1Regulatory Impact AnalysisFor EPA’s Proposed RCRA RegulationOf Coal Combustion Residues (CCR)Generated by the Electric Utility IndustryPrepared by:US Environmental Protection AgencyOffice of Resource Conservation & Recovery (ORCR)(formerly Office of Solid Waste)1200 Pennsylvania AvenueNW (Mailstop 5305P)Washington DC, 20460 USA30 April 20102AcknowledgementsEPA Contractor Support & EPA Staff Assistance for this RIAIn 2009 under EPA contract EP-W-07-0011, work assignment 2-33,Industrial Economics Inc. (Cambridge MA) and its subcontractor DPRA Inc (Minneapolis MN)provided data analysis support for identifying affected entities and estimatingbaseline CCR disposalpractices and costs (Chapter 3), and for estimating costs ofregulatory engineering controlrequirements (Chapter 4)in this RIA.EPA ORCR staff contributingto this RIA: Rachel Alford, Richard Benware, Mark Eads, Christina Kager, and Scott Palmer.3Table of ContentsExecutive Summary 5Chapter 1: Problem Statement: The Need for RCRA Regulation of CCR Disposal 13Chapter 2: Potentially Affected Industries& RCRA Regulatory Options 182A. Identity of Potentially Affected Industries (Electric Utility Industry) 182B. Other Industries withCCR Disposal Units Not Coveredby the Proposed Rule 202C. RCRA Regulatory Options Evaluated in this RIA 24Chapter 3: Baseline CCR Disposal in the Electric Utility Industry 273A. Identity of Coal-Fired Electric Utility Plants 273B. Types of CCR Disposal Units 333C. Types of CCR Generated and Annual Quantities 363D. Size of CCR Disposal Units 413E. Cost of Baseline CCR Disposal 42Chapter 4: Estimated Cost for RCRA Regulation of CCR Disposal 674A. EPA’s Prior Cost Estimates for RCRA Regulationof CCR Disposal at Electric Utility Plants 674B. Regulatory Cost Estimation Algorithms & Results 684B.1 Engineering Control Costs 694B.2 Ancillary Regulatory Requirement Costs 734B.3 Land Disposal Restriction (CCR Dewatering Treatment) Cost 834C. State-by-State Distribution ofRegulatory Cost 1054D. Cost Estimation Uncertainty 107Chapter 5: Potential Benefits of RCRA Regulation of CCR Disposal inthe Electric Utility Industry 1105A. Groundwater Protection Benefits(Avoided Future Cancer Risks &Groundwater Remediation Costs) 1115B. Preventing Future CCR Impoundment CatastrophicFailures (Avoided Future Cleanup Costs) 1335C. Induced Effect of RCRA Regulation of CCR Disposal on Future CCR Beneficial Use 149Chapter 6: Comparison of Regulatory Benefits to Costs 1916A. Comparison of Benefits to Costs Based onAlternative Discount Rates (7%, 3%, 0%) 1916B. Factors Applied for Scaling Benefitsand Costs to the Regulatory Options 198Chapter 7: Supplemental Analyses Required by Congressional Statutes or White House Executive Orders 2047A. Electricity Price Impact (Executive Order 13211) 2047B. Small Business Impact Analysis (RFA/SBREFA) 2087C. Minority & Low-Income Populations Near Electric Utility Plants (Executive Order 12898) 2167D. Child Population Statistics (Executive Order 13045) 2297E. Unfunded Mandates (UMRA) & Federalism Implications Analysis (Executive Order 13132) 237Appendix Provided as separate document(the contents of the Appendix are displayed on the next page of this RIA)4Table of AppendicesNote: Because of its large number of pages (>400 pages), the Appendix is provided as a separatecompanion document to this RIA.Appendix A Chronology of EPA’s RegulatoryEvaluation of CCR (1978 to March 2009)Appendix B List of Other Industries withCoal-Fired Electricity Plants Not Covered by the Proposed Rule or this RIAAppendix C List of 495 Operating Electric Utility Plants Potentially Affectedby the CCR Rulemaking (2007)Appendix D Identity of 200 Entities Which Own the 495 Potentially Affected Electric Utility Plants (2007)Appendix E Baseline State Government Regulatory Requirements for CCR Disposal Units in Top-34 Coal Utility StatesAppendix F Baseline Engineering Controls Installed at CCR Disposal Unitsin the Electric Utility IndustryAppendix G Description of CCR Landfill & Surface Impoundment Engineering Control Cost ModelAppendix H Baseline Cost Estimates for CCRDisposal by the Electric Utility IndustryAppendix I Geological Conditionsat Electric Utility Industry CCR Disposal Unit LocationsAppendix J Incremental Regulatory Cost Estimates for Compliance with the CCR Proposed Rule Regulatory OptionsAppendix K Appendices Supporting theRegulatory Benefits EvaluationAppendix L Electricity Price Impact Analysis Spreadsheet (Executive Order 13211)Appendix M Small Entity Impact Data & Analysis Spreadsheet (RFA/SBREFA)Appendix N Minority & Low-Income Population Data (Executive Order 12898)Appendix O Child Population Data (Executive Order 13045)Appendix P UMRA Written StatementAppendix Q Documentation for EPA’s SocialCost Estimate Assigned to the TVA Kingston 2008 CCR Impoundment Failure Event5Executive SummaryThis RIA evaluates the expected regulatory compliance costs, economic and environmental benefits, and potential impact on CCR beneficialuse, of EPA’s proposed regulation of coalcombustion residual (CCR) disposal by coal-fired electric utility plants. The CCR disposalregulatory options evaluated inthis RIA are based on EPA’s statutory authority contained in the 1976 Resource Conservation andRecoveryAct (RCRA). The main findings of this RIAare summarized below according to six sections:ES-1: Regulatory OptionsEvaluated in this RIAES-2: Benefits of Avoided Future Groundwater Contamination (Human Health Protection& Avoided Remediation Costs)ES-3: Benefits of Avoided Future CCR ImpoundmentStructural Failures (Avoided Cleanup Costs)ES-4: Economic and Environmental Benefits from FutureIncrease in CCR BeneficialUses by Other IndustriesES-5: Regulatory Compliance CostsES-6: Comparison of Regulatory Benefits to CostsES-1: Regulatory Options Evaluated in this RIAThis RIA evaluates three options for RCRA regulation of CCR disposal at coal-fired electric utility plants. All options (a) maintain the existingBevill regulatory exclusion for CCR beneficial uses, and (b) propose the same set of10 custom-tailored engineering controls (i.e., technicaldesign and operating standards) for CCR disposal units:1.Subtitle C “Special Waste” Option: Regulate CCR landfills and impoundments as a “special waste” under Subtitle C requirements, andwould require phase out of impoundments within five years.2.Subtitle D Option (version 2): Composite liners required for all (i.e., existing and future new) CCR impoundments but only for newlandfills. For any CCR landfills and impoundments that closed before the effective date, there would be no regulatory controlsoverthose units, unless the states choose to adopt controls over such units. Also,all surface impoundments (existing and new) would needto have composite liners within 5-years of the effective date.3.Subtitle “D prime” Option: Composite liners required onlyfor new impoundments and landfills;unlined units could continue tooperate. This approach would be the same as the Subtitle Doption above, except that existing impoundments would not be required toretrofit and install a composite liner, or close.6ES-2: Benefits of Avoided FutureGroundwater Contamination (Human Health & Avoided Remediation Costs)By establishing management and permit standards for CCR disposal units under RCRA, the proposed regulatory options will reduceuncontrolled releases and cancer risks, and improve detection and, if necessary, response to future groundwater contamination.This RIAquantifies two components of groundwater protection benefits: (a) human cancer risks avoided from drinking contaminated groundwater, and(b) groundwater contaminationremediation costs avoided.Summary Exhibit 1below presents the monetizedresults of this evaluation.•Estimate of avoided human cancer risks from avoidedfuture groundwater contamination by CCR disposal units:oIndividual skin cancer risks avoided (byeliminating the groundwater pathway for arsenic at CCR impoundments) are estimatedup to 2 x 10-2(i.e., a probability equal to 2 individual human skincancer incidence risks for every 100 persons exposed) usingthe current IRIS skin cancer slope factor for arsenic.o30,400 people use drinking water wells within one mile of coal-fired electric utility plants; ofwhich 8,150 (27%) are children.oTaking into account current CCR disposal unit designs, an estimated145(using the IRIS cancer slope factor) to2,509(using theNRC lung and bladder cancer slope factor1) future human cancer risks are expectedto occur in absence of the proposed RCRAregulation, based on drinking water exposure to arsenic in CCR.•Other human health risks from CCR disposal units not quantified in this RIA:oHuman non-cancer risks, including from selenium, cobalt, nitrate/nitrite,and molybdenum, which may be released togroundwater at levels above the MCL or 3 times the human hazard quotient (HQ).oCancer and non-cancer risks from arsenic and other metals released in effluent from CCR impoundments to surface waters.Summary Exhibit 1Future Avoided Human Cancer Risks & Avoided Groundwater Remediation Cost Benefits($millions present value @7% discount rate over 50-years)Groundwater Protection Benefit CategorySubtitle Cspecial wasteSubtitle D(version 2)Subtitle “D prime”Groundwater Remediation Costs Avoided $466 $168 $84Monetized Value of Cancer Risks Avoided $504 $207 $104Total = $970 $375 $188ES-3: Benefits of Avoided Future CCR Impoundment Structural Failures (Avoided Cleanup Costs)This RIA estimated future avoided cleanupcosts from catastrophic impoundment failures,like the one that occurred at TVA’s Kingston TNcoal-fired electricity plant in December2008, which would be prevented under the proposedrule. Given the increasing age of CCR1EPA calculated a new cancer slope factor for arsenic from data in the National Research Council report “Arsenic in Drinking Water: 2001 Update” athttp://www.nap.edu/openbook.php?isbn=03090762937impoundments, the relative number that present high or significant hazard potential, and the history of CCR impoundment failures to date, thisRIA presents three alternative scenarios of future catastrophic failures, the result for which are displayed inSummary Exhibit 2below:•Failure Scenario #1: Extrapolation of future CCR impoundment failure probabilitybased on the relative (a) recent historical occurrencefrequency, (b) CCR quantity release magnitude, and (c) cleanup costs, associatedwith three recent (2005, 2008, 2009) CCRimpoundment failures which exceeded 1 million gallons in release quantity each.•Failure Scenario #2: Assumes 10% of CCR impoundments inthe high failure risk group (i.e., above40 feet tall and over 25 years old)fail over the next 20 years inabsence of RCRA regulation.2•Failure Scenario #3: Assumes 20% of CCR impoundments inthe high failure risk group (i.e., above40 feet tall and over 25 years old)fail over the next 20 years inabsence of RCRA regulation.Summary Exhibit 2Avoided Future CCR Impoundment Catastrophic Failure Cleanup Costs($millions present value @7% discount rate)Impoundment Failure ScenariosSubtitle Cspecial wasteSubtitle D(version 2)Subtitle “D prime”Failure Scenario #1:Extrapolation of three recent (2005, 2008, 2009)CCR impoundment failure events$5,285 $2,378 $1,216Failure scenario #2:Assuming 10% of 96 high-risk impoundments fail$8,366 $3,795 $1,897Failure Scenario #3:Assuming 20% of 96 high-risk impoundments fail$16,732 $7,590 $3,795The proposed regulation has categories of other benefits from avoiding future CCR impoundment structural failures which this RIA did notquantify and monetize, including potential avoided costsassociated with a few possible benefit categories:1.Litigation costs: Avoided litigation and related costs associated with such damage events.2.Riparian damages: Reduction of toxic chemical contaminated effluent dischargesfrom CCR impoundments to surface waters (i.e.,rivers and lakes) through future phase-out of surface impoundments.33.Non-cancer health risks: Reduction in human health risks from future reduction in human exposure tonon-carcinogenic but otherwisetoxic chemicals contained in CCR, such as selenium, cobalt, nitrate/nitrite, and molybdenum, which, as currently managed in CCR2Based on the responses to our CERCLA 104(e) information requeststo utilities with impoundments, there are 96 impoundments that meet these criteria. However, thisRIA estimates that 16 of these impoundments have closed or areexpected to close before the CCR rule is finalized and goes intoeffect. Therefore, this analysis removedthese 16 impoundments and based the estimated future impoundment failure cleanup costs on a subset of 80 CCR impoundments meeting the ‘at risk’ criterion.3EPA is developing a regulatory proposal under the Clean Water Act to revise the current effluent guidelines for steam electric utilities. Current guidelines only controlpH, total chlorine, and total suspended solids (TSS).EPA’s proposed CCR rule would eliminate CCR surface impoundments, eliminating much of the risk that would beaddressed under revisions to the effluent guidelines, including risks posed by arsenic, selenium, mercury, cadmium, copper, chromium, and nickel.8disposal units, can exceed the human health hazardquotient (HQ) or Maximum Contaminant Limit (MCL).Chapter 5of this RIAprovides a list of contaminants of concern in CCR surface impoundment effluent and potential human health and environmental effects.4.Dry CCR disposal risks: Human health effects from improperly managed dry disposal, whichare based on ongoing research by EPA’sOffice of Research & Development (ORD), may pose greater risks than previously estimated by EPA in 2000 and 2007.ES-4: Economic & Environmental Benefits from Future Increase in CCR Beneficial Uses by Other IndustriesThis RIA evaluated the potential impact that the CCR proposed rule may have on beneficial uses of CCR by other industries. Baseline CCRbeneficial use at the current 62 million tons per year rate (2009)is estimated in this RIA to provide $26 billion per year innationwide socialbenefits consisting of: (a) materials costsavings, plus (b) lifecycle avoided pollution benefits, plus (c) avoided CCR disposal costs to theelectric utility industry. On a presentvalue basis over the 50-year future period-of-analysis (2012-2061) applied in this RIA, the present valueof CCR beneficial use amounts to $778 billion (@7% discount). Although the industries which use CCR for beneficial uses are not subject tothe requirements of the CCR proposed rule, this RIA presents three alternative scenarios of potential induced effect of the CCRrule on futureCCR beneficial use, consisting of increaseduse (scenario #1), decreaseduse (scenario #2), and no change (scenario #3). ThisRIA quanfitiesboth scenario #1 and scenario #2 incrementally in relation to the “no change” scenario #3. EPA believes the increasing beneficial use scenario#1 is most likely because (a) the proposedCCR regulation is targeted at CCR disposalnot at CCR beneficial uses, (b) all CCR regulatoryoptions retain the existing RCRA Bevill exemption for CCR beneficial uses, and (c) the added cost of regulatory compliance willmakebeneficial use relatively more cost-effective and represent an “avoided disposal cost incentive”4to electric utility plantsto increase their supplyof CCR to industrial markets for CCR as a raw or intermediateinput into industrialmanufacturing and construction activities.Furthermore,EPA does not believe that market “stigma”of CCR regulation under RCRA Subtitle C --- asalleged in numerous stakeholder letters to the EPAin 2009 --- will result in a reduction in future annual CCR beneficial use, because the proposed rule designates the Subtitle Coption as a“special waste” rather than as a “hazardous waste.”Summary Exhibit 3below presents the results for both the increase scenario #1 and thedecrease scenario #2.4The concept of “avoided disposal cost incentive” is recognized and defined by the American CoalAsh Association (ACAA) on its website as follows:“If a [coal-fired electric utility] plant markets its [CCR] into commercial applications, then disposal of this [CCR] is not required. Not only is a revenue streamcreated for the [coal-fired electricity plant] but also the need to dispose of the [CCR] is avoided. As discussed above, disposal is not just the transportation andplacement of [CCR] in a disposal site. The need for future space is a concern. If [CCR is] marketed, then the need to developfuture [CCR disposal] sites(including land acquisition, permitting, design and construction costs) is avoided .... It is not uncommon for a company to helpoffset the costs of transportation orplacement at construction sites by providing the contractor or trucking firm a payment of some sort. For example, if the costof disposal at a plant is normally fourdollars a ton, then the company may arrange a payment of four dollars or less to the contractors to cover transportation and placement costs. The differencebetween the amount of this payment and the cost of disposal is also referred to as “avoided disposal costs.” Source: ACAA Frequently Asked Question nr. 14webpage at: http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=5#Q149Summary Exhibit 3Induced Effect of RCRA Regulation of CCR Disposal on Future Annual CCR Beneficial Use($millions present value @7%)ScenariosSubtitle Cspecial wasteSubtitle D(version 2)Subtitle “D prime”Scenario #1: Induced Increase in CCR Beneficial UsePercentage increase relative to baseline CCR beneficial use +11% +4% +2%Economic market value +$5,560 +$2,224 +$890Lifecycle social value+$84,489 +$33,796 +$13,518Scenario #2: Induced Decrease in CCR Beneficial UsePercentage decrease relative to baseline CCR beneficial use -18% Noimpact No impactEconomic market value -$18,744 No impact No impactLifecycle social value -$233,549 No impact No impactES-5: Regulatory Compliance CostsChapter 4of the RIA presents the estimated costsfor industry compliance (and for governmentimplementation) of each regulatory option.Summary Exhibit 4below presents the estimated costs on a present value basis.The RIA presents three categories of regulatory compliancecost. These regulatory costs are incremental to an estimated$5,556 million per year average annual baseline (i.e., current) cost to the electricutility industry for CCR disposal, which represents a baselinecost of $76,678 million in presentvalue on a 7% and 50-year discounting basis.Summary Exhibit 4Estimate of Regulatory Implementation & Compliance Cost($millions present value @7% over 50-years)Cost CategorySubtitle Cspecial wasteSubtitle D(version 2)Subtitle “D prime”1. Engineering controls $6,780 $3,254 $3,2542. Ancillary costs $1,480 $5 $53. Dry conversion cost $12,089 4,836 $0Total Cost (1+2+3) = $20,349 $8,095 $3,259Increase over baseline CCR disposal cost = +27% +11% +4%The dry conversion cost estimate incorporates projection of the recent (1995-2009) electric utility industry trend converting away from wetCCR disposal to dry CCR disposal. In fact, there are several upcoming EPA regulationswhich could accelerate this trend but are not reflectedin the cost estimate of this RIA. These are anticipated rules under the Clean Air Act which will increase the installation ofair pollutionscrubbers and other air emission control technology at coal-fired power plants, as wellas new wastewater effluent guidelines under the CleanWater Act which will require installationof treatment technology for wastewater discharges from CCR impoundments to surface waters.10ES-6: Comparison of RegulatoryBenefits to Industry Compliance CostsThe set of threeSummary Exhibits 5, 6 and 7below compare the estimated regulatory coststo estimated regulatorybenefits, using “netbenefits” and “benefit-cost ratio” comparison indicators. The three Exhibits are based on the three alternative scenarios about the potentialinduced impact of the CCR rule on future annual CCR beneficial use as presented in Section 5C ofthis RIA (i.e., increase, decrease, and nochange, respectively). All three Summary Exhibits below present costs, benefits, and net benefits on both a present value andaverageannualized equivalent basis, based on a 7%discount rate. A set of exhibits inChapter 6of this RIA present thesevalues based on a 3% rate.Summary Exhibit 5Comparison of Regulatory Benefits to CostsScenario #1 – Induced Increase inFuture Annual CCR Beneficial Use($Millions @2009$ Prices and @7% Discount Rate over50-Year Future Period-of-Analysis 2012 to 2061)Impact ElementSubtitle C“Special Waste”Subtitle D(version 2)Subtitle “D prime”A. Present Values:1. Regulatory Costs (1A+1B+1C): $20,349 $8,095 $3,2591A. Engineering Controls $6,780 $3,254 $3,2541B. Ancillary Regulatory Requirements $1,480 $5 $51C. Conversion to Dry CCR Disposal $12,089 $4,836 $02. Regulatory Benefits (2A+2B+2C+2D): $87,221 to $102,191 $34,964 to $41,761 $14,111 to $17,5012A. Monetized Value of Human Cancer Risks Avoided $504 (726 cancer risks) $207 (296 cancer risks) $104 (148 cancer risks)2B.Groundwater Remediation Costs Avoided $466 $168 $842C. CCR Impoundment Failure Costs Avoided $1,762 to $16,732 $793 to $7,590 $405 to $3,7952D. Induced Impact on Future CCR Beneficial Use$84,489$33,796$13,5183. Net Benefits (2 - 1) $66,872 to $81,842 $26,869 to $33,666 $10,852 to $14,2424. Benefit/Cost Ratio (2 / 1) 4.286 to 5.022 4.319 to 5.159 4.330 to 5.370B. Average AnnualizedEquivalent Values:*1. Regulatory Costs (1A+1B+1C) $1,474 $587 $2361A. Engineering Controls $491 $236 $2361B. Ancillary Regulatory Requirements $107 <$1 <$11C. Conversion to Dry CCR Disposal $876 $350 $02. Regulatory Benefits (2A+2B+2C+2D): $6,320 to $7,405 $2,533 to $3,026 $1,023 to $1,2682A.Monetized Value of Human Cancer Risks Avoided $37 $15 $82B. Groundwater Remediation Costs Avoided $34 $12 $62C. CCR Impoundment Failure Cleanup Costs Avoided $128 to $1,212 $58to $550 $29 to $2752D. Induced Impact on Future CCR Beneficial Use $6,122 $2,450 $9803. Net Benefits (2 - 1) $4,845 to $5,930 $1,947 to $2,439 $786 to $1,0324. Benefit/Cost Ratio (2 / 1) 4.286 to 5.022 4.319 to 5.159 4.330 to 5.370* Note: Average annualized equivalent values calculated by multiplying 50-year present values by a 50-year 7% discount rate “capital recoveryfactor” of 0.07246.11Summary Exhibit 6Comparison of Regulatory Benefits to CostsScenario #2 – Induced Decrease inFuture Annual CCR Beneficial Use($Millions @2009$ Prices and @7% Discount Rate over50-Year Future Period-of-Analysis 2012 to 2061)Impact ElementSubtitle C“Special Waste”Subtitle D(version 2)Subtitle “D prime”A. Present Values:1. Regulatory Costs (1A+1B+1C) $20,349 $8,095 $3,2591A. Engineering Controls $6,780 $3,254 $3,2541B. Ancillary Costs $1,480 $5 $51C. Conversion to Dry CCR Disposal $12,089 4,836 $02. Regulatory Benefits (2A+2B+2C+2D):($230,817) to ($215,847)$1168 to $7,965 $593 to $3,9832A. Monetized Value of Human Cancer Risks Avoided $504 (726 cancer risks) $207 (296 cancer risks) $104 (148 cancer risks)2B. Groundwater Remediation Costs Avoided $466 $168 $842C. CCR Impoundment Failure Costs Avoided $1,762 to $16,732 $793 to $7,590$405 to 3,7952D. Induced Impact on CCR Beneficial Use($233,549)$0 (no impact)$0 (no impact)3. Net Benefits (2-1)($251,166) to ($236,196) ($6,927) to ($130) ($2,666)to $7244. Benefit/Cost Ration (2/1)(11.343) to (10.607)0.144 to 0.984 0.182 to 1.222B. Average AnnualizedEquivalent Values:*1. Regulatory Costs (1A+1B+1C) $1,474 $587 $2361A. Engineering Controls $491 $236 $2361B. Ancillary Costs $107 $0.36 $0.361C. Dry Conversion $876 $350 $02. Regulatory Benefits (2A+2B+2C+2D):($16,725) to ($15,640)$85 to $577 $43 to $2892.A Monetized Value of Human Cancer Risks Avoided $37 $15 $82.B Groundwater Remediation Costs Avoided $34 $12 $62.C CCR Impoundment Failure Cleanup Costs Avoided $128 to $1,212 $57to $550 $29 to $2752.D Induced Impact on CCR Beneficial Use($16,923)NA NA3. Net Benefits (2-1)($18,199) to ($17,115) ($502) to ($9) ($193)to $524. Benefit/Cost Ration (2/1)(11,347) to (10.610)0.145 to 0.983 0.182 to 1.225* Note: Average annualized equivalent values calculated by multiplying 50-year present values by a 50-year 7% discount rate “capital recoveryfactor” of 0.07246.12Summary Exhibit 7Comparison of Regulatory Benefits to CostsScenario #3 – No Impact on Future Annual CCR Beneficial Use($Millions @2009$ Prices and @7% Discount Rate over50-Year Future Period-of-Analysis 2012 to 2061)Impact ElementSubtitle C“Special Waste”Subtitle D(version 2)Subtitle “D prime”A. Present Values:1. Regulatory Costs (1A+1B+1C) $20,349 $8,095 $3,2591A. Engineering Controls $6,780 $3,254 $3,2541B. Ancillary Costs $1,480 $5 $51C. Conversion to Dry CCR Disposal $12,089 4,836 $02. Regulatory Benefits (2A+2B+2C+2D): $2,732 to $17,702 $1168 to $7,965 $593 to $3,9832A. Monetized Value of Human Cancer Risks Avoided $504 (726 cancer risks) $207 (296 cancer risks) $104 (148 cancer risks)2B. Groundwater Remediation Costs Avoided $466 $168 $842C. CCR Impoundment Failure Costs Avoided $1,762 to $16,732 $793 to $7,590 $405 to $3,7952D. Induced Impact on CCR Beneficial Use$0 (no change)$0 (no change)$0 (no change)3. Net Benefits (2-1)($17,617) to ($2,647) ($6,927) to ($130) ($2,666)to $7244. Benefit/Cost Ration (2/1) 0.134 to 0.870 0.144 to 0.984 0.182 to 1.222B. Average AnnualizedEquivalent Values:*1. Regulatory Costs (1A+1B+1C) $1,474 $587 $2361A. Engineering Controls $491 $236 $2361B. Ancillary Costs $107 $0.36 $0.361C. Dry Conversion $876 $350 $02. Regulatory Benefits (2A+2B+2C+2D): $198 to $1,283 $85 to $577 $43 to $2892.A Monetized Value of Human Cancer Risks Avoided $37 $15 $82.B Groundwater Remediation Costs Avoided $34 $12 $62.C CCR Impoundment Failure Cleanup Costs Avoided $128 to $1,212 $57to $550 $29 to $2752D. Induced Impact on CCR Beneficial Use $0 $0 $03. Net Benefits (2-1)($1,277) to ($192) ($502) to ($9) ($193)to $524. Benefit/Cost Ration (2/1) 0.134 to 0.870 0.145 to 0.983 0.182 to 1.225* Note: Average annualized equivalent values calculated by multiplying 50-year present values by a 50-year 7% discount rate “capital recoveryfactor” of 0.07246.13Chapter 1Problem Statement: The Need forRCRA Regulation of CCR Disposal1A. Institutional ContextFor purpose of evaluating Federal regulations, the 1993 Executive Order 12866 “Regulatory Planning and Review” (Section 1(b)(1)) requireseach Federal regulatory agency to identify the problem that it intends to address, including where applicable, the failures ofprivate markets orpublic institutions that warrant new agencyaction, as well as to assess the significance of the problem. Inline with this requirement, thisChapter provides a problem statement consisting of the institutional context (i.e., prior EPA actions), significance of the problem (i.e., evidenceof environmental damages), and characterization of market failure.In September 2003, the White House Office of Management and Budget (OMB) updated its guidance tofederal agencies on the developmentof regulatory analysis required under Section 6(a)(3)(c) of the 1993 Executive Order 128665“Regulatory Planning and Review.” The updatedguidance is OMB’s September 17, 2003“Circular A-4 Regulatory Analysis.”6Section A (Introduction) ofCircular A-4 defines three keyelements of good regulatory analysis:1.Statement of the need for the proposed regulation.2.Examination of alternative approaches.3.Evaluation of the benefits and costs (quantitative and qualitative) of the proposedregulation and the main alternatives.Concerning the first basic element listed above (i.e., statement of the need forregulation), Section B ofCircular A-4 requires federal agenciesto demonstrate that the proposed regulation is necessary. TheCircular defines four categories of possible regulatory need:1.Required by law: If the need results from statutory or judicial directive, agencies should describe the:a.specific authority forthe proposed regulationb.extent of discretion available to the agencyc.regulatory instruments available2.Necessary to interpret law.3.Market failure: Three examples cited in Circular A-4 (pages 4 & 5) are:a.externality, common property resources and public goodsb.non-competitive market powerc.inadequate or asymmetric information4.Other social purposes: Six examples cited in Circular A-4 (page 5) are:a.make government operate more efficiently51993 Executive Order 12866 (11 pages) is available at: http://www.whitehouse.gov/OMB/inforeg/eo12866.pdf62003 OMB Circular A-4 (48 pages) is available at: http://www.whitehouse.gov/OMB/Circulars/a004/a-4.pdf14b.redistribute resources to select groupsc.prohibit discriminationd.protect privacye.permit more personal freedomf.promote other democratic aspirationsAs explained below, EPA’s proposed RCRA7regulation of coal combustion residual (CCR) disposal at coal-fired electricity plants is bothrequired by lawand willcorrect market failure.1B. EPA’s Proposed Regulation ofCCR Disposal Is Required by LawIn 1976, Congress amended the 1965 Solid Waste Disposal Act (thefirst federal statute that specifically focused on improving solid wastedisposal methods) by adding industrial hazardous waste management requirements as Subtitle C, among other new requirements. Thisamendment is the 1976 Resource Conservation &Recovery Act (RCRA). The EPA’s regulatory evaluation of coal combustion residues(CCR)dates back to 1978, two years after enactmentof RCRA. In December 1978, the EPA proposed the first industrial hazardous wasteregulationsto implement Subtitle C (i.e., Sections 3001to 3020 of RCRA). At that time, the EPA recognized that certain large-volume industrial wastes,including wastes from the combustion of fossil fuels (aka “CCR”as named in this RIA), mightwarrant special treatment under RCRAregulation. On 18 December 1978, EPA proposed but deferred and never finalized a relatively limited set of ten RCRA Subtitle Cindustrialhazardous waste regulations for the management of CCR.8Included in this deferral of hazardouswaste requirements weresix categories ofindustrial wastes --- which EPA termed “special wastes”9--- until further study and assessment could be completed by EPA to determine theirrisk to human health and the environment. The six categories of special wastes included:1.Cement kiln dust2.Mining waste3.Oil and gas drilling muds and oil production brines4.Phosphate rock mining, beneficiation, and processing waste5.Uranium waste6.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 believedto possess less risk to human health andthe environmentthan the wastes being identified for regulation as RCRA hazardous waste. On 12 October 1980, Congress enacted the Solid WasteDisposalAct Amendments of 1980 (Public Law 96-482) which amended RCRA in several ways. Pertinent to “special wastes” were the Bentsenand7RCRA = Resource Conservation & Recovery Act of 1976: http://www.epa.gov/waste/laws-regs/rcrahistory.htm8Federal Register, Vol. 43, No. 243, 18 December 1978, page 59015, section 250.46-2 “Utility Waste” of “Hazardous Waste Guidelines and Regulations.” This actionproposed the following ten regulatory conditions: (a) waste analysis standards, (b) waste site selection standards, (c) waste site security, (d) waste shipment manifesting, (e)recordkeeping, (f) reporting, (g) waste site visual inspections,(h) waste site closure, (i) waste site post-closure care, and(j) groundwater monitoring.9To learn more about these six “special wastes” see EPA’s special waste website at http://www.epa.gov/osw/nonhaz/industrial/special/index.htm15Bevill Amendments10which exempted “special wastes” from regulation under Subtitle C of RCRA until further study and assessment of riskcould be performed:•1980 Bentsen Amendment(RCRA 3001(b)(2)(A)): Exempted drilling fluids, produced waters, and other wastes associated with theexploration, development, and production of crude oil or natural gas or geothermal energy.