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



## 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

October Decem

ber 2014October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

i 

## Table of Contents

Acronyms

................................ ................................ ................................ ................................ ...... iii Acknowledgements

................................ ................................ ................................ .......................... v Foreword

................................ ................................ ................................ ................................ ........ v i 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

- 4 3

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

- 201 4)

....................... 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

- 18 19

Chapter 2: Affected Universe and Analytic Framework for the RIA

................................ ......... 2

- 1

2.1 Directly Affected Industries

................................ ................................ ...................... 2

- 1

2.2 Ind irectly 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 t he 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 C CR 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 Poll ution 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

- 17 18

5.3 Increased In duced Increase in Futur e Annual CCR Beneficial Use

.................... 5

- 22 24

5. 4 Reduced Incidence of Cancer

................................ ................................ ............. 5

- 29 30

5. 5 Mitigated IQ Losses from Mercury

................................ ................................ .... 5

- 31 32

5. 6 Reduced Lead Exposure

................................ ................................ ..................... 5

- 31 33

5. 7 Reduced Need for Specialized Education

................................ ........................... 5

- 32 34

5. 8 Non

- Market Benefits from Surface Water Quality Improvements

..................... 5

- 33 34

5. 9 Protection of Threatened and Endangered Species

................................ ............. 5

- 34 35

5. 10 Improved Air Qua lity

................................ ................................ ........................ 5

- 35 36October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

ii 5. 11 Reduced Groundwater Withdrawals

..................... 5

- 36 from Conversion to Dry CCR Handling

................................ ................................ ................................ ......................... 5

- 37

5. 12 Conclusion

................................ ................................ ................................ ......... 5

- 37 38

Chapter 6: Non

- Monetized (Qualitative) Benefits

................................ ................................ ...... 6

- 1

6.1 Reduce Reduce d 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 Reduce Reduce d Hazard Dread of Citizens Residing Near CCR Impoundments

... 6

- 6 7

6.4 Reduce Reduce d Cancer and Non

- Cancer Health Effects Resulting from

Recreational Water Use

................................ ................................ ................................ . 6

- 6 7

6.5 Re duce Re duce d Sediment Contamination

................................ ............................. 6

- 7 8

6.6 Reduce Reduce d Water Treatment Costs for Drinking and Irrigation Water

.......... 6

- 8 9

6.7 Improve Improve d Commercial Fishing Yields and Harvest Quality

................... 6

- 8 10

6.8 Increased Participation in Water

- Based Recreation

................................ ............. 6

- 9 10

6.9 Reduce Reduce d Fish Impingement and Entrainment Mortality

........................... 6

- 9 11 6.10 Increased Property Values Surrounding Electric Utility Plants

......................... 6

- 10 11

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: Complianc e and Cost Data Limitations

............................. 7

- 21

7.4 Specific Data Uncertainty Factors in th is RIA

................................ ....................... 7

- 2 5 7.5 Summary of Uncertaint y Factors

................................ ................................ ............ 7

- 26

C hapter 8 : Other Required Analyses

................................ ................................ .......................... 8

- 1

8 .1 Electricity Price and Energy Market Impact s

................................ ........................... 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

- 1 2

8 .5 Unfunded Mandate Reform Act (UMRA) and Federalism Implications Analysis (Executive Order 13132)

................................ ................................ ......................... 8

- 1 4

C hapter 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 Leaki ng Unlined CCR Impoundments

................................ .............. 9

- 18 9.4 Updated Cost & Benefit Results for CCR Final Rule

................................ ............. 9

- 25 9.5 Summary of the Cost and Ben efits of the CCR Final Rule

................................ 9

- 33 50 9.6 Sensitivity An a lyses Related to Plants Fully Closing Coal

- Fired Boilers Pri or to
and After 2015

................................ ................................ ................................ ........... 9

- 34 51October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

iii 9.7 Supplemental Analyses

................................ ................................ ....................... 9

- 40 57October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

iv 

## 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 Limitat i o n 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

M SH A 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 SystemOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

v 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

OSM RE 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 PayOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

vi 

## 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 certa in 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 RI A 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 (E IA) 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 alterna tive regulatory approaches (i.e., Subtitle C special waste

, Subtitle D non

hazardous 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 E P

- 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 Representa tive (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 Nick erson, 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 .”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

vii 

## Foreword : Key U pdates 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 l eaking, 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 requirem ents was essential. EPA’s court

- ordered deadline for the CCR final rule precluded revising the entire RIA and its Append ices (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 assumption s, 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 mod ifications 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 tha t 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 p lanning 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 co al consumption :

o Adopts Replaces 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’s from EPA's power sector modeling platform v.5.13 (developed for application of the Integrated Planning Mo del (IPM)).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

viii 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 C CR 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 rec eiving 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 univers e 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 as sumption 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

.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

ix 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 im poundments 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 Mor e 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 sensiti vity 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 Executiv e 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 ofOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

x the RIA (the Federalism analysis, the small business impacts analysis, the demographic analysis

of low

- inco me 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.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

ES

- 1 

## 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 an d cost estimates to reflect the updated assumptions, data, and rule requirements was essential, thus EPA has updated these estimates in this Executive Summary. However, t o meet the court

- ordered schedule for EPA’s development and promulgation of the CCR fi nal 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 modific i ations 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 R IA 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 (CC R) 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 “Im proving Regulation and Regulatory Review,” and consistent with the White House Office of Management and Bu dget’s (OMB) 2003 “Circular A

- 4: Regulatory Analysis.”

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

f inal 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 esti mates. 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 th e 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;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

ES

- 2  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 benef its 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 informa tion

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 ver sion of the D

- prime regulatory approach considered for public comment in the June 2010 proposed CCR rule

. 2 This RIA evaluates only th e 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 regulat ing CCR in order to: respond to public petitions (2004, 2009) to EPA and Congressional requests (2010) fo r EPA regulation of CCR disposal ; EPA is regulating CCR in order to respond to public petitions (2004, 2009) to EPA f or EPA regulation of CCR disposal to: prevent continued reduce CCR contamination of ground water and surface water; prevent reduce future CCR impoundment structural failures (breakages); reduce continued public exposure to CCR fugitive dust; and correct negative externalities and inadequate and asymmetric inform ation about CCR disposal risks.

Specifically, the CCR final rule regulate s CCR under RCRA Subtitle D as a non

- hazardous

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

landfills and CCR surface im poundments. 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 healt h

- based thresholds

. U nlined CCR impoundments with chemic al 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 require ments, and post

- closure care. Specifically , u nder 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.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

ES

- 3 will set national criteria for landfills and surface impoundments that manage CCR after the final

rule goes into effect in early 201 5 , the effective date assumed for this RIA . Groundwater monitoring is required one year after the effective date of the rule ( 201 6 ). Based on the regulatory compliance cost estimation in this RIA, it is likely that the liner requirements

associated with unlined leaking impoundments whose ground water 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 open ing 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 system s (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. C orrective action for CCR contaminated groundwater (groundwater clean

- up) ; 11. Reporting and recordke eping; 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 conver t 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 c losure capping

.

The CCR final rule also allows for two compliance alternative closure requirements for certain subsets of electric utility plants with leaking unl ined 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 permanent ly cease operation cessation o o f a coal

- fired boiler(s) by a date un certain

, a 5

- year a 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 requireme nt only as a sensitivity analysis.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

ES

- 4 

### 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 th e 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, t his RIA estimate s 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 )

fe es, and natural resource damages due to avoided releases from CCR impoundment s, including

those from structural failure s ; 3 reduction in CCR contaminated ground water clean

- up costs; and prevention reduc tion of cancer and illness due to CCR contamination of groundwater used as drinking water

. D ue 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; imp oundment 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 manage ment 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

account ed for 98% of the annual quantity of CCR generated in 2012. 4 This RIA estimates the electric utility indust ry 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 inte nded 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, embankm ent 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.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

ES

- 5 $ 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 Co st of f or of 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 (2 015

- 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 ar e 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 addresse s 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 s s urface 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 surfac e 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 con centration limits (MCL) standards:

1. Alternative Closure Requirement #1 : For plants that certify no alternative CCR disposal capacity, a 10

- year extension (2028 a time extension ) for initiating

closure c ompleting 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. A lternative C losure R equirement #2 : For plants that certify plans to permanent ly

cessation cease operation of of a coal

- fired boiler(s) by a date un certain , a time extension for completing closure, 5

- year extension (2023) for initiating closure for leaking, unlined CCR impoundments, ther eby 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.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

ES

- 6 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 Hum an Health Benefits and Cost Savings of f or of the CCR

Rule

This RIA estimates 1 1 categories of expected future human health and environm ental benefits and cost savings for the CCR rule. These include reduced CCR impoundment release prevention; release s ; 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 i mpoundment release s

. The

monetary value of this benefit consists of avoided future: impoundment

release structural failure cleanup costs; transaction (e.g, legal ) fees; and natural resource damages. This benefit is attributable to the following CCR pollution control requiremen ts 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, t his benefit applies to different sized impoundments (i.e., large and small) and all future failure event types (i.e., wall breach, “other” releases).

2. Groundwater Reduced g rou ndwater contamination prevention . The physical

nature of this benefit consists of expected future reduction in contami nation of groundwater by preventing reduc ing 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; t ransaction (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. Increased I nduced increase in future annual CCR beneficial use

. The physical

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

as the expected future reduction s 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; 5 and (ii) Reduced (i.e., r educed 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.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

ES

- 7 of premature mortality and chronic bronchitis

, )

, as wel l a s avoided energy and

water costs consumption, due to reduced use of virgin materials

. from the CCR

final rule ’s expected induced diversion of some CCR s 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 a n CCR rule “ cost offset ” associated with the future a nnual 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 )

. , H h owever, the beneficial use impact model was not intertwined integrated with

the CCR rule cost estimation model of CCR . The most significant this 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 e ffects among populations who are exposed to CCR contaminants through consumption of recreational ly 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 futu re reduction in adverse health effects on children exposed to mercury in

- utero as a result of preventing reduc ing 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 c omponent 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 expec ted 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 mana gement 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 IQOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

ES

- 8 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 moneta ry 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

surf ace water by reducing the risk of CC R 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 aqua tic 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 non

market 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 CC R surface impoundment releases

. Threatened and endangered species are species vulnerable to futur e 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 reduction s in the generation of air pollutants, such as nitrogen oxides (NO
x ), sulfur oxides (SO
x ), and carbon dioxide (CO 2 ) from changes in electricity generation, fuel consumption, andOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

ES

- 9 comb ustion expected because of change s in the handling of CCRs. d ash CCR 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 red uctions . 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 d rinking 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 n on

- cancer human healt h benefit from fish consumption (additional to

monetized avoided health effects)

5. Cancer and n on

- 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. W ater 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 p resents the total costs and benefits of the rule

under both a 7% and 3% discount rate.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

ES

- 10 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. Dust CCR fugitive d ust controls $7.09 $224 $3.36 $48.0

5. Run

- Stormwater r un

- 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 CCR i mpoundment structural integrity inspections requirement s $10.9 $344 $11.1 $158

B. Other ancillary costs

10. Groundwater corrective C orrective 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. Impoundment CCR i mpoundment structural integrity inspections requirement s $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: Note s

 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 the se requirements.

 For reason explained in Section 5.3.4 of this RIA, r ow 1 9 above (total cost) does not subtr act 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 a s a negative cost.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

ES

- 11 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 of

Reduced CCR impoundment

releases $1 51 $ 4,760 $13 8 $ 1,960

2 Prevention of

Reduced CCR groundwater

contamination $12.8 $405 $9.86 $141

Closures $1.60 $50.7 $1.46 $20.9

Bottom l iners $6.56 $207 $5.06 $72.2

Groundwater m onitoring $4.65 $147 $3.34 $ 47.7

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

Avo ided compliance cost air pollution & resource consumption $ 84 32 .5 $ 2,670 459 $ 57.1 21.9 $ 956 164

Avoided air pollution & resource use CCR rule

“ cost offset ” (alternatively could be subtracted

from row 19 of Exhibit ES

- A ) $ 32 84 .5 $ 459 2,670 $ 21.9 57.1 $ 164 956

4 Reduced incidence of cancer $0.00 546 $0. 173 $0.002 73 $0.03 90

5 Avoided IQ losses from mercury $0. 279 $8.80 $0.02 46 $0.3 51

6 Avoided IQ losses from lead $0. 186 $ 5.87 $0.016 4 $0.2 34

7 Reduced need for specialized education $0.00 273 $0.0 863 $0 .000 $0 .000

8 Non

- market surface water quality benefits

$2. 26 $ 71.4 $1. 89 $2 7.0 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 $0.7 59 $10. 8

10 Improved air quality from reduced power plant air pollutant emissions (fuel switching) $ 4.66 $ 147 $2. 04 $2 9.1 Reduced air emissions of NOx, SO2

Reduced air emissions of CO2

11 Reduced groundwater withdrawals (after conversion from wet to dry CCR handling) $0.00 273 $0.0 863 $0.002 73 $0.03 90

Column Total s = $289 $8,550 $232 $3,290

Non

- Monetized Benefits

12 Financial benefit . Reduce d investment risk and informa tion asymmetry in financial mark ets for the electric utility industry.

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

14 Dust CCR d ust nuisance benefit . Reduce d 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. Reduce d 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 . Reduce d cancer and non

- cancer health effects resulting from recreat ional 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. Reduce d sediment contamination from reduced deposition of toxic pollutants.

18 W ater quality benefit. Reduce d water treatment costs for drinking and irrigation water.

19 Commercial fisheries benefit. Improve d commercial fishing yields and harvest quality due to aquatic habitat improvements.

20 Tourism benefit. Increase d particip ation in water

- based recreation due to water quality improvements.

21 Avoided impingement and entrainment mortality. Reduce d 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.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

ES

- 12 * The beneficial use benefit in this RIA consists of two compon ents. 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 Ben efits: Alternate Discount Rates

(millions of 2013$)

3% Discount R ate 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 ( BCR 2 /

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 ( BCR 2 /

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 applie s 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 facility plant

- level decisions are likely reasonable, the specific facility plant

- level calculations in the model should not be interpreted as facility plant

- 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 theOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

ES

- 13 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

b ehavior are similar under the SPGELG and the CCR final rule. Each of these assumptions adds uncertainty to the overall result. We note, however, that the se scaled benefits for which the most uncertainty exists represent 2 % of overall

benefits at a 7% disco unt 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 faciliti es 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 coul d 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; th ose benefits are

considered in an addendum to Appendix X of this RIA which will analyze s 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 ass umption.



### ES.5 Other Regula tory and Distributional Impacts

Consistent with requirements under various statutes and executive orders, thi s RIA also assesses the following potential impacts of the CCR rule:

6 Because t he SPGELG rulemaking affect s the same universe of CCR pond s 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

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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ES

- 14  E lectricity price and ene r gy market impacts

. To ass ess 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 associ ated OMB guidance, EPA plans to perform

a p erform ed a n 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 n ot 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 Popul ations 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 in As ordered by Section 101(b) of the

1997 E xecutive O rder 130 45

, Protection of Children from From Environmental Health Risks and Safety Risks (62 FR 19885 19883 , April 23, 1997 ). ), E PA 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 expe nditures that exceed 1% of revenue. This analysis finds federalism impacts to be ambiguous; expenditures are likely to exceed $25

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- 1 

## 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 co al combustion residual (CCR ) landfills and CCR surface impoundments under Subtitle D of the Resource Conservation and Recovery Act (RCRA). To evaluate F ederal 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 signi ficance 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, an d then presents the need for reg ulatory 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 cos ts 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 D

Prime approach) EPA selected for the CCR final rule

.

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

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

7 Executive Order 12866 (11 pages) i s 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 C oal 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.govOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 2 

### 1.2 EPA’s Prior Ac tivities Addressing CCR Management (1978

- 2014 )

This section presents historical highlights of EPA’s prior activiti es 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 firs t 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 re gulations to implement RCRA Subtitle C (Sections 3001 to 3020 of RCRA). At that time, EPA recognized that certain large

volume 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 iden tified 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) repo rting, (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 indust rial special wastes see EPA’s special waste “ Special Waste ” website at: http://www.epa.gov/osw/nonhaz/industrial/special/index.htmOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 3 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

fro m regu lation 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 producti on 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

overbur den 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 exe mpt 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 envir onment 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

C CR 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 S ubtitle 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. Hou se 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 let ter 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.pdfOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 4 1988 EPA published a R eport to Congress with a scope limited to only coal

- fired electric utilities that generat e 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 pub lish a RCRA Subtitle C regulatory determination within six months of issuing the 1988 R eport 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 reg ulatory 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 Feb ruary 12, 1993, EPA published the first of five CCR

- related N ODA s (n otice 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 th ese 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 ongoi ng 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)

n ot 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 Fe bruary 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 R egulatory Determination on Four Large

Volume 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, d oc. 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 5 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 deposit ed 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 auth orities available under the Surface Mining Contr ol 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 h as 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.

20 05 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

re quirements 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

st andards, and corrective action.

2007 For the purpose of evaluating and proposing RCRA Subtitle D regulations, on August 29, 2007, EPA p ublished the second of five CCR NODA s a nnouncing 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 impoundme nts, and (c) EPA's CCR damage case assessment. The NODA also presented two alternative app roaches 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 framewor k 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 I n Mar ch and April 2009 E PA issued Info rmation 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.e du/openbook.php?isbn=0309100496October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 6 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 worke d closely with other F ederal agencies and states to review the information provided by the

ut ility 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 re medial 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 i nto 2013 and covered over 650 CCR impoundments

nationwide. 23

2010 EPA published the June 21, 2010 proposed CCR rule. The 2010 CCR proposal co

proposed both a RCRA Subtitle C s pecial w aste approach and a RCRA Subtitle D non

hazardous waste approach , and discussed a modified RCRA Subtitle D option (named D

prime) which would exempt (gran dfather) existing unlined CCR landfills and unlined CCR impoundments from the liner retrofit requirement.

2010 In August, September, and October 2010 EPA’s Office o f Resource Conservation and Recovery ( ORCR ) held eight public hearings in dif ferent 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. Septembe r 8, 2010 Dallas, TX

4. September 14, 2010 Charlotte, NC

5. Septembe r 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 el ectric utility companies to EPA’s 2009 “information request letters” are posted at http://www.epa.gov/waste/nonhaz/industrial/special/fossil/surveys/index.htm (webl ink 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/spe cial/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/ccr

rule/ccr

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- 7 2010 O n October 21, 2010 EPA published the third of five CCR NODA s to announce and invite public comment on EPA’s 2 009 information request letter survey of electric utility plants and on the 2009 start of EPA’s site assess ments of the structural integrity of CCR surface impoundments.

2011 On October 12, 2011 EPA published the fourth of five CCR NODA s 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 residual s; facility utility 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 laws uits 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 EP A 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 Netwo rk, 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 requestin g the US District Court to comp el the EPA to publish a final

CCR rule.

