OMB REVIEW DRAFT 

Regulatory Impact Analysis 

For EPA’s Proposed Regulation 

Of Coal Combustion Residues 

Generated by the Electric Utility Industry 

Prepared by: 

Mark Eads, Economist 

(703-308-8615; eads.mark@epa.gov) 

US Environmental Protection Agency 

Office of Resource Conservation & Recovery (ORCR) 

(formerly Office of Solid Waste) 

1200 Pennsylvania Avenue, NW (Mailstop 5305P) 

Washington DC, 20460 USA 

08 October 2009 
Table of Contents

Acknowledgements Executive Summary Chapter 1: Problem Statement Chapter 2: Potentially Affected Industrial Facilities & Waste Disposal Units  2A. Identity of Potentially Affected Industries  2B. Identity of Coal-Fired Electric Utility Plants  2C. Types of CCR Disposal Units  2D. Types of CCR Generated and Annual Quantities  2E. Size of CCR Disposal Units Chapter 3: Baseline CCR Management  3A. Cost of Baseline CCR Disposal  3B. Baseline Economic & Environmental Benefits of CCR Beneficial Use Chapter 4: Estimated Cost for RCRA Regulation of CCR Disposal  4A. EPA’s Prior Cost Estimates for Possible RCRA Regulation of CCR Disposal at Electric  4B. Regulatory Options Evaluated in this RIA  4C. Regulatory Cost Estimation Algorithms & Results  4C.1 Engineering Control Costs  4C.2 Ancillary Costs  4C.3 Sub-Option: Land Disposal Treatment Cost Chapter 5: Potential Distributional Effects 

5A. Electricity Price Impact (Executive Order 13211) 

 5B. State-by-State Distribution of Regulatory Costs  5C. Small Business Impact Analysis (RFA/SBREFA) 

5D. Minority & Low-Income Population Statistics (Executive Order 12898) 5E. Child Population Statistics (Executive Order 13045) 

5F. Unfunded Mandates (UMRA) & Federalism Implications Analysis (Executive Order 13

Chapter 6: Sensitivity Analyses 

 6A. Alternative Discount Rates (0%, 3%, 7%)  6B. Data Quality Uncertainty 

6C. Possible Impact on CCR Beneficial Uses 6D. Price and Capacity Impacts on Commercial Hazardous Waste Landfills 

 6E. Uncertainty in Land Disposal Treatment Sub-Option Cost Estimate  6F. Other CCR Disposal Units Not Covered by the Proposed Rule Chapter 7: Potential Benefits of CCR Disposal Regulation at Electric Utility Plants 

 7A. Community Safety Benefits  7B. Human Health Benefits  7C. Ecological Benefits 
Table of Appendices 

Note: Because of its large number of pages (over 250), the Appendix is provided as a separate companion doc

Appendix A Chronology of EPA’s Regulatory Evaluation of CCR (1978 to March 2009) Appendix B List of 495 Operating Electric Utility Plants Potentially Affected by the CCR Rulemaking (200Appendix C Identity of 200 Entities Which Own the 495 Potentially Affected Electric Utility Plants (2007) Appendix D Baseline State Government Regulatory Requirements for CCR Disposal Units in Top-34 Coal Appendix E Baseline Engineering Controls Installed at CCR Disposal Units in the Electric Utility Industry Appendix F Description of CCR Landfill & Surface Impoundment Engineering Control Cost Model Appendix G Baseline Cost Estimates for CCR Disposal by the Electric Utility Industry Appendix H Geological Conditions at Electric Utility Industry CCR Disposal Unit Locations Appendix I Incremental Regulatory Cost Estimates for Compliance with the CCR Proposed Rule Regulato

Appendix J Electricity Price Impact Analysis Spreadsheet (Executive Order 13211) Appendix K Statement of Energy Effects (Executive Order 13211) Appendix L Small Entity Impact Data & Analysis Spreadsheet (RFA/SBREFA) Appendix M Minority & Low-Income Population Data (Executive Order 12898) Appendix N Child Population Data (Executive Order 13045) Appendix O UMRA Written Statement Appendix P List of Other Industries with Coal-Fired Electricity Plants Not Covered by the Proposed Rule o

Appendix Q 1948-2008 US Historical Damage Cases Associated with Electric Utility Plant CCR Disposal U
Acknowledgements

• EPA Contractor Support & EPA Staff Assistance for this RIA 

• In 2009 under EPA contract EP-W-07-0011, work assignment 2-33, Industrial Economics Inc. (Cambridge MA) 

DPRA Inc (Minneapolis MN) provided support for estimating affected entities (Chapter 2), CCR disposal basel

costs (Chapter 3), and engineering control regulatory costs (Chapter 4) of this RIA. 

• EPA-ORCR Program Analysts Rachel Alford, Christina Kager, and Cho-Yi Kwan helped with spreadsheets and 

• Peer Review of this RIA Although RIAs do not normally require peer review according to EPA’s peer review guidance1, prior drafts of this RI

2009 to three independent external reviews outside of ORCR, at least one of which (i.e., Economics Subgroup item 1 considered peer review. Peer review is conducted by qualified individuals (or organizations) independent of those whand who are collectively equivalent in technical expertise (i.e., peers) to those who performed the original work. Peer assessment of the assumptions, calculations, extrapolations, alternate interpretations, methodology, acceptance criteri

pertaining to the specific major scientific and/or technical work product and of the documentation that supports them

1. Economics Subgroup: On 05 May 2009, ORCR convened an “Economics Subgroup2” in cooperation with E

Economics, and Innovation (OPEI). EPA established the Economics Subgroup process in May 2004, and it is “economically significant” rulemakings. All three prior (1988, 1999, 2005) EPA cost estimate studies of RCRCCR at electric utility plants indicated that the potential annualized compliance costs could be greater than the “economically significant” regulatory threshold of $100 million annual effect. The Subgroup consisted of six Rachel Alford, Program Analyst, OSWER-ORCR-PMCAO-ERAS, (2). Mark Eads, Economist, OSWER-ORThomas Gillis, Economist, OA-OPEI-RAPD, (4) Robin Jenkins, Economist, OA-OPEI-NCEE-RPSD, (5) KelOA-OPEI-NCEE-RPSD, and (6) Richard Mattick, OSWER-OAA-OPM. 

2. EPA-OPEI review: In Autumn 2009, ORCR provided the draft CCR proposed rule package including a draft 

Office of Policy, Economics & Innovation for review and comment prior to OMB-OIRA’s review. 

3. OMB review: OPEI provided the CCR proposed rule package including a draft of this RIA, to OMB-OIRA fo

review (i.e., mid-Oct to mid-Dec 2009); 90-day reviews are specified under Executive Order 12866 (Section 6

1 EPA’s 2006 peer review guidance for RIAs states “Generally, if a RIA applies accepted, previously peer-reviewed methods in a straightfor

undergo an additional peer review. RIAs prepared to support “major” or “economically significant” regulations typically do not utilize innovmethods. It is unnecessary to conduct peer reviews of straightforward applications or transfers of accepted, previously peer-reviewed econom

procedures used to transfer or adapt an economic work product are generally established by separate economic guidance documents which hTherefore, RIAs that are developed using these procedures do not normally undergo an additional peer review, even those prepared in suppo

“economically significant” rules. Source: Section 2.2.6 (page 35) of EPA Science Policy Council, “Peer Review Handbook”, 3rd Edition, do

06/002, May 2006, http://www.epa.gov/peerreview/pdfs/Peer%20Review%20HandbookMay06.pdf. 

2 EPA’s Economics Subgroup process is described at (a) EPA’s intranet: http://dchqdomino1.dcicc.epa.gov:9876/OA/OPEI/EconForumIntra

and (b) in Nov 2004 EPA Congressional testimony at http://www.epa.gov/ocir/hearings/testimony/108_2003_2004/2004_1117_slj.pdf 
Executive Summary 

• Industrial Entities Potentially Affected by the Rule 

o Electric utility industry: The proposed rule establishes conditions for disposal of coal combustion residues (CCR) and applies to an e

electric utility plants in NAICS 221112, located in 47 states. Non-utility coal-fired electricity plants (e.g. operated by manufacturing 

universities) are not included in the scope of the proposed rule. 

o Waste management industry: The rule may also affect industrial waste management companies (in NAICS 562211, 562212, 562219)

cleanup/remediation services industry (NAICS 562910) which offsite dispose or remediate CCR spills/releases. 

o Industries which beneficially use CCR: At least 14 industries in the manufacturing, construction, agriculture, mining, and waste man

use” CCR for industrial applications as substitutes for other materials. Because all regulatory options maintain the 1980 RCRA Bevil

uses, these industries are not expected to be impacted by the proposed rule. Potential indirect effects could reduce future annual bene

• Baseline CCR Disposal Practices by the Electric Utility Industry 

The 495 electric utility plants generate an estimated 141.2 million tons/year CCR (2005/2007 estimate) which is managed by either disp

o Disposal: 94.2 million tons/year CCR disposed by 467 plants at a cost of $5.6 billion per year using one or more of three m

1. 311 plants use onsite landfills (56.8 million tons) 2. 158 plants use onsite surface impoundments (22.4 million tons) 

3. 149 plants use offsite landfills (15.0 million tons) 

o Beneficial use: 47.0 million tons/year CCR from 272 plants used as material inputs by at least 14 industries, providing $24.6 billio

1. Economic benefits: $5.0 billion/year energy & water consumption savings, including $177 million/year CCR 

utility plants, and $2,300 million/year net cost savings for avoided purchase of higher price substitute materia

2. Environmental benefits: $19.6 billion/year in avoided air pollution emissions, including $365 million avoide

emissions, plus 402 million tons/year avoided water pollution, and 25 million tons/year avoided solid waste g

• Regulatory Options Evaluated in this RIA 

This RIA evaluates the potential impacts of three options for regulating CCR disposal, consisting of EPA’s preferred option identified in alternative options. All options propose to replace the 1980 RCRA “Bevill exclusion” for CCR disposal with new RCRA regulation, but r

CCR beneficial uses. Differences between the options are mainly their respective RCRA legal authorities and types of CCR disposal unit

o Option 1: Subtitle C: (Preferred option). Regulate CCR disposal as RCRA Subtitle C “K179 hazardous waste”, but with RCR

engineering controls similar to EPA’s 1999 cement kiln dust (CKD) proposed rule, and with land disposal treatment st

o Option 2: Subtitle D: Regulate CCR disposal as RCRA Subtitle D “non-hazardous waste” with the same engineering controls 

o Option 3: Hybrid C&D: Regulate wet CCR disposal (impoundments) under Option 1 and dry CCR disposal under Option 2. 

In addition to these options, the proposed rule presents two other approaches. One approach is the same as Option 2 but egregious violatoOption 1. The second approach is the same as Option 2 in states which develop in 2-years an implementing program but the same as OptiBecause both approaches are hybrids of Options 1 and 2, this RIA did not evaluate them because their impacts would be expected to fall b

• Potential Benefits of Proposed RCRA Regulation 

Although the 1976 RCRA statute does not require benefit-cost justification of RCRA regulations, this RIA presents a qualitative benefit aOMB’s 2003 “Circular A-4: Regulatory Analysis” best practices guidance. The expected benefits of RCRA regulation are reduction in fucases and associated damage costs to local community economies, human health, ecosystems, and the environment. Over the 61-year per66 confirmed damage cases involving CCR disposal units, an average frequency of 1.1 cases per year. Based on incomplete economic d

and using the actual average per-acre cleanup cost from a 2008 damage case (TVA Kingston TN), indicates a minimum $117 to $152 mil

average annual damage costs. However, cleanup costs do not represent all damage cases or types of economic damages, so this is an undebecause it does not include costs for other economic damages: (1) local infrastructure (roadways, water supply, energy supply, sewerage, 

business closures, (3) housing, community buildings (churches, schools), parks, (4) landscape aesthetic values, (5) human health, (6) ecos
• Estimated Cost of RCRA Regulatory Options

As summarized in the Exhibit below, the potential nationwide cost of RCRA regulation ranges from $492 million per year (Option 2 with

sub-option) to $2,274 million per year (Option 1 with treatment) across the regulatory options. 

Summary of Annualized Cost Estimates for RCRA Regulation of CCR Disposal by the Electric Utility Indu

($million average annual over 50-year period 2012-2061 @7% discount rate) 

Regulatory Compliance Cost Element 

Option 1 

(Preferred option) 

RCRA Subtitle C 

hazardous waste 

Option 2 

RCRA Subtitle D 

non-hazardous waste 

Hy

• RCRA Subtitl• RCRA Subtitl

A. Regulatory Compliance Costs 1. Engineering controls $491 $491 2. Ancillary costs $107 $1 3. Sub-option: land disposal treatment dewatering $1,676 $1,676 

Total cost without treatment (1+2) = $598 (+11%)* $492 (+9%)* $5

Total cost with treatment (1+2+3) = $2,274 (+41%)* $2,168 (+39%)* $2,1

B. Other Regulatory Costs Not Annualized in this RIA 4. Added cost for cleanup of future CCR disposal unit failures as RCRA Subtitle C hazardous remediation waste 

Annualized cost not est; 

$18 to $376 per event 

Not applicable 

to this option ($0) 

Annualized 

$18 to 

5. Cost for RCRA Subtitle C facility-wide investigations and facility-wide corrective actions if required 

Annualized cost not est; 

$5.4 per case 

Not applicable 

to this option ($0) 

Annualized 

$5

* Percentages in this Summary Exhibit indicate increases in cost relative to the $5,556 million per year baseline cost for non-regula

• Regulatory Cost Estimation Uncertainties 

This RIA solely relied on secondary sources of information and data, many of which provided limited and uncertain information, requirin

rough estimation techniques for some numerical factors used in the cost calculations and associated numerical analyses of this RIA. Five 

uncertainty factors identified in this RIA are: 1. Data quality uncertainty: This factor includes uncertainty in data sources and data years regarding estimates of affected CCR tonnage

2. CCR beneficial use: Two countervailing uncertainty factors may constitute indirect effects of RCRA regulation of CCR disposal: 

o Listing CCR as “hazardous waste” could create market stigma, state regulatory barriers, or regulatory compliance cost barriers w

beneficial use (e.g., non-encapsulated uses). Such reduction could increase economic demand and induce higher prices for substi

included in the cost estimates of this RIA. 

o On the other hand, some electricity plants may minimize RCRA regulatory costs by increasing their supplies of future annual CC

3. Landfill prices & capacity: Regulation of CCR as hazardous waste will require a national mix of (a) new RCRA Subtitle C permits fo

expansion of commercial hazardous waste landfill capacity. Short-term price hikes and capacity constraints are not factored into the 

4. Dewatering treatment: The cost estimate for this sub-option is based on extrapolation of an estimate developed by a single electric ut

Furthermore, plants recently or soon converting voluntarily to dry disposal will reduce this regulatory cost. For example, TVA annouproposed plan to convert all 11 of its coal-fired electricity plants to dry disposal in absence of this regulation. If finalized, TVA’s pla

cost for this sub-option by roughly 7% (i.e., 11 of 495 plants). 

5. Incomplete cost elements: Because of lack of data or difficulty, this RIA did not formulate annualized cost estimates for three regulat

tank/container storage design and O&M requirements, (b) facility-wide corrective action, and (c) added cost for cleanup of future CC

hazardous remediation waste.
Chapter 1 

Problem Statement 

For purpose of Federal rulemakings, the 1993 Executive Order 12866 “Regulatory Planning and Review” (Section 1(

Federal regulatory agency to identify the problem that it intends to address, including where applicable, the failures oinstitutions that warrant new agency action, as well as to assess the significance of the problem. In line with this requprovides a problem statement consisting of the institutional context (i.e., prior EPA actions), significance of the problenvironmental damages), and characterization of market failure. 

1A. Institutional Context The EPA’s regulatory evaluation of coal combustion residues (CCR) dates back to 1978. In December 1978, the EPA 

industrial hazardous waste regulations to implement Subtitle C (i.e., Sections 3001 to 3020) of the Resource Conserv

(RCRA). At that time, the EPA recognized that certain large-volume industrial wastes, including wastes from the com(aka “CCR” as used in this RIA), might warrant special treatment under RCRA regulation. On 18 December 1978, Eand never finalized a relatively limited set of ten RCRA Subtitle C industrial hazardous waste regulations for the man

Included in this deferral of hazardous waste requirements were six categories of industrial wastes --- which EPA termuntil further study and assessment could be completed by EPA to determine their risk to human health and the enviroof special wastes included: 

1. Cement kiln dust 2. Mining waste 3. Oil and gas drilling muds and oil production brines 4. Phosphate rock mining, beneficiation, and processing waste 5. Uranium waste 6. Utility waste (i.e., fossil fuel combustion waste by electric utility plants) 

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

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

3 Federal Register, Vol. 43, No. 243, 18 December 1978, page 59015, section 250.46-2 “Utility Waste” of “Hazardous Waste Guidelines and 

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

4 To learn more about these six “special wastes” see EPA’s special waste website at http://www.epa.gov/osw/nonhaz/industrial/special/index
Bevill Amendments5 which exempted “special wastes” from regulation under Subtitle C of RCRA until further study 

could be performed: 

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

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

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

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

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

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

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

supports is a continuation of those prior evaluations. 

1B. Environmental Damages A large environmental disaster associated with CCR occurred in 2008, which brought acute public and Congressional 

of industrial wastes, resulting in a renewed call for EPA to complete its regulatory evaluation of CCR. On 22 Decem

billion gallon (i.e., 5.4 million cubic yards) unintentional environmental release (spill) of fly ash sludge over 300 acreValley Authority (TVA) coal-fired electric utility surface impoundment in Kingston TN, causing significant damage 

recreational lake, roadways, gas pipeline, and a railroad, and attracting major citizen, national press, and Congression

CCR management and the urgent need for prevention of such future environmental damage. In the wake of this disas2009 Senate confirmation hearing, EPA Administrator-designate Lisa P. Jackson, testified6: 

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

According to a 23 January 2009 news report,7 there was growing Congressional interest for either the EPA with its ex

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

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

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

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

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

7 Source: Waste Business Journal, “EPA Vows to Act on Coal Waste,” 23 January 2009, http://www.wastebusinessjournal.com/news/wbj200
“Several lawmakers have introduced, or announced plans to introduce, competing legislation to regulate Senate Environment & Public Works Committee Chairwoman Barbara Boxer (D-CA) said she would introcompelling EPA to regulate CCR in the event the Obama EPA fails to act soon. "If we are not satisfied wimove legislatively," Boxer told EPA Administrator-designate Lisa Jackson at a January 14 [2009] confirm

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

Just three weeks after the TVA’s Kingston Tennessee coal slurry impoundment disaster, House Natural Resources Co

Rahall (D-WV) introduced legislation requiring federal standards to regulate the engineering of coal ash impoundmen

January 2009, the Coal Ash Reclamation and Environmental Safety Act of 2009 (H.R. 493) directs the Department of uniform federal design, engineering, and performance standards on coal ash impoundments to avoid a repeat of the daThe legislation, which requires minimum design and stability standards for all surface impoundments constructed to h

regulatory model for impoundments that is used for coal slurry management under the Surface Mining Control and R(SMCRA). In a letter9 dated 02 March 2009, the Environmental Integrity Project and Earthjustice, joined by the National Resour

Sierra Club, Environmental Defense, and 104 other environmental groups requested EPA Administrator Lisa Jackson possible” to regulate CCR. A letter signed by the groups and delivered to EPA on 03 March 2009 identified 12 princdevelopment of EPA standards. These include the phase-out of CCR surface impoundments, locating CCR disposal groundwater or surface water, requiring liners, leachate collection systems and adequate monitoring, and requiring in

term liability for cleanup: 

“The recent disaster at TVA's Kingston Plant stands as a startling reminder that federal standards for CCoverdue. For too long, power companies have been able to dump CCR, laden with a host of toxic metals liselenium, lead, mercury, and boron, in unlined mines, quarries, landfills, and surface impoundments. Witfederal standards governing disposal practices, contaminants can leak or spill from these dump sites, threhuman health, natural resources and wildlife.”10

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

8 Background information about the H.R. 493 legislation is available at: 

http://resourcescommittee.house.gov/index.php?option=com_content&task=view&id=439&Itemid=27

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

9 The 14-page letter is available at: http://www.environmentalintegrity.org/pubs/CCR%20Regulation%20Letter%20to%20EPA%20Adminis10 Source: http://www.environmentalintegrity.org/pub608.cfm 11 US Senate Resolution 64 is available at: http://www.govtrack.us/congress/bill.xpd?bill=sr111-64&tab=committees 
1C. Market Failure OMB’s 2003 Circular A-4 “Regulatory Analysis” guidance (pages 4 to 5) to Federal agencies for implementation of E

identifies three major types of market failure: (1) externality, common property resource and public good, (2) market or asymmetric information. The CCR proposed rule which this RIA supports may be characterized as addressing the 

environmental pollution and damages from CCR disposal landfills and impoundments. As summarized in the “Benef

there are a number of historical and recent environmental damage cases which represent externalities in that some or 

and environmental costs may be external to the electric utility plants (e.g., adverse health effect costs incurred by resi

surrounding the plants). If implemented, the CCR proposed rule may be expected to reduce this market failure externcosts of improving and monitoring the physical integrity of CCR disposal units, in the capital and operating costs incuthemselves. 
Chapter 2 

Potentially Affected Industrial Facilities & Waste Disposal Units 

2A. Identity of Potentially Affected Industries There are two categories of industries which may be directly affected by the CCR regulatory options. “Directly affectentities potentially subject to any of the rule’s requirements.12 In addition, there are 14 or more industries which bene

1. Coal-Fired Electric Utility Industry 

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

• Classification #1 of 2: 

The scope of industrial plants is classifiable as “coal-fired electric utility plants” under the US Census Bureau’s 

Industrial Classification System” NAICS code 22 “Utilities” economic sector, and in that sector, as a subgroup of 

within the NAICS 221112 “Fossil Fuel Electric Power Generation” industry:13NAICS 221112: This industry comprises establishments primarily engaged in operating fossil fuel powered 

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

combustion turbine conventional steam process to produce electric energy. The electric enthese establishments is provided to electric power transmission systems or to electric powe

systems. 

• Classification #2 of 2: 

The scope of industrial plants is classifiable as “electric utilities plus independent power producers” under the 

Administration (EIA) categorization system for its coal combustion electric power sector statistics:14

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

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

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

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

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

footnote 14 at http://www.epa.gov/sbrefa/documents/rfafinalguidance06.pdf 

13 Source: NAICS codes are defined at http://www.census.gov/cgi-bin/sssd/naics/naicsrch?chart=2007 14 Source: EIA glossary of terms at http://www.eia.doe.gov/glossary/index.html 
Independent power A corporation, person, agency, authority, or other legal entity or instrumentality that owns 

producer: facilities for the generation of electricity for use primarily by the public, and that is not an 2. Waste & Environmental Management Services Industries 

In addition, because some electric utility plants transport their CCR to either company-owned or to commercial offsitsome regulatory options may trigger RCRA facility-wide corrective action, the regulatory options of the proposed rul

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

options evaluated in this RIA). 

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

149 of the 495 electric utility plants may transport some or all of the 15 million tons pdisposal). 

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

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

year CCR for offsite disposal). 

NAICS 562910: Environmental cleanup/remediation services industry. 

3. Industries Which “Beneficially Use” CCR 

According to the American Coal Ash Association (ACAA)15 as of 2007 there are over 15 industries which “beneficia

industrial applications. These industrial applications are listed below with corresponding NAICS16 codes estimated b

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

1. Concrete/concrete products/grout NAICS 3273 Cement & Concrete Product Manufactur2. Blended cement/raw feed for clinker NAICS 3273 Cement & Concrete Product Manufactur3. Flowable fill NAICS 23 Construction 

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

usa.org/associations/8003/files/2007_ACAA_CCP_Survey_Report_Form%2809-15-08%29.pdf 

16 NAICS = North American Industrial Classification System; NAICS codes definitions are available at http://www.census.gov/cgi-bin/sssd/

• 2-digit codes represent economic sectors 

• 3-digit codes represent economic sub-sectors 

• 4-digit codes represent industry groups 

• 5-digit and 6-digit codes represent single industries 
4. Structural fills/embankments NAICS 23 Construction 5. Road base/sub-base NAICS 237310 Highway, Street & Bridge Constructio6. Soil modification/stabilization NAICS 23 Construction 7. Mineral filler in asphalt NAICS 324121 Asphalt Paving Mixture & Block Man8. Snow and ice control NAICS 488490 Other Support Activities for Road Tra

9. Blasting grit/  Roofing granules 

NAICS 212319 Other Crushed & Broken Stone Minin

NAICS 324122 Asphalt Shingle & Coating Materials 

10. Mining applications NAICS 212 Mining 11. Gypsum panel products (e.g., wallboard) NAICS 327420 Gypsum Product Manufacturing 12. Waste stabilization/solidification NAICS 5622 Waste Treatment & Disposal 13. Agriculture NAICS 111 Crop Production 14. Aggregate NAICS 23 Construction 15. Miscellaneous/other (unidentified industries) NAICS not identified 

2B. Identity of Coal-Fired Electric Utility Plants This RIA initially identified the sub-group of potentially affected coal-fired electric utility plants using the 2007 US D

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

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

• Database filter #1 of 3: Sorted the 2007 EIA-860 electric plant database by the North American Industry 

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

electric power, natural gas, steam supply, water supply, and sewage removal. Within this sactivities associated with the utility services provided vary by utility: electric power includtransmission, and distribution; natural gas includes distribution; steam supply includes pro

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

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

The file contains generator-specific information such as initial date of commercial operation, prime movers, generating capacity, energy sourproposed generators, proposed changes to existing generators, county and State location (including power plant address), ownership, and FEAlso included are data related to the ability to use multiple fuels; specifically, data on co-firing and fuel switching are included. The EIA-86online at http://www.eia.doe.gov/cneaf/electricity/page/eia860.html. The DOE spreadsheet “existingunits2007” is available at 

http://www.eia.doe.gov/cneaf/electricity/page/capacity/capacity.html. 
distribution; water supply includes treatment and distribution; and sewage removal includtreatment, and disposal of waste through sewer systems and sewage treatment facilities. Exsector are establishments primarily engaged in waste management services classified in Su

Management and Remediation Services. These establishments also collect, treat, and dispo

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

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

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

the coal type codes displayed in Exhibit 2A below. In addition to these five categories of coal, examples secondary energy sources reported by coal burning electric utility plants are agriculture byproducts, distillgas, petroleum coke, propane, and wood & waste solids. 

Exhibit 2A 

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

Item Code Type of Coal 

1 BIT Anthracite Coal, Bituminous Coal 2 LIG Lignite Coal 3 SUB Sub-bituminous Coal 4 WC Waste/Other Coal (Anthracite Culm, Bituminous Gob, Fine Coal, Lignite Waste, Waste Coal) 5 SC Coal Synfuel. Coal-based solid fuel that has been processed by a coal synfuel plant, and coal-based f

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

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

reported operating status of the generators at these plants (i.e., OP, OS, SB, RE, OA)18, 11 plants reporte

out-of-service, 2 plants reported that all generators are on standby and all remaining plants reported that generators is operating. Removal of the 11 out-of-service plants from the master list resulted in a total af495 coal-fired electric utility plants.19 Appendix B presents the list of 495 plants.20

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

Out of service – was not used for some or all of the reporting period and is NOT expected to be returned to service in the next calendar year, available for service but not normally used (has little or no generation during the year) for this reporting period, RE = Retired - no longer in s

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

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

19 This RIA filtered out 11 out-of-service electricity plant identification codes: 508, 511, 996, 1732, 2341, 2468, 2529, 2531, 2908, 3419, an20 In comparison, a 2008 EPA Office of Water (OW) study estimated a nationwide total of 497 coal-fired electric plants using the same 2005 

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

have converted to other non-coal fuels or are not operating). Source: Table 3-1 (page 3-9) of EPA Office of Waster “Steam Electric Power GCategory: 2007/2008 Detailed Study Report,” report nr. 821-R-08-011, August 2008; http://www.epa.gov/guide/304m/2008/steam-detailed-2
For purpose of identifying the types and size classifications for owner entities, this RIA initially used the utility code 

860 database to identify which plants are owned by the same company. Company owner classifications were also ch

using internet searches by plant and company name which sometimes revealed parent company owners. As summari

Exhibit 2C below, these 495 coal-fired electric utility plants are owned and operated by 200 entities which are listed RIA. The 495 plants have a combined electricity generation nameplate capacity of 369,183 MW (megawatts), ranginfrom 2.3 MW to 3,969 MW, with an average size of 746 MW and a median size of 497 MW. This combined capacit

1.088 million MW total US electricity generation capacity as of 2007.21

Exhibit 2B 

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

Item Type of Owner Entity* 

Entity Size 

Class** 

Coal-Fired Electric 

Utility Plant Count 

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

Summary: 

Column totals = 495 

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

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

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

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

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

• Small non-government = Based on the US Small Business Administration NAICS code 221112 small business siz

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

• Non-small non-government = entity’s total annual electricity generation >4 million megawatt hours per year. • Small government = Based on the RFA’s definition (5 US Code section 601(5)) of “small government jurisdiction

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

• Non-small government = entity’s jurisdiction population >50,000 people. 

21 Source: US Dept of Energy (DOE), Energy Information Administration (EIA) website at http://www.eia.doe.gov/cneaf/electricity/epa/epa
Exhibit 2C 

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

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

Item State 

Federal 

government 

State 

Government 

Non-small 

municipal 

Non-small 

company 

Non-small 

cooperative 

County 

government 

Small 

municipal 

Small 

company 

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

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

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

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

Item State 

Federal 

government 

State 

Government 

Non-small 

municipal 

Non-small 

company 

Non-small 

cooperative 

County 

government 

Small 

municipal 

Small 

company 

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

Column totals= 11 13 27 372 20 1 33 12 

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

according to the five types of coal fuel categories: 

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

• Lignite coal (LIG): 21 plants (4%) • Coal-based synthetic fuel (SC): 19 plants (4%) • Sub-bituminous coal (SUB): 201 plants (41%) • Waste/other coal (WC): 33 plants (7%) 

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

and the types of coal burned for the list of 495 plants. As displayed in the state-by-state Exhibit 2D below, 47 states utility plants (3 states --- ID, RI, VT --- and DC do not have electric utility plants). The top-5 state coal-fired electric 

1. PA 34 plants

2. IN & OH 26 plants each

3. IL 25 plants

4. MI & NC 22 plants each

5. KY 21plants
Exhibit 2D 

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

and Associated CCR Generation 

Item State 

Count of 

Plants 

(2007) % of Plants 

CCR Generated 

(tons as of 2005) 

% of CCR 

Generation 

1 AK 2 0.40% 46,179 0.03% 2 AL 10 2.02% 3,210,337 2.27% 3 AR 3 0.61% 744,267 0.53% 4 AZ 6 1.21% 3,334,030 2.36% 5 CA 6 1.21% 159,927 0.11% 6 CO 14 2.83% 1,704,432 1.21% 7 CT 2 0.40% 172,280 0.12% 8 DC 0 0% 0 0% 9 DE 3 0.61% 251,205 0.18% 

10 FL 15 3.03% 6,132,345 4.34% 11 GA 11 2.22% 6,077,700 4.30% 12 HI 2 0.40% 58,968 0.04% 13 IA 19 3.84% 1,136,290 0.80% 14 ID 0 0% 0 0% 15 IL 25 5.05% 3,856,748 2.73% 16 IN 26 5.25% 8,798,844 6.23% 17 KS 8 1.62% 1,495,099 1.06% 18 KY 21 4.24% 9,197,567 6.51% 19 LA 4 0.81% 1,614,800 1.14% 20 MA 4 0.81% 363,150 0.26% 21 MD 8 1.62% 1,932,740 1.37% 22 ME 1 0.20% 48,000 0.03% 23 MI 22 4.44% 2,369,673 1.68% 24 MN 16 3.23% 1,525,979 1.08% 25 MO 20 4.04% 2,679,742 1.90% 26 MS 5 1.01% 1,229,400 0.87% 27 MT 5 1.01% 1,830,624 1.30% 28 NC 22 4.44% 5,504,531 3.90% 29 ND 7 1.41% 3,038,100 2.15% 

Exhibit 2D 

State-by-State Count of NAICS Code 22 

and Associated CCR Gen

Item State 

Count of 

Plants 

(2007) % of Plants 

C

(t

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

 Total 495 100% 1

* Note: In comparison to this estimate based on DRIA, the American Coal Ash Association (ACAACCR generated in 2005 based on its annual volunhttp://acaa.affiniscape.com/associations/8003/file%2809-19-06%29Corrected-11-09-07.pdf 
2C. Types of CCR Disposal Units 

• Estimated Plant Counts by Type of CCR Disposal Unit 

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

“Steam-Electric Plant Operation and Design Report” database.22 The EIA-767 database is the primary data source fo

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

disposition data to the EIA-767 database. Schedule 3 of the EIA-767 database contains the annual disposition of CCR 

following five forms of CCR management categories, according to annual tons disposed for each plant. EIA-767 doe

CCR disposal units for each plant: 

1. Company-owned landfill 2. Company-owned disposal ponds (i.e., surface impoundments) 3. Onsite use and storage (this RIA assumes all of this quantity eventually goes to beneficial use, not disposal4. Sold (for beneficial use) 5. Disposed off site (this RIA assigns these tonnages as offsite commercial landfills) 

The 2005 EIA-767 database contained annual CCR disposal data for 363 of the 495 plants identified in the 2007 EIAplants are over 100 MW in size and thus are covered by the EIA-767 database. For the 132 plants which did not repo

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

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

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

22 Source: The DOE-EIA Form 767 database is available for 5 years spanning 2001 to 2005 at http://www.eia.doe.gov/cneaf/electricity/page/

database includes annual data from organic-fueled or combustible renewable steam-electric plants with a generator nameplate rating of 10 or regardless of current ownership and/or operation. However, it contains annual tonnage CCR generation, CCR disposal, and CCR beneficial 100MW in size. The EIA terminated the EIA-767 database after year 2005. Beginning with calendar year 2007 data, two other surveys, the EIA-923, will collect most of the data formerly collected by Form EIA-767. No data will be collected for 2006. The following weblink prov

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

or the Form EIA-923: http://www.eia.doe.gov/cneaf/electricity/2008forms/consolidate.html 
• Onsite landfills: 311 plants operate onsite CCR landfills (this RIA refers to these as “onsite” landfi

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

 212 plants: Identified through actual data reporting of 363 coal-fired electr

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

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

plants = 132 plants) between 1 MW and 100 MW size for which there is nEIA-767 database, and for which the CCR disposal engineering control coassigned the lowest-cost of three landfill options: onsite dug landfill, onsite landfill. The cost model assignment was dependent upon the level of baseassumed required by each plant’s state location and annual CCR disposal testimated that 99 of the 132 plants without data dispose CCR in onsite land

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

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

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

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

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

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

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

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

of wastes is reported as either (a) company-owned landfill, (b) company-ow

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

means offsite commercial landfill. Plants could have reported offsite minewas not "sold" (e.g., they paid to dispose it in a mine or it was used as min

made to the electric utility). However, it is unknown the sub-quantity of “includes plants reporting tonnages for non-sold uses as offsite minefill.23

23 In July 2009, ORCR contacted the DOE-EIA Form 767 questionnaire contact person (Natalie Ko, Electric Power Division) to clarify this R

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

• 116 plants Non-duplicative sub-total of these five offsite sub

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

for which there is no CCR disposal data in the EIA-767 database, and for wengineering control cost model used in this RIA assigned the lowest-cost o

onsite dug landfill, onsite pile landfill, or offsite landfill. The cost model aupon the level of baseline engineering controls assumed required by each p

annual CCR disposal tonnage. 

• Estimated Counts of CCR Disposal Units 

The methodology of this RIA does not estimate or use secondary information about the actual count of CCR disposal and impoundment units) used by these 467 onsite or offsite disposing plants. However, there are two sources of CCR 

• Source #1 of 2: ASTSWMO 

The February-March 2009 ASTSWMO voluntary participation survey24 of 42 states (which is incomplete coverage o

this RIA for the 495 coal-fired electric plants) estimates a total of 484 electric utility plant CCR disposal units: 

• 227 electric utility plant CCR landfill units in 41 states • 257 electric utility plant CCR impoundment units in 33 states • Total electric utility plant CCR disposal units = 484 (i.e., 227 landfills + 257 impoundments) 

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

NAICS code 221112, (b) may also include counts of CCR disposal units associated with other industries which genin the surveyed states, (c) may include inactive/abandoned as well as active CCR disposal units, or (d) may include 

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

· “Ash is recycled as a beneficial re-use product for flowable fill in the construction industry” 24 Source: Association of State and Territorial Solid Waste Management Officials (ASTSWMO), 01 April 2009 letter to Matt Hale, Director

Conservation and Recovery: http://www.astswmo.org/files/publications/Positionpapers/ASTSWMO-CCB-letter-attachments.pdf 
• Source #2 of 2: EPA 

In March 2009 EPA sent letters25 to 210 coal-fired electric plant facilities and owner companies in order to identify 

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

Kingston TN electricity plant. However, EPA mailed those letters under Comprehensive Emergency Response, CoAct (CERCLA) Section 104 authority, which prohibits the information collected from being used for this RIA or othin CERCLA: 

“The authority of this subsection may be exercised only for the purposes of determining the need for response, otaking any response action under this subchapter, or otherwise enforcing the provisions of this subchapter.” (S

Section 9604(e)(1) “Action Authorized”26) 

Although not used in this RIA other than for reference here, the responses received to the March 2009 EPA letters r

584 CCR impoundments units at electric utility plants. The letters did not collect information about CCR landfills27

2D. Types of CCR and Annual Quantities As of 2008, coal-fired utilities burn approximately 1.036 billion tons of coal per year using a variety of conventional 

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

1. Fly ash 2. Bottom ash 3. Flue gas desulfurization (FGD) sludge 4. Gypsum 5. Other residues (including boiler slag) 

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

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

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

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

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

25 Source: Additional information about these March 2009 EPA letters is available at http://www.epa.gov/osw/nonhaz/industrial/special/foss26 CERCLA Section 9604 is available at http://frwebgate.access.gpo.gov/cgi-bin/usc.cgi?ACTION=BROWSE&TITLE=42USCC103 27 Source: EPA’s 584 CCR impoundment unit count is documented at http://www.epa.gov/osw/nonhaz/industrial/special/fossil/surveys/faqs.
categories in the 2005 EIA 767 database. As estimated in this RIA and displayed below in Exhibit 2G, the 495 elect

141.2 million tons of CCR. 

• >100 MW plants: Exhibit 2E below presents CCR disposition data for a sub-total of 120.9 million tons CCR 

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

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

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

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

assumption is supported by (a) DOE’s August 2006 report29 “Coal Combustion Waste Man

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

(b) the American Coal Ash Association (ACAA) which indicates that 49.6 million tons of cused in 200530. However, the beneficial use estimate in Exhibit 2E below is much less at 3

based on the EIA-767 “Sold” (i.e., beneficial use) CCR tonnage category. But adding the 8"onsite use & storage" yields an estimate of 47.0 million tons (Exhibit 2G), which nearly mbeneficial use estimate of 49.6 million tons. This suggests it is valid to assign the tonnage rdatabase as "onsite use & storage" to beneficial use rather than to disposal. 