•1980 Bevill Amendment(RCRA 3001(b)(3)(A)(i-iii)): Exemptedfossil fuel combustion waste; waste from the extraction, beneficiation,and processing of ores and minerals (including phosphate rock and overburden from uranium ore mining); and cement kiln dust.The Bevill and Bentsen Amendments required EPA to complete full assessments of each exempted waste and submit a formal report toCongress on its findings. As itemized inAppendix Ato this RIA, since 1978, EPA continued to evaluate CCR (as well as the other five wastecategories) for different possible RCRAhazardous and non-hazardous waste regulatory approaches. The proposed RCRA regulationthis RIAsupports is a continuation ofthose prior evaluations.1C. EPA’s Proposed Regulation of CCR Disposal Will Correct Market FailureOMB’s 2003 Circular A-4 “Regulatory Analysis”guidance (pages 4 to 5) to Federal agencies for implementation of Executive Order12866identifies three major types of market failure:1.Externality, common property resource, and public good2.Market power (i.e., lack of market competition from monopolies)3.Inadequate or asymmetric informationThe CCR proposed rule which this RIA supportsmay be characterized as addressing the “negative externality” of environmental pollution anddamages from CCR disposal landfills and impoundments. As summarized in the “Benefits”Chapter 5of this RIA, there are a number ofhistorical and recent environmental damage cases which represent externalities, in that some or all of the (a) human health damages (i.e.,human cancer cases from contaminated groundwater near CCR disposalsites) and (b) environmentaldamages (i.e., ecological damages, naturalresource damages, and socio-economic damages from CCR spills/releases from structural failures inCCR disposal impoundments) may beexternal to the capital and operating costsof the electric utility plants. If implemented, the CCR proposed rule may be expected to reduce thismarket failure externality, by internalizing into the capital and operating costs of the electricutility plants, the added costs of installingengineering controls and oversight of the physical integrity of CCR disposal units.Firms are sometimes held accountable for some of the external costs through lawsuits brought by affected citizens. However, the system ofaccountability can be imperfect. The primaryhuman bearers of the external costs fromCCR disposal are households residing disposal units.When an unorganized group of households sufferexternal costs, they face a host of obstacles to having their costs recuperated.They must10These 1980 RCRA “special waste” amendmentsare named after US Senator Lloyd Bentsen (D-TX; Senate service years 1971-1993) andUS House Congressman TomBevill (D-AL; House service years 1967-1997). Source: Biographical Directory of the US Congress at http://bioguide.congress.gov/biosearch/biosearch.asp16form a coherent organization and they musthave enough funding to launch and maintain a lawsuit. On the other side of such litigation,households usually face a single firm often with greater legal funding resources.This imbalance suggests that external costsof leachatecontamination from industrial waste disposal sites (such as CCR landfills andimpoundments) may not be recuperated.The CCR proposed rule also addresses a secondsource of market failure – inadequate orasymmetric information. Citizens residing near CCRdisposal sites may be unaware of exposureto chemical contaminants contained in CCRleaching from disposal units. Thus, whilenearbycitizens may have the right to legal lawsuitsto recuperate health and property damages, citizens may not be aware of the needto do so untilhealth risks (and health costs)have already been incurred.A very recent example of negative externalities associated with structural failures is the ecological and socio-economic damages and costsassociated with a large environmental disaster involving the collapse of a CCR impoundment in 2008. On 22 December 2008, overa billiongallons (i.e., 5.4 million cubic yards) of CCR was unintentional environmental released over 300 acres from the collapse of a Tennessee ValleyAuthority (TVA) coal-fired electric utility surfaceimpoundment in Kingston TN. This event caused significant damage to 40 homes, theEmory River, a nearby recreational lake, community roadways, a gas pipeline, and a railroad. As indicated inExhibit 5B-2of this RIA, theestimated cleanup costs to the TVA --- not including social costs of ecological damages and community socio-economic damages --- areestimated at $933 million to $1.2 billion. This event attracted major citizen, national press, andCongressional interest in the subject of CCRmanagement and the urgent need for prevention of such future environmental and community damages.In the wake of this disaster, during her14 January 2009 Senate confirmation hearing, EPA Administrator-designate LisaP. Jackson, testified11:“I think that you’ve put your finger on avery important thing that EPA must do right away, which is to assess the hundredsof other sites that are out there. Many of them ... are ... uphill from schools or from areas where just the physical hazardof having this mountain of wetcoal ash, if there’s a break, can endanger livesimmediately. So I would think that EPA needsto first and foremost assess the current state of what’s out here and where there might be another horrible accident waitingto happen ... EPA currently has and has in the past, assessed its regulatory options with respect tocoal ash, and I think it’stime to re-ask those questions and re-look at thestate of regulation of them from an EPA perspective.”According to a 23 January 2009 news report,12there was growing Congressionalinterest for either the EPA with its existing RCRA regulatoryauthorities, or the Congress with potential new legislation, to regulate CCR disposal units:“Several lawmakers have introduced, or announced plans to introduce, competing legislation to regulate CCR. For example,Senate Environment & Public Works Committee Chairwoman Barbara Boxer (D-CA)said she would introduce legislationcompelling EPA to regulate CCR in the event the Obama EPA failsto act soon. "If we are not satisfied with action we maymove legislatively," Boxer told EPA Administrator-designate Lisa Jackson at a January 14 [2009] confirmation hearing. "Idon't want to get to that point because I think you have the authority toregulate this. It needs to be done."”11Lisa Jackson’s 14 January 2009 Senate confirmation hearing testimony and webcast is available from the US Senate Committee onEnvironment and Public Works’website at: http://epw.senate.gov/public/index.cfm?FuseAction=Hearings.Hearing&Hearing_ID=ae2c3342-802a-23ad-4788-d1962403eb7612Source: Waste Business Journal, “EPA Vows to Act on Coal Waste,” 23 January 2009, http://www.wastebusinessjournal.com/news/wbj20090127B.htm17Just three weeks after the TVA’s KingstonTN CCR impoundment disaster,House Natural Resources Committee Chairman Nick Rahall (DWV) introduced legislation requiring federal standards to regulate the engineering of CCR impoundments.13Introduced on 14 January 2009,the Coal Ash Reclamation and Environmental Safety Act of 2009 (H.R. 493) directs the Department ofInterior to impose uniform federaldesign, engineering, and performance standards on CCR impoundments to avoid a repeat ofthe damage done in Kingston TN. The legislation,which requires minimum design and stabilitystandards for all surface impoundments constructed to hold coal ash, draws on the regulatorymodel for impoundments that is used for coal slurry management under the Surface Mining Controland Reclamation Act of 1977 (SMCRA).In a letter dated 02 March 2009, theEnvironmental Integrity Project and Earthjustice, joined by the National Resources DefenseCouncil, theSierra Club, Environmental Defense, and 104 other environmental groups requestedEPA Administrator Lisa Jackson “to act as soon aspossible” to regulate CCR. A letter signed by the groups and delivered to EPA on 03 March 2009 identified 12 principles to guide thedevelopment of EPA standards. These include the phase-out of CCR surface impoundments, locating CCR disposal sites away fromgroundwater or surface water, requiring liners, leachate collection systems and adequate monitoring, and requiring industry toassume longterm liability for cleanup:“The recent disaster at TVA's Kingston Plant stands as astartling reminder that federal standards for CCR are longoverdue. For too long, power companies have been able to dumpCCR, laden with a host of toxic metals like arsenic,selenium, lead, mercury, and boron, in unlined mines,quarries, landfills, and surface impoundments. Withoutfederal standards governing disposal practices, contaminants can leak or spill from these dump sites, threateninghuman health, natural resources and wildlife.”14On 04 March 2009, US Senators Barbara Boxer (D-CA) and Tom Carper(D-DE) submitted Senate Resolution 64 to the Senate CommitteeonEnvironment and Public Works. This resolution calls on the EPA to “immediately” inspect all CCR impoundments and landfills operating atcoal-fired electricity plants, and to propose and finalize“as quickly as possible” rules to regulate CCR under RCRA.1513The text of the 14 January 2009 H.R. 493 bill is available at: http://www.govtrack.us/congress/billtext.xpd?bill=h111-49314Source: http://www.environmentalintegrity.org/pub608.cfm15US Senate Resolution 64 is available at: http://www.govtrack.us/congress/bill.xpd?bill=sr111-64&tab=committees18Chapter 2Potentially Affected Industries & RCRA Regulatory Options2A. Identity of Potentially Affected IndustriesThere are two categories of industries which may be directly affected by the CCR regulatory options. “Directly affected entities” areentities potentially subject to any of the rule’s requirements.16In addition, there are 14 or moreindustries which beneficially use CCR.1.Coal-Fired Electric Utility IndustryThe scope of industrial plants directly affected by the regulatory options is classifiable according to at least two differentglossary systems:•Classification #1 of 2: The scope of industrial plants is classifiable as “coal-fired electric utility plants” under the US Census Bureau’sNorth American Industrial Classification System” NAICS code 22 “Utilities” economic sector, and in that sector, as a subgroup of the1,245 establishments within the NAICS 221112 “Fossil Fuel Electric Power Generation” industry:17NAICS 221112:This industry comprises establishments primarily engaged in operating fossil fuelpowered electric powergeneration facilities. These facilitiesuse fossil fuels, such ascoal, oil, or gas, ininternal combustion orcombustion turbine conventional steam process to produce electric energy. The electric energy produced inthese establishments is provided to electric power transmission systems or to electric power distributionsystems.•Classification #2 of 2: The scope of industrial plants is classifiable as “electric utilities plus independent power producers” under theEnergy Information Administration (EIA) categorization system for its coal combustion electric power sector statistics:18Electric utility:Any entity that generates, transmits, or distributes electricity and recovers the cost of itsgeneration, transmission ordistribution assets and operations, eitherdirectly or indirectly, through cost-based rates set by a separate regulatoryauthority (e.g., State Public Service Commission), or is owned by a governmental unit or the consumers that theentity serves. Examples of these entities include: investor-owned entities, public powerdistricts, public utilitydistricts, municipalities,rural electric cooperatives, and State and Federal agencies.Independent powerA corporation, person, agency, authority, or other legalentity or instrumentalitythat owns or operatesproducer:facilities for the generation of electricity for use primarily by the public, and thatis not an electric utility.16Source: “EPA’s Action Development Process:Final Guidance for EPA Rulewriters: Regulatory Flexibility Act”, OPEI Regulatory Development Series, Nov 2006, seefootnote 14 at http://www.epa.gov/sbrefa/documents/rfafinalguidance06.pdf17Source: NAICS codes are defined at http://www.census.gov/cgi-bin/sssd/naics/naicsrch?chart=200718Source: EIA glossary of terms at http://www.eia.doe.gov/glossary/index.html192.Waste & Environmental Management Services IndustriesIn addition, because some electric utility plants transport their CCR to eithercompany-owned or to commercial offsite landfills, and becausesome regulatory options may trigger RCRA facility-wide corrective action, the regulatory options of the proposed rule may alsoaffect:NAICS 562211: Hazardous waste treatment and disposal industry (may be affectedunder the RCRA Subtitle C regulatoryoptions evaluated in this RIA).NAICS 562212: Solid waste landfill industry(may represent baseline offsite CCR landfills to which the estimated 149 of the495 electric utility plants may transport some or all of the 15 million tonsper year CCR for offsite disposal).NAICS 562219: Other non-hazardous waste treatment and disposal industry (may represent baseline offsite CCR landfills towhich some or all of 149 of the 495 electric utility plantsmay transport some or all of the 15 million tons peryear CCR for offsite disposal).NAICS 562910: Environmental cleanup/remediation services industry.3.Industries Which “Beneficially Use” CCRAccording to the American Coal Ash Association (ACAA)19as of 2007 there are over 15 industries which “beneficially use” CCR forindustrial applications.These industrial applications arelisted below with corresponding NAICS20codes estimated by EPA ORCR. Becausethe regulatory options evaluated in this RIA establish CCR disposal requirements, industries which beneficially use CCR are characterized inthis RIA as potentially “indirectly” affected by the proposed rule rather than “directly” affected (i.e., subject to the rule’srequirements).1. Concrete/concrete products/grout NAICS 3273 Cement & Concrete Product Manufacturing2. Blended cement/raw feed for clinker NAICS3273 Cement & Concrete Product Manufacturing3. Flowable fill NAICS 23 Construction4. Structural fills/embankments NAICS 23 Construction5. Road base/sub-base NAICS 237310 Highway, Street & Bridge Construction6. Soil modification/stabilization NAICS 23 Construction7. Mineral filler in asphalt NAICS 324121 Asphalt Paving Mixture & Block Manufacturing8. Snow and ice control NAICS 488490 OtherSupport Activities for Road Transportation9. Blasting grit/Roofing granulesNAICS 212319 Other Crushed & Broken Stone Mining & QuarryingNAICS 324122 Asphalt Shingle & Coating Materials Manufacturing10. Mining applications NAICS 212 Mining19Source: American Coal Ash Association (ACAA) “2007 Coal Combustion Product (CCP) Production & Use Survey Results (Revised)” athttp://www.acaausa.org/associations/8003/files/2007_ACAA_CCP_Survey_Report_Form%2809-15-08%29.pdf20NAICS = North American Industrial ClassificationSystem; NAICS codes definitions are available athttp://www.census.gov/cgi-bin/sssd/naics/naicsrch?chart=2007•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 industries2011. Gypsum panel products (e.g., wallboard)NAICS 327420 Gypsum Product Manufacturing12. Waste stabilization/solidification NAICS 5622 Waste Treatment & Disposal13. Agriculture NAICS 111 Crop Production14. Aggregate NAICS 23 Construction15. Miscellaneous/other (unidentified industries)NAICS not identified2B. Other Industries with CCR Disposal Units Not Covered by the Proposed RuleThe scope of the proposed rule excludes twoother categories of CCR disposal units from the regulatory options. These other two categoriesare identified here to provide a rough estimate of potential additional cost for regulation if they were added to the scope ofthe rulemaking oraddressed in a separate but similar rulemaking.•Inactive/Abandoned CCR DisposalUnits Excluded from ScopeThe scope of the proposed rule only coversactive (i.e., operating) CCR disposal units used by electric utility plants. Thereare two otheroperating status categories consisting of an estimated count ofat least 197 additional CCR disposal units excluded from the scope of the rule:21•Inactive units: CCR impoundments and landfills not in operation ornot receiving CCR. Inactive impoundments may receive CCR inthe future, becoming active again, and therefore have not been closed permanently.•Abandoned units: CCR impoundments and landfills not in operation andclosed. These impoundments usually have been filled tocapacity and have been permanently closed.In absence of inventory data oninactive units, the nationwide count of such inactive and abandoned units is indirectly and roughly estimated inthis RIA based on known data for large volume coal mining slurrywaste impoundments. There are an estimated 1,600 coal wasteimpoundments in operation across the US in coal-related industries (i.e., coal miningindustry plus industries which burn coal). In addition,there are another 670 coal wasteimpoundments which are no longerin operation but still containcoal waste slurry (i.e., inactive orabandoned).22These two counts represent a ratio of 0.42inactive/abandoned:to:active (i.e., 670:to:1,600).In absence of national survey data, multiplying the 0.42 inactive:to:active coal waste impoundments ratio by the 158 coal-firedelectric utilityplants estimated in this RIAusing CCR impoundments, yields an estimate ofat least 66 inactive/abandoned CCR impoundments maybelocated at electric utility plants (i.e., (158 impoundment using electric utility plants) x (0.42 ratio) = 66).21Source: Definitions of “inactive” and “abandoned” coal waste impoundments from page 23 of the National Research Council book Coal Waste Impoundments: Risks,Responses and Alternatives, National Academy Press, 2002 at http://www.nap.edu/openbook.php?isbn=030908251X22Source: Counts of 1,600 active coal waste impoundments and 670 inactive or abandoned coal waste impoundments from the prior footnoted source.21This RIA did not discover similar data for coal waste landfills in active and inactive/abandonedstatus. For purpose of a rough estimate in thisRIA, multiplying the 0.42 inactive/abandoned:to:active ratio by the 311 electric utility plants which use landfills, indicatesthere may be at least131 inactive or abandoned CCR landfills at or near electric utility plants (i.e., (311 landfill using electric utility plants)x (0.42 ratio) = 131).As of 2004, the Mine Safety & Health Administration (MSHA) oversees 646 active coal mining slurry impoundments in the US, whichimplies954 remainder active coal slurryimpoundments (i.e., 1,600 – 646 = 954).23Of these, this RIA estimatesat least 158 active impoundments at158 electric utility plants, which implies that a fraction of 796 other active coal waste impoundments (i.e., 954 – 158 = 796)may be located atelectric power plants in non-utility industries (see the next sub-section below “Other Industries Excluded from Scope”).•Other Industries Excluded from ScopeThe scope of the proposed rule only includes NAICS code 22 coal-fired electric utilityplants (495 plants). However, there isa range of 139 to759 non-utility facilities which currently, or have the capacity to, burn coal andthus generate CCR. Adding these facilitiesto the scope of theproposed rule could increase thecost estimates by 2% to 28%. This range is based on the following two data sources:Source #1: As displayed below inExhibit 2Abased on 2005 data from the DOE-EIA, there are 139 non-utility coal-firedelectricity plantsowned and operated by 8 other industrialsub-sectors involving 27 industries.Appendix Bof this RIA contains a list of theseother industry plants according toNAICS industry codes. If theseother non-utility industries wereto be added to the scope ofthe CCR proposed rule, a rough estimate of potential additional cost and benefit impacts would be between 2% and 28% relativeto the impacts estimated in this RIA:•>2%: Compared to the 369,183 megawatts (MW) nameplate capacity for the coal-fired electricity plants contained inthe 2005 DOE-EIA database (which contains data on electricity plants at least 10 MWnameplate capacity insize), the 5,959 MW capacity of the 139 non-utility electricity plants representsabout 2% of national coal-firedelectricity generation capacity. Forpurpose of rough estimation – in so far that electricity plant capacitycorrelates to annual CCR generation and thus to annualCCR disposal costs and toregulatory costs --- thispercentage indicates that the additional economic impactof including these additional 139 non-utility plants inthe proposed rule might add at least 2% tothe cost estimates under each regulatory option.•<28%: On the other hand, some CCR disposalcosts and regulatory costs better correlate to the count and size (footprint)of CCR landfills and impoundments, notto electricity generating capacity. For such costs, adding the 139 nonutility plants to the scope of the proposed rule could increase the cost estimates for each regulatory option by upto 28% (i.e., (495 + 139) / (495)).23Source: MSHA “Supporting Statement” for Information Collection Request (ICR) 1219-0015 “Refuse Piles and Impoundment Structures, Recordkeeping and ReportingRequirements”, March 2008: http://www.msha.gov/regs/fedreg/paperwork/2004/04-24046.pdf22Source #2: EPA’s 2002 analysis24of the results from a 2001 survey of non-utility CCRgeneration identified 759 non-utility facilities “withthe capacity to burn coal, and therefore,generate CCR.” The estimated annual CCRgeneration for these facilities is 7.8 milliontons (as of year 2000), which is 5.5% to 6.3% of the 123.1 million to 141.2 million tons CCR generated by electric utility plantsin 2005 as estimated inExhibit 3Dof this RIA. Allowing for annual growthof the 7.8 million tons since 2000 suggests thatadding these 759 facilities to the scope of the proposed rule could increase the cost estimates by 7%.24Source: “Analysis of Non-Utility Coal Combustion Waste Generation and Management Based on the 2001 CIBO Voluntary Survey,” prepared for EPA-OSWER byScience Applications International Corp (SAIC) Engineering & Environmental Management Group (Reston VA) under subcontract to Eastern Research Group (ArlingtonVA), April 2002, EPA contract No. 68-W-02-036, WA 12:.23Exhibit 2AIdentity of Other Industries OperatingCoal-Fired Electricity Plants Not Covered by the Proposed Rule or this RIA2005CountNAICSSectorNAICSIndustryNAICS Industry Code Definition2005Boiler count2005Plant count1 21 2122 Ore mining 4 12 31 311 Food Manufacturing 63 293 31 3122 Tobacco Manufacturing 3 24 31 314 Textile Product Mills 11 45 32 321 Wood Product Manufacturing 1 16 32 322 Paper Manufacturing 9 47 32 322122 Newsprint Mills 98 398 32 32213 Paperboard Mills 19 99 32 325 Chemical Manufacturing 31 610 32 325188 All Other Basic Inorganic Chemical Manufacturing 5 311 32 325211 Plastics Material and Resin Manufacturing 9 412 32 326 Plastics and Rubber Products Manufacturing 4 113 32 327 Nonmetallic Mineral Product Manufacturing 8 314 32 32731 Cement Manufacturing 2 115 33 331 Primary Metal Manufacturing 5 316 33 331111 Iron and Steel Mills 1 117 33 331312 Primary Aluminum Production 3 118 33 333 Machinery Manufacturing 7 219 33 3345 Navigational, Measuring, Electromedical, Control Instruments Mfg 10 120 33 336 Transportation Equipment Manufacturing 1 121 33 337 Furniture and Related Product Manufacturing 1 122 33 339 Miscellaneous Manufacturing 1 123 48 482 Rail Transportation 2 124 48 483 Water Transportation 3 125 61 611 Educational Services 37 1426 62 624 Social Assistance 2 127 92 92 Public Administration 14 4Count = 8 Count = 27 Column Totals = 3541392005 electricity generation nameplate capacity (megawatts) = 5,959Notes:(a) Source: US Dept of Energy, Energy Information Administration (EIA), 2005 Form EIA-860 "Annual Electric Generator Report""Existing Electric Generating Units in the United States, 2005" athttp://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 digitdesignates the industrygroup, the fifth digit designates the NAICS industry, and the sixth digit designates the national industry. The five-digit NAICS code is the level atwhich there is comparability in code and definitions for most ofthe NAICS sectors across the three countries participating inNAICS (the UnitedStates, Canada, and Mexico). The six-digit level allows for the United States, Canada, and Mexico each to have country-specificdetail. A completeand valid NAICS code contains six digits. Source: http://www.census.gov/eos/www/naics/faqs/faqs.html#q5242C. RCRA Regulatory Options Evaluated in this RIAThis RIA evaluates three RCRA regulatory options which are defined with reference to the two alternative regulatory authorities--- Subtitle Cand Subtitle D --- contained in EPA’s 1976 RCRA waste management statutory authority:Option 1: RCRA Subtitle C “special waste”:•Regulate CCR disposed in landfills and surface impoundmentsas “special wastes” under Subtitle C, and requirephase out of surface impoundments withinfive years. This approach:•Eliminates health risks from groundwater and surfacewater contamination for both landfills and surfaceimpoundments, and avoids damages from uncontrolledground “fill” operations(e.g., Gambrills MD andChesapeake VA) and attendant environmental remediation costs.•Eliminates the future threat of catastrophic failures of surface impoundments.•Provides for corrective action, including at closed unitsat facilities with surface impoundments or landfillsregulated under the rule, and imposesgroundwater monitoring requirements.•Provides for Federal oversight, which EPA experience hasshown is necessary for successful implementation ofRCRA industrial waste regulations, especially as it relates to ground-water monitoring and corrective action,when needed. Without Federal oversight, it is highly questionable whether CCR will be properly managed,considering EPA’s experience with the RCRA program of the last 10 years, which illustrate the limited resultsthat could be expected of a Subtitle D rule.Option 2: RCRA Subtitle D “non-hazardous” industrial waste (version 2):•Liners required for all (i.e., existing and future new) CCR surface impoundments but only for new landfills.Subtitle D requirements would setnational criteria for landfills and surface impoundments that manage CCRafter the rule goes into effect. For any CCR landfills and impoundments that closed before the effective date,there would be no regulatory controls over those units, unless the states choose toadopt controls over such units.Also, all surface impoundments (existing and new) would need to have composite liners within 5-years of theeffective date. Consistent with the Subtitle C approach, existing landfills would not need to be lined.•Requirements would not be enforceable by EPA or the states (unless states had similar requirements under statelaw). Lack of enforcement and Federal oversightmay significantly reduce compliance and effectiveimplementation of regulatory requirements.•Although this option does not require phase-out of existing surface impoundments, it could cause some phase-outbecause all surface impoundments would need to have composite liners by a certain date, or they would need toclose down, assuming the rule is effectively implemented by the states.•Eliminates some ground-water contamination over the current situation (e.g., becauseof surface impoundmentretrofitting), thus avoiding some damage cases, again assuming effective implementation.25•Require review of surface impoundments for stability byindependent experts, but because impoundments couldremain in operation (because they are currently lined or owners choose to retrofit linethem rather than phasethem out), there would still bea risk of future structural failures of impoundments.Option 3: RCRA Subtitle “D prime”:•Regulation of disposal undersubtitle D, with liners required only fornew surface impoundments and landfills. Thisapproach would be the same as the subtitle D approachabove, except that existing surface impoundments would notbe required to retrofit and install acomposite liner, or close. Unlinedexisting impoundments could continue tooperate, but new landfills and surface impoundments or expansions of existing landfills must have composite liners.•Under this approach the potential for catastrophic failureof surface impoundments would remain significant, sincephase-out of surface impoundments wouldn’t occur.•Would be less effective than the subtitle C or subtitle Dapproaches in eliminating groundwater contamination (or inhaving it be discovered sooner),but would still provide some benefits over no national regulation. (The same caveatson state regulations and enforcement would apply as in the subtitle D option.)•Would reduce regulatory costs significantlysince conversion to dry disposal would not be required, but would alsoprovide fewer benefits.Evaluation of three regulatory options isconsistent with OMB’s 2003 “Circular A-4: Regulatory Analysis” best practices guidance for Federalagencies, which requires analysis ofat least three regulatory options.25All three regulatory optionsare identical in two ways:1.Beneficial use: All options propose to replace the 1980 RCRA “Bevill exclusion” under 40 CFR 261.4(b)(4) for CCR disposalwith newRCRA waste regulation, but to retain the existing Bevill exclusion for CCR beneficial uses. Beneficial uses of CCR will retain theBevill exclusion and will not be subject to any regulation, either under Subtitle C or Subtitle D.2.Engineering controls: All options propose the same set of10 custom-tailored engineering controls(i.e., technical design andoperating standards) for CCR disposal units. For purpose of launching this RIA inApril 2009, the waste disposal “managementstandards” described inEPA’s August 1999 cement kiln dust (CKD) proposed rule26were used in absence ofuniquely defined controlsspecific to CCR disposal units. This was a reasonable starting point because the CKD management standards are similar or identical tothe technical standards defined in the CCR proposed rule.25OMB’s 2003 Circular A-4 (p.16) directs Federal agencies to analyze at least three regulatory options: http://www.whitehouse.gov/omb/assets/omb/circulars/a004/a-4.pdf26EPA’s 20 August 1999 CKD proposed rule (Federal Register, 67 pages).26During EPA’s April 2009 launch of this RIA, EPA defined three other RCRA options which are verysimilar to the above three options. Theinitial set of options is included in EPA’s October, 8 2009 initial draft (165 pages)of this RIA which EPA submitted to OMB for review inmid-October 2009. The regulatory cost estimation inChapter 4and the supplemental analyses inChapter 7of this RIA are based on theinitial set of three options, defined as follows:2009 Option 1: RCRA Subtitle C “hazardous” industrial waste:•Subtitle C provides Federal enforceability.•RCRA Section 3004(x)27custom-tailor engineering controls (i.e., technical standards) for CCR disposal units.•Subject CCR to Subtitle C land disposal restriction (LDR) 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 yearsafter rule’s effective date.2009 Option 2: RCRA Subtitle D “non-hazardous” industrial waste (version 1):•This option is different from the 2010 Option 2: SubtitleD option because it does notrequire liners for existingimpoundments as the 2010 Option 2 does,but it only requires liners for new impoundments (and only for newlandfills).•Regulate CCR disposal as RCRA Subtitle D non-hazardous waste based on the same custom-tailored engineeringcontrols as the 2009 Option 1.