3. On April 20, 2012 Boral Mater ial 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 NODA s to announce and invite public

comment on additional informa tion 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 scal e 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 signatur e by the EPA Administrator no later than December 19, 2014. A ConsentOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 8 Decree 25 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 publicatio n 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 F ederal regulatory agencies to demonstrate

that F ederal regulation is necessary. In line with the three criteria identified in the preamble to the 1993 Executive Order 12866, Circular A

- 4 indicates that F e deral 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 e xplained below, EPA’s CCR final rule , in regulating CCR landfills and CCR surface impoundments

, address es 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

st andards and EPA regula tory approaches for a CCR final rule ;

2. Respond to 2009 Congressional requests fo r EPA regulation of CCR landfills and CCR surface impoundments ;

3. 2. Prevent Reduce future CCR contamination of groundwater and surface water;

4. 3. Prevent Reduce 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

su r face 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 fo r EPA re gulation 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/file s/044

- 1

- Consent

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- 9 1. Respond to public petitions submit ted to EPA and to the DC District Court

between 2004 and 2012 by citizen, environmental, and industry groups, proposing standards and EPA regula tory 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 f ederally 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 gra vel 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 Regul ation of Coal Combustion Waste

. 28 The proposal provides a framework for comprehensive regulation under RCRA Subtitle D of CCR landfills and

CCR su rface impoundments at coal

- fired electric power plants.

2009 In a letter dated March 2, 2009, the Environmental Int egrity 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 reque st letter identified 12 principles to guide the development of EPA standards, including the phase

- out of CCR surface impoundmen ts, locating CCR landfills and CCR impoundments away from groundwater or surface water, requiring liners, leachate collection sys tems 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, p ower 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, En vironmental 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 Environment al 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://ww w.environmentalintegrity.org/pub608.cfmOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 10 contamin ants 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 fo r 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 mus t 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 immediat ely. 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 respec t 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 E PA 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 peti tion 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 w ebcast is available from the U.S. Senate
Committee on Environment and Public Works’ website at: http://epw.senate.gov/public/ind ex.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.htmOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 11 are not satisfied with action we may move legislatively,” Boxer told EPA Administrator

designate Lisa Jackson at a January 14 [2009] confirmation hearing. “I don't want to get to that point because I think you have the authority to regulate this. It needs to be done .” 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 impos e 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

hol d 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 W orks. 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. Prevent Reduce 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 potenti al 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 Regul atory Determination, EPA did not consider these ecological damage cases

because all involved some form of d ischarge 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 su bstantial 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 violat ions, they nevertheless re flect 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. Sena te 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; F inal 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.htmOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 12 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

.

Hu man 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 prevent is 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 groun dwater, 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 millio n 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 billi on 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 withdra wals. 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 t he 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 “Americ an 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 St ates 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/October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 13 Furthermore, by reducing future incidences of CCR contamination of groundwater and surface waters, the CCR final rule is expected to reduce the futur e 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 h ealth 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 expecte d 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 ex ternality occurs when one party’s actions impose uncompensated benefits or costs on another party. Environmental problems are a classic case of externality. ”October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 14 Exhibit 1

- A
Groundwater Supply to Major Categories of Freshwater Use in the United States (2005) a

Major water use categories b 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 , Circu lar 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, commerci al, 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 i ncludes 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.

 Livestoc k: 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, hog s 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 raisi ng 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 l arge 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.

 Electrici ty 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 15 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 a vailable from the USGS until late 2014 according to the USGS at http://water.usgs.gov/watuse/

4. 3. Prevent Reduce future CCR surface impoundment struct ural failures and

associated releases of CCR into the environment

In addition to the groundwater and surface water damage cases summarized in the pr ior 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 . Structura l failure involves dam safety and structural integrity, a damage path way involving CCR impoundments that EPA did not consider at the time of the May 2000 CCR Regulatory Determination. These seven additional CCR impoundmen t 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 damag e 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)October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 16 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 ut ility 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.

F ortunately, 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 Steven son, Alabama, resulting in a 6.1 million gallon release from a flue

gas 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 Cree k 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 imp oundment. Total r emediation 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 spil ls 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 evide nce of public fe ar 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 informa tion, is

available at: http://www.epa.gov/waste/nonhaz/industrial/special/fossil/coalashletter.htm#letter

43 The 42 CCR impoundment failure events are liste d in Exhibit 6

- A in Section 6.1.2 of this RIA.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 17 impoundments from 113 citizens in comments on the June 2010 proposed CCR rule. 44 This

count consists of 40 citizens sub mitting written comments to EPA’s docket for the June 2010 proposed CCR rule , and 73 citizens making ver bal 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 25 16 3, 5 0 00 people reside withi n one

- mile of CCR landfills and CCR impoundments located at coal

- fired electric utility plants. 46

The CCR impoundment structural failure dam ages 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 propose d 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.

Fugi tive CCR dust fro m 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

- l evel 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.govOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 18 in the air at residences located near CCR landfil ls could exceed the National Ambient Air Quality Standards (NAAQS).October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 19 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

bet ween 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, t he CCR final rule also addresses a a nother 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 pollutio n 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

gro undwater near CCR landfills and impoundments ), and environmental damages (ecological damages, natural resource damages, a nd 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

int ernalizing 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 un aware of exposure to toxic

chemical constituents contained in CCR which may be leaching into th e ground and groundwater

at certain locations . Thus, while nearby citizens may have the right to legal lawsuits to recuperate health and property damages, citize ns may not be aware of the need to do so until health risks (and health costs) have already been incurred.

Firms are sometimes held accou ntable for some of the external health 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 e xternal costs from CCR landfills and impoundments are residents

of h ouseholds located nea r 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 Tran scripts 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 20 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 potenti al

CCR contamination risk s to hou seholds and communities by multiple requirements:

 The CCR rule contains a num ber of provisions requiring electric utility companies to document their compliance with the CCR rule ’s technical requirements.

 T o post those documents on a publically available website in a timely and transparent

manner.

 The rule al so requires utility companies to notify s tate government environmental agencie s of numerous actions, including that certified CCR pollution control and safety

demon strations 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 profession al 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 acce ssible internet site

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 21 

### 1.4 Summary of Public Comments on EPA’s 2010 CCR Proposed Rule RIA

Exhibit 1

- C belo w provides an overview of the 17 types of organizations 50 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:

 D ocke t comments : 431 o rganizations s ubmitted 1,067 RIA

- related c omments d uring the

5

- month ( June 21 to November 19, 2010 ) p ublic c omment period 51 for EPA’s June 21, 2010 p roposed CCR r ule

.

 H earing s comment s : 170 o rganizations s ubmitted 288 RIA

- related c omments at EPA’s

e ight p ublic hearings 52 on the June 21, 2010 p roposed CCR rule h eld sequentially

b etween 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 t he 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 Hearing s 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 Facility Plant 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 spoke speople, it is counted as two organizations. “No organization provided” is counted as a single organization, and if one o rganization 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 rul e, 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

propos ed 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 fr om 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.htmOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 22 Exhibit 1

- D below provides a summary of the specific RIA

- related topics associate d 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 comme nts 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 assoc iate with any particular section s , 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 regula tory costs as indicated in row 2 of Exhibit 1

- D below.

Exhibit 1

- D

Public Co mment Topi cs Related to EPA’s RIA for the 2010 CCR Proposed Rule

RIA Topic and Sub

- Topic Categories Co unt 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 p ollution 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 s pecific 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 comple te job evaluating benefits

.

o RIA needs t o monetize stigma of household value loss near potential CCR spill

sites

.

o RIA should quantify avoided ( 1) litigation costs, ( 2) reduction of effluent

dis charges through phase out of CCR surface impoundments

, ( 3) reduction inOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 23 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 h ealth risk benefits.

o RIA does not evaluate other types of ecological damage s 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 e rror in ancillary cost #15 (waste disposal permit cost)

.

o RIA underestimates Sub title D costs.

o RIA underestimates Subtitle C costs.

o Disagrees with some co st assumptions.



### o R IA 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 cate g ories that are not monetized i n 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 s caling factors are inaccurate f or both Subtitle D options.

 CCR Beneficial U se 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 a voided 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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- 1 

## 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 project ed 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. S ee Sections 9.2.1 and
9.2.2 in Chapter 9 of t his RIA for a description of the relevant modifications and updates to th e 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, def ine 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 impact s coal

fired 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 ( off

site 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

in directly affected by the CCR rule . This RIA evaluates potential indirect i mpacts 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 c oal

- fired electric utility plants as potentially affected by the CCR rule.

The remaining section ( Section 2.4 ) outlines several key an alytic principles that constitute the analytic framework for this RIA , including constant pricing, two alternative discount rates, period of analysis

, and proje ction 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 e ntities 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 analys is will also examine effects on energy producers u sing 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 Actio n Development Process: Final Guidance for EPA Rulewriters: Regulatory Flexibility Act,” OPEI Regulatory Development Series, Nov 2006, Footnote 14 at: http://www.epa.gov/sbrefa/docu ments/rfaguidance11

- 00

- 06.pdfOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 2 commercial waste disposal industries are also directly affected, as are the owners of sand and gravel pits and quar ries 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 a ffected 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 bus iness

ente rprise (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

l arger 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 gener

ation 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 establishment s 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 e lectric 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 reg ulatory 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, municipali ties, 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.htmlOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 3 re quirements 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 es timates 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 requir ements of the CCR final rule do not include

non

- utility coal

- fired electricity plants. This RIA estimates that between 164 and 759 non

utility 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
operat ing 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 co al burned). The DOE Based on the EIA

- 923 database data 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 75 9 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 regulation r ule

. 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/indust rial/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 M anagement 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 4 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 5 Exhibit 2

- A
Industries Op e rating Coal

- Fired Electricity Plants Not Covered by the CCR Rule a

Industry

Count NAICS

Sector b NAICS

Industry b NAICS Description Coal

- based Fuel Total (short tons) Implied CCR

Generation c Plant

Count d

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 Mills e 916,956 92,613 44

7 32 32213 P aperboard 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 d igit 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 se ctors 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

c From Exhibit 2

- I , 8 2

. 612 million tons of non

- FGD CCR were generated at electric utility plants. From Appendix A , 819.16 million tons of coal was burned by ele ctric 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.

d 24 plants reported use of coal

- based fuel by generators at the plant, but the reported quantity used in 2012 was zero short tons.

e One 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

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 6 2.1.2 Commercial Waste Transportation Industry

Industries involved in the transportation of waste may be affected by the CCR final rule b ecause 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 practice s 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 F reight (except Used Goods) Trucking, Long

Distance. This industry includes establishments primarily engaged in providing long

- distance specialized trucking. These establishments provide trucking between metropolitan areas that may

cross North American coun try 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 regulati on may also affect at least three other environmental industries with the following NAICS codes:

 NA ICS 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 com bustion units that currently transport waste for

off

- site disposal.

 NAICS 562910 . Environmental cleanup/remediation services.

2.1.4 Sand and Gravel Pits and Quarries

D epending upon the extent of their current (baseline) CCR management and CCR pollution

control practices, owners of some sand and gravel pits and quarri es 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=enOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 7 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 th e 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 benefi ts 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 ”). H owever, the CCR final rule does not regulate CCR mine filling becau se 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,

thi s 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 li sts 15 industrial applications which beneficially use CCR a ccording to the

Ameri can Coal Ash Association (ACAA) as of 2012 66 (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 r ule 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 counterv ailing 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 orderi ng 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: Amer ican 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#Q14October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 8 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 Gyp sum 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

Source s : * 15 i ndustrial applications listed above according to the 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 ** 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 in stead reinforces the use of existing engineering design and environmental protection best practices in CCR fill operations. T his RIA does not estimate impacts on CCR structural fill.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 9 

### 2.3 Affected Electric Utility Plants

Note : EPA has updated the universe to reflect 61 actual and project ed 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. E xhibits in
this chapter have not been updated to reflect the r evisions descr i bed 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 e nergy 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 bi nding

materials. 70

68 RTI International, EPA’s risk assessment contractor for the CCR rule, initially identified the list of 507 coal

- fired electric

utili ty plants used in this RIA; this RIA updated the universe to 478 plants to reflect newer EIA data.

69 The U.S. Bureau of Cens us defines NAICS 22 as follows:

“ The Utilities sector comprises establishments engaged in the provision of the following utility services: electric p ower, 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 in cludes 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. ” (So urce: 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 o r secondary energy sources reported by coal burning electric utility plants are agriculture byproducts, distillate fuel oil, natural gas, petroleum coke, propane, and wood and w aste
solids.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

2

- 10 3. Removal o f other non

- qualifying power plant s . The tot al number of NAICS 22 power plants listing coal as a primary or secondary fuel is 550 plants . EPA

conducted additional Internet r esearch and removed 72 plant s 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 gene rator units or EGUs) of 375,638 megawatts (MW), or roughly 3 0 % of th e 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 co ntexts (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 dispos ition (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 whe re the data describing facility electricity plant operations were incomplete or unavailable in the EIA

- 923 database

.

Limitation : According to its Section 257.50(e), t he scope of the CCR final rule does not a pply 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 does date of this analysis EPA had not indicate determined

whether this 50% threshold should be calculated relative to individual coal

- fired bo ilers or relative
to an average across all coal

- fired and other fuel type boi lers at each individual electric utility plant. This Consequently, t his RIA did not apply this threshold as a filter to the EIA data.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

2

- 11 Exhibit 2

- C and Exhibit 2

- D below, the 478 coal

- fired electric utility plants are owned a nd 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 Flexibili ty 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 ac ross 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 gover nment 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 t he 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 ho urs 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 Entity a Entity Size

Class b 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 %) 1 3 3 ( 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 ( 1 4 %) 9. Small cooperatives (this RIA assumes all privately

owned) Small 20 ( 4 %) 15 ( 6 %)

Summary

Totals 478 242

Private sector sub

- total [4+5+8+9] 397 (83%) 18 3 (7 6 %) State/local government sub

- total [2+3+6+7] 70 (15%) 58 (24%)

Small entity sub

- total [6+7+8+9] 99 ( 21 %) 8 1 ( 33 %)

a Type of owner entity estimated and assigned based on owner name or internet research on type of ownership.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

2

- 12 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

Total Plants Federal Government
State Government

Non

- small Municipal Non - small Company Non - small Cooperative County Government Small Municipal Small Company Small Cooperative Total 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 Bu siness Regulatory Enforcement Fairness Act (SBREFA) compliance (see text).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

2

- 13 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

Total Plants Federal Government
State Government

Non

- small Municipal Non - small Company Non - small Cooperative County Government Small Municipal Small Company Small Cooperative Total 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 3 25 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.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

2

- 14 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 t ons 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 an d 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.acaa

usa.org/Publications/Production

- Use

- ReportsOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

2

- 15 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 NE TN AZ NJ OK UT AR MS MT LA NM MA NV AK DE HI NH SD CT ME OR PR WA Annual CCR Generation (millions of tons)

Count of Coal - 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 NE TN AZ NJ OK UT AR MS MT LA NM MA NV AK DE HI NH SD CT ME OR PR WA Annual CCR Generation (millions of tons)

Count of Coal - 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 GenerationOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

2

- 16 Exhibit 2

- H below present s state

- by

- state counts of the 478 coal

- fired electric utility plants and their associated annual CCR generation tonnages for 20 12 . Noteworthy is that four states (DC, ID, RI, VT) do not have operating coal

- fired electric utility plants (alth ough they may have non

utility 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 annua l 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

- 92 3 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 as h 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 catego ries 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/cnea f/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.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

2

- 17 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%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

2

- 18  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 no t 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 estimat es 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 a ddresses 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., medium

and lar ge

- 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 2 009 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 inactiv e CCR managem ent units addressed by this RIA

, see Chapter

2.

84 For a complete description of the EIA databases used for disposition quantities, se e Appendix E

.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

2

- 19 2.3.4 CCR Management Practices by P ower P lant 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 coal

fired electric utili ty 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

use use s

. 85 E xhibit 2

- I presents the number of plants using each disposal practice; some facilit ies 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 on

site 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 thei r 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 iden tify CCR landf

ill and surface impoundment s:

 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 th e above sources. This analysis was initially conducted by RTI International and reflects a method using Internet satellite photos to help dete rmine 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 tha t 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.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

2

- 20 E xhibit 2

- I

2012 Count of Coal

- Fired Electric Utility Plants b y CCR Disposition Method

CCR Generation Category Disposal Beneficial Use b

Total

Plants c On

- site

Landfill On

site

Ponds Off

- site Disposal (Landfill) Sold Used

On

- site Used

Off

- site Stored

On

site Stored

Off

site 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 Becaus e 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 non

duplicative cou nt 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 dis posed 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

- s ite, 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" qua ntity 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 h ttp://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=2008

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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2

- 21 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

Sub

totals On

- 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 (31.0%) 9. Other FGD byproducts 7,063.1 435.5 513.7 523.2 886.8 117.3 101.2 0.7 9,641.5

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 the se categories are disposed at potentially active on

- site units at plants reporting burning coa l

- 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.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

2

- 22 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 Sub

total

landfill (onsite+ offsite) Subtotal disposal

Land

fills (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%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

2

- 23 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, re cycle, 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 a n impoundment as a CCR disposal impoundment or a CCR storage impoundment, this RIA used the following algorithm:

 If EIA reported data 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 report indicate 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 make s this assumption to ensure that estimated CCR rule compliance costs at other impoundments

are not understated.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

2

- 24 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 mini mis 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 ina ctive 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 coun t: 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 da ta; 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 co al

- 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 provi des 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 sur face 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 EIA

923 database. That is, approximately 45% of active on

- site CCR management units reported

rec eiving 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 quan tities (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 un its, including 227 landfill s in 41 states and 257 impoundment s in 33 states. See

Association of State and Territorial Solid Waste M anagement 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

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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2

- 25 runoff), or could be storage impo undments (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 includ es information by generalized waste stream (e.g., bottom ash, fly ash) only. While the EIA

identifies database 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 a re 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 Plants a

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.

b These 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.

c CCR management units identified as having zero CCR disposition quantities in the 2012 DOE EIA

- 923 database. Quantities are reported by these plants for othe r final dispositions (e.g., off

- site landfill, sold, used on

- site).October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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2

- 26 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+

SI s % 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

No te: 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, t he 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 synthe tic/composite liners, but only

80 have liners of sufficient thicknes s), 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 m odeling purposes. Note also, total count of 846 impoundments includes 735 active impoundments and 111 inactive impoundments.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

2

- 27 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 cou nts, 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 dispo sal method exceeds the total count of 478 plants.