• 1 to 100 MW plants:Exhibit 2F below presents an additional sub-total of 20.3 million tons per year of CCR g

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

1 and 100 megawatts are not required to report their disposal practices in the 2005 EIA-76percent ash content data from Schedule 4A of the 2005 EIA-767 database were used to est

quantities for 102 plants within this smaller size category. For 5 plants for which EIA-767 unavailable for 2005, coal use data from Schedule 4A of the 2007 EIA-923 database were 

28 In the 2005 DPRA Report, an additional step was included after step 1 that identified additional disposal practices using landfill and surfa

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

29 Source: Footnote c of Table 1 on page 6 of DOE’s August 2006 report at http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=2008 30 Source: ACAA’s 2005 beneficial use data are available at http://acaa.affiniscape.com/associations/8003/files/2005%20CCP%20Survey%2

11-09-07.pdf 
generation quantities for those 5 plants. FGD sludge generation data obtained from Sched

767 database were used for 115 plants. Landfill (either on-site or off-site whichever is mo

assumed CCR disposal practice. No gypsum or other byproduct generation quantities wer

between 1 MW and 10 MW, ash generation quantities estimated using generator nameplatthe 2007 DOE Form 860 database. This 1 MW to 100 MW subtotal of 132 plants consists 

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

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

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

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

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

greater than 100 MW reported no final disposition quantities for FGD sludge in Schedule 3A of the 2005 EIA-767 database, the reported FGis assumed in this RIA to be placed in a landfill for that plant. 
Exhibit 2E 

Annual CCR Disposition for NAICS 22 Electric Utility Plants >100 MW Capacity (tons per year as of 200

A B C D 

Item CCR Category 

Company-Owned 

Landfill 

(Dry Disposal) 

Company-Owned 

Disposal Ponds 

(Wet Disposal) 

Onsite Use & 

Storage (assumed 

as beneficial use) 

Sold for 

Beneficial Use 

Offsite 

(assum

land

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

Exhibit 2F 

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

A B C 

Item CCR Category 

Fly Ash Disposed in 

Off-site Landfill 

(Plants 1 MW 

to 100 MW) 

Fly Ash Disposed in 

Company-owned 

Landfill 

(Plants 1 MW to 100 MW) 

FGD Disposed in 

Company-Owned Landfill 

(Plants >10 MW) 

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

Exhibit 2G 

Annual CCR Disposition for NAICS 22 Electric Utility Plants All Sizes (tons per year as of 2005) 

(Source: Exhibit 2F + Exhibit 2G) 

A B C D 

Item CCR Category 

Company-Owned 

Landfill 

(Dry disposal) 

Company-Owned 

Disposal Ponds 

(Wet disposal) 

Beneficial Use 

(onsite BU + offsite 

BU + storage for BU) 

Offsite Disp

(assumed of

commercial lan

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

 Percentages 40% 16% 33% 11% 
Exhibit 2H below summarizes the respective plant counts, annual tonnage CCR disposal, and electricity generation n467 plants which dispose CCR, according to type of CCR disposal method (i.e., CCR landfills and CCR impoundmenreported more than one management method, the sum of the plants across each disposal method exceeds the total cou

Exhibit 2H 

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

A B C 

Plants Using CCR Landfills (dry disposal) 

Characterizing Metrics Onsite Landfills Offsite** 

Plants Using CCR 

Impoundments*** 

(wet disposal) 

1. 2007 Count of Coal-Fired Electric Utility Plants which Dispose CCR 

311 plants 

(63% of 495) 

149 plants 

 (30% of 495) 

(84 plants solely use 

offsite landfills) 

158 plants 

(32% of 495) 

46

(C

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

56.8 million tons (60%) 

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

15.0 million tons (16%) 

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

22.4 million tons (24%) 

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

94

• • • • 

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

213,978 MW (58%) 

• 11 MW • 3,969 MW • 772 MW • 538 MW 

90,547 MW (25%) 

• 2 MW • 2,911 MW • 608 MW • 350 MW 

180,901 MW (49%) 

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

• • • • 

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

transport large volumes of wet (i.e., watery) CCR long distances. *** Surface impoundments are reported in the EIA-767 database as “company-owned ponds.” This RIA assumes all are located ons
2E. Size of CCR Disposal Units The size of CCR disposal units ranges from modest to very large, with some impoundments covering 1,500 acres or mis based on the annual tonnage of CCR placed in the unit. CCR disposal unit size assumptions for this RIA are adoptthe 2005 DPRA Report: 

• Landfills sizes:

o Designed as “combination fill landfills”

 3.8 million cubic yards capacity  50% of the capacity excavated below grade 40-year capacity (i.e., operating lifespan)32  Per-unit surface area size ranges from 12 acres for 10,000 tons per year to over 2,000 acres for 2,00

o Designed as “pile fill landfills”

 3.4 million cubic yards capacity  5% of the capacity excavated below grade 40-year capacity (i.e., operating lifespan) Per-unit surface area ranges from 16 acres for 10,000 tons per year to over 3,000 acres for 2,000,00

• Surface impoundment sizes:

o 100% of capacity below grade

o 40-year capacity

o Per-unit surface area ranges from 30 acres for 10,000 tons per year, 140 acres for 50,000 tons per year, 500 acre

year, 1,400 acres for 500,000 tons per year, and 5,500 acres for 2,000,000 tons per year.

32 For the 30 Nov 2005 DPRA report (“Estimation of Costs for Regulating Fossil Fuel Combustion Ash Management at Large Electric Utilit

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

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

years. Therefore, this RIA assumes a 40-year lifespan for both landfills and impoundments. 
Chapter 3 

Baseline CCR Management by the Electric Utility Industry 

This chapter evaluates baseline (i.e., current) management of CCR by the electric utility industry. This baseline cons

described in this chapter: CCR disposal and CCR beneficial use. This chapter first presents and evaluation of baselin

operating conditions (i.e., “engineering controls” and “ancillary costs”) of CCR disposal units and an estimate of the 

electric utility industry. A second section of this chapter characterizes baseline CCR beneficial use for CCR which is 

estimate of the associated net benefits to the national economy. 3A. Cost of Baseline CCR Disposal This chapter presents characterizing data and estimates of the costs to the electric utility industry and to governmentindustry engineering controls and other costs associated with CCR disposal. OMB’s 2003 Circular A-4 “Regul

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

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

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

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

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

1. Ground water monitoring 2. Bottom liners 3. Leachate collection system 4. Dust controls – applicable to landfills only 5. Rain and surface water run-on/run-off controls – applicable to landfills only 6. Financial assurance for disposal unit closure and post-closure 

7. Location/siting restrictions (6 types: water tables, floodplains, wetlands, fault areas, seismic zones, karst 

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

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

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

• Characterization of Industry Baseline CCR Disposal 

For each of the 467 operating electric utility plants which currently (2007) dispose CCR onsite or offsite (28 of the 49

their CCR for beneficial uses not disposal), this RIA estimated baseline engineering controls at disposal units and asscosts for each type of disposal (note: the sum of plant counts for each disposal category below exceeds 467 because s

one type of CCR disposal method): 

o 311 plants with active onsite CCR landfills o 158 plants with active onsite CCR surface impoundments o 149 plants which offsite dispose (assumed all involve offsite landfills) 

For this RIA, the “baseline” is defined as existing conditions plus projection of future conditions over the 50-year fut

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

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

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

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

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

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

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

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

studies, and no state-regulatory data on controls from Step 1, no controls are assumed under baseline for oimpoundments; this represents a worst case (i.e., high cost) assumption. 
The associated data sources and findings for each baseline characterization step are described below. 

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

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

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

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

the state): AR, AZ, CA, IA, IN, KS, MD, MN, NE, SD, SI, WV. 

o Impoundments: Voluntary controls for 39 plants with impoundments (25% of 158 plants with impoun

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

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

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

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

upon the effective date of the regulation (e.g., groundwater monitoring), upon retirement of the disposal unit (e.g., pofor newly constructed units only. Appendix D of this RIA provides a summary of the state government requirements impoundments. Current CCR disposal regulations have been reviewed for the top 34 states that utilize coal for produ

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

• Point-of Compliance: 

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

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

• Number of Wells: 

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

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

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

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

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

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

recommends a minimum of one-down-gradient detection well every 500 feet. 
• Monitoring Parameters: 

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

(i.e., 40 CFR 261 Appendix VIII). Of the 34 state regulations reviewed, three states require chemical indicatoimpoundments [CO, PA, WV] and 11 states require chemical indicator monitoring for landfills [IA, FL, KY, MWI, WV]. Three states require Appendix VIII constituent monitoring for impoundments [MO, PA, WV], and Appendix VIII constituent monitoring for landfills [GA, FL, IA, IL, MI, MO, OH, TN, UT, WV]. 

• Monitoring Frequency: 

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

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

• Timing of State Regulation Implementation: 

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

TX, WV, WI. 

2. Bottom liner requirements: 

• Impoundments: 

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

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

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

• Landfills: 

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

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

WV (composite), WY (composite). 
3. Leachate collection/detection system requirements: 

• Impoundments: 

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

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

• Landfills: 

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

collection systems at newly constructed landfills: FL, IL, LA, MS, MO, NV, OK, TX, WI, WV, WY. 

4. Dust control requirements: (landfills only) 

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

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

OH, PA, SC, TN, UT, VA, WA. Nine states require dust controls only at newly constructed landfills: FL, IL (inclMO, NM, OK, WI, WV, WY (includes compaction). 

5. Run-on/run-off control requirements: (landfills only) 

Of the 34 state regulations reviewed, 18 states require immediate compliance with run-on/run-off control requiremGA, IA, IN, KS, MD, MN, MT, NC, NY, OH, PA, SC, TN, UT, VA, WA. 11 states require run-on/run-off only alandfills: FL, IL, LA, MS, MO, NV, OK, TX, WI, WV, WY. 

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

• Impoundments: 

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

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

• Landfills: 

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

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

7. Siting Restrictions (6 categories)

State regulations for the top-25 coal usage states (for electricity) were reviewed back in year 2000 for any siting reregulations were not updated as part of this RIA. The following is a synopsis of state government siting restriction

surface impoundments and landfills, according to six categories of siting restrictions (water table, floodplains, wetzones, unstable karst terrain). 
• 7-1: Below the natural water table: 

o Of the 25 state regulations reviewed, five states have siting restrictions below the natural water table for sur

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

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

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

• 7-2: Floodplains: 

o Of the 25 state regulations reviewed, eight states have siting restrictions in floodplains for surface impoundm

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

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

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

• 7-3: Wetlands 

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

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

o Of the 25 state regulations reviewed, 17 states that have siting restrictions in wetlands for landfills include A

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

• 7-4: Fault areas: 

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

waste in place), WV. 

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

WI. 

• 7-5: Seismic zones: 

o Of the 25 state regulations reviewed, two states have siting restrictions in seismic impact areas for surface im

MO (if closed with waste in place), WV. 

o Of the 25 state regulations reviewed, eight states have siting restrictions in seismic impact areas for landfill

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

• 7-6: Karst areas: 

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

closed with waste in place), ND, PA, WV (1,000 feet away). 

o Of the 25 state regulations reviewed, 12 states have siting restrictions in unstable areas for landfills: AZ, CO

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

8. Closure cap controls 

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

impoundments: AZ (synthetic cap), KY (synthetic cap), LA (clay cap), MO (soil cap), ND (clay or syntheti
cap), OK (clay or synthetic cap), PA (clay or synthetic), TN (synthetic cap). Four states require closure con

constructed surface impoundments: CO (clay or synthetic cap), MI (clay or synthetic cap), NC (soil cap), W

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

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

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

9. Post-closure monitoring requirements 

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

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

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

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

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

groundwater monitoring at newly constructed landfills: FL, IL, LA, MS, NV, OK, WI, WV. 

10. Baseline storage tank/container design and operating standards Not evaluated in this RIA because of a lack of data about the baseline count and conditions of CCR storage or treatmcontainment buildings at electric utility plants 

• Industry Baseline CCR Disposal Characterization Findings 

Appendix E of this RIA presents on a plant-by-plant basis the baseline engineering controls assumed for each of the 

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

and further assumes that all of those offsite landfills currently comply with the engineering controls described in the Cthe regulatory options). Exhibits 3A (for landfills) and Exhibit 3A (for impoundments) below summarize the assign

conditions in this RIA for these 411 plants. 
Exhibit 3A 

Baseline Compliance with State Government Engineering Control Requirements: CCR Landfills 

A B C D E F 

Future new CCR landfills Existing CCR 

Current or State Regulated 

Engineering control 

No. of 

Plants 

Percent of 

311 plants 

with LFs 

Volume of 

CCR diposed 

in landfills 

(tons/year) 

% of 71.8 

million tons 

onsite + offsite 

LF 

No. of 

Plants 

Percent of 

311 plants 

with LFs 

Volu

CCR d

in la

(ton

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

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

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

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

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

0004, 286 pp; http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=2008: 

• 97% of newly constructed CCR landfills have groundwater monitoring (Table 14, p.35) • 97% of newly constructed CCR landfills have liners (Table 13, p.33) 

These percentages reflect a mix of state government permit requirements for some surveyed electricity plants, plus industry voluntary ac
Exhibit 3B 

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

A B C D E F 

Future new CCR impoundments Existing CCR im

Current or State Regulated 

Engineering control 

No. of 

Plants 

Percent of 

158 plants 

with SIs 

Volume of CCR 

disposed in 

impoundments 

(tons/year) 

% of 22.4 

million tons 

CCR disposed 

in 

impoundments 

No. of 

Plants 

Percent of 

158 plants 

with SIs 

V

CC

imp

(t

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

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

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

9. Post Closure Monitoring 78 49% 9,520,360 43% 65 41% 710. Storage design standards ND ND ND ND ND ND 

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

0004, 286 pages; http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=2008: 

• 78% of newly constructed CCR impoundments have groundwater monitoring (Table 14, p.35) • 100% of newly constructed CCR impoundments have liners (Table 13, p.33) 

These percentages reflect a mix of state government permit requirements for some surveyed electricity plants, plus industry voluntary ac
• Baseline CCR Disposal Cost Estimation 

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

• Cost Estimation Framework 

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

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

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

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

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

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

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

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

footage sizes and associated quantities of labor, equipment and materials for the specified designing, constructing, operating, and closing a landfill or impoundment. Then it combcomponent data inputs, with input data on the prices/ costs/ fees for the physical componoutputs, the capital and annual O&M costs of specified sizes of landfills and impoundmecosts/ fees used as input data include a wide range of items, such as the per-acre cost of lequipment, labor, bottom liner materials, and cover materials. For this RIA, the model wgenerate individual cost estimates for a series of five alternatively-sized CCR landfills an

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

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

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

DPRA Inc, Sept 1988, 129 pages which is available from the Federal docket ID nr EPA-HQ-RCRA-2006-0796 for the CCR proposed rule at

EPA previously publicly referenced this cost model in the following six publications: (a) “Draft Regulatory Impact Analysis for Pr

Criteria for Municipal Solid Waste Landfills,” prepared for US EPA Office of Solid Waste by Temple, Barker & Sloane, Inc., ICF IncorporaDPRA Inc.) and American Management Systems, Inc., 05 Aug 1988 (this document includes about a 4-page summary of the cost model); (bfor the Final Criteria for Municipal Solid Waste Landfills,” prepared for US EPA Office of Solid Waste by Temple, Barker & Sloane/ClaytoICF Inc, DPRA Inc, and American Management Systems, Inc., Dec 1990 (this document includes about a 4-page summary of the cost modelRegulatory Impact Analysis for the Final Criteria for Municipal Solid Waste Landfills,” prepared for US EPA, Office of Solid Waste by TemEnvironmental Consultants and ICF Inc, August 1991; (d) “40 CFR Parts 257 and 258 Solid Waste Disposal Facility Criteria: Proposed Rule

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

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

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

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

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

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

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

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

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

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

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

transfer of results from other studies, or data from case studies, or based mostly on professional jrather than data, for some of the major factors used in cost calculations. 

o Scenario-based estimates: Applied in absence of data, case studies, or assumptions for purpose o

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

future conditions based on variations in key drivers of change, including social, technological, e

drivers. Scenario construction is a futures analysis method; as such, scenario-based estimates do future with absolute certainty, but to explore uncertainties, possible consequences, and possible 

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

Record (ENR) Construction Cost Index, and using regional cost adjustment factors applied estimate involving on-site construction. These regional factors account for the variability band landscape construction costs. Cost adjustment factors are derived from the Means Buil

Year 2003 city factors. All the cities for each state were averaged together to derive a state 

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

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

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

depreciation of capital expenditures for pollution control equipment. 

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

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

• 7% discount rate: Applied for calculating both net present value cost and average annualized cost for the engin

applied in this RIA. Because both the annualized baseline cost and annualized incremental prestimated in this RIA consist of primarily (i.e., >95%) industry cost rather than government cdiscount rate rather than a lower (e.g., 3%, 2%, 1% or 0%) discount rate to represent the oppocapital investment and business expense financing (i.e., the average rate of return to corporate consistent with OMB’s 2003 Circular A-435 (page 33) and 1992 Circular A-9436 (page 8) whi

discount rate base-case should be used for regulatory analyses when regulation is expected to 

affect businesses and industries. 

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

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

CCR generation needing disposal from those plants). The 0.73% annual growth factor is base2009 "Annual Energy Outlook 2009" forecast change in US coal consumption for electricity 2010 (22.91 quadrillion Btus) and 2030 (26.41 quadrillion Btus), available at: 

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

• Beneficial use: If reported in the baseline by any particular plant, assumed to continue in the future by that pl• Offsite disposal: If reported in baseline by any particular plant, assumed to continue in the future by that plant. 

cost estimated under both baseline and regulatory options using the engineering control cost m

cost estimated separately outside of the model. 

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

operation were provided in the 1995 EPRI Comanagement Survey, these data were used. If tone disposal unit and more than one reported date for initial year of operation, the years were 

if a facility had three disposal units (2 landfills and 1 impoundment) with installation dates of 

35 2003 OMB Circular A-4: http://www.whitehouse.gov/omb/circulars_a004_a-4/ 36 1992 OMB Circular A-94: http://www.whitehouse.gov/omb/circulars_a094/ 
this RIA assumed the installation date of all the units was 1980. This assumption simplified t

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

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

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

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

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

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

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

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

• New landfills: The most economic of three landfill options, dug (i.e., combination land

below ground and 50% above ground), pile (i.e., 5 % of waste below ground and 95% a

determined within the cost model. The cost for the most economical approach is assignavailable data specify otherwise. The choice is dependent upon on engineering control disposal rate. 

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

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

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

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

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

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

Data (2002). 

 Assumes same groundwater monitoring requirements for both landfills and impoundments 

 Point of compliance: 

Placement at the unit boundary is assumed in the cost estimates. Unit boundary point-of-compliance monitoring c

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

 Number of wells: 

EPA’s March 1985 Ground Water Technical Enforcement Guidance Document (pages 2-8 to 2-16) recommends a 

spacing between down-gradient wells. EPA’s December 1980 SW-611 Procedures Manual for Groundwater MonDisposal Facilities (pages 40 to 43) recommends a maximum of 250 feet spacing between down-gradient wells. Adocuments are the most stringent and the state regulation minimums are the least stringent, a middle ground within 

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

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

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

gradient well is assumed. 

 Constituents: 

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

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

potassium, chloride, sodium, and sulfate) as a cost proxy. 

o Metals: Metals with primary and secondary Maximum Contaminant Levels (MCLs) (i.e., Al, Cu, Fe, Mn, A

Cr, Pb, Hg, Se, Tl). 

 Frequency: 

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

many current state regulations, even if some states require a quarterly or annual basis. 

 Unitized cost estimate: Dividing the average annual cost estimate result displayed in Exhibit 3D below (row item 1

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

above to conduct that activity under state government requirements, yields an average annual per-plant (i.e., unitiz

$64,000. In comparison, EPA’s most recent (2008) Information Collection Request (ICR) No. 0959.13 “Ground-WRequirements” (renewal) for the RCRA Subtitle C 40 CFR 264.92 and 265.92 TSDF “ground-water protection sta
estimate of $28,130 per year.37 The $64,000 unitized cost for groundwater monitoring generated by the above ass

engineering control cost model used for this RIA is 2.3 times larger and more appropriate to this RIA because it rewells per-plant to monitor the groundwater under the larger sized CCR disposal units compared to the average size

industrial waste disposal units. 

2. Baseline bottom liners 

 Same bottom liner requirements for both new landfills and new impoundments  The cost estimates include a composite (2-foot compacted clay-synthetic) liner for the more stringent design and a 2

liner, single-synthetic liner, and a 2-foot compacted ash liner for less stringent baseline designs. 

3. Baseline leachate collection system 

 No leachate collection is assumed from beneath the impoundment liner  The cost estimate is comprised of perforated pipes spaced approximately 300 feet apart along the base of the unit. I

leachate collection. Leachate is shipped by truck for off-site treatment. 

 Assumes 3-inches of leachate per year collected in landfill leachate collection systems. 

4. Baseline dust controls Cost estimate includes CCR compaction equipment, water trucks for spraying CCR during compaction and for sprayi

and covers for landfill trucks: 

 Compaction Equipment 

Ash is assumed to be compacted in the waste management area by self-propelled sheepsfoot rollers for regulatory 

controls. A model cost assumption is that four passes are made by the roller in 6-inch lifts. With these assumptionsapproximately 1,300 cy of ash per day. The operating life of purchased compaction equipment is assumed to be fisheepsfoot rollers required is estimated as follows: 

Rollers = (tons/yr)(2,000 lb/ton)(16.02 kg/m3 / lb/cf)

(1,190 kg/m3)(27 cf/cy)(1,300 cy/day)(300 days/yr) 

The cost of a sheepsfoot roller is assumed to be $75,000 in 1995 dollars. Plants will incur annual costs for equipment operation ($0.63/cy) and maintenance. Maintenance costs are assumed to be 5% of capital costs. Annual costs for compaction are estimated as follows: 

Annual Cost = (tons/yr)(2,000 lb/ton)(16.02 kg/m3 / lb/cf)($0.63/cy) + $75,000*0.05*Rollers 

(1,190 kg/m3)(27 cf/cy) 

• Water Truck for Compaction: 

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

37 $28,130 per year per-facility average cost derived for purpose of this RIA by dividing the reported $27.818 million annual cost by the repo

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

Water Truck Time for Compaction = (tons/yr)(2,000 lb/ton)(16.02 kg/m3 / lb/cf)(8 hr/day)(0.5)

(1,190 kg/m3)(27 cf/cy)(1,300 cy/day) 

One existing water truck for compaction and water spray on roads is estimated to be sufficient for plants managing leyear of ash. Facilities managing between 391,000 and 1,173,000 tons per year are assumed to purchase one additionamanaging between 1,173,000 and 1,955,000 tons per year are assumed to purchase two additional water trucks. Facil1,955,000 tons per year to the maximum facility size modeled of 2,000,000 tons per year are assumed to purchase thrThe cost of a water truck is assumed to be $101,000 in 1995 dollars. The water truck operating life is assumed to be fcosts for water spray for compaction are estimated assuming that the truck travels approximately five miles per day, f

fuel consumption of five miles per gallon at a fuel cost of $1.15 per gallon. The truck is assumed to operate 50% of thcompaction. The daily water volume used is assumed to be 10,000 gallons, at a cost of $2 per 1,000 gallons. The annuash management is estimated as follows: 

Annual Cost = (tons/yr)(2,000 lb/MT)(16.02 kg/m3 / lb/cf)(0.5) * [(8hr/day)($31.50/hr) 

(1,190 kg/m3)(27 cf/cy)(1,300 cy/day) + (5 mi/day)($1.15/gal)/(5 mi/gal) + (10,000 gal/day)($2/1,000 gal)] 

• Covers on Trucks: 

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

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

estimated as follows: Capital Cost = [(tons/year) x (2,000 lb/ton) x (16.02 kg/m3 / lb/cf) x (0.65 hr/load)] x ($4,800) 

Water truck capacity, refill time, and spray width were estimated by ICF in Cost Functions for Alternative CKD Cont

dated July 19, 1996. (1,190 kg/m3)(0.80)(27 cf/cy)(9 cy/load)(2,400 hr/yr) Annual costs for this dust control technology include the cost of the tarps and the cost to replace the tarps. Tarps are e

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

Annual Cost = (tons/yr)(2,000 lb/ton)(16.02 kg/m3 / lb/cf)($155/tarp + 0.25hr/tarp*$19/hr)

(1,190 kg/m3)(0.80)(27 cf/cy)(9 cy/load)(150 load/tarp) 

• Water Spray on Roads: 

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

currently have water trucks and use water spray on roads as a baseline management practice. A model assumption is required for a road length of 1.5 miles (3 miles roundtrip), with a road width of 10 meters. The water truck capacity is gallons and requires approximately one hour to fill. The water truck can spray a width of five meters at an assumed sp

For the baseline scenario, a model assumption is that the entire water volume (5,000 gallons) will be sprayed on each one side of the road (i.e., 1.5 miles x 5 meters). The resulting water volume per road area, averaged over the 1.25 hou
road and refill the truck, is approximately 2.5 times that of the average hourly daytime evaporation rate. Therefore, w

required 3 times per day. The water volume sprayed per road area is estimated as follows: 

Water per Area = (1.5 mi)(5,280 ft/mi)(0.3048 m/ft)(10 m)(5,000 gal)(3.785 L/gal) = 0.784 L/m2 

The time required for the water truck to be filled, spray along both sides of the road, and return for refilling is estimat

Time = (1 hour) + (3 miles)/(10 miles/hour) = 1.3 hour 

Therefore, the total time for one pass is assumed to be 1 hour and 15 minutes. The average rate of water spray is estim

Spray Rate = (0.784 L/m2)(1,000 ml/L)(cm3/ml)(1,000 mm/m) = 0.6272 mm/hr 

(100 cm/m)3(1.25 hr) 

The average hourly daytime evaporation rate is approximately 0.25 mm/hr. Therefore, the water spray rate is approxievaporation rate. Since the total time required for water spray (1.25 hour) times 2.5 is approximately 3, a model assum

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

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

5. Baseline rain and surface water run-on/run-off controls (landfills only) The cost estimates assume that stormwater run-on/run-off control is comprised of a ditch surrounding active area of l

bermed basin for water collection. 6. Baseline financial assurance for CCR disposal unit closure and post-closure care Financial assurance helps assure that the owners and operators of CCR landfills and impoundments have adequately p

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

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

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

costs from being passed from the current generation to future generations.  The cost estimate includes the costs for selecting a financial mechanism, establishing a financial test, and esta

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

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

letter of credit is estimated to be 1% to 3% of the nominal value of the letter of credit (i.e., total cost of closure anapplied the 2% midpoint of this range. Implementation costs are estimated on the assumption that an outside con

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

dollars). Estimate obtained from Mohammad Iqbal and John Collier, ICF, Inc., “Local Government Financial Te
memorandum to George Garland, EPA, 30 April 1995. Additional supporting information obtained from EPA “EEconomic Benefits of RCRA Noncompliance,” September 1997. 

7. Baseline siting/location restrictions Baseline cost not estimated in this RIA. 8. Baseline closure capping to cover unit The cost estimate for this engineering control does not include the closure plan cost or closure certification costs. Cacapital expense. So, if a unit is expected to close in one year the total capping cost is assigned to the last year in the l

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

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

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

a final rule. This RIA assumes the same requirements for both landfills and impoundments: 

 Synthetic cap with drainage layer is comprised of a 60 mil HDPE synthetic liner, 1 foot sand, filter fabric, 1.5 foot s

foot topsoil, and vegetation. It includes a perforated pipe for drainage collection. 

 Synthetic cap without drainage layer is comprised of a 60 mil HDPE synthetic liner, 1.5 foot slope and earth fill, 0.5 

vegetation. 

 Clay cap is comprised of 2 feet of off-site clay, 0.5 foot topsoil, and vegetation. Cover costs would be lower if on-s

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

clay is available. 

 Soil cap is comprised of a 1.5 foot slope and earth fill, 0.5 foot topsoil, and vegetation. The slope of the cap is assum

with a cover toe slope of 4:1 (run:rise). 

9. Baseline post-closure groundwater monitoring requirements 

 Same requirements for both landfills and impoundments  Baseline post-closure monitoring is assumed to comprise 30 years of groundwater monitoring and surface water mo

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

above in this section of the RIA. 

 However, post-closure monitoring costs are estimated in this RIA assuming an annual sum is placed in a fund by aff

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

10. Baseline storage tank/container design and operating standards Baseline cost not estimated in this RIA 
• Baseline “Ancillary Costs” Estimates 

11. Baseline offsite disposal The baseline cost for engineering controls at offsite CCR disposal sites (assumed in this RIA to be commercial Subtit

using the same cost model as the engineering controls for onsite disposal units. In addition, the offsite disposal baselfor truck transport from the electric utility plant to the offsite landfill, calculated as follows:  Baseline Assumptions: 

o 12% (15 million tons/year) CCR currently trucked offsite to non-haz LFs (2005) o 6 miles average one-way trucking distance to offsite LFs38

o $0.10/ton/mile non-haz waste truck operating cost o 12 tons CCR per full truckload (source: Gambrills MD case study); (15 million tons/year) / (12 tons/load) 

per year 

 Baseline Cost Calculations: 

o Manifest cost: $0 o Trucking cost: (15 million tons/year) x (6 miles) x ($0.10/ton/mile truck operating cost for non hazmat) = 

12. Baseline structural integrity inspections Assumptions: Baseline assumption is that 82% of CCR disposal units at electric utility plants are inspected (source: page 36 of joint 

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

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

Cost Calculation: Industry cost: ($10,829/year per facility) x (82% inspected) x (495 plants) = $4.40 million per year State government cost: ($599/year per facility) x (82% inspected) x (495 plants) = $0.24 million per year 

Total (industry + state) = $4.64 million per year 

38 Source: based on actual distance reported for a MD plant at http://www.rachel.org/en/node/445). Note: a broader range of 2.4 miles to 25 

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

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

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

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

Industry Costs 

1 Impoundment Safety Plan prepared by mining company engineer 

>>> Purpose: To evaluate geotechnical, hydrologic, hydraulic & other engineering factors to construct or improve surface impoundment structures to 

avoid structural failures 

1,300 $70.07/hr 

2 Revisions to Impoundment Safety Plan prepared by mining company engineer2 40 $70.07/hr 3 Fire Extinguishing Plan prepared by mining company engineer or supervisor 20 $70.07/hr 4 Annual Status Report & Annual Certification prepared by company engineer 

>>> Purpose: To determine whether impoundments are operated and maintained according to approved engineering safety plan 

2 $70.07/hr 

5 Recordkeeping and weekly inspections3 

>>> Purpose: To determine whether any signs of instability have developed 

2.5 hrs per inspectn x 17 inspect = 42.5 

$30.27/hr 

Subtotal (Industry costs): 

State Government Costs 

6 Review of Impoundment Safety Plans 160 hrs tech review + 

2 hrs admin review 

$30.57/hr 

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

2 hrs admin review 

$30.57/hr 

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

Subtotal (State government costs): 

Total Cost 

Total industry + state government cost: 

Notes: * Elements, labor hours, and labor costs are based on the “Supporting Statement” for the March 2008 DOL/MSHA ICR 12-19-0015, “RefuStructures, Recordkeeping, and Reporting Requirements” at: http://www.msha.gov/regs/fedreg/paperwork/2004/04-24046.pdf 1. Assumes plans are valid for 10-years similar to the length of RCRA permits. 2. Assumes one revision to the plan will be made during 10-years. 3. Average labor hours per inspection between inspections at sites with monitoring instruments (3 hours) and at sites without monitoring in

13. Baseline RCRA facility-wide investigations (RFI) Baseline cost assumed to be $0 because this RIA assumes that all baseline CCR disposal units used by electric utility 

under RCRA Subtitle C. 
14. Baseline facility-wide corrective action Because CCR is not regulated as Subtitle C hazardous waste, there are no existing facility-wide (i.e., CCR disposal un

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

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

corrective action requirements: 

o AZ, IN, and IA establish a corrective action alert level and response action in site-specific state permits o CO requires corrective action for new units o 9 states (FL, GA, KY, MI, NC, ND, PA, UT, WI) require corrective action 

o IL, MN, TX, WV, WY do not allow groundwater degradation, but specific enforcement mechanisms are not 

regulations 

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

o NM requires an abatement plan. 

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

o AZ establishes corrective action alert level and response action in site-specific state permits o 15 states (CO, FL, GA, IL, KY, MI, NC, ND, OH, OK, PA, UT, WV, WI, WY) require corrective action o MN, TX do not allow groundwater degradation, but, specific enforcement mechanisms are not specified in s

o MO, TN require assessment only 

o NM requires an abatement plan 

15. Baseline waste disposal permit cost 

• Assumptions: 

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

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

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

• Industry waste disposal permit cost: 

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

impoundment or landfill) = $80,000 per Subtitle C permit 

o Assume RCRA Subtitle D (40 CFR 257, 258) waste permitting activities are less burdensome than RCR

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

Subtitle D (40 CFR 257, 258), assume Subtitle D permitting costs are lower by the 3.3 factor: ($80,000 per year average Subtitle C waste disposal permit cost) / (3.3) = $24,300 per non-haz waste dis

[((93% landfills w/permit) x (337 landfills)) + ((12% impoundments w/permit) x (158 impoundments))] $8.1 million 

 Amortized industry cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $
• State government waste disposal permit cost: 

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

Subtitle C waste disposal permits:39

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

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

o Assume RCRA Subtitle D (40 CFR 257, 258) waste permitting activities are less burdensome than RCR

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

Subtitle D (40 CFR 257, 258), assume Subtitle D permitting costs are lower by the 3.3 factor: ($58,200 per year average Subtitle C waste disposal permit cost) / (3.3) = $17,600 per non-haz waste dis

o State Cost Calculation: 

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

 Total baseline permit cost (industry + state government) = $1.01 million per year 16. Baseline enforcement inspection Not estimated in this RIA. 17. Baseline remediation of environmental releases Not estimated in this RIA. 

39 Source: Based on cost data from page 84 of January 2007 ASTSWMO report “State RCRA Subtitle C Core Hazardous Waste Managemen

Costs Final Report” at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20C
• Baseline CCR Disposal Cost Estimation Results 

Exhibit 3D below displays the average annualized costs for each of the baseline cost components, as well as on an av

plant basis. Appendix G provides plant-by-plant and owner entity-by-entity estimates of baseline costs. 

Exhibit 3D 

Industry Baseline Cost Estimates for CCR Disposal by Electric Utility Plants (Onsite + Offsite) 

($millions per year in 2009$ discounted @7% over 50-year period-of-analysis 2012 to 2061) 

Baseline Cost Element CCR Landfills (311 plants) CCR Impoundments (158 plants) Row 

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

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

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

Subtotal Ancillary costs = $1,196 $2.5 

Cost Summary (A+B) 

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

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

Average cost per CCR ton disposed = $59 per ton 

(71.8 million tons per year) 

$59 per ton 

(22.4 million tons per year) 

(94.2 

* Note: For purpose of validity check, in comparison to the baseline cost estimate in this Exhibit above, the 2005 DOE-EIA Form 767 dataindicates $5,890 million in annual capital and O&M cost reported by steam electric plants with nameplate capacity of 100 MW or greater, for water pollution, (b) $0.193 million for solid waste, (c) $0.185 for other pollution, (d) $3,627 million capital expense for air pollution abmillion for collection and disposal O&M costs for fly ash, bottom ash, and FGD. The $1,546 million is only 28% of the estimate in this EDOE-EIA Form 767 cost data are associated with 179 coal-fired plants, which represent only 36% of the 495 coal-fired electric utility plan
3B. Baseline Economic & Environmental Benefits of CCR Beneficial Use According to CCR beneficial use market data compiled for year 200540 as displayed below in Exhibit 3E, and extrap

as displayed in Exhibit 3F below, 62 million tons of annual CCR generated by 272 of the 495 electric utility plants is 

beneficially used as material substitutes in at least 14 industrial applications. The purpose of this section is to provicategories of baseline benefits associated with baseline CCR beneficial use: 

1. Economic benefits: Baseline economic benefits are based on the entire annual tonnage of CCR benefici2. Environmental benefits: Baseline environmental benefits are only based on the three categories of encapsula

(i.e., concrete, cement, and wallboard representing a sub-total of 58% of all CCR beaddressed in a secondary study used as a reference in this section of the RIA. 

The economic benefits estimated in this section are based on recent market prices. However, environmental benefit

study which applied a “lifecycle analysis” (LCA) methodology which involves estimating both internalized and exter

impacts: 

“Life cycle analysis depicts the production of materials in a system of complex physical outcomes, and can princremental physical consequences of a change in material inputs, technology, waste management practices, In LCA, as in reality, one change in the physical system, such as the substitution of fly ash for virgin Portland 

corresponding cascade of economy-wide impacts and shifts. As inputs are substituted, technologies, physical 

exposure pathways change. Using a range of modeling platforms and life cycle inventories to calculate the owith each incremental change, LCA calculates the net result of all of these interactions, capturing the total ina change in operations on physical environmental impacts such as air emissions, and energy and water use.” 

• Economic Benefits of CCR Beneficial Use 

As estimated in Exhibit 3E below (Column F), CCR used for beneficial use applications has an estimated annual US million per-year based on annual CCR sales revenue data supplied by 233 electric utility plants to the 2005 EIA-767 RIA to 2009. Based on comparison with the average higher prices for substitute industrial materials, using lower-pric

national economy with $2,300 million in annual net cost savings compared to the higher $2,477 million annual cost o

these 14 industrial applications (see Column I of Exhibit 3E). 

40 Source: EPA Office of Solid Waste “Waste and Materials-Flow Benchmark Sector Report: Beneficial Use of Secondary Materials – Coal 

Report, EPA report nr. 530-R-08-003, prepared by Industrial Economics Inc., 95 pages, 12 Feb 2008 at: http://www.epa.gov/osw/partnershipThe beneficial use market data cited in this source is summarized from the American Coal Ash Association (ACAA) 2005 national survey of 
Exhibit 3E 

Estimate of Annual Materials Cost Savings Benefit of CCR Generated by the Electric Utility Industry for Beneficial Use in I

A B C D E F (C x E) G 

Item Industry Application 

2005 CCR 

beneficial use 

(million tons) 

% of CCR 

beneficial use 

market 

Average market 

price paid electric 

plants* 

($/ton) 

Implied annual CCR 

sales revenues to 

electric utility plants 

Average price 

for substitute 

material 

($/ton) 

Im

m

1 Construction concrete ingredient 

NAICS code 3273 

See 1A + 1B See 1A + 1B See 1A + 1B See 1A + 1B See 1A + 1B S

1A Direct ingredient: substitute for portion 

of portland cement ingredient in concrete mfg NAICS code 3273 

16.35 33.0% $0 to $45 $0 to $735.8 million $80 $

1B Indirect ingredient: raw feed blended 

with limestone or shale to make cement clinker to be ground into cement for concrete mfg NAICS code 3273 

4.22 8.5% $0 to $45 $0 to $189.9 million $80 $

2 Construction structural fill for building 

foundations and embankments NAICS code 238910 

8.35 16.8% $1 $8.35 million $3 $

3 Construction wall board 

NAICS code 327420 

8.18 16.5% $0 to $8 $0 to $65.4 million $4.5 to $12 $

4 Waste stabilization (substitute for lime) 

NAICS code 5622 

2.84 5.7% $15 to $25 $42.6 to $71.0 million $66 $

5 Blasting grit 

NAICS code 212322 

1.63 3.3% Not reported Not reported Not reported N

6 Roofing granules 

NAICS code 324122 

Included with 

grit (row 5) 

Included with 

grit (row 5) 

Not reported Not estimated Not reported N

7 Other minor uses (n=7)** 8.04 16.2% $3 to $20 $24.1 to $160.8 

million 

$5 to $83 $4

Column totals (2005) = 49.61 100% 

Implied 

average (F/C) 

= $3 

$75 to $1,231 million 

(best estimate  = 

$149 million) 

Implied 

average (H/C) 

= $40 

$

(b

$1

2009 updated estimates = 62.09** * $177 million $

Explanatory notes: Source: Data in columns C, E, and G are from “Waste and Materials-Flow Benchmark Sector Report: Beneficial Use of Secondary Materials 

EPA report nr. 530-R-08-003, prepared by Industrial Economics Inc., 95 pages, 12 Feb 2008 at http://www.epa.gov/osw/partnerships/c2p2/p

* Average price includes “free on board” (FOB) shipping and insurance costs paid by the supplier from the point of manufacture to a specifie** Other minor uses include: (1) agricultural soil amendment for flue gas desulfurization gypsum, (2) road base foundation layer underlying mine reclamation material as substitute for soil, (4) mineral filler in asphalt, (5) soil stabilizer, (6) snow and ice control substitute for sand, an

*** 2009 update estimated tonnage (Column C above) derived in Exhibit 3F of this RIA; 2009:to2005 multiplier = 62.09/49.61 = 1.25. **** “Best estimate” in Column F based on sum of coal-fired electric plant CCR “byproduct sales revenues” from the DOE-EIA F767_PLA

 “Best estimate” in Columns H and I derived by numerical interpolation of the ranges displayed based on the proportionate best estimate 
Exhibit 3F 

Estimate of 2009 CCR Beneficial Use Quantity (Short Tons) 

A. Actual Data: 

Year 

CCR Beneficial Use* 

(tons per year) % change % Use Linear Regression Output 

Actual = 2001 37,119,321 R-Squared 0.915 Actual = 2002 45,523,256 22.6% 35% Standard Error 1,990,394 Actual = 2003 46,384,405 1.9% 38% Observations 7 Actual = 2004 49,089,818 5.8% 40% CoefficientActual = 2005 49,612,541 1.1% 40% Intercept (5,487,554,7Actual = 2006 54,203,170 9.3% 43% X Variable 2,762,393 Actual = 2007 56,039,005 3.4% 43% 

* Source: Amer. Coal Ash Assoc http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenb

B. Trendline: Year Regression best fit % change 

Trendline = 2001 39,994,500 Trendline = 2002 42,756,900 6.9% Trendline = 2003 45,519,300 6.5% Trendline = 2004 48,281,600 6.1% Trendline = 2005 51,044,000 5.7% Trendline = 2006 53,806,400 5.4% Trendline = 2007 56,568,800 5.1% Trendline = 2008 59,331,200 4.9% Trendline = 2009 62,093,600 4.7% 

Annual average growth rate = 5.7% 

CCR Beneficial Use (2001-2009)

30,000,00035,000,00040,000,00045,000,00050,000,00055,000,00060,000,00065,000,00070,000,000

2001 2002 2003 2004 2005 2006 2007 2008 200

Year

Tons CCR Per Year

ACAA actual data Trendline
Exhibit 3G below presents a 2004 state-by-state summary of annual quantity of CCR beneficially used. 