•Except under RCRA Section 7003 “imminent and substantial endangerment” authority, this option is not Federallyenforceable because RCRA Subtitle D directs EPA only toassist state government waste management programs.282009 Option 3: Hybrid RCRA Subtitle C & Subtitle D:•Subtitle C regulation of CCR impoundments (same as the 2009 Option 1)•Subtitle D regulation of CCR landfills (same as the 2009 Option 2)27The following excerpt from RCRA Section 3004(x) pertains specifically to CCR, by providing EPA with authority “to modify” theRCRA Subtitle C technical standardsfor regulation of CCR disposal:“Section 3004(x): If... (2) fly ash waste, bottom ash waste, slag waste, and flue gas emission control waste generated primarilyfrom the combustion of coal orother fossil fuels... is subject to regulation under this subtitle, the [EPA] Administrator is authorized to modify the requirements of subsections (c), (d), (e), (f), (g),(o) and (u) and section 3005(j), in the caseof landfills or surface impoundments receiving such solidwaste, to take into account the special characteristics of suchwastes, the practical difficulties associated with implementationof such requirements, and site-specific characteristics, including but not limited to the climate,geology, hydrology and soil chemistry at the site, so long as such modified requirements assure protection of human health andthe environment.”28Section 4001 of Subtitle D of the 1976 RCRA statute prescribesthe Federal role under Subtitle D as assistance to state governments: “The objectives of this subtitle areto assist in developing and encouraging methods for the disposal of solid waste... Such objectives are to be accomplished through Federal technical and financialassistance to States or regional authorities for comprehensive planning pursuant to Federal guidelines designed to foster cooperation among Federal, State and localgovernments and private industry.”27Chapter 3Baseline CCR Management in the Electric Utility IndustryThis Chapter characterizes baseline (i.e.,current) CCR management practices withinthe electric utility industry. This baseline consists of twocomponents described in this Chapter: CCR disposal and CCR beneficial use. This Chapter begins with a description of baselineCCRmanagement quantities (i.e., annual tonnagesof CCR) and CCR disposal methods used by the electric utility industry. This Chapter alsopresents an evaluation of baseline operating conditions (i.e., “engineering controls” and“ancillary costs”) of CCR disposal units and anestimate of the associated costs to the electric utility industry. This Chapter concludes with a characterization of baselineCCR “beneficial use”(for CCR which is not disposed) and an estimate of associated net benefits to the environment and the national economy.3A. Identity of Coal-Fired Electric Utility PlantsThis RIA initially identified the sub-groupof potentially affected coal-fired electric utility plants using the 2007 US Department of Energy(DOE), Energy Information Agency (EIA) database for electricitypower plants from the Form EIA-860 "Annual Electric Generator Report.”This data was supplemented with the master list of utility plants from the 2007 EIA-860 database entitled “existingunits2007”.29This RIAapplied three database filters to identify the subset of electricity plantswhich may potentially be affected by the proposed rule:•Database filter #1 of 3: EPA sorted the 2007 EIA-860 electric plant database by the North American Industry ClassificationSystem (NAICS) industrial codes, and deleted all plants not assigned utility sector NAICScode 22 (only 2-digit NAICScodes are provided by the EIA database).NAICS 22:The Utilities sector comprises establishments engagedin the provision of the following utility services:electric power, natural gas, steam supply, water supply,and sewage removal. Withinthis sector, the specificactivities associated with the utility services provided vary by utility: electric power includes generation,transmission, and distribution; natural gas includesdistribution; steam supplyincludes provision and/ordistribution; water supply includestreatment and distribution; and sewage removal includes collection,treatment, and disposal of wastethrough sewer systems and sewage treatment facilities. Excluded from thissector are establishmentsprimarily engaged in waste management services classified in Subsector 562 WasteManagement and Remediation Services. These establishments also collect, treat, and dispose of waste29The EIA-860 database is itemized on an electricity generator unit basis, not on a per-plant basis. It includes specific information about generators at electric power plantsowned and operated by electric utilities andnon-utility industries (i.e., including independent power producers, combined heatand power producers, and other industrials).The file contains generator-specific information such as initial date of commercial operation, prime movers, generating capacity, energy sources, status of existing andproposed generators, proposed changes to existing generators, county and State location (including power plant address), ownership, and FERC qualifying facility status.Also included are data related to the ability to use multiple fuels; specifically, data on co-firing and fuel switching are included. The DOE spreadsheet “existingunits2007”is available at http://www.eia.doe.gov/cneaf/electricity/page/capacity/capacity.html.28materials; however, they do not use sewersystems or sewage treatment facilities”Source: US Bureau ofCensus at: http://www.census.gov/eos/www/naics/•Database filter #2 of 3: EPA deleted all of the units that did not use coalas either a primary or secondary energy sourceusing the coal type codes displayed inExhibit 3Abelow. In addition to these five categories of coal, examples of otherprimary or secondary energy sources reported by coal burning electricutility plants are agriculture byproducts, distillate fueloil, natural gas, petroleum coke, propane, and wood & waste solids.Exhibit 3ATypes of Coal Used by Electric Utility Plants as Coded in the 2007 DOE-EIA DatabaseItemCodeType of Coal1BITAnthracite Coal, Bituminous Coal2LIGLignite Coal3SUBSub-bituminous Coal4 WC Waste/Other Coal (Anthracite Culm, Bituminous Gob, Fine Coal, Lignite Waste, Waste Coal)5 SC Coal Synfuel. Coal-based solid fuel that has been processed by a coal synfuel plant,and coal-based fuels such asbriquettes, pellets, or extrusions, which are formedfrom 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 plants. Based on thereported operating status of the generators at these plants(i.e., OP, OS, SB, RE, OA)30, 11 plants reported thatall generators areout-of-service, 2 plants reportedthat all generators are on standby and all remaining plants reported that at least one of theirgenerators is operating. Removalof the 11 out-of-service plantsfrom the master list resultedin a total affected plant population of495 coal-fired electric utility plants.31Appendix Cpresents the list of 495 plants.32For purpose of identifying the types and size classifications for owner entities,this RIA initially used the utility code reported in the 2007 EIA860 database to identify which plants are owned by the same company. Company owner classifications were also checked for manyplantsusing internet searches by plant and company name which sometimes revealed parent company owners. As summarized inExhibit 3Band30OP = Operating - in service (commercial operation) and producing electricity. Includes peaking unitsthat are run on an as needed (intermittent or seasonal) basis, OS =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 nextcalendar year, SB = Standby/Backup -available for service but not normally used (has little or no generation during the year) for this reporting period, RE = Retired - no longer in service and not expected to bereturned to service, and OA = Out of service – was not used forsome or all of the reporting period but was either returned toservice on Dec 31 or will be returned to servicein the next calendar year. Note: Units undergoing maintenance or repair of less than 12 months and are expected to be returnedto service are assigned operating status.31This RIA filtered out 11 out-of-service electricity plant identification codes: 508, 511, 996, 1732, 2341, 2468, 2529, 2531, 2908, 3419, and 55612.32In comparison, a 2008 EPA Office of Water (OW) study estimated a nationwide total of 497 coal-fired electric plants using thesame 2005 EIA-767 database; the 495plants estimated in this RIA are less thanthe 2008 EPA OW estimate because this RIA takes account of more recent plant operating status information (i.e., plants whichhave 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 Generating Point SourceCategory: 2007/2008 Detailed Study Report,” report nr. 821-R-08-011, August 2008; http://www.epa.gov/guide/304m/2008/steam-detailed-200809.pdf29Exhibit 3Cbelow, these 495 coal-fired electricutility plants are owned and operated by 200 entities which are listed inAppendix Dto thisRIA. The 495 plants have a combined electricity generationnameplate capacity of 369,183 MW (megawatts), ranging in individualplant sizefrom 2.3 MW to 3,969 MW, with an average sizeof 746 MW and a median size of 497 MW. Thiscombined capacity represents 34% ofthe1.088 million MW total US electricitygeneration capacity as of 2007.33Exhibit 3BSummary Classification of 495 Coal-Fired Electric Utility Plants by Type/Size of Owner Entities (2007)ItemType of Owner Entity*Entity SizeClass**Coal-Fired ElectricUtility Plant CountOwner EntityCount1 Federal government Non-small 11 12 State government jurisdictions (authorities, districts) Non-small 13 73 Medium & large population municipal government jurisdictions Non-small 27 194 Medium & large companies Non-small 372 1105 Medium & large cooperatives (this RIA assumes all privately-owned) Non-small 20 126 Small county government jurisdictions (commission) Small 1 17 Small municipal government jurisdictions (agencies, commissions) Small 33 338 Small companies Small 12 119 Small cooperatives (this RIA assumes all privately-owned) Small 6 6Summary:Column totals =495200Private sector sub-total (items 4+5+8+9) = 410 (83%) 139 (70%)State/local government sub-total (items 2+3+6+7) = 74 (15%) 60 (30%)Small entity sub-total (items 6+7+8+9) = 52 (11%) 51 (26%)Notes:* Type of owner entity estimated and assigned by EPA ORCR based onowner name or internet research on type of ownership.** Size class determined according to thefollowing numerical threshold criteria consistent with EPA’s Nov 2006 guidance for RegulatoryFlexibility Act (RFA) Small Business RegulatoryEnforcement Fairness Act (SBREFA) compliance:•Small non-government = Based on the US Small Business Administration NAICS code 221112 small business size standard of <4million 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 section601(5)) of “small government jurisdiction” as thegovernment of a city, county, town, township, village, school district, or special district with a population of less than 50,000.•Non-small government = entity’s jurisdiction population >50,000 people.33Source: US Dept of Energy (DOE), Energy Information Administration (EIA) website at http://www.eia.doe.gov/cneaf/electricity/epa/epat2p2.html30Exhibit 3CState-by-State Electric Utility Plant Counts by Type/Size of Owner Entity (2007)Count of Plants Owned by Non-Small EntitiesCount of Plants Owned by Small EntitiesItemStateFederalgovernmentStateGovernmentNon-smallmunicipalNon-smallcompanyNon-smallcooperativeCountygovernmentSmallmunicipalSmallcompanySmallcooperativeRow totalplants1 AK 2 22 AL 2 7 1 103 AR 3 34 AZ 2 3 1 65 CA 6 66 CO 1 2 11 147 CT 2 28 DC 09 DE 3 310 FL 5 9 1 1511 GA 10 1 1112 HI 2 213 IA 1 13 3 2 1914 ID 015 IL 2 21 2 2516 IN 21 5 2617 KS 2 6 818 KY 2 1 14 3 1 2119 LA 4 420 MA 4 421 MD 8 822 ME 1 123 MI 2 13 5 2 2224 MN 1 10 5 1625 MO 5 10 2 2 1 2026 MS 3 1 1 527 MT 4 1 528 NC 19 3 2229 ND 2 5 730 NE 4 3 731 NH 2 232 NJ 1 6 733 NM 3 334 NV 2 235 NY 11 1 1 1336 OH 2 20 4 2637 OK 1 4 1 638 OR 1 131Exhibit 3CState-by-State Electric Utility Plant Counts by Type/Size of Owner Entity (2007)Count of Plants Owned by Non-Small EntitiesCount of Plants Owned by Small EntitiesItemStateFederalgovernmentStateGovernmentNon-smallmunicipalNon-smallcompanyNon-smallcooperativeCountygovernmentSmallmunicipalSmallcompanySmallcooperativeRow totalplants39 PA 32 2 3440 RI 041 SC 4 10 1442 SD 2 243 TN 7 744 TX 1 2 14 1 1 1945 UT 1 4 1 646 VA 15 1 1647 VT 048 WA 1 149 WI 12 3 2 1750 WV 16 1651 WY 8 1 9Column totals= 11 13 27 372 20 1 33 12 6495The annual amount of coal burned by these 495 operating plants is1.036 billion tons per yearas reported in the 2007 EIA-923 database,according to the following five types of coal fuel categories:•Bituminous coal (DOE-EIA data code= BIT): 330 plants (67% of 495 plants)•Lignite coal (LIG): 21 plants (4%)•Coal-based synthetic fuel (SC): 19 plants (4%)•Sub-bituminous coal (SUB): 201 plants (41%)•Waste/other coal (WC): 33 plants (7%)Many plants use more than one coal fueltype so the above percentages exceed 100%.Appendices B & Cpresent the quantity of coal burnedand the types of coal burned for the list of 495plants. As displayed in the state-by-stateExhibit 3Dbelow, 47 states have coal-fired electricutility plants (3 states --- ID, RI, VT --- and DC do not have electric utility plants). The top-5 state coal-fired electric utility plant counts are:1.PA 34 plants2.IN & OH 26 plants each3.IL 25 plants4.MI & NC 22 plants each5.KY 21plants32Exhibit 3DState-by-State Count of NAICSCode 22 Electric Utility Plantsand Associated CCR GenerationItemStateCount ofPlants(2007)% of PlantsCCR Generated(tons as of 2005)% of CCRGeneration1 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 3DState-by-State Count of NAICSCode 22 Electric Utility Plantsand Associated CCR GenerationItemStateCount ofPlants(2007)% of PlantsCCR Generated(tons as of 2005)% of CCRGeneration30 NE 7 1.41% 614,473 0.44%31 NH 2 0.40% 176,900 0.13%32 NJ 7 1.41% 735,214 0.52%33 NM 3 0.61% 3,983,300 2.82%34 NV 2 0.40% 391,500 0.28%35 NY 13 2.63% 1,479,792 1.05%36 OH 26 5.25% 10,429,446 7.39%37 OK 6 1.21% 1,490,800 1.06%38 OR 1 0.20% 99,900 0.07%39 PA 34 6.87% 15,359,680 10.88%40 RI 0 0% 0 0%41 SC 14 2.83% 2,178,359 1.54%42 SD 2 0.40% 103,753 0.07%43 TN 7 1.41% 3,240,120 2.29%44 TX 19 3.84% 13,165,728 9.32%45 UT 6 1.21% 2,582,144 1.83%46 VA 16 3.23% 2,388,527 1.69%47 VT 0 0% 0 0%48 WA 1 0.20% 1,405,220 1.00%49 WI 17 3.43% 1,412,534 1.00%50 WV 16 3.23% 9,231,718 6.54%51 WY 9 1.82% 2,224,848 1.58%Total495100%141.2 million*100%* Note: In comparison to this estimate based on DOE-EIA databases cited in thisRIA, the American Coal Ash Association (ACAA) estimated 123.1 million tonsCCR generated in 2005 based on its annual voluntary participation survey :http://acaa.affiniscape.com/associations/8003/files/2005%20CCP%20Survey%20%2809-19-06%29Corrected-11-09-07.pdf333B. Types of CCR Disposal Units•Estimated Plant Counts by Type of CCR Disposal UnitThe scope of CCR disposal units covered bythis RIA is active units (i.e., operational units which were receiving CCR as of year 2005).Inactive or abandoned units (i.e., non-operatingunits) are excluded from thescope of this RIA. The data source used to identify baseline CCRmanagement practices and active units is the 2005 U.S. Department of Energy (DOE) Energy Information Administration (EIA) FormEIA-767“Steam-Electric Plant Operation and Design Report” database.34The EIA-767 database is the primary data source for reporting annual CCRdisposition for plants generating greater than 100 MW (megawatts) of electricity. Plants smaller than 100 MW are not requiredto report CCRtonnage and disposition (i.e., typeof disposal and beneficial use) data to the EIA-767 database. Schedule 3 of the EIA-767 database containsthe annual disposition of CCR in one or more of the following five forms of CCR management categories, according to annual tonsdisposedfor each plant. EIA-767 does not contain counts of CCR disposal units for each plant:1.Company-owned landfill2.Company-owned disposal ponds(i.e., surface impoundments)3.Onsite use and storage (this RIA assumes all of this quantity eventually goesto beneficial use, not disposal)4.Sold (for beneficial use)5.Disposed off siteThe 2005 EIA-767 database contained annual CCR disposal data for363 of the 495 plants identified in the 2007 EIA-860 database.The 363plants are over 100 MW in size and thusare covered by the EIA-767 database. Forthe 132 plants which did not report CCR disposal practicesin the 2005 EIA-767 database because they are less than 100 MW insize, disposal of CCR is assumedto take place in on-site oroff-sitelandfills (whichever is the lowest-cost method as assigned by theCCR disposal engineering control cost model used for this RIA). For each ofthe 495 coal-fired utility plantsidentified in the prior section of this RIA using the 2007EIA-860 database, baseline CCR disposal practiceswere assigned using the methodology and data sources presented below. Based on this analysis,467 of the 495 plants dispose CCRusing thefollowing methods. The 28 remainder of the 495 plants do not dispose because they solely supplytheir CCR for beneficial uses.A total of 272of the 495 plants supply CCR for beneficialuses. The total count of disposal methods exceeds the 467 totalcount of disposingplants becausesome plants use more than one disposal method. The EIA-767 database does not contain counts of disposal units for each plant so only plantcounts are summarized below according to disposal method, not CCR disposal unit counts. Because some plants use more than onedisposalunit, the total count of CCR disposal units – although unknown for purpose of this RIA -- exceeds the 467 total count of disposing plants.34Source: The EIA-767 database includes annual data from organic-fueled or combustible renewable steam-electric plants with a generator nameplate rating of 10 or moremegawatts (MW) regardless of current ownership and/or operation. However, it contains annual tonnage CCR generation, CCR disposal, and CCR beneficial use data onlyfor plants over 100MW in size. The EIA terminated the EIA-767 database after year 2005. Beginning with calendar year 2007 data, two other surveys, the Form EIA-860and the Form EIA-923, will collect most of the data formerly collected by Form EIA-767. No data will be collected for 2006. The following weblink provides a crosswalkof the data elements previously collected onthe Form EIA-767 for 2005 with the corresponding data elements to be collected beginning with calendaryear 2007 on theForm EIA-860 or the Form EIA-923: http://www.eia.doe.gov/cneaf/electricity/2008forms/consolidate.html34•Onsite landfills:311 plantsoperate onsite CCR landfills (this RIA refers tothese as “onsite” landfills although some may belocated off plant property). This estimate consistsof two sources (i.e., 212 plants + 99 plants):212 plants: dentified throughactual data reporting of 363 coal-firedelectric plantsin size >100 MWcontained in the 2005 EIA-767 database, out of the total 495 plants identified using the 2007 EIA860 database (as described in the previous section above).99 plants: This estimate is based on the remainder 132 electric utility plants (i.e., 495 minus 363plants = 132 plants) between 1 MWand 100 MW size for which there is no CCR disposal data in theEIA-767 database, and for which the CCR disposal engineering control cost model used in this RIAassigned the lowest-cost of three landfill options:(1) onsite dug landfill, (2) onsite pile landfill, or(3) offsite landfill. The cost model assignment was dependent upon the level of baseline engineeringcontrols assumed required by each plant’s state location and annual CCR disposaltonnage. The costmodel estimated that 99 of the 132 plants without data dispose CCR in onsite landfills.•Onsite impoundments:158 plantsoperate onsite CCR surface impoundments (aka “ponds,” “embankments,” “dams,” “dikes,” “wetdumps,” “constructed wetlands”). This RIA assumes that all impoundments are “onsite” although some maybe located off plant property.The non-duplicative count of plants using onsite landfills and/or onsite impoundments is383 plants.•Offsite disposal:149 plantsassigned as sending CCR offsite for disposal to commercial landfills (of which 84 plants solelyship CCR for offsite disposal). Off-site landfillsreceiving CCR are assumed to already be in compliancewith EPA’s RCRA Subtitle D guidance. The 149 plantsassigned as using offsite landfills consist of thefollowing assignments according to datasources (i.e., 116 plants + 33 plants):116 plants: Electric utility plants >100 MW size (source: 2005 EIA-767 database): Final dispositionof wastes is reported as either (a) company-owned landfill, (b) company-owned disposal pond, (c)on-site use & storage, (d) sold, or(e) off-site disposal. This RIA assumes that off-site disposalmeans offsite commercial landfill. Plants could havereported offsite minefill in this category if itwas not "sold" (e.g., they paid to dispose it in a mine or it was used as minefill and no payment wasmade to the electric utility). However, it isunknown the sub-quantity of “offsite disposal” whichincludes plants reporting tonnages for non-sold uses as offsite minefill.3535In July 2009, ORCR contacted the DOE-EIA Form 767 questionnairecontact person (Natalie Ko, Electric Power Division) to clarify this RIA’s assignment of all “offsitedisposal” tonnages as commercial landfills. The DOE-EIA contactperson responded with additional information from four 2005 Form EIA-767 questionnaires regardinghow electricity plant respondents optionallycharacterized the fly ash and bottom ash reported in the Form EIA-767 survey questionnaire as “Off Site Disposal” :· “This quantity of fly ashwas given away at no cost”· “The fly ash was sent off site for beneficial use”· “The fly ash is injected into thenearby mines for recharging the mines”· “Ash is recycled as a beneficial re-use product for flowable fill in the construction industry”35•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-products)•Sub-total = 116 plants(non-duplicative count)33 plants: This estimate is based on the 132 electricutility plants between 1 MW and 100 MW sizefor which there is no CCR disposal data in theEIA-767 database, and for which the CCR disposalengineering control cost model used in this RIA assigned the lowest-cost of three landfill options:(1) onsite dug landfill, (2) onsite pile landfill, or (3) offsite landfill. The cost model assignment wasdependent upon the level of baseline engineeringcontrols assumed required by each plant’s statelocation and annual CCR disposal tonnage.•Estimated Counts of CCR Disposal UnitsThe methodology of this RIA does not estimate or use secondaryinformation about the actual count of CCR disposal units (i.e.,landfill unitsand impoundment units) used by these 467 onsite or offsite disposingplants. However, there are two sources of CCR disposal unit counts:•Source #1 of 2: ASTSWMO: The February-March 2009 ASTSWMO voluntary participation survey36of 42 states (which is incompletecoverage of the 47 states identified inthis RIA for the 495 coal-fired electric plants) estimates a total of 484 electric utility plant CCRdisposal units:•227 electric utility plant CCRlandfill 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 inthe ASTSWMO survey to electric utility plants inNAICS code 221112, (b) may also include counts of CCR disposal unitsassociated with other industries which generate coal-firedelectricityin the surveyed states, (c) may include inactive/abandoned as well as active CCR disposal units, or (d) may include landfills or impoundmentsoperated by electric utility plants whichcontain other types of waste streams (e.g.waste water treatment ponds without co-mingled CCR).Source #2 of 2: EPA: In March 2009 EPA sent letters37to 210 coal-fired electric plant facilities and owner companies in order to identify thelocation of CCR impoundments and evaluate their structural integrity inthe wake of the December 2008 CCR impoundment collapseand36Source: Association of State and TerritorialSolid Waste Management Officials (ASTSWMO), 01 April 2009 letter to Matt Hale, Director, EPA Office of ResourceConservation and Recovery: http://www.astswmo.org/files/publications/Positionpapers/ASTSWMO-CCB-letter-attachments.pdf36flooding at the TVA Kingston TN electricity plant. Although not used in this RIA other than for reference here, the responsesreceived to theMarch 2009 EPA letters resulted in identification of 584 CCR impoundments units at electric utility plants. The letters did not collectinformation about CCR landfills383C. Types of CCR and Annual QuantitiesAs of 2008, coal-fired utilities burn approximately 1.036 billion tons of coal peryear using a variety of conventional combustion technologies.NAICS 22 electric utility coal combustion resultsin the generation of five types of CCR:1.Fly ash2.Bottom ash3.Flue gas desulfurization (FGD) sludge4.Gypsum5.Other residues (including boiler slag)These wastes may be (a) disposed in onsite landfills and surface impoundments (i.e., ponds, dams, embankments, lagoons), or (b)may beapplied to beneficial uses, or (c) disposed offsite. At the time of preparing this RIA in 2009, waste generation and disposition data fromSchedule 8, Part A of the 2007 DOE EIA databasefor the Form EIA-932 “PowerPlant Operations Report” database had yet to be finalized.Instead, the most currently available waste data was from the 2005 DOE EIA Form 767“Steam-Electric Plant Operation and DesignReport”database. Therefore, the 2005 EIA-767 database is the primary source used in this RIA to quantify CCR generation and identifythe ultimatedisposition of CCR (i.e., typeof disposal or beneficial use). CCR generation and final disposition are reported under the above five CCR typecategories in the 2005 EIA 767 database. As estimated in this RIA and displayed below inExhibit 3E, the 495 electric utility plants generated141.2 million tons per yearof CCR (2005/2007 mixed data).Interpretive Note: This RIA’s CCR generation estimate of 141.2 million tons is 15% and 8% higher,respectively, than the123.1 million tons (2005)and the131.1 million tons (2007)annual CCR generation estimates published bythe American Coal Ash Association (ACAA).39The numerical discrepancy between this RIA’s estimate andthe ACAA estimates may be explained by the fact thatboth estimates (i.e., thisRIA and the ACAA) arebased on incomplete CCR tonnage disposition data for less than the “universe” of all known operating37Source: Additional information about these March 2009 EPA letters is available at http://www.epa.gov/osw/nonhaz/industrial/special/fossil/coalashletter.htm38Source: EPA’s 584 CCR impoundment unit count is documented athttp://www.epa.gov/osw/nonhaz/industrial/special/fossil/surveys/faqs.htm#1839As of the date of this RIA, ACAA’s “Coal Combustion Products Production & Use Statistics” website contains annual CCR generation and annual CCR beneficial usetonnage estimates for the US electric utility industry for years 2001, 2002, 2003, 2004, 2005, 2006, 2007, and 2008. As reported in footnotes on ACAA’s annual surveyresults data tables, ACAA’s CCR generation and CCR beneficial use annual tonnage estimates are based on the following survey coverages: 2001 coverage not indicated ondata table; 2002 2/3rdcoal burn; 2003 60% coal burn; 2004 60% coal burn; 2005 54% coal burn; 2006 57% coal burn reported by 58 electric utilities; 2007 161 plants; and2008 274 plants. ACAA’s annual CCR tonnage data webpage is athttp://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=337electric utility plants in the datayear, extrapolated to plants for which there is no CCR tonnage data in theEIA database (in the case of this RIA’s estimationmethodology) and in the case of the ACAA estimates,extrapolated to plants not covered by ACAA’s annual utility industry survey by supplementing with EIAdata.The estimate of CCR generation developed inthis RIA consists of the following breakoutof generation estimates according to two electricutility plant size categories, which correspond to the CCR tonnage disposition data reporting cut-off requirement in the EIA-767 database:•>100 MW plants:Exhibit 3Ebelow presents CCR disposition data for a sub-total of120.9 million tonsCCR generated per year asreported by plants with annual electricity generation >100 MW from Schedule 3A of the 2005 EIA-767 database foreach plant.•Ash generation data (fly ash and bottom ash) were available for 385 plants.•FGD sludge generation data wereavailable for 72 plants.•Gypsum generation data were available for 31 plants.•Other byproduct generation datawere available for 40 plants.If plants > 100 MW reported either company landfill, company disposal ponds, sold for beneficial use, or off-sitedisposal of CCR in the EIA-767 database, these final disposition practices are assumed in this RIA for the baseline. Atotal 179 plants with company-owned CCR landfills and 158 plants with company-owned CCR surfaceimpoundments were reported inthe 2005 EIA-767 database (i.e.,337 of the 495 electric plants).40112 of the 495plants reported 8.2 million “on-site use and storage” which thisRIA assigned as beneficialuse not as disposal. Thisassumption is supported by (a) DOE’s August 2006 report41“Coal Combustion Waste Management at Landfills andSurface Impoundments 1994-2004” which interpreted the entire "onsite use & storage"quantity as beneficial use, and(b) the American Coal Ash Association (ACAA) which indicates that 49.6 million tons of coal ash were beneficiallyused in 200542. However, the beneficial use estimate inExhibit 3Ebelow is much less at 38.8 million tons which isbased on the EIA-767 “Sold” (i.e., beneficial use) CCR tonnage category. But adding the 8.2 million tons reported as"onsite use & storage" yields anestimate of 47.0 million tons (Exhibit 3G), which nearly matches the ACAAbeneficial use estimate of 49.6 million tons. This suggestsit is valid to assign the tonnage reported in the EIA-767database as "onsite use & storage" to beneficial use ratherthan to disposal.40In the 2005 DPRA Report, an additional step was included afterstep 1 that identified additional disposal practices using landfill and surface impoundment as reported inthe 1995 EPRI Comanagement Survey. This data source was not used to identify CCR management units in this RIA given it dates back to 1995. The data source is onlyused to identify existing engineering controls for the units identified in the 2005 EIA 767 database. In the 2005 DPRA Report,14 additional landfills and 10 surfaceimpoundments were identified using this information source.41Source: 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=200842Source: ACAA’s 2005 beneficial use dataare available at http://acaa.affiniscape.com/associations/8003/files/2005%20CCP%20Survey%20%2809-19-06%29Corrected11-09-07.pdf38•1MW to 100 MWExhibit 3Fbelow presents an additional sub-total of20.3 million tonsper year of CCR generated by 132 electricutility plants between 1 MW and 100 MW in capacity which had no CCR management information in the EIA767database, because plants less than 100 MW are not required to report their CCR management annual tonnages in theEIA-767 database. Therefore, this RIA formulated anestimate for this size category of plants based on thefollowing approach. Coal use and percent ash content data from Schedule 4A of the 2005 EIA-767 database wereused to estimate ash generation quantities for 102 plants within this smaller size category. For 5 plants for whichEIA-767 coal use data were unavailable for 2005, coal use data from Schedule 4A of the 2007 EIA-923 databasewere used to estimate CCR generation quantities for those 5 plants. FGD sludge generation data obtained fromSchedule 843of the 2005 EIA-767 database were used for 115 plants. Landfill (either on-site or off-site whicheveris more economical) is the assumed CCR disposal practice. No gypsum orother byproduct generation quantitieswere estimated. For plants between 1 MW and 10 MW, ash generation quantities estimated using generatornameplate capacity rating data from the 2007 DOE Form 860 database. This 1 MW to 100 MW subtotal of 132plants consists of two sub-categories:•10 MW to 100 MW: 5.4 million tons of CCR for 110 plants estimated by multiplying the quantity of coal theyburned by the percent CCR content of the coal data from Schedule 4A of the 2005 EIA-767 database and 2007DOE EIA 923 database, or using generator nameplate rating data from the 2007 EIA-860 database and anaverage percent ash content.•1 MW to 10 MW: 14.9 million tons of FGD sludge reported for 22 plants in Schedule 8 of the 2005 EIA-767database that did not reportany FGD sludge in Schedule 3A of the 2005 EIA-767 database.43In general, data obtained from Schedule 8 of the 2005 EIA-767 database reflects information reported by plants between 10 MW and 100 MW. However, if a plantgreater than 100 MW reported no final disposition quantities for FGD sludge in Schedule 3A of the 2005 EIA-767 database, the reported FGD sludge quantity in Schedule 8is assumed in this RIA to be placed in a landfill for that plant.39Exhibit 3EAnnual CCR Disposition for NAICS 22Electric Utility Plants >100 MW Capacity (tons per year as of 2005)A B C D E F (A+...+E)Item CCR CategoryCompany-OwnedLandfill(Dry Disposal)Company-OwnedDisposal Ponds(Wet Disposal)Onsite Use &Storage (assumedas beneficial use)Sold forBeneficial UseOffsite Disposal(assumed offsitelandfills)Row Totals1 Fly Ash 21,324,280 15,212,590 3,744,370 20,760,230 9,314,540 70,356,0102 Bottom Ash 5,707,740 4,311,630 3,487,660 5,453,717 1,907,480 20,868,2273 Flue Gas Desulfurization Sludge 9,526,400 1,886,200 465,600 408,910 2,506,540 14,793,6504 Gypsum (salable) 54,620 872,100 372,100 8,437,400 782,800 10,519,0205 Other CCR 226,510 82,900 108,830 3,729,400 247,680 4,395,3206 Totals 36.8 million 22.4 million 8.2 million 38.8 million 14.8 million 120.9 millionExhibit 3FAnnual CCR Disposition for NAICS 22 Electric Utility Plants 1 MW to 100 MW Capacity (tons per year as of 2005)ABCD (A+B+C)ItemCCR CategoryFly Ash Disposed inOff-site Landfill(Plants 1 MWto 100 MW)Fly Ash Disposed inCompany-ownedLandfill(Plants 1 MW to 100 MW)FGD Disposed inCompany-Owned Landfill(Plants >10 MW)Row Totals1 Fly Ash 274,917 5,147,468 NA 5,422,3852 Bottom Ash Included under Fly Ash Included under Fly Ash NA Included under fly ash3 Flue Gas Desulfurization Sludge NA NA 14,852,300 14,852,3004 Gypsum (salable) NA NA Included in row 3 Included in FGD5 Other Byproducts Included under Fly Ash Included under Fly Ash NA Included under fly ash6 Totals 0.3 million 5.1 million 14.9 million 20.3 millionExhibit 3GAnnual CCR Disposition for NAICS22 Electric Utility Plants All Sizes (tons per year as of 2005)(Source:Exhibit 3E+Exhibit 3F)ABCDE (A+B+C+D)ItemCCR CategoryCompany-OwnedLandfill(Dry disposal)Company-OwnedDisposal Ponds(Wet disposal)Beneficial Use(onsite BU + offsiteBU + storage for BU)Offsite Disposal(assumed offsitecommercial landfills)Row Totals1 Fly Ash 26,471,748 15,212,590 24,504,600 9,589,457 70,356,0102 Bottom Ash 5,707,740 4,311,630 8,941,377 1,907,480 20,868,2273 Flue Gas Desulfurization Sludge 24,378,700 1,886,200 874,510 2,506,540 14,793,6504 Gypsum (salable) 54,620 872,100 8,809,500 782,800 10,519,0205 Other CCR 226,510 82,900 3,838,230 247,680 4,395,3206 Totals56.8 million22.4 million47.0 million15.0 million141.2 millionPercentages 40% 16% 33% 11% 100%40Exhibit 3Hbelow summarizes the respective plant counts, annual tonnage CCR disposal, and electricity generation nameplate capacities ofthe467 plants which dispose CCR, according to type of CCR disposal method (i.e., CCR landfills andCCR impoundments). Because some plantsreported more than one management method, the sum of the plantsacross each disposal method exceeds the total count of 467 disposing plants.Exhibit 3HSummary of Plant Size and CCR Disposal Methods Estimated in this RIAABCDPlants Using CCR Landfills (dry disposal)Characterizing MetricsOnsite LandfillsOffsite**Plants Using CCRImpoundments***(wet disposal)Row Totals(non-duplicative)1. 