Exhibit 2

- N
Summary of Electric Uti lity 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 c On

- Site Off

- Site a

Plant Counts

2012 Count of Coal

- Fired Electric Utility Plants that Dispose of CCR (478 total) 188 177 d 144 459 e

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.” A s described in this chapter, this RIA do es 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 EIA

860, or else 2009 EIA

- 86 0 if not available (7 plants).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

2

- 28 

### 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 factors Forecast of future annual coal consumption for annual

coal

- fired el ectricity generation (as a proxy for basis estimating in this RIA future

a nnual 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 ma rket 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, t his 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” surv eys, 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 historic al data for years prior to 2014 to anal yze 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, Circul ar 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. De partment of Commerce, Bureau of Economic Analysis “Implicit Price Deflator for Gross Domestic Product” ( http://www.bea.gov/national/nip aweb/TableView.asp?SelectedTable=13&Freq=Qtr&FirstYear=2009&LastYear=2011 ].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

2

- 29 2.4.2 Discount Rate

Consistent with guidance in OMB Circular A

- 4 and EPA’s Gui delines for Preparing Economic Analyses , this RIA also applies two alternative discount rates of 7 % and 3 %

. OMB re commends

that 7% be used in RIAs evaluating a regulation that will mainly displace or alter the use of capital in the privat e 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 Pe riod 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 heal th and environ mental 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 mig ration 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 perio d 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 fut ure 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 th e final rule will begin to have effects, even if that is expected to be some time in the fu ture. 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 i n perpetuity as they are dredged out with regularity and thus do not reach capacity.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 30 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 val ues 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 implementat ion 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 ( Chap ter 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 M odel. S ee 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 calculat ions 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 31 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 201 5 to 2040 forecast of coal consumption for electricity generation from EIA’s 2014 Annual Energy Outlook (AEO). 98 This RIA applies the “ R eference case C ase ” presented in the 2014 AEO; this

R eference r eference 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 thi s 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 R eference 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 contin ues 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 generatio n 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 g as 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 case of 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 201 2 (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 Administr ation (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/October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 32 Exhibit 2

- P
DOE

- EIA Projection of Coal Consumptions Consumption 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

2011 2015 2019 2023 2027 2031 2035 2039 2043 2047 2051 2055 2059 2063 2067 2071 2075 2079 2083 2087 2091 2095 2099 2103 2107 2111 Quadrillion Btu Coal Consumption for Electricity Generation

14.5 15 15.5 16 16.5 17 17.5 18 18.5

2011 2015 2019 2023 2027 2031 2035 2039 2043 2047 2051 2055 2059 2063 2067 2071 2075 2079 2083 2087 2091 2095 2099 2103 2107 2111 Quadrillion Btu Coal Consumption for Electricity GenerationOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 33 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 chang es 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 compan ies 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 e xample, 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 bu t phase

- out of wet

CCR (i.e., surface impoundment s) 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 34 doc umented 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 a nd 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 in corporating overall trends in energy production future annual projection of coal consumption for electricy generation
from EIA’s AEO 2014 AEO projection case that which 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.govOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 35October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 36 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 convers ion from wet to dry CCR a

2. Duke Energy Company 5 Planned convers ion from wet to dry CCR b

2 Conversion away from coal as a fuel source c

3. Hoosier Energy REC Inc. 1 Planned convers ion from wet to dry CCR b

4. Vectren Southern Indiana Gas and Electric Company 2 Planned convers ion from wet to dry CCR b

5. Westar Energy Company 1 Planned convers ion from wet to dry CCR b

6. Progress Energy 4 Conversion away from coal as a fuel source c

7. Xcel Energy 2 Converted to natural gas c

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 Fr om Company to Company” ( http://btop.courierpress.com/news/2009/oct/24/coal

- ash

- disposal

- varies

- from

- company

tocompany/?print=1 ).

 The Janu ary 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.myrtlebeachonlin e.com/2012/01/17/2607592/duke

- agrees

- to

- pollution

- contr ols.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

- Pays

Dividends_79.html)

h EPA identifie d 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

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 1 

## 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. S ee Sections 9.2 and 9.4 in Cha pter 9 of this RIA for a description of the relevant modifications and the resultant re

estimated 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 ti meframe serves two purposes:

o T o 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 operatin g standards on new CCR units th an on existing units).

o To support estimation of long

- t erm benefits and costs of the CCR rule ’s regulatory requirements that affect fut ure 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 wit hout 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 unit s
, 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 wit h 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 pol lution controls at CCR units.

101 Consistent with the analytic f ramework 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 woul d look absent the rule .”October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 2 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 empirically

justifiable factors. This RIA considers 12 categories of potential baseline costs associated with
state government reg ulation of CCR management that are related to CCR pollution controls and other possible CCR management requirements. Nine cost categories are “unit

- level” costs that

a ccrue to individual CCR management units (i.e., CCR landfills and impoundments) :

1. Groundw ater 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 l andfill 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 C CR 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 wi th a scope b roader 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 toOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 3 For each of the 478 operating coal

- fired electric utility plants in the universe, this RIA estimates

baseline CCR pol lution 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 regula tory 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 mul tiple 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 pond s 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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- 4 For 268 of the 310 exist ing active on

- site landfill s (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 li ner. 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 impoundment s (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 impoundm ents, 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 landfill s, this RIA uses the applicable state regulatory requirements for thos e 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 landfill s (34%). 115 For the remaining landfill s, 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 wh ile 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 probabilist ically 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 insufficie ntly.

For add itional 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 o n 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 5 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 s tate

- 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 charact erize the baseline, by CCR management unit type and CCR pollution control.

Exhibit 3

- A
Summary of Methodology Used in Characterizing Baseline CCR Pol lution Controls

CCR Unit Type Liner Type Closure Cap Type Leachate Collection System Other Unit

- Level

Controls

Existing active/open

landfills a 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 landfills b Survey data Survey data Survey data No controls assigned
Existing active/open impoundments a Survey data State regulations data State regulat ions 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 impoundments b 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 Thi s RIA assumes that CCR management unit operations pre

- date t he 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 lac k all other

unit

- level pollution controls.

3.1 .2 Baseline State Gov ernment 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 e stablished 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 mo nitoring), 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 6 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 w ith 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 pollutio n 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 co ntrol for al l active operating CCR management units, whereas other states may require particular pollution controls only for fu ture newly

- constructed units. Thus, baseline costs associated with state requirements as estimated in this RIA change over the 10 0

- 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 regu lations for CCR

m anagement 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 governm ent 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 J esse 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 o btained 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 requ irements 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 Managem ent 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 7 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); we ll 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 un it 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 rev iewed 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 th is 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 s ampling 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 differenc es 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 b y 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 lan dfills. 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 surf ace impoundments, and seven require liners for existing landfills. Eleven states require liners at newly

- constructed surface impoundments, and 24 states require liners at newly

- constructedOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 8 landfills. In the counts of states above, states are listed twice i f they require bottom liners for both existing and newly

- constructed units.

States requiring liners vary in the liner types they req uire 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 requ irements 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 coll ection 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 re quire 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 landfil ls, and 24 states require dust control at newly

constructed 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 applie s a generalized, simplified assumption that landfill operators:

 Co mpact CCR to maximize available landfill capacity;

 U se water wetting to facilitate compaction and for dust control; and

 S pray water on unpaved roads.

Not e that while this RIA estimate s 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 estima ted in this chapter do not reflect any costs associated with dust controls currently implemented at surface impoundments.

3.1 .2.5 Storm Water R un

- On/Run

- Off Control Requirements

Of the 34 states reviewed, 22 require storm water run

- on/run

- off control fo r existing landfills, and 25 states require run

- on/run

- off control at newly

- constructed landfills. In the counts of statesOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 9 above, states are listed twice if they require run

- on/run

- off control for both existing and new

units.

Note that while this RIA esti mate s CCR final rule compliance costs associated with run

- on/run

off 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 hav e 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 floodp lains 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 P ollution Control Agency to develop new regulations requiring safer locations for future landfills in Minnesota. The new regulations, which sti ll need final approvals as of October 2011, would more tightly restrict the location of industrial and municipal l andfills and would limit taxpayer exposure for potential remediation costs. The new rules would prohibit new landfills in areas where groundwate r could move contaminants quickly, and would limit placement in karst areas. The new rules would also prohibit l andfills from being built where contaminants could reach property boundaries within 100 days. The new rules don't apply to existing landfil ls. See "Stricter pollution rules for state's landfills could kill Xcel Energy's plan for fly

- ash site in West Lakela nd 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 i mpoundments, 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 (i f 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 10  Wetlands . O f 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 newly

constructed 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 re quire for diff erent 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

- constr ucted 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 Kar st 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, Ke ntucky, Minnesota, Missouri, North Dakota, Pennsylvania, Tennessee, and Wisconsin; and West Virginia (1,000 feet away).October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 11 monitoring at newly

- constru cted 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 Structu ral 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 describe d 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, structu ral 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 Baseli ne 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 mo difications 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 la ndfills 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. DO E/PI

- 0004, Aug 2006 at: http://nepis.epa.gov/Exe/ZyPDF.cgi/600004O8.PDF?Dockey=600004O8.PDF

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 12 Exhibit 3

- B

Baseline Compliance with State Government CCR Pollution Control Requirement s: 310 On

- Site CCR Landfills

CCR Pollution

Control Category Subcategory

Description Required for Future New CCR Landfills a Required for Existing CCR Landfills a

Unit Count Percent of

Existing

LFs CCR Total

(tons) Percent of

CCR Total b Unit

Count Percent

of Existing

LFs CCR Total

(tons) Percent of

CCR

Total b

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 Restrictions c 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 oth er than construction of a new CCR landfill. Figures in these columns represent the requirements that would be applicable if each e xisting 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 ) reports indicate that 41.7 million tons of CCR are disposed into on

- site landfills, this RIA identified 18 plants reporting on

- site CCR disposal in land fills where no CCR landfill s 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 fo r each plant. For existing CCR landfills, this R IA does not account that any landfills would be affected by location restrictions because the landfills are currently still operating (and thus not requir ed to close). For new CCR landfills, this exhibit presents only those potential

new landfills that wou ld be impacted by a given site restriction requirement, rather than all potential new landfills in a state with such a site r estriction requirement in place, except for floodplains, where no new data were collected. Given that all new and existing CCR land fills 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 r estricti ons in place, these site restrictions do not apply to the geographic areas

in which most of these facilities are located.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 13 Exhibit 3

- C Baseline Compliance with State Government CCR Pollution Control Requirements:

735 Active On

- Site CCR Surface Impoundments

CCR Pollution Control Category a Subcategory Description Required for Future New CCR Impoundments b Required for Existing CCR Impoundments b

Unit

Count Percent of

Existing

SIs CCR Total

(tons) Percent of

CCR

Total c Unit

Count Percent of

Existing

SIs CCR Total

(tons) Percent

of CCR

Total c Groundwater Monitoring 194 26% 2,023,774 14% 139 19% 1,456,921 10%

Bottom Liner Synthetic/Composite 193 26% 2,191,406 15% 80 d 11% 956,262 6% Clay 96 13% 3,312,608 22% 76 d 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 Restrictions e 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 Inspections f 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 b e 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 tonn age 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 con trol 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 r eflect only those existing surface impoundments with sufficiently thick liners. There are five such existing surfac e 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 impoundm ents 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 d ate 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 operati ng (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 alr eady comply with floodplains site restriction requirements, no new CCR impoundments can be sited such that they are impacted by th is 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 loc ated.

f Unlike the other pollution control requirements in this table, the estimate of the percent of existing SIs subject to structural integri ty inspection requirements in the baseline was not obtained though EPA’s direct review of existing state regulations. Rather than a pplying 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 inspection s in the baseline.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 14 

### 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 u pdates. 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. Final ly, 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 RI A 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 mo del considers two

landfill des igns; 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 elec tric 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 15 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 (con sistent with 40 years of disposal) is capped and closed, rather than the entirety of the impoundment, and allows for the p ossibility that impoundment s 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 20 05 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 th e 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 landfill s still operating; the results are as follows: Surface impoundment age data indicates approxima tely 38% of the impoundment s exceed 40 years of age currently (513 CCR surface impoundments with age data):

 Mean age = 37 years

 Median age = 37 years

 75 th percentile age = 45 years

 80 th percentile range = 47 years

 90 th percentile age = 54 years

 95 th percentile age = 59 years

 99 th percentile age = 65 years

 Maximum age = 67 years Landfill age data indicates appro ximately 7% of the landfill s exceed 40 years of age currently (255 CCR landfills with age data):

 Mean age = 26 years

 Median age = 28 years

 90 th percentile age = 38 years

 95 t h percentile age = 44 years

 99 th 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 perpetu ity so long as they are regularly dredged. (Confi rmed by communication with engineering experts at GZA Geoenvironmental, Inc.)

131 This RIA assumes the following: a compacted dry waste density of 1,190 kg/m 3 ; in

- situ wet waste density of 900 kg/m 3 ; 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 be low grade side slope of 3:1 (rise:run).

132 Technically, the lan dfill controls (as opposed to a surface impoundme nt ) likely are constructed in several phases (e.g., one cell per year, three years, five years, etc.).October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 16 Exhibit 3

- D Key Assump tions for Sizing of CCR Management Units

Dimension Category Landfills Surface Impoundments Combination Landfill Pile Landfill
Capacity excavated below grade 50% 5% 100%
Depth a,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, m edian 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 1 5 feet, average depth of 24 feet, and maximum depth of 546 feet).

c Consistent with range of areas identified in review of unit a rea 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 (min imum 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.

T his 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; t his 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 vertically

ex panded 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, follo wed by 40 as a vertically

expanded 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 repurpos ed, 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

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- 17 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 coal

fired electric utilit y 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 propos ed 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 t ype.

This RIA used the cost model to generate individual cost estimates for a set of five differently

sized 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 Subt itle 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 mod el 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 , Federa l 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.

EP A, 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: Comp liance 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; Propo sed 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 lin er materials, cover materials, and the per

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- 18  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 impoun dment 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 s cale, 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 dri vers 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 sensitivit y 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

, Exhi bit 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 land fills 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 vertically

expa nded 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 t o not

u nderestimate 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 give n 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 19 dewatering costs associated with CCR storage impoundments were obtained by consultation with engine ering 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 contr ol requirements

under the CCR final CCR rule. The STATA model contains a database populated with plant

- by

plant 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

po llution 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 electri c 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

accurat e 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 stud ies 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 examin e 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 pr edict 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 el ectric 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 cos ts 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 Offic e 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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- 20 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 a llocation 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 pro babilistic 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 und er 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 state

specific 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 clos ing of CCR units for each utility plant. EPA used three data sources to determine the age of ea ch landfill and impoundment , including research by RTI International, the 1995 Electric Power Research Institute ( EPRI)

Co

- management Survey, and the DOE E IA

- 860 database. If no CCR unit or power plant boiler in stallation 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 thes e 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 21 In addition, as discussed i n 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 this This RIA applies both a 7 3 % and a 3 7 % discount rate for calculating both net present value costs and average annualized costs, consistent with OMB and EPA recommendations Circular A

- 4 (s ee Section 2

. 4 .2 ). 141

 CCR generation forecast

. Based on As indicated in Section 2.4.4 , t his 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 EIA Annual 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 coal

fired 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 explan ation 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 Engineeri ng 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 adjustmen t 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 d erive 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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- 22 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

- cos tly 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 give n year based on (which this RIA estimates in relation to the EIA AEO 2014 projections projection of future coal consumption for CCR electricity generation in that year. )

. For example, AEO 2014 projects that coal consumption for ele ctricity generation will be 2. 43 4 % 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. 43 4 % 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 annualize d 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 dispos al 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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- 23 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

- sit e 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 asso ciated 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 reports data indicate wet CCR disposal with at least one on

site, 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 impoundm ents at plants where EIA reports data indicate zero wet CCR disposal (n=384) ;

o All impoundments that are not the largest impoundm ent at a plant where

EIA reports data 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 c ontrols present at each impoundment, reflecting baseline state regulatory information, adjusted to reflect state

- specific costs.

145 The STATA model is cognizant of landfill age, e ven 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 clo ses, 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 ma kes a choice once; after an initial landfill closure. Moreover, the STATA model assumes all subsequent choices will be the same, consistent with t he fact that EIA AEO projections do projection of future coal consumption for electricity generation do es 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 appli ed 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 closu re of a new landfill will fall outside the 100

- year period of analysis for nearly all

landfills in the universe.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 24 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 c hanges in CCR tonnage disposed (based on EIA AEO 2014 projections for CCR generation in that year),

, combined with fixed costs refl ected in the Fortran equations

. of

the cost model for this RIA.

This cost stream continue s 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 p ost

- 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

- si te 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 c lose 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 25  Choice 3: Impoundment closure, wet

- dry conversion, and subsequent disposal of dry

- handled CCR in a new dug pile lan dfill 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) cos t 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 least

cost 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, on

site 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

- closu re monitoring costs applied annually for 40 years after closure) and the cost of wet

dry 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 dry

handled CCR (or $3.94 on a wet

- tonnage basis) for annual dredg ing 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 conversio n; 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 c osts 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 we t 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 speci fic modeling considerations, this RIA model s 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 beOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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3

- 26  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 th e 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 monit oring applied annually for 40 years after closure) if required by the state regulatory baseline.

The STATA model compares each of these sets o f costs on a going

- forward basis in any subsequent future year and chooses the lowest

- co st 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 S torage I mpoundments

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. S ee 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 d redging. 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 co nversion 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 subsequ ent choices will be the same, consistent with t he fact that EIA AEO projections do projection of future coal consumption for electricity generation do es not project changes in CCR generation and disposal past 2040, and as such any option determined be the l owest

- 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 ana lysis for nearly all impoundments in the universe.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 27 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 engi neering 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 stor age impoundment, this RIA must also assign a “tonnage handled” volume to each storage impoundment. Using EIA data and the disposal impoundment/storage impoundment algorithm descri bed earlier in this c hapter, this RIA was able to map all wet

- handled CCR ton nage reported by indicated 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 CC R tonnage reported by indicated in the EIA data associated with a plant is evenly divided across all storage impoundments identified at the plant;

 In cases where no wet

- h andled CCR tonnage was reported by indicated 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 m ultiplies 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 assumptio n 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 subs et 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 fa ctor represents the ratio of densities between the two types of CCR (dry versus wet).

154 Source: This 25% assumption was f ormulated for this RIA by e ngineers from GZA Geoenvironmental based on expert judgment and institutional knowledge from the company’s extensive experience with the electric power industry.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 28 quantity of CCRs that would be managed in two stages. This is consistent with the ratio of bottom ash tonnage to combined fl y 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 t his 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 sensit ivity 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 s tate 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 impound ments are assumed to exist in perpetuity, the year

- to

year 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 co ntrol 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 relati vely 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, a nother 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 on

or off

- site commercial indus trial 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 29 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 conve rsion 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 exte nt 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 appl y 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.

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 “hu rdle 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 (pa ge 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 unde rtaking. 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 alteran tive 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 O ffice of W ater’s 2010 s urvey d ata 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.cfmOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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3

- 30 longer period representing the 40

- year average operati ng life of the newly

constructed 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 c ost 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 abov e 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 managemen t 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 contr ols

and individual CCR units. This RIA simulates these costs as ac cruing only to those units located in states requiring the specific pollution controls; the baseline cost methodology presented below

does not uniformly assign base line costs to each CCR unit potentially affected by the CCR rule.