Exhibit 3G 

State-by-State Summary of CCR Beneficial Use (2004*) 

A B C D E 

Item State 

2004 CCR 

generation 

(short tons) 

2004 CCR 

beneficial use 

(short tons) 

% CCR 

used 

beneficially 

1 AK 43,000 Not reported NR 2 AL 3,408,000 663,000 19% 3 AR 688,000 324,000 47% 4 AZ 2,764,000 1,161,000 42% 5 CA 50,000 0 0% 6 CO 1,548,000 252,000 16% 7 CT 181,000 0 0% 8 DC 0 0 NA 9 DE 121,000 24,000 20% 

10 FL 5,092,000 3,171,000 62% 11 GA 3,141,000 1,022,000 33% 12 HI 48,000 0 0% 13 IA 1,260,000 750,000 60% 14 1D 0 0 0% 15 IL 4,419,000 1,968,000 45% 16 IN 9,549,000 3,023,000 32% 17 KS 1,399,000 575,000 41% 18 KY 14,537,000 2,521,000 17% 19 LA 1,588,000 716,000 45% 20 MA 310,000 130,000 42% 21 MD 1,983,000 646,000 33% 22 ME 36,000 0 0% 23 MI 2,145,000 614,000 29% 24 MN 1,561,000 387,000 25% 25 MO 2,348,000 1,070,000 46% 26 MS 1,758,000 681,000 39% 27 MT 952,000 51,000 5% 28 NC 3,545,000 1,641,000 46% 29 ND 2,757,000 731,000 27% 30 NE 469,000 299,000 64% 31 NH 141,000 57,000 40% 

A B C 

Item State 

2004 CCR 

generation 

(short tons) 

20

ben

(sh

32 NJ 600,000 33 NM 3,668,000 34 NV 825,000 35 NY 1,379,000 36 OH 6,980,000 37 OK 1,277,000 38 OR 95,000 39 PA 9,545,000 40 RI 0 41 SC 2,172,000 42 SD 105,000 43 TN 3,803,000 44 TX 12,943,000 45 UT 2,341,000 46 VA 2,442,000 47 VT 0 48 WA 2,301,000 49 WI 1,437,000 50 WV 7,220,000 51 WY 2,106,000 

 Totals = 129,001,000 

Notes: * Source: DOE & EPA, “Coal Combustion WLandfills and Surface Impoundments 1994-22006, page 5 (Table 1) at: http://www.ead.anl.gov/pub/doc/coal_waste_

In comparison, the ACAA reports that a 5% 122,465,119 tons CCR was generated in 200

usa.org/associations/8003/files/2004_CCP_S
• Environmental Benefits Associated with CCR Beneficial Use 

From a materials lifecycle analysis perspective, CCR beneficial use generates net environmental benefits. Based on a 

two of the 14 CCR beneficial use industrial applications (i.e., concrete and wallboard) there are 12 environmental benannual magnitudes estimated below in Exhibit 3H. This estimate of environmental benefits is based on only 47% (i.

the 49.62 million tons for the 2005 CCR beneficial use market as reported in that 2008 study. Thus, these estimates m

environmental benefits of CCR beneficial uses. These net benefits are not additive to the economic benefits, but enco

Exhibit 3H 

Baseline Environmental Benefits from Current Beneficial Use of CCR

A B C D 

Item Environmental impact indicator 

Estimated* annual environmental impact 

savings for 47% of CCR beneficial use tonnage 

(47% = 23.2 million tons in 2005) 

Unit values** for monetizing 

environmental impacts 

(updated to 2009$) 

A. Resource Consumption Savings 

1 Energy consumption 158 trillion BTU energy savings $0.00003093 per BTU 2 Water consumption 32.1 billion gallons water savings $0.0025259 per gallon 

 Subtotal (1+2) = 

B. Air Pollution Savings 

3 GHG - greenhouse gas emissions 

(carbon dioxide + methane) 

11.5 million metric tons CO2 equivalent emissions avoided 

$5.20 to $58.23 per metric ton 

(midpoint = $31.71 per metric ton) 

4 CO – carbon monoxide 9,200 metric tons emissions avoided Not Monetized 5 NOx – nitrous oxides 30,400 metric tons emissions avoided $10,255 per metric ton 6 SOx – sulfur oxides 23,900 metric tons emissions avoided $62,375 per metric ton 7 PM – particulate matter 9,704 metric tons emissions avoided $486,312 per metric ton 8 Particles Unspecified 26,200 metric tons emissions avoided $486,312 per metric ton 9 Hg - mercury 0.584 metric tons emissions avoided $186,067 per metric ton 

10 Pb - lead 0.656 metric tons emissions avoided $186,067 per metric ton 

 Subtotal (3 to 10) = 

C. Other Environmental Impact Savings 

11 Waterborne wastes 2,446 short tons waste generation avoided 

(SM + BOD + COD + Cu + Hg + Pb + Se) 

Not Monetized 

12 Non-hazardous waste 27,991 short tons waste generation avoided Not Monetized 

Total all impacts (1 to 12) = 

41 Source: Exhibit 5-3 of “Waste and Materials-Flow Benchmark Sector Report: Beneficial Use of Secondary Materials – Coal Combustion P

Industrial Economics Inc for the EPA Office of Solid Waste, 12 Feb 2008, 95 pages at http://www.epa.gov/osw/partnerships/c2p2/pubs/benu
Exhibit 3H (continued) 

Baseline Environmental Benefits from Current Beneficial Use of CCR

Notes: * Column C: Environmental impact estimates displayed above in Column C are based on only two of the 14 beneficial use industrial apmillion tons per year fly ash CCR used in concrete, plus 8.2 million tons per year FGD CCR used in wallboard). These estimates are frof “Waste and Materials-Flow Benchmark Sector Report: Beneficial Use of Secondary Materials – Coal Combustion Products,” preparEconomics Inc for the EPA Office of Solid Waste, 12 Feb 2008; available at http://www.epa.gov/osw/partnerships/c2p2/pubs/benuse07

report does not provide environmental impact estimates for the other 12 beneficial use industrial applications. ** Column D: Unit values applied for monetization are from the following sources: 

A. Row 1 & Row 2: 2007 values from Exhibit 5-3 (page 5-6) of the Industrial Economics Inc reference report. Unit values updated 

2009 using NASA’s Gross Domestic Product Deflator Inflation Calculator at http://cost.jsc.nasa.gov/inflateGDP.html

B. Row 3: 2007 unit value range of $5 to $56 from the 2007 column of Table III.H.6-3, page 29617 of the EPA and DOT-NHTSA “

Establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards,” Federal R

186, 28 Sept 2009. For this RIA the range was updated from 2007 to 2009 dollars using NASA’s Gross Domestic Product Deflahttp://cost.jsc.nasa.gov/inflateGDP.html 

C. Rows 4-10: Unit values from the report “The Influence of Location, Source, and Emission Type in Estimates of the Human Heal

Ton of Air Pollution” by Neal Fann, Charles Fulcher and Bryan Hubbell, in Air Quality, Atmosphere & Health, Volume 2, No.3

176. The dollar values from this report were updated from 2006 to 2009 using NASA’s Gross Domestic Product Deflator Inflatihttp://cost.jsc.nasa.gov/inflateGDP.html 

D. Rows 12-13: Waterborne wastes and non-hazardous waste were not monetized in the Feb 2008 EPA/Industrial Economics Inc. re

for Column C. 
Chapter 4 

Estimated Cost for RCRA Regulation of CCR Disposal 

4A. EPA’s Prior Cost Estimates for Possible RCRA Regulation of CCR Disposal at Electric UEPA’s Office of Solid Waste (OSW, which EPA renamed as the ORCR effective 18 January 2009), formulated the focompliance cost estimates for different RCRA-based regulatory approaches to CCR disposal by the electric utility ind1988: OSW's 1988 Report to Congress on CCR estimated $2.4 billion to $4.7 billion per year (1986$) in potential a

industry cost (514 plants in 1984) for compliance with technical standards contained in 40 CFR 264 RCRA Suregulations. The range reflects different liner assumptions (i.e., single versus double liners) and whether only 

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

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

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

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

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

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

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

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

Source: EPA OSWER report nr. EPA 530-R-99-010, March 1999. 

2005: In a November 2005 report, an OSW contractor (DPRA Inc) estimated $304 million to $521 million per year 

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

criteria such as cover material, dust control, run-on/run-off control, (c) design criteria such as liner and leachagroundwater monitoring, (e) closure and post-closure standards, and (f) financial assurance for closure, post-caction. This estimate accounted for state CCR management requirements as of 2004, but did not include costs 

Source: EPA-OSWER document ID nr. EPA-HQ-RCRA-2006-0796-0469 at http://www.regulations.gov. 

These three prior RCRA regulatory cost estimates range from $304 million to $4.7 billion per year. Even without up

estimates to the current 2009 price level, all three prior cost estimates exceed the 1993 Executive Order 12866 Sectiosignificant” $100 million annual effect threshold for Federal rulemakings. 
4B. Regulatory Options Evaluated in this RIA This RIA evaluates the potential impacts of three options (labeled in this RIA as Option 1, Option 2, Option 3) for re

consisting of EPA’s preferred option (i.e., Option 1 below) identified in the Federal Register notice for the CCR prop

alternative options (i.e., Option 2 and Option 3 below). These options were initially identified in the EPA-OSWER 1Combustion Residue Regulation” early guidance/options selection briefing for EPA Administrator Lisa Jackson, and (i.e., Option 1) was selected in her 13 July 2009 “Early Guidance/Options Selection” memo to EPA’s CCR rulemakinto these main options, this RIA evaluates the land disposal treatment standard as a sub-option potentially applicable to Evaluation of three regulatory options is consistent with OMB’s 2003 “Circular A-4: Regulatory Analysis” best pract

agencies.42

All regulatory options are identical in two ways: 

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

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

2009 Early Guidance/Options Selection memo (item 2, page 2) stipulated that beneficial uses of CCR will retaand will not be subject to any regulation, either under Subtitle C or Subtitle D. 

2. Engineering controls: All options propose the same set of nine custom-tailored engineering controls (i.e., te

operating standards) for CCR disposal units. 

a. For purpose of launching this RIA in March 2009, the waste disposal “management standards” describ

cement kiln dust (CKD) proposed rule43 were used in absence of uniquely defined controls specific to 

was a reasonable starting point because the CKD management standards are similar or identical to the 

defined in the CCR proposed rule. 

b. Existing CCR landfills and impoundments are assumed to be exempted (“grandfathered”) from the bo

collection requirements of these controls. 

c. Otherwise all engineering controls apply to future newly constructed units. 

The main differences between the options are their respective RCRA legal authorities and types of CCR disposal unit

Option 1: Subtitle C (Preferred Option): 

• Regulate CCR disposal as RCRA Subtitle C “K179” listed hazardous waste. Subtitle C pro

enforceability. 

42 Page 16 of OMB’s 2003 Circular A-4 directs Federal agencies to analyze at least three options: http://www.whitehouse.gov/omb/assets/om43 EPA’s 20 August 1999 CKD proposed rule (Federal Register, 67 pages) is available at http://www.epa.gov/osw/nonhaz/industrial/special/
• Use RCRA 3004(x) authority to custom-tailor engineering controls (i.e., technical standard

The following excerpt from Use RCRA Section 3004(x)44authority to custom-tailor engine

technical standards) for CCR disposal units. 

Option 2: Subtitle D: 

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

treatment standards as Option 1. 

• Except under RCRA Section 7003 substantial endangerment authority, this option is not Fede

RCRA Subtitle D directs EPA only to assist state governments under Subtitle D.45

Option 3: Hybrid C&D: 

• Regulate wet CCR disposal (impoundments) same as Option 1 and dry CCR disposal same a

Sub-option: Subject CCR to land disposal treatment standards prior to disposal: 

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

• Wet CCR (impoundments): Dewatering and dry disposal within 5 years after rule’s effective 

In addition to the above options, the Federal Register notice for the proposed rule presents two other regulatory appro

in August 2009. One of the approaches is the same as Option 2 but egregious violators would be regulated under Opt

approach is the same as Option 2 in states which develop in 2-years an implementing program but the same as Option 

Because both approaches are hybrids of Option 1 and Option 2, they are not separately evaluated in this RIA because 

expected to fall between the impacts of Option 1 and Option 2 as estimated in this RIA. 

44 The following excerpt from RCRA Section 3004(x) pertains specifically to CCR, by providing EPA with authority “to modify” the RCRA 

for regulation of CCR disposal: “Section 3004(x): If... (2) fly ash waste, bottom ash waste, slag waste, and flue gas emission control waste generated primarily from the cofuels... is subject to regulation under this subtitle, the [EPA] Administrator is authorized to modify the requirements of subsections (c), (d), 

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

difficulties associated with implementation of such requirements, and site-specific characteristics, including but not limited to the climate, gechemistry at the site, so long as such modified requirements assure protection of human health and the environment.” 

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

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

governments and private industry.” 
4C. Regulatory Cost Estimation Algorithms & Results

This section presents incremental cost estimates for each regulatory option, for both existing active (i.e., operating) landfills and impoundments, and by size/type of affected electric utility plant owner entity. Incremental comparison o

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

Analysis” best practices guidance to Federal agencies: 

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

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

As listed below, this RIA estimates 18 potential regulatory costs and the land disposal treatment standard sub-option, same unit cost data sources and the same framework (i.e., 2009 price level, 50-year period of analysis, etc.), identified 

this RIA for baseline cost estimation. According to three methodological groupings, this RIA estimates three categor

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

1. Ground water monitoring 2. Bottom liners – for future new units only 3. Leachate collection system – for future new units only 4. Dust controls – applicable to landfills only 5. Rain and surface water run-on/run-off controls – applicable to landfills only 6. Financial assurance for disposal unit closure and post-closure 7. Location/siting restrictions (6 types: water tables, floodplains, wetlands, fault areas, seismic zones, karst ter8. Closure capping to cover unit 9. Post-closure monitoring requirements 10. Temporary storage requirements – not estimated in this RIA because do not have information on the b

conditions of CCR storage tanks and storage buildings at electric utility plants. 

B. Ancillary costs for CCR disposal – estimated outside of the engineering control cost model: 

11. Offsite disposal (hazmat trucking, RCRA manifesting, offsite RCRA TSDF permits) 12. Structural integrity inspections – impoundments only 13. RCRA facility-wide investigation (RFI) 14. RCRA facility-wide corrective action 

15. RCRA TSDF hazardous waste disposal permits for onsite disposal 16. RCRA enforcement inspection 17. Cleanup remediation of future CCR impoundment failures as RCRA hazardous waste 18. EPA administrative reporting & recordkeeping 
C. Sub-option: Land disposal treatment standards – may be applied to any of the regulatory options: 

o Dry CCR disposal (landfills): Moisture conditioning and compaction included in engineering control coo Wet CCR disposal (impoundments): Estimated outside and separately of the engineering controls cost m

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

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

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

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

(GDP) threshold identified in OMB’s 1995 guidance46 for attempting to measure such other economic effects for pur

analysis compliance. Based on the 2008 US GDP of $14.42 trillion,47 the 0.25% to 0.5% threshold is equal to $36 bi

4C.1 Regulatory Cost to Industry for RCRA “Engineering Controls” This RIA assumes that that same set of RCRA 3004(x) custom-tailored engineering controls is required under each o

the costs for engineering controls for all regulatory options are mostly, but not entirely, based on the same cost estimaabove in Chapter 3 for estimation of baseline engineering control costs. Furthermore, this RIA assumes that the engin

similarly specified in EPA’s cement kiln dust 20 August 1999 proposed rule.48 This assumption was required to laun

2009 prior to the initial draft of the CCR proposed rule itself. This RIA assumes that liners and leachate collection sy

only to future new CCR landfills and impoundments. Offsite disposal costs are assumed unaffected under all regulatCCR disposal units are assumed to be commercially-owned units (i.e., owned by the waste management industry) and 

compliance with the custom-tailored engineering controls. For engineering controls added to existing units the costs years of the lifespan of the landfill or impoundment. 1. Regulatory groundwater monitoring cost Same cost estimation formula applied above in Chapter 3 for baseline cost estimation. 2. Regulatory bottom liner cost Same cost estimation formula applied above in Chapter 3 for baseline cost estimation. 

46 Source: Section 4.B(3) of OMB’s 31 March 1995 guidance for implementing the UMRA (http://www.whitehouse.gov/omb/memoranda_1

would note that such macro-economic effects tend to be measurable, in nation-wide econometric models, only if the economic impact of the to 0.5 percent of Gross Domestic Product. A regulation with a smaller aggregate effect is highly unlikely to have any measurable impact in m

is highly focuses on a particular geographic region or economic sector.” 

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

Report of the President at http://www.gpoaccess.gov/eop/tables09.html 

48 Federal Register, Vol.64, No.161, 20 Aug 1999, pp.45632-45697. 
3. Regulatory leachate collection cost Same cost estimation formula applied above in Chapter 3 for baseline cost estimation. 4. Regulatory fugitive dust control cost Same cost estimation formula applied above in Chapter 3 for baseline cost estimation. 5. Regulatory financial assurance cost Same cost estimation formula applied above in Chapter 3 for baseline cost estimation. 6. Regulatory closure costs Same cost estimation formula applied above in Chapter 3 for baseline cost estimation. 7. Regulatory siting/location restriction costs This cost element is estimated outside of the engineering controls cost model, using the factors, data and calculations 

• Count of Existing Electric Plants Which May be Affected by Siting Restrictions 

To estimate the potential cost of siting restrictions, this RIA conducted a GIS analysis to determine which facilities mrestrictions. As summarized below, the GIS analysis was conducted for three of the six possible site restrictions (i.e., 

datasets pertaining to fault areas, seismic zones, and karst zones readily available to EPA-ORCR at the 2009 launch olimitation potentially results in under-estimation in this RIA of the number or electric utility plants which may be affe

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

estimating the potential cost of this regulatory element is over five-times higher than the $0.75 million49 cost per-plan

another study for siting restriction mitigation involving karst mitigation and floodplain/wetland mitigation; this proba

possible cost underestimation in this RIA for this regulatory element. 

The GIS was based on the DOE-EIA eGRID database to identify the geographic coordinates for 491 of the 495 

(disregarding four plants not present in the eGRID database). Appendix H of this RIA presents site location data for used in the GIS analysis. In order to geographically capture both the facilities and their waste units, and to compensaexists uncertainty as to the exact facility location versus the reported geographic coordinates (i.e., depending on whet

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

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

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

landfills that could reasonably be considered on-site. 1. Water table restrictions: GIS analysis not conducted for this site restriction 

2. Floodplain restrictions: GIS analysis not conducted for this site restriction 

49 Source: $0.75 million siting restriction mitigation cost for a single electric utility plant is from page 10 (slide number TVA-00007496) of “

Matrix: Pond or Peninsula?,” 27 Jan 2005 Plant Managers Conference Room at http://www.tva.gov/kingston/tdec/pdf/TVA-00007487.pdf 
3. Wetlands restrictions: GIS analysis not conducted for this site restriction 4. Fault area restrictions To identify fault zones, used the USGS database, “Quarternary Fault and Fold Database for the United States,” which 

location data on faults and associated folds.50 This analysis identified plants including their buffers which fall within 

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

• 1-mile buffer: 1 plant falls within 200 feet of a fault line. • 3-mile buffer: 3 plants fall within 200 feet of a fault line. (these three plantss are located in NV and UT). 

It is important to note that this preliminary analysis has certain limitations and may not capture facilities in other areAccording to the USGS fault line database, no relevant faults are located in the central and eastern US. The USGS description that this absence of identified faults with movement in the central and eastern US is partly a real phenomUS has more tectonic activity, but that it is partly a detection problem caused by geological characteristics present in US, such as glacial sediments, that conceal evidence of movement along faults. For this reason, the analysis of seisare defined based on the likelihood of future seismic activity, may represent a more reliable estimate of the number affected by fault area restrictions.53

5. Seismic zone restrictions: To identify seismic zones, we used USGS National Seismic Hazard Maps, which gives peak horizontal acceleration a

exceedance in 50 years.54 To run the seismic impact zone analysis, we identified those facilities, including their buff

the seismic impact zones that have a 10% or greater probability of exceeding a maximum horizontal acceleration of 1(i.e., 0.10 g) in 250 years.55 The USGS data we used gives probabilities of exceedance over 50 years; thus we used a 

probability of exceedance, and assumed that this equates to a 10% probability of exceedance in 250 years. 

• 1-mile buffer: 151 plants fall within seismic zones • 3-mile buffer: 152 plants fall within seismic zones 

6. Karst zone restrictions: 

This analysis used two databases: (1) DOE-EIA’s eGRID database to identify the geographic coordinates of 491 of t

(disregarding four plants that were not present in the eGRID database), and (2) the USGS's GIS database "Engineerin

50 US Geological Survey, 2006, “Quarternary Fault and Fold Database for the United States” at: http//earthquakes.usgs.gov/regional/qfaults. 51 RCRA defines “Holocene” as “the most recent epoch of the Quarternary period, extending from the end of the Pleistocene to the present” 52 Faults designated by the dataset as showing movement during the Holocene are not necessarily believed to have produced an earthquake o

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

53 The USGS data layer used for this analysis indicates that faults with Holocene movement are located only in states in the West and Southw

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

number of plants affected is not unexpected given the relatively small number of plants in these regions. However, the RCRA Practice Manuplants in CA and NV, and in parts of AK, AZ, CO, HI, ID, MT, NM, UT, WA, WY would be located within 200 feet of relevant faults. This plants (out of the 491 plants analyzed), if all facilities in the identified states may be affected by fault area restrictions.

54 U.S. Geological Survey, 2008, “National Seismic Hazard Maps,” from USGS website: http://gldims.cr.usgs.gov/nshmp2008/viewer.htm. 55 We used this threshold for seismic impact zones to be consistent with that used in RCRA’s municipal solid waste landfill location restricti
which provides national-scale data on karst coverage.56 Four types of karst areas are identified in the dataset: (a) lon

tubes, and caves over 1000 feet long and 250 feet deep); (b) short karst (fissures, tubes, and caves less than 1000 fee

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

• 1-mile buffer: 138 plants fall within karst zones • 3-mile buffer: 177 plants fall within karst zones These counts do not distinguish between the four different types of karst terrain identified in the data set; this analys

upper bound of potentially affected facilities. 

• Potential Cost for Existing & New Electric Plants to Meet Siting Restrictions 

According to the above findings for the three siting/location criteria evaluated in this RIA (i.e., fault areas, seismic z

maximum count of 177 plants could be affected (this is the upper-end of the affected plant counts across the three si

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

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

engineering measures have been incorporated into disposal unit design to mitigate the potential adverse impacts dispor be caused by, these six siting considerations. 

The cost to construct a berm is based on the cost to construct a 10-foot tall flood berm using US Army Corps of 

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

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

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

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

o Impoundment berms: The average surface impoundment size for existing units in the cost model is 34

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

feet. Therefore, the cost to construct a berm around an average-size impoundment is $4.3 million.57

o Landfill berms: Similarly, the average landfill size for existing units in the cost model is 278 acres. Ass

and that the berm would be constructed on three sides of the landfill (leaving one side open for truck acclength is 10,447 feet, and the cost to construct a berm surrounding an average-size landfill is $3.9 million

Using the 3-mile buffer karst zone finding of 177 plants, the potential cost for constructing berms at those plants plus 

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

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

56 U.S. Geological Survey, 1984, “Engineering aspects of karst,” from USGS website: http://pubs.usgs.gov/of/2004/1352. File used: karst.sh57 For purpose of comparison to the $4.3 million (per impoundment) and $3.9 million (per landfill) siting restriction mitigation cost estimates 

estimated an “assumed” cost of $500,000 for karst mitigation and $250,000 for floodplain mitigation for a potential new CCR disposal site imitigation. Extrapolation of TVA’s $750,000 cost estimate to 11,594 feet (impoundment) yields $6.7 million (i.e., (11,594 feet / 1,300 feet) feet (landfill) yields $6.0 million (i.e., 10,447 feet / 1,300 feet) x ($750,000)). Source for TVA cost estimate: page 10 of “Kingston Fossil Pl

Peninsula?”, 27 January 2005 Plant Managers Conference, http://www.tva.gov/kingston/tdec/pdf/TVA-00007487.pdf 
o New units: Apply 0.73% average annual growth rate in future CCR generation (cited elsewhere in this R

of future new or expanded disposal units over 50-years, and assume 36% (i.e., 177/495) will need berms

(495 existing disposal units) x (1.0073% growth rate)^(50 years) = 712 existing plus new units over 

(712 units over 50-years) – (495 existing units) = 217 future new disposal units (217 future new units) x (36% needing berms) x ($4.1 million average berm cost) = $318 million Amortized with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) =$23 million/y

 Average annualized berm cost for existing + new units = $76 m8. Regulatory closure cost Same cost estimation formula applied above in Chapter 3 for baseline cost estimation. 9. Regulatory post-closure monitoring cost Same cost estimation formula applied above in Chapter 3 for baseline cost estimation. 10. Storage design and operating standards for tanks, containers, and containment buildings Not estimated in this RIA due to lack of baseline information about the count and condition of these units at electric u

4C.2 Regulatory Ancillary Costs For estimating most of the “Other Ancillary Costs” in this section, this RIA distinguishes between RCRA Subtitle C a

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

government RCRA-authorized regulatory programs. 

11. Regulatory offsite disposal costs (hazmat trucking, RCRA manifests, RCRA TSDF permits for offsite) 

This pertains to Option 1 only. Assume that Subtitle C options add extra cost to (a) truck hauling to offsite disposal, must become RCRA Subtitle C permitted. This cost estimate does not include taxes/trans-state government fees asso

disposal. 

11a & 11b. added truck hauling cost (Option 1 only) 

Assumptions: 

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

• 6 miles average one-way trucking distance to offsite LFs58

58 Source: based on actual distance reported for a MD plant at http://www.rachel.org/en/node/445). Note: a broader range of 2.4 miles to 25 

distance was reported by an OH plant at http://www.columbusdispatch.com/live/content/local_news/stories/2008/04/14/Powerfills.ART_AR08_B1_FF9TI0U.html?sid=101, and a WI plant, respectively at http://www.lacrossetribune.com/articles/2007/09/21/news/03landfill0921.txt 
• $0.19/ton/mile hazardous waste truck operating cost • 12 tons CCR per full truckload (source: Gambrills MD case study); (15 million tons/year) / (12 tons/lotruckloads per year 

Cost Calculations: 

• 11a. Manifest cost: (1.25 million truckloads) x ($53 per manifest per load average cost from EPA 2007 

million per year • 11b. Trucking cost (distance + operating cost): (15 million tons/year) x (6 miles) x ($0.09/ton/mile add

for hazardous waste loads) = $8.1 million per year • Subtotal (11a manifest + 11b trucking): $74.1 million per year 

11c. Added cost for RCRA Subtitle C permits for all offsite CCR landfills under Subtitle C (i.e., Option 1 and Option 

Assumptions: 

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

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

• Industry average cost per waste disposal permit: 

($44059 average RCRA Part A permit application cost per-plant per-year) + ($68,96060 average RCRA 

per-facility per-year) = $69,400 per Subtitle C permit per year 

($69,400 per permit per year) x (3 years ICR annualization period) = $208,200 per permit (149 offsite CCR landfills) x ($208,200 per permit) = $31.02 million 

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

• State government average cost per waste disposal permit: 

Average cost for state government review of RCRA Subtitle C permits consists of four activities:61(1,215 pre-application activities) + ($27,063 application review) + ($26,846 permit issuance) + ($3,110 p$58,200 per permit 

 (149 offsite CCR landfills) x ($58,200 per Subtitle C permit) = $8.67 million  Amortized state cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $0.6

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

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

59 $440 unitized cost derived for this RIA from EPA Information Collection Request (ICR) No. 0262.12 “RCRA Hazardous Waste Permit A

Part A”, Federal Register, Vol.74, No.17, 28 Jan 2009, page 4958; http://edocket.access.gpo.gov/2009/pdf/E9-1804.pdf 

60 $68,960 unitized cost derived for this RIA from EPA Information Collection Request (ICR) No. 1573.12 “Part B Permit Application”, Fe

page 25237, 27 May 2009; http://edocket.access.gpo.gov/2009/pdf/E9-12285.pdf 

61 Source: Based on cost data from page 84 of January 2007 ASTSWMO report “State RCRA Subtitle C Core Hazardous Waste Managemen

Costs Final Report” at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20C
• Industry share of cost = $76.35 million per year • State government share of cost = $0.63 million per year • Total (industry + states) = $76.98 million per year 

12. Regulatory structural integrity inspection cost 

• Assumptions: 

Assume that the residual 18% of the non-inspected plants require inspection over the 82% baseline inspection covera

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

• Cost Calculation: 

Industry cost: ($10,829/year per facility) x (18% not inspected) x (495 plants) = $0.96 million per year 

State government cost: ($599/year per facility) x (18% not inspected) x (495 plants) = $0.054 million per year 

Total (industry + state) = $1.01 million per year 

13. Regulatory RCRA facility-wide investigation (RFI) cost 

• Industry RFI cost: • As of 2008, state government corrective action covers 64% of electric utility industry impoundments and 78% 

assume that 57 plants with impoundments (i.e., 36% x 158 plants with impoundments) plus 74 plants with landfil

with landfills) may require RFIs, for a total of 131 RFIs. • The purpose of an RFI is to obtain information to fully characterize the nature, extent and rate of migration of 

waste or constituents to determine whether interim corrective measures and/or a Corrective Measures Study may waste units at the facility (source: EPA 530/SW-89-031, May 1989, Vol.I). RFIs may include: rapid field screeni

instruments, drilling in soils, excavating test pits, ground-water monitoring, waste testing, biomonitoring, and site 

photography, site mapping. • RFI average cost: 

$0.75 million average cost for RFIs involving captive industrial landfills 

 $0.69 million average cost for RFIs involving captive industrial waste management (assume applies to impou

Source: EPA OSRE memorandum “Transmittal of Average Cost of Investigation Derived from Fund-Lead SuMeasures Cost Compendium, and Compendium of Related Guidance Documents”, 01 Nov 2004. This memo 

remedial investigation costs can be used as a proxy for RCRA RFI costs. Industry RFI cost calculations: 

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

Total = $94.8 million total cost to industry Amortized industry RFI cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $6.9 

• State government RFI cost: 
State government RFI review, approval, oversight average cost per RFI = $76,00062

(131 RFIs) x ($76,000 review, approval, oversight average cost per RFI to state governments) = $10 million total Amortized state government RFI cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = 

equivalent • RFI total cost (industry + state governments) = $7.6 million per year 

14. Regulatory RCRA facility-wide corrective action cost Average annualized future potential cost not estimated in this RIA because high degree of uncertainty. Through a pro

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

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

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

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

As of 2008 the RCRA corrective action universe is about 3,800 sites nationwide.66 Relative to the RCRA-reg

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

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

corrective action remedies usually involve mitigating damages to surface water and groundwater. The General Accou

reported67 that RCRA corrective action could cost 3,698 non-Federal hazardous waste treatment, storage, or disposal 

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

cost per-facility. Updated68 to 2009$ implies an average of $5.365 million RCRA corrective action cost per facility.

15. Regulatory RCRA TSDF waste disposal permit cost for onsite disposal RCRA Subtitle C hazardous waste regulations require hazardous waste treatment, storage, disposal facilities (TSDFs) as described in 40 CFR 270 consisting of a two-part (i.e., Part A and Part B) application process. The paperwork bur

62 Source: Divided the $2,200,600 annual RFI cost to 10 state governments by the 29 annual RFIs from page 82 of the January 2007 ASTSW

Subtitle C Core Hazardous Waste Management Program Implementation Costs Final Report” at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20Core%20Project.pdf 

63 Source: RACER unit cost reported on p.38 of EPA’s 2000 “Unit Cost Compendium” , document ID nr. EPA-HQ-RCRA-2002-0031-0429 64 Source: derived from cost data contained on page 83 of the ASTSWMO “State RCRA Subtitle C Core Hazardous Waste Management Pro

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

65 Source: “Corrective Measures Study Scope of Work”, EPA Region 3 at: http://www.epa.gov/reg3wcmd/ca/pdf/CMSATTC.pdf 66 Source: 3,800 corrective action cases represents EPA’s “2020 Corrective Action Universe” as identified on EPA Hazardous Waste Correc

website at: http://www.epa.gov/waste/hazard/correctiveaction/facility/index.htm#2020 

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

Accelerate Cleanups,” report nr. GAO/RCED-98-3, October 1997; http://www.gao.gov/archive/1998/rc98003.pdf 

68 Updated from 1996$ to 2009$ using the NASA “Gross Domestic Product Deflator Inflation Calculator” at http://cost.jsc.nasa.gov/inflateG
requirement is estimated below. Furthermore, but not included in the cost estimate below, are separate, additional RCcontaining “technical requirements” used by permit issuing authorities (e.g., RCRA-authorized state government wasRegional offices) to determine what technical requirements must be placed in permits. The separate cost of technical in the “Engineering Controls” regulatory cost section of this RIA above. 

• Assumptions: 

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

have such state permits, assume disposal units will need new Subtitle C hazardous waste disposal perm

Option 3 (impoundments only). 

o 411 of the 495 total electric utility plants currently dispose onsite (84 of the 495 plants solely dispose C

• Industry average cost per waste disposal permit: 

o ($44069 average RCRA Part A permit application cost per-plant per-year) + ($68,96070 average RCRA 

per-facility per-year) = $69,400 per Subtitle C permit per year ($69,400 per permit per year) x (3 years ICR annualization period) = $208,200 per permit (411 plants) x ($208,200 per permit) = $85.57 million 

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

• State government average cost per waste disposal permit: 

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

Subtitle C waste disposal permits:71

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

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

o State Cost Calculation: 

 (411 electricity plants dispose CCR onsite) x ($58,200 per Subtitle C permit per year) = $23.9 million  Amortized state cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $1.7 

• Total Subtitle C permit cost (industry + state government) = $7.9 million per year 

16. Regulatory RCRA enforcement inspection cost 

• Assumptions: 

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

average calculated by dividing the $1,517,357 annual enforcement inspection cost to 10 surveyed state annual enforcement cases, from page 87 of the January 2007 ASTSWMO report “State RCRA Subtitle 

Management Program Implementation Costs Final Report” 

69 $440 unitized cost derived for this RIA from EPA Information Collection Request (ICR) No. 0262.12 “RCRA Hazardous Waste Permit A

Part A”, Federal Register, Vol.74, No.17, 28 Jan 2009, page 4958; http://edocket.access.gpo.gov/2009/pdf/E9-1804.pdf 

70 $68,960 unitized cost derived for this RIA from EPA Information Collection Request (ICR) No. 1573.12 “Part B Permit Application”, Fe

page 25237, 27 May 2009; http://edocket.access.gpo.gov/2009/pdf/E9-12285.pdf 

71 Source: Based on cost data from page 84 of January 2007 ASTSWMO report “State RCRA Subtitle C Core Hazardous Waste Managemen

Costs Final Report” at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20C
o 1.6% average annual enforcement inspection frequency based on dividing the 11,965 LQG “large quan

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

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

• Cost calculation: 

($7,900 per LQG enforcement) x (495 electric utility plants) x (1.6% LQG enforcements annually) = $0.063 m

17. Regulatory future remediation added cost Potential $18.5 million to $376 million per case in added cleanup cost for future surface impoundment failures, if regSubtitle C rather than Subtitle D, is based on the two example case studies summarized in Exhibit 4I below. 
Exhibit 4I 

Two Case Studies: 

Possible Added Cost Under RCRA Subtitle C Regulation of CCR Cleanup at Electricity Plants from CCR Impound

(Note: Assumptions or numerical factors unique to each case study are applied in the cost calculations below 

rather than the national average assumptions and numerical factors applied elsewhere in this RIA)

Case Study #1: 

TVA Kingston TN (2008) 

Case Study #2: 

Constellation Energy Gambrills MD 

If cleanup as non-hazardous waste: Baseline Assumptions: 

• 3.32 million tons released • $0.10/ton/mile truck operating cost (source: OSW-EMRAD) • 45 miles to Subtitle D LF (source: OSW-EMRAD) • $35/ton tipping fee (source: 2005 Chartwell) • 154,000 truckloads (source: TVA assumes 21.6 tons ash per load) 

Baseline Cost Calculations: 

• Trucking cost: (3.32 million tons) x (45 miles) x ($0.10/ton /mile) = 

$15 million 

• LF tipping fee: ($35/ton) x (3.32 million tons) = $116 million • Manifest: $0 • Case #1 total = $131 million for event 

If cleanup as non-hazardous waste: Baseline Assumptions: 

• 0.25 million tons released • $0.10/ton/mile truck operating cost (source: OS• 193 miles to Subtitle D LF (Constellation Energ

to existing VA fly ash LF) 

• $35/ton tipping fee (source: 2005 Chartwell) • 20,833 truckloads (source: Constellation Energy 

per load) 

 Baseline Cost Calculations: 

• Trucking cost: (0.25 million tons released) x (1

/mile) = $5 million 

• LF tipping fee: ($35/ton) x (0.25 million.tons) = • Manifest: $0 

Case #2 total = $14 million for event 

If cleanup as RCRA Subtitle C hazardous waste Assumptions: 

• 3.32 million tons released • $0.19/ton/mile truck operating cost (source: TVA) • 370 miles to Subtitle C LF (source: TVA) • $80/ton Subtitle C tipping fee (source: TVA) • 154,000 truckloads (source: TVA assumes 21.6 tons ash per load) 

Cost Calculations: 

• Trucking cost: (3.32 million tons) x (370 miles) x ($0.19/ton/mile 

truck operating cost) = $233 million 

• LF tipping fee: ($80/ton) x (3.32 million tons) = $266 million • Manifest: (154,000 truckloads) x ($53 manifest cost per load) = $8 

million 

• Case #1 total = $507 million for event 

If cleanup as RCRA Subtitle C hazardous waste Assumptions: 

• 0.25 million tons released • $0.19/ton/mile truck operating cost (from TVA• 179 miles to Subtitle C LF (closest is Envirosaf

tons permitted capacity) 

• $90/ton tipping fee (2004 ETC national median • 20,833 truckloads (source: Constellation Energy 

per load) 

Cost Calculations: 

• Trucking cost: (0.25 million tons) x (179 miles) 

truck operating cost) = $8.5 million 

• LF tipping fee: ($90/ton) x (0.25 million tons) = • Manifest: (20,833 truckloads) x ($53 manifest c

million 

• Case #2 total = $32.5 million for event 

Case #1 incremental cost over non-hazardous: 

$376 million for cleanup event 

Case #2 incremental cost over non-ha

$18.5 million for cleanup even
18. EPA administrative reporting and recordkeeping costs Three of the regulatory costs itemized above -- item 11 offsite disposal truck manifesting and offsite disposal hazardo

structural integrity inspection reporting, and item 13 RCRA facility-wide investigation (RFI) – include the cost of papitems. In addition, certain features of the Subtitle C options of the proposed rule require four other paperwork burden 

18a. Notice of Regulated Waste Activity & EPA ID Number 

RCRA Subtitle C regulations for hazardous waste “generators” require generators to notify their facilities as such and numbers (40 CFR 262.12). According to EPA’s most recent (2009) estimate, the average per-facility response burde

Applied to the 495 electric utility plants yields an estimated one-time notification cost of $80,190 (i.e., (495 electric unotification)). Amortized with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $5,800 per yeaequivalent. 

o Industry share of cost: (86%) x ($5,800/year) = $5,000/year o State government share of cost: (14%) x ($5,800/year) = $800/year 

18b. General Paperwork Standards for Hazardous Waste TSDFs This cost item represents a set of paperwork burden activities grouped under 40 CFR 264/265 Subpart B (i.e., 264.10 265.19) and includes (1) maintaining records for the K179 hazardous waste that is stored, treated, and/or disposed onlocation, design, construction, operating methods, techniques, and practices for onsite K179 storage, treatment, and/oplans for unanticipated damages from K179 onsite storage, treatment and/or disposal, (4) maintaining qualifications omaintaining continuity and financial responsibility of facility operation, and (6) personnel hazmat training. Accordin(2009) estimate the average per-facility paperwork burden is $27,350 per facility per year.73 Applied to the 411 elect

currently dispose onsite (i.e., 84 of the 495 plants solely dispose CCR offsite with other companies) yields an estimat

per year. 

o Industry share of cost: (86%) x ($11.24 million/year) = $9.67 million/year o State government share of cost: (14%) x ($11.24 million/year) = $1.57 million/year 

18c. RCRA Hazardous Waste Biennial Report RCRA Subtitle C requires hazardous waste LQG large quantity generators (40 CFR 262.41) and hazardous waste TS

disposal facilities (40 CFR 264.75 and 265.75) to submit “Hazardous Waste Report” information on a 2-year repeatinBiennial Report”). According to EPA’s most recent (2009) estimate, the average annualized per-facility response bur

Extrapolated to 495 electric utility plants yields a cost estimate of $1.69 million per year. 

72 $162 per year notification cost derived from EPA Information Collection Request (ICR) No. 0261.16 “Notification of Regulated Waste AcRegister, Vol.74, No.123, pages 31028-31029, 29 June 2009; http://edocket.access.gpo.gov/2009/pdf/E9-15310.pdf 73 $27,350 per facility per year average cost derived from EPA Information Collection Request (ICR) No. 1571.09 “General Hazardous WasRegister, Vol.74, No.23, pages 6152-6154, 05 Feb 2009; http://edocket.access.gpo.gov/2009/pdf/E9-2467.pdf74 $3,410 per facility per year average cost derived from EPA Information Collection Request (ICR) No. 0976.14 “2009 Hazardous Waste R

Vol.74, No.93, pages 22922-22924, 15 May 2009; http://edocket.access.gpo.gov/2009/pdf/E9-11410.pdf 
o Industry share of cost: (86%) x ($1.69 million/year) = $1.45 million/year o State government share of cost: (14%) x ($1.69 million/year) = $0.24 million/year 

18d. CERCLA Reportable Quantity (RQ) Spill/Leak Reporting Section 103(a) of CERCLA requires facilities and vessels to immediately notify the National Response Center (NRCrelease (e.g., spill, leak) into the environment if the amount of the release equals or exceeds the substance’s reportable 

general there are five RQ categories (1, 10, 100, 1,000 or 5,000 pounds). The CCR propose rule proposes to add CCR 

hazardous waste (i.e., Options 1, 3 and 4) to the CERCLA list of hazardous substances and assign an RQ of one-poun

use of concentrations to determine RQ thus resulting in a range of 1,294 pounds to 10,000,000 pounds for 12 chemica

of facilities (i.e., establishments) in the US manufacturing sector (NAICS 31, 32, 33) plus the US waste management 

rough indicators, there are 315,000 industrial facilities in the US which may handle RQ-listed hazardous substances.7

most recent (2007) estimate, the average per-facility response burden is $122 (i.e., 4.1 burden hours) per facility per raverage annual 25,861 facilities at an annual paperwork burden cost of $3.161 million.76 Relative to this 300,000 ind

this annual count of RQ-reporting facilities represents an 8% fraction. Extrapolated to the 495 electric utility plants y40 possible RQ reports per year, at a cost of $4,900 per year (i.e., (495 electric utility plants) x (8% RQ reports per yereport)). 

o Industry share of cost: (86%) x ($4,900/year) = $4,200/year o State government share of cost: (14%) x ($4,900/year) = $700/year 

Sub-total cost item 17 (17a + 17b + 17c + 17d) = $12.94 million per year. 

o Industry share of cost: (86%) x ($12.94 million/year) = $11.13 million/year o State government share of cost: (14%) x ($12.94 million/year) = $1.81 million/year 

Exhibit 4J below presents a summary of these “Ancillary Cost” elements numbered from 11 to 18. 