2007 Count of Coal-FiredElectric Utility Plants whichDispose CCR311 plants(63% of 495)149 plants(30% of 495)(84 plants solely useoffsite landfills)158 plants(32% of 495)467 plants dispose CCR(94% of 495)(CCR from the remainder28 plants is solely forbeneficial uses)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 tons15.0 million tons (16%)•20 tons•1.28 million tons•100,899 tons•33,000 tons22.4 million tons (24%)•500 tons•1.04 million tons•141,550 tons•67,300 tons94.2 million tons(100%)•110 tons•2.11 million tons•201,796 tons•89,300 tons3. 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 MW90,547 MW (25%)•2 MW•2,911 MW•608 MW•350 MW180,901 MW (49%)•75.3 MW•3,564 MW•1,145 MW•893 MW369,183 MW (100%)•2 MW•3,969 MW•746 MW•497 MWNotes:* 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,because it is expensive totransport large volumes of wet (i.e., watery) CCR long distances.*** Surface impoundments are reported in the EIA-767 database as “company-ownedponds.” This RIA assumes all are located onsite.413D. Size of CCR Disposal UnitsThe size of CCR disposal units ranges frommodest to very large, with some impoundments covering 1,500 acres or more. Sizing of the unitsis based on the annual tonnage of CCR placedin the unit. CCR disposal unit size assumptions for this RIA are adopted from Section 4.4.1 ofthe 2005 DPRA Report:•Landfills sizes:Designed as “combination fill landfills”3.8 million cubic yards capacity50% of the capacity excavated below grade40-year capacity (i.e., operating lifespan)44Per-unit surface area size ranges from 12 acres for 10,000 tonsper year to over 2,000 acres for 2,000,000 tons per year.Designed as “pile fill landfills”3.4 million cubic yards capacity5% of the capacity excavated below grade40-year capacity (i.e., operating lifespan)Per-unit surface area ranges from 16 acres for 10,000 tonsper year to over 3,000 acres for 2,000,000 tons per year.•Surface impoundment sizes:o100% of capacity below gradeo40-year capacityoPer-unit surface area ranges from 30 acres for 10,000 tons per year, 140 acres for 50,000 tons per year, 500 acres for 200,000tons peryear, 1,400 acres for 500,000 tons per year, and 5,500 acres for 2,000,000 tons per year.44For the 30 Nov 2005 DPRA report (“Estimation of Costs for Regulating Fossil Fuel Combustion Ash Management at Large Electric Utilities Under Part 258”, docketdocument ID nr. EPA-HQ-RCRA-2006-0796-0469), the EPA asked utility industry representatives forthe typical lifespan years of CCR landfills and impoundments.Industry representatives provided a 40-year estimate for both. This estimate is supported by data provided by industry in the1995 EPRI Comanagement Survey. In theEPRI Survey, data describing six CCR landfills noted the year the unit was opened and the estimated date of closure. The average life expectancy is 34 years and themedian life expectancy is 38 years. Similarly, data provided for 18 CCR impoundments indicate an average life expectancy of 45years and a median life expectancy of 46years. Therefore, this RIA assumes a 40-year lifespan for both landfills and impoundments.423E. Cost of Baseline CCR DisposalThis Chapter presents characterizing data and estimates of the costs to the electric utility industryand to government, for baseline (i.e., current)industry engineering controls and other costs associated withCCR disposal. OMB’s 2003Circular A-4 “Regulatory Analysis” (page 15)requires RIAs to measure the benefits and costsof regulations againsta 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 publiclyavailable data used in priorstudies andreports, updated using empirically-justifiable factors. For purpose of this RIA, the possible types ofbaseline costs include:A. Baseline “engineering control“costs for CCR disposal units:1.Ground water monitoring2.Bottom liners3.Leachate collection system4.Dust controls – applicable to landfills only5.Rain and surface water run-on/run-off controls – applicable to landfills only6.Financial assurance for disposalunit closure and post-closure7.Disposal unit location restrictions (6 types: water tables, floodplains, wetlands, fault areas,seismic zones, karst terrain)8.Closure capping to cover unit9.Post-closure monitoring requirements10.Storage design and operating standards (tanks, containers, containment buildings) – not evaluated in this RIAB. Baseline “ancillary costs” directly related to CCR disposal:11.Offsite disposal12.Structural integrity inspections – impoundments only13.RCRA facility-wide investigation (RFI)14.Corrective action15.Waste disposal permits16.Inspection & enforcement17.Remediation of environmental releases•Characterization of Industry Baseline CCR DisposalFor each of the 467 operating electric utility plants which currently (2007) dispose CCR onsite or offsite (28 of the 495 totalplants solely sendtheir CCR for beneficial uses not disposal),this RIA estimated baselineengineering controls at disposal units and associatedbaseline disposal43costs for each type of disposal (note: the sum of plant counts for each disposal category below exceeds 467 because some plantsuse more thanone type of CCR disposal method):o311 plants with active onsite CCR landfillso158 plants with active onsite CCR surface impoundmentso149 plants which offsite dispose (assumed all involve offsite landfills)For this RIA, the “baseline” is defined as existing conditions plus projection of future conditionsover the 50-year future period-of-analysis2012 to 2061 applied in this RIA (this RIA assumes year 2012 represents thefirst year when the finalrule could take effect, if promulgated).Baseline engineering controls were estimated using the following2-step method which is based ontwo alternative and complementary sourcesof information:•Step 1: If the plant reported controlsin the 1995 EPRI Comanagement Survey, 1996 CIBO Survey, or the 1994-2004 DOE-EPA Study,the stricter of these controls or state-specified controls areassumed for the baseline. Thesestudies contained control datafor 89 plants withCCR landfills and 50 plants with CCR impoundments (i.e., 139 of the 495electric utility plants).State regulations added additionalcontrols at 69 of the 89 landfill plants and 43 of the 50 impoundment plants with plant specific information (e.g., the EPRI Survey data mayhave indicated that the unit had a liner only but stateregulations required groundwater monitoring and capping so these additional controlswere added).•Step 2: Controls specified under state regulations for 34 states are assumed for all other plants in those 34 states for the baseline if no1995 EPRI Comanagement Survey data, 1996 CIBO Survey data, or 1994-2004 DOE-EPA Study data are available for that plant. Thisstep resulted in assigning state-required controls to 201 plants with CCR landfills and 55 plants with CCR impoundments (i.e.,256 of the495 plants). Overall state regulations were added to 270plants with CCR landfills and 98 plants with CCR impoundments.For the 100 plants (i.e., 47 plants with landfills and 53 plants with impoundments) for which there are no data from the threestudies, and no state-regulatorydata on controls from Step 1,no controls are assumed under baseline for on-site landfills andimpoundments; 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 DisposalEngineering Controls Identified inPrior Industry Surveys (1995, 1996, 2004)The controls identified through the Step 1prior studies were more stringent than the state government requirements discussed in Step 2 for:oLandfills: Voluntary controls for 25 plants with landfills (9% of227 plants landfills) receiving 6.4million tons per year (i.e.,9% of total landfill CCR quantity) in 12 states(some are identified as voluntary because state regulations were not reviewed forthe state): AR, AZ, CA, IA, IN, KS, MD, MN, NE, SD, SI, WV.44oImpoundments: Voluntary controls for 39 plants with impoundments (25% of 158 plants withimpoundments) receiving 5.5million tons per year (i.e., 25% of totalCCR impoundment quantity) in 14 states (some are identified as voluntary because stateregulations were not reviewed forthe state): AL, FL, IA, IL, IN, LA,MN, MS, NM, OH, SC, TX, UT, WY.•Step 2: Baseline State Government CCRDisposal Engineering Control Requirements for Landfills & Impoundments (2008)Several states have already established certain CCR disposal unit design and operatingrequirements that are required to be implemented eitherupon the effective date of the regulation(e.g., groundwater monitoring), upon retirement of the disposal unit (e.g., post-closure monitoring), orfor newly constructed units only.Appendix Eof this RIA provides a summary of the state government requirements for both landfills andimpoundments. Current CCR disposal regulations have been reviewed for the top 34 states that utilize coal for producing electricity forrequired engineering controls at landfills and impoundments. The plants located in these states account for 99% of the annualquantity of CCRmanaged in company-owned (i.e., onsite) landfills and impoundments.State regulations were reviewed for the following 34 states: AL, AZ,CO, FL, GA, IA, IL, IN, KS, KY, LA, MD,MI, MN, MS, MO, MT, NV, NM, NY, NC, ND,OH, OK, PA, SC, TN,TX, UT, VA, WA, WV,WI, WY. Below is a synopsis of the baseline state government requirements according to the engineering controls listed above.1. Groundwater monitoring requirements:•Point-of Compliance:Two options for point-of-compliance groundwater monitoring includeinstalling monitoring wells atthe unit boundary or within 150meters of the unit boundary. Recent changesto state regulations suggest that statestypically require unit boundary monitoring.•Number of Wells:Certain states specify a minimumnumber of monitoring wells: FL (3 wells for impoundments), IA (1 well for landfill), IL (multiplewells for landfills), KY (3 wells for landfills), LA (3 wellsfor impoundments and landfills), MO (4 wells for impoundments andlandfills), ND (3 wells for impoundments), OK (3 wells for impoundments and 4 wells for landfills),TN (3 wells for landfills),UT (3wells for landfills), WV (3 wells for impoundments and 4 wellsfor landfills). Well spacing design criteria for landfill boundarydetection wells for FL, IA, and KS were reviewed. FL requires a minimum of one down-gradient detection well every 500 feet placedwithin 50 feet of the unit. Iowa requires a minimum of one detection well every 600 feet placedwithin 50 feet of the unit. KSrecommends 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 Appendix VIII constituents(i.e., 40 CFR 261 Appendix VIII). Of the 34state regulations reviewed, three statesrequire chemical indicator monitoring forsurfaceimpoundments [CO, PA, WV] and 11 states require chemical indicator monitoring for landfills [IA, FL, KY, MI, OH, OK, PA, TN, UT,WI, WV]. Three states requireRCRA Appendix VIII constituent monitoring for impoundments [MO, PA, WV],and 10 states requireRCRA 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 regulations reviewed,one state requires quarterly sampling for surface impoundments[CO (depending on the ground-waterclassification)] and three statesrequire quarterly monitoring for landfills [IA (until baseline conditions are established), IL (first 5 years), MI]. Five states require semi-45annual sampling for surface impoundments [LA, MO, ND, PA (chemical indicators), WV] and 12states require semi-annualmonitoring for landfills [FL, GA, KY, LA, MO, OH (chemical indicators), OK,PA (indicator parameters),TN (chemical indicators),UT, WV, WY]. Three states require annual sampling for surface impoundments [CO (depending on the ground-water classification),PA (metals and VOCs), WV] and five states require annual sampling for landfills [IA (after baseline established), IL (after 5 years), OH(metals, TOC, TDS, chloride, sodium and radionuclides), PA(metals and VOCs), TN (RCRAAppendix VIII constituents)].•Timing of State Regulation Implementation:In the baseline, certain states requiregroundwater monitoring only for newly constructed units. These baseline costs are tracked asfuture baseline cost streams in the cost model. Of the 34 state regulations reviewed, nine states require immediate compliancewithmonitoring requirements for impoundments: LA, MN, MO, ND, NV, NY, OK, SC, UT. Eightstates that only require groundwatermonitoring only at newly constructed surface impoundments: CO, FL, KY, MI, NC, PA,WI, WV. 21 states require immediatecompliance with monitoring requirements for landfills: AL, CO,GA, IA, IN, KS, KY, MI, MN, MT, NC, ND, NY, OH, PA, SC, TN,UT, VA, WA, WY. Ten statesrequire groundwater monitoring only at newly constructed landfills: FL, IL, LA, MS, MO, NV, OK,TX, WV, WI.2. Bottom liner requirements:•Impoundments:Of the 34 state regulations reviewed, 10 states require immediate compliance with liner requirements for surface impoundments:FL(composite), KS (composite), KY (composite), LA (composite),MO (composite), ND (clay or synthetic), NV (composite), NY(composite), OK (composite), and PA (composite). Six states require liners only at newly constructed surface impoundments: CO(clayor soil), MI (clay or composite), NC (composite), WI (composite, synthetic or clay), WV (composite), WY (composite).•Landfills:Of the 34 state regulations reviewed, 19 states require immediate compliance with liner requirements for landfills: AL (composite), CO(clay or synthetic), GA (composite), IN (clay), KS (composite), LA(composite), MI (composite), MN(clay), MT (composite), NC(composite), ND (clay or synthetic), NY (composite), OH (composite),PA (composite), SC (composite or clay), TN (composite), UT(composite), VA (composite), and WA (composite). 10 states requireliners only at newly constructed landfills: FL (composite ordouble), IL (clay or composite), MS composite), MO (composite), NV (composite), OK (composite), TX (composite), WI (composite),WV (composite), WY (composite).3. Leachate collection/detection system requirements:•Impoundments:Of the 34 state regulations reviewed, ninestates require immediate compliance withleachate collection/detection system requirementsfor surface impoundments: FL, KS, KY, LA, MO, ND, NV, NY, PA. Five states require leachate collection/detection systems only atnewly constructed surface impoundments: CO, MI, NC, WV, WI.•Landfills:Of the 34 state regulations reviewed, 18 states require immediate compliance with leachate collection system requirements for landfills:AL, CO, GA, IN (karst areas only), KS, MI, MN, MT, NC, ND, NY, OH, PA, SC,TN, UT, VA, WA. 11 states require leachatecollection systems at newly constructed landfills: FL, IL, LA, MS, MO, NV, OK, TX, WI, WV, WY.464. Dust control requirements: (landfills only)Of the 34 state regulations reviewed, 16 states require immediate compliance with dust control requirements (wetting and truckcoversand/or compaction) for landfills: CO, GA (compaction only), IA,IN, KS, MI, MN (includes compaction), ND (includes compaction),NY,OH, PA, SC, TN, UT, VA, WA. Ninestates require dust controls only at newly constructed landfills: FL, IL (includes compaction), LA,MO, NM, OK, WI, WV, WY (includes compaction).5. Run-on/run-off control requirements: (landfills only)Of the 34 state regulations reviewed, 18 states require immediate compliance with run-on/run-off control requirements for landfills: AL, CO,GA, IA, IN, KS, MD, MN, MT, NC, NY, OH, PA, SC, TN, UT, VA, WA. 11 states requirerun-on/run-off only atnewly constructedlandfills: 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 requirements for surfaceimpoundments: AZ, KY, LA, MN, MO, ND, NM, NV,OK, TN, and UT. Four states requirefinancial assurance requirements only atnewly constructed surface impoundments: CO, MI, NC, WI.•Landfills:Of the 34 state regulations reviewed, 22 states require immediate compliance with financial assurance requirements for landfills: CO,FL (new construction), GA, IA, IN, KS, KY, MI, MN, MO, MT,NC, ND, NY, OH, SC, TN, UT, TX, VA, WA, WY. Eight statesrequire financial assurance requirements only at newly constructed landfills: FL, IL, LA, MS, NV, OK, WI, WV.7. Disposal Unit Location Restrictions (6 categories)State regulations for the top-25 coal usagestates (for electricity) were reviewed back in year 2000 for any location restrictions. Theseregulations were not updated as part of this RIA. The following is a synopsis ofstate government location restrictions on locating CCRsurface impoundments and landfills,according to six categories of location restrictions (water table, floodplains, wetlands, fault areas,seismic zones, unstable karst terrain).•7-1: Below the natural water table:oOf the 25 state regulations reviewed, fivestates have location restrictions belowthe natural water table for surface impoundments:NC (4 feet above seasonal water table),ND (within aquifer), OK (if less than 15 feetabove ground-water table), WV (5 feet aboveground-water table), WY.oOf the 25 state regulations reviewed, eight states have location restrictions below the natural water table for landfills: FL,IA (5 feetabove ground water), MI (4 feet above groundwater), MN (5 feet above ground water), NC (4 feet above seasonal water table), ND(within aquifer), OH (5 feet above water table for wastes with higher leachate concentrations), TN (if less than 5 feet above watertable).•7-2: Floodplains:47oOf the 25 state regulations reviewed, eightstates have location restrictions in floodplains for surface impoundments: KS (underpermit), KY, MO (if closed with waste in place), NC, ND, OK (if dike notat least 1 foot above 100-year flood elevation), PA, WV.oOf the 25 state regulations reviewed, 20 states have location restrictions in floodplains for landfills: AZ, CO, FL, IL, IN, IA, KS, KY,MI, MN, MO, NC, ND, OH,OK, PA, TN, WV, WI, WY.•7-3: WetlandsoOf the 25 state regulations reviewed, five states have location restrictions in wetlands forsurface impoundments: KY, MO (if closedwith waste in place), ND, PA, WV.oOf the 25 state regulations reviewed, 17 states that have location restrictions in wetlands for landfills include AZ, CO, FL, IL, IN, IA,KY, MI, MN, MO, ND, OK,PA, TN, WV, WI, WY.•7-4: Fault areas:oOf the 25 state regulations reviewed, two states have location restrictions in faultareas for surface impoundments: MO (if closed withwaste in place), WV.oOf the 25 state regulations reviewed, sevenstates have location restrictions in fault areas for landfills: AZ, CO, MO, OH, TN,WVand WI.•7-5: Seismic zones:oOf the 25 state regulations reviewed, two states have location restrictions in seismic impact areas for surface impoundments: includeMO (if closed with waste in place), WV.oOf the 25 state regulations reviewed, eight states have location restrictions in seismic impact areas for landfills: AZ, CO, IL, MO, OK(if within 5 miles of epicenterof 4.0 earthquakes), TN, WV, WI.•7-6: Karst areas:oOf the 25 state regulations reviewed, fivestates have location restrictions in unstable areas for surface impoundments: KY, MO(ifclosed with waste in place), ND,PA, WV (1,000 feet away).oOf the 25 state regulations reviewed, 12 states have location restrictions in unstable areas for landfills: AZ, CO, IN, IA, KY,MN,MO, ND, PA, TN, WV (1,000 feet away), WI.8. Closure cap controls•Of the 34 state regulations reviewed, ninestates require immediate compliance withclosure control requirements for surfaceimpoundments: AZ (synthetic cap), KY (synthetic cap), LA (clay cap), MO(soil cap), ND (clay or synthetic cap), NM (syntheticcap), OK (clay or synthetic cap), PA (clay or synthetic), TN (synthetic cap). Four states requireclosure controls only at newlyconstructed surface impoundments: CO (clay orsynthetic cap), MI (clayor synthetic cap), NC (soil cap), WI (synthetic cap).•Of the 34 state regulations reviewed, 23 states require immediate compliance with closure control requirements for landfills: AL(synthetic cap), CO (clay cap), GA (soil cap), IA (clay cap), IN (clay cap), KS (soilcap), KY, MD (clay cap), MI (clay or syntheticcap), MN (clay cap), MO (soil cap), MT(clay cap), NC (soil cap), ND (clay or synthetic cap), NY (synthetic cap), OH (syntheticcap), PA (synthetic cap), SC (synthetic cap), TN (clay cap), TX(synthetic cap), UT (soil cap),VA (synthetic cap), and WA (syntheticcap). Nine states require closure controlsonly at newly constructed landfills: FL (synthetic cap),IL (clay or synthetic cap),LA (claycap), MS (soil cap), NV (soil cap), OK (clay cap), WI (clay cap), WV (soil or clay cap), WY (synthetic cap).489. Post-closure monitoring requirements•Of the 34 state regulations reviewed, 11 states require immediate compliance with post-closure groundwater monitoring requirement forsurface impoundments: AZ, LA, MO, ND, NM,NV, NY, OK, SC, TN, UT. Seven statesrequire post-closure groundwater monitoringonly at newly constructed surface impoundments: CO, KY, MI, NC, PA, WI, WV.•Of the 34 states reviewed, 22 states require immediate compliance withpost-closure groundwater monitoring requirements for landfills:AL, CO, GA, IA, KS, KY, MD, MI, MN, MO, MT, ND, NY, OH, PA, SC, TN, TX, UT, VA, WA, WY. Eight states require post-closuregroundwater monitoring at newly constructed landfills: FL, IL, LA, MS, NV, OK, WI, WV.10. Baseline storage tank/containerdesign and operating standardsThe baseline storage tank /container design and operating standards were not evaluated in this RIA because of a lack of data about the baselinecount and conditions of CCR storage or treatment tanks, containers, and containmentbuildings at electric utility plants•Industry Baseline CCR DisposalCharacterization FindingsAppendix Fof this RIA presents on a plant-by-plantbasis the baseline engineering controls assumed for eachof the 383 of the 495 electricutility plants which onsite dispose CCR (84plants solely dispose CCR offsite; this RIA assumes that all offsite CCR disposal units are landfills,and further assumes that all of those offsite landfills currentlycomply with the engineering controls described in this RIA for the regulatoryoptions).Exhibits 3I(for landfills) andExhibit 3J(for impoundments) below summarize the assignment of baseline conditions in this RIAfor these 411 plants which dispose CCR onsite.49Exhibit 3IBaseline Compliance withState Government EngineeringControl Requirements: CCR LandfillsABCDEFGHFuture new CCR landfillsExisting CCR landfillsCurrent or State RegulatedEngineering controlNo. ofPlantsPercent of311 plantswith LFsVolume ofCCR diposedin landfills(tons/year)% of 71.8million tonsonsite + offsiteLFNo. ofPlantsPercent of311 plantswith LFsVolume ofCCR disposedin landfills(tons/year)% of 71.8 milliontons onsite +offsite LF1. Groundwater Monitoring 302 97%* 69,706,646 97%* 272 81% 60,623,231 85%2. Bottom Liner 302 97%* 69,706,646 97%* 238 71% 52,505,314 73%3. Leachate Collection System 273 81% 62,696,310 88% 222 66% 49,213,424 69%4. Dust Controls 215 64% 40,634,681 57% 205 61% 42,781,444 60%5. Run on/Run off Controls 261 77% 60,342,426 84% 209 62% 46,232,440 65%6. Financial Assurance 266 79% 56,861,231 79% 231 69% 49,487,222 69%7. Site restrictins 1. Water table 98 29% 18,878,963 26% ND ND ND ND2. Floodplains 232 69% 50,072,235 70% ND ND ND ND3. Wetlands 199 59% 40,227,659 56% ND ND ND ND4. Fault areas 72 21% 18,816,363 26% ND ND ND ND5. Seismic zone 66 20% 13,056,165 18% ND ND ND ND6. Karst areas 152 45% 33,970,045 47% ND ND ND ND8. Cap Synthetic or Clay 245 73% 52,234,482 73% 213 63% 46,031,621 64%Soil 48 14% 10,990,166 15% 50 15% 12,094,140 17%Clay/Soil 13 4% 5,419,918 8% 5 1% 3,022,219 4%9. Post Closure Monitoring 271 80% 61,444,140 86% 232 69% 53,249,880 74%10. Storage design standards ND ND ND ND ND ND ND NDNotes:ND = Not determined. Comparisons have not been made comparing the date the statesite restriction regulation became effectiveand the date of existing landfillconstruction for each plant.* According to the August 2006DOE/EPA report “Coal CombustionWaste Management at Landfillsand Surface Impoundments, 1994-2004” report nr. DOE/PI0004, 286 pp; http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=2008:• 97% of newly constructed CCR landfills have groundwater monitoring (Table 14, p.35)• 97% of newly constructed CCR landfills have liners (Table 13, p.33)These percentages reflect a mix of state government permit requirements for some surveyed electricity plants, plus industry voluntary actions for other plants.50Exhibit 3JBaseline Compliance with State Government Engineering Control Requirements: CCR Surface ImpoundmentsABCDEFGHFuture new CCR impoundmentsExisting CCR impoundmentsCurrent or State RegulatedEngineering controlNo. ofPlantsPercent of158 plantswith SIsVolume of CCRdisposed inimpoundments(tons/year)% of 22.4million tonsCCR disposedinimpoundmentsNo. ofPlantsPercent of158 plantswith SIsVolume ofCCR disposedinimpoundments(tons/year)% of 22.4million tonsCCR disposedinimpoundments1. Groundwater Monitoring 123 78%* 17,472,000 78%* 78 49% 9,216,470 41%2. Bottom Liner 158 100%* 22,400,000 100%* 62 39% 6,920,820 31%3. Leachate Collection System 61 39%7,676,710 34% 48 30% 5,338,110 24%4. Dust control NA NA NA NA NA NA NA NA5. Runon/runoff control NA NA NA NA NA NA NA NA6. Financial Assurance 63 40% 7,694,010 34% 58 37% 7,327,410 33%7. Site restrictns 1. Water table 28 18% 3,039,860 14% ND ND ND ND2. Floodplains 51 32% 6,902,610 31% ND ND ND ND3. Wetlands 34 22% 5,347,550 24% ND ND ND ND4. Fault areas 15 9% 1,675,350 7% ND ND ND ND5. Seismic zone 15 9% 1,675,350 7% ND ND ND ND6. Karst areas 34 22% 5,347,550 24% ND ND ND ND8. Cap Synthetic 38 24% 5,911,760 26% 31 20% 4,298,660 19%Soil 27 17% 2,490,050 11% 23 15% 2,293,550 10%Clay 3 2% 254,800 1% 3 2% 254,800 1%9. Post Closure Monitoring 78 49% 9,520,360 43% 65 41% 7,181,760 32%10. Storage design standards ND ND ND ND ND ND ND NDNotes:NA = Not applicable to surface impoundments.ND = Not determined. Comparisons have not been made comparing the date the statesite restriction regulation became effectiveand the date of existing surfaceimpoundment construction for each plant.* According to the August 2006DOE/EPA report “Coal CombustionWaste Management at Landfillsand Surface Impoundments, 1994-2004” report nr. DOE/PI0004, 286 pages; http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=2008:• 78% of newly constructed CCR impoundments have groundwater monitoring (Table 14, p.35)• 100% of newly constructed CCR impoundments have liners (Table 13, p.33)These percentages reflect a mix of state government permit requirements for some surveyed electricity plants, plus industry voluntary actions for other plants.51•Baseline CCR Disposal Cost EstimationThis section presents baseline cost estimates for both onsiteand offsite CCR disposal units(i.e., landfills and impoundments)for 467 of the 495electric 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 decreasingrelative degrees of expected accuracy):oData-based estimates: Based on a landfill and impoundment engineering controls cost estimation model using relativelyrobust and recent data inputs(e.g., 2005 or newer) pertaining to CCR quantities and disposal methods for individualelectric utility plants. The cost model was first developed by EPA in 1988 to support EPA’s 1991 final criteria formunicipal solid waste RCRA Subtitle D landfills, and EPA’s1999 proposed rule cement kiln dust landfill requirements.45The cost model consists of two software components;Appendix Gto this RIA provides additional details about themodel:1stof 2 cost model components: Unit Cost Component: The first component is a Fortran computer programmedcost model which dates back to 1988. This model specifies the various steps andphysical units (e.g., squarefootage sizes and associated quantities of labor, equipment and materials for the specified sizes) involved indesigning, constructing, operating, andclosing a landfill or impoundment.Then it combines the physicalcomponent data inputs, with input dataon the prices/ costs/ fees for the physical components to estimate as modeloutputs, the capital and annual O&M costs of specified sizes of landfillsand impoundments. The unit prices/costs/fees used as input data includea wide range of items, such as the per-acre cost of land,clearing, excavation,equipment, labor, bottom liner materials, and cover materials. For this RIA, the model was run multiple times togenerate individual cost estimates for a series of five alternatively-sized CCR landfills and impoundments withvarying types of engineeringcontrols to represent the range of sizes and engineering controlsin the population of495 electric utility plants. The size categories are defined in tons per day of CCR disposed. Each CCR landfill or45The 1988 cost model is documented in the “User’s Manual for the Subtitle D Municipal Landfill Cost Model” draft report prepared for EPA’s Office of Solid Waste byDPRA Inc, Sept 1988, 129 pages which is available from theFederal docket as document ID nr EPA-HQ-RCRA-2006-0796.EPA previously publicly referenced this cost model in the following six publications: (a) “DraftRegulatory Impact Analysis for Proposed Revisions to Subtitle DCriteria for Municipal Solid Waste Landfills,” prepared for US EPA Office of Solid Waste by Temple, Barker & Sloane, Inc., ICFIncorporated, Pope-Reid Associates (nowDPRA Inc.) and American Management Systems, Inc., 05 Aug 1988 (this document includes about a 4-page summary of the cost model); (b) “Regulatory Impact Analysisfor the Final Criteria for Municipal Solid Waste Landfills,” prepared for US EPA Office of Solid Waste by Temple, Barker & Sloane/Clayton Environmental Consultants,ICF Inc, DPRA Inc, and American Management Systems, Inc., Dec 1990 (this document includes about a 4-page summary of the cost model); (c) “Addendum to theRegulatory Impact Analysis for the Final Criteria for MunicipalSolid Waste Landfills,” preparedfor US EPA, Office of Solid Waste by Temple, Barker & Sloane/ClaytonEnvironmental Consultants and ICF Inc, August 1991; (d) “40 CFRParts 257 and 258 Solid Waste Disposal Facility Criteria: Proposed Rule,” Federal Register,Vol.53,No.168, pp.33314-33422, 30 Aug 1988; (e) “Revised Criteria for Municipal Solid Waste Landfills,” Federal Register Volume 56, pp. 50978, 09 Oct 1991; (f) “TechnicalBackground Document: Compliance Cost Estimated for the Proposed Land Management Regulation of Cement Kiln Dust,” prepared for the US EPA, Office of SolidWaste by DPRA Inc, 10 April 1998.; and (g) “40 CFR Parts 259, 261, 266, and 270 Standards for the Management of Cement Kiln Dust; Proposed Rule,” Federal RegisterVol.64, No.161, pp. 45632-45697, 20 Aug 1999.52impoundment is assumed to operate 300 days per year (average number of operating days for coal-fired boilersbased on 2005 DOE EIA 767 database). The size categories are 10,000, 50,000, 200,000, 500,000 and 2,000,000tons of CCR per year. Size is the primary determinant of overall cost; however, landfills and impoundmentsexhibit increasing returns to scale: the larger the landfill or impoundment, the lowerthe cost per ton of CCRmanaged. The cost equations generated by these unit costmodel runs are used as inputs in the second componentof the cost model to compute landfill and impoundment costcurves (equations) based on size for each combinationof engineering controls, so that a unique cost estimate may be assigned to each of the 495 electric utility plantsaccording to each plant’s uniqueannual CCR disposal tonnage.2ndof 2 cost model components: Plant-by-Plant & Aggregate Cost Component: The second component of themodel is an Excel spreadsheet with Visual Basic programming used to estimate unique baseline (i.e., current) andregulatory option costs for each electric utility plant.The spreadsheet is populated with plant-by-plant dataincluding plant location, known disposaland beneficial reuse practices, known or estimated baseline engineeringcontrols on CCR disposal units, annual CCR disposaltonnages, and known or estimated CCR landfill andimpoundment future closure years. Thespreadsheet is also populated with thecost equations generated by the firstcomponent of the model for the various engineering controls (e.g., groundwater monitoring and safety inspections)and for off-site landfill disposal costs. The Visual Basicprogramming is used for this RIA to estimate engineeringcontrol costs for both the (a) baseline and (b) regulatoryoptions for each plant over a 50-year future period-ofanalysis (i.e., 2012 to 2061). The plant-by-plant estimated costs are then aggregated in this second component ofthe model on an average annualized basis.oAssumption-based estimates: These are based on relatively limited data, and/or older data (e.g., older than 2005), or metaanalysis transfer of results from other studies, or data from case studies, or based mostly on professional judgmentassumptions rather than data, for some ofthe major factors used in cost calculations.oScenario-based estimates: These are applied in absence of data, case studies, or assumptions for purpose of illustratingpotential lower- and upper-bound costs (i.e., bounding estimates). EPA defines “scenarios” as qualitative projections ofpossible future conditions based on variations in key drivers of change, including social, technological, economic andinstitutional drivers. Scenarioconstruction is a futures analysis method; as such, scenario-based estimates do not strive topredict the future with absolute certainty, but to exploreuncertainties, possible consequences, and possible outcomes.46•2009 price level: Costs are normalized tobeginning-of-year 2009dollars using inflation factors developed by Engineering NewsRecord (ENR) Construction Cost Index,and using regional cost adjustment factors applied to each plant costestimate involving on-site construction. These regional factors account for the variability between states in site workand landscape construction costs. Cost adjustment factors are derived from the Means Building Construction CostsYear 2003 city factors. All the cities for each state were averaged together to derive a state average.46“Source: EPA Office of Science Policy, “Shaping Our Environmental Future: Foresight inthe Office of Research & Development,”report nr. EPA 600/R-06/150, 2006at: http://www.epa.gov/osp/futures/FuturesHandbook.pdf53•Before-tax costs: Baseline disposal costs estimated on a before-tax basis to approximate theoverall economic cost (i.e., real resourceallocation for the economy as a whole,rather than on an after-tax basis which would approximate a relatively narrowerfinancial cost to the electric utility industry because after-tax costs subtract business expense tax deductions anddepreciation of capitalexpenditures for pollutioncontrol equipment.