The cost equations discus sed 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 th is 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 indu strial equipment. The IRS class life represents equipment depreciation periods for taxation purposes. Although IRS class lifes may be accelerated relative to phys ical 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 lif e of 39 years. Source: Page 110 of IRS Publication 946 “How to Depreciate Property, ” June 28, 2014.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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3

- 31 depending on unit size and on which pollution co ntrols 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 ap plied, 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 cost s 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 lifespan lifespan s

.

The remaind er of this section presents the ass umptions 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

Fort ran

- 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/E b N/E b

Run

- on/Run

- off Controls $0.06 $7,296 $0.09 $9,315 N/E b N/E b

Water Table Not Estimated Not Estimated Not EstimatedOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 32 Exhibit 3

- E

Fort ran

- 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

Restrictions c 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

Cap d 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 Monitoring e $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 An nual 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.

I n addition to the costs applied in Exhibit 3

- E , the cost estimation model includes costs

associated w ith 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 e xpansion 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

assoc iated 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 33 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

- gra dient 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. Wh ere 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 calcu lates 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

Groundwat er 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 mi ddle 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 mon itoring 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, pota ssium, 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 E PA’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 cos t 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 Reques t (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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 34 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 estima tes 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 affectin g 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 o n 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 assig ns 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 compactio n 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 o peration ($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 C CR 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 s ame 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 comp action 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 lan dfills and surface impoundments.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 35 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 betwe en 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 facility plant 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 mil es 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 practi ce. 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 approxi mately 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 req uired 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 purpos e 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 lifesp ans, the IRS class lif

e 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 1 0 2 of IRS Publicat ion 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 36 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 ass umes 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 assumpti on 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/ru n

- 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 Est imates

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 ma ke sufficient demonstrations to

allo w 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 an d 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

States 170 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, EP A 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 t o 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 mean s a fault zone in the context of the definition, is included a s part of the definition of fault, and thus the 200

- foot setback distance will apply to the outermost bou ndary of a fault or fault zone.

170 USGS source at http://earthquake.usgs.gov/hazards/qfaults /October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 37 centr oid may be one or two kilom eters 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 two

mile standard to iden tify 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 t o 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 manageme nt 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 off

site 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 poten tially affected by the CCR

rule.

172 “Vulnerability Criteria Information for Coal Combustion Residuals Plants Revised Technical Directive 4

- 3, WA 1

- 02, EP A

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 standa rds 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 des ign features to be protected include all containment structures ( i.e., liners, leachat e collection systems, and surface water control systems). The demonstration must be certified by an independent registered professional engineer and the owner or operator mu st 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 collec ted 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 Cuthb ertson, EPA Office of Resource Conservation and Recovery, December 31, 2010.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 38 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 uni t, 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

i n 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 restriction s 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 model s that on average, seven CCR disposal units will shift to off

site 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 adeq uate 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, an d the owner or operator must notify the state that the demonstration has b een 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 39 management unit. 178 This RIA assumes the same requirements for both landfill and

i mpoundment 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 conse rvative 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

im pact on the post

- rule costs discussed in Chapter 4 because, as shown in Exhibit s 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 Requi rement 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 ide ntical 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

inclu ded 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 vegetati on.

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 woul d be

lower if on

- site clay is available.

183 This closure cap is comprised of a 1.5 foot slope and earth f ill, 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 im pacts on total incremental costs, on the order of less than 2% of total incremental costs.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 40 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 onl y 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 post

closure monitoring costs to out

- years beyond the 100

- year period of analysis in this RIA. While this assumption sl ightly 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 f or 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 $1 2,858 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 w ere not available. This RIA therefore uses a more generic estimate based on a surveyed subset of impoundments.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 41 Exhibit 3

- F
Baseline Cost to Industry and State Governments for Impoundment Structural Integrity Evaluations

Paperwork Burden Element a Labor hours Cost (2006$) Cost per

Plant Annualized Cost

per Plant b
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 engineer c 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

ins tability 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 i nspection 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 201 3 BLS Employment Cost Index for professional, scientific and technical

workers/104.6 December 2006 index = 1.1874October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 42 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 S ection 4.3

. 10 . To the extent that the baseline corrective action requirements in these states are not as stringent as those

r equired 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 ove rstate 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 requir ements. 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 st ates, 21 required correction action:

 For surface impoundments: Arizona, Indiana, and Iowa establish a corrective action alert level and response action in site

specific 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 regulation s; 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 respon se 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 no t 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 requirement s 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 indica tes: (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 corr ective action as of 2011, although the corrective action could be a r elatively 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)October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 43 3.2 .5.12 Baseline Impoundment Closure and Conversion t o 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 convers ions is consistent with the recent ( 2009 1996 to 2011 201 2 ) declining trend in wet handling of CCR tonnage for disposal documented in as 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 convers ion under

the CCR final rule . Detailed information on calculations used to estimate wet

- dry conversion

co sts can be found in S ection 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 th e 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 2012 comparison of EIA

- 92 3 data, CCR “pond d isposal” 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 G DP 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 o f “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 th an other waste types.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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3

- 44 

### 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,

r espectively

. 191

, 192 Appendix N provi des plant

- by

- plant and owner entity

- by

- ent ity 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, be cause surface impoundments will not undergo changes in CCR management as a result of groun dwater contamination events, this RIA do es 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 present s the expected value , which can be thought of as average of the costs for each outcome, weighted by the likelihood of that outcome

occurri ng, as the central estimate. This RIA do es 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 at tributed 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 facility plant with an impoundment that switches to dry hand ling 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 c hapter and Chapter 4 indicate the cost of future CCR
management o f the CCR that is currently in landfills and current CCR management in landfills (before those existing landfills close), and the “disposa l impoundment” tables in these c hapters indicate the cost of current CCR management in disposal impoundments as well a s 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 ev en 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 mana gement
f or 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 con trols,

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

r equirements, as opposed to estimated, illustrative

- only cost breakdowns.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

3

- 45 both the baseline and the CCR final rule scenarios. For additional information on the uncertainty and variability to to tal 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 Landfill s 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 Total s = $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 o f existing and new landfill s subject to these requirements. ** Despite a probabilistic component inherent in the applica tion of this cost component, this Exhibit present s 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 pro babilistic component of modeling this requirement can be found in Chapter 7

.

NOTE: EPA has updated or oth er wise 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 oth er wise modified this exhibit of the RIA;

see Exhibits 9

- F to 9

- I in Section 9.4.1 of this RIA for updated exhibits.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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3

- 46 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 $2,4 40

3. Leachate collection systems $25 2

4. CCR fugitive d ust controls $20.1

5. Run

- on/run

- off controls $4.3

6. Location restrictions** $2 2. 6

7. Closure capping $3 9

. 0

8. Post

- closure groundwater monitoring (30 years) $0.2

9. CCR impoundment s tructural 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 s tructural integrity inspections** $0.1

14. Corrective action for CCR contaminated groundwater $0.5 4

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 cos t of these requirements and weighted by the number o f existing and new landfill s subject to these requirements. ** Despite a probabilistic component inherent in the applica tion of this cost component, this Exhibit
present s an expected value cost rather tha n 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 oth er wise 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.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

3

- 47 (2013$). 193 This cost includes amortiz ation 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 c onveyor 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 inc lude 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 pollutio n 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 dis posal. 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 th e 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 und er 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 land fills where no CCR landfill s 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 lo cated 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 distanc e 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, t he total cost of the facility may be increased, resulting in higher disposal costs over time."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

3

- 48 These costs rang e 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 unkno wn 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 t hat 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 dispos al ar e 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 fo r 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 elect ric 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.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

- 1 

## Chapter 4

Estimated Costs for the CCR Rule

Not e : 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. S ee 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 . T he rule requirements are outlined below. Th is 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 t wo 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 : EP A has updated this section of the RIA to reflect revisions to the rule requirements

. These updates are not reflected in this section. S ee Section 9.3 in Chapter 9 of this RIA for a description of the relevant modifications and updates to this section.

O n June 21, 2010, EPA co

- proposed t wo 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 closu re 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, groundw ater monitoring, fugitive CCR dust controls, financial assurance, corre ctive 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 s afety 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 2 facilities that dispose of, treat, o r, 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 n ational 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; exis ting 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 requirem ents 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 EP A 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 : T his 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 op erate 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 ver sion of the June 2010 prop osed 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 u tility 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 fu ture 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. S pecifically:

 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

remova l system.

o Existing landfills that continue to receive CCRs after the effective date of

the C CR rule may continue to operate , and are not required to beOctober 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

- 3 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 alt ernative. 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 effectiv ely 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 poin t 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

thresho lds 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 surfac e 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 l iners 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 exi sting surface impoundments with clay or composite liners, 19 liners have been identif ied 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 grou ndwater 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 earl y unit closure for lined impoundments.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 4 pertaining to closure within five years of the rule’s publication date applies only to those impoundments found to ex ceed 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, groundw ater 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 eithe r 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 rul e.

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 req uirements 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 (20 15 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 impou ndments, and costs associated with the requirements vary in s ome 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 ); andOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 5  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 un der 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 assumpt ion 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 c ontrols 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 d ust cont rols; and

 Storm water r un

- on/run

- off controls.

The incremental CCR pollution control costs associated with these three cost items are Fortran

based 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 landf ill 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 cappi ng 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 e xist under state regulatory baselines.

At closure, the model compares a number of distinct CCR management and disposal options on a going

- forward basis:October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 6  CCR management and disposal in a new on

- site dug landfill for 40 years, which will be vertically

- expa nded 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 basi s 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

- yea r 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 wit h CCR landfills. 203 This is in contrast to the post

rule 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 land fills with all attendant cost equations within the model. Furthermore, if a landfill closes, chooses a new landfill, and that new landfill is vertically ex panded 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 STA TA model assumes all subsequent choices will be the same, consistent with t he fact that EIA AEO projections do projection of future coal consumption for electricity generation do es 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 onl y 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 per iod 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 the ir 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 7 4.1.2 Disposal Impoundments

Note : EPA has updated or otherwise m odified this section of the RIA. These updates are not reflected in the text and exhibits in this section. S ee 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.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

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- 8 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 regul atory 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 e ach 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 even t 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 dispos al 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 state

adjusted Fortran

- based cost equation, with year

- to

- ye ar 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 projections projection of future coal consumption for CCR electricity generation in that year. )

. In additi on, 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);October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 9  Fugitive CCR d ust controls; and

 Storm water r un

- 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 turn s 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 F ortran 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 incur red 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

20 20 (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, di sposal 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 incur red 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 t hat 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 trigge r for the decision point in this case.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 10 the out

- year event is incurred prior to 20 20 , or Year 6 of the analysis, in which case the decision point is pushed out to 20 20 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 impoun dments 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 T he STATA

- based model, as well as this RIA refer to “decision points” and “unit closure” as the first year in which a coal

fired electric utility plant must take steps to change CCR management method (including closing an ex isting 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 metho d. 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 o f 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 e xisting 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 t o determine

age

- based decision points. This is consistent with the assumption that impoundments above 40 years of age represent newly

created “cells” of older existing impoundments; however, to the extent that those older impoundments incurred a contaminat ion 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)October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 11 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 going

forward 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 conversio n, 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)October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 12  Choice 3: Impoundment closur e, 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

- specifi c 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 contr ols, and run

- on/run

off 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, on

site landfill at the same plant (this choice is unavailable if there are no on

site landfills at the same plant, or if the existing landfill has closed and

shifted to off

- site disposal i n 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

p ile 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 cos ts 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 dis posal 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 conver ted disposal impoundments may incur higher costs in the CCR final rule scena rio 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 basel ine. Total conversion costs are approximately $20.07 per ton. Costs associated wit h 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 we t 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 13 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 addition al 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 3 0

- 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 o f 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. S ee 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

co nversion costs across all plant sizes. Due to speci fic modeling considerations, this RIA model s 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 alwa ys 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 c hoices will be the same, consistent with t he fact that EIA AEO projections do 2014 projection of future coal consumption for electricity generation do es not project changes in CCR generation and disposal past 2040, and as such any option determined be the l owest

- 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 ana lysis 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 14 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 i n 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 requireme nts 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,” th e 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 d etermined 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 pl ace 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 st orage 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, du st 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

-October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 15 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 storag e 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 st orage 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

stor age 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 i nto 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 rec ordkeeping 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 impoundmen t 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 cost s 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

re present 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 cr eation 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 ret rofit

costs for s torage 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 facility plant . See Section 4.3.10 for more information.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 16 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 in dustry are affected by the CCR final rule, impacts on these industries are expected to be positive, based on an increased demand for transportatio n and off

site disposal of CCR. This RIA addresses the potential impacts associated with increases in off

sit e 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 P ollution 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
government s 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.,

gr oundwater 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 include d in the baseline cost estimates in Chapter 3

, this section briefly summarizes the cost assum ptions for the CCR final rule

. Estimation of these

costs employs the same data sources and methodology used to estimate baseline costs. For unit

level costs not in cluded 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

estimat e compliance costs of the CCR final rule.

Unit

- level costs are described in Se ctions 4. 2 .1 through 4. 2 .9 . They include:

1. Groundwater monitoring;

2. Composite liners;

3. Leachate collection systems;October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 17 4. Fugitive dust controls;

5. Rain and surface water run

- on/run

- off controls;

6. Disposal unit location restrictions

– water tables, floodplains, wetl ands, 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 S ections 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 Ge neral 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. S ee 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 gen eral 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

es timation 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 C ost 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 n ot all costs are explicitly and uniquely estimated in relation to the electric utility industry. Cost uncertainties are addressed briefly in more deta il in Chapter 7

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- 18 unit with a given set of CCR pollution controls and baseline requirements is based on a set of Fortran equat ions 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 oth er 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 t he 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 pollut ion 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 co sts 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 baselin e and $50 under the CCR rule , or an incremental cost of $25. Running the model with the first pollution control only yields a baseline co st 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 co sts 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 pollut ion 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 contaminatio n 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 increas ed 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 al l pollution controls are required simultaneously. It is possible that simultaneous pollutio n 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 19 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 regularl y, 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 impoundme nts are present but

EIA reports data 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 manageme nt 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 f or additional discussion regarding alternative compliance assumptions.

 E conomies of scale

. This RIA does not account for any economies of scale resulting from co

- located (adjacent) CCR management units. For example, co

located 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 inspec tions 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 baseli ne 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 20 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 cos t 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 c hapter 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 u nknown, 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 promp ts 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 contin ue 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 character istics 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

resul ts 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 contro l 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. C osts d iffer 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 detail ed 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

modelin g determines that an impoundment must close prior to this 40

- year assumed lifespan,October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 21 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 facilit ies 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 2 7 years of the unit’s life beginning in 201 5 (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., 201 7 . (The effective date of the rule is 6 months after publication in the Fed eral 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 d isposal 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 dis posal 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 require s 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 Estimate s

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 colle ction systems for all newly

constructed 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 EstimatesOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 22 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 requirements 222 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 lifespa n of the unit (i.e., landfill).

The CCR final rule require s the following five fugitive CCR dust control requir ements:

 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 agent s 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, revi sed 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 specif ically

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- 23 that the facility electric 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 in cluding 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 profession al 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 residen ts and employees of the facility plant . The plant must also notify t he 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

a ssortment of baseline state government dust control requirements. This baseline practice constitutes two of eight dust control measures requi red under the CCR final rule . Although only one of the eight control measures is a requirem ent 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. De tailed 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 rep lacement 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

cover ed by this RIA, as at most, three dust control plans would need to be created for aOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 24 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, a nd $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

record keeping 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 Appe ndix 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, thr ee 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 appr oximately $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 con trol 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 l evel 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 Impou ndment 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 tha t it includes a number of dust control technologies as aOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 25 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 assum ed 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 p er 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 t hat all surface impoundment s undergo closure as landfills, meaning that surface impoundments are not excavated, nor is their ash trucked off

- site. In summary, dust controls are generally unnecess ary for s urface impoundment s, 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, t his 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

avera ge 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 Enginee rs 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 use s the frozen, high

- wind days scenario as a proxy for these cases as well.

225 In cases where impoundment acr eage 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 26 For surface impoundm ents, 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 n ew 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 im poundment 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 run

on/run

- off controls at surface impoundments are not un derstated, 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, t his 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 doe s 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 followi ng 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 demonstration s 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 base d 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,” me morandum 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 27 Database of the United States 229 to determine the distance of the nearest fault to the CCR plant centroids, although this centroid may be one or two kilomete rs 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 loc ated 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 fa ult 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.

 Sei smic 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 t he 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 e xceedence 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 CC R

rule.

231 “Vulnerability Criteria Information for C oal 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 reg ulatory 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 des ign

featur es 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 mu st
noti fy 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 collec ted

from USGS Na tional Seismic Hazard Maps ( http://earthquake.usgs.gov/hazards/products/conterminous/2008/update_201001 ) to determine which plants are located in areas with peak gr ound 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 28 Overall, this RIA identifies only 13 CCR management units (nine landfills and four disposal impoundments) that ar e 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 identi fies 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. Onl y 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 distributiona l 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 mo deled as closing, these restrictions apply only to landfills and disposal impoundmen ts. 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 all ow the construction of new CCR units, and the continued operation of existing CCR landfills and surface impoundments in karst terrac es where the owner or operator can demonstrate that engineering measures have been incorporated into the landfill, surface

i mpoundment, 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, an d

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 ele ctric 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/ se e 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 thi s 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 29 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 Estimate s

237 However, it is worth noting that the unstable areas location r estriction 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 decis ion point and unit closure, as opposed to only forcing offsite disposal once a unit has already closed.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 30 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 detail ed and comprehensive evaluations , and

t hat 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 mor e 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

clas sify 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 t o 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, th is 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 ass igns 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 ex pert judgment and institutional knowledge based on the company’s extensive experience with the electric power industry.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 31 o $18,000 for every plant with an exi sting 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 i f 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 imp oundments 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” i nspections (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 reme diation 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, pla nts 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 tha t 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 impoundm ent s that are modeled to close.