75 315,000 industrial facilities based on “Number of Establishments” published for NAICS codes 31-33 Manufacturing (293,919 establishme

Waste management and remediation services (21,254 establishments) from the US Census Bureau in its “2007 Economic Census” at http://w

Not all manufacturing or waste management facilities necessarily handle hazardous substances so this is an over-estimate, but there are also mining, construction, utilities, transporters, and wholesalers), which handle hazardous substances not included in this facility count which of

76 $122 per facility average cost derived from EPA Information Collection Request (ICR) No. 1049.11 “Notification of Episodic Releases of 

(Renewal); Federal Register, Vol.72, No.205, 24 Oct 2007, pp.60357-60358; http://edocket.access.gpo.gov/2007/pdf/E7-20934.pdf 
Exhibit 4J 

Summary of “Ancillary Cost” Estimates Associated with RCRA Regulation of CCR Disposal 

($millions average annualized; 2009$) 

Ancillary Cost Element 

Applicability to 

CCR Regulatory Options 

Electric Utility 

Industry Cost 

State Government 

RCRA-Authorized 

Program Cost 

11. Ancillary offsite disposal costs Option1 $76.35 $0.63 12. Impoundment structural integrity inspections Option 1, Option 2, Option 3 $0.96 $0.054 13. RCRA facility-wide investigations (RFIs) Option 1, Option 3 $6.9 $0.7 14. RCRA facility-wide corrective action Option 1, Option 3 Not estimated – 

historical 

average cost = 

$5.4 million per 

facility 

Not estimated 

15. RCRA TSDF waste disposal permits Option 1, Option 3 $6.2 $1.7 16. RCRA enforcement inspections Option 1, Option 3 $0 $0.063 17. Future disposal unit failure cleanup remediation as RCRA hazardous waste 

Option 1, Option 3 Not est. – case 

study example 

Not est. – case 

study example 

18. EPA administrative reporting & recordkeeping 18a. EPA regulated waste notification 18b. RCRA TSDF general paperwork standards 18c. RCRA haz waste biennial report 18d. CERCLA RQ reporting 

Option 1, Option 3 Subtotal= $11.13 

$0.005 

$9.67 $1.45 

$0.0042 

Subtotal= $1.81 

$0.0008 

$1.57 $0.24 

$0.0007 

Column Totals by Option: 

 Option 1 $101.5 $5.0  Option 2 $0.96 $0.05  Option 3* $8.04 $1.19 

* Option 3 costs for ancillary cost items 13, 14, 15, 16, 17, and 18 are proportioned only to the 158 plants with impoundments thregulated under Subtitle C for this option, by the proportionate multiplier: (158 plants w/impoundments) / (495 total plants) = 0.
4C.3 Sub-Option: Cost for the Land Disposal Treatment Standard (i.e., dewatering CCR for dAs presented in the CCR proposed rule, this sub-option consists of two components: 

• Dry CCR disposal (landfills): Moisture conditioning and compaction to 95% maximum dry density value accordi

ASTM D 1557 test methods prior to disposal in landfills. 

• Wet CCR disposal (impoundments): Dewatering to remove solids prior to disposal in impoundments within 5-yea

The potential cost for this treatment standard is estimated below. 

However, only the potential cost for the wet CCR disposal dewatering treatment standard is estimated in this section 

potential cost for meeting the dry CCR moisture conditioning and compaction requirements are already estimated in i

controls” in this chapter above: 

• Examples of CCR Dewatering Methods: 

Based on the following recent (1997-2009) example descriptions of dry CCR disposal practices at existing or planned 

plants, dry CCR disposal may involve different methods for any given plant: 

1. Tanks & chain drag: As described in March 2009 by the Basin Electric Power Cooperative.77 Bottom ash wi

and the water will be re-circulated to transport additional bottom ash. Bottom ash will be removed using a chthen be hauled by truck to a lined landfill offsite. The fly ash will be conveyed in a dry state. Both ashes will close to the plant site. 

2. Pressure squeeze conveyor: Another tank-based example apparently similar to the Basin Cooperative method 

disposal conversion by the coal mining industry, involving the Phoenix Process Equipment company supplier 

processing equipment. This second example involves a thickening tank, porous conveyor belt and pressure to coal washings, producing a semi-solid, 75% dewatered cake which is scraped off the conveyor belt and stacke

cost for this process is reported at $0.50 per ton of coal waste processed.78

3. Horizontal belt filters: According to a May 2009 technical paper79, dewatering gypsum using horizontal belt f

electric utility industry, and a new modified horizontal belt filter method involving two feedboxes allows fly a

be dewatered simultaneously. 

4. Storage silos & rail system: As described June 200980 for a $10 million conversion project located at Detroit E

Michigan Power Plant -- a four boiler unit, 3,200-megawatt power station originally constructed in 1974. Inst

77 Source: March 2009 Basin Electric Power Cooperative examples at http://www.basinelectric.com/News_Center/Feature_Articles/Coal_ash78 Source: Dave Cooper, “Better, Safer Ways to Handle Coal Slurry Do Exist”, page 14 of the Nov 2001 “E”-Notes Newsletter of the Ohio V

at http://www.ohvec.org/newsletters/enotes_97-01_pdf/enotes_2001_11.pdf 

79 Source: May 2009 horizontal belt filter technical paper by Alex Hohne at http://www.flyash.info/2009/036-hohne2009.pdf 80 Source: June 2009 Detroit Edison Monroe Power Plant example at http://www.headwaters.com/data/upimages/press/6.30.09MonroeAshR
collect the coal ash in a dry state, plus dry ash storage facilities (storage silos), and truck/rail loading equipme

dry ash to concrete producers in the Midwest United States and Eastern Canada. 

5. Integrated silo system: Integrated with precipitators, vacuum pumps and bag filter/receivers, as described in a

about the 1997 dry fly ash system conversion of Northern Indiana Public Service Company’s Michigan City P

For this RIA, EPA ORCR identified four alternative existing studies with cost estimates (dated 1981, 1985, 2005, and wet CCR disposal at coal-fired electric utility plants. The first three studies provided cost estimates on a per-plant ba

study provided an extrapolated nationwide cost estimate. However, only the 2005 study is used in this RIA as a basis estimate for the wet CCR dewatering land disposal treatment sub-option, because the first two studies are over 25-yea

and the 2009 study does not provide sufficient details for verification of data and calculations. These three other stud“Sensitivity Analysis” Chapter of this RIA, as well as used to illustrate the magnitude of cost estimation uncertainty i

studies, compared to the estimate derived below in this section of the RIA. 

• Summary of 2005 TVA CCR Dry Disposal Cost Study • In August 2009 TVA announced a proposed plan to convert its wet CCR disposal to dry disposal. TVA’s CEO T

28 July 2009 US Congressional subcommittee hearing that TVA has developed a 5-year plan to shift CCR disposimpoundments to dry landfills. TVA estimated it will cost between $1.5 billion to $2 billion over 8 to 10 years fo

utility plants.82 Detailed or semi-detailed calculations of TVA’s 2009 cost estimate are not available for this RIA 

nationwide. 

• However, a 2005 TVA cost estimate titled “Kingston Fossil Plant Decision Matrix: Pond or Peninsula?” provides 

dry conversion of the TVA Kingston TN plant.83 The TVA cost study involves conversion of an existing impoun

dispose wet fly ash and wet bottom ash at the TVA Kingston TN electric utility plant, for future dry fly ash and dr

The FGD stream remains wet-sluiced before and after this hypothetical conversion in the cost study. In addition t

the electric plant boilers and the impoundment for dry ash disposal, the cost study also includes the cost for constr

water runoff management pond (Source: row item 68 of TVA’s “Appendix C Detailed Cost Sheets”, slide nr. TV

• TVA cost study involves conversion of 475,600 cubic yards of fly ash plus bottom ash per year; this RIA estimate

equivalent to 880,000 tons per year, assuming 1.85 tons per cubic yard multiplier.84

81 Source: Dec 1997 NIPSC conversion report at http://www.babcockpower.com/pdf/rst-145.pdf 82 Source: TVA news release “TVA Coal Combustion Products Remediation Plan Proposed”, 20 Aug 2009 http://www.tva.gov/news/release83 Source: TVA 27 January 2005 plant managers conference slide presentation (25 pages) at: http://www.tva.gov/kingston/tdec/pdf/TVA-000

presented as “Option 1” and dry disposal is presented as “Option 2” in the TVA cost presentation. Additional details for the TVA cost estim

http://www.tva.gov/kingston/tdec/pdf/TVA-00007402.pdf 

84 "Source: 1.85 tons per cubic yard multiplier represents the midpoint from the following 1.2 to 2.5 range: According to EPA’s 1988 Repor

Combustion of Coal by Electric Utility Power Plants,” page 3-14), the dry density of fly ash is 80-90 lbs/cubic ft which translates to a specif

Highway Administration studied fly ash for use in highway construction and reported its specific gravity may be as low as 1.7 to as high as 3http://www.tfhrc.gov/hnr20/recycle/waste/cfa52.htm). Conversion of this implied 1.4 to 3.0 range in fly ash specific gravities to tons-per-cu
• The TVA cost study did not estimate the cost for dewatering FGD (gypsum) because FGD is already dewatered b

plants for beneficial uses, thus only four of the 495 electric utility plants (i.e., TVA Widows Creek plant, TVA Pa

Gas & Electric Co Trimble County plant, and Northern Indiana Public Service Company R.M. Schafer plant) wet 

FGD per year in impoundments as of 2005 (source: column B of Exhibit 2C of this RIA). 

• Unit cost (i.e., average cost per ton) of conversion from wet to dry disposal estimated from the 2005 TVA cost an

estimates for converting from wet ash disposal to dry ash disposal: 

TVA wet disposal TVA dry disposal Added cost for dry Unitized dry 

o Capital cost $13.12 million PV $38.45 million PV Cost not incremental $43.7/ton pe

o Annual O&M cost $10.63 million PV $17.51 million PV $6.88 million PV $0.60/ton (@

(Note: PV = present value for TVA’s 25-year period of analysis 2005-2029; TVA costs are in 2005$ pric

• Cost estimate calculation under conversion to dry disposal scenario, calculated based on TVA’s per-ton cost extra

tons per year baseline wet CCR (i.e., wet fly ash, wet bottom ash, wet FGD, wet gypsum, wet other CCR) disposaof the 495 electric utility plants: 

o Capital cost: (22.4 million tons per year wet CCR disposal for conversion at 158 plants) x ($43.7/ton p

cost) x (20 years capitalization period) x (1.174 price update multiplier85 to 2009$ price level) = $22,9

capital cost Annual equivalent capital: ($22,984 million) x (0.07246 capital recovery factor @7% & 50-years) = $

o O&M cost: ($0.60/ton conversion O&M cost) x (22.4 million tons/year wet CCR disposal for conversi

years future operational period 2017-2061 which assumed to begin 5 years after 2012 final rule promu

update multiplier to 2009$ price level) = $710 million undiscounted total O&M PV present value discounted @7% over 50-years = $153 million PV present value O&M Annual equivalent O&M: ($153 million) x (0.07246 capital recovery factor @7% & 50-years) = $11 m

o Total annualized cost (capital + O&M) = ($1,665 million/year capital) + ($11 million/year O&M) = $1

Exhibit 4N below summarizes the above regulatory cost estimates on an incremental basis (i.e., without including the estimated in Chapter 3 of this RIA). Exhibit 4O below summarizes the same regulatory cost estimates sub-totaled (i

according to the nine different size/type categories of owner entities. Appendix I presents itemized plant-by-plant, in

costs estimates for the electric utility plants. 

o Low-end: (1.4 g/cm3) / (0.000001 m3/cm3) x (0.764 m3/yd3) / (1000 g/kg) x (2.204 lbs/kg) / (2000 lbs/short ton) = 1.2 shor

o High-end: (3.0 g/cm3) / (0.000001 m3/cm3) x (0.764 m3/yd3) / (1000 g/kg) x (2.204 lbs/kg) / (2000 lbs/short ton) = 2.5 shor

85 1.174 price update multiplier represents 2009:to:2005 ratio in the Engineering-News Record Construction Cost Index: (8566 CCI for July 
Exhibit 4N 

Summary of Regulatory Cost Estimates for RCRA Regulation of CCR Disposal by Electric Utility Plan

($millions in 2009 price level; average annual amortized @7% discount rate over 50-year period 2012 to 2061

RCRA Regulatory Cost Element 

Option 1 

(Preferred Option) 

Subtitle C hazardous waste 

Option 2 

Subtitle D 

non-hazardous waste 

Subtitle Subtitle 

A. Engineering Controls (onsite): $491 $491 1. Groundwater monitoring $13 $13 2. Bottom liners $95 $95 3. Leachate collection $8 $8 4. Fugitive dust controls $5 $5 5. Water runon/runoff controls $2 $2 6. Financial assurance $30 $30 7. Siting/location restrictions $76 $76 8. Closure capping to cover unit $255 $255 9. Post-closure groundwater monitoring $2 $2 10. Storage design & operating standards Not estimated in this RIA Not estimated in this RIA Not B. Other Ancillary Costs: $107 $1 11. For offsite disposal (11a+11b+11c) =  11a. RCRA manifest cost  11b. Added operation for hazmat truck  11c. Offsite LF RCRA Subtitle C permit 

$77 $66 

$8 $3 

$0 

Not relevant Not relevant Not relevant 

(offsi

so no 

12. Structural integrity inspections $1 $1 13. RCRA facility-wide investigation $7.6 Not relevant 14. RCRA facility-wide corrective action Not estimated in this RIA; 

historical average = 

$5.4 million per case 

Not relevant Not e

h

$5

15. RCRA TSDF haz waste disposal permit $7 Not relevant 16. RCRA enforcement inspection $0.06 $0 17. Future added cleanup cost as haz waste Not estimated in this RIA: 

case studies indicate possible 

$18 to $376 million per case 

Not relevant Not e

case st

$18 to 

18. EPA paperwork reporting/records $13 Not relevant C. Sub-option: Land Disposal Treatment Standard $1,676 $1,676 TOTAL ANNUALIZED COSTS: 

Total cost w/out land disposal treatment (A+B) = 

Average cost per-ton (94.2 million tons disposed) = 

Average cost per-plant (467 disposing plants) = 

$598 

($6.35 per ton) 

($1.28 million per plant) 

$492 

($5.22 per ton) 

($1.05 million per plant) 

($1.

Total cost with land disposal treatment (A+B+C) = 

Average cost per-ton (94.2 million tons disposed) = 

Average cost per-plant (467 disposing plants) = 

$2,274 

($24.14 per ton) 

($4.87 million per plant) 

$2,168 

($23.01 per ton) 

($4.64 million per plant) 

($4.
Exhibit 4O 

Summary of Regulatory Cost Estimates According to Electric Utility Plant Owner Entity Size/Type Categ

($millions in 2009 price level; average annual amortized @7% discount rate over 50-year period 2012 to 2061

Size/Type of Entity* 

Count of All 

Plants in 

Category*** 

Option 1 

(Preferred Option) 

Subtitle C hazardous waste 

Option 2 

Subtitle D 

non-hazardous waste 

O

Subtitle C foSubtitle D fo

A. Without land disposal treatment sub-option: 1. Non-Small City 27 plants $30.6 $27.1 2. Non-Small Company 372 plants $460.8 $378.5 3. Non-Small Coop 20 plants $37.5 $34.6 4. Non-Small Federal 11 plants $23.4 $20.8 5. Non-Small State** 13 plants $29.3 $27.1 6. Small City 33 plants $2.0 $1.6 7. Small Company 12 plants $4.1 $1.9 8. Small Coop 6 plants $10.4 $0.3 9. Small County 1 plant $0.004 $0.004 

Total all 9 categories = 495 plants*** $598 $492 

B. With land disposal treatment sub-option: 1. Non-Small City 27 plants $46.9 $43.5 2. Non-Small Company 372 plants $1,897.2 $1,815.0 $3. Non-Small Coop 20 plants $87.7 $84.8 4. Non-Small Federal 11 plants $183.2 $180.7 5. Non-Small State** 13 plants $41.6 $39.4 6. Small City 33 plants $2.8 $2.5 7. Small Company 12 plants $4.1 $1.9 8. Small Coop 6 plants $10.4 $0.3 9. Small County 1 plant $0.004 $0.004 

Total all 9 categories = 495 plants*** $2,274 $2,168 $

Notes: * Size/Type classification methodology defined in Chapter 2 (Exhibit 2B) of this RIA. ** State government costs include costs to (a) state government electric utility plants regulatory costs, plus (b) state government 

programs for option implementation. *** The total count of coal-fired electric utility plants is shown in the Exhibit; however, only a sub-total of 467 of the 495 may i

regulatory costs because 28 plants solely supply their CCR for beneficial uses. 
Chapter 5 

Potential Distributional Effects 

The purpose of this chapter is to address OMB’s 2003 Circular A-4 “Regulatory Analysis” (page 14) requirement for 

separate description of distributional effects for proposed regulations. OMB defines distributional effects as: “[T]he impact of a regulatory action across the population and economy, divided up in various ways (e.g., income gr

industrial sector, geography).” This chapter presents six potential distributional effects for the estimated costs of the regulatory options within the sc

A. Potential impact on electricity prices within electric utility plant customer service areas (Executive Order 

B. State-by-state distribution of average annualized costs C. Small business share of average annualized costs (RFA/SBREFA) 

D. Minority & low-income populations surrounding potentially affected electric utility plants 

E. Child populations surrounding potentially affected electric utility plants F. Unfunded Mandates (UMRA) & Federalism implications analysis (Executive Order 13132) 

5A. Potential Impact on Electricity Prices (Executive Order 13211) The 2001 Executive Order 1321186 “Actions Concerning Regulations that Significantly Affect Energy Supply, Distri

Federal agencies to evaluate and prepare a statement on any potential adverse effects of economically-significant rule

supply, distribution or use, including: 

• Shortfall in energy supply • Energy price increases • Increased use of foreign energy supplies 

The OMB’s 13 July 2001 Memorandum M-01-2787 guidance for implementing this Executive Order identifies nine n(thresholds) of potential adverse energy effects, three of which are relevant for evaluation in this RIA: 86 The 18 May 2001 EO-13211 is available at: http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=2001_register&docid=fr22my01-87 OMB’s 13 July 2001 Memorandum M-01-27 is available at: http://www.whitehouse.gov/omb/memoranda_m01-27/ 
• Increases in the cost of energy production in excess of 1%

• Increases in the cost of energy distribution in excess of 1%• Other similarly adverse outcomes.

Because this RIA did not collect and analyze data on energy production cost or energy distribution cost, this RIA eva

of the CCR regulatory options on electricity prices relative to the 1% threshold of both indicators as an indicator of “ooutcome”. This RIA calculated the potential increase in statewide electricity prices that the industry compliance costCCR regulatory option. This calculation involved plant-by-plant annual revenue estimates and annualized complianc

respective statewide average electricity prices for the 495 electric utility plants, according to the following four steps. 

• Step 1: Downloaded the annual million megawatt capacity data for each of the 495 plants from the DOE-EIA 

estimated annual electricity output for each plant, by multiplying the capacity data by three factors: 

o 365 operating days per year 

o 24 operating hours per day o 86.8% capacity utilization per year88

• Step 2: Estimated the annual electricity sales revenue for each plant by multiplying the estimated annual electr

plant (from Step 1), by the respective statewide average retail price (May 2009) of electricity for all sectors (i.e., r

industrial, transportation) from DOE-EIA at http://www.eia.doe.gov/cneaf/electricity/epm/table5_6_a.html

• Step 3: Added the estimated incremental regulatory costs on a plant-by-plant basis, to the estimated annual ele

each plant, to obtain a hypothetical future annual revenue target, which represents a 100% cost pass-thru scenariorepresents an upper-bound case of potential electricity price increase. Furthermore, if this 100% cost pass-thru is electricity supply in each state, not just averaged over the 495 coal-fired electricity plants as done in this RIA, the increase in electricity price would be less than this upper-bound case presented in this RIA. 

• Step 4: Divided the hypothetical future annual revenue target by the estimated annual electricity output for eac

hypothetical future (higher) target price for each plant, which incorporates the added regulatory cost. Compared tthe current price to calculate the potential price increase on a percentage basis for each of the 495 plants. 

Exhibit 5A below presents the findings of this energy price evaluation on a state-by-state basis and in nationwide aggwithout the land disposal treatment sub-option, Exhibit 5A-2 with the sub-option, and Exhibit 5A-3 summary). As drow of Exhibit 5A, none of the options have an expected nationwide average energy price increase >1%. Appendix plant calculation spreadsheet used for this electricity price impact analysis. 88 Source: 86.8% capacity utilization is the 1972-2008 annual average published in the 15 May 2009 Federal Reserve Statistical Release G.17 

Capacity Utilization” data for Utilities at http://www.federalreserve.gov/releases/g17/Current/default.htm 
Exhibit 5A-1 

State by State Breakout of Average Electricity Price Increases Per Option 

Without Land Disposal Treatment Sub-Option 

Item 

Number of 

Plants State 

May 2009 

statewide average 

electricity price ($ 

per kilowatt hour) 

Option 1 

Average Price 

Increase 

Option 2 

Average Price 

Increase 

Option 3 

Average Pric

Increase 

Average annualized cost (from Exhibit 4N) = $598 $492 $500 

1 2 AK $0.1518 1.30% 1.23% 1.25% 2 10 AL $0.0856 0.205% 0.189% 0.192% 3 3 AR $0.0762 0.238% 0.225% 0.228% 4 6 AZ $0.1002 0.659% 0.622% 0.632% 5 6 CA $0.1337 0.717% 0.676% 0.687% 6 14 CO $0.0797 0.110% 0.006% 0.006% 7 2 CT $0.1712 0.074% 0.000% 0.000% 8 0 DC $0.1337 9 3 DE $0.1236 0.156% 0.127% 0.129% 

10 15 FL $0.1136 0.096% 0.077% 0.078% 11 11 GA $0.0859 0.175% 0.163% 0.166% 12 2 HI $0.1892 0.245% 0.171% 0.174% 13 19 IA $0.0710 0.213% 0.198% 0.202% 14 0 ID $0.0602 15 25 IL $0.0924 0.144% 0.099% 0.101% 16 26 IN $0.0766 0.249% 0.207% 0.210% 17 8 KS $0.0822 0.207% 0.190% 0.193% 18 21 KY $0.0640 0.673% 0.593% 0.603% 19 4 LA $0.0748 0.043% 0.040% 0.041% 20 4 MA $0.1534 0.027% 0.000% 0.000% 21 8 MD $0.1316 0.060% 0.017% 0.017% 22 1 ME $0.1222 0.520% 0.346% 0.352% 23 22 MI $0.0986 0.056% 0.052% 0.053% 24 16 MN $0.0804 0.499% 0.471% 0.478% 25 20 MO $0.0757 0.137% 0.116% 0.118% 26 5 MS $0.0893 0.112% 0.106% 0.108% 27 5 MT $0.0720 1.263% 1.193% 1.212% 28 22 NC $0.0839 0.170% 0.148% 0.151% 29 7 ND $0.0698 0.023% 0.012% 0.012% 30 7 NE $0.0705 0.223% 0.206% 0.210% 31 2 NH $0.1544 0.055% 0.004% 0.004% 32 7 NJ $0.1421 0.118% 0.045% 0.045% 33 3 NM $0.0769 0.788% 0.407% 0.414% 34 2 NV $0.0960 0.548% 0.518% 0.526% 
Exhibit 5A-1 

State by State Breakout of Average Electricity Price Increases Per Option 

Without Land Disposal Treatment Sub-Option 

Item 

Number of 

Plants State 

May 2009 

statewide average 

electricity price ($ 

per kilowatt hour) 

Option 1 

Average Price 

Increase 

Option 2 

Average Price 

Increase 

Option 3 

Average Pric

Increase 

35 13 NY $0.1543 0.024% 0.000% 0.000% 36 26 OH $0.0930 0.169% 0.132% 0.134% 37 6 OK $0.0698 0.121% 0.050% 0.051% 38 1 OR $0.0751 0.212% 0.200% 0.204% 39 34 PA $0.0960 0.270% 0.229% 0.232% 40 0 RI $0.1343 41 14 SC $0.0826 0.038% 0.028% 0.028% 42 2 SD $0.0742 0.098% 0.084% 0.086% 43 7 TN $0.0860 0.013% 0.001% 0.001% 44 19 TX $0.1019 0.074% 0.038% 0.039% 45 6 UT $0.0690 0.355% 0.336% 0.341% 46 16 VA $0.0916 0.137% 0.078% 0.079% 47 0 VT $0.1282 48 1 WA $0.0684 0.000% 0.000% 0.000% 49 17 WI $0.0918 0.067% 0.063% 0.064% 50 16 WV $0.0668 0.687% 0.615% 0.625% 51 9 WY $0.0602 0.365% 0.315% 0.320% 

Summary: 

Minimum = $0.0602 0.0000% 0.0000% 0.0000% 

Maximum = $0.1892 1.2982% 1.2259% 1.2459% 

Average = $0.0985 0.2709% 0.2259% 0.2296% 

Median = $0.0860 0.1691% 0.1316% 0.1337% 

Nationwide = $0.0884 0.209% 0.172% 0.175% 
Exhibit 5A-2 

State by State Breakout of Average Electricity Price Increases Per Option 

With Land Disposal Treatment Sub-Option 

Item 

Number of 

Plants State 

May 2009 

statewide average 

electricity price ($ 

per kilowatt hour) 

Option 1 

Average Price 

Increase 

Option 2 

Average Price 

Increase 

Option 3 

Average Pric

Increase 

Average annualized cost (from Exhibit 4N) = $2,274 $2,168 $2,176 

1 2 AK $0.1518 1.30% 1.23% 1.25% 2 10 AL $0.0856 1.43% 1.416% 1.419% 3 3 AR $0.0762 0.293% 0.280% 0.283% 4 6 AZ $0.1002 1.141% 1.103% 1.113% 5 6 CA $0.1337 0.717% 0.676% 0.687% 6 14 CO $0.0797 0.121% 0.017% 0.017% 7 2 CT $0.1712 0.074% 0.000% 0.000% 8 0 DC $0.1337 9 3 DE $0.1236 0.156% 0.127% 0.129% 

10 15 FL $0.1136 0.131% 0.112% 0.113% 11 11 GA $0.0859 1.160% 1.149% 1.152% 12 2 HI $0.1892 0.245% 0.171% 0.174% 13 19 IA $0.0710 0.548% 0.534% 0.537% 14 0 ID $0.0602 15 25 IL $0.0924 0.531% 0.486% 0.488% 16 26 IN $0.0766 1.387% 1.345% 1.348% 17 8 KS $0.0822 0.545% 0.529% 0.532% 18 21 KY $0.0640 2.307% 2.227% 2.237% 19 4 LA $0.0748 0.464% 0.462% 0.462% 20 4 MA $0.1534 0.027% 0.000% 0.000% 21 8 MD $0.1316 0.080% 0.037% 0.037% 22 1 ME $0.1222 0.520% 0.346% 0.352% 23 22 MI $0.0986 0.459% 0.454% 0.455% 24 16 MN $0.0804 2.013% 1.985% 1.993% 25 20 MO $0.0757 0.817% 0.796% 0.798% 26 5 MS $0.0893 0.197% 0.191% 0.193% 27 5 MT $0.0720 5.582% 5.512% 5.531% 28 22 NC $0.0839 1.122% 1.100% 1.102% 29 7 ND $0.0698 0.994% 0.982% 0.982% 30 7 NE $0.0705 0.223% 0.206% 0.210% 31 2 NH $0.1544 0.055% 0.004% 0.004% 32 7 NJ $0.1421 0.118% 0.045% 0.045% 33 3 NM $0.0769 2.103% 1.722% 1.729% 34 2 NV $0.0960 0.548% 0.518% 0.526% 
Exhibit 5A-2 

State by State Breakout of Average Electricity Price Increases Per Option 

With Land Disposal Treatment Sub-Option 

Item 

Number of 

Plants State 

May 2009 

statewide average 

electricity price ($ 

per kilowatt hour) 

Option 1 

Average Price 

Increase 

Option 2 

Average Price 

Increase 

Option 3 

Average Pric

Increase 

35 13 NY $0.1543 0.024% 0.000% 0.000% 36 26 OH $0.0930 1.193% 1.155% 1.157% 37 6 OK $0.0698 0.151% 0.080% 0.081% 38 1 OR $0.0751 0.212% 0.200% 0.204% 39 34 PA $0.0960 0.702% 0.661% 0.665% 40 0 RI $0.1343 41 14 SC $0.0826 0.394% 0.384% 0.384% 42 2 SD $0.0742 0.098% 0.084% 0.086% 43 7 TN $0.0860 0.517% 0.504% 0.504% 44 19 TX $0.1019 0.292% 0.255% 0.256% 45 6 UT $0.0690 0.602% 0.583% 0.588% 46 16 VA $0.0916 0.688% 0.628% 0.629% 47 0 VT $0.1282 48 1 WA $0.0684 0.000% 0.000% 0.000% 49 17 WI $0.0918 0.082% 0.077% 0.078% 50 16 WV $0.0668 1.441% 1.369% 1.379% 51 9 WY $0.0602 1.396% 1.346% 1.351% 

Summary:

Minimum = $0.0602 0.0000% 0.0000% 0.0000% 

Maximum = $0.1892 5.5822% 5.5119% 5.5313% 

Average = $0.0985 0.7489% 0.7039% 0.7076% 

Median = $0.0860 0.5205% 0.4860% 0.4876% 

Nationwide = $0.0884 0.795% 0.758% 0.761% 

Because this price analysis is based only on the 495 potentially affected coal-fired electric utility plants (with 333,500 capacity) rather than on all electric utility and independent electricity producer plants in each state using other fuels s

nuclear, hydroelectric, etc. (with 678,200 megawatts nameplate capacity), these price effects are higher than would be 

were averaged over the entire electric utility and independent electricity producer supply (totaling 1,011,700 megawa76,100 megawatts of combined heat and electricity producers).89

89 Source: 2007 megawatt nameplate capacity data from the Energy Information Administration “Table 2.3. Existing Capacity by Producer T

http://www.eia.doe.gov/cneaf/electricity/epa/epaxlfile2_3.pdf 
• Electricity Impact Findings 

On a nationwide basis for all 495 plants, compared to the estimated average electricity price of $0.0884 per kilowatt-h

the 100% regulatory cost pass-thru scenario may increase prices for the 495 plants by 0.172% to 0.795% across the rsummarized in Exhibit 5A-3 below. Although none of the regulatory options exceed the 1% threshold of EO 13211, 

uncertainty factors listed in the Sensitivity Analysis Chapter of this RIA may increase the cost estimate upwards of 40

in a possible 100% regulatory cost pass-thru high-end estimate of x% (i.e., (0.795% for Option 1 with land disposal tr1.113%), this RIA includes a “Statement of Energy Effect” (Appendix K), as required by Section 1 of EO 13211. 

Exhibit 5A-3 

Summary of Potential Future Increase in Retail Electricity Prices Charged by Coal-Fired Electric Utility P

Regulatory cost 

estimate range 

Option 1 

(Preferred Option) 

Average price 

increase 

Option 2 

Average price 

increase 

Opt

Avera

inc

Low-end from Exhibit 5A-1 (without the land disposal treatment sub-option) 0.209% 0.172% 0.1High-end from Exhibit 5A-2 (with the land disposal treatment sub-option) 0.795% 0.758% 0.7

For actions likely to have a significant adverse energy effect, Section 2 of the EO 13211 requires agencies to consider the action. Part 7 of OMB’s July 13, 2001 guidance (i.e., Memorandum M-01-27) for implementing EO 13211 lists salternatives, of which the fifth example “Alternative Levels of Stringency” is included in this RIA and the CCR propo

regulatory options and sub-option described in this RIA represent alternative stringency levels of regulation, as evideconditions, as well as the relatively broad range in estimated industry and state/local government costs for each optionExhibit 5A-3 above, all options without the land disposal treatment sub-option provide less-stringent alternatives belfor this evaluation, even with a cost estimate uncertainty factor of +40% added (i.e., even if the average price increasemultiplied by a high-end cost uncertainty factor of 1.40). 
5B. State-by-State Distribution of Incremental CCR Regulatory Costs Exhibit 5B below summarizes the distribution of estimated regulatory costs on a state-by-state basis and by option (i

regulatory costs without the land disposal treatment sub-option, and Exhibit 5B-2 for costs with the sub-option). Thi

is a simple apportionment of nationwide average annualized cost under each option according to state-by-state annua

by the 495 coal-fired electric utility plants. 

Exhibit 5B-1 

State-by-State Distribution of Estimated Incremental Costs for Regulatory Options 

Without Land Disposal Treatment Sub-Option 

($million average annualized cost in 2009$ over 50-year period of analysis 2012 to 2061) 

A B C D E F G 

Item State 

# of coalfired 

electricity 

plants 

2005 CCR 

generation by 

coal-fired 

electric utility 

plants (tons/year) 

State % of 

nationwide CCR 

generation (based 

on Column D) 

Option 1 

Subtitle C 

hazardous waste 

Option 2 

Subtitle D 

non-hazardous waste 

SubtitSubtit

1 AK 2 46,179 0.03% $0.2 $0.2 2 AL 16 3,210,337 2.27% $15.7 $12.9 3 AR 4 744,267 0.53% $3.0 $2.5 4 AZ 8 3,334,030 2.36% $13.4 $11.0 5 CA 6 159,927 0.11% $0.6 $0.5 6 CO 12 1,704,433 1.21% $6.8 $5.6 7 CT 0 172,280 0.12% $0.7 $0.6 8 DC 0 0 0.00% $0.0 $0.0 9 DE 2 251,205 0.18% $1.0 $0.8 

10 FL 15 6,132,345 4.34% $29.9 $24.6 11 GA 13 6,077,700 4.30% $24.7 $20.3 12 HI 1 58,968 0.04% $0.2 $0.2 13 IA 15 1,136,289 0.80% $4.6 $3.8 14 ID 0 0 0.00% $0.0 $0.0 15 IL 17 3,856,748 2.73% $15.9 $13.1 16 IN 33 8,798,845 6.23% $36.6 $30.1 17 KS 8 1,495,099 1.06% $6.0 $4.9 18 KY 31 9,197,567 6.51% $39.7 $32.6 19 LA 3 1,614,800 1.14% $6.5 $5.3 20 MA 0 363,150 0.26% $1.5 $1.2 21 MD 4 1,932,740 1.37% $7.8 $6.4 22 ME 1 48,000 0.03% $0.2 $0.2 23 MI 24 2,369,673 1.68% $9.5 $7.8 24 MN 20 1,525,979 1.08% $6.1 $5.0 
Exhibit 5B-1 

State-by-State Distribution of Estimated Incremental Costs for Regulatory Options 

Without Land Disposal Treatment Sub-Option 

($million average annualized cost in 2009$ over 50-year period of analysis 2012 to 2061) 

A B C D E F G 

Item State 

# of coalfired 

electricity 

plants 

2005 CCR 

generation by 

coal-fired 

electric utility 

plants (tons/year) 

State % of 

nationwide CCR 

generation (based 

on Column D) 

Option 1 

Subtitle C 

hazardous waste 

Option 2 

Subtitle D 

non-hazardous waste 

SubtitSubtit

25 MO 20 2,679,742 1.90% $10.8 $8.8 26 MS 6 1,229,400 0.87% $4.9 $4.1 27 MT 5 1,830,624 1.30% $7.3 $6.0 28 NC 27 5,504,531 3.90% $22.8 $18.8 29 ND 9 3,038,100 2.15% $12.2 $10.0 30 NE 6 614,473 0.44% $2.5 $2.0 31 NH 1 176,900 0.13% $0.7 $0.6 32 NJ 2 735,214 0.52% $3.0 $2.4 33 NM 4 3,983,300 2.82% $16.0 $13.2 34 NV 2 391,500 0.28% $1.6 $1.3 35 NY 11 1,479,792 1.05% $6.6 $5.4 36 OH 24 10,429,446 7.39% $48.0 $39.5 37 OK 3 1,490,800 1.06% $6.0 $4.9 38 OR 1 99,900 0.07% $0.4 $0.3 39 PA 28 15,359,680 10.88% $64.3 $52.9 40 RI 0 0 0.00% $0.0 $0.0 41 SC 14 2,178,360 1.54% $8.7 $7.2 42 SD 2 103,753 0.07% $0.4 $0.3 43 TN 12 3,240,120 2.29% $19.3 $15.9 44 TX 18 13,165,728 9.32% $53.0 $43.6 45 UT 7 2,582,144 1.83% $10.4 $8.5 46 VA 13 2,388,526 1.69% $9.6 $7.9 47 VT 0 0 0.00% $0.0 $0.0 48 WA 1 1,405,220 1.00% $5.6 $4.6 49 WI 12 1,412,534 1.00% $5.7 $4.7 50 WV 20 9,231,718 6.54% $38.8 $31.9 51 WY 12 2,224,848 1.58% $8.9 $7.3 

Totals = 495 141.2 million 100% $598 $492 
Exhibit 5B-2 

State-by-State Distribution of Estimated Incremental Costs for Regulatory Options 

With Land Disposal Treatment Sub-Option 

($million average annualized cost in 2009$ over 50-year period of analysis 2012 to 2061) 

A B C D E F G 

Item State 

# of coalfired 

electricity 

plants 

2005 CCR 

generation by 

coal-fired electric 

utility plants 

(tons/year) 

State % of 

nationwide CCR 

generation 

(based on 

Column D) 

Option 1 

Subtitle C 

hazardous waste 

Option 2 

Subtitle D 

non-hazardous waste 

Subtitle Subtitle 

1 AK 2 46,179 0.03% $0.7 $0.7 2 AL 16 3,210,337 2.27% $51.7 $49.3 3 AR 4 744,267 0.53% $12.0 $11.4 4 AZ 8 3,334,030 2.36% $53.7 $51.2 5 CA 6 159,927 0.11% $2.6 $2.5 6 CO 12 1,704,433 1.21% $27.4 $26.2 7 CT 0 172,280 0.12% $2.8 $2.6 8 DC 0 0 0.00% $0.0 $0.0 9 DE 2 251,205 0.18% $4.0 $3.9 

10 FL 15 6,132,345 4.34% $98.8 $94.2 11 GA 13 6,077,700 4.30% $97.9 $93.3 12 HI 1 58,968 0.04% $0.9 $0.9 13 IA 15 1,136,289 0.80% $18.3 $17.4 14 ID 0 0 0.00% $0.0 $0.0 15 IL 17 3,856,748 2.73% $62.1 $59.2 16 IN 33 8,798,845 6.23% $141.7 $135.1 17 KS 8 1,495,099 1.06% $24.1 $23.0 18 KY 31 9,197,567 6.51% $148.1 $141.2 19 LA 3 1,614,800 1.14% $26.0 $24.8 20 MA 0 363,150 0.26% $5.8 $5.6 21 MD 4 1,932,740 1.37% $31.1 $29.7 22 ME 1 48,000 0.03% $0.8 $0.7 23 MI 24 2,369,673 1.68% $38.2 $36.4 24 MN 20 1,525,979 1.08% $24.6 $23.4 25 MO 20 2,679,742 1.90% $43.2 $41.1 26 MS 6 1,229,400 0.87% $19.8 $18.9 27 MT 5 1,830,624 1.30% $29.5 $28.1 28 NC 27 5,504,531 3.90% $88.6 $84.5 29 ND 9 3,038,100 2.15% $48.9 $46.6 30 NE 6 614,473 0.44% $9.9 $9.4 31 NH 1 176,900 0.13% $2.8 $2.7 32 NJ 2 735,214 0.52% $11.8 $11.3 
Exhibit 5B-2 

State-by-State Distribution of Estimated Incremental Costs for Regulatory Options 

With Land Disposal Treatment Sub-Option 

($million average annualized cost in 2009$ over 50-year period of analysis 2012 to 2061) 

A B C D E F G 

Item State 

# of coalfired 

electricity 

plants 

2005 CCR 

generation by 

coal-fired electric 

utility plants 

(tons/year) 

State % of 

nationwide CCR 

generation 

(based on 

Column D) 

Option 1 

Subtitle C 

hazardous waste 

Option 2 

Subtitle D 

non-hazardous waste 

Subtitle Subtitle 

33 NM 4 3,983,300 2.82% $64.1 $61.2 34 NV 2 391,500 0.28% $6.3 $6.0 35 NY 11 1,479,792 1.05% $23.8 $22.7 36 OH 24 10,429,446 7.39% $168.0 $160.1 37 OK 3 1,490,800 1.06% $24.0 $22.9 38 OR 1 99,900 0.07% $1.6 $1.5 39 PA 28 15,359,680 10.88% $247.4 $235.8 40 RI 0 0 0.00% $0.0 $0.0 41 SC 14 2,178,360 1.54% $35.1 $33.4 42 SD 2 103,753 0.07% $1.7 $1.6 43 TN 12 3,240,120 2.29% $52.2 $49.7 44 TX 18 13,165,728 9.32% $212.0 $202.1 45 UT 7 2,582,144 1.83% $41.6 $39.6 46 VA 13 2,388,526 1.69% $38.5 $36.7 47 VT 0 0 0.00% $0.0 $0.0 48 WA 1 1,405,220 1.00% $22.6 $21.6 49 WI 12 1,412,534 1.00% $22.7 $21.7 50 WV 20 9,231,718 6.54% $148.7 $141.7 51 WY 12 2,224,848 1.58% $35.8 $34.2 

Totals = 495 141.2 million 100% $2,274 $2,168 
5C. Small Business Impact Analysis (RFA/SBREFA) According to the requirements of the 1980 Regulatory Flexibility Act (RFA) as amended by the 1996 Small Business Fairness Act (SBREFA), Federal regulatory agencies are required to make initial determinations if proposed regulato

“significant economic impact on a substantial number of small entities” (SISNOSE). Small entities include small bus

organizations, and small governmental jurisdictions. Agencies are required to conduct a Regulatory Flexibility Screemake this determination. This section of the RIA presents the methodology and findings for the RFSA conducted for Unless Agencies are able to certify that a particular regulatory action is not expected to have a SISNOSE, the RFA/SB

analysis of the potential adverse economic impacts on small entities, completion of a Small Business Advocacy Reviestage), preparation of a Small Entity Compliance Guide (final rule stage), and Agency review of the rule within 10 ye

The small business impact analysis of this RIA follows the four analytic steps described in EPA’s RFA/SBREFA ana

Step 1: Determine which small entities are subject to the rule’s requirements 

Step 2: Select appropriate measures for determining economic impacts on these small entities and estimate thStep 3: Determine whether the rule may be certified as not having a significant impact on small entities (SISNStep 4: Document the screening analysis and include the appropriate RFA statements in the preamble 

• Step 1: Identification of Small Entities 

Consistent with EPA’s RFA/SBREFA guidance (page 15), this RIA applies the following small size definitions: 

Small company: Based on the US Small Business size standard for NAICS code 221112 (fossil fue

company which generates less than 4 million megawatt-hours electricity output per yea

Small government: Based on the RFA/SBREFA’s definition (5 US Code section 601(5)) of “small gover

government of a city, county, town, township, village, school district, or special districthan 50,000. 