•50-year period: A 50-year future time horizon (aka period-of-analysis) was appliedbecause new construction for replacement of allCCR disposal units and end of existing lifespan is estimated to have occurred at least once by that time.•7% discount rate: A 7% discount rate was applied for calculating both net present value cost and average annualized cost fortheengineering control unit costs applied in this RIA.Because both the annualized baseline cost and annualizedincremental proposed rule costs estimated in this RIA consist of primarily (i.e., >95%) industry cost rather thangovernment cost, this RIA applies a 7%discount rate rather than a lower (e.g.,3%, 2%, 1% or 0%)discount rate torepresent the opportunity cost of business capital investment and business expense financing (i.e., the average rate ofreturn to corporate capital). This isconsistent with OMB’s 2003 Circular A-447(page 33) and 1992 Circular A-9448(page 8) which indicate thata 7% discount rate base-case should be usedfor regulatory analyses when regulation isexpected to primarily and directlyaffect businesses and industries.•0.73% growth: Baseline cost estimates increased 0.73% per year over the 50-year future time horizon toreflect a 0.73% annualgrowth in coal consumption at electric utility plants (whichis a proxy for future annual growth in the annual tonnage ofCCR generation needing disposal from those plants). The0.73% annual growth factor isbased on DOE-EIA's January2009 "Annual Energy Outlook 2009" forecast change in US coalconsumption for electricity generation between year2010 (22.91 quadrillion Btus) and 2030 (26.41quadrillion Btus), available at:http://www.eia.doe.gov/oiaf/aeo/index.html•Beneficial use: If reported in the baseline by any particular plant, beneficial usewas assumed to continue in the future bythat plantunder the baseline projection over the 50-year future period-of-analysis. Section 5C inChapter 5of this RIAevaluates potential changes to thisbeneficial use baseline under alternative regulatory impact scenarios.•Offsite disposal: If reported in baselineby any particular plant, offsite disposalwas assumed to continue in the future bythat plant.Offsite disposal landfill cost estimated under both baselineand regulatory options using the engineering control costmodel. Truck operating cost estimatedseparately outside of the model.•Existing unit closure: One set of years for the opening and closure of disposal units are assumed for each facility. If datafor initial year ofoperation were provided in the 1995 EPRIComanagement Survey, these data wereused. If the plant had more than472003 OMB Circular A-4: http://www.whitehouse.gov/omb/circulars_a004_a-4/481992 OMB Circular A-94: http://www.whitehouse.gov/omb/circulars_a094/54one disposal unit and more than one reported date for initial year of operation, the years were averaged. For example,if a facility had three disposal units (2 landfills and 1 impoundment) with installation dates of 1970, 1980, and 1990,this RIA assumed the installation date of all the units was1980. This assumption simplified the cost calculations on aper facility basis instead of aper disposal unit basis. If no disposal unit installation data were available, the installationyear is assumed to be equal to the earliest boiler installation year reported in either the 2007 EIA 860 database for thatplant or 1998 EIA 767 database, whicheverwas older. If no disposal unit orboiler installation year data wereavailable, an installation year of 1980 was assumed. If the 1995 EPRI Comanagement Survey provided a forecastedclosure year for a unit, new unit installation is assumed to occur in that year. Otherwise, if no closure forecast year isprovided, closure is assumed to occur 40years after the year of installation(assumed average lifespan for CCR landfillsand impoundments).•New unit construction: The timing of whenbaseline state regulatory requirements for newly constructed units begin to be incurred dependson the installation and closure date for the existing disposalunits. Baseline state regulatory cost requirements areincurred at the closure date of the disposal unit when new unit construction occurs. For example, if a plant’s disposalunit is assumed in this RIA to close in 2019; new unit construction costs required under state regulations are incurredover its assumed 40-year future lifespan beginning in 2020.•New landfills: The most economic of three landfill options –(1) combination landfill with 50% of waste belowground and 50% above ground, (2) pilelandfill with 5 % of waste belowground and 95% above ground, or (3)offsite landfill -- is determined withinthe cost model. The cost for the most economical approach is assigned tothat plant unless available data specify otherwise. The choice isdependent upon on estimated engineeringcontrol costs and annual CCR disposal tonnage.•New impoundments: If currently used as a disposal unit, this RIA assumes a landfill will be constructed as thefuture new disposal unit as impoundments reach end of lifespan, because the model calculates that new landfillsare more economical to construct for two cost reasons: (a) if no pre-existing land depressions for use as a newimpoundment, the cost for a larger excavation for a newimpoundment rather than a smaller excavation for alandfill is necessary, and (b) the primary determinant of manyof the cost for engineering controls is the footprintof the disposal unit such that thesame set of engineering controlsfor a new impoundment would be moreexpensive than for a new landfill. However, the cost model does not estimate the associated capital and annualO&M costs for future conversion ofexisting wet ash and wet scrubberboilers and conversion of wet CCRconveyance equipment used for moving CCR to disposal units. These conversion costs are estimated separatelyoutside of the cost model in this RIA.55•Baseline “Engineering Control” Cost Estimates1. Baseline ground water monitoringGroundwater monitoring costs are based on theRemedial Action Cost Engineering and Requirements (RACER) cost estimating software(2002) with costs based on the R.S. Means, Environmental Cost Handling Options and Solutions (ECHOS), Environmental RemediationCostData (2002).Assumes same groundwater monitoring requirements for both landfills and impoundmentsPoint of compliance:Placement at the unit boundary is assumed in the cost estimates. Unit boundary point-of-compliance monitoring complies with the “within150 meter point-of-compliance” criterion.Plants monitoring at the unit boundary will incur no additional costs under the within 150 meterplacement criteria.Number of wells:EPA’s March 1985 “Ground Water Technical Enforcement Guidance” Document (pages 2-8 to 2-16) recommends a maximum of 150 feetspacing between down-gradient wells. EPA’s December 1980 SW-611“Procedures Manual for GroundwaterMonitoring at Solid WasteDisposal Facilities” (pages 40 to 43) recommends a maximum of 250 feet spacing betweendown-gradient wells. Assuming the technicaldocuments are the most stringent and thestate regulation minimums are the least stringent, a middle ground within the range isanticipatedand used in the cost estimates. This RIA does not evaluatethe cost differences between theupper and lower bounds of well spacing.Groundwater monitoring well costs in this analysis assume a minimum of 2 down-gradient wells for the first 800 feet of length along twosides of the landfill or impoundmentunit, which is assumed to be square, plus additional wells spaced every 400 feet. In addition, one upgradient well is assumed.Constituents:The cost estimates include monitoring for the following chemicalindicators and metals, which represents a reasonable “likely-case”scenario between indicators only and RCRA 40 CFR 261 Appendix VIII constituent monitoring which includes about 500 chemicalsubstances:oChemical indicators: Based on EPA’s 1999 cement kiln dust proposed rule parameters(i.e., pH, conductivity, total dissolved solids,potassium, chloride, sodium, and sulfate) as a cost proxy.oMetals: Metals with primary and secondary Maximum Contaminant Levels (MCLs) (i.e., Al, Cu, Fe,Mn, Ag, Zn, Sb, As, Ba, Be, Cd,Cr, Pb, Hg, Se, Tl).Frequency:The cost estimates only include semi-annual sampling (most-likely case) analogous to EPA’s 1999 cement kiln dust proposed ruleand tomany current state regulations, even if somestates require a quarterly or annual basis.Unitized cost estimate: Dividing the average annual cost estimate result displayed inExhibit 3Lbelow (row item 1) for baseline groundwater monitoring, by the count of electric utility plants estimated inExhibit 3I(row 1, column A) andExhibit 3J(row 1, column A) aboveto conduct that activity under state governmentrequirements, yields an average annualper-plant (i.e., unitized) cost estimateof $64,000. Incomparison, EPA’s most recent (2008) Information CollectionRequest (ICR) No. 0959.13 “Ground-Water Monitoring Requirements”(renewal) for the RCRA Subtitle C 40 CFR 264.92 and 265.92 TSDF “ground-water protection standard” provides an estimate of $28,13056per year.49The $64,000 unitized cost for groundwater monitoring generated bythe above assumptions appliedin the engineering controlcost model used for this RIA is 2.3 times larger and more appropriate to this RIA because it reflects a larger number of wellsper-plant tomonitor the groundwater under the larger sized CCR disposal units compared to the average sizes of other types of industrial waste disposalunits.2. Baseline bottom linersSame bottom liner requirements for both new landfills and new impoundmentsThe cost estimates include a composite (2-foot compacted clay-synthetic) liner for the more stringent design anda 2-foot compacted clayliner, single-synthetic liner, and a 2-foot compacted ash liner for less stringent baseline designs.3. Baseline leachate collection systemNo leachate collection is assumedfrom beneath the impoundment linerThe cost estimate is comprised of perforated pipes spaced approximately 300 feet apart along the base of the unit. It includesa wet well forleachate 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 controlsCost estimate includes CCR compaction equipment, water trucksfor spraying CCR during compaction and for spraying unpaved landfill roads,and covers for landfill trucks:Compaction EquipmentAsh is assumed to be compacted in the waste management area byself-propelled rollers for regulatory scenarios including dust controls. Amodel cost assumption is that four passesare made by the roller in 6-inch lifts. With these assumptions, the roller can compactapproximately 1,300 cy of ash per day. The operating life of purchased compaction equipment is assumed to be five years. The number ofsheepsfoot rollers required is estimated as follows:Rollers = (tons/yr)(2,000lb/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 dust. A modelassumption isthat FFC plants currently use water trucks50% of the operational day tocontrol dust on roads (seeWater Spray on Roads). It is reasonable to49$28,130 per year per-facility average cost derived for purpose ofthis RIA by dividing the reported $27.818 million annual cost by the reported 989 TSDFs from the EPAICR 0959.13, Federal Register, Vol.73, No.103, page 30617; 28 May 2008; http://edocket.access.gpo.gov/2008/pdf/E8-11888.pdf57assume that the same water trucks will beused for the roads and the ash management unit. Therefore, it is assumed that an existing water truckis available for compaction 50% of the operational day. Additional water trucks are assumed to be necessary to facilitate compaction for largefacilities. The cost of tarps, tarp mechanisms, and installationof the mechanisms, as well as the life of each tarp were estimated by ICF in “CostFunctions for Alternative CKD Control Technologies” (Draft), 19 July 1996. A model assumption is that a water truck will be necessary forcompaction 50% of the time required by the compaction equipment.The water truck time for compaction is estimated as follows:Water Truck Time for Compaction = (tons/yr)(2,000 lb/ton)(16.02 kg/m3/ lb/cf)(8 hr/day)(0.5)(1,190 kg/m3)(27 cf/cy)(1,300 cy/day)One existing water truck for compaction andwater spray on roads is estimated to be sufficient for plants managing less than 391,000 tons peryear of ash. Facilities managing between 391,000 and 1,173,000 tons per year are assumed to purchase one additional water truck. Facilitiesmanaging between 1,173,000 and 1,955,000 tons per year are assumed topurchase two additional water trucks. Facilities managingmore than1,955,000 tons per year to the maximum facility size modeled of2,000,000 tons per year are assumed to purchase three additional water trucks.The cost of a water truck is assumed tobe $101,000 in 1995 dollars. The water truck operating life is assumed to be five years. The operatingcosts for water spray for compaction are estimated assuming thatthe truck travels approximately five miles per day, for each day used, with afuel consumption of five miles per gallonat a fuel cost of $1.15 per gallon. The truck is assumed to operate 50% of the hoursrequired forcompaction. The daily water volume used isassumed to be 10,000 gallons, at a cost of $2 per 1,000 gallons. The annual cost associated withash management is estimated as follows:Annual Cost = (tons/yr)(2,000lb/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 for this dust controltechnology include the cost of the roll-on tarp mechanism and the installation of thismechanism. Capital costs for covers ontrucks areestimated 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 Control Technologies”(Draft), dated July 19, 1996.(1,190 kg/m3)(0.80)(27 cf/cy)(9 cy/load)(2,400 hr/yr)Annual costs for this dust control technology include the cost of the tarps and the cost toreplace the tarps. Tarps are estimated to be replacedevery 150 loads. Replacement of a tarp isestimated to require 15 minutes. Annual costs for covers on trucks are estimated as follows:Annual Cost = (tons/yr)(2,000 lb/ton)(16.02 kg/m3 / lb/cf)($155/tarp + 0.25hr/tarp*$19/hr)(1,190 kg/m3)(0.80)(27 cf/cy)(9cy/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 assumption is thatFFC plantscurrently have water trucks and use waterspray on roads as a baseline management practice. A model assumption is that dust control isrequired for a road length of 1.5 miles (3 miles roundtrip), witha road width of 10 meters. Thewater truck capacity is assumed to be 5,000gallons and requires approximately one hour tofill. The water truck can spray a width offive meters at an assumed speed of 10miles per hour.For the baseline scenario, a model assumptionis that the entire water volume (5,000 gallons) will be sprayed on each pass of the truck alongone side of the road (i.e., 1.5 miles x 5 meters). The resulting water volume per road area,averaged over the 1.25 hours required to spray the58road and refill the truck, is approximately 2.5 times that of the average hourly daytime evaporation rate. Therefore, water spray on roads will berequired 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/m2The time required for the water truck to befilled, spray along both sides of the road,and return for refilling is estimated as follows:Time = (1 hour) + (3 miles)/(10 miles/hour) = 1.3 hourTherefore, the total time for one pass is assumed to be 1 hourand 15 minutes. The average rateof water spray is estimated asfollows: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 rateis approximately 0.25 mm/hr. Therefore, the water spray rate is approximately 2.5 times theevaporation rate. Since the total time required for water spray (1.25 hour) times 2.5 is approximately 3, a model assumption isthat water sprayon roads is required approximately every 3 hours. In order to coordinate the water truck use for road spray and ash compaction,it is assumedthat the truck alternatesbetween these two requirements during the day. Therefore, over a nine-hour day (eight working hours plus one hour forlunch), roads are sprayed 3 times, requiring a total of approximately 4 hours, or 50% of the operational day. Because it is assumed that FFCfacilities currently spray water on roads for dust control, the incremental cost from the baseline to the compliance scenariosis zero.5. Baseline rain and surface water run-on/run-off controls (landfills only)The cost estimates assume that stormwater run-on/run-off control is comprised of a ditch surrounding active area of landfill and an excavatedbermed basin for water collection.6. Baseline financial assurance for CCR disposal unit closure and post-closure careFinancial assurance helps assure that theowners and operators of CCR landfills andimpoundments have adequately planned for the future costof closure, post-closure care, and corrective action for known releases, and to assurethat adequate funds will be available when needed to coverthese costs if the owner or operator is unwilling or unable to do so. Financial assurance helps protect future generations from paying fordamages caused by or the prevention of damages potentially created from current wastemanagement activities. Requiring provision offinancial assurance during operation of landfills and impoundments places the cost burden on the current owner and consumer, and preventscosts from being passed from the current generation to future generations.The cost estimate includes the costs for selecting a financial mechanism, establishing a financial test, and establishing a letter of credit.The differences between RCRA Subtitle C and Subtitle D financialassurance mechanisms are not assessed. This RIA assumes the samerequirements for both landfills and impoundments:•Capital cost includes selection of financial assurance mechanism, establishment of financial test, and establishment of letterof credit.The letter of credit is assumed to be most available to utilities and will be utilized in most circumstances. This is amortized in the annualcost.•Annual cost includes maintenance of financial test and maintenance of letter of credit. Establishment andannual maintenance of theletter of credit is estimated tobe 1% to 3% of the nominal value of the letterof credit (i.e., total cost of closure and postclosure). This RIAapplied the 2% midpoint of this range. Implementation costs are estimated on the assumption that an outside consulting firm and legalassistance will assist in obtaining and maintaining the letter of credit ($692 per year in 1995 dollars or $1,051 per year inflated to 2009dollars). Estimate obtained from Mohammad Iqbal and John Collier,ICF, Inc., “Local Government Financial Test Economic Analysis,”59memorandum to George Garland, EPA, 30 April 1995. Additional supporting information obtained fromEPA “Estimating Costs for theEconomic Benefits of RCRA Noncompliance,” September 1997.7. Baseline disposal unit location restrictionsBaseline cost not estimated in this RIA.8. Baseline closure capping to cover unitThe cost estimate for this engineering control does not include the closure plan costor closure certification costs. Cappingcosts are a largecapital expense. So, if a unit isexpected to close inone year the total capping cost is assigned to the last year in the life of the unit. However,businesses are likely to borrow money from a bank for these large capital costs and annualize themover a set period of time, for example, 10 or20 years. Incremental cost estimates in the cost model are overestimated for large capital expenditures applied to existing units that have beenadded over short time periods. In addition,owners are likely toclose these units prior to the proposed rule coming into effect if promulgated asa final rule. This RIA assumes the samerequirements for both landfills and impoundments:Synthetic cap with drainage layer is comprised of a 60 mil HDPE synthetic liner, 1 foot sand, filter fabric, 1.5 foot slope andearth fill, 0.5foot topsoil, and vegetation.It includes a perforatedpipe for drainage collection.Synthetic cap without drainagelayer is comprised of a 60 mil HDPE synthetic liner, 1.5 foot slope andearth fill, 0.5 foot topsoil, andvegetation.Clay cap is comprised of 2 feet of off-site clay, 0.5 foot topsoil, and vegetation.Cover costs would be lower if on-site clayis available.Soil/clay cover is comprised of 0.5 foot clay, 0.5 foot earthfill, and 0.5 foot topsoil, and vegetation. Cover costs would belower if on-siteclay is available.Soil cap is comprised of a 1.5 foot slope and earth fill, 0.5 foot topsoil, and vegetation. The slope of the cap is assumed tobe 0.02:1 (rise:run)with a cover toe slope of 4:1 (run:rise).9. Baseline post-closure groundwater monitoring requirementsSame requirements for both landfills and impoundmentsBaseline post-closure monitoring is assumed to comprise 30 years of groundwater monitoring and surface water monitoring on a semi-annualbasis. The physical parameters (i.e., pointof compliance, number of wells, sets of chemical indicators and sets of chemical constituentsmonitored, and semi-annual frequency) and unit cost are assumed identical as definedin the baseline groundwater monitoring cost item 1above in this section of the RIA.However, post-closure monitoring costs are estimated in this RIA assuming an annual sum is placed in a fund by affected entities (i.e., electricutility owners) during the assumed average 40-year operating lifeof the CCR disposal unit. At the time of closure sufficientmonies will beavailable in the fund to cover post-closure monitoring for the next 30 years beyond end-of-lifespan, assuming an annual interest rate of 7%.10. Baseline storage tank/containerdesign and operating standardsBaseline cost not estimated in this RIA60•Baseline “Ancillary Costs” Estimates11. Baseline offsite disposalThe baseline cost for engineering controlsat offsite CCR disposal sites (assumed in this RIA to be commercial Subtitle D landfills) is estimatedusing the same cost model as the engineering controls for onsite disposal units. In addition, the offsite disposal baseline cost includes the costfor truck transport from the electric utility plant to the offsite landfill, calculated as follows:Baseline Assumptions:o12% (15 million tons/year) CCR currently trucked offsite to non-haz LFs (2005)o6 miles average one-way trucking distance to offsite LFs50o$0.10/ton/mile non-haz waste truck operating costo12 tons CCR per full truckload (source: Gambrills MD case study); (15 million tons/year) / (12 tons/load) = 1.25 million truckloadsper yearBaseline Cost Calculations:oManifest cost: $0oTrucking cost: (15 million tons/year) x (6 miles) x ($0.10/ton/mile truck operating cost for non hazmat) = $9.0 million/year12. Baseline structural integrity inspectionsAssumptions:Baseline assumption is that 82% of CCR disposal units at electric utilityplants are inspected (source:page 36 of joint DOE/EPA report “CoalCombustion Waste Management at Landfills and SurfaceImpoundments, 1994-2004”, report nr. DOE/PI-0004, Aug 2006 at:http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=2008). Per-plant cost for inspections estimated inExhibit 3Kbelow.Cost Calculation:Industry cost: ($10,829/year per facility) x (82% inspected) x (495 plants) = $4.40 million per yearState government cost: ($599/year per facility) x (82%inspected) x (495 plants) = $0.24 million per yearTotal (industry + state) = $4.64 million per year50Source: based on actual distance reported for a MD plant at http://www.rachel.org/en/node/445). Note: a broader range of 2.4miles to 25 miles in one-way offsite landfilldistance was reported by an OH plant at http://www.columbusdispatch.com/live/content/local_news/stories/2008/04/14/Powerfills.ART_ART_04-14-08_B1_FF9TI0U.html?sid=101, and a WI plant, respectively athttp://www.lacrossetribune.com/articles/2007/09/21/news/03landfill0921.txt61Exhibit 3KSummary of Industry & State Government Labor Costs for MSHASurface Impoundment Safety Plan & Annual Inspections& Estimate of Annual Costs for SimilarStructural Integrity Activities for Electric Utility Plant Surface ImpoundmentsItemPaperwork Burden Element*Labor hoursCost (2006)Cost per facilityAnnualizedIndustry Costs1 Impoundment Safety Plan prepared by mining company engineer>>> Purpose: To evaluate geotechnical, hydrologic, hydraulic & otherengineering factors to construct or improve surface impoundment structures toavoid structural failures1,300 $70.07/hr $91,091 $9,1092 Revisions to Impoundment Safety Plan prepared by mining company engineer240 $70.07/hr $2,803 $2803 Fire Extinguishing Plan prepared by mining company engineer or supervisor 20 $70.07/hr $1,401 $1404 Annual Status Report & Annual Certification prepared by company engineer>>> Purpose: To determine whether impoundments are operated and maintainedaccording to approved engineering safety plan2 $70.07/hr $140 $145 Recordkeeping and weekly inspections3>>> Purpose: To determine whether anysigns of instabilityhave developed2.5 hrs per inspectn x17 inspect = 42.5$30.27/hr $1,286 $1,286Subtotal (Industry costs): $10,829 per facility per yearState Government Costs6 Review of Impoundment Safety Plans 160 hrs tech review +2 hrs admin review$30.57/hr $4,952 $4957 Review of revisions to Impoundment Safety Plans 30 hrs tech review +2 hrs admin review$30.57/hr $978 $988 Review and prepare responses for impoundment abandonment plans 1 $30.57/hr $31 per plan $39 Review of annual inspection Status Reports and Certifications 1 $30.57/hr $31 per report $3Subtotal (State government costs): $599 per facility per yearTotal CostTotal industry + state government cost: $11,428 per inspectionNotes:* Elements, labor hours, and labor costs are based on the “Supporting Statement” for the March 2008 DOL/MSHA ICR 12-19-0015, “Refuse Piles and ImpoundingStructures, Recordkeeping, and Reporting Requirements” at: http://www.msha.gov/regs/fedreg/paperwork/2004/04-24046.pdf1. 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 siteswith monitoring instruments (3 hours) and at sites without monitoring instruments (2 hours).6213. Baseline RCRA facility-wide investigations (RFI)Baseline cost assumed to be $0 because this RIA assumes that all baseline CCR disposal units usedby electric utility plants are not regulatedunder RCRA Subtitle C.14. Baseline facility-wide corrective actionBecause CCR is not regulated as Subtitle Chazardous waste, there are no existing facility-wide (i.e., CCR disposal units plusother waste unitsalso located at the same plant) corrective action requirements, although some state governments have the following unit-specific correctiveaction requirements affecting CCR disposal units.State regulations for the top 25 coal usage states (for electricity) were reviewedfor correction action requirements in 2000.These regulationswere not updated as part of this RIA. Corrective action requirements were identified in 21 of the 25 states.•Surface impoundments: 71% of CCRimpoundments representing 67% ofCCR impoundment annual tonnagehave state government baselinecorrective action requirements:oAZ, IN, and IA establish acorrective action alert level and responseaction in site-specific state permitsoCO requires correctiveaction for new unitso9 states (FL, GA, KY, MI, NC, ND,PA, UT, WI) requirecorrective actionoIL, MN, TX, WV, WY do not allow groundwaterdegradation, but specific enforcementmechanisms are not specified in stateregulationsoMO requires corrective action for units closed with waste in place, otherwise, corrective actionmay be established under a permitoNM requires an abatement plan.