4.2 .11 Corrective Action Remediation Cost Estimate s

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 Tren ds” that provides RCRA corrective action

240 For RCRA corrective action requirements under Subtitle D, see 40 CFR 257.21

– 257.28.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 32 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 t han 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 atten dant 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.clu

in.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 millio n average cost ($2003),

ove r 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).October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 33 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 ($millions) Average Cost ($millions) Low High Low High < $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% disc ount 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 to tal 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 T he 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 gen erators (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 17,50 0 (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, 2001October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 34 weighted annual costs are then $2,600 under a 7% discount r ate 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 resul t 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 thi s sectio n 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 unit

based level; however, these cost s 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 tw o 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 requirement s incl uded in this category

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 35 on

- site disposal units, while others pertain solely to surface impoundments. Overall, under a 7% discount rate, these reporting and recordkeeping costs sum to $ 2 4,636 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 pla nt. 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 n ot 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 Estimate s

In the baseline, disposal impoundments will close a nd 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 o n

- site landfill will

result in lower fut ure CCR management and disposal costs relative to opening another on

- site disposal impoundm ent. 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 facility an may still choose to open a new lined

on

- site surface impoundment if that is determined to be the most cost

- effec tive 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 associat ed 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 impoundme nts 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 critica l 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 sy stems 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 t he 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 36 Plants closing impoundment systems must recon struct 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 a rea. 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 primar y 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 fo r 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 techn ical 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 eq uipment 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 convers ion 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 Co al 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_20 01_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.pdfOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 37 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

f inal r ule wet

- handle FGD gypsum and might potentially require the implementation of a tank system, this RIA does not separately model t his 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 standa rd 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 wet

dry conversion cost (also ob tained 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 d egree 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 pr oposed rule indicate that general

wet

- dry conversion costs are higher than ta nk 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 n ationwide 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 impound ment s

. 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

convers ion 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 t he 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 followin g 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

we t

- 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

preserv e 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/questionnair e.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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 38 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 dispo sal 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 th e associated costs in the CCR final rule scenario. 255

4.2 .13.1 Financial Hurdle Costs for Wet

- dry C onversion

As indicated in this c hapter 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 capi tal 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 el ectricity 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 fo llowing 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 syste ms 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 capita l 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

l ogic 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/ste am

- electric/questionnaire.cfm

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 39  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 hu rdles 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 Adjust ments

– 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

deter mines 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 co sts 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, th is RIA assesses the cost of dewatering and

capp ing 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 co sts.
This RIA estimates one

- tim e 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 wi th available

dimension data. This RIA annualize s 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 ass igned in order toOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 40 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 present s 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 requiremen t to which they correspond, at 0.0 8 % and 0.06% of costs, respectively. 257



### 4.3 Summary of CCR Final Rule Regulatory Costs

N ote : 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. S ee Sections 9.2, 9.3

, and 9.4 in Chap ter 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 display s total incremental average annuali zed 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 provid es 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 recordkeep ing, 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 41 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 groun dwater contamination events that prompt changes in CCR management. Correspondingly, Exhibit 4

- D characterize s the variability inherent in this probabilistic component by displaying total incremental costs under a central estimate scenario, which presents a n 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 weightin g 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 probabili stic 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

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 42 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. Dust CCR fugitive d ust 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 cost s ) does not subtract the “cost offset ” which is di splayed 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.

 ** De spite a probabilistic component inherent in the applica tion of this cost component, this Exhibit present s 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 43 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. Dust Fugitive CCR d ust controls $4.74

5. Run

- Storm water r un

- 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 inactive I nactive 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 anti cipated 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 beha vior 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 44 4.3 .1 Summary of Largest and Smallest Percentage Components of Regulatory Costs

Note : EPA has update d or otherwise modified this section of the RIA; see Se ctions 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 cost s such as groundwater monitoring and dust controls. As a result, the majority of rule costs (over 65 % for li ners 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 uni t

- 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 i n 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, cappi ng, 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 update d or oth er wise modified this section of the RIA; see Se ctions 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 45 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: probabil istic 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 bas is 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 var iance 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 acro ss 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 e xhibit has not been updated to reflect the revisions described in Section 9.2, 9.3
and 9.4 in Chapter 9 of this RIA

.

E xhibit 4

- F

Cumulative Probability Functions of Total Post

- Rule Costs Present Values at 7% Discount Rate (2013$)

Disposal Impoundments

– Total Post

- Rule CostsOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 46October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 47 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

N ote : 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

sec tion. S ee 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 bas is (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:October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 48  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 u nit, 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 th e ends of their operating lifespans and have been replaced with newly

- lined

u n its. Second, for unlined impoundments, age is a probabilistic input into the likelihood of a groundwater contamination event occurring. Given that these events prompt decision po ints 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 ei ther 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 202 0, 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

c hapter, given the probabilistic relatio nship 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 multi

year 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 di splays 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 annualize d 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 wil l 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 present ed 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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4

- 49 $- $200 $400 $600 $800 $1,000 $1,200

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

- 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

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

- 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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- 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 o f 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 e xhibit 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
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4

- 51 generally do not occur until later in the period of analysis. While costs appea r 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 w et

- 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

con tamination 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

on ly slight variations due to the future annual change s 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 pro babilities to incur groundwater contamination events in years other than 2020 based on their ages.

4.3 .4 Changes in Universe Composition over Time

No te : 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. S ee 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 impoun dments 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

eve nt. 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, co nsider 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 contaminatio n 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
Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

4

- 52 Note : The e xhibit s 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

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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 LFOctober 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

- 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 e xhibit has not been updated to refl ect 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

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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 LFOctober 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

- 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 impo undments 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 r eaches the end of its operating life.

0 20 40 60 80 100 120 140 160

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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 SIOctober 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 e xhibit 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, cl osure 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

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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 SIOctober 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 conve rsion option is cost

effective 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 m anagement 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, conversi on 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.

Exhibi t 4

- M below displays the post

- rule universe composition for storage impoundments. As

described earlie r in this c hapter 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 subs equent 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 gro undwater 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 alre ady 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 e xhibit has not been updated to reflect the re visions 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 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 SIOctober 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

- 57 Note : This e xhibit 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 20 14); 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);

 Exis ting 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 st orage 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

- sit e 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 alread y 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 t ime reflects solely the disposal impoundments that have shift ed 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

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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 SIOctober 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

- 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 e xhibit 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 disposalOctober 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

- 59 Note : The e xhibits 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 exhibit s 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 eff ects 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 disposalOctober 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

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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 LFOctober 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 e xhibits 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

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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 LFOctober 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 e xhibit 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

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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 LFOctober 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

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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 SIOctober 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 e xhibit 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 th e 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 constitut e approximately just 1% of t otal 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

im poundment s, as nearly al l 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 of f

- site disposal in out

- years (or, conversely, that relatively smaller landfills are those that opt to transition to new on

site 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

2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080 2085 2090 2095 2100 2105 2110 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 SIOctober 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

No te : 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
cha pter. S ee 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 uses 260

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, fac ilities 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 r ule 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.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

- 2 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 dis charges 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 model ed for the ELG rule to correspond to the surface impoundments project ed 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 surfa ce 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 w ater 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 wa ter 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 mod eled for the ELG rule to correspond to the surface impoundmentsOctober 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

- 3 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 R IA 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 consi stency 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 exten t 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 two three benefit categories

, prevention of

--- reduction in CCR impoundment releases and prevention of , re duction 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 associa ted 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 of

Reduced 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 of

Reduced future CCR groundwater contamination Groundwater pollution prevention controls Groundwater contamination rates by liner type

3. Increase I nduced future annual

in crease in CCR beneficial use use s 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 mer cury exposure from maternal fish consumption Scaled from EPA

- OW estimates

262 To the extent that EPA

- OW’s analy ses change in the SPGELG final rule , the results in this RIA would move accordingly.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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5

- 4 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 water

based 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 vicin ity of

CCR units Habitat improvements leading to potential increases in threatened and endangered species’ populations Scaled from EPA

- OW estimates

1 0 . Improved air quality from electricy plant emissions , including

reduced air pollutant emissions of

NO x , SO 2 , particu late matter, and &

CO 2 Reduced mortality and morbidity from exposure

to air pollutants ; avoided climate change impacts Scaled from EPA

- OW estimates

1 1 . 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

hand ling 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, t hese 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) possi ble conversion to dry handling in lieu o f retrofitting CCR ponds with lin ers (fly ash and bottom ash), and (b) conversion from FGD impoundments to FGD tank systems . This RIA scales

values for the monetized benefits from t he SPGELG proposed rule using the following three

- step
method : 264

Step 1: De termine 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 empl oys 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 assu mes that plant management and closure behavior are

similar under SPGELG and the CCR final rule.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 5 electric ut ility 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 th e Ste am Electric Power Generating Point Source Category,” EPA Office of Water, April 2013, available as document ID nr. EPA

HQ

- OW

- 2009

- 0819

- 2256 at http://www.regulations.gov

266 As explained on pages 10

- 1 and 10

- 2 of E PA

- 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, EPA

OW’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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 6 Waste Type P ollutant 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 C CR landfills from CCR pollution control requirements, including exemption from the leachate collection system requirement, this RIA subtracts EPA

OW’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 EPA

OW’s Benefits

This step calculates a second scaling fact or 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 9 3% 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 requirem ent 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 tha t 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 t o 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 add s the 29% FGD pond tonnage toOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 7 the 64% adjusted subto tal from above. As a result, this step estimate s 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 adjust s the scaling factor upward to acc ount for the additional CCR pond tonnage not associated with ELG4

benefits.

Step 3: Calculate the Overall Benefits Scaling Multiplier

No te : EPA has updated the the assumptions in calculating this multiplier. These updates are not reflected in the text and exhibits in this section. S ee Sections 9.2 .5 and 9.4 in Chapter 9 of this RIA for a description of the relevant modification s 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 perc entage 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 result s 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: T he 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 stora ge 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 scalin g 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 loa dings 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 ben efits 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 otherOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 8 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 categori es in detail, beginning

with the three benefit categories monetized using met hodologies specific to this RIA, followed by the rema ining 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 t he 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 prevention reduc tion of future releases, including thos e 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 t h e baseline

× Reduced overall annual probability of failure

× Gallons released per failure ( capacity fa ctor )

× 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 red uced 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, incl uding 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).October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 9 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 contri bute 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 weather

related 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 exam ple, 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; seepa ge 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, Natio nal Research Council, National Academy Press, Washington, D.C., 2000.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 10 7. Operational and maintenance factors . Operational procedures for water diversion and release prior to and during flooding; operational proc edures 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 di rectly , 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 occurre nce 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. S ee 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 preventing reduc ing 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 bene fits by reducing risk and preventing reduc ing costly remediation, but also lead to increases in costs rela ted 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 ke y 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, involv ement 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 th ese 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/spec ial/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#lette r.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 11 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 unde r 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 lett ers 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 imp oundments), 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 Stat istics for the 49 CCR Impoundment Release Events

1995

- 2009
Capacity (acre

- feet) Height

(feet) CCR gallons

released Year of

release

Observation s 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 rele ases, 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 year s for those observations that

we re noted prior to 2000 in determining annual release risks

. U tilities 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 r eleases 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 ev ent would be 540 acre

- feet ((2,000 * 0.27).October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 12 for each type of release were c alculated 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:

 H eight (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

fee t or more above the upstream

to to e

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 numb er 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) w ere 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 cap acity 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 appli es 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 requi rements may prevent and thereby reduce future CCR impoundment release events. The post

- rule re lease rates and capacity factors are

shown in Exhibit 5

- E . Although the elements of the CCR rule are designed to prevent reduce 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 d etected, 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 orOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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5

- 13 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%.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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5

- 14 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 CCR rule requirements to have prevented reduce 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 15 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 F actors 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 % reduc tion in future wall breach events

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 16 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 F uture CCR Impoundment Releases a

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). Th ese 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 fail e d 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, li mits 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 n early constant pressure over time from the water contained beh ind 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

variatio n 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 signifi cant 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 o f 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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5

- 17 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 rep roduced

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$) Unit Unit ized

Remediation Costs ( dollars 2013$ 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 cost s 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 assign ed 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 18 For each year of the analysis, this RIA estimates futu re 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 ye ar 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 g a llon 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 contaminati on 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 thes e cases t he power

- generating facility electric utility plant owner. To estimate NRD cost s avoided as a result of prevented reduc ed 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 prepare d 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, c ases 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 samp le 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. NR D 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 19 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 availab le 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 i ndirectly 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 impoundm ents 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 env ironmental 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 ana lysis , 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 g a llon released

In addition to remediation costs and NRD, transaction costs as a result of impoundment releases can be significant. Transaction costs include l itigation costs incurred in the process of negotiating NRD, determining responsibili ty 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.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

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- 20 TVA and paid to the Shook Hardy and Bacon law firm were reported at $11 million as of

Decem ber 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 releas es , 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 remed iation 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, t he average transaction costs represen t 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 litigatio n ) costs. The benefits estimated in this section stem from impoundment closures, t he 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.” Associ ated Press. December 16, 2011. Accessed through the Chattanooga Times Free Press at: http://www.timesfreepress.com/news/2011/dec/16/tva

- says

- legal

costs

- 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

- legal

costs

- ha ve

- 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 o f 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

- r elated activities of major U.S. corporations." Report to Congressional Requesters. December 23, 1994.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 21 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 baseli ne, at most CCR impoundment s 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 preventing reduc ing 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

gr oundwater 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 pe rtaining to CCR impoundment s. 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 facility electric utility plant is located:

 High

Level : States have groundwater monitoring requirements for both new a nd

existing CCR impoundment s.

 Low

Level : States have monitoring requirements for newly constructed CCR

impoundment s only.

 None : States do not have any gr oundwater 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 w ith 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 impoundm ent 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 22 assumed identification represents the time from release at an unlined impoundment to peak groundwater co ncentration at nearby drinking water wells. Specifically, this time was estimated

as t he first percentile time from release to peak groundwater concen trations

. 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.

Assumpt ions 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 yea r of its implementation , this RIA assumes that groundwater contami nation from CCR impoundment s will always be detected early. Furthermore, this RIA assumes that closure and capping of an impoundment prevents any
residual risk from liner s. Thus, when impoun dments close, risk of contamination goes to zero.

Unde r 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

lin ers 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 mus t 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 eve nts which may occur under the CCR final rule :

 This RIA assumes that no r eleases 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 manage ment units , the RIA multiplies the probability that an impoundment or landfill is operating by the risk of leakage to estimate the combined probab ility that a unit is both operating and leaks. Land fills are assumed to remain operating or be replaced with a new landfill for the durat ion of the period of analysis

.

 The risk of ground water contamination for CCR impoundments is the probability

weighted 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 assessme nt. 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 f irst 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 wit hout stringent monitoring

standards.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 23  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 ch anged to match the new composite liner type for these un its.

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 req uirements are listed in Appendix

G . Th is RIA assigns a risk of contamin ation 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 wat er 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 d ata.

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 esti mation 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 exp ected that higher contamination probabilities occur at lower distances (i.e., one meter) relative to greater distances (i.e., one

- mile radii).October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 24 may understate costs.

 Early Groundwater Remediation: To estimat e 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 25 th percentile remediation costs displayed in Exhibit 5

- J below, representing th e 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 y ears 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 disco very allows CCR contamination to migrate farther, resulting in more extensive remediation. This RIA a ssigns these events

the 75 th percentile remediation costs in Exhibit 5

- J , represe nting 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 residua l risk associated with composite liners. Then, this RIA multiplies the sum of the risk

of release at acti ve impoundments and landfill s 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 opposi te 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 th ese 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 per fectly predict impoundment op erations, 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 25 Groundwater contamination also results in d amages 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 contam ination. 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 parti cular 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
separate ly 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

t o 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 contaminant s , they have a common injured resource (groundwater) and affect areas consistent with those that might be expected to be impacted from CC R 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 avoi ded 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, w hich 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 contamin ation events at:

 The Verona Well Field site contamination included volatiles organic compounds and impacte d three aquifers over an a rea of approximately 160 acres.

 The South Valley Superfund Site involves groundwater contamination resulting from various manufacturing and industrial

processes occ urring at the Albuquerque site.

 The Ensign

- Bickford Trojan Facilit y incident involved discharges from an explosives manufacturing facility that created a groundwater plume extending approximat ely 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 26 

### 5.3 I nduced I ncrease d 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 Section s 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 b eneficial use

of CCR. Of the 12 0 .4 million short tons of CCR generated by coal

- fir ed electric power plants in 2012 (from Chapter 2 of this RIA), approximately 52 million tons (43 %) were beneficially used in place of virgin materia ls 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 substitu te for virgin sand and gravel in structural fill applications, and usi ng FGD gypsum as a substitute for raw gypsum in wallboard production. Focusing on only these

three industrial market applications , this RIA conducted a detailed an assessment of the beneficial

use potential future impacts of the CCR rule

, on these beneficial uses (i.e., induced future increase)

, as documented in Appendix S . This se ction summarizes the results of that analysis,

and also estimate s the “ avoided disposal costs associated future potential “ cost offset ” associated

with changes the 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 sepa rately 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 si milarities 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 relate s 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 impo undments 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 fin al 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 describ ed in this paragraph

, this analyzed option differs from both the CCR final rule and

the regulatory scenarios examined in Appendix S

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 27 beneficial use. However, there have been other modifications to the cost estimation methodology of this RIA since specification of the analyzed opti on 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 rul e) 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 o ptions 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 g reater detail in Appendix S

.

The LP approach of this RIA estimate s 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 benefi cial 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 dispo sal 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 benefici al 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 th e need to develop future sites (including land acquisition, permitting, design and construction costs) is avoided. If a utility is unable to market or otherw ise 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 competit ion 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 co nstruction 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 cove r 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.acaa

usa.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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 28 5.3.2 Estimated Changes Fu ture 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 wall board 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 ava ilable 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 con version fro m wet handling to dry handling.

Exhibit 5

- K Percentage Change Increase 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 remai ns 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 un certainty associated with projecting beyond 2035, this RIA assumes that post

- 2035 beneficial use impacts remain constant at levels projected for 2035.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

- 29 Complementing the percentage changes in beneficial use shown in Exhibit 5

- K

, Exhibit 5

- L presents the absolute change increase 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 in Increase in CCR Beneficia l Use by Option and Application (millions of tons)

Year Fly Ash in Concrete FGD Gypsum in Wallboard CCR

in Structural 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 in Future 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 Section s 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 thes e changes in dem and. 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 imp acts associated with

the changes increase 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

.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

- 30 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, benefit s 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 a ccount 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 t hat for SO
x , where there exists a cap and trade permit program, firms must pay to emit SOx. A portion of the SO
x emissions avoided from beneficially using CCR is from the energy sector. Under the presumption that the marginal costs of abatement equal the v alue of marginal damages, the value of the portion of SO
x emissions from the energy sector could be reflected in the energy cost savings. In other words, under the SO
x cap and trade system, a

reduction in SO
x from one source could lead to increased emissi ons 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 Sec tion s 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 Changes Induced Incr ase ease in CCR Beneficial Use

Year Energy (MMBtu) Water

(Million Gal) Greenhouse

Gases (Tons) NO
x

(Tons) PM 2.5

(Tons) PM 10

(Tons) SO
x

(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

Monet ized Value of Beneficial Use by Environmental 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 $17.0October 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

- 31 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 Costs CCR 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 Section s 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 are beneficial use which is

not directly affected regulated by the 2015 CCR final rule (e.g., using fly ash as a substitute for portland cement in concrete production).