Based on the nameplate megawatt (MW) capacity for all electricity generating units (including those powered by n

electricity plant from the 2007 DOE-EIA 860 database, this RIA estimated annual megawatt-hours electricitmultiplying the nameplate capacity by (a) 365 days per year, and (b) 24 hours per day to calculate each owner 

90 EPA’s RFA/SBREFA guidance: “EPA’s Action Development Process: Final Guidance for EPA Rulewriters: Regulatory Flexibility Act as 

Business Regulatory Enforcement Fairness Act”, EPA Office of Policy, Economics & Innovation, Nov 2006, 105 pages: http://www.epa.gov/sbrefa/documents/rfaguidance11-00-06.pdf 
capacity. Appendix C of this RIA indicates the assigned size of the owner company or city government for each elec

to two size categories: “Small” or “Non-small”.91

Exhibit 5C below presents the resultant count and summary of the characteristics of the small electric utility entities 

Exhibit 5C 

Summary of Characteristics of Small Electric Utility Entities 

A B C D 

Small Entity Sub-Categories 

Count of coalfired electric 

utility plants 

(2005/2007) 

Estimated count of 

owner entities 

(2005/2007) 

Estimated 2007 annual 

megawatt hours (mwh) 

capacity for all electricity 

plants owned by all 

entities 

Estimated 2009 

annual electricity 

sales for all entities 

($millions/year) 

1. Small City Government 33 33 34.0 $2,592 2. Small Company 12 11 10.6 $948 3. Small Cooperative 6 6 12.0 $947 4. Small County Government 1 1 0.3 $23 Summary: 

All small entities = 52 plants 

(11%) 

51 entities 

(26%) 

 56.8 

(1%) 

$4,509 

(1%) 

All non-small entities = 443 plants 

(89%) 

149 entities 

(74%) 

5,380.5 

(99%) 

$419,056 

(99%) 

All entities (non-small + small) = 495 plants 200 entities 5,437 million mwh* $423,565** 

Notes: * Annual electricity generation capacity based on all electric plants and types of electric generation units (e.g. coal-fired, oil-fired, hy

wind, biomass, etc.) owned by these companies, not just coal-fired electricity generation capacity. ** $423.6 billion per year annual electricity sales estimated in this RIA is 73% of the $581.6 billion per year total revenues reported (Utilities sector) in the 2007 Economic Census at: http://factfinder.census.gov/servlet/IBQTable?_bm=y&-geo_id=D&-ds_name=EC

91 It should be noted that some of the companies identified as small using the SBA size standard for NAICS 22 and the utility code specificat

database to identify each corporate entity may be subsidiaries of a larger holding company (classified under a different NAICS) rather than a addition some of these power companies may have merged. For example, State Line is owned by Dominion Resources of Virginia, NortheaEnergy North America, Inc. (SEGNA), Rio Bravo Poso and Rio Bravo Jasmin are owned by the North American Power Group, Ltd (NAPG)

owned by TONDU, Public Service Enterprise Group (PSEG) and Excelon are merged. This approach likely overstates the number of small e
• Step 2: Measures for Determining Economic Impacts on Small Entities 

According to Table 1 of EPA’s 2006 RFA/SBREFA small business impact analytic guidance, there are the following 

be used to determine if small entities may be significantly impacted by a proposed rule: 

• Small business impact tests: 

o Sales test: Annualized compliance costs as a percentage of sales o Cash flow test:Debt-financed capital compliance costs relative to current cash flow o Profit test: Annualized compliance costs as a percentage of profits 

• Small government impact tests: 

o Revenue test: Annualized compliance costs as a percentage of annual government revenues o Income test: Annualized compliance costs to household (per capita) as a percentage of median house

Based on annual electricity generation data for the small owner entities in the electric utility industry identified in Ap

annual sales/annual revenue test was used for this analysis. As itemized and estimated for each owner entity in the spAppendix L to this RIA, for each small entity computed the respective sales revenue test percentages by the equation 

(AEGC x 1,000) x (ASP) x (CU) = annual $sales or $revenues per small entity 

Where: 

AEGC = Annual electricity generation capacity per-entity in annual million megawatts (per-entity mega

Appendix C). This estimate involved downloading the annual million megawatt capacity data electricity plants from the DOE-EIA website (2007), and then multiplying the capacity data by 

o 365 operating days per year o 24 operating hours per day 

ASP = February 2009 average statewide retail price to ultimate consumers for electricity (i.e., cents pe

relevant state or states applicable to the location of electric plants owned by each company; ele

composite price charged to residential, commercial, industry and transportation sectors92

CU = 86.8% electric utility industry capacity utilization from 1972-2008 average reported by the 15 M

Statistical Release G.17 “Industrial Production & Capacity Utilization” data for Utilities at: 

http://www.federalreserve.gov/releases/g17/Current/default.htm 

92 DOE’s Energy Information Administration (EIA) publishes state-by-state average retail electricity prices for four end-user sectors (i.e., re

industrial, transportation) and on a composite basis at: http://www.eia.doe.gov/cneaf/electricity/epm/table5_6_a.html
• Step 3 & Step 4: Determine and document whether the proposed rule may be certified as having “No SISN

Determined whether each regulatory option may have a “significant impact on a substantial number of small entities” 

may become subject to the requirements of the proposed rule. This determination involved comparing the estimated 

costs for each entity as displayed in Appendix I of this RIA, to the respective annual sales and revenues for each entiabove. Numerically, this comparison involved calculating the percentage of regulatory compliance costs relative to a

for each company for each of the regulatory options. Then compared the percentage results for each small entity to th

thresholds defined in Table 2 of EPA’s RFA/SBREFA analytic guidance. Exhibit 5D below displays the numerical rthe suggested RFA/SBREFA impact interpretation according to the three thresholds. 

<1% threshold: Annualized regulatory costs may be less then 1% of annual sales or revenues fo1% or more threshold: Annualized regulatory costs may be 1% or more of annual sales or revenues for 3% or more threshold: Annualized regulatory costs may be 3% or more of annual sales or revenues for 
Exhibit 5D 

Estimated Impact of Regulatory Options on Small Entities (RFA/SBREFA Analysis Results) 

($millions average annualized direct costs @7% discount rate over 50-year period 2012-2061) 

Cost as Percentage of 

Annual Electricity Revenues 

Option 1 

(Preferred Option) 

Subtitle C hazardous waste 

Option 2 

Subtitle D 

non-hazardous waste 

Option 

Subtitle C for mpoSubtitle D for land

A. Count of Small Entities: Without land disposal treatment: $16.4 $3.9 $3.9 

Less than 1% 46 50 50 

1% or greater 5 1 1 3% or greater 0 0 0 

With land disposal treatment: $17.3 $4.7 $4.8 

Less than 1% 46 50 50 

1% or greater 5 1 1 3% or greater 0 0 0 

B. % of Small Entities: Without land disposal treatment: 

Less than 1% 90% 98% 98% 

1% or greater 10% 2% 2% 3% or greater 0% 0% 0% 

With land disposal treatment: 

Less than 1% 90% 98% 98% 

1% or greater 10% 2% 2% 3% or greater 0% 0% 0% 

C. SISNOSE Findings: Without land disposal treatment: 

Less than 1% Presumed No SISNOSE Presumed No SISNOSE Presumed No S

1% or greater Presumed No SISNOSE Presumed No SISNOSE Presumed No S3% or greater Presumed No SISNOSE Presumed No SISNOSE Presumed No S

With land disposal treatment: 

Less than 1% Presumed No SISNOSE Presumed No SISNOSE Presumed No S

1% or greater Presumed No SISNOSE Presumed No SISNOSE Presumed No S3% or greater Presumed No SISNOSE Presumed No SISNOSE Presumed No S
• Limitations of RFA/SBREFA Determination 

Not included in the RFA/SBREFA analysis of this RIA are two factors unique to the electric utility industry, which m

entity impacts relative to the estimates above in this RIA: 

• Factor #1 of 2: According to the 2007 DOE-EIA database on electric utility plants, two-thirds of the coal-fi

units at electric utility plants owned by small entities can switch to at least one of six other fuels: 

1. Agricultural byproducts (database code = AB) 2. Distillate fuel oil (DFO) 3. Natural gas (NG) 4. Petroleum coke (PC) 5. Propane (PG) 6. Wood & wood waste solids (WDS) 

• Factor #2 of 2: The small business impact analysis in this RIA applies the full industry compliance cost to t

However, because consumer demand for electricity is (a) highly price-inelastic and (b) projected go grow b

electric utility plants may be expected to pass-thru much, if not all, of their regulatory costs (pending state ghike approval). The next section of this RIA evaluates the possibility of regulatory compliance cost pass-th

• Compliance Cost Pass-Thru Analysis 

o Ability to Raise Electricity Prices 

Traditionally, the electric utility industry has functioned as a regulated monopoly, providing essential electrical servicfranchise in exchange for having rates closely regulated by State public utility commissions (PUCs; sometimes called commissions) and the Federal Energy Regulatory Commission (FERC). The FERC regulates rates charged for sales 

utilities, even if they are in the same state. It also regulates the pricing and use of transmission for wheeling, and asse

mergers. In most states (California de-regulated electricity in 1998), the PUCs/PSCs set allowable rates upon applicaother affected parties allowed to present testimony. By law the utility must recover its cost of service, which includes expenses and a "fair" return on equity.94

93 30% additional electricity demand forecst for year 2025 relative to year 2005, from slide 17 of “Energy & Water: Emerging Issues and Tra

and Mike Hightower, Sandia National Laboratories, at: http://www.ct-si.org/Summit2007/spk/RKottenstette.pdf 

94 Source: “Electric Utility Regulation” by Robert J. Michaels in the Concise Encyclopedia of Economics at: 

http://www.econlib.org/library/Enc1/ElectricUtilityRegulation.html 
Based on the electricity ratemaking process described by the Pennsylvania PUC95as a case example, when an electric 

price increase (aka rate hike), it must file a request with the PUC showing the proposed new rates and effective date, increase is needed. The utility also must notify customers at least 60 days in advance. The notice must include the amincrease, the proposed effective date, and how much more the ratepayer can expect to pay. Under the law, the utility 

its reasonably incurred expenses and a fair return on its investment. The PUC evaluates each utility’s request for a racriteria. During the investigation, hearings are held before an Administrative Law Judge (ALJ) at which the evidence increase is examined and expert witnesses testify. In addition, consumers are offered an opportunity to voice their opiBriefs may be submitted by the formal parties. A recommendation to the PUC is made by the ALJ. Finally, the matt

Commissioners for a vote and final decision. Together with the 60-day notice period, the rate increase process takes Recent (2008) examples of requested or PUC-approved electricity rate hikes are summarized in Exhibit 5E below:96

Exhibit 5E 

Summary of 2008 US Electricity Price Hikes

Item State Effective date Requested or approved price hike 

1 AL Oct 2008 14.6% 2 CO Feb 2008 28% 3 FL July to Oct 2008 10 to 37% (8 companies) 4 KS 2008 15% 5 MO Jan 2008 28% 6 NC Sept 2008 to Jan 2009 10% to 17.7% (3 companies) 7 SC July to Oct 2008 6% to 10% (4 companies) 8 TVA (7 states) Oct 2008 20% 

Overall range = Jan to Oct 2008 6% to 37% 

Average (20 electricity plant owner entities) = 19% 

Some state governments have deregulated the electric utility industry, thereby allowing multiple electric suppliers, no

electricity supplier, to compete and set their own retail prices in those state markets. As of 2003, 18 states have dereg

soon deregulate:97

• Deregulated states (18): AZ, CT, DE, DC, IL, ME, MD, MA, MI, NH, NJ, NY, OH, OR, PA, RI, TX, V

(11 of these states no longer have a price cap) 

95 Source: Pennsylvania Public Utility Commission, “The PUC Ratemaking Process and the Role of Consumers”, January 2008 at: 

http://www.puc.state.pa.us/general/consumer_ed/pdf/Ratemaking_Complaints.pdf 

96 Source: “Recent Examples of Rate Increases in Vertically Integrated States”, The Compete Coalition, Washington DC, 05 November 2008 

http://www.competecoalition.com/resources/recent-examples-rate-increases-vertically-integrated-states 

97 Source: “Status of State Electric Industry Restructuring Activity as of February 2003”, US Dept of Energy, Energy Information Administr

http://www.eia.doe.gov/cneaf/electricity/chg_str/restructure.pdf 
• May soon deregulate (6): AR, MT, NM, NV, OK, WV (note: CA deregulated in 1998 but has suspended) 

While average prices rose 21% in regulated states from 2002 to 2006, prices increased 36% during that period in 11 owhere rate caps expired, suggesting greater pricing flexibility in deregulated states.98

o Inelastic Demand for Electricity 

At the wholesale level, as a result of technological and regulatory barriers, the majority of electricity pricing plans do and react to the actual market value of their electricity consumption/ conservation. Since end-users do not face the remaking their consumption decisions, there is little demand reaction to changes in real time wholesale electricity price

consumer demand for electricity has been largely inelastic. The lack of real time metering at the retail level means th

how much they use or indeed how much electricity costs until after the fact. Thus consumers cannot react to high pri

consumption.100

o Cost Pass-Thru Conclusion 

Based on the above three cost pass-thru factors consisting of (a) 20 examples of recent (2008) PUC-regulated rate hik19% per company which far exceeds the 1% and 3% SISNOSE screening analysis thresholds defined by EPA’s guida

deregulated states which have de-regulated the price of electricity, and (c) the fact that consumer demand for electriciinelastic, this RIA concludes that it is likely that electric utility suppliers could pass-thru all, or nearly all, of the futurregulatory compliance costs for the CCR proposed rule such that a significant impact on small entities and non-small 

98 Source: “Shocking Electricity Prices Follow Deregulation”, USA Today, 10 Aug 2007 at: http://www.usatoday.com/money/industries/ene

prices_n.htm 

99 Source: page 1 of “Demand Responsiveness in Electricity Markets”, Ronald Lafferty et al., Office of Markets, Tariffs and Rates, 15 Jan 2

http://www.naseo.org/committees/energyproduction/documents/demand_responsiveness_in_electricity_markets.pdf 

100 Source: “Power Price Volatility and Risk Management: An Introduction”, Anne Ku, Sept 2000 (this is the original, unedited article, later Business magazine Sept/Oct 2000) at: http://www.analyticalq.com/energy/volatility/default.htm 
5D. Minority & Low-Income Population Statistics (Executive Order 12898)

Under the 1994 Executive Order (EO) 12898101 it is the responsibility of Federal agencies to the greatest extent pract

law, and consistent with the principles set forth in the report on the National Performance Review, each Federal agen

environmental justice (EJ) part of its mission by identifying and addressing, as appropriate, disproportionately high a

or environmental effects of its programs, policies, and activities on (a) minority populations and (b) low-income pop

defined in EO 12898, for purpose of this RIA the following definitions are applied: 

• Minority population: Numerically measured according to Census Bureau “non-white” statistics • Low-income population: Numerically measured according to Census Bureau “individuals below poverty

Furthermore, section 3-302(b) of EO 12898 provides a trigger which indicates that Federal agencies shall collect and facilities or sites expected to have “substantial environmental, human health, or economic effect” when such facilities 

to “substantial” Federal environmental action: 

“In connection with the development and implementation of agency strategies in section 1-103 of this order, e

agency, whenever practicable and appropriate, shall collect, maintain and analyze information on the race, nincome level, and other readily accessible and appropriate information for areas surrounding facilities or sitesubstantial environmental, human health, or economic effect on the surrounding populations, when such facibecome the subject of a substantial Federal environmental administrative or judicial action. Such information available to the public unless prohibited by law.” 

The EO 12898 does not establish quantitative thresholds for “substantial effect” on the surrounding populations, nor dquantitative threshold. This RIA uses the (1) CCR disposal baseline environmental and human health hazards (e.g., denvironmental and human health protection objectives described in the CCR proposed rule, as indicators of “substant

reason, this section of the RIA presents an EJ data collection and analysis involving a 5-step process to compare mino

population data for each electric utility plant location, to respective statewide population data, to identify whether thegroups disproportionately reside in geographic areas where electric utility plants are located. In addition, this RIA idaffects of the CCR proposed rule on (a) environmental justice populations surrounding offsite landfills which may recenvironmental justice populations within electric utility plant customer service areas. 

101 Source: 1994 Executive Order 12898 is available at: http://www.epa.gov/fedrgstr/eo/eo12898.htm102 The US Census Bureau defines “poverty” following the Office of Management and Budget's (OMB) Statistical Policy Directive 14. The 

money income thresholds that vary by family size and composition to determine who is in poverty. If a family’s total income is less than the 

family and every individual in it is considered in poverty. Poverty income thresholds are available at http://www.census.gov/hhes/www/pov
• Collection of Minority & Low-Income Demographic Data 

Step 1: Plant address 5-digit zip codes formed the geographic basis for this EJ population data collection. Because zi

irregularly shaped geographic areas, this zip code based data collection may be considered a “screening level” 

of Census uses over 33,000 “Zip Code Tabulation Areas” (ZCTA) for its Census counts of population and othbased on the US Postal Service’s over 42,000 nationwide zip codes.103 Currently, there are no size restriction

small a ZCTA can be in terms of either a minimum/maximum number of housing units or geographic area. A

be as small as a few city blocks or may cover many square miles. Many ZIP codes are for villages, census-de

of cities, or other entities that are not municipalities. The nationwide average zip code population is about 7,2million mid-2009 US population) / (42,500 zip codes)). The nationwide average zip code area is about 83 squsquare miles total US land and water area) / (42,500 zip codes)), which is a land area equivalent to a five-mile sq.miles) / (3.1416))^0.5). In comparison, the radial area monitored for contamination in response to the DeceKingston TN electric plant CCR spill is reportedly four miles,104and this average four-mile zip code radial dis

mile to 15-mile radial distances used by EPA’s Superfund “Hazard Ranking System” (HRS) to define affected having either (a) soil contamination only (1-mile), (b) groundwater and/or airborne contamination (4-miles), o

contamination (15-miles downstream). More information about EPA’s HRS is available at http://www.epa.gov/superfund/programs/npl_hrs/hrsint.htm. Using the Census search engine Factfinder (http:factfinder.census.gov/home/saff/main.html?_lang=en), retriefor 464 (94%) of the 495 electric utility plants. For 42 plants (8%) there was no zip code Census data because 

complete address data from DOE, or because the Census search engine did not have data for the zip code. 

Step 2: Collected statewide percentage data for minority and low-income subgroups for purpose of benchmark comp

by-plant sub-group population statistics. 

o Collected low-income population statewide percentages (3-year averages for 1998 to 2000) from the f

Bureau website: http://www.census.gov/hhes/www/poverty/poverty00/tabled.pdf

o Collected statewide percentages for white population sub-group (data year 2000) from the Census Bur

http://www.census.gov/prod/2001pubs/c2kbr01-4.pdf. Subtracting the percentage of white population 

100% to produced the respective minority percentage for each state. For data year 2000, the Census Bthe white population classification by collecting both data for people who claimed to be “white-only” claimed to be “mixed white”. Since the purpose of the EJ analysis is to evaluate all minorities, this ste

collecting the “white-only” data in order to calculate the minority percentage which includes people w

of mixed race. Exhibit 5F below displays the statewide Census data for low-income and minority sub

103 Source: US Census Bureau ZIP Code Tabulation Area (ZCTA) Frequently Asked Questions at: http://www.census.gov/geo/ZCTA/zctafa

zip code count is from the US Postal Service’s FAQ website at: http://zip4.usps.com/zip4/welcome.jsp 

104 Source: 4 mile radial monitoring area reported by Waste & Recycling News, 13 Feb 2009; http://www.wasterecyclingnews.com/email.htm
Exhibit 5F 

Statewide Benchmark Data on Low-Income and Minority Populations (2000) 

Item State Low Income % Minority % 

1 AK 8.4% 30.7% 2 AL 14.7% 28.9% 3 AR 15.8% 20.0% 4 AZ 13.5% 24.5% 5 CA 14.0% 40.5% 6 CO 8.5% 17.2% 7 CT 7.7% 18.4% 8 DC 17.4% 69.2% 9 DE 9.9% 25.4% 

10 FL 12.1% 22.0% 11 GA 12.5% 34.9% 12 HI 10.6% 75.7% 13 IA 7.9% 6.1% 14 ID 13.3% 9.0% 15 IL 10.5% 26.5% 16 IN 8.3% 12.5% 17 KS 10.5% 13.9% 18 KY 12.5% 9.9% 19 LA 18.5% 36.1% 20 MA 10.1% 15.5% 21 MD 7.3% 36.0% 22 ME 9.8% 3.1% 23 MI 10.2% 19.8% 24 MN 7.8% 10.6% 25 MO 9.8% 15.1% 26 MS 15.5% 38.6% 27 MT 16.% 9.4% 28 NC 13.2% 27.9% 

Item State Low Income % 

29 ND 12.7% 30 NE 10.7% 31 NH 7.6% 32 NJ 8.1% 33 NM 19.3% 34 NV 10.1% 35 NY 14.7% 36 OH 11.1% 37 OK 14.1% 38 OR 12.9% 39 PA 9.8% 40 RI 10.2% 41 SC 12.0% 42 SD 9.4% 43 TN 13.4% 44 TX 14.9% 45 UT 8.1% 46 VA 8.1% 47 VT 10.3% 48 WA 9.5% 49 WI 9.0% 50 WV 15.8% 51 WY 11.1% 

 Min = 7.3% (MD)  Max = 19.3% (NM)  National = 11.9% 
• Comparison of Minority & Low-Income Populations Surrounding Electric Utility Plants to Statewide Be

Step 3, Step 4 and Step 5 of this evaluation described below involved three complementary levels of data comparisonalso involved two complementary numerical comparisons, one based on calculating numerical percentages and the ot

1. Plant level: Plant-by-plant disaggregated data comparison to statewide benchmarks 

2. State level: State-by-state aggregated plant data comparison to statewide benchmarks 

3. Nationwide level: Nationwide aggregated plant data comparison to nationwide benchmarks 

• Calculation of Three Alternative Demographic Statistics Comparison Methods 

Step 3: On a plant-by-plant basis, compared the plant zip code percentage minority and percentage low-income popu

respective statewide average percentages for each sub-group. This constituted the 1st level of data comparison

Step 4: For purpose of summary, aggregated the plant level population comparison data for each state as displayed in 

constituted the 2nd level of data comparison. There are no data displayed for DC, ID, RI or VT because there 

utility plants in those states. Appendix M of this RIA presents the plant-by-plant Census data on which this E

also involved aggregating the data across all 495 plants for comparison with the nationwide aggregate minorit

percentage benchmarks. This constituted the 3rd level of data comparison. 

Exhibit 5G 

Minority and Low-Income Population Data Aggregated on State-by-State Basis 

A B C D E F 

(E/D) 

G 

(Exh 5F) 

H 

(DxG) 

I J K 

(DxJ) 

L 

(Exh 

General Population Data Low Income Population Data (Below Poverty) Minority Pop

Item State 

ZIP 

code 

count 

2000 

population 

residing in 

electric utility 

plant zip code 

areas 

Count of 

plant zip 

code 

residents 

below 

poverty 

level 

% of plant zip 

code residents 

below poverty 

level 

State % 

below 

poverty 

level 

Expected 

count of 

residents 

below 

poverty 

based on 

state% 

Count of 

plants with 

zip% > 

state% 

poverty 

level 

% of 

plant zip 

code 

residents 

that are 

minority 

Count of 

plant zip 

code 

residents 

that are 

minority 

Sta

wid

mino

1 AK 2 18,552 2,284 12.31% 8.40% 1,558 1 31.95% 5,928 30.72 AL 9 82,854 20,331 24.54% 14.70% 12,180 6 42.17% 34,942 28.93 AR 3 11,786 1,214 10.30% 15.80% 1,862 0 7.74% 912 20.04 AZ 6 34,941 7,433 21.27% 13.50% 4,717 5 43.70% 15,270 24.55 CA 4 112,895 24,749 21.92% 14.00% 15,805 5 45.22% 51,049 40.56 CO 15 214,095 29,395 13.73% 8.50% 18,198 10 17.88% 38,275 17.27 CT 2 42,716 6,427 15.05% 7.70% 3,289 1 45.14% 19,284 18.48 DC ND 
Exhibit 5G 

Minority and Low-Income Population Data Aggregated on State-by-State Basis 

A B C D E F 

(E/D) 

G 

(Exh 5F) 

H 

(DxG) 

I J K 

(DxJ) 

L 

(Exh 

General Population Data Low Income Population Data (Below Poverty) Minority Pop

Item State 

ZIP 

code 

count 

2000 

population 

residing in 

electric utility 

plant zip code 

areas 

Count of 

plant zip 

code 

residents 

below 

poverty 

level 

% of plant zip 

code residents 

below poverty 

level 

State % 

below 

poverty 

level 

Expected 

count of 

residents 

below 

poverty 

based on 

state% 

Count of 

plants with 

zip% > 

state% 

poverty 

level 

% of 

plant zip 

code 

residents 

that are 

minority 

Count of 

plant zip 

code 

residents 

that are 

minority 

Sta

wid

mino

9 DE 3 46,925 3,979 8.48% 9.90% 4,646 1 28.86% 13,543 25.4

10 FL 13 224,502 23,866 10.63% 12.10% 27,165 5 20.76% 46,617 22.011 GA 9 202,973 29,461 14.51% 12.50% 25,372 4 42.66% 86,581 34.912 HI 1 25,054 1,150 4.59% 10.60% 2,656 0 78.17% 19,584 75.713 IA 14 324,050 31,434 9.70% 7.90% 25,600 13 7.02% 22,744 6.114 ID ND 15 IL 23 455,834 83,407 18.30% 10.50% 47,863 14 41.46% 188,970 26.516 IN 17 323,323 25,460 7.87% 8.30% 26,836 10 6.96% 22,488 12.517 KS 6 59,517 7,718 12.97% 10.50% 6,249 4 36.76% 21,881 13.918 KY 17 255,033 32,497 12.74% 12.50% 31,879 7 8.48% 21,615 9.919 LA 4 30,381 7,546 24.84% 18.50% 5,620 3 45.16% 13,721 36.120 MA 3 95,798 14,420 15.05% 10.10% 9,676 1 20.69% 19,819 15.521 MD 7 101,141 10,622 10.50% 7.30% 7,383 4 12.39% 12,527 36.022 ME 1 6,748 1,037 15.37% 9.80% 661 1 1.30% 88 3.123 MI 20 383,284 30,735 8.02% 10.20% 39,095 8 10.56% 40,477 19.824 MN 15 187,012 20,910 11.18% 7.80% 14,587 10 10.78% 20,157 10.625 MO 19 251,484 24,714 9.83% 9.80% 24,645 10 7.47% 18,794 15.126 MS 4 69,209 17,675 25.54% 15.50% 10,727 3 51.63% 35,735 38.627 MT 5 53,209 8,441 15.86% 16.00% 8,513 2 13.25% 7,050 9.428 NC 16 238,874 37,388 15.65% 13.20% 31,531 9 34.49% 82,397 27.929 ND 5 27,087 2,440 9.01% 12.70% 3,440 1 4.40% 1,193 7.630 NE 6 79,313 8,992 11.34% 10.70% 8,486 2 11.38% 9,027 10.431 NH 2 53,302 4,355 8.17% 7.60% 4,051 2 5.40% 2,877 4.032 NJ 6 119,286 17,958 15.05% 8.10% 9,662 3 43.96% 52,438 27.433 NM 4 17,491 4,638 26.52% 19.30% 3,376 3 55.72% 9,746 33.234 NV 3 8,471 823 9.72% 10.10% 856 1 15.75% 1,334 24.835 NY 13 226,416 29,187 12.89% 14.70% 33,283 3 17.42% 39,451 32.136 OH 23 391,705 42,242 10.78% 11.10% 43,479 7 12.24% 47,953 15.037 OK 6 30,357 6,117 20.15% 14.10% 4,280 4 38.84% 11,791 23.838 OR 1 3,884 596 15.35% 12.90% 501 1 39.19% 1,522 13.439 PA 28 167,254 15,499 9.27% 9.80% 16,391 15 6.61% 11,048 14.640 RI ND 41 SC 12 222,414 28,746 12.92% 12.00% 26,690 8 31.40% 69,831 32.842 SD 2 30,508 1,763 5.78% 9.40% 2,868 1 5.55% 1,694 11.3
Exhibit 5G 

Minority and Low-Income Population Data Aggregated on State-by-State Basis 

A B C D E F 

(E/D) 

G 

(Exh 5F) 

H 

(DxG) 

I J K 

(DxJ) 

L 

(Exh 

General Population Data Low Income Population Data (Below Poverty) Minority Pop

Item State 

ZIP 

code 

count 

2000 

population 

residing in 

electric utility 

plant zip code 

areas 

Count of 

plant zip 

code 

residents 

below 

poverty 

level 

% of plant zip 

code residents 

below poverty 

level 

State % 

below 

poverty 

level 

Expected 

count of 

residents 

below 

poverty 

based on 

state% 

Count of 

plants with 

zip% > 

state% 

poverty 

level 

% of 

plant zip 

code 

residents 

that are 

minority 

Count of 

plant zip 

code 

residents 

that are 

minority 

Sta

wid

mino

43 TN 8 158,267 26,572 16.79% 13.40% 21,208 4 37.38% 59,159 19.844 TX 17 98,402 14,147 14.38% 14.90% 14,662 10 22.41% 22,052 29.045 UT 6 34,209 3,885 11.36% 8.10% 2,771 6 5.22% 1,784 10.846 VA 15 220,800 21,822 9.88% 8.10% 17,885 11 37.78% 83,411 27.747 VT ND 48 WA 1 21,842 3,394 15.54% 9.50% 2,075 1 9.54% 2,083 18.249 WI 13 178,705 23,577 13.19% 9.00% 16,083 8 12.00% 21,446 11.150 WV 13 64,771 15,577 24.05% 15.80% 10,234 11 6.45% 4,179 5.051 WY 8 69,736 6,439 9.23% 11.10% 7,741 1 4.92% 3,428 7.9

Summary: 

Column totals 430 6,076,410 783,062 12.9% 11.9% 658,336 240 21.7% 1,317,895 24.

18.9% 

 Min = 4.6% 7.3% 1.3% 3.1 Max = 26.5% 19.3% 78.2% 75.

Extrapolated to 495 plants = 256 
Step 5: Ratios: Compared the percentages of minority and low-income populations surrounding the plants to their re

benchmark percentages and to the nationwide percentages of these populations as calculated in Step 4, by calc

between the plant zip code group populations compared to statewide and nationwide percentages of minority populations. The purpose of these ratios is to indicate the relative degree by which the percentages are below 

percentages. Exhibit 5H below displays the results. 

Exhibit 5H 

Comparison of Minority and Low-Income Populations Near Coal-Fired Electric Utility Plants to Statewide Per

A B C D E F (D–E) G (D/E) H I J 

Low-Income Data Comparison Minority Data Com

Item State 

Count of 

plants 

Percent 

LowIncome 

Population 

Surroundin

g Plants 

Statewide 

Low-Income 

Percentage Difference Ratio 

Percent 

Minority 

Population 

Surrounding 

Plants 

Statewide 

Minority 

Percentage Di

1 AK 2 12.3% 8.4% 3.9% 1.47 32.0% 30.7% 2 AL 9 24.5% 14.7% 9.8% 1.67 42.2% 28.9% 3 AR 3 10.3% 15.8% -5.5% 0.65 7.7% 20.0% -4 AZ 6 21.3% 13.5% 7.8% 1.58 43.7% 24.5% 5 CA 5 21.9% 14.0% 7.9% 1.57 45.2% 40.5% 6 CO 15 13.7% 8.5% 5.2% 1.62 17.9% 17.2% 7 CT 2 15.0% 7.7% 7.3% 1.95 45.1% 18.4% 8 DC NR NA NA NA NA NA NA 9 DE 3 8.5% 9.9% -1.4% 0.86 28.9% 25.4% 

10 FL 14 10.6% 12.1% -1.5% 0.88 20.8% 22.0% 11 GA 9 14.5% 12.5% 2.0% 1.16 42.7% 34.9% 12 HI 1 4.6% 10.6% -6.0% 0.43 78.2% 75.7% 13 IA 17 9.7% 7.9% 1.8% 1.23 7.0% 6.1% 14 ID NR NA NA NA NA NA NA 15 IL 25 18.3% 10.5% 7.8% 1.74 41.5% 26.5% 16 IN 19 7.9% 8.3% -0.4% 0.95 7.0% 12.5% 17 KS 7 13.0% 10.5% 2.5% 1.24 36.8% 13.9% 18 KY 19 12.7% 12.5% 0.2% 1.02 8.5% 9.9% 19 LA 4 24.8% 18.5% 6.3% 1.34 45.2% 36.1% 20 MA 4 15.1% 10.1% 5.0% 1.49 20.7% 15.5% 21 MD 8 10.5% 7.3% 3.2% 1.44 12.4% 36.0% -22 ME 1 15.4% 9.8% 5.6% 1.57 1.3% 3.1% 23 MI 23 8.0% 10.2% -2.2% 0.79 10.6% 19.8% 24 MN 15 11.2% 7.8% 3.4% 1.43 10.8% 10.6% 25 MO 19 9.8% 9.8% 0.0% 1.00 7.5% 15.1% 
Exhibit 5H 

Comparison of Minority and Low-Income Populations Near Coal-Fired Electric Utility Plants to Statewide Per

A B C D E F (D–E) G (D/E) H I J 

Low-Income Data Comparison Minority Data Com

Item State 

Count of 

plants 

Percent 

LowIncome 

Population 

Surroundin

g Plants 

Statewide 

Low-Income 

Percentage Difference Ratio 

Percent 

Minority 

Population 

Surrounding 

Plants 

Statewide 

Minority 

Percentage Di

26 MS 4 25.5% 15.5% 10.0% 1.65 51.6% 38.6% 27 MT 6 15.9% 16.0% -0.1% 0.99 13.2% 9.4% 28 NC 19 15.7% 13.2% 2.5% 1.19 34.5% 27.9% 29 ND 7 9.0% 12.7% -3.7% 0.71 4.4% 7.6% 30 NE 6 11.3% 10.7% 0.6% 1.06 11.4% 10.4% 31 NH 2 8.2% 7.6% 0.6% 1.08 5.4% 4.0% 32 NJ 6 15.1% 8.1% 7.0% 1.86 44.0% 27.4% 33 NM 4 26.5% 19.3% 7.2% 1.37 55.7% 33.2% 34 NV 3 9.7% 10.1% -0.4% 0.96 15.7% 24.8% 35 NY 13 12.9% 14.7% -1.8% 0.88 17.4% 32.1% -36 OH 24 10.8% 11.1% -0.3% 0.97 12.2% 15.0% 37 OK 6 20.2% 14.1% 6.1% 1.43 38.8% 23.8% 38 OR 1 15.3% 12.9% 2.4% 1.19 39.2% 13.4% 39 PA 31 9.3% 9.8% -0.5% 0.95 6.6% 14.6% 40 RI NR NA NA NA NA NA NA 41 SC 12 12.9% 12.0% 0.9% 1.08 31.4% 32.8% 42 SD 2 5.8% 9.4% -3.6% 0.61 5.6% 11.3% 43 TN 8 16.8% 13.4% 3.4% 1.25 37.4% 19.8% 44 TX 18 14.4% 14.9% -0.5% 0.96 22.4% 29.0% 45 UT 6 11.4% 8.1% 3.3% 1.40 5.2% 10.8% 46 VA 16 9.9% 8.1% 1.8% 1.22 37.8% 27.7% 47 VT NR NA NA NA NA NA NA 48 WA 1 15.5% 9.5% 6.0% 1.64 9.5% 18.2% 49 WI 15 13.2% 9.0% 4.2% 1.47 12.0% 11.1% 50 WV 16 24.0% 15.8% 8.2% 1.52 6.5% 5.0% 51 WY 9 9.2% 11.1% -1.9% 0.83 4.9% 7.9% 

Summary:

 Min = 4.6% 7.3% -6.0% 0.43 4.4% 3.1% - Max = 26.5% 19.3% 10.0% 1.95 78.2% 75.7% 

Nationwide = 464 12.9% 11.9% 1.0% 1.08 21.7% 24.9% 
• Minority & Low-Income Demographic Findings 

Below is a summary of the three alternative but complementary comparison approaches based on the same minority adata: (a) itemized plant-by-plant basis, (b) nationwide aggregation basis, and (c) state-by-state aggregation basis. For relative degree by which either group living near the 495 plants may exceed their respective statewide population per

are compared as a numerical ratio whereby a ratio of 1.00 indicates that the group population percentage living near a 

statewide average, a ratio greater than 1.00 indicates the group population percentage near the plant is higher than the ratio less than 1.00 indicates the group population is less than the respective statewide average. 

• General population findings: 

o 464 plants (i.e., 94% of the 495 universe) for which year 2000 Census plant address zip code data are 

states. 

o The plant address zip code population surrounding the 464 plants with zip code data is 6.08 million, w

13,091 surrounding population per plant. 

• Low-income population findings: 

o 0.78 million low-income population surrounding the 464 plants represents 12.9% of the 6.08 million t

populations; this is higher than the 11.9% national percentage. 

o State-by-state low-income population percentages surrounding these plants range from 4.6% in HI to 2

o Extrapolated and aggregated across all 495 plants, 256 plants (52%) have surrounding populations wh

benchmark percentage of low-income population. 

o The ratios of low-income population percentages surrounding these plants range from 0.43 to 1.95, an

compared to the national average ratio of the low-income population is 1.08. 

o Approximately 29 of the 47 states (62%) have higher percentages of low-income populations compare

statewide benchmarks. 

o States with the largest difference in low-income populations surrounding the plants compared to their 

1. Mississippi (26% vs. 16%) 2. Alabama (25% vs. 15%) 

3. Illinois (18% vs. 11%) 4. New Jersey (15% vs. 8%) 5. Connecticut (15% vs. 8%) 

• Minority population findings: 

o 1.32 million minority population surrounding the 464 plants represents 21.7% of the 6.08 million tota

this is lower than the 24.9% national minority population. 
o The state-by-state range of minority population percentages surrounding these plants ranges from 1.3% 

o Extrapolated and aggregated across all 495 plants, 138 plants (28%) have surrounding populations wh

benchmark minority percentage of population. 

o The ratio of minority population percentages surrounding these plants range from 0.34 to 2.92, and the 

compared to the national average ratio of the minority population is 0.87. 

o Approximately 24 of the 47 states (51.1%) have disproportionately high percentages of minority popu

address zip code area compared to the rest of the state. 

o States with the largest difference in minority populations between the zip codes where the plants are lo

of the state are as follows: 

1. Connecticut (45% vs. 18%) 2. Arizona (44% vs. 25%) 3. Oregon (39% vs. 13%) 4. Tennessee (37% vs. 20%) 5. Kansas (37% vs. 14%) 

• Plant level results: 

Using the plant-by-plant (i.e., itemized zipcode) basis, 138 plants (28%) have surrounding minority populations whicminority benchmark percentages, whereas 357 plants (72%) have minority populations below their statewide benchm

plant zip code ratio of 0.39 (i.e., 138/357). Because this ratio is 61% less than 1.00 (i.e., 1.00 minus 0.39), this findin

relatively small count of plants have surrounding minority population percentages which disproportionately exceed thAlso on a plant zip code basis, 256 plants (52%) have surrounding low-income populations which exceed their respecwhereas 239 plants (48%) have surrounding low-income populations below their statewide benchmarks, which represof 1.07 (i.e., 256/239). Because this ratio is only slightly (7%) above 1.00, it indicates that a slightly disproportionate 

surrounding low-income population percentages which exceed their statewide benchmarks. 

