

annual 

CCR 

disposal

(LFs + 

SIs)

(1,000 

tons)

Plants 

incurring 

costs 

under 

CCR 

Final 

Rule2

Count of on-site 

CCR management 

units incurring 

costs under CCR 

Final Rule (active 

+ inactive SIs)

CCR Final Rule

Annualized 

regulatory 

costs

($millions) Notes

Annualized 

regulatory 

benefits, 

excluding 

beneficial 

use

($millions)3

1 AK 2 26,974 1 1 $1.3 $0.5

2 AL 10 1,561,900 9 34 $29.8

2 plants incur > 61% of 

costs; partially close per 

OW data

$29.4

3 AR 5 361,700 3 5 $3.4 $0.3

4 AZ 6 2,386,300 5 18 $51.8 1 plant incurs > 29% of 

costs $3.4

5 CA 8 47,700 0 0 $0 $0

6 CO 14 735,818 9 40 $5.0 $0.7

7 CT 1 0 0 0 $0 $0

8 DC 0 0 0 0 $0 $0

9 DE 2 210,158 2 3 $3.0 <$0.1

10 FL 14 815,254 12 29 $9.1

1 plant incurs > 45% of 

costs; partially closes 

per NEEDS data

$1.5

11 GA 11 1,288,452 10 34 $14.1 1 plant incurs > 29% of 

costs $17.6

12 HI 2 0 0 0 $0 $0

13 IA 17 655,366 16 46 $12.6 $1.2

14 ID 0 0 0 0 $0 $0

15 IL 22 614,992 16 52 $24.8 1 plant incurs > 29% of 

costs $9.1

16 IN 26 2,949,167 18 78 $39.9 3 plants incur > 44% of 

costs $11.7

17 KS 8 648,376 7 23 $10.2 $2.2

18 KY 20 7,336,518 16 53 $125.8

5 plants incur > 66% of 

costs; one of which 

partially closes per OW 

data

$5.0

19 LA 4 1,368,400 4 17 $6.1 <$0.1

20 MA 3 0 2 9 $0.7 <$0.1

21 MD 8 6,600 4 7 $1.4 <$0.1

22 ME 1 0 0 0 $0 $0

23 MI 22 830,318 11 24 $9.7 $7.6

24 MN 14 601,800 7 22 $17.6 1 plant incurs > 26% of 

costs <$0.1

25 MO 20 582,638 18 49 $21.0 $7.3

26 MS 5 117,900 4 12 $1.8 $0.5

27 MT 5 896,766 4 17 $4.4 $5.0

28 NC 19 997,500 11 34 $13.0 $19.8

29 ND 7 941,300 7 30 $5.1 $1.0

30 NE 7 504,704 7 12 $10.0 $0.4

31 NH 2 1,100 1 3 $0.8 <$0.1

32 NJ 6 0 2 6 $1.2 <$0.1

33 NM 4 1,381,600 2 12 $24.7

1 plant incurs > 94% of 

costs; fully closes per 

OW data

<$0.1

34 NV 3 162,000 3 11 $0.9 $0.2

35 NY 9 292,510 4 10 $1.5 $0.2

36 OH 25 3,889,400 13 38 $55.3 3 plants incur > 76% of 

costs $7.9

37 OK 6 119,500 5 13 $2.7 $0.8

38 OR 1 37,500 1 1 <$0.1 <$0.1

39 PA 31 3,041,950 12 49 $49.6 1 plant incurs > 83% of 

costs $11.2

40 PR 1 0 0 0 $0 $0

41 RI 0 0 0 0 $0 $0

42 SC 12 710,500 8 26 $7.5 $2.0
October 2014 EPA Interagency Review Draft: Do Not Circulate or Cite

Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

9-58

Exhibit 9-X

State-by-State Summary of CCR Rule Costs and Benefits (3% discount rate)1

A B C D E F G H

State

2012 

count of 

coal-fired 

electric 

utility 

plants

2012 

annual 

CCR 

disposal

(LFs + 

SIs)

(1,000 

tons)

Plants 

incurring 

costs 

under 

CCR 

Final 

Rule2

Count of on-site 

CCR management 

units incurring 

costs under CCR 

Final Rule (active 

+ inactive SIs)

CCR Final Rule

Annualized 

regulatory 

costs

($millions) Notes

Annualized 

regulatory 

benefits, 

excluding 

beneficial 

use

($millions)3

43 SD 2 70,407 1 2 $2.16 <$0.1

44 TN 7 899,400 5 18 $7.7 $10.2

45 TX 19 6,314,100 19 83 $82.5 2 plants incur > 37% of 

costs $6.0

46 UT 6 1,458,888 5 18 $24.7 <$0.1

47 VA 16 552,361 6 12 $12.2 $3.0

48 VT 0 0 0 0 $0 $0

49 WA 1 0 1 1 <$0.1 <$0.1

50 WI 16 151,224 11 31 $6.6 $1.3

51 WV 17 5,796,225 9 25 $15.9 $10.8

52 WY 11 1,243,300 5 21 $16.2 1 plant incurs > 34% of 

costs $2.5

Summary statistics:

Minimum 0 0 0 0 $0 $0

Maximum 31 7,336,518 19 83 $125.8 $29.4

Mean 9 1,011,703 6 20 $14.1 $4.3

Median 7 567,500 5 15 $5.6 $1.4

Totals 478 52,608,565 316 1,029 $733.6 $172

1 Values may not sum to the reported totals due to rounding.

2 A plant may have appear on EIA’s list of 478 coal-fired electric utility plants but not incur any costs under the CCR final rule if: 1) the plant 

closes prior to 2016, as identified by the IPM NEEDS v.5.13 database; 2) the plant reports no on-site CCR disposal toin the EIA database and 

thus does not dispose of any CCR in on-site management units; or, 3) the plant is in full compliance with all regulatory requirements of the CCR 

rule as applicable to its CCR management units.

3 These benefits do not include the category of CCR beneficial use.