. The CCR rule cost results estimates presented in Chapter 4 , however, assume that all CCR currently managed through disposal will continue to be disposed of following promul gation of the final rule, thus overestimat ing the CCR rule’s true

cost impacts . To account for the expected reduction in future annual CCR disposal resulting

from t he rule, this RIA estimates the an 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 costs this cost offset , this RIA applies the approach represented by Equation 1:

( 1 ) A = ∑ ( B t × C t )

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;

B t = the increase in CCR beneficial use in year t (measured in tons); and

C t = 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 analysi s presented in Chapter 4 , this RIA estimates avoided disposal costs of approximately $1.3 billion in presentOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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5

- 32 value terms, based on a 7% discount rate. On an annualized basis, this represents a potential
future annual “ cost savings offset ” of approximately $ 92 million per year ( based on a 7 7% 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 impor tant to note that these avoided costs represent this co st offset represent s 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 compliance this cost savings are offset 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 Section s 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% dis count rate). In addition, as indicated in the exhibit, the avoided compliance cost benefit described above represents approximately three

fourths of the estimated benefits associated with beneficial use. environmental benefits of the expected future induced increase in CCR beneficial u se, 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:

1 A 1 . Environmental Benefits of Increased CCR Beneficial Use $30 .0 $38 .0
2. Avoided Compliance Costs A2. CCR Rule “ C ost Offset ”

Associated with Increased CCR Beneficial Use $92 .0 $125

Column totals = $122 .0 $163

B. Present Value:

1 B 1 . Environmental Benefits of Increased CCR Beneficial Use $430 $1,200
2. Avoided Compliance Costs B 2. 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 , t he 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 RI A with respect to this cost offset factor.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 33 

### 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 post

compliance 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 o rder 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) f or 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 populat ion of 137,476.

For the baseline and ea ch 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 th ese 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

associa ted 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 assum es a linear relationship between pollution inputs and benefits, and is not able to take into account that human health benefits may be si te 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

- R

13

- 004, April 2013, available from the Federal regulatory docket as document ID nr. EPA

- HQ

- OW

- 2009

- 0819

- 2238

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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5

- 34 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 ri sks 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 P rotection 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 (20 01); (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 canc er 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 th e 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

- to

cancer 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,” E PA 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 W elfare 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 res ults of this analysis suggest that benefits for the CCR rule are approximately $0.7 million, annualized at a 7% discount rate.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

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- 35 

### 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 abov e 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 m ercury 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 num ber 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 h air 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 avoid ed 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 i n less education and therefore reduced education costs.

At a 3% discount rate, the estimated annual benefits of avoided IQ losses from reduced maternal

exp osure to mercury for the ELG 3 option range between $4.1 million and $5.8 million and range from between $8.4 million and $12.1 million for the ELG 4 option of the proposed SPGELG rule

. This benefit monetization method represents only one component of society’s willingness

- to

- pay to avoid IQ de creases, 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

Standar ds 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.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

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- 36 

### 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 ben efit 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 se ction 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 populat ion 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

betwe en 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 concentra tion 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 willingness

to

- 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 l ifetime 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 annua l benefits of the ELG 4 option are between $5.6 and $7.9 million, assuming a 3% discount rate. This benefit monetization method

repr esents 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 F or 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

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- HQ

- OW

- 2009

- 0819

- 2238 at http://www.regulations.gov.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 37 

### 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 lifet ime 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. Dep artment of Commerce , ad justed 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 compensator y education requirements at $0.02 million and $0.07 million,

for the ELG 3 and ELG 4 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 I Q 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 e nvironmental 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; an d

 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 aqu atic life) are not bought or sold directly and thus do not haveOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 38 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 r ule 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 regulat ion. 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 annuali zed 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 perm itted 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 non

use values. However, given the protected nature of threatened and endangered species a nd the

298 This benefit category is scaled from the estimates in the SPGELG proposed rule. As with human health benefits, t his 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 characteris tics of the affected waterbody, affected population, and pre sence 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 n r. EPA 821

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- HQ

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- 2238 at http://www.regulations.gov.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 39 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 a pproach 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 endang ered 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 stud ies 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 eco nomic 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. 1 0 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 (NO
x ), sulfur oxides (SO
x ), and carbon dioxide (CO 2 ) can provide human health and other benefits. NO
x and SO
x are known precursors to fine particulate matter (PM 2.5 ), a criteria air pollutant that has been associated with a variety of

adverse health effects, the most notable of which is premature mortality. CO 2 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 dama ges from increased flood frequencies, and the loss of ecosystem services, among other sources of

economic loss. Increased CO 2 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. T his 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

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- 40 The CCR rule may have both posi tive 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

be nefits 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 RIA will be forthcoming in an addendum reporting output from IPM.

EPA

- OW compared the estimates of NO
x , SO
x , and CO 2 in the baseline scenario to the post

compliance 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 the se benefits to the CCR rule, this RIA assume s that similar changes in generation will result from the CCR rule and that market impacts can be scaled linearly. For NO
x and SO
x , EPA

- OW then developed est imates 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 combinati on of emission type and source category. Thus, the Agency developed benefits per ton estimates for specific combinations of emission source categories and

PM 2.5 precursors. On the other hand, EPA

- OW estimated the benefits per ton of CO 2 emitted using estim ates 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 fo r that year, and then summing the benefits across all emissions type/source category combinations. The annualized benefits from reducing emissions of NO
x , SO
x and CO 2 are $127.6 million and $170.5 million,

for the SPGELG proposed rule ELG 3 and ELG 4 options respectively, assuming a 3% discount

rate.



### 5. 1 1 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

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13

- 004, April 2013, available from the Federal regulatory docket as document ID nr. EPA

- HQ

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- 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 span ning 2010 through 2050.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 41 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

alternati ve 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 util ized 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 gall ons 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 ELG 3 and ELG 4 options , respectively, assuming a 3% d iscount rate.



### 5. 1 2 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 a nd 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 als o 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 a llow site

- specific analysis. Finally, more detailed risk assessment could improve the estimation of benefits associated with prevented reduc ed 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

m illion 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 f

or the Steam Electric Power Generating Point Source Category,” EPA Office of Water, EPA report nr. EPA 821

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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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 42 a 3% discount rate, this RIA estimates that $ 420 m illion 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 b ut 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 43 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 of

Reduced CCR impoundment releases $208 $220

2. Prevention of

Reduced CCR groundwater contamination $9.8 $13.4

Closures $0.83 $1.45

Liners $5.410 $7.000 Monitoring $3.52 $4.91

3. Increase I nduced future annual i ncrease in CCR beneficial use use s $ 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 cancer b $0.021 $0.015

5

. Avoided IQ losses from mercury b $0.187 $0.783

6

. Avoided IQ losses from lead b $0.125 $0.522

7

. Reduced need for specialized education b $0.000 $0.008

8

. Non

- market surface water quality benefits b, 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 species b $5.8 $2 .6

10

. Improved air quality b quality of electric utility plants b , c Reduced air emissions of NOx, SO2

Reduced air emissions of CO2 $15.5 $13.1

11

. Reduced groundwater withdrawals b withdrawals (after conversion from wet to dry CCR handling) b $0 $0

Total Column Total s = $ 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. 1 2 .2 Regulatory Benefits for Inactive CCR Management Units

As discussed in Chapter 4 , this RIA identified a total of 111 i nactive CCR surface impoundments . Under the CCR final ru le, these inactive CCR impoundments are required to

dewater and install an engi neered 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 th e 111 inactive CCR impoundments , this RIA assumes that closure capping and post

closure groundwater monitoring will provide an additional benefit of $1. 4 8 million per year, assuming a 7% discount rate, consis ting of both cancer prevention reduc tion and reduction in

futu re groundwater contamination costs . This benefit is approximated in absence of data by

ass uming the 111 inactive impoundments are of similar size and regional distribution compared

to the a ctive on

- site landfills, and by simple linear extrapolation of the benefit estimates presented in Exhibit 5

- O for the univers e of 735 active on

- site CCR management units, using aOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 44 multiplier of 0.151 ( i.e., 111/735). Using a 3% discount rate, this additional benefit is estimated at $ 2.03 million per year.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 1 

## 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 o f fugitive CCR dust, and preventing reduc ing CCR impoundment releases

.

 Indirect benefits: Associated with other O ther 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. Dust CCR fugitive d ust health and nuisance benefit s . Reduce community

n uisance 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 impoundment s. 4. Cancer and n on

- cancer human health benefi t

. 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 benefi t

. 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. Commerci al 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 2 10. Avoided impingement and entrainment mortal ity. 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 cos ts 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

wit h 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 r ule, 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 spe cific 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 i s 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 P rogress 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 possibl e. 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, Se pt 17, 2003, pp. 26

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- 3 The value of this benefit would be to reduce future expenses and time associ ated 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 comm ents 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, t his 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’ ma rket 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 capit al 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, e nergy, 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 e stimated 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 re mediation (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 mil lion in na tural 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 lia bilities 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,October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 4 th erefore 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

asses sment 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 ma rket value , and by extension the efficiency of financial markets , and suggest that inaccu rate 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 e fficiently 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, red ucing 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 fin al 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 communitie s 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.

 T o 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 acro ss 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 Env ironmental 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 5 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 acce ssible internet site.

I f 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 dis

benefit 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 env ironmental 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 uncer tainty 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 decr ease 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, Stepha n 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, F inancial 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 6 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 environ mental 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) ex amines 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 r elationship 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 f ind 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. Douthe tt, 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 Fina ncial 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.” Workin g 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.

321 Boto san, 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 informatio n pertaining to a firm’s social performance (i.e. dedication to environmental practices or donations to a char ity)October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 7 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 w ith 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 t his 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 live d 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 quanti fied air and water quality benefits, and would be difficult to separate. But it is likely that those estimates do include the full value of decreasing or eliminating this fear so regulationt that improves CCR management through groundwater controls, structu ral 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 i nvolvement, 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,” Ch icago

- 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 8 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 tha t 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 sho uld 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

e xpected 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. Ne urological 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 non

cancer 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

exposu re, 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

su rface 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 analys e s of risk.

328 A dose

- response relationship is an increase in incidences of an adverse health out come 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 9 stream and lake beds, posing a particular threat to benthic (i.e., bottom

- d welling) 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 addit ional 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 significantl y 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 so urce 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 alte rnate 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

Radionuclid es in the Allegheny River: A Possible Link with Marcellus Shale Operations.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 10 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 n ot 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 surfa ce

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 loadi ngs 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 an d, 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 sh ows 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 impou ndment 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 substit ute 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 i n 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 Agenc y (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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 11 quantify or mon etize this benefit category. This category of benefits is additional to the water

based 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 imp ingement 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 d id 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 cond itions 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

valu ation 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 n eighborhood 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 fe asible.

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 wat er 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 facility plant , and may result in fish mortality due to the high temperatures and pressure changes ins ide the facility plant

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 12 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 hous e 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
expecte d 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 controll ing 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 le ss 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 impound ments. 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 RI A, such as recreation improve ments 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 t he hazardous sites which are cleaned up. As such, applying this relationship to leaking

CCR surface impoundment closures may overstate benefi ts 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 ponds impoundment s . This study conservatively estimates that brownfield cleanup leads to a 5.12% increase in property values fo r 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 crow ding, 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 character isitics 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 1 

## 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 chap ter 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

u pdated 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 re levant, 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 so urce 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, potenti al for plants to comply through fuel switching, tonnage assumed to be handled in storage impoundments, and uncertainty related to transportation to off

site disposal facilities. In addition, uncertainties related to aspects of the cost estimates treated pr obabilistically 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 cap acity 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 uncert ainty

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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 2 

### 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 va riation 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 facility plant 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

descr iption 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 conve rsion, does not capture facility plant

- 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 op tions 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 rece nt developments in the energy market may, for the first time in history, provide some plants with the option to cost

effectively switch from coal to natural gas as a potential method of complying with the CCR rule. The cost model used for this RIA predate s this recent market shift, and does not include the detailed electricity marke t model or the specific facility plant information (e.g., age and technology of coal boilers) that would be necessary to incorporate fuel

- switching as a compliance option. Secti on 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 impac t 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). 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

- handle d tonnage at a given plant reflect realistic possibilities for CCR management in storage impoundments.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 3 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 wit h off

- site disposal under the final CCR rule based on model calibration that ensures that off

site 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 r ule, 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 groundwate r contamination event and thus reach a decision point in a given year . T he 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 purp oses.

 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 sub

ject 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” st atus; 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 ass uming 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

ha ve 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.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

7

- 4 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, cons istent 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 highl y variable depending on facility plant 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 conve rsion, does not capture facility plant

- 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

- d ry conversion at a CCR impoundment if the

d ifference in dry versus wet manage ment 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 wet

dry conversion results in a substantial cost savings relative to wet CCR management o ptions

available to the facility utility 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 mo del 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 purpo ses 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 5 Note : This e xhibit has no t 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 Impoundment s $2 1 5 $26 5

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 facility plant ) identified by Office of Water. Because these large plants also incur a substantial portion of the cost associated with the final CCR rule, e specially 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 man agement 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. T he minimum cost in

Exhibit 7

- E is approximately 61 % less than the central estimate, and the maximum cost is approximately 7 9 % 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 est imate 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 assum ption does not supersede the range of possible uncertainty associated with other assumptions and modeling considerations.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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7

- 6 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 RI A 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 b ecomes a viable complia nce option as compliance option as a result of this the CCR rule, this RIA may overestimate the costs and

underestimate the benefits associated with the CCR rule. 342 The IPM model run analysis

described in Chapter 8 does capture simulate potential future fuel switching by electric utilty plants

.

Recent Developments in the Natural Gas Production Market

Over the last 12 months, developments Developments 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. Accor ding 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 ma de possible by technology advances. Shale gas provided only a tiny fraction of total U.S. gas production before 2005, but now represents represented almost 25 %. % in 2010. EIA expects production of shale gas to increase dramatically by 2035, with only a smal l 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 alr eady 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 ene rgy 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 analys is

are intended for closure or conversion. Therefore, baseline costs may also be overstated. While considerations of fuel switching

are take n into account by the EIA AEO estimates 2014 projection of future coal consumption for electricity generation, that drive

C CR growth in this RIA, those estimates do projection is a national aggregation which do es not explicitly indicate closure or fuel switching of specific electric utility plants. If more fuel switching occurs in the baseline than the this analysis assumes, bot h costs and benefits in this RIA will be overstated simply because there are fewer CCR

- generating plants, but incremental rule costs could be gen erally similar on a per

- facility plant basis. In cases where rule

- related cost increases make fuel

- switching co st

effective, 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.ana lysisgroup.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

- 1 616116/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

7

- 7 envir onmental regulations, and increased competition from natural gas and renewable plants. By 2035, EIA EIA’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 ga s 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 o f CCR un der the

CCR rule and

, other than the IPM analysis referenced in Chapter 8

, does not consider the possibility that electr ic utility plants or their owner entities may decide to move away switch from

coal as a fuel source to other fuels . The market shifts outlined above post

- date the development

of the co st model used in this RIA; t he 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 af fected 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

sh ort

- 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 wh ich 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 pla nts 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 ge neration 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, plantOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

7

- 8 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 natura l 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 retrofittin g 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 owne d 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 univers e, 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

conside red 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 a n 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 Generat ion 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, 20 09 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/energy

environment/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.”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

7

- 9 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.

T o 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 proc ess, 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, b ut 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. 3 2 .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 (fi xed 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 e valuate an upper

- bound analysis where plants are assumed to handle 100% of their wet

handled 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

- f

ired

- power

- plants

- come

- clean

ahead/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. Availabl e at: http://www.anga.us/media/41047/congressional research service

- ng in power generation.pdfOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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7

- 10 Not e : This e xhibit 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 Ra te (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 ru le. 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 5 2 %, and total incremental compliance costs of the rule decrease by over 28 %. 354 Similarly, the lower

bound assumption that no wet

- handled CCR tonnage is placed in storage impoundments on an interim basis, which includes only the fixed or “constant” costs asso ciated 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 incremen tal compliance costs fall to $ 481 million as a central estimate, or a decline of approximately 3 5 % 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 T ransport 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 i n 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 basel ine.

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 th em. Changes to this assumption should be made only in concert with changes to other inputs to ensure that the relationship bet ween 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 decrea sed storage tonnage are very large.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

7

- 11 Exhibit 7

- D examines the impac t 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 e xhibit 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 $10 3 $9 4

. 6

CCR Impoundments $2 1 5 $ 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%. Over all, 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 hi t 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 co sts associated with these elements:

 O ccurrence 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 purp oses 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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7

- 12 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 maxi mum 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 giv en 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 enti re 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 mini mum 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 represent s 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 figure s below track with those pres ented 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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7

- 13 Note : This e xhibit h as not been updated to reflect the revisions described in Section 9.2, 9.3 and 9.4 in Chapter 9 of this RIA

.

E xhibit 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 belo w 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

conside ration.

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 c ost 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

lin ear 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 impoundm ents 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 assumingOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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7

- 14 that each of these impoundments is unlined. Exhibit 7

- F below indicates the range of cost impacts stemming from these assumptions.

Note : This e xhibit 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 $2 34 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

- 1 7 % 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, o r a reduction of approximately 1 5 %; 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 e ither sufficiently

demonstrated or failed to do so

, and switche d 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 inheren t 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 characteri zed in Exhibit 7

- F reflects a part of the broader probabilistic variability shown in Exhibit 7

- E

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 15 Note : This e xhibit 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 $10 3 $10 3 $11 2 Disposal Impoundments $2 1 5 $2 0 2 $2 2 7

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 associ ated with these bounding analyse s 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 unit s 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” inspec tion 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” inspec tions, 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 th e 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 16 Note : This e xhibit 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 Annu alized 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 1 4 %, while the maximum cost is essentially

the same as the central estimate. Overall, this probabilistic element has a minim al 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 facility electricity plant : with assignment of a dditional 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 wit h 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 non

impoundment 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, re sult 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 r esults 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 s tringent 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 17 Uncertainty in Overall Cost Estimates

Note : This e xhibit 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 indica ted 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 c oncavity of the cumulative probability function in Exhibit 7

- I indicates that the majority of costs occur between

the 30 th and 80 th 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 billio n in present va lue terms under a seven percent 7% 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 t he curve shown above, this yields a range between $714 million and $782

million in annu alized 2013$ at a seven percent 7% discount discount rate. Exhibit 7

- J

summarizes these bounds.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 18 Note : This e xhibit 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 30 th $3,570 $714

Central estimate of total incremental costs (expected value) N/A $3,590 $738

Upper bound of likely cost range 80 th $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 30 th to 80 th percentile range represent less overall variability

than cos ts between the minimum value and the 30 th percentile, and the costs between the 80 th 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 i mpacts 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 uncert ainty 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 b y 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 19 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 appropriat e 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 e ach 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
present s 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 a nalysis 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. Fo r this sensitivity analysis, the R IA assume s 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 qu estionnaire 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.htmOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 20 In total, changing the assumptions associated with the capacity factors results in avoide d release

costs of 511% to

- 6 5%. 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 h and, the upper bound assumption

leads to to tal incremental benefits of $1,269 million annually, compared t o 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 f or 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 sensit ivity scenarios.

Exhibit 7

- N characterizes the results of these analyses.