• State level results: 

Using the state-by-state aggregation basis, the percentages of minority and low-income populations surrounding the ptheir respective statewide population benchmarks. From this, state ratios revealed that 24 of the 47 states (51%) hav

percentages, and 29 of the 47 states (62%) have higher low-income percentages surrounding the 495 plants, suggestinhigher minority surrounding population and a relatively large disproportionate, higher low-income surrounding populcomparison to the other two numerical comparisons, this state-by-state count approach does not include numerically-

counts or state surrounding populations, which explains why this comparison method yields a different numerical reshow population comparison results may be sensitive to the comparison method. 
• Nationwide results: 

Using the nationwide aggregation basis across all 495 plants in all 47 states where the plants are located, 6.08 million 

surrounding the plants, which include a sub-total of 1.32 million (21.7%) minority and a sub-total of 0.8 million (12.9groups. A comparison of these percentages to the national benchmark averages across all states of 24.9% minority anrepresents a minority ratio of 0.87 (i.e., 21.7%/24.9%) and a low-income ratio of 1.08 (i.e., 12.9%/11.9%). These nat

indicate a slightly lower disproportionate minority population surrounding the 495 plants, and a slightly higher dispropopulation surrounding the plants. Comparison of nationwide population sub-totals for all plants for each demograph

expected value based on statewide averages, reveals that: 

o +18.9% additional low-income residents near the plants compared to the expected low-income popula

averages (i.e., 783,062 low-income population for all 464 plants compared to 658,336 expected count 

averages.) 

o -5.8% less minority residents near the plants compared to the expected minority population based on s

1,317,896 minority population for all 464 plants compared to 1,241,382 expected count if based on sta

These three alternative comparisons indicate that the current (baseline) environmental and human health hazards and 

CCR disposal units, and the expected future benefits of the regulatory options, may have a disproportionately lower epopulations and may have a disproportionately higher effect on low-income populations. 

• Other Potentially Affected Minority & Low-Income Populations 

There are two other potential differential effects of the regulatory options on two other population groups: (a) populat

CCR landfills, and (b) populations within the customer service areas of the 495 electric utility plants. 

o Offsite CCR Landfills 

The potential effect on offsite landfills involves the RCRA Subtitle C based regulatory options (i.e., Option 1 and Opdifferent fractions of CCR generation may be required to be disposed in RCRA Subtitle C permitted hazardous waste non-hazardous waste landfills: 

• CCR fraction #1: Electric utility plants may switch the management of CCR, in whole or in part, from current o

commercial RCRA-permitted hazardous waste landfills (56.8 million is disposed in onsite lan

disposed in onsite impoundments, totaling 79.2 million tons disposed onsite). 

• CCR fraction #2: Some or all of the CCR which is currently disposed in offsite landfills that do not have RCRA 

also switch to RCRA-permitted commercial hazardous waste landfills if the current receiving RCRA Subtitle C permits (15.0 million tons is disposed offsite). 
• CCR fraction #3: Annual CCR generation which could also switch to offsite commercial RCRA-permitted land

currently supplied for industrial beneficial use applications, if such use becomes curtailed in p

either state government regulations or from market stigma (47.0 million tons is beneficially u

• CCR fraction #4: Future cleanup of CCR disposal unit failures (e.g., impoundment collapse) would be require d

permitted hazardous waste landfills (the two CCR impoundment release case studies in Exhib

represent a range of 0.25 million to 3.3 million tons per failure event). 

One or more of these four potential shifts of CCR disposal from current non-hazardous landfills to hazardous waste ladisproportionate effect on populations surrounding these locations, and in particular, minority and low-income popula

commercial hazardous waste facilities, if current landfills operated by electric utility plants do not obtain future perm

RCRA hazardous waste. A recent (2007) study determined that minority and low-income populations disproportionahazardous waste facilities, although the study included other types of commercial hazardous waste treatment and dispto commercial hazardous waste landfills.105 An example of such potential EJ concerns is a 2009 US national news ite

made by the Tennessee Valley Authority (TVA) to train transport 3 million tons of the TVA’s (Kingston TN electrici

CCR impoundment collapse site cleanup waste, 350 miles away to a landfill in a rural Alabama county which reporte

minority (African American) and 33% low-income residents.106 However, this example serves to illustrate that EJ co

conclusive or shared by all affected EJ populations, as evidenced by the following remarks made to news reporters by government officials and county residents:107

“To county leaders, the train’s loads, which will total three million cubic yards of coal ash from a massive spi

in east Tennessee last December [2008], are a tremendous financial windfall. A per-ton “host fee” that the lapay the county will add more than $3 million to the county’s budget of about $4.5 million. The ash has create

jobs for local residents in a county where the unemployment rate is 17 percent and a third of all households apoverty line. A sign on the door of the landfill’s scale house says job applications are no longer being acceptmore than enough. But some residents worry that their leaders are taking a short-term view, and that their cotoo easily persuaded to take on a wealthier, whiter community’s problem.... County leaders, who are mostly baccusations of environmental injustice, saying that the ash is perfectly safe and that criticism has been fostere

even competitors who wanted the ash disposal contract for themselves..... Bob Deacy, vice president of clean 

105 Source: United Church of Christ, “Toxic Wastes and Race at Twenty 1987-2007”, March 2007, http://www.ucc.org/assets/pdfs/toxic20.p

made findings on minority and low-income population data within a 1.8-mile radius “host neighborhood” of 413 commercial hazardous wast

host” areas. The study (page x) found that “Host neighborhoods of commercial hazardous waste facilities are 56% people of color whereas ncolor... Poverty rates in the host neighborhoods are 1.5 times greater than non-host areas (18% vs. 12%).” 

106 Source: Shaila Dewan, “Clash in Alabama Over Tennessee Coal Ash,” The New York Times, 30 Aug 2009 at http://www.nytimes.com/2107 Source: At least two news organizations identically reported these remarks on 30 Aug 2009: 

#1 of 2: New York Times, “Clash in Alabama Over Tennessee Coal Ash” at http://www.nytimes.com/2009/08/30/us/30ash.html 

#2 of 2: Waste Business Journal, “Waste From TVA Spill Begins to Arrive at Alabama Landfill Amid Controversy” at 

http://www.wastebusinessjournal.com/news/wbj20090901D.htm 
project development for the Tennessee Valley Authority, whose Kingston Fossil Plant was the site of the ash salmost 300 acres of land and waterways, said Arrowhead [Alabama landfill] was chosen because it was reacinstead of truck, because it underbid other sites and because, unlike closer landfills, it had the capacity to han

o Electricity Service Area Customers 

A third potential effect of the regulatory options described in today’s notice is the price of electricity supplied by somelectric utility plants could increase to cover the cost of regulatory compliance. Thus customers in electric utility serv

experience price increases, although the RIA estimates that future potential price increases could be expected to be beto the $0.0900 per kilowatt hour national average price (February 2009) for all four customer sectors (i.e., residential, 

and transportation). The RIA for today’s action did not evaluate the customer service area populations for the 495 pl
5E. Child Population Statistics (Executive Order 13045)

• Purpose of Child Population Data Analysis 

Under Executive Order (EO) 13045 of 21 April 1997, Federal Agencies shall make it a high priority (a) to identify an

health and safety risks that may disproportionately affect children, and (b) shall ensure that its policies, programs, actaddress disproportionate risks to children that result from environmental health or safety risks. Although the EO doeUS Census Bureau defines “children” as follows108: 

Children: The term "children"... are all persons under 18 years, excluding people who maintain households, 

subfamilies as a reference person or spouse. 

The purpose of this section is not to evaluate children risks, but to evaluate whether disproportionate percentages of c

utility plants. This analysis involves a 5-step process for comparing children population data for each electric utility children population data to identify whether children disproportionately reside in geographic areas where electric util

• Collection of Child Demographic Data 

Step 1:Plant address 5-digit zip codes formed the geographic basis for this child population data collection. Because 

irregularly shaped geographic areas, this zip code based data collection may be considered a “screening level” 

of Census uses over 33,000 “Zip Code Tabulation Areas” (ZCTA) for its Census counts of population and othbased on the US Postal Service’s over 42,000 nationwide zip codes.109 Currently, there are no size restriction

small a ZCTA can be in terms of either a minimum/maximum number of housing units or geographic area. A

be as small as a few city blocks or may cover many square miles. Many ZIP codes are for villages, census-de

of cities, or other entities that are not municipalities. The nationwide average zip code population is about 7,2million mid-2009 US population) / (42,500 zip codes)). The nationwide average zip code area is about 83 squsquare miles total US land and water area) / (42,500 zip codes)), which is a land area equivalent to a 5-mile rasq.miles) / (3.1416))^0.5). In comparison, the radial area monitored for contamination in response to the DeceKingston TN electric plant CCR spill is reportedly four miles,110 and this average 5-mile zip code radial distanmile to 15-mile radial distances used by EPA’s Superfund “Hazard Ranking System” (HRS)111 to define affechaving either (a) soil contamination only (1-mile), (b) groundwater and/or airborne contamination (4-miles), o

108 The US Census Bureau definition of “children” is from its “Current Population Survey (CPS) - Definitions and Explanations” website at: 

http://www.census.gov/population/www/cps/cpsdef.html 

109 Source: US Census Bureau ZIP Code Tabulation Area (ZCTA) Frequently Asked Questions at: http://www.census.gov/geo/ZCTA/zctafa

zip code count is from the US Postal Service’s FAQ website at: http://zip4.usps.com/zip4/welcome.jsp 

110 Source: 4 mile radial monitoring area reported by Waste & Recycling News, 13 Feb 2009; http://www.wasterecyclingnews.com/email.htm111 More background information about EPA’s HRS is available at http://www.epa.gov/superfund/programs/npl_hrs/hrsint.htm. 
contamination (15-miles downstream). Using the Census search engine Factfinder (http:factfinder.census.gov/home/saff/main.html?_lang=en), retrieved total population and people 18 and over 

electric utility plants. For 42 plants (8%) there was no zip code Census data because the plants did not have cDOE or because the Census search engine did not have data for the zip code. 

Step 2: Collected 3-year (2005 to 2007) average statewide percentages for people 18 and older data using the followi

http://factfinder.census.gov/jsp/saff/SAFFInfo.jsp?_pageId=gn10_select_state as displayed in Exhibit 5I belo

Exhibit 5I 

State-by-State Data on Child Populations (2005-2007 Average) 

Row State % children in state 

1 AK 27.0% 2 AL 24.4% 3 AR 24.8% 4 AZ 26.4% 5 CA 25.9% 6 CO 24.7% 7 CT 23.7% 8 DC 19.5% 9 DE 23.9% 

10 FL 22.3% 11 GA 26.5% 12 HI 22.3% 13 IA 23.9% 14 ID 27.3% 15 IL 25.1% 16 IN 25.1% 17 KS 25.2% 18 KY 23.9% 19 LA 25.4% 20 MA 22.5% 21 MD 24.4% 22 ME 21.5% 23 MI 24.6% 24 MN 24.5% 25 MO 24.4% 26 MS 26.3% 27 MT 23.2% 28 NC 24.4% 29 ND 22.5% 

Row State % chi

30 NE 31 NH 32 NJ 33 NM 34 NV 35 NY 36 OH 37 OK 38 OR 39 PA 40 RI 41 SC 42 SD 43 TN 44 TX 45 UT 46 VA 47 VT 48 WA 49 WI 50 WV 51 WY 

Max (UT) 

Min (DC) 

Nationwide 
• Comparison of Child Populations Living Near Electric Utility Plants to Statewide Benchmarks 

Step 3, Step 4 and Step 5 of this evaluation described below involved three complementary levels of data comparisonalso involved two complementary numerical comparisons, one based on calculating numerical percentages and the otnumerical ratios: 

1. Plant level: Plant-by-plant disaggregated data comparison to statewide benchmarks 

2. State level: State-by-state aggregated plant data comparison to statewide benchmarks 

3. National level: National aggregated plant data comparison to statewide benchmarks 

Step 3: On a plant-by-plant basis, compared the plant zip code percentage children, to the respective statewide averag

Step 4: For purpose of summary, aggregated the plant level children population comparison data for each state as dis

below. There are no data displayed for DC, ID, RI or VT because there are no coal-fired electric utility plants 

Appendix N of this RIA presents the plant-by-plant Census data on which this Exhibit is based. 

Exhibit 5J 

State-by-State Child Population Data for Coal-Fired Electric Utility Plants 

General Population Data Child Population Data 

Item 

Count of 

plant 

unique zip 

codes State 

Count of plant 

zip codes which 

have Census 

population data 

2000 plant 

zip code 

resident 

population 

Child 

population 

count (<18 

years) in plant 

zip codes 

Child 

population 

percentage 

in plant zip 

codes 

Statewide 

percentage 

child 

population 

Expec

children co

plant zip c

based on s

1 2 AK 2 18,552 5,188 27.96% 27.00% 5,002 9 AL 9 82,854 21,978 26.53% 24.40% 20,213 3 AR 3 11,786 3,359 28.50% 24.80% 2,924 6 AZ 6 34,941 11,526 32.99% 26.40% 9,225 5 CA 4 112,895 36,285 32.14% 25.90% 29,246 15 CO 15 214,095 49,190 22.98% 24.70% 52,887 2 CT 2 42,716 10,743 25.15% 23.70% 10,128 NA DC 9 3 DE 3 46,925 11,169 23.80% 23.90% 11,21

10 14 FL 13 224,502 55,025 24.51% 22.30% 50,0611 9 GA 9 202,973 50,964 25.11% 26.50% 53,7812 1 HI 1 25,054 8,158 32.56% 22.30% 5,5813 17 IA 14 324,050 77,708 23.98% 23.90% 77,4414 NA ID 
Exhibit 5J 

State-by-State Child Population Data for Coal-Fired Electric Utility Plants 

General Population Data Child Population Data 

Item 

Count of 

plant 

unique zip 

codes State 

Count of plant 

zip codes which 

have Census 

population data 

2000 plant 

zip code 

resident 

population 

Child 

population 

count (<18 

years) in plant 

zip codes 

Child 

population 

percentage 

in plant zip 

codes 

Statewide 

percentage 

child 

population 

Expec

children co

plant zip c

based on s

15 25 IL 23 455,834 129,772 28.47% 25.10% 114,416 19 IN 17 323,323 83,594 25.85% 25.10% 81,1517 7 KS 6 59,517 16,532 27.78% 25.20% 14,9918 19 KY 17 255,033 63,012 24.71% 23.90% 60,9519 4 LA 4 30,381 8,617 28.36% 25.40% 7,7120 4 MA 3 95,798 23,078 24.09% 22.50% 21,5521 8 MD 7 101,141 23,529 23.26% 24.40% 24,6722 1 ME 1 6,748 1,561 23.13% 21.50% 1,4523 23 MI 20 383,284 94,994 24.78% 24.60% 94,2824 15 MN 15 187,012 46,208 24.71% 24.50% 45,8125 19 MO 19 251,484 60,084 23.89% 24.40% 61,3626 4 MS 4 69,209 19,867 28.71% 26.30% 18,2027 6 MT 5 53,209 14,115 26.53% 23.20% 12,3428 19 NC 16 238,874 57,728 24.17% 24.40% 58,2829 7 ND 5 27,087 7,411 27.36% 22.50% 6,0930 6 NE 6 79,313 20,853 26.29% 25.30% 20,0631 2 NH 2 53,302 10,713 20.10% 23.10% 12,3132 6 NJ 6 119,286 29,806 24.99% 24.00% 28,6233 4 NM 4 17,491 5,656 32.34% 25.60% 4,4734 2 NV 2 8,471 1,827 21.57% 25.80% 2,1835 13 NY 13 226,416 57,612 25.45% 23.20% 52,5236 24 OH 23 391,705 101,253 25.85% 24.20% 94,7937 6 OK 6 30,357 8,513 28.04% 24.90% 7,5538 1 OR 1 3,884 1,378 35.48% 23.20% 901 39 31 PA 28 167,254 36,581 21.87% 22.60% 37,7940 NA RI 41 12 SC 12 222,414 60,391 27.15% 24.20% 53,8242 2 SD 2 30,508 7,510 24.62% 24.80% 7,5643 8 TN 8 158,267 40,682 25.70% 24.10% 38,1444 18 TX 17 98,402 27,471 27.92% 27.70% 27,2545 6 UT 6 34,209 11,769 34.40% 30.90% 10,5746 16 VA 15 220,800 55,824 25.28% 23.90% 52,7747 NA VT 48 1 WA 1 21,842 5,514 25.24% 23.90% 5,2249 15 WI 13 178,705 36,428 20.38% 23.80% 42,53
Exhibit 5J 

State-by-State Child Population Data for Coal-Fired Electric Utility Plants 

General Population Data Child Population Data 

Item 

Count of 

plant 

unique zip 

codes State 

Count of plant 

zip codes which 

have Census 

population data 

2000 plant 

zip code 

resident 

population 

Child 

population 

count (<18 

years) in plant 

zip codes 

Child 

population 

percentage 

in plant zip 

codes 

Statewide 

percentage 

child 

population 

Expec

children co

plant zip c

based on s

50 16 WV 13 64,771 10,946 16.90% 21.50% 13,9251 9 WY 8 69,736 19,732 28.30% 24.00% 16,73

Summary: 

Total 464 429 6,076,410 1,541,854 25.37% 24.70% 1,480,8

4.1% 

 Min= 16.90% 21.50%  Max= 35.48% 30.90% 

Extrapolated to 495 plants = 

Step 5: The percentage of children population surrounding the plant zip codes were compared to overall state 

nationwide percentage of this sub-group population, by calculating ratios between the plant zip code ccompared to statewide and nationwide percentages of children population. Exhibit 5K below display

Exhibit 5K 

Comparison of Child Population Data on a State-by-State Basis 

Item State Plants 

Percentage of 

Zip Code 

Population 

under 18 

Years Old 

Statewide 

Percentage of 

Children 

(Exhibit 5I) Difference Ratio 

1 AK 2 28.0% 27.0% 1.0% 1.04 2 AL 9 26.5% 24.4% 2.1% 1.09 3 AR 3 28.5% 24.8% 3.7% 1.15 4 AZ 6 33.0% 26.4% 6.6% 1.25 5 CA 5 32.1% 25.9% 6.2% 1.24 6 CO 15 23.0% 24.7% -1.7% 0.93 7 CT 2 25.1% 23.7% 1.4% 1.06 8 DC NR NA NA NA NA 9 DE 3 23.8% 23.9% -0.1% 1.00 

10 FL 14 24.5% 22.3% 2.2% 1.10 11 GA 9 25.1% 26.5% -1.4% 0.95 12 HI 1 32.6% 22.3% 10.3% 1.46 
Exhibit 5K 

Comparison of Child Population Data on a State-by-State Basis 

Item State Plants 

Percentage of 

Zip Code 

Population 

under 18 

Years Old 

Statewide 

Percentage of 

Children 

(Exhibit 5I) Difference Ratio 

13 IA 17 24.0% 23.9% 0.1% 1.00 14 ID NR NA NA NA NA 15 IL 25 28.5% 25.1% 3.4% 1.13 16 IN 19 25.9% 25.1% 0.8% 1.03 17 KS 7 27.8% 25.2% 2.6% 1.10 18 KY 19 24.7% 23.9% 0.8% 1.03 19 LA 4 28.4% 25.4% 3.0% 1.12 20 MA 4 24.1% 22.5% 1.6% 1.07 21 MD 8 23.3% 24.4% -1.1% 0.95 22 ME 1 23.1% 21.5% 1.6% 1.08 23 MI 23 24.8% 24.6% 0.2% 1.01 24 MN 15 24.7% 24.5% 0.2% 1.01 25 MO 19 23.9% 24.4% -0.5% 0.98 26 MS 4 28.7% 26.3% 2.4% 1.09 27 MT 6 26.5% 23.2% 3.3% 1.14 28 NC 19 24.2% 24.4% -0.2% 0.99 29 ND 7 27.4% 22.5% 4.9% 1.22 30 NE 6 26.3% 25.3% 1.0% 1.04 31 NH 2 20.1% 23.1% -3.0% 0.87 32 NJ 6 25.0% 24.0% 1.0% 1.04 33 NM 4 32.3% 25.6% 6.7% 1.26 34 NV 2 21.6% 25.8% -4.2% 0.84 35 NY 13 25.4% 23.2% 2.2% 1.10 36 OH 24 25.8% 24.2% 1.6% 1.07 37 OK 6 28.0% 24.9% 3.1% 1.13 38 OR 1 35.5% 23.2% 12.3% 1.53 39 PA 31 21.9% 22.6% -0.7% 0.97 40 RI NR NA NA NA NA 41 SC 12 27.2% 24.2% 3.0% 1.12 42 SD 2 24.6% 24.8% -0.2% 0.99 43 TN 8 25.7% 24.1% 1.6% 1.07 44 TX 18 27.9% 27.7% 0.2% 1.01 45 UT 6 34.4% 30.9% 3.5% 1.11 46 VA 16 25.3% 23.9% 1.4% 1.06 47 VT NR NA NA NA NA 48 WA 1 25.2% 23.9% 1.3% 1.06 
Exhibit 5K 

Comparison of Child Population Data on a State-by-State Basis 

Item State Plants 

Percentage of 

Zip Code 

Population 

under 18 

Years Old 

Statewide 

Percentage of 

Children 

(Exhibit 5I) Difference Ratio 

49 WI 15 20.4% 23.8% -3.4% 0.86 50 WV 16 16.9% 21.5% -4.6% 0.79 51 WY 9 28.3% 24.0% 4.3% 1.18 

 Min = 16.9% 19.5% -4.6% 0.79  Max = 35.5% 30.9% 12.3% 1.53  Nationwide = 464 25.4% 24.7% 0.7% 1.03 

• Child Population Data Findings 

Below is a summary of the three alternative but complementary comparison approaches based on the same children pby-plant (i.e., itemized zip code) basis, (b) nationwide aggregation basis, and (c) state-by-state aggregation basis. For the relative degree by which children may exceed these statewide percentages, the percentages are compared as a numratio of 1.00 indicates that the child population percentage living near a plant is equal to the statewide average, a ratio indicates the child population percentage near the plant is higher than the statewide population, and a ratio less than 1population is less than the respective statewide average.

• General population findings 

o 464 plants (i.e., 94% of the 495 universe) for which Census plant address zip code data are located 

o The plant address zip code population surrounding these plants is 6.08 million, which is an averag

population per plant. 

• Child population findings 

o The sub-total number of children surrounding these 464 plants is 1.54 million (i.e., 25.4% of 6.08 

the national average of the child population in the US is 24.7%. 

o The ratios of the children population percentages surrounding these plants range from 0.79 to 1.53

ratios compared to the national average ratio of the low-income population is 1.03. 

o 27 of the 47 states (57%) have disproportionately high percentages of children within the plant ad

compared to the statewide percentages. 

o States with the largest difference in the children population between the zip codes where the plant

the statewide percentages are as follows: 

1. Oregon (36% vs. 23%) 
2. Hawaii (33% vs. 22%) 3. New Mexico (32% vs. 26%) 4. Arizona (33% vs. 26%) 5. California (32% vs. 26%) 

o A sub-total 291 plants (63%) have surrounding children populations which exceed their respective 

• Plant level results: 

Using the plant-by-plant (i.e. itemized zip code) basis, 310 plants (63%) have surrounding child populations which ex

children benchmark percentages, whereas 185 plants (37%) have children populations below their statewide benchmaplant zip code ratio of 1.68 (i.e., 310/185). Since this ratio is much greater than 1.00, this finding indicates that a highof plants have surrounding child population percentages which exceed their statewide benchmark. 

• State level results: 

Using the state-by-state aggregation basis, the percentage of child populations surrounding the plants were compared 

statewide population benchmarks. The state-by-state ratios revealed that approximately 27 of the 47 states (57%) havpercentages of children within the plant address zip code area compared to the rest of the state suggesting a disproporpopulation. However, in comparison to the other two numerical comparisons above, this state-by-state count approacnumerically-weighting of state plant counts or state surrounding populations, which explains why this comparison menumerical result. This method illustrates how population comparison results may be sensitive to the comparison meth

• Nationwide results: 

Using the nationwide aggregation basis across all 495 plants in all 47 states where the plants are located, 6.08 million surrounding the plants, which include a sub-total of 1.54 million children (25.4%). Comparison of this percentage to benchmark across all states of 24.7% children yields a ratio of 1.03 (i.e., 25.4%/24.7%). This ratio indicates a slightl

child population surrounding the 495 plants. Comparison of the nationwide child population sub-total for all plants readditional children reside near the plants, compared to the expected child population if based on state averages (i.e., 1near the 464 plants compared to 1,480,831 expected children count). These three alternative comparisons indicate that the current (baseline) environmental and human health hazards and 

CCR disposal units, and the expected future benefits of the regulatory options, may have a disproportionately higher populations. 
5F. Unfunded Mandates (UMRA) & Federalism Implications Analysis (Executive Order 131

• UMRA 

Among its other purposes and Federal agency rulemaking requirements, Title II of the 1995 Unfunded Mandates Ref

U.S.C. 1531-1538), requires Federal agencies, unless otherwise prohibited by law, to assess the effects of their regulalocal, and tribal governments and on the private sector, to determine whether any proposed rulemaking: 

 “...is likely to result in promulgation of any rule that includes any Federal mandate that may result in the explocal, and tribal governments, in the aggregate, or by the private sector, of $100 million or more in any one y

Section 202 of UMRA requires Federal agencies which propose rules that are likely to exceed this $100 million expe

the private sector or on state/local/tribal governments, to prepare a “Written Statement” containing the following five the Written Statement to OMB as well as summarize it in the Federal Register notice (aka “preamble”) for the propos

1. Identification of the applicable authorizing Federal law 2. Qualitative and quantitative assessment of the anticipated costs and benefits of the rule including the costs and 

and tribal governments or the private sector, and an analysis of whether Federal resources may be available to 

3. Estimates of future compliance costs and any disproportionate budgetary effects 4. Estimates of effects on the national economy such as productivity, economic growth, employment, job creatio

competitiveness 

5. Description and summary of agency’s prior consultation with elected representatives of the affected State, loc

Section 202 of UMRA allows Federal agencies to prepare the “Written Statement “in conjunction with or as a part of 

analysis. Accordingly, the purpose of this section of the RIA is to determine whether the regulatory options evaluated 

UMRA direct cost threshold. Findings: The private sector and the state/local government shares of direct compliance costs under each option 

Exhibit 5L, which indicates that: 

 Private sector cost test: All of the regulatory options are expected to result in expenditures of $

aggregate for the private sector, in any one year (i.e., 139 companies and cooperatives of the to

 State/local/tribal government cost test: None of the regulatory options are expected to result in 

million or more for State, local, and tribal governments in the aggregate in any one year (there 

government owner entities identified in Exhibit 5M below, no known tribal owner entities, plu

According to the private sector test finding, EPA has prepared an “UMRA Written Statement” which is attached to th
• Federalism (Executive Order 13132) 

The 1999 Federalism Executive Order 13132 (Federal Register, Vol.64, No. 153, 10 Aug 1999) furthers the policies o

Mandates Reform Act (UMRA) by establishing federalism principles, federalism policymaking criteria, and a state/lo

consultation process for the development of Federal regulations that have federalism implications. Federalism implicregulations and other Federal policies and actions that have substantial direct effects on states, on the relationship bet

government and the states, or on the distribution of power and responsibilities among the various levels of governmen

For purpose of complying with the Section 6 consultation process of EO 13132, this section of the RIA evaluates whe

options may “impose substantial direct compliance costs” on state/local governments. As summarized in Exhibit 5L

impose four types of direct costs on the 60 state/local government owner entities identified in Exhibit 5M below: 

• State/local government owned electric utility plants: 

1. Engineering control costs for CCR disposal units located at electric utility plants owned by state/local gov

2. Ancillary costs for CCR disposal units located at electric utility plants owned by state/local governments. 3. Conversion to dry disposal costs for CCR disposal units located at electricity utility plants owned by state/

• State government environmental agencies: 

4. Regulatory implementation, administration, and enforcement costs to RCRA-authorized state government 

Consistent with the “direct cost” scope of EO 13132, not included in Exhibit 5L are potential indirect costs in the forrevenues to electricity plants associated with potential reductions in CCR sold by plants for beneficial use under the twhich such an possible indirect effect is estimated in this RIA. EPA’s 2008 guidance112 for compliance with EO 13132 describes two numerical methods (i.e., numerical tests) for ev

rule may have federalism implications with respect to “substantial direct compliance costs”: 

1. $25 million test: Annualized direct compliance cost expenditures to state/local governments in aggregate of $2

2. 1% test: Annualized direct compliance costs faced by state/local governments is likely to equal or exceed 1% 

[* Note: Page 29 of “Attachment A: Guidance for Implementing the Federalism 1% Test” to EPA’s Nov 2008 Order 13132: Federalism” defines small government “general revenue” as “made up of intergovernmental revtheir own sources and excludes utility, liquor store and employee retirement revenue.” However, given that th

affects electric utility industry, this RIA applies the “1% Test” in relation to only State/local government elect

112 The two methods are from page 6 of “EPA’s Action Development Process -- Guidance on Executive Order 13132: Federalism,” OPEI Re

Nov 2008, 62 pages at http://intranet.epa.gov/adplibrary/documents/federalismguide11-00-08.pdf 

113 Although one of the stated purposes of EO 13132 in its first paragraph is “to further the policies of the 1995 Unfunded Mandates Reform 

million annual direct cost trigger is 75% lower than the $100 million annual direct cost trigger prescribed in Section 202 of UMRA. 
• Findings for UMRA Impact and Federalism Implication Tests Based on estimated regulatory costs on state/local governments displayed in Exhibit 4O (Chapter 4) of this RIA undeExhibit 5L below displays whether the costs potentially exceed the UMRA and Federalism thresholds defined above

o UMRA finding: All options >$100 million private sector test; all options <$100 million state/loc

o Federalism finding: All options >$25 million state/local government test; all options <1% state/loca

However, for consistency with the RFA/SBREFA small business impact analysis presented in a separate section abovestimates it is highly likely that the direct compliance costs under each option may be passed-thru to electricity plant higher electricity prices. The feasibility of such a compliance cost pass-thru scenario is evaluated and confirmed by t

in the RFA/SBREFA small business impact section of this RIA. 

Exhibit 5L 

UMRA and Federalism Tests for CCR Disposal Regulatory Options 

($millions average annualized costs @7% discount rate over 50-years 2012 to 2061, 2009$) 

Type of Direct Compliance Cost 

Option 1 

(Preferred Option) 

Subtitle C 

hazardous waste 

Option 2 

Subtitle D 

non-hazardous waste 

SubtitSubtit

A. Without land treatment disposal sub-option: $598 $492 UMRA Test: 1. Private sector $100 million direct cost threshold test $512.7 $415.3 2. State/local government $100 million direct cost threshold test* $67.3 $55.9 Federalism Test: 1. $25 million threshold test: sub-total State/Local govt cost $67.3 $55.9 2. 1% Test: State/local govt cost as percentage of State/Local government electric utility annual revenues 

0.158% 0.131% 

B. With land treatment disposal sub-option: $2,274 $2,168 UMRA Test: 1. Private sector $100 million direct cost threshold test $1,999.4 $1,902.0 2. State/local government $100 million direct cost threshold test* $96.7 $85.3 Federalism Test: 1. $25 million threshold test: sub-total State/Local govt cost $96.7 $85.3 2. 1% Test: State/local govt cost as percentage of State/Local government electric utility annual revenues 

0.227% 0.200% 

* Note: Remainder Federal government costs represent costs associated with Federally-owned electric utility plants (i.e., Tennessee Vare not subject to either the UMRA or Federalism tests. Therefore, the sub-total private sector direct cost plus the state/local governm

add-up to the total annual cost estimate under each option; the remainder cost is for the Federally-owned plants. 
Exhibit 5M 

List of 74 Coal-Fired Electric Utility Generation Plants Which EPA Estimates Are Owned by 60 State/Local Gov

Source: Compiled by EPA-OSWER-ORCR based on 2007 data from the US Energy Information Administratio

Item Owner Entity Name Electric Utility Plant Name State 

O

S

1 Grand River Dam Authority GRDA OK Non2 Lower Colorado River Authority Fayette Power Project TX Non3 Nebraska Public Power District Gerald Gentleman NE Non4 Nebraska Public Power District Sheldon NE Non5 Omaha Public Power District Nebraska City NE Non6 Omaha Public Power District North Omaha NE Non7 Platte River Power Authority Rawhide CO Non8 Salt River Project Coronado AZ Non9 Salt River Project Navajo AZ Non

10 South Carolina Pub Service Auth Cross SC Non11 South Carolina Pub Service Auth Dolphus M Grainger SC Non12 South Carolina Pub Service Auth Jefferies SC Non13 South Carolina Pub Service Auth Winyah SC Non14 American Municipal Power-Ohio, Inc Richard Gorsuch OH Non15 Ames City of Ames Electric Services Power Plant IA Non16 City of Columbia Columbia MO Non17 City of Hamilton Hamilton OH Non18 City of Lakeland C D McIntosh Jr FL Non19 City of Owensboro Elmer Smith KY Non20 City of Springfield Dallman IL Non21 City of Springfield Lakeside IL Non22 City Utilities of Springfield James River Power Station MO Non23 City Utilities of Springfield Southwest Power Station MO Non24 Colorado Springs City of Martin Drake CO Non25 Colorado Springs City of Ray D Nixon CO Non26 Gainesville Regional Utilities Deerhaven Generating Station FL Non27 Independence City of Blue Valley MO Non28 Independence City of Missouri City MO Non29 JEA Northside Generating Station FL Non30 JEA St Johns River Power Park FL Non31 Kansas City City of Nearman Creek KS Non32 Kansas City City of Quindaro KS Non33 Lansing Board of Water and Light Eckert Station MI Non34 Lansing Board of Water and Light Erickson Station MI Non35 Los Angeles City of Intermountain Power Project UT Non36 Orlando Utilities Comm Stanton Energy Center FL Non37 Rochester Public Utilities Silver Lake MN Non
Exhibit 5M 

List of 74 Coal-Fired Electric Utility Generation Plants Which EPA Estimates Are Owned by 60 State/Local Gov

Source: Compiled by EPA-OSWER-ORCR based on 2007 data from the US Energy Information Administratio

Item Owner Entity Name Electric Utility Plant Name State 

O

S

38 San Antonio City of J K Spruce TX Non39 San Antonio City of J T Deely TX Non40 Vineland City of Howard Down NJ Non41 Crisp County Power Comm Crisp Plant GA Sma42 Austin City of Austin Northeast MN Sma43 Board of Water Electric & Communications Muscatine Plant #1 IA Sma44 Cedar Falls Utilities Streeter Station IA Sma45 City of Dover Dover OH Sma46 City of Grand Haven J B Sims MI Sma47 City of Holland James De Young MI Sma48 City of Jasper Jasper 2 IN Sma49 City of Logansport Logansport IN Sma50 City of Marquette Shiras MI Sma51 City of Marshall Marshall MO Sma52 City of Menasha Menasha WI Sma53 City of Orrville Orrville OH Sma54 City of Painesville Painesville OH Sma55 City of Richmond Whitewater Valley IN Sma56 City of Shelby Shelby Municipal Light Plant OH Sma57 City of Sikeston Sikeston Power Station MO Sma58 City of Virginia Virginia MN Sma59 Crawfordsville Electric Light & Power Crawfordsville IN Sma60 Fremont City of Lon Wright NE Sma61 Grand Island City of Platte NE Sma62 Greenwood Utilities Commission Henderson MS Sma63 Hastings City of Whelan Energy Center NE Sma64 Henderson City Utility Commission Henderson I KY Sma65 Hibbing Public Utilities Commission Hibbing MN Sma66 Jamestown Board of Public Utilities S A Carlson NY Sma67 Manitowoc Public Utilities Manitowoc WI Sma68 Michigan South Central Power Agency Endicott Station MI Sma69 New Ulm Public Utilities Commission New Ulm MN Sma70 Pella City of Pella IA Sma71 Peru City of Peru IN Sma72 Texas Municipal Power Agency Gibbons Creek TX Sma73 Willmar Municipal Utils Commission Willmar MN Sma74 Wyandotte Municipal Service Commission Wyandotte MI Sma
Exhibit 5N (Continued) 

List of 74 Coal-Fired Electric Utility Generation Plants Which EPA Estimates Are Owned by 60 State/Local Gov

Source: Compiled by EPA-OSWER-ORCR based on 2007 data from the US Energy Information Administratio

Footnotes: * NAICS code 22 electric “utility” generator plants listed in EIA’s 2007 data source at: http://www.eia.doe.gov/cneaf/electricity/page/eia860.html **Type of owner entity assigned by EPA ORCR based on business type disclosed in owner name or plant-by-plant internet type of ownership. Size class determined according to the following numerical criteria consistent with EPA’s Nov 2006 guiRegulatory Flexibility Act (RFA) Small Business Regulatory Enforcement Fairness Act (SBREFA) compliance: 

• Small non-government = Based on the US Small Business Administration NAICS code 221112 small business siz<4 million megawatt hours per year total annual electricity generation by all plants owned by the entity. • Non-small non-government = Entity’s total annual electricity generation >4 million megawatt hours per year. • Small government = Based on the RFA’s definition (5 US Code section 601(5)) of “small government jurisdiction

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

• Non-small government = Entity’s jurisdiction population with more than 50,000 people. 
Chapter 6 

Sensitivity Analyses 

This chapter describes and estimates the magnitude of six major uncertainty, variable, and scope factors in the for

of the cost estimates and associated quantitative analyses presented in the previous chapters of this RIA. The sensitiv

A. Alternative discount rates B. Data quality uncertainty C. Possible impact on baseline CCR beneficial uses 

D. Price and capacity impacts on commercial hazardous waste landfills E. Uncertainty in land disposal treatment sub-option cost estimate 

F. Other CCR disposal units not covered by the proposed rule 

6A. Alternative Discount Rates (0%, 3%, 7%)

Because the annualized average costs --- to both industry and to state governments --- estimated in this RIA were form

instance as uniform average annual costs, their numerical dollar values are not sensitive to alternative discount rates oanalysis applied in this RIA. However, some of the average annualized costs involve capital investments (e.g., one tiengineering controls), and capital costs are sensitive to discount rates because this RIA converted (i.e., annualized) ca

annualized equivalent costs over the 50-year period of analysis, using a 7% discount rate. For annualization of such o

applied a 7% discount rate to represent the financial opportunity cost (i.e., borrowing cost) to affected businesses, wh

OMB’s 2003 Circular A-4 (page 33) and 1992 Circular A-94 (page 8) which indicate that a 7% discount rate base-caregulatory analyses when regulation is expected to primarily and directly affect businesses and industries. For purpose of this discount rate sensitivity analysis, alternative discount rates are not applied to the micro-formulatioand other one-time cost estimated in this RIA, but to the present value calculations of the overall (i.e., aggregate) aveeach regulatory option over the 50-year period of analysis applied in this RIA. Exhibit 6A below presents the results 

alternative discount rates (i.e., 0% non-discounted, 3%, and 7%). These three alternative discount rates are identified 

A-4 guidance114 (page 45) for purpose of RIA discount rate sensitivity analyses. 

114 OMB’s 17 Sept 2003 Circular A-4 “Regulatory Analysis” guidance is available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/ 
Exhibit 6A 

Discount Rate Sensitivity Analysis for Average Annual Values of Estimated Regulatory Options 

($millions per year over 50-year period of analysis 2012 to 2061) 

Alternative Discount Rates 

Option 1 

(Preferred Option) 

• Subtitle C hazardous 

waste 

Option 2 

• Subtitle D nonhazardous waste 

Opt

• Subtitle for 

impoundm

• Subtitle D 

A. Without land treatment disposal sub-option: 

7% (base case for this RIA) $598 $492 $5

3% $321 $264 $2

0% (not discounted) $165 $136 $

B. With land treatment disposal sub-option: 

7% (base case for this RIA) $2,274 $2,168 $2

3% $1,220 $1,163 $1

0% (not discounted) $628 $598 $6
6B. Data Quality Uncertainty This section addresses OMB’s 2003 Circular A-4 “Regulatory Analysis” guidance (page 40) requirement for RIAs inexpected annual economic effects of $1 billion or more, to present a formal quantitative analysis of the uncertainties a

estimates. Because this RIA does not monetize benefits, this section only addresses uncertainties with respect to cost 

baseline cost and incremental costs for the regulatory options. This section first presents three specific examples of 

factors in this RIA, followed by an overall uncertainty factor to represent all such specific data quality uncertainty fthree factors below are not additive across their low- and high-end percentage range endpoints because such simple aunlikely compounding of these factors): 

• Specific Examples of Data Quality Uncertainty Factors in This RIA 

1. CCR tonnage data:As described respectively in Chapter 3 and Chapter 4 of this RIA, the baseline and regulato

cost estimates are based on the annual CCR disposal and beneficial use tonnages reported bthe 2005 DOE-EIA Form 767 database. However, the DOE-EIA 767 data reporting form1

respondents with a definition for the “tons” collected in Schedule 3 of the data reporting fothree numerical definitions of “ton” commonly used in the US (i.e., short-ton = 2,000 pounpounds; and metric ton = 2,205 pounds), this factor potentially introduces -20% to +20% u

purpose of consistency with the use of short-tons in most EPA RCRA program reports,116 t

“tons” as short-tons. 