•Landfills: 66% of CCR landfills with 81% ofCCR landfill annual tonnage have state government corrective action requirements:oAZ establishes corrective actionalert level and response action insite-specific state permitso15 states (CO, FL, GA, IL, KY, MI, NC, ND, OH,OK, PA, UT, WV, WI, WY)require corrective actionoMN, TX do not allow groundwater degradation, but, specific enforcement mechanismsare not specified in state regulationsoMO, TN require assessment onlyoNM requires an abatement plan15. Baseline waste disposal permit cost•Assumptions:o93% of CCR landfills have a state government non-hazardous waste disposal permit and 12% ofCCR impoundments have suchpermits. Source: page 28, Table 9 of “Coal Combustion Waste Management at Landfills and Surface Impoundments, 1994-2004”,August 2006 athttp://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 facilitypermit requirements) + ($25,000 average RCRA Part B forimpoundment or landfill) = $80,000 per Subtitle C permitoAssume RCRA Subtitle D (40 CFR 257, 258)waste permitting activities are less burdensome than RCRA Subtitle C wastepermits. Based on factor of 3.3 times more technical standards listed in RCRA Subtitle C (40 CFR 264/265, 268, 270) compared toSubtitle D (40 CFR 257, 258), assume SubtitleD permitting costs are lower by the 3.3 factor:63($80,000 per year average Subtitle C waste disposal permit cost) / (3.3) =$24,300 per non-haz waste disposal permit[((93% landfills w/permit) x(337 landfills)) + ((12% impoundments w/permit)x (158 impoundments))] x ($24,300 per permit) =$8.1 millionAmortized industry cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years)= $0.59 million/year•State government waste disposal permit cost:oBuild estimate based on the following four RCRA Subtitle C permit-related state government activities associated with RCRASubtitle C waste disposal permits:51(1,215 pre-application activities) + ($27,063 application review)+ ($26,846 permit issuance) + ($3,110 permit maintenance) =$58,200 average cost per Subtitle C waste disposal permit.oAssume RCRA Subtitle D (40 CFR 257, 258)waste permitting activities are less burdensome than RCRA Subtitle C wastepermits. Based on factor of 3.3 times more technical standards listed in RCRA Subtitle C (40 CFR 264/265, 268, 270) compared toSubtitle D (40 CFR 257, 258), assume SubtitleD permitting costs are lower by the 3.3 factor:($58,200 per year average Subtitle C waste disposal permit cost) / (3.3) =$17,600 per non-haz waste disposal permitoState Cost Calculation:[((93% landfills w/permit) x(337 landfills)) + ((12% impoundments w/permit)x (158 impoundments))] x ($17,600 per permit) =$5.85 millionAmortized state cost with a capitalrecovery factor of 0.07246 (@7% discountrate & 50-years) = $0.42 million/yearTotal baseline permit cost (industry+ state government) = $1.01 million per year16. Baseline enforcement inspectionNot estimated in this RIA.17. Baseline remediation of environmental releasesNot estimated in this RIA.51Source: Based on cost data from page 84 of January 2007 ASTSWMO report “State RCRA Subtitle CCore Hazardous Waste ManagementProgram ImplementationCosts Final Report” at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20Core%20Project.pdf64•Baseline CCR Disposal Cost Estimation ResultsExhibit 3Lbelow displays the average annualized costs for each of the baseline cost components, as well ason an average per-ton and perplant basis.Appendix Hprovides plant-by-plant and owner entity-by-entity estimates of baseline costs.Exhibit 3LIndustry Baseline Cost Estimates for CCR Disposalby Electric Utility Plants (Onsite + Offsite)($millions per year in 2009$ discounted @7% over 50-year period-of-analysis 2012 to 2061)Baseline Cost ElementCCR Landfills (311 plants)CCR Impoundments (158 plants)Row totals (467 of 495 plants)A. Engineering controls (onsite disposal):1. Ground water monitoring $19.2 $8.0 $27.2 0.5%2. Bottom liners $2,751 $1,219 $3,970 71.5%3. Leachate collection system$105.5 $52.2 $157.7 2.8%4. Dust controls $24.2 $2.8 $27.1 0.5%5. Water run-on/run-off controls $4.8 $0.7 $5.6 0.10%6..Financial assurance $61.2 $17.9 $79.2 1.4%7. Disposal location restrictions Not estimated Not estimated Not estimated8. Closure capping to cover unit $72.7 $15.7 $88.5 1.6%9. Post-closure groundwater monitoring $1.3 $0.5 $1.8 0.03%10. Storage design/operating requirements Not estimated Not estimated Not estimatedSubtotal Engineering Control costs = $3,040 $1,317 $4,357 78%B. Ancillary costs for CCR disposal:11. Offsite disposal (commercial landfills) $1,193 $0 $1,193 21.5%12. Structural integrity inspections $2.46 $2.18 $4.64 0.08%13. RCRA facility-wide investigation (RFI) $0 $0 $0 0%14. Corrective action Not estimated Not estimated Not estimated NE15. Waste disposal permits $0.69 $0.32 $1.01 0.02%16. Enforcement inspection Not estimated Not estimated Not estimated NE17. Remediation of environmental releases Not estimated Not estimated Not estimated NESubtotal Ancillary costs = $1,196 $2.5 $1,199 22%Cost Summary (A+B)Column total annualized cost = $4,236 $1,320$5,556(includes $1,193 offsite disposal)PV = $76,678 (@7%, 50-years)Average annual cost per plant = $13.6 million per plant $8.4 million per plant $11.9 million per plantAverage cost per CCR ton disposed = $59 per ton(71.8 million tons per year)$59 per ton(22.4 million tons per year)$59 per ton(94.2 million tons/year disposed)65•Validity Check of BaselineCost Estimate (2 Tests):oValidity Test #1 of 2: Comparison to ACAA Published Estimate of Average CCR Disposal CostAs displayed above inExhibit 3Lthe estimated baseline (i.e., current) average annualizedcost to the 495 coal-fired electric utility plants fordisposal of CCR is $5.6 billion per year (2009$). This annualized cost includes amortization of capital investment in construction of disposalunits and associated equipment (i.e., in-plant equipment forextracting CCR from boilers, CCR storage equipment, CCR conveyanceequipmentsuch as slurry pipelines for wet CCR or trucks and mechanical conveyor belts for dryCCR, and the disposal units themselves), plus annualexpenditures for operation, maintenance and replacement/expansion ofthis equipment and disposal units. On a unitized cost-per-ton basis --calculated by dividing the annualized baseline cost by the estimated 94.2 million tons per year (as of 2005) CCR disposed in (a) onsite landfillsplus (b) offsite landfills plus (c) impoundments annually – the estimated baseline costrepresents an average unitized cost of$59 per-ton.In comparison, the American Coal Ash Association (ACAA) estimatesthat the average unit cost (per-ton) forbaseline disposal ofCCR bycoal-fired electric utility plants ranges as low as $3 per-ton to higher than $40 per-ton:"As one can see, a variety of factors enterinto determining disposal costs. The lowest cost occurs whena disposal site islocated near the power plant and the materialbeing disposed can be easily handled. Ifthe material can be piped, rather thantrucked, costs are usually lower. In thesetypes of situations, cost may be as low as$3 to $5 per ton. In other areas, whendistance is far away and the [CCR] must behandled several times due to its moisture content or volume, costs could range from$20 to $40 per ton. In some areas, the costs are even higher. If new sites arerequired and extensive permitting processes takeplace, the total cost of the facility may be increased, resulting in higher disposal costs over time."52The reasons the average annualized and unitizedbaseline CCR disposal costof $59 per-ton estimated inthis RIA, is higher thanthe baselinecost range of $3 to over $40 per-ton reported by the ACAA, are:•Low-end unitized cost: The low-end of ACAA’s reported cost range is $3 to $5 per-ton. Assuming the cheapest operating surfaceimpoundment does not include a linerand leachate collection costs as estimated inthis RIA for impoundments in states with suchregulatory requirements, the baseline surfaceimpoundment unitized cost may be as low as$2 per-ton based on the cost elementsapplied in this RIA. This low-end unitized costmay be derived from the impoundment cost column ofExhibit 3Las follows:(Column total cost - Row 2 cost - Row 3 cost) / (22.4 million tons per year managed in impoundments) =($1,317 million/year - $1,219 million/year - $52.2 million/year) / (22.4 million tons per year) =$2.04 per-ton•High-end unitized cost: The upper-end of ACAA’s reported costrange is $20 to $40 per ton, whichapplies to offsite disposal. Thecost estimation of this RIA incorporates off-site commercial disposalcosts on a state-by-state specific basis according to electricity52Source: ACAA webpage containing Frequently Asked Question nr. 13 at http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=5#Q1366power plant location, using commercial landfill tipping fees ($2009) for contaminated soil, which range widely from $11 per-tonto$135 per-ton, with a national average of $50 per-ton. For example,commercial landfill tipping fees for contaminated soil forsome ofthe high coal usage states are:TN = $11.19/ton, IN = $32.73/ton, OH = $35.48/ton, and PA = $57.96/ton. The baseline costestimation method of this RIA then addeda CCR offsite transportation and loading cost of approximately $33 per-ton based on theRACER cost estimation tool. For the estimated 15.0 million tons per-year of CCR disposed in offsite landfills, the estimated baselinecost is $1,193 million per-year,which is equivalent to$79.53 per-tonover the 50-year timeperiod of the RIA cost analysis whichassumes increasing coal usage (0.73% per-year) by electric utilities andsubsequent offsite landfilldisposal over the 50 yeartimeperiod. It is unknown what cost elementsare included in the high-endof the ACAA reported cost range (e.g., transportation costand/or landfill tipping fee cost).In addition, electric utilitycompanies likely have annual or multi-year contracts with offsite landfilloperators that offer lower tipping fees than the state-averageoff-site contaminated soil tipping fees used in this RIA.oValidity Test #2 of 2: Comparison to CCR Disposal Costs Contained in the EIA Form 767 DatabaseThe 2005 Energy Information Administration (EIA) Form 767 database (Schedule 3, PartB) indicates $5,890 million in annual capital andO&M cost reported by steam electric plants with nameplate capacity of 100 MW or greater, including (a) $0.314 million per yearfor waterpollution controls, (b) $0.193 million per year for solid wastedisposal, (c) $0.185 million per year for other pollution controls, (d) $3,627million per year capital expense for air pollution abatement, and (e) $1,546 million per year for collection and disposal O&M costs for fly ash,bottom ash, and FGD. This last cost element --- $1,546 million per year for CCR disposal --- is only 28% of the $5,556 millionper yearestimate displayed inExhibit 3Labove. However, the 2005 EIA Form767 cost data are associated withonly 179 coal-firedelectric utilityplants, which represent only 36% of the 495 coal-fired electric utility plants addressed by this RIA. Therefore, to facilitatea direct comparison,the $1,546 million per year cost from the data in EIA Form 767 may be extrapolated to all 495 plants by multiplying by the factor 2.765 (i.e.,495 / 179), which produces an estimated extrapolated costfor all 495 plants of $4,275 million per year (i.e., 2.765 x $1,546 million per year).This extrapolated cost is 23% lower thanthe $5,556 million per year baseline cost estimated in this RIA. This comparison suggests thebaseline cost estimated in this RIA may be an over-estimate, butit is not clear whether the costdata in the EIA Form 767 database includebaseline costs to the electric utility plants for compliance with existing state government regulations concerning CCR disposal(e.g., theannualized cost for obtaining and maintaining state government disposal permits and the annualized cost for impoundment structural integrityinspections), asdoes this RIA.67Chapter 4Estimated Cost for RCRA Regulation of CCR DisposalNote: EPA formulated cost estimates in this Chapter basedon the October 2009 draft RIA regulatory options. Because thehigh-end cost of those options (i.e., for the Subtitle C “hazardous waste” option) islarger than the high-end cost for the 2010regulatory options (i.e., for the Subtitle C “special waste” option), the costs in this Chapter are proportionately over-estimated.However, Section 6B of this RIA appliesscaling factors to adjust the costs estimated in this Chapter to the 2010 options.4A. EPA’s Prior Cost Estimates forPossible RCRA Regulation of CCR Disposal at Electric Utility PlantsIn prior studies, EPA’s Office of SolidWaste (which EPA renamed as the ORCR effective 18 January 2009), formulated the following industrycompliance cost estimates for different RCRA-based regulatoryapproaches to CCR disposal by the electric utility industry:1988: OSW's 1988 Report to Congress on CCR estimated$2.4 billion to $4.7 billionper year (1986$) in potential average annualizedindustry cost (514 plants in 1984) for compliance withtechnical standards contained in 40 CFR 264 RCRASubtitle Chazardous wasteregulations. The range reflects different liner assumptions (i.e., single versus double liners) and whether only unlined CCR units closeor all existing units close requiring construction of new units. This cost includesclosure costs but not a cost for corrective actionexcavating and removing CCR to Subtitle C facilities for closure ofexisting units. This reportseparately estimated that correctiveaction “at a cost of about $2.0 billion perplant, industry-wide costs would exceed $1.0 trillion” lump-sum cost, which is equivalent to$43 billion annualized cost (discounted @3% over 40-years). Source: EPA-OSWER report nr. EPA/530-SW-88-002, Feb 1988.1999: OSW’s 1999 Report to Congress focused on the “co-management”(i.e., low-volume mixed withhigh-volume) subset of CCR units(i.e., 206 units at 353 plants in 1994), constituting 53 milliontons (50%) of the 105 million total high-volume electric utility CCRgeneration in 1997. This report estimated a range of$800 million to $900 millionper year (1998$) in potential average annualizedcompliance cost to the electric utilityindustry to comply with technicalstandards similar to 40 CFR 258 RCRASubtitle Dnonhazardous waste regulations. This cost estimate includes openingnew CCR units to replace existingunits that do not meet Subtitle Dstandards, including the following itemized costs: land purchase,site development, liner installation, leachate collection, groundwaterwells & monitoring, closure costs, and post-closure costs. Thisestimate accounted for state CCRmanagement requirements as of1997.Source: EPA OSWER reportnr. EPA 530-R-99-010, March 1999.2005: In a November 2005 report, an OSW contractor (DPRA Inc) estimated$304 million to $521 millionper year (2005$) in potentialaverage annualized cost for the electricutility industry (i.e., 470 units at 452 plants in 2003) to comply with regulatory optionsdeveloped with reference to the “tailored standards” of EPA’s 1999 cement kiln dust proposed rule which based many elements on40CFR 258 RCRASubtitle Dnon-hazardous waste regulations. Costelements in this report included(a) location standards, (b) operatingcriteria such as cover material, dust control, run-on/run-off control, (c) design criteria such as liner and leachate collection, (d)groundwater monitoring, (e) closure and post-closure standards, and (f) financial assurance for closure, post-closure and corrective68action. This estimate accounted for state CCRmanagement requirements as of 2004, but did not include costs for corrective action.Source: EPA-OSWER document ID nr. EPA-HQ-RCRA-2006-0796-0469 at http://www.regulations.gov.These three prior RCRA regulatory cost estimates range from$304 million to $4.7 billionper year. Even withoutupdating these prior costestimates to the current 2009 price level,all three prior cost estimates exceedthe 1993 Executive Order 12866 Section 3(f)(1)“economicallysignificant” $100 million annual effect threshold for Federal rulemakings.4B. Regulatory Cost Estimation Algorithms & ResultsThis section presentsincremental cost estimatesfor each regulatory option, for both existingactive (i.e., operating) and future new CCRlandfills and impoundments, and by size/type ofaffected electric utility plant ownerentity. Incremental comparison of the estimated cost ofeach regulatory option to the baseline (as estimated inChapter 3of this RIA) is consistent withOMB’s 2003 “Circular A-4: RegulatoryAnalysis” best practices guidance to Federal agencies:“Identify a baseline. Benefitsand costs are defined in comparisonwith a clearly stated alternative. This normally will be a“noaction” baseline: what the world will belike if the proposed rule is not adopted.”As listed below, this RIA estimates 18 potential regulatory costs andthe land disposal restriction (LDR) dewatering treatmentstandard, basedon many of the same unit cost data sourcesand the same framework (i.e., 2009 price level, 50-year period of analysis, etc.), identified in theprior chapter of this RIA for baseline cost estimation. According tothree methodological groupings, this RIA estimates threecategories ofregulatory costs:A.Engineering controlsfor CCR disposal units – estimated using the cost model described in the prior chapter of this RIA:1.Ground water monitoring2.Bottom liners – for future new units only3.Leachate collection system – for future new units only4.Dust controls – applicable to landfills only5.Rain and surface water run-on/run-off controls – applicable to landfills only6.Financial assurance for disposalunit closure and post-closure7.Disposal unit location restrictions (6 types: water tables, floodplains, wetlands, fault areas,seismic zones, karst terrain)8.Closure capping to cover unit9.Post-closure monitoring requirements10.Temporary storage requirements – not estimated in this RIA because do not have information on the baseline counts or physicalconditions of CCR storage tanks and storage buildings at electric utility plants.69B.Ancillary costsfor CCR disposal – estimated outside ofthe engineering control cost model:11.Offsite disposal (hazmat trucking, RCRAmanifesting, offsite RCRA TSDF permits)12.Structural integrity inspections – impoundments only13.RCRA facility-wide investigation (RFI)14.RCRA facility-wide corrective action15.RCRA TSDF hazardous waste disposal permits for onsite disposal16.RCRA enforcement inspection17.Cleanup remediation of future CCR impoundment failures as RCRA hazardous waste18.EPA administrative reporting & recordkeepingC.LDR costfor land disposal restriction dewatering treatment – Sections3004(d) and (m) of the RCRA statute require treatment prior toland disposal for Subtitle C hazardous waste listings, but notfor Subtitle D non-hazardous waste regulation. The purpose of the treatmentis to “substantially diminish the toxicity of the waste or substantially reduce the likelihood ofmigration of hazardous constituents from thewaste so that short-term and long-termthreats to human health and the environment are minimized” (source: section 3004(m)):oDry CCR disposal (landfills): Moisture conditioning and compaction included in engineering control cost item 4.oWet CCR disposal (impoundments): Estimated outside and separately of the engineering controls cost model in this RIA.This RIA does not include eitherqualitative or quantitative estimation of the potential effects of the proposed rule on economic productivity,economic growth, employment, job creation, orinternational economic competitiveness.These potential effects are identified as factors inboth the 1993 Executive Order “Regulatory Planning and Review” (section 3(f)(1)) and in the 1995 Unfunded Mandates Reform Act (section202(a)(4)). These other potential economic effects are excluded from this RIA because the upper-end of the range in average annualizedregulatory cost across all regulatory optionsas estimated in this chapter below,does not exceed the 0.25% to 0.5% of Gross Domestic Product(GDP) threshold identified in OMB’s 1995 guidance53for attempting to measure such other economic effects for purpose of UMRA economicanalysis compliance. Based onthe 2008 US GDP of $14.42 trillion,54the 0.25% to 0.5% threshold is equal to $36 billion to $72 billion.4B.1 Regulatory Cost to Industry for RCRA “Engineering Controls”This RIA assumes that that same set ofRCRA 3004(x) custom-tailoredengineering controls is required under each of the regulatory options, sothe costs for engineering controls for allregulatory options are mostly, but not entirely, based on the same cost estimation formulae describedabove inChapter 3for estimation of baseline engineering control costs. Furthermore, this RIA assumes that the engineering control costs are53Source: Section 4.B(3) of OMB’s 31 March 1995 guidance for implementing the UMRA state that “We would note that such macro-economic effects tend to bemeasurable, in nation-wide econometric models, only if the economic impact of the regulation reaches 0.25 percent to 0.5 percent of Gross Domestic Product. A regulationwith a smaller aggregate effect is highlyunlikely to have any measurableimpact in macro-economic terms unless it is highly focuses on a particular geographic region oreconomic sector.”54Source: 2008 3rdquarter estimate of 2008 US GDP as reported in “TABLE B–8.—Gross domestic product by major type of product, 1959–2008” of the2009 EconomicReport of the President at http://www.gpoaccess.gov/eop/tables09.html70similarly specified in EPA’s cementkiln dust 20 August 1999 proposed rule.55This assumption was required to launch this RIA in April 2009prior to the initial draft of the CCR proposed rule and its regulatory options. This RIA assumes that liners and leachate collection systemsrequirements apply only to future new CCRlandfills and impoundments. Offsite disposal costs are assumed unaffected under allregulatoryoptions because offsite CCR disposal unitsare assumed to be commercially-owned units(i.e., owned by the waste management industry) andassumed currently in compliance with the custom-tailored engineering controls. For engineeringcontrols added to existing units the costs areadded to the remaining years of the lifespan of the landfill or impoundment.1. Regulatory groundwater monitoring costSame cost estimation formula applied above inChapter 3for baseline cost estimation.2. Regulatory bottom liner costSame cost estimation formula applied above inChapter 3for baseline cost estimation.3. Regulatory leachate collection costSame cost estimation formula applied above inChapter 3for baseline cost estimation.4. Regulatory fugitive dust control costSame cost estimation formula applied above inChapter 3for baseline cost estimation.5. Regulatory financial assurance costSame cost estimation formula applied above inChapter 3for baseline cost estimation.6. Regulatory closure costsSame cost estimation formula applied above inChapter 3for baseline cost estimation.7. Regulatory disposal unitlocation restriction costsThis cost element is estimated outside ofthe engineering controls costmodel, using the factors,data and calculations below.•Count of Existing Electric Plants WhichMay be Affected by Location RestrictionsTo estimate the potential cost of location restrictions, this RIA conducted a GIS analysis to determine which facilities may beaffected bylocation restrictions. As summarized below, the GIS analysis was conducted for three of the six possiblesite restrictions (i.e., using three GISbased datasets pertaining to fault areas, seismic zones, andkarst zones readily available to EPA-ORCR at the 2009 launch of this RIA). Thislimitation potentially results in under-estimation in this RIA of the number or electric utility plants which may be affected and thus underestimation of regulatory locationrestriction costs. On the other hand, the average per-plant cost of $4.1 million applied below for estimatingthe potential cost of this regulatory elementis over five-times higher than the $0.75 million56cost per-plant cost estimated by another study for55Federal Register, Vol.64, No.161, 20 Aug 1999, pp.45632-45697.56Source: $0.75 million disposal unit location restriction mitigation cost for a single electric utility plant is from page 10 (slide number TVA-00007496) of “Kingston FossilPlant Decision Matrix: Pond or Peninsula?,” 27 Jan 2005 Plant Managers Conference Room at http://www.tva.gov/kingston/tdec/pdf/TVA-00007487.pdf71location restriction mitigationinvolving karst mitigation and floodplain/wetland mitigation; this probably overly offsets thepossible costunderestimation in this RIA for this regulatory element.The GIS was based on the DOE-EIA eGRID database to identify the geographic coordinates for 491 ofthe 495 electric utility plants(disregarding four plants notpresent in the eGRID database).Appendix Iof this RIA presents site location data for each electric utility plantused in the GIS analysis. Inorder to geographically capture both the facilities and their waste units, and to compensate forthe fact that thereexists uncertainty as to the exact facility location versus the reported geographic coordinates (i.e., depending on whether location was measuredby plant centroid, street address, smokestack, etc.), this GIS analysis used botha 1-mile and a 3-mile buffer around the reported facilitycoordinates. This RIA presumes these buffers are likely to ensure inclusion of the facility's onsite CCR disposal units, and account foruncertainty in the location data. The 1-mile buffer should capture all impoundments;the 3-mile buffer represents an upper-bound to capture alllandfills that could reasonably be considered on-site.1. Water table restrictions: GIS analysisnot conducted for thissite restriction2. Floodplain restrictions: GIS analysis notconducted for this site restriction3. Wetlands restrictions: GIS analysis not conducted for this site restriction4. Fault area restrictionsTo identify fault zones, used the USGS database, “Quarternary Fault and Fold Database for the United States,” which contains national scalelocation data on faults and associated folds.57This analysis identified plantsincluding their buffers which fall within 200 feet of fault lines thathave exhibited movement in the Holocene era.The USGS dataset includes fault lines that are believed to have been a source ofearthquakesgreater than magnitude 6 duringthe Quarternary (the past 1,600,000 years) and it defines “Holocene” as the past 15 thousand years.58,59•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 plantsare located in NV and UT).It is important to note that this preliminary analysis has certain limitations and may not capture facilities in other areas ofseismic risk.According to the USGS fault line database, norelevant faults are located in the centraland eastern US. The USGS states in its databasedescription that this absence of identified faults with movement in the central and eastern US is partly a real phenomena, because the westernUS has more tectonic activity, butthat it is partly a detection problem caused by geological characteristics present in the central and easternUS, such as glacial sediments, that conceal evidence of movement along faults. Forthis reason, the analysis of seismic zonesbelow, whichare defined based on the likelihood of future seismic activity, mayrepresent a more reliable estimate of the number of facilities potentiallyaffected by fault area restrictions.6057US Geological Survey, 2006, “Quarternary Fault and Fold Database for the United States” at:http//earthquakes.usgs.gov/regional/qfaults. File used: fitarc.shp58RCRA defines “Holocene” as “the most recent epoch of the Quarternary period, extending from the end of the Pleistocene to the present” (40 CFR 264.18(a)(2)(iii)).59Faults designated by the dataset as showing movement during the Holocene are not necessarily believed to have produced an earthquake of magnitude 6 or greater duringthe Holocene. Rather, they are believed to have produced an earthquake of magnitude 6 or greater during the Quarternary, but their most recent suspected movement of anydegree was during the Holocene.60The USGS data layer used for this analysis indicates that faults with Holocene movement are located only in states in the Westand Southwest regions of the US. Thisappears generally consistent with a separate analysis inthe RCRA Practice Manual(Garrett, Theodore L., 2004, published by American Bar Association), and the smallnumber of plants affected is not unexpected given the relatively small number of plants in these regions. However, theRCRA Practice Manualalso notes that virtually allplants in CA and NV, and in parts of AK, AZ, CO, HI, ID, MT, NM, UT, WA, WY would be located within 200 feet of relevant faults. This suggests an upper bound of 54plants (out of the 491 plants analyzed), if all facilities in the identified states may be affected by fault area restrictions.725. Seismic zone restrictions:To identify seismic zones, USGS National Seismic Hazard Maps provide peak horizontal acceleration at different probabilities ofexceedancein 50 years.61Identified those facilities, including their buffers, which overlap with the seismicimpact zones that have a 10% or greaterprobability of exceeding a maximum horizontal acceleration of 10% the force of gravity (i.e., 0.10 g) in 250 years.62The USGS data givesprobabilities of exceedance over 50 years; thusused a data layer presenting 2% probability of exceedance, and assumed that this equates to a10% probability of exceedance in 250 years.•1-mile buffer: 151 plants fall within seismic zones•3-mile buffer: 152 plants fall within seismic zones6. Karst zone restrictions:This analysis used two databases: (1) DOE-EIA’s eGRID databaseto identify the geographic coordinates of 491 of the 495 plantsanalyzed(disregarding four plants that were not present in the eGRID database), and (2) theUSGS's GIS database "Engineering Aspects ofKarst,"which provides national-scale data on karst coverage.63Four types of karst areas are identified in the dataset: (a) long karst features (fissures,tubes, and caves over 1000 feet long and 250 feet deep); (b) short karst(fissures, tubes, and cavesless than 1000 feet long and 50 feet deep),(c) areas where karst features are generally absent but present in small isolated areas, and (d) pseudo-karst areas, which havefeaturesanalogous to karst.•1-mile buffer: 138 plants fall within karst zones•3-mile buffer: 177 plants fall within karst zonesThese counts do not distinguish between the four different types ofkarst terrain identified in the data set; this analysis represents an initialupper bound of potentiallyaffected facilities.•Potential Cost for Existing & New Electric Plantsto Meet Disposal Unit Location RestrictionsAccording to the above findings for the three location criteria evaluatedin this RIA (i.e., fault areas, seismic zones, karstzones), a maximumcount of 177 plants could be affected (this is the upper-end ofthe affected plant counts across the three location evaluations). The potentialcost to these plants of the location restrictions is estimatedin this RIA using the cost toretro-fit existing CCR disposal units and to protectnew CCR disposal units with a berm (aka levee). A berm is a type of engineering measure which may serve to demonstrate that engineeringmeasures have been incorporated into disposal unit design tomitigate the potential adverse impacts disposal units may have on,or be causedby, these six location considerations.The cost to construct a berm is based on the cost to constructa 10-foot tall flood berm using USArmy Corps of Engineers’ publication“Flood Proofing – How toEvaluate Your Options,”(July 1993), which provides unitcosts in 1993 dollars to construct clay core flood controllevees that are two, four, andsix-feet high. This RIA inflated these unit costs to2009 dollars using the ENR Construction Cost Index, andconducted a regression analysis on the unit costs (i.e., extrapolated the cost based onthe implied cost curve of the smaller berms) to estimatethe cost to construct a 10-foot tall berm. The estimated costper linear foot to construct a10-foot tall berm is $375. It isassumed that this unitcost could apply to both existing and new units, and that the berm would be constructed physically separate from the disposal unit, notintegral as “freeboard” to the disposal unit’s structure.61U.S. Geological Survey, 2008, “National Seismic Hazard Maps,”from USGS website: http://gldims.cr.usgs.gov/nshmp2008/viewer.htm. Data file used: pga2pct_p.shp.62This threshold for seismic impact zones is consistent with RCRA’s municipal solid waste landfill location restrictions (40 CFR258.14(a)(b)(1)).63U.S. Geological Survey, 1984, “Engineeringaspects of karst,” from USGS website: http://pubs.usgs.gov/of/2004/1352. File used:karst.shp.73oImpoundment berms: The average surface impoundment size for existing units in the cost model is 343 acres. Assuming asquare impoundment and that the berm would be constructed on three sides of the impoundment the average berm length is 11,594feet. Therefore, the cost to construct a berm around an average-size impoundment is $4.3 million.64oLandfill berms: Similarly, the average landfill size for existingunits in the cost model is 278 acres. Assuming a square landfilland that the berm would be constructed on three sides of thelandfill (leaving one side open for truck access), the average bermlength is 10,447 feet, and the cost to construct aberm 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 futureplants is:oExisting units: ($4.1 million average berm cost) x(177 disposal units) = $726 million total costAmortized with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $53 million/year equivalentoNew units: Apply 0.73% average annual growthrate in future CCR generation (cited elsewhere in this RIA) to estimate the countof future new or expanded disposal units over 50-years, and assume 36% (i.e., 177/495) will need berms:(495 existing disposal units) x (1.0073%growth rate)^(50 years) = 712 existing plus new units over 50-years(712 units over 50-years) – (495 existingunits) = 217 future new disposal units(217 future new units) x (36% needing berms) x ($4.1 million average berm cost) = $318 million total costAmortized with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $23 million/year equivalentAverage annualized berm cost forexisting + new units = $76 million/year equivalent8. Regulatory closure costSame cost estimation formula applied above inChapter 3for baseline cost estimation.9. Regulatory post-closure monitoring costSame cost estimation formula applied above inChapter 3for baseline cost estimation.10. Storage design and operating standards fortanks, containers, and containment buildingsNot estimated in this RIA due to lack of baseline informationabout the count and condition of these units at electric utilityplants4B.2 Ancillary Regulatory Requirement CostsFor estimating most of the “Other Ancillary Costs” in this section, this RIA distinguishes between RCRA Subtitle C and RCRA Subtitle Drequirements according to the respective basis of each regulatoryoption, as well as between costs to electric utility plants and costs to stategovernment RCRA-authorizedregulatory programs.64For purpose of comparison to the $4.3 million (per impoundment) and $3.9 million (per landfill) location restriction mitigation cost estimates above, in 2005 the TVAestimated an “assumed” cost of $500,000 for karst mitigation and $250,000 for floodplain mitigation for a potential new CCR disposal site involving 1,300 linear feet formitigation. Extrapolation of TVA’s $750,000 cost estimate to 11,594 feet (impoundment) yields $6.7 million (i.e., (11,594 feet/ 1,300 feet) x ($750,000)), and to 10,447feet (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 Plant Decision Matrix: Pond orPeninsula?”, 27 January 2005 Plant Managers Conference, http://www.tva.gov/kingston/tdec/pdf/TVA-00007487.pdf7411. Regulatory offsite disposal costs (hazmat trucking, RCRA manifests, RCRA TSDF permits for offsite)EPA assumed that Subtitle C options add extra cost to (a) truck hauling to offsitedisposal, and (b) all offsite landfills mustbecome RCRASubtitle C permitted. This cost estimate does not include taxes/trans-state government fees associated with off-site disposal.11a & 11b. Added truck haulingcost (Subtitle C options)Assumptions:•Affects the 12% (15 million tons per year) annual CCR generation currently trucked offsite to non-haz LFs (2005)•6 miles average one-way trucking distance to offsite LFs65•$0.19/ton/mile hazardous waste truck operating cost•12 tons CCR per full truckload (source: Gambrills MD case study); (15 million tons/year) / (12 tons/load) = 1.25 milliontruckloads per yearCost Calculations:•11a. RCRA manifest cost: (1.25 million truckloads) x ($53 permanifest per load average cost from EPA 2007 ICR 801.15) =$66 million per year•11b. Trucking cost (distance + operating cost): (15 million tons/year) x (6 miles) x ($0.09/ton/mile added truck operating costfor hazardous waste loads) = $8.1 million per year•Subtotal (11a manifest + 11b trucking): $74.1 million per year11c. Added cost for RCRA Subtitle C permitsfor all offsite CCR landfills under Subtitle CAssumptions:•Added operating cost to offsite CCR landfills for meeting engineering control requirements under eachof the regulatory optionsevaluated in this RIA are included in the“Engineering Control Costs” section above, so are not againcalculated here to avoiddouble-counting. Only the paperwork burden costfor obtaining a RCRA permit is estimated here.