Exhibit 7

- M Alternative Probability of Release a Scenarios for Sensitivity Analysis

Scenario Pre

- Rule Post

- Rule RIA Analysis Base Case a 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 t he 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 r eported 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 21 In total, changing the assumptions associated with the probability of release results in avoid ed

release costs of 12% to 9 %. In terms of the total impoundment release costs avoided from this rule, the agg ressive 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

h and, the middle case assumption leads to to tal incremental benefits of $226 million an nually, compared t o 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 ev aluated 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 complianc e 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, e stablishing 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 implementati on (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 1 6% 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 enf

orcement 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 sub chapter [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 St ates, and (b) any other governmental instrumentality or agency, to the extent permitted by the eleventh amendment to the Constituti on) who is alleged to be in violation of any permit, standard, regulation, condition, requirement, prohibition, or order whic h 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

, transp ortation, 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

- 82October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 22 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 differen t approach. The cost and benefit estimates ( Chapter s 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 valu es (i.e., costs

and benefi ts) 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.,

g roundwater 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 prevention is reduc tion 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 oth er 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 req uirements 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 e xhibit 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 f inal r ule 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 jo int 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 CCROctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
Regulatory Impact Analysis (RIA) for EPA’s 2015 Coal Combustion Residuals (CCR) Final Rule

7

- 23 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 s urveyed 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 Managem ent

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/

post

closure Dust

controls Leachate

collection Location

and pre

siting 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,” Augus t 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 Va riance 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 waiver s/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 bet ween 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 stand ards at

C CR 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 basis 362 supported the variance/waiv er, this RIA only

362 The 2006 DOE/EPA study indicates that state government variances and waivers to state CCR regulations were ge nerally 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, bir ds) 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.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

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- 24 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 reductio ns 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

contro l requ irements

.

Note : This e xhibit 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. 4 9

2. Bottom liners 4% $4 66

3. Leachate collection systems 2% $1 9.2

4. Dust controls 9% $4. 32

5. Run

- on/run

- off controls 0% $2 2

. 8

6. Location restrictions 4% $2 2

. 4

7. Closure capping 1% $1 9

. 3

8. Post

- closure monitoring 1% $0.06 72

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% $0.26 7

15. Corrective action 0% $0.47 3

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

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 25October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 26 

### 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 bene fit an d 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 to nnage 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

con sistency 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

tonn age data.

i. For example, one source ( ACAA 365 ) 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) name plate capacity) plus supplemental estimates made in this RIA for sm all plants (<100 MW capacity). This inconsiste ncy in data sources represents

- 9% to +10% uncertainty (i.e., [(109.8

- 120.4) / (120.4) =

- 9%] to [(12 0.4

- 109.8) / (109.8) = +10%]).

ii. Further more, 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 land fills where no CCR landfill s were previously identified. This discrepancy thus represents an additional 9% uncertainty with regard to the landfill disp osal estimate, or another 3% uncertainty with regard to

tota l 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 availab le 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/biennialrepor t/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.pdfOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 27 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 interac t with one another (e.g., changes in the cost of wet

dry 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 an other.

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 m ajor. 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 m ajor. 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 one

way transport distance does not substantially affect costs. Affects relative costs of all options, including

fuel substitution.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 28 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. Thi s assumption
represents + 21% to + 28% uncertainty. Affects number of

relesaes avoided and

related benefits.

Compliance Assumptions

8. RIA assumes 1 00% industry compliance May overstate both

costs and benefits

. Unknown. Relies on level of

voluntary compliance and

state enfor cement

. 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 +1 0 % 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 1 

## Chapter 8 Other Required Analyses

Note : EPA has updated the cost and benefit information that inform this chapter of the RIA;

see Section s 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 present s other supplemental analyses for the CCR final rule. Specifically, the chapter considers potential impacts associated with the following issues:

 E lectricity price and energy market impacts

. EPA intends to assess d th e 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 busines s 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 r ule 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 o r the potential for unfunded mandates.



### 8 .1 Electricity Price and Energy Market Impact s

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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 2 To assess the impact of the final rule on electricity markets pursuant to the Executive Order and

ass ociated OMB guidance, EPA plans to perform ed 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 regul atory, 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 , an d 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 genera tion by plant type. EPA plans to rely relies 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 ex tent 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

benefic ial 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 Section s 9.2.1 and 9.7 in Chapter 9 of this RIA for a description of the relevant modifications to this section. E xhibits 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 CC R 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 a re 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 in clude 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 acti on 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 Complianc e 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 sm all entities are subject to the rule’s requirements. Second, this RIA selected appropriate measures for

366 EPA’s RFA/SBREFA guidance: “EPA’s Action De velopment 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/document s/rfaguidance11

- 00

- 06.pdfOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 3 determining economic impacts on these small entities and estimated those impacts. Third, this RIA determined whether the rule may be certified as not ha ving 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 t o 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 c ount 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 ha zardous waste management facilities (via the RCRA biennial report), not from solid waste facilities. EPA does not know the identity, compan y size, or other information about the offsite landfills currently used by the electric utility industry. However, t he 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 la rger hold ing 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 N orth 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 conservati ve, as it likely overstates the number of small entities.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 4 Note : This e xhibit 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 Sub

Categories 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 capacit y.

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 avera ge 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 o f the 478 electricity plants were retrieved from the EIA website (2012).October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 5 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 compl iance

costs to annual revenues for each company against the following three impact thresholds (as
defined in EPA’s 200 6 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 t his analysis reflects the central estimate (expected value) of the

total incremental co st 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 o f 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 affect ed. Of these, only six small entities experience costs exceeding 1% of revenues, and only one experiences costs exceeding 3% of revenues

. Appendix

C prov ides more information regarding estimated impacts for particular entities

. Therefore, this

RIA conclude s 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 onli ne 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 ($).October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 6 Exhibit 8

- B Summary of Regulatory Cost Estimates According to Electric Utility Plant Owner Entity Size/Type Category a

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 20 13 $ annualized at a 7% discount rate over 100

- year period 201 5 to 211 4

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

- ine lastic, 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 rate setting (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 e lectric 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 Forecast f orecast at : http: //www.eia.gov/forecasts/aeo/er/

. NOTE: EPA has updated t his exhibit of the RIA;

see Exhibit 9

- V in Section 9.7 of this RIA for updated exhibits.

NOTE: EPA has updated t his exhibit of the RIA;

see Exhibit 9

- V in Section 9.7 of this RIA for updated exhibits.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 7 regulated by state public utility commissions (PUCs) and the Federal Energy Regulator y 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 up on 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 pri ces. 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 range d 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 m arkets. 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 reg ulated 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

electri city 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 fin ding 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/E nc1/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 rate s 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 incl ude the amount of the proposed rate increase, the proposed effective date, and how much more the rat epayer 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 bef ore an Administrative Law Judge (ALJ) at which the evidence in support of the rate increase is ex amined and expert witnesses testify. In addition, consumers are offered an opportunity to voice their opinions and give testimony. Briefs may be submitted by the for mal 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” (Washingt on). Available online at: http://www.competecoalition.com/resources/recent

- examples

- rate

- increases

- vertically

- integrated

- states

379 The most recent available data on deregulation from EIA is from 2010. EIA also notes that at that time, seven states (AR, AZ,

C A, 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.g ov/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 Hi mori, 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 8 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 : F igures and e xhibits 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, disproporti onately 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 low

income populations, this RIA developed a geogr aphic 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, dem ographic, 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 ch aracteristics 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, respe ctively :

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 Manage ment: An Introduction”, Anne Ku, Sept 2000. Available online at: http://www.analyticalq.com/energy/volatility/default.htmOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 9 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 t o approximate population s 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 populat ions 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 consider s demographic characteristics for two geographic areas (i.e., one

- mile radius and catchment areas surrounding surfa ce 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 10 Poverty Level. Both of these proportions are roughly comparable with nationwide

benchmarks. 384 Nationally, 24.8% of the population belongs to a minority gr oup, 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 lan dfills 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 benchmar ks 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 nati onwide 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 n ationwide 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 Pove rty 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 belo w the Federal Poverty Level as a result of not excluding persons living in institutional group quarters, such as dormitories and military b ases, 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 plan ts evaluated, 16 8 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 plan ts evaluated, 78 plants have surrounding pop ulations 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 i nstitutional group quarters from landfill data but not from surface impoundment data.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 11 plants have proportions of minority populations that exceed the compara ble state

- wide percentage of minority populations; for example, 10 of these plants exceed the comparable state

wide 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 h igher 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 in crease r isks 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 cou ld 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 a nd 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 w et

- 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 antic ipated 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. 7 0%, belong to tribal populations. Of the 188,8 00 people within one mile of the 24 2 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 classif ied as Native American according to census data. Ho wever, 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 populatio ns 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 release s 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..October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 12 percentages of minority and low

- income populations as compared to nat ional averages, these populations will also see reductions in risk as a result of the rule.

Note : This e xhibit 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%)

24.8% 11.3% Surface impoundment one

- mile radius 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%)

n/a n/a Surface impoundment one

- mile radius 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%)

n/a n/a Surface impoundment one

- mile radius 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 impoundme nts . 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 : Th e figures and e xhibits 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 r ule. However, the policy conclusions of this analysis are unaffected by the change.

T his RI A 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 a n increased fr equency of children (i.e., residents under 18), compared with the national proportion of residents under 18.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 13 The remainder of this section examines the following children’s health considerations:

 Existence of human health impacts of CCR disposal unit lo cations 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, one

mile radius pop ulation 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 exc eeds 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, onl y 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.

T he 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

Whil e the actual changes in facility operation utility plant operation s , including CCR impoundment closures, predicted by the cost analysis of this RIA are uncerta in, examination of

the facilities plant s 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 sel ects the largest of those populations as the basis for these calculations.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 14 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 addition al or new risk to

children.

Exhibit 8

- D summarizes the results of this screening

- level analysis.

Note : This e xhibit 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 Implica tions 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 a ggregate, or by the private sector, of $100 million or more in any one year.”October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 15 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 f ive 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 e ffects;

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 sta te, 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 wh ether 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 16 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. Additi onal 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 w hether 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 d isplays 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 t he 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 17 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 test b $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 bu rden 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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9

- 1 

## 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 ben efits 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 modifi cations 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 ana lysis, 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 B ase C ase projection of future 2014 2015

- 2050 coal consumption for electricity

gen eration for future estimates of CCR tonnage generation over time , replacing the Energy Information Administration (EIA) 2014 Annual Energy Outlook (AEO)

Reference case C ase f

orecast described in Chapter 2

.

3. Scaling factor for CCR quantities managed in s tora ge impoundments : A revision to the

estimated t onnage of CCR managed in storage ( dredged ) impoundments , reflectingOctober 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

- 2 updated information from EPA’s Office of Water RIA for its Steam Electric Power Generation Effluent Limitation Guidelines (SPGELG) June 2013 p roposed rule about the distribution of CCR impoundments receiving and treating different types of coal ash.

4. CCR beneficial use : An adjustment to the CCR benefi cial 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 p er 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 surf ace 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 re leases 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 pl ants 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 chemic al contamination maximum con centration 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, a n extension of time to initiate closure to find or devel op 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, t he 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 safet y criteria. However, EPA expect s that it would be a small number.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

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- 3 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 permanent ly

cessation cease operation of a coal

- fired boiler(s) by a date un certain , a n 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 r egarding 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 sensitiv ity 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 a nd 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 anal yses, including the forthcoming EPA’s IPM a nalysis 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.gov see 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

-October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 4 party reports on planned closures of coal

- fired electric utility plants, and includes a broader set of plants than the IPM NEEDS data data base

. 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 wil l 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 on

site CCR management units, and therefore incur costs associated with the CCR fi nal rule as described in for closing and capping their CCR units upon plant closure (if eligible, according to

the RIA. “ alternativ e closure requirement #2 ” addressed in Section 9.3 )

. The remaining 14, according to information from the EIA, currently sole l y dispose of ash CCR off

- site or solely sell it for beneficial use, and are therefore unaffected by the CCR rule. Thu s, 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 al l 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

Ch apter 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 ch apter, 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 “s team 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 E IA

- 860 databases underpinning the construction of the

affected universe in this RIA.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

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- 5 of this RIA: the average year of full closure across these 11 plants is approximately 2019, and of the 11 plants, only two are indicat ed 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 applicab le 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 com plete 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 stat e 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 pe riod follo wing the year in which the facility electric 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 operati ng life, o r the year of facility plant 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 method s prior

to their listed facility plant retirem ent 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 facility plant 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 facility plant 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 wi th 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 resu lt of a groundwater contamination event).

400 A plant is de fined 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

.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

- 6 o In the post

- rule scenario, landfills are assumed to close permanently in either the year

of facility plant closure or upon reaching 80 years of age, whichever com es earliest. Closure capping and post

- closure monitoring costs are applied for 40 years following

landfill or facility plant 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 facility 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, th ese 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 ap plied 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 facility plant closure. For unlined disposal impoundments qualifying for this option, no a ssessment of whether or not the units experience groundwater contamination events occurs, as the units cease operating as of the year of facility plant closure or an earlier date. All costs applicable to existing disposal impoundments under the post

- rule sc enario (groundwater monitoring, fugitive CCR dust controls, stormwater run

- on/run

- off controls, corrective action, impoundment

stru ctural integrity inspections requirement s ) 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 facility plant 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 facility plant closure. Closure capping and post

- closure monitoring costs are applied for 40 years following facility plant closure. For unlined stora ge impoundments qualifying for this option, no assessment of whether or not the unitsOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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9

- 7 experience groundwater contamination events occurs, as the units cease operating as of the year of facility plant closure. All costs applicable to existing storage impound ments under the post

- rule scenario (groundwater monitoring, fugitive CCR dust controls, stormwater run

- on/run

- off controls, corrective action, impoundment structural integrity inspections requirement ) are applied accordingly to the algorithms

in described i n 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 E nergy I nformation A dministration’s (EIA) 2014 Annual Energy Outlook 401
( 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 th e 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 forecasts forecast , 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 sa me 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 data of future coal consumption for electricity generation

.

E xhibit 9

- A

Comparison of EIA AEO 2014 Reference c ase (applied in Chapter 2 )

and IPM v.5.13 Base Case (applied in Chapter 9 )

401 The EIA AEO 2014 AEO i s report 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.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

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- 8 

### 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 u niverse, management, and cost assumptions associated with these impoundments. 0 2 4 6 8 10 12 14 16 18 20

2014 2024 2034 2044 2054 2064 2074 2084 2094 2104 2114 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

2014 2024 2034 2044 2054 2064 2074 2084 2094 2104 2114 Quadrillion Btu Coal Consumption by Electric Utility Plants for Electricity Generation

AEO 2014 Reference Case

IPM v.5.13 Base CaseOctober 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

- 9 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

r eceived 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 assume s , absent other information, the lar gest impoundment at the 142 electric utility plants that report report ed wet CCR disposal to in 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 ponds impoundments at those plants, as well as the 384 ponds impoundment s at plants that do not report wet CCR dispo sal, 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 man agement 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 r eceive or st ore 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 r eceive 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 ac counts 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 impo undments open to manage bottom ash, which is sluiced into these storage impoundments and then dredged and disposed of elsewhere.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 10 Summary data from EPA O ffice of W ater ’s (EPA

- OW) 2010 survey of electric utility plants provides information about whether a n impoundment directly receives CCR wast es from a process (e.g., the first impoundment in a series of impoundment s) 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 was tes, 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 r easonable assumption that a primary impoundment for fly ash wastewater contains large quantities of solids. This may also be the case for bottom ash wastewater, t hough

some plants that use dewatering bins will remove a large fraction of the bottom ash prio r to releasing wastewater to an impoundment. M any plants also use hydrocyclones to remove FGD solids prior to the FGD impoundment

.

EPA

- OW’s 2010 survey includes 885 CCR impoundment s. Of these, 500 are primary CCR impoundment s, meaning that they directly r eceive at least one type of CCR waste (for this analysis, either fly ash, bottom ash, or FGD wastewater). The remaining 385 CCR impoundment s in the EPA

- OW universe contain CCR wastewater, but these impoundment s receive wastewater as overflow from another C CR impoundment

.

In addition, nearly 90% of primary CCR impoundments and 95% of non

- CCR impoundment s 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 conve rsion of ash systems, plants would either continue to operate the impoundment s 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 pri mary and non

- primary CC R 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 p rimary impoundments in the F ly A sh and B ottom A sh (n = 129) and the F ly A sh O nly (n = 33) categories are roughly consistent with th is 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 manage ment units affected by the CCR Final Rule f inal r ule 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.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

- 11  The remaining primary impoundments in Exhibit 9

- B (n = 25 3 ) are categorized as

“ B ottom A sh O nly

. . ” T his chapter continues to employ the assumption that 25 percent %

of waste is received by, and dredg ed 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. T his 25 percent % factor is consistent

with independent engineering estimates 406 of the maximum quantity of solids that could be economically double

- managed in stor ag e 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 assum es that non

- primary impoundments manage (receive and dredge) a qua ntity equivalent to five percent 5% 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 avera ge of CCR tonnage managed in storage impoundments, reflecting 253 imp oundments that manage 25 percent % of

wet

- disposed CCR tonnage at plants with storage impoundments and 385 that manage five
percent 5% 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.

Exh ibit 9

- B
CCR Impoundment Counts in the EPA

- OW 2010 Survey Impoundment Population

by CCR Type & Impoundment Type

CCR Type Primary CCR

Impoundments for a t Least

One of the CCRs a Non

- Primary CCR Impoundment s d All CCR Impoundment s (Primary + Non

- Primary)

All Impoundment s with other Non

CCR

Wastewater 5 All Impoundment s with other Non

CCR

Wastewater e All Impoundment s with other Non

CCR

Wastewater e

Bottom Ash only b O nly b 253 230 196 188 449 418

Fly Ash Only b 33 25 16 16 49 41

FGD Only 85 59 80 68 165 127 Fly Ash and

Bottom Ash b,c 129 127 93 92 222 219

406 25% assumption formulated by en gineers from GZA Geoenv ironmental based on expert judgment and institutional

k nowledge based on extensive experience with the electric power industry.

407 This analysis excludes FGD

- related ponds.

408 5% assumption formulated by en gineers from GZA Geoenv ironmental based on expert judgment and institutional k nowledge

based on extensive experience with the electric power industry.

409 Note that this calculation in cludes all non

- primary ponds, including FGD ponds, because the lower

- bound 5% double

management parameter does not require a comparison of bottom ash tonnage to total (fly ash plus bottom ash tonnage) as corroborating evidence.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

- 12 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 elect ric 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 p lants, the bulk of the FGD solids are removed prior to the FGD wastewater being se nt 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 A sh” 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 primar y 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 transpo rt water and the overflow from this first impoundment is transferred to a second impoundmen t 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 c lassified 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, th ese 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. Th ese 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 applica tion 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 L aden 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 F ann 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 approxima tely 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 Crit ical Care Medicine. 173: 667

- 672.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 13 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 sca ling 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 o ut

- 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 a pples

- 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.

. Thi s chapter applies the 22 per cent % 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 a sh, and FGD pollutant removals for the ELG4 regulatory option

.