2. Data sources: Also with respect to CCR tonnage data, this RIA cites multiple possible sources of data bas

sources. For example, as displayed in Exhibit 2D of this RIA, one source (American Coal provides an industry survey-based estimate of CCR generation by electric utility plants in 2Whereas this RIA estimates 141.2 million tons CCR generation in 2005 based on data from 767 database for plants >100 MW in size and based on supplemental estimates made in this plants. This data source inconsistency factor represents -13% to +15% uncertainty range. 

3. Data years: Information and data used to evaluate and estimate the cost of baseline CCR disposal pract

published sources dated 1995, 1996, and 2006. Furthermore, unit costs for CCR disposal uapplied in this RIA are from different published data years such as 2000, 2004, and 2007. Thistorical data to 2009 price levels using various indexes, some of which were specific to a cost, and other indexes were general (e.g., GDP Price Deflator). The uncertainty in accuracby use of historical data is not quantified. 

115 Instructions to the 2005 DOE-EIA Form 767 data reporting questionnaire (24 pages) are available at 

http://www.eia.doe.gov/cneaf/electricity/forms/eia767/eia767instr.pdf

A copy of the 2005 DOE-EIA 767 data reporting questionnaire (16 pages) is available at http://www.eia.doe.gov/cneaf/electricity/forms/eia7

116 One example of the standardized use of “short-tons” in EPA RCRA program reports is the RCRA Biennial Hazardous Waste Reports whi

http://www.epa.gov/waste/inforesources/data/biennialreport/index.htm 
• Overall Data Quality Uncertainty Range 

The method applied to characterize the overall level of quantitative uncertainty in the cost estimates of this RIA, is ba

2005 “Recommended Practice No. 18R-97: Cost Estimate Classification System as Applied in Engineering, Procurem

the Process Industries”117. This method is specifically applicable to cost estimates developed for mechanical and che

used for engineering, procurement and construction across a wide variety of industries including the electric utility incode 22). As summarized in Exhibit 6B below, this cost estimate classification system involves five estimation categ2, Class 3, Class 4, Class 5) reflecting different relative (a) levels of cost definition, (b) purposes and uses of cost estimethodologies, (d) expected accuracy ranges, and (e) degrees of cost estimate preparation effort. 

Exhibit 6B 

Summary of Cost Estimation Classification System 

for Characterizing Data Quality Uncertainty in this RIA 

Estimate 

Category 

Level of Detail 

(Quantity of Input Information & Data) 

Level of Effort 

(Time Required to Complete the Cost Estimate) 

Class 5 Very limited information (e.g., little more than proposed project type, location, and capacity). Very limited amount of time and with little effort, some

requiring less than one hour FTE to prepare the cost esti

Class 4 

1% to 5% complete, limited information (e.g., preliminary engineered process and equipment lists) for purpose of alternatives analysis, screening analysis, or demonstration of economic feasibility. 

Sometimes requiring up to two months FTE for preparincost estimate. 

Data quality uncertainty range applied in this RIA (i.e., between Class 3 and Clas

Class 3 

10% to 40% complete, semi-detailed information (e.g., process flow diagrams, equipment diagrams, layout drawings, engineered process and equipment lists). 

May require up to nine months FTE to prepare the cost estimate. 

Class 2 30% to 70% complete, detailed information May require up to 1.5 years FTE to prepare the cost estiClass 1 50% to 100% complete and full project definition (e.g., virtually all engineering and design documentation/plans) May require up to or over three years FTE to prepare th

estimate. 

Because the bulk of the data collection and analysis presented in this RIA was executed in a relatively short time (i.e.

detailed information for baseline CCR disposal conditions, disposal unit costs, and engineering control and ancillary 

options, the level of numerical uncertainty for the baseline cost and incremental costs for each of the regulatory optio

may be classified between a Class 3 and Class 4 type of estimate (i.e., -25% to +40%), as displayed below in Exhibit 

ranges represent a probability distribution about the cost estimates, and may be interpreted as the expected values (i.e

end and high-end ranges about each cost estimate. Such quantitative indicators of uncertainty are identified in OMB’

117 Recommended Practice No. 18R-97 (10 pages) published by the Association for the Advancement of Cost Engineering at: http://www.aac
41) as acceptable for characterizing probability distributions for cost estimates involving major rules with possible an$1 billion or more for one or more regulatory options. 

Exhibit 6C 

Cost Estimation Uncertainty with Overall Data Quality Uncertainty Factor Applied 

($millions average annualized costs over 50-year period 2012-2061 in 2009$) 

Cost Estimate Uncertainty Indicator 

Option 1 

(Preferred Option) 

• Subtitle C hazardous 

waste 

Option 2 

• Subtitle D nonhazardous waste 

Option 

• Subtitle C for im• Subtitle D for la

A. Without land disposal treatment sub-option: Best estimate (average annualized cost) $598 $492 $500 

-25% uncertainty low-end $448 $369 $375 

+40% uncertainty high-end $837 $689 $700 

B. With land disposal treatment sub-option: Best estimate (average annualized cost) $2,274 $2,168 $2,17

-25% uncertainty low-end $1,706 $1,626 $1,63

+40% uncertainty high-end $3,184 $3,035 $3,04
6C. Potential Impact on Baseline CCR Beneficial Uses The 2003 OMB Circular A-4 “Regulatory Analysis” (page 26) recommends that Federal agencies look beyond the di

costs of rulemakings and consider any important ancillary benefits and countervailing risks (i.e., indirect effects). Thancillary benefit as a favorable impact of the rule that is typically unrelated or secondary to the purpose of the rulemacountervailing risk is an adverse economic, health, safety, or environmental consequence that may occur due to a reguestimated and accounted for in the direct cost of the regulation. This section identifies and quantifies a potential coun

proposed rule on CCR beneficial use. Described below are five hypothetical scenarios for potential impact of RCRA regulation on the annual tonnage of b

use. One of the five scenarios (i.e., Scenario #5) portrays an increase in future beneficial use, whereas all of the other Scenarios #1 to #4) portray future reductions in beneficial use ranging from 4% to 42% potential loss in annual bene

regulatory option and scenario. Relative to the 62 million tons of annual CCR beneficial use estimated in this RIA fothis RIA, the 4% to 42% scenario-based loss range represents 2.5 million to 26 million tons per year potential loss in In addition to the change in associated economic and environmental benefits of change in beneficial use, the coal-firewould also be faced with a change in annual CCR disposal cost associated with the affected beneficial use tonnages. beneficial use impact scenario, Exhibit 6D presents a summary of (a) percentage change for each scenario, (b) associ

benefits, (c) associated change in environmental benefits, and (d) associated change in future annual CCR disposal co

• Scenario #1 of 5: Market Stigma (non-quantified loss under Option 1 & Option 3) 

This potential source of beneficial market loss was identified by the American Coal Ash Association (ACAA) indicat

letter addressed to the EPA Administrator which asserted the possibility of stigma resulting from RCRA Subtitle C re

“Any designation of [CCRs] as hazardous wastes would have significant and long-lasting effects upon this na

to beneficially use or reuse fly ash or bottom ash in sustainable construction applications. Even a “contingenapproach would have the same effect, as the industry would consider a contingent classification the equivalenC... Either designation would unnecessarily stigmatize [CCRs].” 

This hypothetical market loss scenario is also conceptually feasible in light of a number of studies which have docum

phenomenon of hazardous waste stigma in relation to property value loss.118 According to published theories summa

118 For example, one study of hazardous waste stigma impact on property values is “Stigma: The Psychology and Economics of Superfund” p

al. for the EPA under contract nr. CR 824393-01-0, July 2004, 241 pages, at: http://yosemite.epa.gov/ee/epa/eerm.nsf/vwGA/8B86459E07EC
of hazard stigma, when a place or a product is stigmatized, its economic value may decrease to levels below what one 

takes into account the actual risk associated with it. Consequently, the potential economic impact of product stigma m

difference between the market price and the lower (i.e., perceived risk adjusted) price which consumers are willing to is available), or the reduction in consumer demand and sales/revenues or market asset value. Adverse market effects 

from hazard stigma may be particularly acute, because according to psychological and anthropological research, peop

about even minute exposures to carcinogenic substances. 

• Scenario #2 of 5: Restrictions on “Use Constituting Disposal” (42% loss under Option 1; 7% loss under Op

For Option 1: The proposed CCR regulatory options based on RCRA Subtitle C propose to change the regulatory sta

hazardous waste. Because some beneficial uses (e.g., non-encapsulated uses) might become considered under 40 CF

state regulations, as by-products used in a manner constituting disposal (i.e., UCD “use constituting disposal”) by: 

• Direct placement on the land, or • Used to produce products that are applied to or placed on the land or are otherwise contained in products th

on the land. 

This scenario estimates that 42% of baseline beneficial uses might become subject to Federal or state regulations or re

beneficial uses of hazardous wastes. This estimate is based on 58% of CCR beneficial uses which may be considered represent encapsulated applications: cement (33.0%), concrete (8.5%), and wallboard (16.5%). The added cost of meC RCRA hazardous waste beneficial use regulations (addressed by the next Scenario #3), or state regulatory restrictio

encapsulated uses, or perception of new legal liabilities by industries beneficially using CCR, or market stigma, could For Option 3: Applying this scenario to only the fraction of wet CCR used as an input/ ingredient for beneficial uses. 

how much wet CCR annual tonnage goes to beneficial uses, this RIA assumes that the 16% wet CCR disposal tonnagannual disposal), is a proxy for that factor. Applying the 42% from above to 16% implies a beneficial use loss of 4% 

(16% wet CCR) = 7% loss).

• Scenario #3 of 5: Added Cost of RCRA Regulation of Beneficial Use (33% loss under Option 1; 5% loss un

This scenario is a variation built upon Scenario #2 above “use constituting disposal” whereby some UCD might conti

119 Source: Howard Kunreuther & Paul Slovic, “Coping with Stigma: Challenges and Opportunities,” Risk: Health, Safety & Environment, V

339 at: http://opim.wharton.upenn.edu/risk/downloads/01-07-HK.pdf 
For Option 1: The added cost for meeting the 40 CFR 266 Subpart C hazardous waste regulations for hazardous wast

(UCD) is estimated at $26 per ton of hazardous waste.120 At an average $13 per ton price for purchasing CCR for be

(source: Column E of Exhibit 3E), this additional Subtitle C regulatory cost could increase the price of CCR by 200% industries which use CCR for beneficial use applications. The implied higher Subtitle C regulated price of $39 per tooverall estimated $46 per ton average purchase price for substitute virgin materials for beneficial uses (source: Columthe $39 per ton price is higher than three beneficial use categories --- construction fill (16.8% of market), wallboard (45% of the minor uses (16.2%) --- of which construction fill and minor uses might be considered non-encapsulated Uthe higher regulated price could result in loss of 33% of beneficial use markets (i.e., 16.8% + 16.2%). For Option 3: Applying this scenario to only the fraction of wet CCR used as an input/ ingredient for beneficial uses. 

how much wet CCR annual tonnage goes to beneficial uses, this RIA assumes that the 16% wet CCR disposal tonnagannual disposal), is a proxy for that factor. Applying the 33% from above to 16% implies a beneficial use loss of 4% 

(16% wet CCR) = 5% loss). However, it is likely that most all baseline CCR supplied for beneficial uses is dewatere

• Scenario #4 of 5: State regulatory barriers (25% loss under Option 1; 4% loss under Option 3) 

For Option 1: On 08 July 2009, EPA ORCR received comments from EPA Region 5 that CCR disposal regulatory op

Subtitle C hazardous waste regulations, could reduce CCR beneficial use in at least three (MN, OH, WI) of the six sta

following reason: 

"Several [EPA] Region 5 states have submitted comments to EPA indicating that a hazardous waste listing wi

affect their beneficial use programs. Some states questioned whether they would be able to continue approvin[CCR] if they were considered hazardous when disposed because their beneficial use programs can only applhazardous waste.... Region 5 states have objected to a hybrid approach and believe it would still create barr

beneficial use programs. A few of our states (OH, MN, WI) can not apply their beneficial use programs to ha

In ORCR’s 16 April 2009 study “State Government Coal Combustion Waste Beneficial Use Programs and RCRA Ha

from the docket for the CCR proposed rule, EPA ORCR reviewed state waste management and industrial waste bene

states with relatively large annual tonnage generation of CCR (i.e., FL, GA, IA, IL, IN, MN, PA, TX, UT, WI). Basepresented in Exhibit 2B of this RIA, these 10 states represent 188 (i.e., 38%) of the 495 NAICS 221112 coal-fired elemillion (i.e., 42%) of the 149 million annual tons CCR generation (estimated in this RIA for 2007). The review revea

120 Source: Using recycling/recovery as a proxy for beneficial use, based on cost estimates for RCRA hazardous waste recycling/recovery pre

“Regulatory Impact Analysis: USEPA’s 2008 Final Rule Amendments to the Industrial Recycling Exclusions of the RCRA Definition of Soavailable at http://www.regulations.gov/fdmspublic/component/main?main=DocumentDetail&d=EPA-HQ-RCRA-2002-0031-0602. The $2

from this source by dividing its estimated $106.4 million/year baseline cost (source: DSW RIA Exhibit 6C) for compliance with Subtitle C hrecovery regulations pertaining to 4.13 million tons/year hazardous waste currently plus prospectively recycled/recovered (source: DSW RIA 
MN, PA, TX, WI) limit industrial waste beneficial use to non-hazardous wastes. Combining Region 5’s three states wApril 2009 study suggest that at least seven states (i.e., FL, IL, MN, OH, PA, TX, WI), which this RIA applies as a Creduction scenario for this Option. Based on 2007 DOE-EIA data presented in Exhibit 2B and Exhibit 3G, respectiv

account for 126 (i.e., 25%) of the 495 electric utility plants and account for 15 million tons (i.e., 25%) of the 60 millioannual CCR beneficial use (2007). This analysis suggests a potential 25% future loss in beneficial use for the Subtitl

For Option 3: Applying this scenario to only the fraction of wet CCR used as an input/ ingredient for beneficial uses. 

how much wet CCR annual tonnage goes to beneficial uses, this RIA assumes that the 16% wet CCR disposal tonnagannual disposal), is a proxy for that factor. Applying the 25% state government restrictions identified in scenario #4 beneficial use loss of 4% (i.e., (25% state restriction) x (16% wet CCR) = 4% loss).

• Scenario #5 of 5: Regulation avoidance (non-quantified increase) 

As estimated in Chapter 4 of this RIA, each regulatory option is expected to impose compliance costs on electric utilithat 28 of the 495 potentially affected plants solely provide CCR for beneficial uses, some additional plants may also 

disposal by solely providing their CCR to beneficial use applications, to avoid compliance costs. For example, one e

which plants may use to affect such a switchover from CCR disposal to increased CCR beneficial use by some electrioffer their CCR to other industries for free, which some plants currently do as evidenced by the zero ($0) low-end maranges displayed for three beneficial use categories (i.e., concrete, cement, wallboard) displayed in Column E of Exh

attempt to quantify this scenario, but as estimated in Exhibit 3F, CCR beneficial use has been growing an average an

2001 and 2009, which indicates growing national economic demand for CCR in beneficial uses might not be a constrfuture growth. 
Exhibit 6D 

($millions average annualized in 2009$) 

A. Possible percentage change in 

CCR beneficial use annual tonnage 

B. Possible change in national 

economic & environmental benefits 

C. Possibl

t

CCR Beneficial Use 

RCRA Regulatory Impact 

Scenario Option 1 Option 2 Option 3 Option 1 Option 2 Option 3 Option 1 

Baseline w/out RCRA regulation 62.1 million tons/year $24,597 per year 1. Market stigma Decrease not 

est. 

0% Decrease not 

est. 

Decrease not 

est. 

$0 Decrease not 

est. 

Decrease no

est. 

2. Restrictions on “use constituting disposal” (UCD) 

-42% 

(-26.1 mill.) 

0% -7% 

(-4.3 mill.) 

-$10.331 $0 -$1,747 +$2,219 

3. Added cost for UCD regulatory compliance 

-33% 

(-20.5 mill.) 

0% -5% 

(-3.1 mill.) 

-$8,117 $0 -$1,230 +$1,743 

4. State regulatory barriers -25% 

(-15.5 mill.) 

0% -4% 

(-2.5 mill.) 

-$6,149 $0 -$984 +$1,318 

5. Regulation avoidance Increase not 

est. 

0% Increase not 

est. 

Increase not 

est. 

$0 Increase not 

est. 

Decrease no

est. 

Notes: NA = Not applicable because potential impact on CCR beneficial use assumed in this RIA as only relevant to Subtitle C hazardous waste bas

Option 1 and Option 3). * Potential increase in annual disposal cost estimated as midpoint between two alternative CCR disposal sub-scenarios: 

• Onsite disposal: Cost estimate consists of two elements: 

o #1: RCRA Subtitle C permitting and lateral expansion of existing onsite landfills @$59 per ton baseline cost estimated in E

o #2: Incremental unit cost for regulatory options estimated in Exhibit 4N of this RIA without land disposal treatment (assum

to beneficial uses is dewatered by electricity plants prior to delivery to industrial users). Option 1: $6.35 per ton Option 3: $5.31 per ton 

o #1+#2: Total unit cost applied for onsite disposal: Option 1 = $65.35 per ton Option 3: $64.31 per ton 

• Offsite disposal: Cost estimate consists of two elements from which the midpoint is applied in this Exhibit: 

o #1: Landfill cost: @$61 to $139 per ton (midpoint = $100 per ton) for offsite commercial hazardous waste landfills (bulk w

reported in May 2004 by the Environmental Technology Council national survey at http://www.etc.org/costsurvey8.cfm

o #2: Trucking & manifesting cost: $5/ton average unit cost based on calculations from cost items 11A and 11B of the “Anc

Chapter 4 of this RIA (i.e., ($74.1 million/year) / (15 million tons/year associated with the Gambrills MD case study)). 

o #1+#2: Total unit cost applied for offsite disposal = $105 per ton 

• Midpoint applied between onsite & offsite disposal sub-scenarios: 

o Option 1: $85.18 per ton (rounded to $85 per ton) 

o Option 3: $84.66 per ton (rounded to $85 per ton) 
6D. Price and Capacity Impacts on Commercial Hazardous Waste Landfills

For the scenarios estimated in the prior section of this chapter involving an estimated range of 4% to 42% potential fubeneficial use under the Subtitle C options (i.e., Option 1 and Option 3), such loss would require additional disposal otons annually (i.e., (62.1 million tons per year beneficial use estimate for 2009) x (4% to 42%)), which will likely creproblems: 

1. Annual disposal rate exceedance: Relative to the range of 2.5 million to 26 million lost beneficial use annnua

smaller quantity of 2 million tons per year of RCRA-regulated hazardous waste which is currently disposed in 

permitted onsite (captive) and offsite (commercial) landfills in the US.121 This implies a potential 25% to 1,3

demand for hazardous waste landfill capacity. 

2. Limited geographic availability: There are currently 19 to 24 commercial hazardous waste landfills operating 

However, the CCR which is currently beneficially used is generated by 272 electric utility plants located in 41 

at commercial hazardous waste landfills would require out-of-state shipment involving at least 24 to 26 states 

commercial hazardous waste landfills. 

3. Remaining disposal capacity exceedance: The 19 to 24 commercial hazardous waste landfills have an availabl

of 21.7 million to 25.4 million tons hazardous waste.124 The 62.1 million tons per year of CCR beneficial use consume this entire remaining total capacity within one-half year or less. 

4. Increase landfill prices: In addition, such a large increase in nationwide economic demand for commercial haz

could drive-up landfill tipping fees which recently (2004) ranged between $61 and $139 per ton nationwide ($

121 Source: 2 million tons per year is based on the annual average of landfill tonnages reported for years 2001 (2.09 million tons), 2003 (1.68 

million tons), and 2007 (1.94 million tons) in EPA’s “RCRA National Analysis Biennial Hazardous Waste Report” at http://www.epa.gov/waste/inforesources/data/biennialreport/index.htm 

122 Source: These two ranges (i.e., 19 to 24 commercial haz waste landfill counts and 15 to 17 states) are from two alternative data sources: 

• Source #1 of 2: 24 commercial RCRA-permitted hazardous waste landfill count and 17 state identities as listed in the Hazardous Waste 

US Commercial Hazardous Waste Management Facilities,” Vol.25, Issue 1, 2007, pp.4.1 to 4.44. The 17 states are AL, AR, CA, CO, IDOH, OK, OR, TX, UT. 

• Source #2 of 2: As compiled 02 Oct 2009 by EPA OSWER-ORCR staff (Cpan Lee, Environmental Scientist), this available remaining 

three sources: (a) actual capacity estimates provided to OSWER-ORCR by facilities in April-Sept 2009, (b) information provided to OSand States in April/May 2009, and (c) capacity estimates developed by OSWER-ORCR using 1995-2007 RCRA Biennial Report data. ID, IL, IN, LA, MI, NV, NY, OH, OK, OR, TX, and UT. 

123 The 41 states are AL, AR, AZ, CO, DE, FL, GA, IA, IL, IN, KS, KY, LA, MA, MD, MI, MN, MO, MS, MT, NC, ND, NE, NH, NJ, NM

SD, TN, TX, UT, VA, WA, WI, WV, WY. 

124 Source: 02 Oct 2009 estimates by EPA OSWER-ORCR staff (Cpan Lee, Environmental Scientist) cited in prior footnote in this section of 
average).125 As verification of this potential effect on landfill prices, a recent (August 2009) market study126 o

hazardous waste industry, provides the following empirical evidence of price increases by commercial hazard

response to annual increases in landfill disposal tonnage: 

“On average, the number of surveyed landfill firms that increased prices exceeds the number that rece

volumes in 2008. Volumes increased for 50 percent of respondents and decreased for 42 percent, but prices and 33 percent left prices unchanged. The survey did not ask how much, if any, of the reported due to fuel surcharges. The survey did determine that 92 percent of respondents applied fuel surchargsurcharges cannot account for all of the price increases because the surcharges cover increased costsrespondents reported increased [profit] margins.” 

125 Source: US commercial hazardous waste landfill prices for bulk hazardous waste without treatment reported by the Environmental Techn

2004 Incinerator and Landfill Cost Data” website at http://www.etc.org/costsurvey8.cfm 

126 Source: Page 10 of “Hazardous Waste Industry Review 2008-2009,” Joan Berkowitz and Robert Crisp, Farkas Berkowitz & Company, A

http://www.farkasberkowitz.com/marketresearch.htm 
6E. Uncertainty in Land Disposal Treatment Sub-Option Cost Estimate There are two sources of uncertainty for this uncertainty factor: (1) uncertainty in the future count of electric utility pby this sub-option, and (2) uncertainty in the equipment/process modification cost to affected plants for complying wmagnitude of each uncertainty source is estimated separately below in this section. 

6E.1 Uncertainty in Plants Potentially Affected by This Sub-Option 

Chapter 4 of this RIA estimates the potential annualized costs for regulatory engineering controls, ancillary regulatory disposal treatment requirement based on the electric utility plant counts, CCR disposal methods (i.e., onsite or offsite or beneficial use) and associated CCR annual tonnages from the 2005 DOE-EIA Form 767 database supplemented wForm 860 database. However, with respect to the land disposal treatment cost estimate in this RIA, since 2005 some 

voluntarily eliminated wet CCR disposal, or are planning to eliminate wet disposal. For example, in August 2009 the Authority (TVA) announced a proposed plan to eliminate wet CCR disposal (i.e., to convert to dry disposal) at all 11 

utility plants over the next eight to ten years.127 TVA’s 11 plants represent 7% of the estimated 158 plant count using 

2005; if TVA voluntarily converts its 11 plants, the cost of the land disposal treatment sub-option attributable to the Cbe over-estimated by at least 7% in this RIA. 

6E.2 Uncertainty in the Per-Plant Equipment/Process Modification Cost for This Sub-Option 

In addition to the 2005 Tennessee Valley Authority (TVA) cost study referenced and applied in Chapter 4 of this RIA plant equipment/process modification cost for compliance with the land disposal treatment option, EPA ORCR is awcost studies (1981, 1985, and 2009) which are summarized in this section below. The first two studies provide cost e

basis for a few plant sizes, and the 2009 study provides a nationwide cost estimate. This RIA did not apply these othtwo are over 25-years old (i.e., 1981 and 1985) and the third study does not provide sufficient details for verification These studies are summarized below and used as a basis for formulating alternative nationwide cost estimates for the sub-option, for the purpose of illustrating the potential magnitude of uncertainty in this RIA’s cost estimate in relation 

• Study #1 of 3: 1981 TVA/EPA 

• In January 1981, TVA’s Energy Demonstrations and Technology Office (Chattanooga TN) co-authored with EPA’

Environmental Research Laboratory (Research Triangle Park NC) a study titled “Economic Analysis of Wet VersuSystems,” Interagency Energy/Environment R&D Program Report, report no. TVA/OP/EDT-81/30 and EPA-600-7

127 Source: 20 August 2009 TVA press release at http://www.tva.gov/news/releases/julsep09/ccprp_other.htm 128 Source: 1981 TVA/EPA report at 

http://nepis.epa.gov/Exe/ZyNET.exe/20006ORT.TXT?ZyActionD=ZyDocument&Client=EPA&Index=1981+Thru+1985&Docs=&Query=t
• The study compares the relative costs of wet and dry methods of coal ash disposal for five electric plant power size 

MW, 900 MW, 1,300 MW, 2,600 MW) with annual coal ash generation ranging from 0.2 million to 1.7 million per 

• Per-plant capital and O&M costs estimated based on 35-year assumed plant lifespan in 1980$. Capital costs for (a) 

handling systems, (b) conveyance/transport, and disposal units, were obtained from equipment suppliers. 

• The study found (page 67) there is not a significant difference in ash system economics based on the method of ana

analysis “indicates that wet disposal is typically the least cost alternative. However, various dry disposal options arange of those costs. The costs are, in fact, sensitive to spreading the dry disposal area capital costs over the life othe in-plant handling system cost. Use of either the lower dilute phase transport system cost or the dense phase coin the dry disposal system alternative become the least cost alternative.” 

• The study also noted that staged construction may provide 30% saving in system total cost: “[T]he above analyses 

all the required facilities upon start-up. In the case of dry disposal, this is a reasonable assumption although site p

proceed during the development of the site. In the case of wet disposal, it may be economically sound to construct even if the amount of material to be placed or the engineering estimate is higher for staged construction. This is dudam or levee and the cost of money over the life of the project. As an example... wet disposal area was analyzed fo

occurring in 1980 and by a staged construction sequence (3 stages). In this case, staged construction provided a 3

total cost of the system.” 

• The 1981 study used two cost methods. The “Present Worth” (aka present value PV) cost method findings (page 6

comparative ranges in wet dry versus wet disposal costs: 

Disposal method 1980$ cost ($/ton) 2009$ update ($/ton)129

Dry disposal $2.19 to $4.50 $4.81 to $9.87 Wet disposal $1.86 to $5.68 $4.08 to $12.46 

• Using the EPA ORCR 2009$ updated unit cost midpoints displayed above yields the following rough cost estima

utility plants with CCR impoundments: 

o Capital cost: (22.4 million tons per year wet CCR disposal for conversion at 158 plants) x ($4.81 to $9

unitized present value cost) x (40.6% capital cost fraction) x (50 years period-of-analysis for this RIA) $4,488 million present value capital cost Annualized capital cost: ($2,187 million to $4,488 million) x (0.07246 capital recovery factor @7% & million to $325.2 million per year 

o O&M cost130: (22.4 million tons per year wet CCR disposal for conversion at 158 plants) x [(($4.81 to 

disposal unitized present value cost) x (59.4% dry O&M fraction)) – (($4.08 to $12.46 per ton wet disp

&EndTime=&SearchMethod=3&TocRestrict=n&Toc=&TocEntry=&QField=pubnumber%5E%22600781013%22&QFieldYear=&QFieldMld=pubnumber&IntQFieldOp=1&ExtQFieldOp=1&XmlQuery=&File=D%3A%5Czyfiles%5CIndex%20Data%5C81thru85%5CTxt%5C000er=ANONYMOUS&Password=anonymous&SortMethod=h%7C-&MaximumDocuments=10&FuzzyDegree=0&ImageQuality=r75g8/r75g8/x150y150g16/i425&Display=p%7Cf&DefSeekPage=x&SearchB

ionS&BackDesc=Results%20page&MaximumPages=1&ZyEntry=1&SeekPage=x 

129 1980$ costs from the 1981 TVA/EPA study updated by EPA ORCR to 2009$ using the GDP calculator at http://cost.jsc.nasa.gov/inflateG
value cost) x (31.6% wet O&M fraction))] x (45 years dry disposal operational period 2017-2061 whicyears after 2012 final rule promulgation) = $1,580.5 million to $1,941.4 million present value O&M Annualized O&M cost: ($1,580.5 million to $1,941.4 million) x (0.07246 capital recovery factor @7% million to $140.7 million per year 

o Total annualized cost (capital + O&M) = ($158.5 million to $325.2 million per year capital) + ($114.5 

per year O&M) = $273 million to $466 million per year 

• Study #2 of 3: 1985 EPA 

• EPA’s Air and Energy Engineering Research Laboratory (Research Triangle Park NC) published cost estimates for 

disposal at coal-fired electric utility plants in the report “Full-Scale Field Evaluation of Waste Disposal from Coal-

Plants”, document nr. EPA/600/S7-85/028, August 1985, 12 pages.131

• This is a 3-year study of waste characterization, environmental data, engineering, and cost evaluations associated w

and FGD waste by six coal-fired electricity plants ranging in nameplate capacity between 310 to 1,786 megawatts aNC, PA, and WY. EPA used this study to assist preparation of EPA’s 1988 “Report to Congress on Wastes from thElectric Utility Power Plants” (report no. EPA530-SW-88-002, Feb 1988). 

• This study developed “generic” capital and annual O&M costs for both wet CCR pond disposal and dry CCR landf

involving fly ash, bottom ash, and FGD, based on specific costs for the six sites combined with cost estimates from 

EPRI, and other organizations. Exhibit 6E below displays the unitized capital costs and Exhibit 6F below displayfrom the study updated for this RIA to 2009 price level. 

• Using the 2009-updated mean unit capital and O&M cost estimates displayed in Exhibit 6E and Exhibit 6F, provi

estimates for conversion to dry disposal, based on extrapolation to 22.4 million tons per year baseline wet CCR (i.e

ash, wet FGD, wet gypsum, wet other CCR) disposal in impoundments at 158 of the 495 electric utility plants whic180,901 MW nameplate total capacity: 

o Capital cost: (180,901,000 kilowatt capacity for 158 electric utility plants with surface impoundments) x 

capital cost per kilowatt capacity from Exhibit 6E) = $6,810 million capital cost 

130 O&M cost extrapolation calculation in this RIA for the 1981 study applies two different O&M cost percentages based on the study’s 59.4

percentage derived from page B-10, and on the study’s 31.6% wet disposal O&M cost percentage derived from page C-11. 

131 Source: 1985 EPA AEERL report at 

http://nepis.epa.gov/Exe/ZyNET.exe/2000TNFC.TXT?ZyActionD=ZyDocument&Client=EPA&Index=1981+Thru+1985&Docs=&Query=

ethod=1&TocRestrict=n&Toc=&TocEntry=&QField=pubnumber%5E%22600S785028%22&QFieldYear=&QFieldMonth=&QFieldDay=&

FieldOp=1&ExtQFieldOp=1&XmlQuery=&File=D%3A%5Czyfiles%5CIndex%20Data%5C81thru85%5CTxt%5C00000010%5C2000TNFPassword=anonymous&SortMethod=h%7C-&MaximumDocuments=10&FuzzyDegree=0&ImageQuality=r75g8/r75g8/x150y150g16/i425&Display=p%7Cf&DefSeekPage=x&SearchB

ionS&BackDesc=Results%20page&MaximumPages=1&ZyEntry=1&SeekPage=x 
Annual equivalent cost: ($6,810 million) x (0.07246 capital recovery factor @7% & 50-years) = $4

o O&M cost: (22.4 million tons per year wet CCR disposed in impoundments) x (-$17.40 cost savings per 

disposal from Exhibit 6F) = -$389 million per year O&M cost savings. 

o Total average annualized cost (capital + O&M) = ($494 million/year capital cost) – ($389 million/year O

$105 million per year dry conversion cost. 

Exhibit 6E 

Comparison of Unitized Capital Costs for Wet and Dry CCR Disposal 

Source: 1985 EPA Study; $/kW 

Plant Size Categories (MW = megawatts) 

250 500 1000 2000 

Acr

Item Disposal Operation 

Wet or Dry 

CCR Min Max Min Max Min Max Min Max Min 

1A Fly ash handling/processing Wet $2.3 $6.8 $1.9 $5.5 $1.5 $6.4 $1.3 $3.6 $1.3 

1B Dry $2.2 $4.1 $1.8 $3.3 $1.4 $2.7 $1.2 $2.2 $1.2 

2 Fly ash storage Dry $4.7 $8.8 $4.2 $7.7 $3.7 $6.8 $3.2 $5.9 $3.2 

3A Fly ash transport Wet $3.5 $6.4 $2.7 $5.1 $2.2 $4.0 $1.7 $3.2 $1.7 

3B Dry $0.3 $0.5 $0.3 $0.6 $0.3 $0.5 $0.2 $0.5 $0.2 

4A Fly ash placement/disposal Wet $15.1 $27.8 $12.9 $23.9 $11.0 $20.5 $9.4 $17.5 $9.4 

4B Dry $4.3 $8.1 $3.3 $6.1 $2.5 $4.7 $1.9 $3.6 $1.9 

5 Bottom ash 

handling/processing 

Wet/Dry $2.2 $4.6 $1.7 $3.7 $1.3 $3.0 $1.0 $2.4 $1.0 

6A Bottom ash transport Wet $3.0 $5.6 $2.4 $4.5 $1.9 $3.6 $1.5 $2.8 $1.5 

6B Dry $0.2 $0.4 $0.2 $0.3 $0.1 $0.2 $0.1 $0.2 $0.1 

7A Bottom ash 

placement/disposal 

Wet $6.4 $11.8 $5.1 $9.6 $4.2 $7.7 $3.4 $6.2 $3.4 

7B Dry $1.3 $2.4 $1.1 $2.0 $0.9 $1.6 $0.7 $1.3 $0.7 

Summary: 

Wet Subtotal (1A+3A+4A+5+6A+7A) Wet (1982$) $32.5 $63.0 $26.7 $52.3 $22.1 $45.2 $18.3 $35.7 $18.3 

Dry Subtotal (1B+2+3B+4B+6B) Dry (1982$) $15.2 $28.9 $12.6 $23.7 $10.2 $19.5 $8.3 $16.1 $8.3 

2009 Updated Wet Subtotal* Wet (2009$) $72.8 $141.1 $59.8 $117.1 $49.5 $101.2 $41.0 $79.9 $41.0 

2009 Updated Dry Subtotal* Dry (2009$) $34.0 $64.7 $28.2 $53.1 $22.8 $43.7 $18.6 $36.0 $18.6 

* Note: 2009 price update multiplier (source: ENR Construction Cost Index ratio 2009:to:1982 = 8564/3825) = 2.239 
Exhibit 6F 

Comparison of Annual O&M Costs for Wet and Dry CCR Disposal 

Source: 1985 EPA Study; $/dry metric ton

Plant Size Categories (MW = megawatts) 

250 500 1000 2000 

Ac

Item Disposal Operation 

Wet or Dry 

CCR Min Max Min Max Min Max Min Max Min 

Fly Ash: 

1A Fly ash handling/processing Wet $2.5 $6.8 $1.0 $5.4 $1.6 $4.3 $1.3 $3.6 $1.0 

1B Dry $2.5 $4.7 $2.1 $3.9 $1.7 $3.2 $1.5 $2.7 $1.5 

2 Fly ash storage Dry $3.3 $6.1 $3.0 $5.6 $2.8 $5.2 $2.5 $4.7 $2.5 

3A Fly ash transport Wet $4.2 $7.6 $3.2 $5.9 $2.5 $4.7 $2.0 $3.7 $2.0 

3B Dry $1.7 $3.1 $1.5 $2.8 $1.3 $2.5 $1.2 $2.2 $1.2 

4A Fly ash placement/disposal Wet $11.5 $21.3 $9.1 $16.8 $7.2 $13.5 $5.7 $10.5 $5.7 

4B Dry $7.0 $13.0 $5.6 $10.5 $4.6 $8.5 $3.7 $6.9 $3.7 

 Subtotal fly ash Wet (1982$) $18.2 $35.7 $13.3 $28.1 $11.3 $22.5 $9.0 $17.8 $8.7  Dry (1982$) $11.2 $20.8 $9.2 $17.2 $7.6 $14.2 $6.4 $11.8 $6.4 

Bottom Ash: 

5 Bottom ash 

handling/processing 

Wet/Dry $11.3 $22.8 $9.0 $19.1 $6.9 $15.7 $5.3 $12.8 $5.3 

6A Bottom ash transport Wet $9.2 $17.1 $7.3 $13.5 $5.6 $10.3 $4.3 $7.9 $4.3 

6B Dry $3.4 $6.3 $2.8 $5.2 $2.2 $4.1 $1.8 $3.3 $1.8 

7A Bottom ash 

placement/disposal 

Wet $9.2 $17.1 $7.9 $14.6 $6.5 $12.1 $5.4 $10.0 $5.4 

7B Dry $5.4 $10.0 $4.7 $8.8 $4.1 $7.6 $3.5 $6.5 $3.5 

 Subtotal bottom ash Wet (1982$) $29.7 $57.0 $24.2 $47.2 $19.0 $38.1 $15.0 $30.7 $15.0  Dry (1982$) $20.1 $39.1 $16.5 $33.1 $13.2 $27.4 $10.6 $22.6 $10.6 

Summary (Fly Ash & Bottom Ash): 

Weighted average* Wet (1982$) $20.7 $40.4 $15.7 $32.3 $13.0 $25.9 $10.3 $20.6 $10.1 

 Dry (1982$) $13.2 $24.8 $10.8 $20.7 $8.8 $17.1 $7.3 $14.2 $7.3 

2009 updated weighted average** Wet (2009$) $46.4 $90.4 $35.2 $72.3 $29.1 $58.1 $23.1 $46.2 $22.6 

 Dry (2009$) $29.5 $55.6 $24.2 $46.4 $19.8 $38.3 $16.4 $31.8 $16.4 

Incremental cost from convers

Notes: * Fly:to:ash weighted average based on 2005 relative annual tonnages evaluated in the RIA: Fly ash tons/year = 15,200,000; Bottom ash ton** 2009 price update multiplier (source: ENR Construction Cost Index ratio 2009:to:1982 = 8564/3825) = 2.239 
• Study #3 of 3: 2009 USWAG 

• On 11 June 2009 the Utility Solid Waste Action Group (Jim Roewer, Executive Director) emailed to ORCR (Ma

page cost study USWAG sponsored by the EOP Group Inc., containing an estimate of $39,000 million present vato dry disposal: “Cost Estimates for Closure of Ash Ponds at Fossil Fuel Power Generation Facilities”, prepared Inc. USWAG/EOP’s $39,000 million PV estimate uses a 3% discount rate over 20 years with a 10-year implemeconsists of:

o $12,900 million PV (33%) for fly ash and bottom ash conversion to dry disposal

o $2,500 million PV (6%) for foregone sunk cost in pondso $23,700 million PV (61%) for construction of new wastewater plants for other non-ash ancillary wastewat

which are currently co-mingled with the wet ash.

• For purpose of comparing this estimate with the other two cost studies above, the following rough calculations ex

the 20-year period from the USWAG/EOP study, to the 50-year period applied in this RIA:

o Dry management O&M cost = ($2.00 per ton higher cost than wet management) x (20.6 million tons 

impoundments) x (40-years after 10-year impoundment phase-out) = $1,648 million (undiscounted). 

PV discounted @7% over 50-years = $279 million PV present value 

o Waste water treatment plant (WWTP) O&M cost = ($525 million per year) x (40-years after 10-year 

= $21,000 million (undiscounted). 