•Industry average cost per waste disposal permit:($44066average RCRA Part A permit application cost per-plant per-year) + ($68,96067average RCRA Part B application costper-facility per-year) = $69,400 perSubtitle C permit per year($69,400 per permit per year) x (3 years ICRannualization period) = $208,200 per permit(149 offsite CCR landfills) x ($208,200 per permit) = $31.02 millionAmortized industry cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years)= $2.25 million/year65Source: based on actual distance reported for a MD plant at http://www.rachel.org/en/node/445). Note: a broader range of 2.4miles to 25 miles in one-way offsite landfilldistance was reported by an OH plant at http://www.columbusdispatch.com/live/content/local_news/stories/2008/04/14/Powerfills.ART_ART_04-14-08_B1_FF9TI0U.html?sid=101, and a WI plant, respectively athttp://www.lacrossetribune.com/articles/2007/09/21/news/03landfill0921.txt66$440 unitized cost derived for this RIA from EPA InformationCollection Request (ICR) No. 0262.12 “RCRA Hazardous Waste PermitApplication and ModificationPart A”, Federal Register, Vol.74, No.17, 28 Jan 2009, page 4958; http://edocket.access.gpo.gov/2009/pdf/E9-1804.pdf67$68,960 unitized cost derived for this RIA from EPA Information Collection Request (ICR) No. 1573.12 “Part B Permit Application”, Federal Register, Vol.74, No.100,page 25237, 27 May 2009; http://edocket.access.gpo.gov/2009/pdf/E9-12285.pdf75•State government average cost per waste disposal permit:Average cost for state government review of RCRASubtitle C permits consists of four activities:68(1,215 pre-application activities) + ($27,063 application review)+ ($26,846 permit issuance) + ($3,110 permit maintenance) =$58,200 per permit(149 offsite CCR landfills) x ($58,200 per Subtitle C permit) = $8.67 millionAmortized state cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $0.63 million/year•Total Subtitle C permit cost (industry+ state government) = $2.9 million per yearTotal cost for item 11 (11a + 11b + 11c):•Industry share of cost = $76.35 million per year•State government share of cost = $0.63 million per year•Total (industry + states) = $76.98 million per year12. Regulatory structural integrity inspection cost•Assumptions:EPA assumed that the residual 18% of the non-inspected plants require inspection overthe 82% baseline inspection coverage.The per-plant cost for inspections is estimated in theChapter 3baseline above.•Cost Calculation:Industry cost: ($10,829/year per facility) x (18% not inspected) x (495 plants) = $0.96 million per yearState government cost: ($599/year per facility) x (18%not inspected) x (495 plants) = $0.054 million per yearTotal (industry + state) = $1.01 million per year13. 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%of landfills. Thus,assume that 57 plants with impoundments (i.e., 36% x 158 plantswith impoundments) plus 74 plantswith landfills (i.e., 22% x 337 plantswith 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 ofmigration of releases of hazardouswaste or constituents to determine whetherinterim corrective measures and/or a Corrective Measures Study may be necessary forotherwaste units at the facility (source: EPA 530/SW-89-031, May 1989, Vol.I). RFIs may include: rapid field screening using portable fieldinstruments, drilling in soils,excavating test pits, ground-water monitoring, waste testing, biomonitoring, and site surveying, sitephotography, site mapping.•RFI average cost:$0.75 million average cost for RFIs involving captive industrial landfills68Source: Based on cost data from page 84 of January 2007 ASTSWMO report “State RCRA Subtitle CCore Hazardous Waste ManagementProgram ImplementationCosts Final Report” at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20Core%20Project.pdf76$0.69 million average cost for RFIs involving captive industrial waste management (assume applies to impoundments)Source: EPA OSRE memorandum “Transmittal of Average Cost ofInvestigation Derived from Fund-Lead Superfund Costs, InterimMeasures Cost Compendium, and Compendiumof Related Guidance Documents”, 01 Nov2004. This memo indicates that Superfundremedial investigation costs can beused 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 costTotal = $94.8 million total cost to industryAmortized industry RFI cost with a capital recovery factor of 0.07246 (@7% discountrate & 50-years) = $6.9 million/year equivalent•State government RFI cost:State government RFI review, approval,oversight average cost per RFI = $76,00069(131 RFIs) x ($76,000 review, approval, oversight average costper RFI to state governments) = $10 million total costAmortized state government RFI cost witha capital recovery factor of 0.07246 (@7%discount rate & 50-years) = $0.7 million/yearequivalent•RFI total cost (industry + stategovernments) = $7.6 million per year14. Regulatory RCRA facility-wide corrective action costAverage annualized future potential costwas not estimated in this RIA because ofa high degree of uncertainty. Through a process calledcorrective action, RCRA Subtitle C requires RCRA-regulated facilities to investigate andclean-up releases of hazardous wastesor constituentsto the environment identified in the RCRAfacility-wide investigation (RFI). After the RFI, if the need for cleanup is discovered, the RCRAregulated facility must perform a “Corrective Measures Study” (CMS) which may range in cost from $100,000 to $800,000 for sucha study.70State government cost for corrective measures study & corrective action review, approval,oversight is $117,300 per case.71The purpose of aCMS is to develop and evaluate the corrective action alternative(s) and to recommendthe corrective measure(s) be taken at thefacility.72As of 2008 the RCRA corrective action universe is about 3,800 sites nationwide.73Relative to the RCRA-regulated universe of217,500 facilities (consisting of about 16,000 hazardous waste LQG “large quantity generators” plus about 200,000 hazardous waste SQG“small quantity generators” plus about 1,500 hazardous waste TSDF “treatment, storage,disposal facilities” as of 2008), the 3,800 correctiveaction universe implies a 1.75% relative incidence of occurrence (i.e., 3,800 / 217,500 = 1.75%).Corrective action costs varyfrom facility-tofacility depending on the number and types ofwaste management units and other industrial equipment/processes and wastes involved. The69Source: Divided the $2,200,600 annual RFI cost to 10 state governments by the 29 annual RFIs from page 82 of the January 2007ASTSWMO report “State RCRASubtitle 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.pdf70Source: RACER unit cost reported on p.38 of EPA’s 2000 “UnitCost Compendium” , document ID nr. EPA-HQ-RCRA-2002-0031-0429 at: http://www.regulations.gov71Source: derived from cost data contained on page 83 of theASTSWMO “State RCRA Subtitle C Core Hazardous Waste Management Program Implementation CostsFinal Report”, January 2007at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20Core%20Project.pdf72Source: “Corrective Measures Study Scope of Work”, EPA Region 3 at: http://www.epa.gov/reg3wcmd/ca/pdf/CMSATTC.pdf73Source: 3,800 corrective action cases represents EPA’s “2020 Corrective Action Universe” as identified on EPA Hazardous WasteCorrective Action Facility Informationwebsite at: http://www.epa.gov/waste/hazard/correctiveaction/facility/index.htm#202077corrective action remedies usually involve mitigating damages tosurface water and groundwater.The General Accountability Office (GAO)reported74that RCRA corrective action could cost 3,698 non-Federal hazardous waste treatment, storage, or disposal facilities a total ofabout$16 billion (1996$) to clean up their properties contaminated by hazardous substances, representing an average $4.327 million corrective actioncost per-facility. Updated75to 2009$ implies an average of $5.365 millionRCRA corrective action cost per facility.15. Regulatory RCRA TSDF waste disposalpermit cost for onsite disposalRCRA Subtitle C hazardous waste regulations require hazardous waste treatment, storage, disposalfacilities (TSDFs) to obtain RCRA permitsas described in 40 CFR 270 consisting of a two-part (i.e., Part A and Part B) application process. The paperwork burden cost of thisrequirement is estimated below. Furthermore, but not includedin the cost estimate below, areseparate, additional RCRA regulationscontaining “technical requirements”used by permit issuing authorities (e.g., RCRA-authorized state government waste programs or EPARegional offices) to determine what technical requirements must be placed in permits.The separate cost of technical requirements is estimatedin the “Engineering Controls” regulatory cost section of this RIA above.•Assumptions:oAlthough 93% of CCR landfills have a state government non-hazardous waste disposal permit and 12% of CCR impoundmentshave such state permits, assume CCR disposal units willneed new RCRA disposal permits under Subtitle C options.o383 of the 495 total electric utility plantscurrently dispose onsite (i.e., 84 of the 495 plants solely dispose CCR offsite, plus 28plants solely supply CCR for beneficial uses).•Industry average cost per waste disposal permit:o($44076average RCRA Part A permit application cost per-plant per-year) + ($68,96077average RCRA Part B application costper-facility per-year) = $69,400 perSubtitle C permit per year($69,400 per permit per year) x (3 years ICRannualization period) = $208,200 per permit(383 plants) x ($208,200 per permit) = $79.74 millionAmortized industry cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $5.8 million/year•State government average cost per waste disposal permit:oBuild estimate based on the following four RCRA Subtitle C permit-related state government activities associated with RCRASubtitle C waste disposal permits:78(1,215 pre-application activities) + ($27,063 application review)+ ($26,846 permit issuance) +($3,110 permit maintenance) =$58,200 average cost per Subtitle C waste disposal permit per year.74Source: page 1 of USGeneral Accountability Office (GAO),“Hazardous Waste: Progress Underthe Corrective Action Program is Limited, But New Initiatives MayAccelerate Cleanups,” report nr. GAO/RCED-98-3, October 1997; http://www.gao.gov/archive/1998/rc98003.pdf75Updated from 1996$ to 2009$ using the NASA “Gross Domestic Product Deflator Inflation Calculator” at http://cost.jsc.nasa.gov/inflateGDP.html76$440 unitized cost derived for this RIA from EPA InformationCollection Request (ICR) No. 0262.12 “RCRA Hazardous Waste PermitApplication and ModificationPart A”, Federal Register, Vol.74, No.17, 28 Jan 2009, page 4958; http://edocket.access.gpo.gov/2009/pdf/E9-1804.pdf77$68,960 unitized cost derived for this RIA from EPA Information Collection Request (ICR) No. 1573.12 “Part B Permit Application”, Federal Register, Vol.74, No.100,page 25237, 27 May 2009; http://edocket.access.gpo.gov/2009/pdf/E9-12285.pdf78Source: Based on cost data from page 84 of January 2007 ASTSWMO report “State RCRA Subtitle CCore Hazardous Waste ManagementProgram ImplementationCosts Final Report” at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20Core%20Project.pdf78oState Cost Calculation:(383 electricity plants dispose CCR onsite) x ($58,200per Subtitle C permit per year) = $22.3 million per year•Total Subtitle C permit cost (industry+ state government) = $28.1 million per year16. Regulatory RCRA enforcement inspection cost•Assumptions:oState government average cost = $7,900 per Subtitle C inspection (source: hazardous waste LQG large quantity generatoraverage calculated by dividing the $1,517,357annual enforcement inspection cost to10 surveyed state governments by 192annual enforcement cases, from page 87 of the January 2007 ASTSWMO report “State RCRA Subtitle C Core Hazardous WasteManagement Program Implementation Costs Final Report”o1.6% average annual enforcement inspection frequency based ondividing the 11,965 LQG “largequantity generator” universereported by 10 survey states by the 192 hazardous waste LQGenforcement cases reportedin the January 2007 ASTSWMOreport “State RCRA Subtitle C CoreHazardous Waste Management ProgramImplementation Costs Final Report”•Cost calculation:($7,900 per LQG enforcement) x (495 electric utility plants) x (1.6% LQG enforcements annually) = $0.063 million per year17. Regulatory future remediation added costPotential $18.5 million to $376 million per case in added cleanup costfor future surface impoundmentfailures, if regulated under RCRASubtitle C rather than Subtitle D, is based on the two example case studies summarized inExhibit 4Abelow.79Exhibit 4ATwo Case Studies:Possible Added Cost Under RCRA Subtitle C Regulation of CCRCleanup at Electricity Plants from CCR Impoundment Failures(Note: Assumptions or numerical factors unique to eachcase study are applied in the cost calculations belowrather than the national average assumptions andnumerical factors applied elsewhere in this RIA)Case Study #1:TVA Kingston TN (2008)Case Study #2:Constellation Energy Gambrills MD (2008)If cleanup as non-hazardous waste:Baseline Assumptions:•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 eventIf cleanup as non-hazardous waste:Baseline Assumptions:•0.25 million tons released•$0.10/ton/mile truck operating cost (source: OSW-EMRAD)•193 miles to Subtitle D LF (Constellation Energy’s mileage estimateto existing VA fly ash LF)•$35/ton tipping fee (source: 2005 Chartwell)•20,833 truckloads (source: Constellation Energy assumes 12 tons ashper load)Baseline Cost Calculations:•Trucking cost: (0.25 million tons released) x (193 miles) x ($0.10/ton/mile) = $5 million•LF tipping fee: ($35/ton) x (0.25 million.tons) = $9 million•Manifest: $0Case #2 total = $14 million for eventIf cleanup as RCRA Subtitle C hazardous wasteAssumptions:•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/miletruck 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) = $8million•Case #1 total = $507 million for eventIf cleanup as RCRA Subtitle C hazardous wasteAssumptions:•0.25 million tons released•$0.19/ton/mile truck operating cost (from TVA)•179 miles to Subtitle C LF (closestis Envirosafe OH with 0.9 milliontons permitted capacity)•$90/ton tipping fee (2004 ETC national median fee)•20,833 truckloads (source: Constellation Energy assumes 12 tons ashper load)Cost Calculations:•Trucking cost: (0.25 million tons) x (179 miles) x ($0.19/ton/miletruck operating cost) = $8.5 million•LF tipping fee: ($90/ton) x (0.25 million tons) = $23 million•Manifest: (20,833 truckloads) x ($53 manifest cost per load) = $1million•Case #2 total = $32.5 million for eventCase #1 incremental costover non-hazardous:$376 million for cleanup eventCase #2 incremental costover non-hazardous:$18.5 million for cleanup event8018. EPA administrative reporting and recordkeeping costsThree of the regulatory costs itemized above-- item 11 offsite disposal truck manifesting and offsite disposal hazardous wastepermits, item 12structural integrity inspections, and item 13 RCRA facility-wideinvestigation (RFI) – include the cost of paperwork burden forthose items. Inaddition, certain features of the SubtitleC options of the proposed rule requirefour other paperwork burden activities:18a. Notice of Regulated Waste Activity& EPA ID NumberRCRA Subtitle C regulations for hazardous waste “generators” requiregenerators to notify their facilities as such and obtain EPA identificationnumbers (40 CFR 262.12). According to EPA’s most recent (2009) estimate, the average per-facility response burden is $162 perfacility.79Applied to the 495 electric utility plants yields an estimated one-time notification cost of $80,190 (i.e., (495 electric utility plants) x ($162 pernotification)). Amortized witha capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $5,800 per year average annualequivalent.oIndustry share of cost: (86%) x ($5,800/year) = $5,000/yearoState government share of cost:(14%) x ($5,800/year) = $800/year18b. General Facility Standards for Hazardous Waste TSDFsThis cost item represents aset of paperwork burden activities grouped under 40 CFR 264/265 Subpart B (i.e., 264.10 to 264.19 and 265.10 to265.19) and includes (1) maintaining records for hazardous waste that is stored, treated,and/or disposed onsite, (2) descriptions of location,design, construction, operating methods, techniques, and practices for onsite hazardous waste storage, treatment, and/or disposal, (3)contingency plans for unanticipated damages from hazardous waste onsite storage, treatment and/or disposal, (4) maintaining qualifications offacility ownership, (5) maintaining continuity and financial responsibility of facility operation, and (6) employee hazardous waste training.According to EPA’s most recent (2009) estimate the average per-facility paperwork burdenis $27,350 per facility per year.80Applied to the383 electric utility plants which currentlydispose onsite (i.e., 84 of the 495 plantssolely dispose CCR offsite with other companies, plus 28plants solely provide CCR for beneficial uses) yields an estimated cost of ($27,350 perfacility pre year) x (383 plants whichdispose CCR) =$10.48 million/year:oIndustry share of cost: (86%) x ($10.48 million/year) = $9.01 million/yearoState government share of cost: (14%)x ($10.48 million/year) = $1.47 million/year18c. RCRA Hazardous Waste Biennial ReportRCRA Subtitle C requires hazardous waste LQG large quantity generators (40 CFR 262.41) and hazardous waste TSDF treatment, storage, anddisposal facilities (40 CFR 264.75 and 265.75) tosubmit “Hazardous Waste Report” information on a 2-year repeating cycle (aka“RCRA79$162 per year notification cost derived from EPA Information Collection Request (ICR) No. 0261.16 “Notification of Regulated Waste Activity (Renewal)”, FederalRegister, Vol.74, No.123, pages 31028-31029, 29 June2009; http://edocket.access.gpo.gov/2009/pdf/E9-15310.pdf80$27,350 per facility per year average cost derived from EPA Information Collection Request (ICR)No. 1571.09 “General Hazardous Waste Facility Standards”, FederalRegister, Vol.74, No.23, pages 6152-6154, 05 Feb 2009.81Biennial Report”). According to EPA’s most recent (2009) estimate, the average annualized per-facility response burden is $3,410 per year.81Extrapolated to 495 electric utility plants produces a cost estimate of $1.69 million per year.oIndustry share of cost: (86%) x ($1.69 million/year) = $1.45 million/yearoState government share of cost: (14%)x ($1.69 million/year) = $0.24 million/year18d. CERCLA Reportable Quantity (RQ) Spill/Leak ReportingSection 103(a) of CERCLA requires facilities and vessels to immediately notify the National Response Center (NRC) of a hazardous substancerelease (e.g., spill, leak) into the environment if the amount of the release equals or exceeds the substance’s reportable quantity (RQ) limit. Ingeneral there are five RQ categories (1, 10, 100, 1,000 or 5,000 pounds). Subtitle C options may add CCR to the CERCLA list ofhazardoussubstances and assign an RQ of one-pound, as well as allowing the use of concentrations to determine RQ thus resulting in a range of 1,294pounds to 10,000,000 pounds for 12 chemicals. Using the total count offacilities (i.e., establishments) in the US manufacturing sector (NAICS31, 32, 33) plus the US waste management sector (NAICS 562) as rough indicators, there are 315,000 industrial facilities in theUS which mayhandle RQ-listed hazardous substances.82According to EPA’s most recent (2007) estimate, the average per-facility response burden is $122(i.e., 4.1 burden hours) per facility per response, based on anaverage annual 25,861 facilitiesat an annual paperwork burdencost of $3.161million.83Relative to this 300,000 industrial facilityuniverse, this annual count of RQ-reporting facilities represents an 8% fraction.Extrapolated to the 495 electric utility plants yields a roughestimate of 40 possible RQ reports per year, at a cost of $4,900per year (i.e., (495electric utility plants) x (8% RQ reports per year) x ($122per RQ report)).oIndustry share of cost: (86%) x ($4,900/year) = $4,200/yearoState government share of cost:(14%) x ($4,900/year) = $700/yearSub-total cost item 17 (17a + 17b + 17c + 17d) = $12.94 million per year.oIndustry share of cost: (86%) x ($12.94 million/year) = $11.13 million/yearoState government share of cost: (14%)x ($12.94 million/year) = $1.81 million/yearExhibit 4Bbelow presents a summary of these “Ancillary Cost” elements numbered from 11 to 18.81$3,410 per facility per year average cost derived from EPA Information Collection Request (ICR) No. 0976.14 “2009 Hazardous Waste Report”, Federal Register,Vol.74, No.93, pages 22922-22924, 15 May 2009; http://edocket.access.gpo.gov/2009/pdf/E9-11410.pdf82315,000 industrial facilities based on “Number of Establishments” published for NAICScodes 31-33 Manufacturing (293,919 establishments) plus NAICS code 562Waste management and remediation services (21,254 establishments)from the US Census Bureau in its “2007 Economic Census.” Not all manufacturing or wastemanagement facilities necessarily handle hazardous substances so this is an over-estimate, but there are also other economic sectors (e.g., mining, construction, utilities,transporters, and wholesalers), which handlehazardous substances not included in thisfacility count which offsets this over-estimate.83$122 per facility average cost derived from EPA Information Collection Request (ICR) No. 1049.11 “Notification of Episodic Releases of Oil and Hazardous Substances(Renewal); Federal Register, Vol.72, No.205, 24 Oct 2007, pp.60357-60358;http://edocket.access.gpo.gov/2007/pdf/E7-20934.pdf82Exhibit 4BSummary of “Ancillary Cost” Estimates Associated with RCRARegulation of CCR Disposal($millions averageannualized; 2009$)Ancillary Cost ElementApplicability toCCR Regulatory OptionsElectric UtilityIndustry CostState GovernmentRCRA-AuthorizedProgram CostRow TotalCost11. Ancillary offsite disposal costs Subtitle C $76.35 $0.63 $76.9812. Impoundment structural integrity inspections Subtitle C and Subtitle D $0.96 $0.054 $1.0113. RCRA facility-wide investigations (RFIs) Subtitle C $6.9 $0.7 $7.614. RCRA facility-wide corrective action Subtitle C Not estimated –historicalaverage cost =$5.4 million perfacilityNot estimated Not est.15. RCRA TSDF waste disposal permits Subtitle C $5.8 $22.3 $28.116. RCRA enforcement inspections Subtitle C $0 $0.063 $0.06317. Future disposal unit failure cleanupremediation as RCRA hazardous wasteSubtitle C Not est. – casestudy exampleNot est. – casestudy exampleNot est.18. EPA administrative reporting & recordkeeping18a. EPA regulated waste notification18b. RCRA TSDF general facility standards18c. RCRA haz waste biennial report18d. CERCLA RQ reportingSubtitle C Subtotal= $11.13$0.005$9.01$1.45$0.0042Subtotal= $1.81$0.0008$1.47$0.24$0.0007$12.94$0.0058$10.48$1.69$0.0049Column Totals for the three options of the October 2009 draft RIA :Subtitle C hazardous waste $100.4 $25.6$126.7Subtitle D (version 1) $0.96 $0.05$1.0Hybrid C&D* $7.9 $7.7$15.6* Hybrid C&D costs for ancillary cost items13, 14, 15, 16, 17,18 are proportioned only to the158 plants with impoundments that would beregulated under Subtitle C for this option,by the proportionate multiplier: (158 plants w/impoundments) / (495 total plants) =0.319834B.3 Land Disposal Restriction Cost(for dewatering treatment of CCR)This element consists of two components:•Dry CCR disposal (landfills): Moisture conditioning and compaction to 95% maximum dry density value according to ASTM D 698 orASTM D 1557 test methods prior to disposal in landfills.•Wet CCR disposal (impoundments): Dewatering to remove solids priorto disposal in impoundments within 5-years of rule’s effective date.The potential cost for this treatment standard is estimated below.However, only the potential cost for the wet CCR disposal dewatering treatment standard is estimated in this section of the RIAbecause thepotential cost for meeting the dry CCR moisture conditioning and compaction requirements are already estimated in item 4 of the“engineeringcontrols” in thischapter above:•Examples of CCR Dewatering MethodsBased on the following recent (1997-2009) example descriptions of dry CCR disposalpractices at existingor planned coal-firedelectric utilityplants, 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.84Bottom ash will be dewatered in tanksand the water will be re-circulated to transport additional bottom ash. Bottom ash will be removed using a chain drag. The ash willthen be hauled by truck to a lined landfill offsite. The fly ashwill be conveyed in a dry state. Both ashes will be disposedin a landfillclose to the plant site.2.Pressure squeeze conveyor: Another tank-based example apparently similar tothe Basin Cooperative method is reported for drydisposal conversion by the coalmining industry, involving the Phoenix Process Equipment companysupplier of alternative slurryprocessing equipment. This second example involves a thickening tank, porous conveyorbelt and pressure to squeeze water out of thecoal washings, producing a semi-solid, 75%dewatered cake which is scraped off the conveyor belt and stacked like a pile of sand. Thecost for this process is reported at$0.50 per ton of coal waste processed.853.Horizontal belt filters: According to a May 2009 technical paper86, dewatering gypsum using horizontalbelt filters is common in theelectric utility industry, and a new modified horizontal belt filter method involvingtwo feedboxes allows fly ash and FGD (gypsum) tobe dewatered simultaneously.4.Storage silos & rail system: As described June 200987for a $10 million conversion project located at Detroit Edison’s MonroeMichigan Power Plant -- a four boiler unit, 3,200-megawatt power station originally constructed in1974. Installation of equipment tocollect the coal ash in a dry state, plusdry ash storage facilities (storage silos), and truck/rail loading equipment for distribution of thedry ash to concrete producers in the Midwest United Statesand Eastern Canada.84Source: March 2009 Basin Electric Power Cooperative examples at http://www.basinelectric.com/News_Center/Feature_Articles/Coal_ash_handling.html85Source: Dave Cooper, “Better, Safer Ways toHandle Coal Slurry Do Exist”, page 14 of the Nov 2001 “E”-Notes Newsletter of theOhio Valley Environmental Coalitionat http://www.ohvec.org/newsletters/enotes_97-01_pdf/enotes_2001_11.pdf86Source: May 2009 horizontal belt filter technical paper byAlex Hohne at http://www.flyash.info/2009/036-hohne2009.pdf87Source: June 2009 Detroit Edison Monroe Power Plant example at http://www.headwaters.com/data/upimages/press/6.30.09MonroeAshRelease.pdf845.Integrated silo system: Integrated with precipitators, vacuum pumps and bag filter/receivers, as described in an engineering report88about the 1997 dry fly ash system conversion of Northern Indiana Public Service Company’s Michigan City Plant.For this RIA, EPA ORCR identified fouralternative existing studies with costestimates (dated 1981, 1985, 2005, and 2009) comparing dry andwet CCR disposal at coal-fired electric utility plants. The first three studies provided costestimates on a per-plant basis,whereas the 2009study provided an extrapolated nationwide cost estimate. However,only the 2005 study is used inthis RIA as a basis for deriving a costestimate for the wet CCR dewatering land disposal treatment, because the first two studies are over 25-years old (1981 and 1985), and the 2009study does not provide sufficient details for verification of dataand calculations. These three other studies are summarizedbelow in thischapter to illustrate the magnitude of cost estimation uncertainty implied by the other studies, compared to the estimate derived below in thissection of the RIA.•Summary of 2005 TVA CCR Dry Disposal Cost Study•In August 2009 TVA announced a proposed plan to convert its wet CCRdisposal to dry disposal. TVA’s CEO TomKilgore said before a28 July 2009 US Congressional subcommittee hearing that TVA has developed a 5-year plan to shift CCR disposal from wetimpoundments to dry landfills. TVA estimated it will cost between$1.5 billion to $2 billion over 8 to 10 years for its 11 coal-fired electricutility plants.89Detailed or semi-detailed calculationsof TVA’s 2009 cost estimate are not available for this RIA to use for extrapolationnationwide.•However, a 2005 TVA cost estimate titled “Kingston Fossil Plant Decision Matrix: Pond or Peninsula?” provides detailed cost estimates fordry conversion of the TVA Kingston TN plant.90The TVA cost study involves conversion ofan existing impoundment currently used todispose wet fly ash and wet bottom ash at the TVA Kingston TN electric utility plant, for future dry fly ash and dry bottom ashdisposal.The FGD stream remains wet-sluiced beforeand after this hypothetical conversion in the cost study.In addition to the cost ofconvertingthe electric plant boilers and the impoundment for dry ashdisposal, the cost study also includes the cost for construction ofa new stormwater runoff management pond (Source: row item 68 of TVA’s “Appendix C Detailed Cost Sheets”, slide nr. TVA-00007403).•TVA cost study involves conversion of 475,600 cubic yards of fly ash plus bottom ash peryear; this RIA estimates this quantityisequivalent to 880,000 tons per year, assuming 1.85 tons per cubic yard multiplier.9188Source: Dec 1997 NIPSC conversion report athttp://www.babcockpower.com/pdf/rst-145.pdf89Source: TVA news release “TVA Coal Combustion Products Remediation Plan Proposed”, 20 Aug 2009 http://www.tva.gov/news/releases/julsep09/ccprp_other.htm90Source: TVA 27 January 2005 plant managers conference slide presentation (25 pages).. Wet disposal is presented as “Option 1”and dry disposal is presented as “Option2” in the TVA cost presentation. Additional details for the TVA cost estimates are available at http://www.tva.gov/kingston/tdec/pdf/TVA-00007402.pdf91"Source: 1.85 tons per cubic yard multiplier represents the midpoint from the following 1.2 to 2.5 range: According to EPA’s1988 Report to Congress (“Wastes from theCombustion 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 specific density of 1.4. The FederalHighway Administration studied fly ash for use in highway construction and reported its specific gravity may be as low as 1.7 to as high as 3.0. Conversion of this implied1.4 to 3.0 range in fly ash specific gravities to tons-per-cubic-yard as follows:oLow-end: (1.4 g/cm3) / (0.000001 m3/cm3) x (0.764 m3/yd3) / (1000 g/kg) x (2.204 lbs/kg) / (2000 lbs/short ton) = 1.2 short tons per cubic yard.oHigh-end: (3.0 g/cm3) / (0.000001 m3/cm3) x (0.764 m3/yd3) / (1000 g/kg) x (2.204 lbs/kg) / (2000 lbs/short ton) = 2.5 short tons per cubic yard.85•The TVA cost study did not estimate the costfor dewatering FGD (gypsum) because FGD isalready dewatered bymost electric utilityplants for beneficial uses, thus only fourof the 495 electric utility plants (i.e.,TVA Widows Creek plant,TVA Paradise plant, LouisvilleGas & Electric Co Trimble County plant, and Northern Indiana Public Service CompanyR.M. Schafer plant) wet dispose 1.9 milliontonsFGD per year in impoundments as of 2005 (source: column B ofExhibit 3Gof this RIA).•Unit cost (i.e., average cost perton) of conversion from wet to dry disposal estimated from the 2005 TVA cost analysis which provides costestimates for converting from wet ash disposal to dry ash disposal:TVA wet disposalTVA dry disposalAdded cost for dryUnitized dry costoCapital cost $13.12 million PV $38.45 million PV Costnot incremental $43.7/ton per year (@20 years)oAnnual O&M cost $10.63 million PV $17.51 million PV $6.88 million PV $0.60/ton (@13 years)(Note: PV = present value for TVA’s 25-year periodof analysis 2005-2029; TVA costs are in 2005$ prices)•Cost estimate calculation under conversion to dry disposal scenario, calculated based on TVA’sper-ton cost extrapolation to 22.4 milliontons per year baseline wet CCR (i.e., wet fly ash, wet bottom ash, wet FGD, wet gypsum, wet other CCR) disposal in impoundmentsat 158of the 495 electricutility plants:oCapital cost: (22.4 million tons per year wet CCR disposal for conversion at 158 plants) x ($43.7/ton per year conversion capitalcost) x (20 years capitalization period) x (1.174 price update multiplier92to 2009$ price level) = $22,984 million undiscountedcapital costAnnual equivalent capital: ($22,984 million)x (0.07246 capital recovery factor @7% & 50-years) = $1,665 million per yearoO&M cost: ($0.60/ton conversion O&M cost) x (22.4 million tons/yearwet CCR disposal for conversion at 158 plants) x (45years future operational period 2017-2061 which assumed to begin 5 years after 2012final rule promulgation) x (1.174 priceupdate multiplier to 2009$ price level)= $710 million undiscounted total O&MPV present value discounted @7% over50-years = $153 million PV present value O&MAnnual equivalent O&M: ($153 million) x (0.07246 capital recovery factor @7% & 50-years) = $11 million per yearoTotal annualized cost(capital + O&M) = ($1,665 million/year capital) + ($11 million/year O&M) = $1,676 million/year•Uncertainty in Land DisposalTreatment Cost EstimateIn addition to the 2005 Tennessee Valley Authority (TVA) cost studyreferenced above, there are three other related cost studies (1981, 1985,and 2009) which are summarized below. The first two studies provide cost estimates on a per-plant basis for a few plant sizes,and the 2009study provides a nationwide cost estimate. This RIA did not apply these other studies becausethe first two are over 25-yearsold (i.e., 1981 and1985) and the third study does not provide sufficient details for verification of dataand calculations. These studies are summarized below andused as a basis for formulating alternative nationwide cost estimates for land disposal treatment, for the purpose of illustrating the potentialmagnitude of uncertainty in this RIA’s cost estimate in relation to these other studies.921.174 price update multiplier represents 2009:to:2005 ratio in theEngineering-News Record Construction Cost Index: (8566 CCIfor July 2009) / (7297 CCI for 2005).86•Study #1 of 3: 1981 TVA/EPA•In January 1981, TVA’s Energy Demonstrations and Technology Office(Chattanooga TN) co-authored with EPA’s IndustrialEnvironmental Research Laboratory(Research Triangle Park NC) astudy titled “Economic Analysis ofWet Versus Dry Ash DisposalSystems,” Interagency Energy/Environment R&D Program Report, report no. TVA/OP/EDT-81/30 and EPA-600-7-81-013, 126 pages.93•The study compares the relative costs of wet and dry methods of coal ash disposalfor five electric plant power size categories(300 MW, 600MW, 900 MW, 1,300 MW, 2,600 MW) with annual coal ash generation ranging from 0.2 million to 1.7 million per year per plant.