Step 2 : Calculate the quantity of annual CCR impoundment tonnage associated with EPA

OW’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 absenc e 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 resulti ng from replacing the EIA AEO projections of CCR growth (via estimates of future coal consumption for electricity generation ) with the IPM projections v5.13 base case projection , as described in Section 9.2.2

. 413 EPA

- OW’s 2013 S PGELG proposed rule is availab le at Federal Register, Vol. 78, No. 110, June 7, 2013.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 14 does not address. The s econd 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 assume s 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 conti nued 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 provi des 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 relea se 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 t hat 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

f inal r ule may not align accurately. However, in the a bsence of additional information from OW, this chapter considers this a reasonable assumption for applying benefits at the scale predicted for the SPGELG rule.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 15 9.2.6.1 Changes to Post

- Rule Release Rate for Wall

- B reaches

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 R ico et al. as well as based on analysis of the 2009 EPA Office of Resource Conservation and Recovery ( O RCR) su rvey data, 416 the 2002 N ational Response Center (NRC)

report, 417 and the 2011 Chambers and Higman s tudy. 418 This change was made for the following

reasons:

 The 2011 Chambe rs and Higman study is not peer

- reviewed and only discusses resi dual

failures in generalities; n o firm list of entities and incidents included in the dataset is provided. However, t he Chambers and Higman st udy does pull heavily from Rico et al. (2008) and t he residual failure rate s for the two methods are roughly comparable : 0.04%

vs. 0.044%.

 The 2002 NRC report regarding M ine 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 existen ce over the 25

- year period.

This source indicates that 7 13 impoundments were in existence in 2001. Likely, m ore i mpoundments were in use in the 1970s

- 80s ( which woul d further drop residual failure) but data are not available to quantify this.

o T he source n otes that “...incidents reviewed here...are not a complete list ” but instead represent “ select events .” T he incidents described in the report are large

- scale

fa ilures that resulted in significant damage and sometimes death; the source does not

appear to contai n 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 pos t

- 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 probabili ty 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 l imited than that used in Rico et al

. (2008). While the ORCR data set f ocused 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,” Nation al 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 2 009 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=513583October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 16 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 prevent reduce 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 r ange of other releases, including overtopping and wall seepage. However, the benefits estimates in this chapter reflect an updated assumption that not all “o ther release” events actually have a measurable environmental impa ct.

The benefits estimates in this chapter reflect the assumption that seepage events are very small in

relea se volume, and do not incur substantial cleanup costs or NRD damages . Of the 32 “o ther release” events with causation data, 13 are seepage events

. T his chapter makes the followi ng revisions to the “o ther releases” category:

 For calculating pre

- and post

- rule release probabilities, the 13 seep age events are removed from the list of “ other releases.”

 For calculating post

- rule release probabilities, the CCR final r ule 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 constit ute 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 p ost

- 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

= 0.5 9 % (6

- 0)/2,212

= 0.28%October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 17 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 18 9.2.6.3 Modifications to Impoundment Release Volume Capacity Factor s

Th e benefits estimates in th is 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 g reater 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 un der 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

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 19 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)October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 20 

### 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

t o monetize CO 2 impacts in RIAs. I n November 2013

, the O ffice of Management & Budget (O MB ) issued updated SCC values that reflect two minor technical corrections to the prior May

201 3 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 underly ing article (Climatic Change).

2. The second addressed an inadvertent misspecification of the equilibrium climate sensitivity d istribution in the FUND model.

Both are described in detail in Appendix B of the revised SCC T echnical Support Document (TSD). 420 These technical corrections resulted in a small decrease i n 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 CO 2 to $37 per metric ton (in 2007 $ ). OMB's Office of Information and Regulatory Affairs (OIRA ) publishe d 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 c ompleting 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,

avail able at: http://www.whitehouse.gov/sites/default/files/omb/assets/inforeg/technical

- update

- social

- cost

- of

- carbon

- for

regulator

- 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. Th e

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 f inal r ule.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 21 requirements of the rule

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

. 2. A lternative C losure R equirement #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 d ate 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 requireme nt , 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

.

B elow 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

Th e 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 C CR final rule, a leaking, unlined CCR impoundment that exceeds the MCL groundwater protection standard s these units may continue to receive CCR s if the owner or
operator is able to certif

y that the leaking impoundment unit is the only feasible option for disposal, due to no a lternative on

- site or off

- site disposal capacity . The owner or operator must:

 C omply with all other requirements of the rule, including initiating corrective action as required under the rule if the su rface impoundment is unlined and leaking such that one

or more MCLs are exceeded

,

 Provide annual certif

ication that alternative capacity is not available and document efforts to obtain additional capacity ; and

422 In addition to these two alternative closure requirements , EP A also revised its base case compliance requirements for leaking unlined CCR impoundments for all other plants. The base case represents the stan dard compliance requirements for all plants

under the CCR f

inal r ule, and is consistent with t he costs estimated in Chapters 3 and 4 . Within six months after determining

that the MCL groundwater protection standard s 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 man agement to begin within the 5

- year window:

 Impoundments in excess of 40 acres may request up to five 2

- ye ar 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 impo undment

.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 22  W hen alternative capacity is identified, obt ain 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 sa me timeframes as in the base case. In estimating the costs and benefits of t his 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

. There fore, the timeline and decision logic for the model provided below only discuss es this alternative closure requirement in terms of its applicability to leaking, unlined surface impoundments.

The timeline for a plant that obtains a n 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 rece ive

five, two year extensions.

9.3.1.1 Decision Logic for Costs Incurred at Plants that Obtain Alternative Closure Requirement #1

T o evaluate Alternative Closure Requirement #1, t his 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 inc urring 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 delay s these costs 10 years for estimating this alternative.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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9

- 23 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 i mpoundment 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 a n alternative closure requirement for 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) Report Report ed wet CCR disposal in per 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 data data base ; 425 and

3) Have no on

- site CCR landfills. 426

, 427

424 In the this RIA, the probability of a groundwater contamination MCL exceedance event is de pendent on the age of a n 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 o n 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

fir st 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 2 02 8, 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 oppor tunities 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 beneficia l use optio ns 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 t hough 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 li ned 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 facility plant may shift management of CCR s from a disposal impoundment to an existing storage impoundmen t (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 facility plant , 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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- 24 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

landfi lls.

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 ass ociated 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 represe ntative 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 cos t 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 databa se. 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 t his

alternative cl osure 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 associa ted

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.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

- 25 Exhibit 9

- E
Cost Estimat ion 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 adjuste d 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 least

cost 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 imp oundments (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 6 1 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 d isposal 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 contami nation event is 2028 in

this chapter , rather than the 2020 , as modeled in t he 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 impoundm ents 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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9

- 26 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, bas ed 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 t han 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 havin g 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 Coal

Fired Boiler(s) by a Date Un C c ertain

A second alternative closure requirement in the CCR final rule addresses power plants that plan to cease burning coal to 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 u nlined, leaking CCR i mpoundments 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 disposa l capacity is available, and and must certif y ing 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 impoundme nt ceases receiving CCR , owner/operator must complete closure within 5 years, but no later than 10 years after first detecting the exceed a nce 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 bo i ler must cease operation and the disposal un it must have completed closure within 8.5 years of the publication date of the rule. For CCR surface impoundments larger tha t n 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.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

- 2 7 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 b e 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 themselv es 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 t heir 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 operatin g 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 o f 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 bus iness 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 altern ative 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

R equirement #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 plan ts 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 experien ce 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 an d results in the delay of the accrual of closure costs until the year of facility plant 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 o f 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 re quirement 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.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

- 28 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 an alysis is less than five percent 5% of total costs presented in this chapter without taking this alternative closure requirement into account. Correspondingly, it appears that Alternative Closure Require ment #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 leak ing, 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 remov es 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

factor generation) f

rom 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 stor age 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 be nefit 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; andOctober 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

- 29  The inclusion of an additional sc aling 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 B aseline Costs of the CCR Final Rule

Exhibits 9

- F t o 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 impoun dments, and aggregate costs, respectively. All of these estimates reflect a reduction in

baseline cos ts 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 adj ustment factors described abov e.

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 $0October 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

- 30 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 $11,300October 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

- 31 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 c orrective 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 $34,800October 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

- 32 

### 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 esti mates
reflect a reduction in total incremental cos ts 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 Manage ment 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 $0.40 4 $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 $2,570October 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

- 33October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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9

- 34 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 $2,920October 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

- 35 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: Note s:

 For reason explained in Section 5.3.4 of this RIA, row 19 above (tota l costs) does not subtract the “ cost offset " which is

d isplayed 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 indic ated 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 in active 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 I ncremental 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 ben efits 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.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

- 36October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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9

- 37 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 of

Reduction in CCR impoundment

releases $1 51 $ 4,760 $13 8 $ 1,960

2 Prevention Reduction in CCR contamination of groundwater contamination $12.8 $405 $9.86 $141

Closures $1.60 $50.7 $1.46 $20.9

Bottom l iners $6.56 $207 $5.06 $72.2

Groundwater m onitoring $4.65 $147 $3.34 $ 47.7

3 Increase In duced future in crease in CCR beneficial

use use s * $ 117 $3,130 $79.0 $1,120

Avoi ded compliance cost air pollution & resource consumption $ 84 32 .5 $ 2,670 459 $ 57.1 21.9 $ 956 164

Avoided air pollution & resource use CCR rule “ cost offset ” (alternatively could be subtracted from row 19

of Exhibit 9

- M ) $ 32 84 .5 $ 459 2,670 $ 21.9 57.1 $ 164 956

4 Reduced incidence of cancer $0.00 546 $0. 173 $0.002 73 $0.03 90

5 Avoided IQ losses from mercury $0. 279 $8.80 $0.02 46 $0.3 51

6 Avoided IQ losses from lead $0. 186 $ 5.87 $0.016 4 $0.2 34

7 Reduced need for specialized education from IQ losses $0.00 273 $0.0 863 $0 .000 $0 .000

8 Non

- market surface water quality benefits

$2. 26 $ 71.4 $1. 89 $2 7.0

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 $0.7 59 $10. 8

10 Improved air quality from reduced air pollution emissions from power plants $ 4.66 $ 147 $2. 04 $2 9.1 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) $0.00 273 $0.0 863 $0.002 73 $0.03 90

Column Total s = $289 $8,550 $232 $3,290

Non

- Monetized Benefits

12 Financial benefit . Reduce d investment risk and informa tion asymmetry in financial mark ets for the electric utility industry.

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

14 Dust nuisance benefit . Reduce d 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. Reduce d non

- cancer health effects resulting fr om fish consumption. This is a separate

benefit from the avoided cancer risks monetized in Chapter 5

. 16 Cancer and non

- cancer human health benefit . Reduce d cancer and non

- cancer health effects resulting from recreational water use. This is a separate ben efit from the human health benefit from reduction in fish consumption, which is estimated in Chapter 5

. 17 Avoided sediment contamination. Reduce d sediment contamination from reduced deposition of toxic pollutants.

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

19 Commercial fisheries benefit. Improve d commercial fishing yields and harvest quality due to aquatic habitat improvements.

20 Tourism benefit. Increase d participation in water

- based recreation d ue to water quality improvements.

21 Avoided impingement and entrainment mortality. Reduce d 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.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

- 38 Notes:

* The beneficial use benefit in this RIA consists of two components. The sub

- rows below di splay 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.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

- 39 

### 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

- f ired 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 D istribution 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 groun dwater 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

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 9

- O Total Incremental Costs by Year: All Active & Inactive CCR Management Units

Original RIA Estimates (Chapters 3 and 4)

Revised Estimates (Chapter 9)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

- 40 

### 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 present s 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 CostsOctober 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

- 41 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 201 3$)

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 t he 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 r ule , though the cost and benefit results in this chapter reflect one of the two alternat ive 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 ne t costs of the rule have diminished by $86 m illion 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 al ternative 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 f inal

r ule.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

- 42 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 the y are located at plants that continue to operate. Correspondingly, it is unclear to what extent the RIA

- identifie d 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 ina ctive impoundments not considered in this RIA. As a simplifying assumption given this uncertainty, this chapter uses the same universe of inacti ve 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 refl ect 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

r eleased from the EPA Office of Water’s 2010 survey 432 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 sensitivit y analyses specific to the new assumptions and algorithms employed in this chapter:

 Expansion of a nalysis to c onsider p lants r eporting p artial c losure 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 a ddition al p lants a nnouncing f ull c losure 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 ab out 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.cfmOctober 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

- 43 The costs and benefits present ed 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

sensit ivity 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 imp act 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 o perating 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 A nalysis 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 uni ts within the ana lysis 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 data base as closing EGUs either before

or after 201 6 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 cl osed 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 represent s 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 o ptions 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 f i nal r ule. 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.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

- 44 This sensitivity analysis results in adding nin e plants and 31 CCR manageme nt 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, an d 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 coal

fired 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 2016October 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

- 45 9.6.1.2 Inclusion of A ddition al Plants Announcing Full Closure in the 2010 EPA Office of

Water S urvey

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

electr ical 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. Th at 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 ident ifies 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 plan ts 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 whe re 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 provid e 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). A n additional five plants are modeled as closing using this method, for a total of 16. Thes e 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 eit her 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).

I n addition, a ll 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 consis tent with

436 EPA Office of W ater’s 2010 mail survey to power plants for the Steam Electric Power Ge nerating 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.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

- 46 Sensitivity Analysis 1

, except that it includes plants identified in either NEEDS v.5.13 or EPA

OW survey databases.

This sensitivity analysis adds an additional 31 plants to the list of plants fully closing prior to 2016, bringing the total num ber 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, t his sensitivity analysi s adds 12 plants to the list of plants fully closing after 2015, resulting in a total of 23 such plants

. The se 12 additional plants contain, across them, an additional 40 CCR management units ( 6 landfills, 9 disposal impoundments, and 25 storage impoundmen ts). 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 EPA

OW 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 closur e prior to 2016, this may slightly overestimate costs presented in this ta ble 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 th ree 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; correspondingl y, 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 an alysis; for this plant the closure year is revised from 2026 in the main analysis to 2016 in this sensitivity analysis.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

- 47 availing themselves of Alternative Closure Requirement #2, would result in cost redu ctions of

more than five percent 5% 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 benef icial 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. I mpoundment release prevention 1. Reduced CCR

i mpoundment releases $138 $133 $132 $123

2. Prevention of

Reduced

CCR groundwater

contamination $9.86 $10.1 $9.91 $10.3

3. Increase I nduced future

i ncrease in CCR beneficial

use 1 use s 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 Benefits 2 = $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 lower

bound estimates of potential rule costs, because they do not consider two additional sources of uncertainty: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

- 48  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 alternati ve 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 coal

fired generating units cease 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 units cease burning coal

. In effect, these plants are likely to cease burn ing coal operations 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 t he rule. However , a forthcoming analysis will separate
EPA report

, Appendix X (December 2014) reports the results of running the IPM for the

CCR final rule and will contains an estimate retirements of 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 case future coal use consumption for electricity generation

forecasts from Department of Energy’s published 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 assumptions alternative s cenari os

.



### 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 conservativ e) 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 RuleOctober 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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9

- 49 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 th is 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 ut ilization factor of 86 .1 percent % is applied to estimate revenues for each owner entity; this chapter revises this e stimate 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

o wner 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 inc remental 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 lo cal 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 prev ailing 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

continu es 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 governme nts, 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 Pr oduction and Capacity Utilization” data for Utilities Available online at http://www.federalreserve.gov/releases/g17/Current/default.htm . However, this factor incl udes 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 f inal rule, the 56.7 percent %

coal

- fired electricity generation capacity utilization factor is based on 2012 annual data provided by EIA in the Electricity Powe r Monthly data publication “Table 6.7.A Capacity Factors for Utility Scale Generators Primarily Using Fossil Fuels, January 20 08

- 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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9

- 50 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

test b $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 Stat e/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 fo r 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 ut ilization factor of 86.1 percent % was applied ; based on data for the NAICS 22 utilities sector (which in cludes 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 SBR E FA 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 o f 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 percent 1% of

revenues and one small entity may experien ce costs exceeding three percent 3% 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 companie s, 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 sma ll city plants, 42 plants owned by small companies, and 17 small cooperative plants.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

- 51 Exhibit 9

- V Summary of Regulatory Cost Estimates According to Electric Utility Plant Owner Entity Size/Type Category a

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 201 3$ annualized at a seven percent 7% discount rate over 100

- year period 2015 to 2114

. b This chapter applies a capacity ut ilization factor of 56.7 percent % based on data for coal

- fired electric utility plants , relati ve 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 surfa ce impoundments appear to have percentages of minority and low

- income residents roughly comparable to the nationwide average, populations

surroundin g 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 d ownstream 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% nati onwide, 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 andOctober 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

- 52 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 consi dered 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 th ese 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, t he 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, incl uding 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 var ious 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 ef fects on disproportionately poor or low

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 price potential 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.October 2014 EPA Interagency Review Draft : Do Not Circulate or Cite
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9

- 53 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 state

by

- state subtotals of the estimated CCR final rule annualized cost s and benefit s at 7 % and 3 % discount rates, respectively. T otal cost s and benefits across all states equal the total rule cost s presented in Section 9.4 , specifically Exhibit 9

- M

.

T his 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 f inal r ule 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 ser ve 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

- specifi c, plant

specific, 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, a s 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 d ifferences in operations and costs : t he assumptions and inputs to the CCR RIA cost model use national average estimates of

CCR p ollution 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 h ave 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 cos ts across states.

 Inter

- state CCR disposal location uncertainty : similar to average unitized costs, e stimated industry regulatory compliance costs consider state average off

- site disposal costs for each plant. The analysis does not include a spatial analy sis or consider whether lower

cost 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 cos ts 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 commercialOctober 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

- 54 industrial waste landfill capacity, the in

- state cost assumption may be particularly misleading

.

 Benefits associated with CCR impoundment s : The most significant monetized benefits

of the CCR rule are the impacts avoiding future CCR impoundment release s. Th ese low

probability, 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 th e 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.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

- 55 Exhibit 9

- W
State

- by

- State Summary of CCR Rule Costs and Ben efits (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

Rule 2 Count of on

- site

CCR management units incurring

costs under CCR Final Rule (active + inactive SIs) CCR Final R ule

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 $4 2.0 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 $1.7October 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 Ben efits (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

Rule 2 Count of on

- site

CCR management units incurring

costs under CCR Final Rule (active + inactive SIs) CCR Final R ule

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 $3 7.0 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 disp osal to in 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

Rule 2 Count of on

- site

CCR management units incurring

costs under CCR Final Rule (active + inactive SIs) CCR Final R ule

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 incur s > 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 incur s > 45 % of

costs ; partially closes per NEEDS data $1.5

11 GA 11 1,288,452 10 34 $14.1 1 plant incur s > 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 incur s > 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 incur s > 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 incur s > 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 incur s > 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 $2.0October 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

Rule 2 Count of on

- site

CCR management units incurring

costs under CCR Final Rule (active + inactive SIs) CCR Final R ule

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 incur s > 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 disp osal to in 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.