PV discounted @7% over 50-years = $3,558 million PV present value 

• Substituting these 50-year based PV O&M cost estimates for the 20-year based PV O&M cost estimates int

$39,000 million 20-year PV total cost estimate produces the following 50-year based average annualized co

o Capital cost:($39,000 million PV total cost) – ($400 million 20-year PV dry management O&M) – ($

WWTP O&M) = $33,400 million PV capital cost 

Annual equivalent capital cost: ($33,400 million PV) x (0.07246 capital recovery factor @7% & 50-yea

year annualized capital cost 

o O&M cost: ($279 million 50-year PV dry management O&M) + ($3,558 million 50-year PV WWTP 

PV present value O&M 

Annualized O&M cost: ($3,837 million PV) x (0.07246 capital recovery factor @7% & 50-years) = $27

o Total annualized cost (capital + O&M) = $2,698 million per year 

Exhibit 6G below presents a summary of the extrapolated cost estimates based on the per-plant cost findings from th

studies, compared to the cost estimate based on the 2005 TVA cost study applied in Chapter 4 of this RIA. 
Exhibit 6G 

Summary of Cost Estimates Based on Three Alternative Studies 1981, 1985, 2009 

Compared to the Cost Estimate of Chapter 4 in this RIA 

($millions updated to 2009$) 

A B C D 

Type of Dry Conversion 

Cost Element 

Cost Study #1 

EPA 1981 

Cost Study #2 

EPA 1985 

Selected for Basis 

of the Estimate 

Applied in this 

RIA 

Cost Study #3 

TVA 2005 

Cost Study #4 

USWAG/EOP 2009 

1. Capital cost: 

1a. Present value (PV) = $2,187 to $4,488 $6,810 $22,984 $33,400 

1b. Annualized equivalent* = $158 to $325 $494 $1,665 $2,420 

2. Average annual O&M cost $115 to $141 -$389 savings $11 $278 -3. Total annualized cost (1b+2) $273 to $466 $105 $1,676 $2,698 

Row 3 implied uncertainty range compared to estimate based on 2005 TVA study = 

*Note: Annualized over a 50-year period @7% discount rate. 
6F. Other CCR Disposal Units Not Covered by the Proposed Rule The scope of the proposed rule excludes two other categories of CCR disposal units from the regulatory options. The

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

• Inactive/Abandoned CCR Disposal Units Excluded from Scope 

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

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

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

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

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

capacity and have been permanently closed. 

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

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

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

abandoned).133 These two counts represent a ratio of 0.42 inactive/abandoned:to:active (i.e., 670:to:1,600). 

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

plants estimated in this RIA using CCR impoundments, yields an estimate of at least 66 inactive/abandoned CCR implocated at electric utility plants (i.e., (158 impoundment using electric utility plants) x (0.42 ratio) = 66). 

This RIA did not discover similar data for coal waste landfills in active and inactive/abandoned status. For purpose o

RIA, multiplying the 0.42 inactive/abandoned:to:active ratio by the 311 electric utility plants which use landfills, indi131 inactive or abandoned CCR landfills at or near electric utility plants (i.e., (311 landfill using electric utility plantsAs of 2004, the Mine Safety & Health Administration (MSHA) oversees 646 active coal mining slurry impoundment

MSHA “Supporting Statement” for Information Collection Request (ICR) 1219-0015 “Refuse Piles and ImpoundmenRecordkeeping and Reporting Requirements”, March 2008: http://www.msha.gov/regs/fedreg/paperwork/2004/04-24

132 Source: Definitions of “inactive” and “abandoned” coal waste impoundments from page 23 of the National Research Council book Coal WResponses and Alternatives, National Academy Press, 2002 at http://www.nap.edu/openbook.php?isbn=030908251X 133 Source: Counts of 1,600 active coal waste impoundments and 670 inactive or abandoned coal waste impoundments from the prior footnot
954 remainder active coal slurry impoundments (i.e., 1,600 – 646 = 954). Of these, this RIA estimates at least 158 acelectric utility plants, which implies that a fraction of 796 other active coal waste impoundments (i.e., 954 – 158 = 79electric power plants in non-utility industries (see the next sub-section below on “Other Industries Excluded from Sco

• Other Industries Excluded from Scope 

The scope of the proposed rule only includes NAICS code 22 coal-fired electric utility plants (495 plants). However, 759 non-utility facilities which currently, or have the capacity to, burn coal and thus generate CCR. Adding these facproposed rule could increase the cost estimates by 2% to 28%. This range is based on the following two data sourcesSource #1: As displayed below in Exhibit 6H, based on 2005 data from the DOE-EIA, there are 139 non-utility c

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

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

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

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

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

size), the 5,959 MW capacity of the 139 non-utility electricity plants represents about 2electricity generation capacity. For purpose of rough estimation – in so far that electriccorrelates to annual CCR generation and thus to annual CCR disposal costs and to regu

percentage indicates that the additional economic impact of including these additional 1the proposed rule might add at least 2% to the cost estimates under each regulatory opti

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

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

Source #2: EPA’s 2002 analysis134 of the results from a 2001 survey of non-utility CCR generation identified 759 

the capacity to burn coal, and therefore, generate CCR.” The estimated annual CCR generation for the

tons (as of year 2000), which is 5.5% to 6.3% of the 123.1 million to 141.2 million tons CCR generate

in 2005 as estimated in Exhibit 2D of this RIA. Allowing for annual growth of the 7.8 million tons siadding these 759 facilities to the scope of the proposed rule could increase the cost estimates by 7%.

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

Science Applications International Corp (SAIC) Engineering & Environmental Management Group (Reston VA) under subcontract to EasterVA), April 2002, EPA contract No. 68-W-02-036, WA 12:. 
Exhibit 6H 

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

2005 

Count 

NAICS 

Sector 

NAICS 

Industry NAICS Industry Code Definition 

2005 

Boiler coun

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

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

 Count = 8 Count = 27 Column Totals = 354 

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

Notes: (a) Source: US Dept of Energy, Energy Information Administration (EIA), 2005 Form EIA-860 "Annual Electric Generator Rep"Existing Electric Generating Units in the United States, 2005" at http://www.eia.doe.gov/cneaf/electricity/epa/epat2p2.html

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

group, the fifth digit designates the NAICS industry, and the sixth digit designates the national industry. The five-digit NAICS cwhich there is comparability in code and definitions for most of the NAICS sectors across the three countries participating in NAStates, Canada, and Mexico). The six-digit level allows for the United States, Canada, and Mexico each to have country-specific and valid NAICS code contains six digits. Source: http://www.census.gov/eos/www/naics/faqs/faqs.html#q5 
Chapter 7 

Potential Benefits of CCR Disposal Regulation at Electric Utility Pla

The potential benefits of CCR regulation identified in this chapter are based on three categories of risks which the proformulated to reduce, thereby providing future hazard risk reduction benefits: 

• Community safety benefits • Human health benefits • Ecological benefits 

The first category is largely based on engineering information from secondary published sources135 and on EPA’s col

damage cases associated with CCR disposal units located at coal-fired electric utility plants, and the second and third 

summary from EPA’s 2007 draft risk assessment for CCR disposal units. 

7A. Community Safety Benefits 

• Causes of Failures Involving Industrial Surface Impoundments 

Thousands of large industrial surface impoundments worldwide contain billions of tons of mineral extraction and proOver their operational lifespans, most surface impoundments are raised sequentially using the "upstream" constructio

level of the impounded waste during the filling process. This method, while available at low cost, implies a number ostructural stability. These hazards require assessment, monitoring and control during siting, construction, and operati

impoundments. Examples of possible failure mechanisms (i.e., failure causes) are:136

135 EPA is aware of one additional published study not otherwise cited or applied in this RIA, which provides monetized estimates of two po

human health benefits for EPA regulation of CCR disposal units: a recent (June 2009) report published by the Institute for Policy Integrity (I

reduced future cleanup costs associated with a reduction in the future probability of catastrophic failure of CCR impoundments, and (b) mon

exposure to chemicals leaching from CCR disposal units. However, the IPI report does not derive a nationwide, average annualized future vfrom its presentation of single facility-based estimates. Source: “No More Excuses: The Economic Case for Coal Ash Regulation,” J.Scott H

Integrity, New York University School of Law, Policy Brief No.3, June 2009, 40 pages at http://www.policyintegrity.org/publications/docum

136 Source: The following website provides color animations of these major failure mechanisms: “Safety of Tailings Dams,” World Informa

is an information and networking center for citizens and environmental organizations concerned about nuclear energy, radioactive waste, radhttp://www.wise-uranium.org/mdas.html#DISAST 
• Weak base: If the soil or rock at shallow depth below the dam is too weak to support the impoundment, mov

plane will occur. This may result in partial or complete failure of the dam. 

• Earthquakes: During cyclic mechanical stress as experienced during seismic events, the slurries (including th

impoundment) may liquefy. 

• Over-filling: Excessive rises in the level of the water ponding in the impoundment can also cause failures. Th

by inflow from heavy rainfall or melting snow, or by overfilling or overtopping with excessive 

• Seepage: Piping occurs if seepage within or beneath the impoundment causes erosion along its flowpath. 

result in local or general structural failure of the impoundment. 

• Overbuild: If the sides of an impoundment are raised too fast to add capacity, structural failure can occur fr

pressure within the impoundment. 

• Failures Involving Industrial Surface Impoundments in the USA 

According to one historical review137 of “major failures” involving industrial surface impoundments, in the USA, 28 

historical major failures (i.e., 32%) occurred in 13 states (AZ, CO, FL, KY, MD, MS, MT, NC, NM, NV, TN, TX, W

average annual rate of 0.6 major failures per years (i.e., (28 incidents) / (48 year historical period)). The 28 major faifollowing 9 industries: 

1. NAICS 21211 coal mining (n = 5) 2. NAICS 212234 copper ore mining (n = 3) 3. NAICS 212221 gold ore mining (n = 2) 4. NAICS 212231 lead ore & zinc ore mining (n = 1) 5. NAICS 212321 construction sand & gravel mining (n = 1) 

6. NAICS 212291 uranium ore mining (n = 2) 7. NAICS 212399 gypsum mining, mica mining (n = 2) 8. NAICS 221112 fossil fuel electric power generation138 (n = 1) 

9. NAICS 325312 phosphate fertilizer manufacturing (n = 11) 

• Damage Cases Involving Electric Utility Industry CCR Surface Impoundments 

137 Source: “Chronology of Major Tailings Dam Failures” at: http://www.wise-uranium.org/mdaf.html 138 This is the NAICS that is applicable to EPA’s CCR proposed rule. 
The scope of the regulatory options addressed in this RIA is limited to NAICS 22 coal-fired electric utility plants. Hoeconomic, environmental, and human health damages, and baseline risks associated with at least two other out-of-scoimpoundments located at electricity utility plants: 

• Damages & risks from impoundments similar in size to those in other out-of-scope industries: 

One recent example is the 08 March 2009 pipeline rupture at a western Maryland paper mill (NAICS code 32electricity, which spilled approximately 4,000 gallons of slurried coal ash into the North Branch of the Potomnorthwest of Washington DC. The Maryland spill occurred at New Page Corp., which powers its paper mill imegawatt coal-fired plant and pipes slurried coal ash to a storage lagoon that it owns and operates across the r

The lagoon has a capacity of roughly 1.2 million gallons. (Source: The Bureau of National Affairs, Daily Env

March 2009, Vol.45, page A-13: http://www.bna.com/products/ens/bder.htm). 

• Damages & risks from other types of out-of-scope secondary materials generated by the utility electricity indu

An example of this second category is the January 9, 2009, Tennessee Valley Authority (TVA) coal waste spiplant in northeast Alabama, less than three weeks after the enormous Tennessee coal ash spill at TVA's Kingsspill, which TVA said originated from a gypsum treatment operation, released about 10,000 gallons of toxic gwhich spilled into Widows Creek and the nearby Tennessee River. Gypsum ponds contain limestone spray frwhich trap sulfur dioxide emissions before they are released into the air and turn them into sludge and solid w

Under the 1980 Bevill amendment for the “special waste” categories of the Solid Waste Disposal Act (also known as amendment), EPA was statutorily required to examine “documented cases in which danger to human health or the enproved” from the disposal of the coal combustion residues. After publishing the1988 Report to Congress on “Wastes 

Coal by Electric Utility Power Plants139,” EPA received alleged damage cases from citizens and groups from 1988 to 

gathered or received information on 135 possible damage cases and has evaluated 85 of these cases. Of the 85 cases determined that 24 were proven cases of damage.140 Forty-three cases were determined to be potential damages to gr

water and 18 cases were determined to be rejected. The 67 proven and/or potential damage cases were reported in th

139 EPA -OSWER1988 Report to Congress: “Waste from the Combustion of Coal by Electric Utility Power Plants,” report nr. EPA/530-SW

http://www.regulations.gov as document ID nr. EPA-HQ-RCRA-1988-0094-0035, 500 pages. The companion Appendices are available as d

RCRA-1988-0094-0036. 

140 EPA applied the following three criteria for classification of the damage cases in the July 2007 CCR damage case report. These criteria a

Regulatory Determination (Federal Register, Vol. 65, p. 32224): 

• Documented exceedances of primary MCLs or other health-based standards measured in ground water at sufficient distance from the 

indicate that hazardous constituents have migrated to the extent that they could cause human health concerns, and/or 

• Where a scientific study demonstrates there is documented evidence of another type of damage to human health or the environment (e

• Where there has been an administrative ruling or court decision with an explicit finding of specific damage to human health or the en

management of CCRs with other industrial waste types, CCRs must be clearly implicated in the reported damage. 

These three criteria resulted in 24 proven damage cases and 43 potential damage cases, for a total of 67 damage cases listed in the July 2007 
Combustion Waste Damage Case Assessment” report available at http://www.publicintegrity.org/assets/pdf/CoalAshEPA-HQ-RCRA-2006-0796. The damage cases span the 61-year historical period from 1948 to 2008. 

For purpose of summarizing these historical CCR damage cases in this RIA, this RIA presents a summary of the quan

(i.e., physical and cost indicators) reported in the documentation for some of the cases listed in the July 2007 damage two more recent damage cases. The following steps describe how the quantitative indicators were obtained for summ

Step 1: Reviewed the 67 damage cases in July 2007 report to determine and obtain the quantitative indicat

Because only a small number of the written case descriptions in the 2007 report contained quantita

for background documentation for the cases in the July 2007 report, which yielded the following d

• Memorandum from November 29, 2000 to Dennis Ruddy, EPA from Pat Ransom and Rich 

Review of Causative Factors for Coal Combustion Waste Damage Cases 

• Memorandum from April 20, 2000 to Dennis Ruddy, EPA from Jennifer Cohen and Pat Ra

Additional Information Regarding Fossil Fuel Combustion Waste Damage Cases 

• Memorandum from April 20, 2000 to Dennis Ruddy, EPA from Jennifer Cohen and Pat Ra

Rationale and Conclusions Regarding Commenter-Identified Fossil Fuel Combustion Wast

• Memorandum March 5, 2003 to Dennis Ruddy, EPA from Pat Ransom and Sara Dennis, S

Report on Resolution of 18 Previously Indeterminate Candidate Damage Cases 

Step 2: Obtained information about three additional CCR damage cases not listed in the July 2007 damage 

December 2008 TVA Kingston TN damage case, (b) the January 2008 Constellation Energy Gamband (c) the August 2005 PPL Martins Creek PA power plant damage case. Furthermore, in the Ste

2007 report, identified four cases which apparently pertain mainly to oil waste release damages rat

(i.e., FP&L Port Everglades, FP&L Rivera, FPC P.L. Bartow, Brayton Point). Addition of the thre

subtraction of the four oil cases resulted in 66 relevant CCR damage cases from 1948 to 2008 (i

cases including TVA TN, Martins Creek PA, Gambrills MD, plus 39 potential CCR damage cases

Step 3: Review of the July 2007 report, background documents, and three recent cases resulted in the data 

which some cases contained data. Appendix Q of this RIA presents a table of the data extracted f

1. Case ID number 2. State location 3. Site name 4. Active or inactive CCR disposal unit 5. Reference year (i..e., year associated with contamination event or year of contamination dis6. Type of CCR disposal unit involved 

7. Lined or unlined CCR disposal unit 
8. CCR disposal unit onsite or offsite 9. Site acres 10. CCR disposal unit operating lifespan 11. Tons CCR released 12. Acres of contamination 13. First year of cleanup 14. Count of homes damaged 15. Off-site contamination 16. Fish kill 

• Summary of Electric Utility CCR Disposal Damage Case Findings 

Exhibit 7A below provides a state-by-state count of damage cases and count of associated CCR disposal units in the 

or potential damage cases reported in EPA’s July 2007 “Coal Combustion Waste Damage Case Assessment” report. 

report contains 85 cases, not all of them are actually relevant to CCR disposal units, as explained above. 

Exhibit 7A 

State-by-State Count of Historical CCR Disposal Damage Cases 

1948-2008

Item State 

Count of CCR 

damage cases 

Count of CCR disposal units 

identified in damage cases 

1 AZ 1 1 2 FL 1 1 3 GA 1 1 4 IA 1 1 5 IL 8 8 6 IN 7 7 7 KY 1 1 8 MA 3 3 9 MD 2 3 

10 MI 1 3 11 MN 1 1 12 NC 3 3 13 ND 3 4 14 NY 4 4 15 OH 3 3 16 PA 2 2 17 SC 2 3 
Exhibit 7A 

State-by-State Count of Historical CCR Disposal Damage Cases 

1948-2008

Item State 

Count of CCR 

damage cases 

Count of CCR disposal units 

identified in damage cases 

18 TN 5 5 19 TX 3 3 20 VA 2 3 21 WI 11 11 22 WY 1 2 

Column totals= 

66 

(average = 1.08 

cases per year) 

73 

(average = 1.20 disposal 

units per damage case 

• Of the total of 66 damage cases there were: 

o 30 known off-site contamination cases o 21 known on-site contamination cases o 15 cases that did not state whether the contamination was on-site or off site. 

• As counted in Exhibit 7B below, four different types of CCR disposal units were involved in the damage case

o 24 impoundments (aka ponds, settling basins, dams, embankments, constructed wetlands) o 21 landfills (this includes at least one case in which the CCR landfill was formerly a “gravel quarry pito 5 sand & gravel pits (aka quarries) o 1 ash pile o 22 units not classified 

The count of 73 CCR disposal units does not include all units associated with the 66 damage cases because some casemultiple units but did not provide a count of units. For example if the word “ponds” was used in some damage cases 

many ponds were related to those cases; only one pond was counted in Exhibit 7B below. According to operational 

• Active: 7 active CCR disposal units (i.e., 29% of known operating status units) • Inactive: 18 inactive CCR disposal units (i.e., 71% of known operating status units). This RIA assumed a C

inactive if the unit was stated in the damage case as no longer being used for disposal or if a cap w

• Unknown: 48 CCR disposal units involved in the damage cases were not clearly defined as either active or ina

Exhibit 7B, Exhibit 7C and Exhibit 7D below summarize the quantitative data from the damage cases. 
Exhibit 7B 

State-by-State Counts of CCR Disposal Units Involve d in the 1948-2008 Damage Cases (61-year historical p

A B C D E F G 

Item State Landfill 

Pond (aka impoundment 

or settling basin) 

Sand, Gravel 

Pit or Quarry 

Ash 

Pile 

Unknown 

Type 

1 AZ 0 1 0 0 0 2 FL 0 0 0 0 1 3 GA 0 1 0 0 0 4 IA 1 0 0 0 0 5 IL 2 1 0 0 5 6 IN 2 2 0 0 3 7 KY 1 0 0 0 0 8 MA 3 0 0 0 0 9 MD 1 1 1 0 0 

10 MI 1 0 0 0 2 11 MN 0 0 0 0 1 12 NC 0 1 0 0 2 13 ND 0 3 0 1 0 14 NY 1 0 0 0 3 15 OH 1 1 0 0 1 16 PA 1 1 0 0 0 17 SC 0 2 0 0 1 18 TN 0 3 0 0 2 19 TX 0 3 0 0 0 20 VA 0 2 1 0 0 21 WI 5 2 3 0 1 22 WY 2 0 0 0 0 

 Column Totals = 

(% of known types) 

21 

(41%) 

24 

(47%) 

5 

(10%) 

1 

(2%) 22 

(51 

Counts if proportionately 

extrapolated to all 73 units 30 34 7 1 0 

Average annual frequency 

Over 61-year historical 

period 1948-2008 

0.49 0.56 0.12 0.02 
Exhibit 7C 

Physical Characteristics of CCR Disposal Damage Cases (1948-2008) 

Data Type Site Acres 

CCR Disposal 

Unit Operating 

Lifespan (years) 

Tons of CCR 

Released from 

Disposal Unit 

Acres of 

Contamination 

Nu

H

D

Maximum 235 23 10.0 million* 275 Minimum 8.5 8 80 13 Count of cases with data 9 8 2 3 Average per case 75 14 5.0 million 103 * Note: 10.0 million tons represents the reported 5.4 million cubic yard release December 2008 at the TVA Kingston Tmultiplied by 1.85 short tons per cubic yard average density for all types of coal ash. 

Exhibit 7D 

Summary of Types of CCR Disposal Damage Case Contamination (1948-2008)

Type of Contamination Proven Damage Cases 

Potential Damage 

Cases 

Row Totals 

(% of known typ

Ground Water 18 25 43 (69%) Surface Water 10 3 13 (21%) Wetlands 4 0 4 (7%) Dust 2 0 2 (3%) Unknown Type of Contamination 2 13 15 

Totals = 34 41 77* (62 known t

* Note: Some damage cases had multiple types of contamination so the total count of types of contamination in this taexceed the total count of damage cases. 

Although the 1976 RCRA statute does not require benefit-cost justification of RCRA regulations, OMB’s 2003 “CircAnalysis” best practices guidance states (pages 18 and 27) that: 

“[RIAs] should discuss the expected benefits and costs of the selected regulatory option and any reasonable a

should monetize quantitative estimates whenever possible.... If you are not able to quantify the effects [benefi

should present any relevant quantitative information along with a description of the unquantified effects, such gains, improvements in quality of life, and aesthetic beauty.” 

The historical damage case summary information provided in Exhibit 7A, Exhibit 7C and Exhibit 7D above may be 

quantitative estimate of baseline average annual damage cases and associated damage costs. The expected benefits opotential reduction in the baseline frequency of cases and costs. Over the 61-year period 1948-2008 there have been 

cases involving CCR disposal units, which represents a baseline average frequency of 1.08 cases per year (i.e., (66 ca
on incomplete economic damage data from those cases, and using the actual average per-acre cleanup cost from a 200Kingston TN), indicates the following baseline average annual damage costs for cleanup: 

(1.08 cases per year) x (31% known cases involving surface water, wetlands, dust requiring cleanup, which ex

cases that only involved groundwater contamination) x (average 103 acres contamination per damage case) x 

million per acre)141 = $117 million to $152 million per year. 

However, cleanup costs do not represent all economic damages, so this is an underestimate because it does not includleast eight other categories of economic damages: 

1. Damages to local infrastructure (roadways, water supply, energy supply, sewerage, telecommunications) 2. Lost sales and service revenues from business closures (temporary or permanent) 3. Lost employment from business closures (temporary or permanent) 4. Damages to housing, community buildings (churches, schools), parks 

5. Damages to landscape aesthetic values 6. Damages to human health 7. Damages to ecosystems 8. Damages to environmental attributes (e.g., natural resources)

141 Initially (Feb 2009), TVA estimated the cost of clean-up for the Kingston TN plant coal ash spill (22 Dec 2008) could cost between $525 

cost depended on the disposal method of the 5.4 million cubic yards of ash that spilled affecting 275 acres. The range does not include costs actions, litigation or long-term environmental remediation. Source: Waste & Recycling News, 13 Feb 2009; http://www.wasterecyclingnews.com/email.html?id=1234543579 On 18 Aug 2009, TVA published a revised estimate of cleanup costs: “Du

of the final methods of remediation, a range of reasonable estimates has been developed by cost category and either the known amounts, mosend of the range for each category has been accumulated to determine the total estimate. The range of estimated costs varies from approximaapproximately $1.2 billion.” This implies an average unitized cost for clean-up of $3.4 million to $4.4 million per acre. .Source: page 13 of FY2009”, 18 Aug 2009 at http://www.tva.gov/kingston/admin_record/pdf/51.pdf 
Exhibit 7E below provides a summary of the state location, name of electric utility plant, type of CCR disposcontamination, and types of chemical contaminants identified for each of the 66 damage cases involving at lea

Exhibit 7E 

Unit-by-Unit Summary of 1948-2008 CCR Damage Cases Involving at Least 73 CCR Disposal Units 

A B C D E 

Row 

item State 

Damage case 

site name 

(Electricity plant) 

Type of CCR disposal 

unit involved in damage 

Type of 

contamination Chemical contamin

1 MA Salem Acres Site landfill 

Groundwater, wetlands 

polycyclic aromatic hydioxins/furans, volatile chromium, arsenic, be

2 MA City of Beverly/Vitale Brothers Fly Ash Pit landfill 

Groundwater, surface water, dust arsenic, iron, mangane

3 NY Don Frame Trucking, Inc. Fly Ash Landfill Groundwater lead 4 VA Virginia Electric Power Co. Possum Point pond cadmium, nickel 5 VA Virginia Electric Power Co. Possum Point pond Groundwater cadmium, nickel 6 MD 

PEPCO Morgantown Generating Station Faulkner Off-site Disposal Facility landfill 

Groundwater, surface water, wetlands 

7 MD 

PEPCO Morgantown Generating Station Faulkner Off-site Disposal Facility pond 

Groundwater, surface water, wetlands 

8 VA 

Virginia Power Yorktown Power Station Chrisman Creek Disposal Site sand & gravel pit 

Groundwater, surface water 

vanadium, selenium, acopper, molybdenum, 

9 NC Hyco Lake Roxboro pond selenium 

10 GA Georgia Power Company Plant Bowen pond Surface water 11 TN 

DOE Oak Ridge Y-12 Plant Chestnut Ridge Operable Unit 2 DOE Oak Ridge Reservation, Oak Ridge pond Surface water 

Al, Fe, Cu, As, Ca, MnV, Zn, Hg, Se 

12 SC South Carolina Electric & Gas Canadys Plant pond Groundwater nickel 13 SC South Carolina Electric & Gas Canadys Plant pond arsenic 14 NC Belews Lake selenium 15 SC U.S. DOE Savannah River Project 16 WI 

Dairyland Power Cooperative E.J. Stoneman Generating Station Ash Disposal Pond pond Groundwater sulfate, boron 

17 WI WEPCO Highway 59 Landfill sand & gravel pit 

Wetland, ground water 

sulfate, boron, manganchloride, selenium 

18 WI Alliant Nelson Dewey Ash Disposal Facility Settling basins Groundwater arsenic, selenium, sulf19 WI WEPCO Cedar-Sauk Landfill sand & gravel pit 

Groundwater, wetland selenium, sulfate, boro

20 WI WEPCO Port Washington Facility Quarry Groundwater boron, selenium 
Exhibit 7E 

Unit-by-Unit Summary of 1948-2008 CCR Damage Cases Involving at Least 73 CCR Disposal Units 

A B C D E 

Row 

item State 

Damage case 

site name 

(Electricity plant) 

Type of CCR disposal 

unit involved in damage 

Type of 

contamination Chemical contamin

21 MI 

Lansing Board of Water& Light North Lansing Landfill landfill Groundwater lithium, manganese, p

22 MI 

Lansing Board of Water & Light North Lansing Landfill 

NA (not used for disposal) 

23 MI 

Lansing Board of Water& Light North Lansing Landfill lithium, manganese, p

24 IN 

NIPSCO Yard 520 Landfill Site Township of Pines landfill Groundwater benzene, arsenic, man

25 TX Brandy Branch Reservoir 

cooling reservoir received discharge from ash ponds Surface water selenium 

26 TX 

Southwestern Electric Power Company Welsh Reservoir 

cooling reservoir discharge from an open settling pond Surface water selenium 

27 TX Texas Utilities Electric Martin Lake Reservoir ponds Surface water selenium 28 ND 

Basin Electric Power Cooperative W.J. Station Surface Impoundment impoundment Groundwater 

29 ND 

Cooperative Power Association/ United Power Creek Station Surface Impoundments pond 

30 ND 

Cooperative Power Association/ United Power Creek Station Surface Impoundments pond Groundwater arsenic, selenium, sulf

31 MA 

Rezendes South Main Street Ash Landfill, Freetown landfill Groundwater sulfates, manganese, ir

32 NY 

AES Creative Resources Weber Ash Disposal Site Groundwater sulfate, manganese, iro

33 NY 

Central Hudson Gas and Electric Corporation Danskammer Waste Management Facility 

sulfate, sulfide, dissolvmagnesium, manganes

34 NY C.R. Huntley Fly ash Landfill landfill Groundwater 

arsenic, iron, manganesolids 

35 PA Elrama Plant landfill Groundwater cadmium 36 TN 

Tennessee Valley Authority Bull Run Steam Plant, Oak Ridge Surface water aluminum, calcium, ir

37 TN 

Tennessee Valley Authority Widows Creek Fossil Fuel Plant Alabama Groundwater cadmium, chromium 

38 TN 

Tennessee Valley Authority Colbert Fossil Fuel Plant, Alabama impoundment Groundwater cadmium, sulfate, chro

39 NC Duke Power Allen Steam Generating Plant Groundwater manganese, iron 40 KY Cinergy East Bend Scrubber Sludge Landfill landfill dissolved solids, iron, 
Exhibit 7E 

Unit-by-Unit Summary of 1948-2008 CCR Damage Cases Involving at Least 73 CCR Disposal Units 

A B C D E 

Row 

item State 

Damage case 

site name 

(Electricity plant) 

Type of CCR disposal 

unit involved in damage 

Type of 

contamination Chemical contamin

41 FL Florida Power and Light Lansing Smith Plant Ground water 

cadmium, chromium, manganese 

42 IL 

Commonwealth Edison Powerton Plant Mahoney Landfill Pekin Tazewell County landfill Ground water cadmium, lead, nitrate

43 MN 

Xcel Energy Southern Minnesota Municipal Power Agency Sherburne County (Sherco) Generating Plant Becker 

arsenic, cadmium, chrnitrate, chloride, coppezinc 

44 WI Alliant Rock River Ash Disposal Facility Ground water arsenic, mercury, sulfa45 IN Michigan City Site, Michigan City pond Ground water arsenic 46 IN Bailly Generating Station pond Groundwater arsenic, lead, cadmium 47 WI Alliant Edgewater 1-4 Ash Disposal Site landfill Ground water boron, sulfate, iron, ch48 WI 

Wisconsin Power Supply Co (WPSC) Pulliam Ash Disposal Site landfill Ground water sulfate, manganese, iro

49 IL Central Illinois Light Co Duck Creek Station 

sulfate, total dissolved iron 

50 IL Illinois Power Co. Hennepin Power Station Groundwater sulfate, total dissolved 51 IL Illinois Power Co Havanna Power Plant impoundment manganese, sulfate 52 WI 

Dairyland Power Alma On-site Fly Ash Landfill landfill Groundwater sulfate, manganese 

53 WI 

Dairyland Power Alma Off-site Fly Ash Landfill landfill sulfate, manganese, bo

54 IL Illinois Power Vermillion Power Station Groundwater sulfate, total dissolved 55 IL 

Central Illinois Public Service Company Hutsonville Power Station Groundwater sulfate, total dissolved 

56 IL 

Illinois Power Company Wood River Power Station Groundwater 

sulfate, total dissolved iron 

57 IN R.M. Schahfer Generating Station sulfate 58 IL 

Coffeen/White & Brewer Trucking Fly Ash Landfill landfill Sulfate, total dissolved 

59 IN 

Southern Indiana Gas and Electric Company (SIGECO) A.B. Brown Generating Station Sulfate total dissolved 

60 OH 

Cincinnati Gas & Electric Co Miamiview Landfill landfill Sulfate 

61 IN 

Indiana Power & Light Peterburg Generating Station sulfate, total dissolved 

62 IN 

Hoosier Energy Mermon Generating Station Coal Combustion Waste Landfill landfill Groundwater barium, chromium, ca
Exhibit 7E 

Unit-by-Unit Summary of 1948-2008 CCR Damage Cases Involving at Least 73 CCR Disposal Units 

A B C D E 

Row 

item State 

Damage case 

site name 

(Electricity plant) 

Type of CCR disposal 

unit involved in damage 

Type of 

contamination Chemical contamin

63 OH Cinergy W.C. Beckjord Station Groundwater sulfate 64 WI Lemberger Landfill landfill 

Ground water, surface water 

volatile organic compochromium, cadmium, 

65 OH Conesville Fixed FGD Sludge Landfill pond 

lead off-site, (chromiuselenium on-site) 

66 IA Muscatine County Landfill landfill sulfate, selenium 67 WY Dave Johnston Power Plant landfill Ground water cadmium, manganese, 68 WY Dave Johnston Power Plant landfill 69 ND 

Montana Dakota Utilities R.M. Heskett Station pile Ground water sulfate, boron 

70 AZ 

Arizona Public Service Co. Cholla Steam Electric Generating Station pond Groundwater sulfate, total dissolved 

71 TN TVA pond Surface water arsenic 72 PA Martin's Creek PA Power Plant Pond Surface water 73 MD Constellation Energy Gambrills MD quarry Groundwater, dust 

Arsenic, beryllium, suthallium, aluminum, m

Note: Blank cells in this table indicate that information was not readily available. 
7B. Human Health Benefits This section describes some of the human health hazard risks which RCRA regulation of CCR disposal may reduce. 

based on information published in EPA’s 1998 and 2009 CCR risk assessment studies referenced in the Federal Regi

CCR proposed rule. Complete references and details for the summarized information below are provided in those stuHuman health risks to human individuals may occur from exposure to chemical constituents in CCR. Exposure may 

exposure routes. Potential chemical constituent releases from CCR landfills and surface impoundments include: 

• Leaching of CCR to ground water 

• Overland transport of CCR from erosion and runoff 

• Air emissions of CCR 

The potential of exposure from any one of these exposure pathways for a particular chemical is dependent on the phycharacteristics of the chemical, the properties of the waste stream, and the environmental setting. EPA conducted a p

assessment of potential human health risks from CCR constituents leaching to groundwater that subsequently migrate

drinking water well, or to nearby surface water, and is ingested as drinking water or through fish consumption. EPA 

preliminary analysis of human health effects from constituents that have eroded or run off from waste management uneffects from breathing windblown particulate matter from landfill disposal. 

Longstanding EPA policy is for EPA risk assessments to include a characterization of risks at two points on a distribuestimates: 

• Central tendency risk estimate: Represents conditions likely to be encountered in a typical exposure situation 

• High-end risk estimate: Represents conditions likely to be encountered by individuals with higher expos

Examples of factors that would influence a nearby resident’s exposure are the residence’s distance from a CCR dispoindividual’s behavior or activity patterns. In EPA’s 1998 CCR risk assessment the high end risk estimates were deveinput values for certain variables, while in EPA’s 2009 risk assessment the high end risk estimates are the 90th percen

probabilistic analysis. The comparisons that EPA uses to judge whether either a high-end or central tendency estimated risk is of concern ar

142 For additional information about risk estimation see EPA’s “Guidance for Risk Characterization”, 1995 at http://www.epa.gov/OSA/spc/p

that “For the Agency's purposes, high end risk descriptors are plausible estimates of the individual risk for those persons at the upper end of t

“exposure above about the 90th percentile of the population distribution.” The 50th percentile represents the “central tendency” estimate of 
• Cancer risk: For purpose of evaluating actual or potential human individual cancer risk, EPA’s risk criteria are in 

million (i.e., 0.000001 or 1.0 x 10^-6) “excess” probability of developing cancer during a lifetime, to one in ten th

with one in one hundred thousand (i.e., 0.00001) being the “point of departure” for listing a waste as a RCRA hazCFR 261 Subpart B listing criteria. 

• Non-cancer risk: For human non-cancer hazard, the risk criterion is an estimated exposure above the level at whi

effects would be expected to occur. The risk is expressed as a ratio of the estimated exposure to the exposure at w

would be no adverse health effects; this ratio is also called a hazard quotient (HQ), and a risk of concern equates tor in certain cases of drinking water exposure, water concentrations above the Maximum Contaminant Level (MC

Safe Drinking Water Act. 

The exposure pathways for humans that EPA has evaluated for CCR landfills and surface impoundments are nearby r

ingestion and air inhalation, and fish consumption by recreational fishers: 

• Ground Water Ingestion 

Chemical constituents can leach from CCRs in landfills and impoundments into the ground water and subsequently bwho rely on well water. Some of the chemical constituents (e.g., arsenic) that were modeled in EPA’s risk assessmen

criteria, including the “point of departure” for listing as a hazardous waste, for the high end receptor. Additionally, thevidence that such potentially toxic constituents have leached from CCR disposal units into ground water at levels exwater standards. Comparing the results from the 2009 risk assessment with the CCR damage cases indicates that the groundwater exceedances for some of the same constituents found in the damage cases (i.e., arsenic, boron, cadmiumselenium). 

• Air Inhalation 

Air emissions from CCR disposal sites can originate from CCR unloading operations, CCR spreading and compactinsuspension of particulates from vehicular traffic, and from wind erosion. Air inhalation exposures may cause adverse either due to inhalation of small-diameter (less than 10 microns) “respirable” particulate matter that causes adverse ef

asthma attacks or increased mortality (and for which National Ambient Air Quality Standards for particulate matter hunder the Clean Air Act), or due to toxic effects of these respirable particles. At CCR landfills, the highest estimated 

individual excess lifetime risk of 4 in one million for farmers, due to inhalation of chromium (all chromium present in was assumed to be in the more toxic, hexavalent form). For CCR impoundments, the highest risk value was 2 in one (again assuming all chromium present was hexavalent). 

143 See 40 CFR 300.430. 
• Fish Consumption 

Exposure for this pathway stems from human consumption of fish that are caught in surface water bodies, such as stre

located near CCR landfills or surface impoundments. There are several ways in which a nearby surface water body, a

in that water body, could become contaminated due to CCR disposal activities: 

• Runoff and erosion from the CCR landfill or surface impoundment 

• Direct deposition of airborne CCR particles (i.e., CCR dust) • Migration of CCR contaminated groundwater from underneath the CCR disposal units into the nearby surface wa

• Direct discharge (effluent) from CCR impoundments – either intentional (e.g., NPDES permitted) discharges or u

structural failure with flooding release) discharges 

For example – although it did not cover electric utility plants in its national survey design -- EPA’s 2001 national invsurface impoundments144 states that out of the entire group of non-hazardous, industrial surface impoundments from 

economic sectors, an estimated 25% of all of these facilities had an industrial waste disposal impoundment overtoppin

where there is significant precipitation, or impoundment structural failure. An estimated 20% of the population of noimpoundments has fishable water bodies within 150 meters (i.e., about one-tenth of a mile) of the impoundment. And impoundments with fishable water bodies within 150 meters experienced an impoundment overtopping event. Once CCR constituents are in surface waters, fish may absorb the dissolved constituents during normal respiration accontaminants that concentrate in the sediments may be introduced into fish through the food chain. Contaminants can either or both of these exposure vehicles depending on the chemical’s potential for bio-concentration and bio-accumu

EPA’s 2009 risk assessment addresses potential human health risks from eating fish that are contaminated due to the 

water contamination mechanism: contaminated groundwater that migrates from underneath the CCR landfill or imponearby surface water bodies. 

• The high end results from this assessment indicate that arsenic migrating from surface impoundments may pose c

concern (individual excess lifetime cancer risk of two in one hundred thousand for unlined units and seven in one units). 

• The high end non-cancer hazard estimate for selenium migrating from unlined surface impoundments was above 

1.0. 

• The central tendency results from this assessment do not indicate cancer or non-cancer risks in the range of conce

144 Source: Page 2-26 (section 2.3.2.4) of EPA OSWER “Industrial Surface Impoundments in the United States,” report nr. EPA530-R-01-00

http://www.epa.gov/waste/hazard/tsd/ldr/icr/index.htm 
7C. Ecological Benefits This section describes some of the ecological hazard risks which RCRA regulation of CCR disposal may reduce. Thiinformation published in EPA’s 1998 and 2009 CCR risk assessment studies. Complete references and details for the below are available in those studies. For ecological non-cancer hazards that are modeled, the risk criterion is a hazard impacts on individual organisms, with a risk of concern being an estimated hazard quotient either greater than one. In 

considered documented evidence of ecological harm, such as field studies published in peer-reviewed scientific literasufficient to determine adverse ecological effects in lieu of or in addition to modeling potential ecological risks. Two types of exposures can occur for ecological receptors: 

• Exposures in which ecological receptors inhabit a CCR disposal unit directly 

• Exposures in which CCR or its chemical constituents migrate, or move, out of the CCR disposal unit and contami

water, or sediment 

For exposures in which ecological receptors directly inhabit a CCR disposal unit, EPA’s 1998 risk assessment found constituents present in utility CCR managed in impoundments may pose adverse effects on organisms that inhabit tho

1. Aluminum (amphibians) 2. Arsenic (birds) 3. Boron (amphibians) 4. Cadmium (mammals) 5. Lead (mammals) 6. Mercury (birds) 7. Selenium (mammals & amphibians) 

There are at least seven recent (i.e., 1978-2002) references in peer-reviewed scientific literature specific to CCR manimpoundments that confirm and extend EPA’s 1998 risk assessment results showing deformities and reproductive effon or near CCR disposal sites and other impacts on aquatic organisms and communities. In addition, seven of the 24 (i.e., 29%) proven damages to surface water identified in EPA’s July 2009 CCR damage ecological damages to fish, frogs, and other wildlife as a result of discharges from CCR impoundments. 

• In five of these seven cases, lakes constructed as cooling water sources for coal-fired power plants received disch

CCR settling ponds containing elevated levels of selenium resulting in elevated levels of selenium in fish in the la

• In another damage case, CCR was disposed of in a nearby quarry from 1967 to 1990. Concentrations of selenium

thallium were elevated in largemouth bass from the quarry relative to bass from another nearby site and some fish 
deformed bony structures. Higher concentrations of arsenic, selenium and lead were also found in small animals in animals from a reference site. 

• Finally, at another site, CCR was sluiced (transported in water) to settling basins. A continuous flow of sluice wa

swamp which discharged into a stream. Observations of bull frog tadpoles inhabiting the settling basins and swam

and impaired swimming and predator avoidance abilities. Many studies suggested that effects were caused by the low pH; siltation; high soluble salts concentration; pozzolanic action), as well as the trace metals in the CCR.