•Per-plant capital and O&M costs estimatedbased on 35-year assumed plant lifespan in1980$. Capital costs for (a) in-plant coal ashhandling 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 economicsbased on the method of analysis. Present worthanalysis “indicates that wet disposal is typically the least cost alternative. However, various dry disposal options are within a 15 percentrange of those costs. The costs are, in fact, sensitive to spreading the dry disposal area capital costs over the life of thepower station andthe in-plant handling system cost. Use ofeither the lower dilute phase transport systemcost or the dense phase collection system cost resultsin the dry disposal system alternative become the least cost alternative.”•The study also noted that stagedconstruction may provide 30% saving in system total cost: “[T]he above analyses assumed construction ofall the required facilities upon start-up. In the case of dry disposal, this isa reasonable assumption although site preparation costs wouldproceed during the development of the site. In the case of wet disposal, it may be economically sound to construct the embankment in stages,even if the amount of material to be placed or the engineering estimate is higher for staged construction. This is due to thehigh cost of thedam or levee and the cost of money over the life of the project.As an example... wet disposal area was analyzed for all constructionoccurring in 1980 and by a staged construction sequence (3 stages). In this case, staged construction provided a 30 percent savings in thetotal cost of the system.”•The 1981 study used two cost methods. The “Present Worth” (akapresent value PV) cost method findings (page 62) indicated thefollowingcomparative ranges in wet dry versus wet disposal costs:Disposal method1980$ cost ($/ton)2009$ update ($/ton)94Dry disposal $2.19 to $4.50 $4.81 to $9.87Wet disposal $1.86 to $5.68 $4.08 to $12.4693Source: 1981 TVA/EPA report athttp://nepis.epa.gov/Exe/ZyNET.exe/20006ORT.TXT?ZyActionD=ZyDocument&Client=EPA&Index=1981+Thru+1985&Docs=&Query=tva+wet+dry+disposal&Time=&EndTime=&SearchMethod=3&TocRestrict=n&Toc=&TocEntry=&QField=pubnumber%5E%22600781013%22&QFieldYear=&QFieldMonth=&QFieldDay=&UseQField=pubnumber&IntQFieldOp=1&ExtQFieldOp=1&XmlQuery=&File=D%3A%5Czyfiles%5CIndex%20Data%5C81thru85%5CTxt%5C00000000%5C20006ORT.txt&User=ANONYMOUS&Password=anonymous&SortMethod=h%7C-&MaximumDocuments=10&FuzzyDegree=0&ImageQuality=r75g8/r75g8/x150y150g16/i425&Display=p%7Cf&DefSeekPage=x&SearchBack=ZyActionL&Back=ZyActionS&BackDesc=Results%20page&MaximumPages=1&ZyEntry=1&SeekPage=x941980$ costs from the 1981 TVA/EPA studyupdated by EPA ORCR to 2009$ using the GDP calculator at http://cost.jsc.nasa.gov/inflateGDP.html87•Using the EPA ORCR 2009$ updated unit cost midpoints displayed above yields the following rough cost estimate for the 158 electricutility plants with CCR impoundments:oCapital cost: (22.4 million tons per year wet CCR disposal for conversion at 158 plants) x ($4.81 to $9.87 per ton dry disposalunitized present value cost) x (40.6% capital cost fraction)x (50 years period-of-analysis for this RIA) = $2,187 million to$4,488 million present value capital costAnnualized capital cost: ($2,187 million to $4,488 million) x(0.07246 capital recovery factor @7% & 50-years) = $158.5million to $325.2 million per yearoO&M cost95: (22.4 million tons per year wet CCR disposal for conversion at 158 plants) x [(($4.81 to $9.87 per ton dry disposalunitized present value cost) x (59.4% dryO&M fraction)) – (($4.08 to $12.46 per ton wetdisposal unitized present value cost)x(31.6% wet O&M fraction))] x (45 yearsdry disposal operational period 2017-2061 which assumed to begin 5 years after 2012final rule promulgation) = $1,580.5 million to $1,941.4 million present value O&MAnnualized O&M cost: ($1,580.5 million to$1,941.4 million) x (0.07246 capital recoveryfactor @7% & 50-years) = $114.5million to $140.7 million per yearoTotal annualized cost(capital + O&M) = ($158.5 million to $325.2 million per year capital) + ($114.5 million to $140.7 millionper year O&M) = $273 million to $466 million per year•Study #2 of 3: 1985 EPA•EPA’s Air and Energy Engineering ResearchLaboratory (Research Triangle Park NC) published cost estimates for both wet and dryCCRdisposal at coal-fired electricutility plants in the report “Full-Scale Field Evaluation of Waste Disposal from Coal-Fired Electric GeneratingPlants”, document nr. EPA/600/S7-85/028, August 1985, 12 pages.96•This is a 3-year study of wastecharacterization, environmental data, engineering, and cost evaluations associated with disposal of coal ashand FGD waste by six coal-firedelectricity plants ranging in nameplate capacitybetween 310 to 1,786 megawatts and located inFL, IL, MN,NC, PA, and WY. EPA used thisstudy to assist preparation ofEPA’s 1988 “Report to Congress on Wastes from the Combustion of Coal byElectric Utility Power Plants” (report no. EPA530-SW-88-002, Feb 1988).•This study developed “generic” capital and annual O&M costsfor both wet CCR pond disposal anddry CCR landfill disposal methodsinvolving fly ash, bottom ash, and FGD, based on specific costs forthe six sites combined with cost estimates from other studies by TVA,95O&M cost extrapolation calculation in this RIA for the 1981 study applies two different O&M cost percentages based on the study’s 59.4% dry disposal O&M costpercentage derived from page B-10, and on the study’s 31.6%wet disposal O&M cost percentage derived from page C-11.96Source: 1985 EPA AEERL report athttp://nepis.epa.gov/Exe/ZyNET.exe/2000TNFC.TXT?ZyActionD=ZyDocument&Client=EPA&Index=1981+Thru+1985&Docs=&Query=&Time=&EndTime=&SearchMethod=1&TocRestrict=n&Toc=&TocEntry=&QField=pubnumber%5E%22600S785028%22&QFieldYear=&QFieldMonth=&QFieldDay=&UseQField=pubnumber&IntQFieldOp=1&ExtQFieldOp=1&XmlQuery=&File=D%3A%5Czyfiles%5CIndex%20Data%5C81thru85%5CTxt%5C00000010%5C2000TNFC.txt&User=ANONYMOUS&Password=anonymous&SortMethod=h%7C-&MaximumDocuments=10&FuzzyDegree=0&ImageQuality=r75g8/r75g8/x150y150g16/i425&Display=p%7Cf&DefSeekPage=x&SearchBack=ZyActionL&Back=ZyActionS&BackDesc=Results%20page&MaximumPages=1&ZyEntry=1&SeekPage=x88EPRI, and other organizations.Exhibit 4Cbelow displays the unitized capital costs andExhibit 4Dbelow displays the unitized O&M costsfrom the study updated for this RIA to 2009 price level.•Using the 2009-updated mean unit capital and O&M cost estimates displayed inExhibit 4CandExhibit 4D, provides the following costestimates for conversion to dry disposal, based on extrapolation to 22.4 million tons per yearbaseline wet CCR (i.e., wet flyash, wet bottomash, wet FGD, wet gypsum, wet other CCR) disposal in impoundmentsat 158 of the 495 electric utilityplants which have a subtotal of180,901 MW nameplate total capacity:oCapital cost:(180,901,000 kilowatt capacity for 158 electric utility plants with surface impoundments) x ($37.60 dry conversioncapital cost per kilowatt capacity fromExhibit 4C) = $6,810 million capital costAnnual equivalent cost: ($6,810 million)x (0.07246 capital recovery factor@7% & 50-years) = $494 million/yearoO&M cost: (22.4 million tons per year wet CCR disposed in impoundments) x (-$17.40 costsavings per ton to manage for drydisposal fromExhibit 4D) = -$389 million per year O&M cost savings.oTotal average annualized cost(capital + O&M) = ($494 million/year capital cost) – ($389 million/year O&M cost savings) =$105 million per year dry conversion cost.Exhibit 4CComparison of Unitized Capital Costs for Wet and Dry CCR Disposal (Source: 1985 EPA Study; $/kW)Plant Size Categories (MW = megawatts)25050010002000Row SummaryAcross Four Size CategoriesItemDisposal OperationWet or DryCCRMinMaxMinMaxMinMaxMinMaxMinMaxMidpntMean1A Fly ash handling/processing Wet $2.3 $6.8 $1.9 $5.5 $1.5 $6.4 $1.3 $3.6 $1.3 $6.8 $4.1 $3.71B Dry $2.2 $4.1 $1.8 $3.3 $1.4 $2.7 $1.2 $2.2 $1.2 $4.1 $2.7 $2.42 Fly ash storage Dry $4.7 $8.8 $4.2 $7.7 $3.7 $6.8 $3.2 $5.9 $3.2 $8.8 $6.0 $5.63A Fly ash transport Wet $3.5 $6.4 $2.7 $5.1 $2.2 $4.0 $1.7 $3.2 $1.7 $6.4 $4.1 $3.63B Dry $0.3 $0.5 $0.3 $0.6 $0.3 $0.5 $0.2 $0.5 $0.2 $0.6 $0.4 $0.44A Fly ash placement/disposal Wet $15.1 $27.8 $12.9$23.9 $11.0 $20.5 $9.4 $17.5 $9.4 $27.8$18.6 $17.34B Dry $4.3 $8.1 $3.3 $6.1 $2.5 $4.7 $1.9 $3.6 $1.9 $8.1 $5.0 $4.35 Bottom ashhandling/processingWet/Dry $2.2 $4.6 $1.7 $3.7 $1.3 $3.0 $1.0 $2.4 $1.0 $4.6 $2.8 $2.56A Bottom ash transport Wet $3.0 $5.6 $2.4 $4.5 $1.9 $3.6 $1.5 $2.8 $1.5 $5.6 $3.6 $3.26B Dry $0.2 $0.4 $0.2 $0.3 $0.1 $0.2 $0.1 $0.2 $0.1 $0.4 $0.3 $0.27A Bottom ashplacement/disposalWet $6.4 $11.8 $5.1 $9.6 $4.2 $7.7 $3.4 $6.2 $3.4 $11.8 $7.6 $6.87B Dry $1.3 $2.4 $1.1 $2.0 $0.9 $1.6 $0.7 $1.3 $0.7 $2.4 $1.6 $1.4Summary:Wet Subtotal (1A+3A+4A+5+6A+7A) Wet (1982$) $32.5 $63.0 $26.7 $52.3 $22.1 $45.2 $18.3 $35.7 $18.3 $63.0 $40.7 $37.0Dry Subtotal (1B+2+3B+4B+6B) Dry (1982$) $15.2 $28.9 $12.6 $23.7 $10.2 $19.5 $8.3 $16.1 $8.3 $29.0 $18.7 $16.82009 Updated Wet Subtotal* Wet (2009$) $72.8 $141.1 $59.8 $117.1 $49.5 $101.2 $41.0 $79.9 $41.0 $141.1 $91.0 $82.82009 Updated Dry Subtotal* Dry (2009$) $34.0 $64.7 $28.2 $53.1 $22.8 $43.7 $18.6 $36.0 $18.6 $64.9 $41.8$37.6* Note: 2009 price update multiplier (source: ENR Construction Cost Index ratio 2009:to:1982 = 8564/3825) = 2.23989Exhibit 4DComparison of Annual O&M Costs for Wet and Dry CCRDisposal (Source: 1985 EPA Study; $/dry metric ton)Plant Size Categories (MW = megawatts)25050010002000Row SummaryAcross Four Size CategoriesItemDisposal OperationWet or DryCCRMinMaxMinMaxMinMaxMinMaxMinMaxMidpntMeanFly Ash:1A Fly ash handling/processing Wet $2.5 $6.8 $1.0 $5.4 $1.6 $4.3 $1.3 $3.6 $1.0 $6.8 $3.9 $3.31B Dry $2.5 $4.7 $2.1 $3.9 $1.7 $3.2 $1.5 $2.7 $1.5 $4.7 $3.1 $2.82 Fly ash storage Dry $3.3 $6.1 $3.0 $5.6 $2.8 $5.2 $2.5 $4.7 $2.5 $6.1 $4.3 $4.23A Fly ash transport Wet $4.2 $7.6 $3.2 $5.9 $2.5 $4.7 $2.0 $3.7 $2.0 $7.6 $4.8 $4.23B Dry $1.7 $3.1 $1.5 $2.8 $1.3 $2.5 $1.2 $2.2 $1.2 $3.1 $2.2 $2.04A Fly ash placement/disposal Wet $11.5 $21.3 $9.1 $16.8 $7.2 $13.5 $5.7$10.5 $5.7 $21.3 $13.5 $12.04B Dry $7.0 $13.0 $5.6 $10.5 $4.6 $8.5 $3.7 $6.9 $3.7 $13.0 $8.4 $7.5Subtotal fly ash Wet (1982$) $18.2 $35.7 $13.3 $28.1 $11.3 $22.5 $9.0 $17.8 $8.7 $35.7 $22.2 $19.5Dry (1982$) $11.2 $20.8 $9.2 $17.2 $7.6 $14.2 $6.4 $11.8 $6.4 $20.8 $13.6 $12.3Bottom Ash:5 Bottom ashhandling/processingWet/Dry $11.3 $22.8 $9.0 $19.1 $6.9 $15.7 $5.3 $12.8 $5.3 $22.8 $14.1 $12.96A Bottom ash transport Wet $9.2 $17.1 $7.3 $13.5 $5.6 $10.3 $4.3 $7.9 $4.3 $17.1 $10.7 $9.46B Dry $3.4 $6.3 $2.8 $5.2 $2.2 $4.1 $1.8 $3.3 $1.8 $6.3 $4.1 $3.67A Bottom ashplacement/disposalWet $9.2 $17.1 $7.9 $14.6 $6.5 $12.1 $5.4 $10.0 $5.4 $17.1 $11.3 $10.47B Dry $5.4 $10.0 $4.7 $8.8 $4.1 $7.6 $3.5 $6.5 $3.5 $10.0 $6.8 $6.3Subtotal bottom ash Wet (1982$) $29.7 $57.0 $24.2 $47.2 $19.0 $38.1 $15.0 $30.7 $15.0 $57.0 $36.0 $32.6Dry (1982$) $20.1 $39.1 $16.5 $33.1 $13.2 $27.4 $10.6 $22.6 $10.6 $39.1 $24.9 $22.8Summary (Fly Ash & Bottom Ash):Weighted average* Wet (1982$) $20.7 $40.4 $15.7 $32.3 $13.0 $25.9 $10.3 $20.6 $10.1 $40.4 $25.2 $22.4Dry (1982$) $13.2 $24.8 $10.8 $20.7 $8.8 $17.1 $7.3 $14.2 $7.3 $24.8 $16.1 $14.62009 updated weighted average** Wet (2009$) $46.4 $90.4 $35.2 $72.3 $29.1 $58.1 $23.1 $46.2 $22.6 $90.4 $56.5 $50.1Dry (2009$) $29.5 $55.6 $24.2 $46.4 $19.8 $38.3 $16.4 $31.8 $16.4 $55.6 $36.0$32.7Incremental cost from conversion to dry disposal =-$17.4Notes:* Fly:to:ash weighted average based on 2005 relative annual tonnages evaluated in the RIA: Fly ash tons/year = 15,200,000; Bottom ash tons/year = 4,300,000** 2009 price update multiplier (source: ENR Construction Cost Index ratio 2009:to:1982 = 8564/3825) = 2.23990•Study #3 of 3: 2009 USWAG•On 11 June 2009 the Utility Solid Waste Action Group (Jim Roewer, Executive Director) provided to EPA a 14-page cost study USWAGsponsored by the EOP Group Inc., containing an estimate of $39,000 million present value (PV) forconversion to dry disposal: “CostEstimates for Closure of Ash Ponds at Fossil Fuel Power Generation Facilities”, prepared in 2009by EOP Group Inc. USWAG/EOP’s$39,000 million PV estimate uses a 3% discount rate over 20 years with a 10-year implementation period, and consists of:o$12,900 million PV (33%) for fly ash andbottom ash conversion to dry disposalo$2,500 million PV (6%) for foregone sunk cost in pondso$23,700 million PV (61%) for construction ofnew wastewater plants for other non-ashancillary wastewaters (e.g., stormwater)which are currently co-mingled with the wet ash.•For purpose of comparing this estimate withthe other two cost studies above, thefollowing rough calculations extend the O&M costs fromthe 20-year period from the USWAG/EOP study, tothe 50-year period applied in this RIA:oDry management O&M cost = ($2.00 perton higher cost than wet management) x (20.6 million tons per year inimpoundments) x (40-years after 10-year impoundment phase-out) = $1,648 million (undiscounted).PV discounted @7% over 50-years = $279 million PV present valueoWaste water treatment plant (WWTP) O&M cost = ($525 millionper year) x (40-years after10-year impoundment phase-out)= $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 costestimates into the USWAG/EOP$39,000 million 20-year PV total cost estimate producesthe following 50-year based average annualized cost:oCapital cost:($39,000 million PV total cost) – ($400 million 20-year PVdry management O&M) – ($5,200 million 20-year PVWWTP O&M) = $33,400 million PV capital costAnnual equivalent capital cost: ($33,400million PV) x (0.07246 capital recovery factor @7% & 50-years) = $2,420 million peryear annualized capital costoO&M cost: ($279 million 50-year PV dry management O&M) +($3,558 million 50-year PV WWTP O&M) = $3,837 millionPV present value O&MAnnualized O&M cost: ($3,837 million PV) x (0.07246 capital recovery factor @7% & 50-years) = $278 million per year O&MoTotal annualized cost(capital + O&M) = $2,698 million per yearExhibit 4Ebelow presents a summary of the extrapolated cost estimatesbased on the per-plant cost findings from these three alternativecoststudies, compared to the cost estimate based onthe 2005 TVA cost study applied in this RIA.91Exhibit 4ESummary of Wet Conversion Cost Estimates Based on Four Alternative Studies 1981, 1985, 2005, 2009($millions updated to 2009$)ABCDE (A to D)Type of Dry ConversionCost ElementCost Study #1EPA 1981Cost Study #2EPA 1985Selected for Basisof the EstimateApplied in thisRIACost Study #3TVA 2005Cost Study #4USWAG/EOP 2009Implied Range1. Capital cost:1a. Present value (PV) = $2,187 to $4,488 $6,810 $22,984 $33,400 $2,187 to $33,4001b. Annualized equivalent* = $158 to $325 $494 $1,665 $2,420 $158 to $2,4202. Average annual O&M cost $115 to $141 -$389 savings $11 $278 -$389 savings to $2783. Total annualized cost (1b+2) $273 to $466 $105$1,676(PV** = $23,137)$2,698 $105 to $2,698Row 3 implied uncertainty range compared to estimate based on 2005 TVA study =-94% to +61%Notes:* Annualized over a 50-yearperiod @7% discount rate.** Present value computed by multiplying the annualized value by a 13.801 present value multiplier, which represents 7% discount over 50-years.•Update of Cost Estimate for Converting from Wet to Dry CCR DisposaloPurpose of Dry Conversion Cost Estimate UpdateThe purpose of this section is to update the initial estimate above in this RIA, ofthe cost of converting CCR disposal impoundments to drydisposal (i.e., landfills). The initial$23.137 billionestimate (present value discounted at 7% over50-years) presented inabove in this sectionof the RIA is based on the 2005 universe of 158 coal-fired electricutility plants (classified inNAICS code 22) with active CCR impoundmentsaddressed in EPA’s October 2009 draft RIA for the proposed rule.Exhibit 4Fbelow provides a summary ofthis initial cost estimate.97As ofFebruary 2010, the 2005 universe is the latestavailable data from the U.S. Departmentof Energy’s Energy Information Administration (EIA)Form 767 database, because the EIA temporarily suspended its electric utility industry data collection survey questionnaire torevise it.97EPA’s 2009 draft RIA cost estimate was based on an extrapolation of a cost estimate developed in 2005 by the Tennessee ValleyAuthority (TVA) for converting itsKingston TN coal-fired electric plant to dry disposal of fly ash and bottom ash. Inthe RIA, EPA (a) unitized TVA’s cost estimate on a cost-per-ton basis for both thecapital cost and annual O&M cost components, and then (b) extrapolated the unit costs to the 2005 national universe of 22.4 million tons wet disposed CCR associated withthe 158 electric utility plants with active CCR impoundments as of 2005.Exhibit 4Fbelow displays how the draft RIA timed the capital and O&M costs over the 50-yearperiod of analysis applied in the RIA (2012 to 2061), and the result of discounting the 50-year cost stream at a 7% annual rate.92Exhibit 4FPR O P O SE D R U L E OC T 200 9 R IA "O P T IO N 1" (R C R A S u b tile C 30 04x )Al l Im p o u n d m e n ts M u s t C o n v e rt to D ry A s h S y s te m in 5 -Y e a rsC a p it a l co st fo r c o n ve rs io n to d r y (n o n -d is c o u n t e d lu m p -s u m ) = $ 2 2 ,9 8 4 , 0 0 0 ,0 0 0A d d e d a n n u a l O & M f o r d r y co m p a re d to w e t (n o n -d i sc o u n te d ) = $ 1 5 , 8 0 0 , 0 0 0A B5- Year pha se -outC o u n t o f e x is ti n g 0 8 O c t 2 0 0 9 d ra ft R I Ae le c t ric u tilit y s im p le e s t im a t e ifp la n t s w ith lu m p -s u m c a p i ta l c o s tR o w Y e a r im p o u n d m e n t s i n 1 st ye a r o f fin a l ru le1201 21 5 8 $ 2 2 , 9 8 4 ,0 0 0 , 0 0 02 201 3 158 $03 201 4 158 $04 201 5 158 $05 201 6 158 $06 2 0 1 7 1 5 8 $ 1 5 ,8 0 0 , 0 0 07 2 0 1 8 1 5 8 $ 1 5 ,8 0 0 , 0 0 08 2 0 1 9 1 5 8 $ 1 5 ,8 0 0 , 0 0 09 2 0 2 0 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 0 2 0 2 1 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 1 2 0 2 2 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 2 2 0 2 3 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 3 2 0 2 4 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 4 2 0 2 5 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 5 2 0 2 6 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 6 2 0 2 7 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 7 2 0 2 8 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 8 2 0 2 9 1 5 8 $ 1 5 ,8 0 0 , 0 0 01 9 2 0 3 0 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 0 2 0 3 1 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 1 2 0 3 2 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 2 2 0 3 3 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 3 2 0 3 4 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 4 2 0 3 5 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 5 2 0 3 6 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 6 2 0 3 7 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 7 2 0 3 8 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 8 2 0 3 9 1 5 8 $ 1 5 ,8 0 0 , 0 0 02 9 2 0 4 0 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 0 2 0 4 1 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 1 2 0 4 2 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 2 2 0 4 3 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 3 2 0 4 4 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 4 2 0 4 5 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 5 2 0 4 6 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 6 2 0 4 7 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 7 2 0 4 8 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 8 2 0 4 9 1 5 8 $ 1 5 ,8 0 0 , 0 0 03 9 2 0 5 0 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 0 2 0 5 1 1 5 8 $ 2 2 , 9 8 4 ,0 0 0 , 0 0 04 1 2 0 5 2 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 2 2 0 5 3 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 3 2 0 5 4 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 4 2 0 5 5 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 5 2 0 5 6 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 6 2 0 5 7 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 7 2 0 5 8 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 8 2 0 5 9 1 5 8 $ 1 5 ,8 0 0 , 0 0 04 9 2 0 6 0 1 5 8 $ 1 5 ,8 0 0 , 0 0 05 0 2 0 6 1 1 5 8 $ 1 5 ,8 0 0 , 0 0 0N o n -d is c o u n t e d t o ta l c o s t = $ 4 6 , 6 6 3 ,0 0 0 , 0 0 0N o n -d is co u n t e d a v e ra g e c o s t = $ 9 3 3 ,0 0 0 , 0 0 0P re s e n t va lu e c o s t (@ 7 % d is c .r a te ) =$ 2 3 , 1 6 7 ,0 0 0 , 0 0 0A v e r a g e a n n u a liz e d c o s t (@ 7 % d is c .r a te ) =$ 1 ,6 7 9 , 0 0 0 , 0 0 0Dis c o u n t ra t e =7 %An n u a l e n g in e e ri n g + a n c illa r y co st s f o r R I A " O p tio n 1 " S u b t itle C = $ 5 9 5 ,0 0 0 ,0 0 0T o t a l a n n u a lize d c o s t f o r R I A " O p tio n 1 " S u b t itle C =$ 2 ,2 7 4 ,0 0 0 ,0 0 0P re se n t v a lu e c o s t (@ 7 % d is c . ra t e ) =$ 3 1 , 3 8 3 ,0 0 0 , 0 0 0PR O P O SE D R U LE OC T 200 9 R IA "O P TIO N 1" (R C R A S ubtile C 30 04x )Al l Im p o u n d m e n ts M u st C o n vert to D ry A sh S ys te m in 5 -Y e a rsC a p it a l co st fo r c o n ve rs io n to d r y (n o n -d is c o u n te d lu m p -s u m ) = $ 2 2 ,9 8 4 , 0 0 0 ,0 0 0A d d e d a n n u a l O & M f o r d r y co m p a re d to w e t (n o n -d i sc o u n te d ) = $ 1 5 , 8 0 0 , 0 0 0A B5- Year pha se -outCo u n t o f e x is ti n g 0 8 O c t 2 0 0 9 d ra ft RI Ae le c tric u tilit y s im p le e s tim a t e ifp la n t s w ith lu m p -s u m c a p i ta l c o s tR o w Y e a r im p o u n d m e n ts i n 1 st ye a r o f fin a l ru le1201 21 5 8 $ 2 2 , 9 8 4 ,0 0 0 ,0 0 02 201 3 158 $03 201 4 158 $04 201 5 158 $05 201 6 158 $06 2 0 1 7 1 5 8 $ 1 5 ,8 0 0 ,0 0 07 2 0 1 8 1 5 8 $ 1 5 ,8 0 0 ,0 0 08 2 0 1 9 1 5 8 $ 1 5 ,8 0 0 ,0 0 09 2 0 2 0 1 5 8 $ 1 5 ,8 0 0 ,0 0 01 0 2 0 2 1 1 5 8 $ 1 5 ,8 0 0 ,0 0 01 1 2 0 2 2 1 5 8 $ 1 5 ,8 0 0 ,0 0 01 2 2 0 2 3 1 5 8 $ 1 5 ,8 0 0 ,0 0 01 3 2 0 2 4 1 5 8 $ 1 5 ,8 0 0 ,0 0 01 4 2 0 2 5 1 5 8 $ 1 5 ,8 0 0 ,0 0 01 5 2 0 2 6 1 5 8 $ 1 5 ,8 0 0 ,0 0 01 6 2 0 2 7 1 5 8 $ 1 5 ,8 0 0 ,0 0 01 7 2 0 2 8 1 5 8 $ 1 5 ,8 0 0 ,0 0 01 8 2 0 2 9 1 5 8 $ 1 5 ,8 0 0 ,0 0 01 9 2 0 3 0 1 5 8 $ 1 5 ,8 0 0 ,0 0 02 0 2 0 3 1 1 5 8 $ 1 5 ,8 0 0 ,0 0 02 1 2 0 3 2 1 5 8 $ 1 5 ,8 0 0 ,0 0 02 2 2 0 3 3 1 5 8 $ 1 5 ,8 0 0 ,0 0 02 3 2 0 3 4 1 5 8 $ 1 5 ,8 0 0 ,0 0 02 4 2 0 3 5 1 5 8 $ 1 5 ,8 0 0 ,0 0 02 5 2 0 3 6 1 5 8 $ 1 5 ,8 0 0 ,0 0 02 6 2 0 3 7 1 5 8 $ 1 5 ,8 0 0 ,0 0 02 7 2 0 3 8 1 5 8 $ 1 5 ,8 0 0 ,0 0 02 8 2 0 3 9 1 5 8 $ 1 5 ,8 0 0 ,0 0 02 9 2 0 4 0 1 5 8 $ 1 5 ,8 0 0 ,0 0 03 0 2 0 4 1 1 5 8 $ 1 5 ,8 0 0 ,0 0 03 1 2 0 4 2 1 5 8 $ 1 5 ,8 0 0 ,0 0 03 2 2 0 4 3 1 5 8 $ 1 5 ,8 0 0 ,0 0 03 3 2 0 4 4 1 5 8 $ 1 5 ,8 0 0 ,0 0 03 4 2 0 4 5 1 5 8 $ 1 5 ,8 0 0 ,0 0 03 5 2 0 4 6 1 5 8 $ 1 5 ,8 0 0 ,0 0 03 6 2 0 4 7 1 5 8 $ 1 5 ,8 0 0 ,0 0 03 7 2 0 4 8 1 5 8 $ 1 5 ,8 0 0 ,0 0 03 8 2 0 4 9 1 5 8 $ 1 5 ,8 0 0 ,0 0 03 9 2 0 5 0 1 5 8 $ 1 5 ,8 0 0 ,0 0 04 0 2 0 5 1 1 5 8 $ 2 2 , 9 8 4 ,0 0 0 ,0 0 04 1 2 0 5 2 1 5 8 $ 1 5 ,8 0 0 ,0 0 04 2 2 0 5 3 1 5 8 $ 1 5 ,8 0 0 ,0 0 04 3 2 0 5 4 1 5 8 $ 1 5 ,8 0 0 ,0 0 04 4 2 0 5 5 1 5 8 $ 1 5 ,8 0 0 ,0 0 04 5 2 0 5 6 1 5 8 $ 1 5 ,8 0 0 ,0 0 04 6 2 0 5 7 1 5 8 $ 1 5 ,8 0 0 ,0 0 04 7 2 0 5 8 1 5 8 $ 1 5 ,8 0 0 ,0 0 04 8 2 0 5 9 1 5 8 $ 1 5 ,8 0 0 ,0 0 04 9 2 0 6 0 1 5 8 $ 1 5 ,8 0 0 ,0 0 05 0 2 0 6 1 1 5 8 $ 1 5 ,8 0 0 ,0 0 0N o n -d is c o u n t e d t o ta l c o s t = $ 4 6 , 6 6 3 ,0 0 0 ,0 0 0N o n -d is co u n t e d a v e ra g e c o s t = $ 9 3 3 ,0 0 0 ,0 0 0P re s e n t va lu e c o s t (@ 7 % d is c .r a te ) =$ 2 3 ,1 6 7 ,0 0 0 , 0 0 0A v e r a g e a n n u a liz e d c o s t (@ 7 % d is c .r a te ) =$ 1 ,6 7 9 ,0 0 0 , 0 0 0Dis c o u n t ra t e =7 %An n u a l e n g in e e ri n g + a n c illa r y co sts fo r R I A " O p tio n 1 " S u b t itle C = $ 5 9 5 ,0 0 0 ,0 0 0T o t a l a n n u a lize d c o s t fo r R I A " O p tio n 1 " S u b t itle C =$ 2 ,2 7 4 ,0 0 0 , 0 0 0P re se n t v a lu e c o s t (@ 7 % d is c . ra t e ) =$ 3 1 ,3 8 3 ,0 0 0 , 0 0 093oRecent Trend in CCR Impoundment Phase-OutsSince formulating the initial cost estimate above, EPA obtained new information whichindicates that many electric utility plants have alreadyclosed or are planning to close CCR impoundments and convert to dry disposal (i.e., landfill disposal and/or sell and transportdry CCR offsitefor beneficial use by other industries)for reasons independent of the CCR proposed rule. As displayed below inExhibit 4G, EIA’s historicaldata98for the electric utility industry indicate that between 1996 and 2005, the tonnage of CCR disposed in impoundments has decreased by10% from 25.2 to 22.5 million tons despite total CCR generation at electric utility plants increasing 24% over that same periodfrom 102.0million tons (1996) to 126.3 milliontons (2005). This represents an average annual CCR impoundmentphase-out rate of 1.1% per year.1996200510-year decreaseTonnage wet disposal 25.188 million 22.537 million 10%Percentage of generation 25%of CCR 18% of CCR 7%Exhibit 4GDocumentation of Recent Trend (1996-2005) In Switching From Wet to Dry CCRDisposal in the US Electric Utility IndustryCoal Ash, FGD Waste - EIA DataThousand Short TonsUtilityLandfill(Dry)UtilityDisposalPonds(Wet)On SiteUse andStorage SoldOff SiteDisposal Total %UtilityLandfill(Dry)UtilityDisposalPonds(Wet)On SiteUse andStorage SoldOff SiteDisposal Total %Fly Ash 21,450 15,710 2,446 12,091 8,110 59,806 59% 22,557 15,322 4,645 21,211 10,626 74,360 59%Bottom Ash 5,340 4,973 1,968 4,322 2,537 19,140 19% 6,109 4,374 3,553 5,767 2,177 21,981 17%Sludge 12,938 3,484 1,011 236 987 18,655 18% 9,592 1,886 467 409 2,507 14,861 12%Gypsum 502 987 379 1,190 88 3,146 3% 55 872 372 8,513 783 10,595 8%Other 171 35 0 691 305 1,202 1% 227 83 116 3,749 315 4,490 4%Total 40,401 25,188 5,804 18,529 12,028 101,950 100% 38,539 22,537 9,153 39,650 16,407 126,286 100%% Share of TotalUtilityLandfill(Dry)UtilityDisposalPonds(Wet)On SiteUse andStorage SoldOff SiteDisposal TotalUtilityLandfill(Dry)UtilityDisposalPonds(Wet)On SiteUse andStorage SoldOff SiteDisposal TotalFly Ash 36% 26% 4% 20% 14% 100% 30% 21% 6% 29% 14% 100%Bottom Ash 28% 26% 10% 23% 13% 100% 28% 20% 16% 26% 10% 100%Sludge 69% 19% 5% 1% 5% 100% 65% 13% 3% 3% 17% 100%Gypsum 16% 31% 12% 38% 3% 100% 1% 8% 4% 80% 7% 100%Other 14% 3% 0% 57% 25% 100% 5% 2% 3% 84% 7% 100%Total 40% 25% 6% 18% 12% 100% 31% 18% 7% 31% 13% 100%1996 20051996 200598Source: US Department of Energy EIA F767_PLANT databaseat: http://www.eia.doe.gov/cneaf/electricity/page/eia767.html94One important reason for this change is thatdry systems allow plants more flexibility inthe type of coal they use as fuel. For example, asplants switched from bituminous to sub-bituminous coal, they also converted to dryfly ash handling systems because the ash from some subbituminous coals has cementitious propertiesthat can cause plugging and high maintenance costs for some wet ash disposal systems, thusnecessitating dry ash systems. Also, sometypes of sub-bituminous coal fly ash arein economic demand by the cement industry because oftheir low carbon content and need to be storeddry for transport. EIA’s historical data for coal-fired electric plant fly ashdisposal confirms thissame trend away from wet disposal to drydisposal (and to beneficialreuse). In 1996, 26% of fly ash was disposed of in ponds(aka“impoundments”). This fly ash disposal method dropped to 21% in 2005.•Possible Factors Behind this CCRDry Disposal Conversion TrendIn the next few years, there will be a number of factors thatmay affect the way coal-fired plants in the electric utility industry operatethat may further encourage CCR drydisposal rather than wet disposal. Five example factors are:1.Federal regulations: EPA plans to issue a number of regulations that willaffect electric utility plants under the Clean Air Actand the Clean Water Act. For example anticipated Clean AirAct regulations will likely lead to increased use of SO2controls on existing electric utility plantsthat will increase the tonnage of fluegas desulfurization (FGD) solids that mustbeprocessed (i.e., beneficially used or disposed) and is some cases add calcium derivatives to the existing fly ash (through useof dry scrubbers). While the incremental costs of handling suchadditional materials are sitespecific, there are a number offactors that are likely to drive electricutility companies to give more consideration to dry CCR disposal. While wet disposalwas common on earlier generationsof wet scrubbers, in recentcases, some electric utility companies have focused muchmore strongly on options to reduce costs by finding beneficial uses for CCR. Furthermore, given the magnitude of theupcoming projects and growing public interest in how CCR are handled and disposed, expediting approval of the projectmay also drive towards consideration of dry disposal methods.2.State regulations: A number of state governments areconsidering programs that may affect their respective state-wideeconomic demand for electricity.3.Technology: New technologies for generation, transmission, and use of electricity arebeing introduced into the market.4.Fuel cost: Spot markets for coal make it easy for plants to fuelswitch or mix coal fuel types. This means, among otherthings that wet CCR disposal systems, becausethey limit the types of coal that theseplants can use, are likely to be furtherreduced.5.Plant property: As land availability constraints becomes more importantto electric utility plants(e.g., some electric utilityplants are located in riparian settings),on-site wet disposal areas become less important in favor of smaller footprint on-sitedry disposal landfills and sending CCR off-site for disposal or beneficial use.As electric utility companies face this myriadof changes, they are likely to be reconsidering at a very detailed level how they areoperating their plants. In fact, this is evident in the factthat some electric utility companies have already announced actual or plannedclosures of a number of coal-fired electric generator units, while other companies have announced plans to switch some units orplants95from coal to other fuels such as natural gas. This consideration of the way electric utility plants will operate is likely toinclude areconsideration of how the plants will handle and disposal CCR. Furthermore, since future air pollutionregulations are likely to causemore reassessment at electricity plants with older and less efficient air emission particulatecontrol devices and air pollution scrubbers,air regulations themselves are likely to provide further inducement to reconsider CCR disposal practices atplants that are currentlyusing wet disposal. These actions in the near future also meanthat the market and regulatoryenvironment in which these plants operatewill continue to be in flux and the ability to operate in a waythat will make them able to respond quickly to changes will beimportant.Corroborating continuation of this historical phase-out trend are recent (2009) announcements by fiveelectric utility companies (i.e., TennesseeValley Authority (TVA), Duke Energy Company,Hoosier Energy REC Inc, Vectren Southern Indiana Gas & Electric Company, and WestarEnergy Company)99that they plan to convertall or a significant portion of their CCR impoundments to dry management within the next 10years corroborates continuation ofthis recent impoundment phase-out trend. These 18 plants alone comprise 17% of the annual 22.4 milliontons CCR disposed annually in impoundments (as of 2005). In addition, three companies have announced planned coal-fired electricity plantclosures or planned switching from coal toother fuels. These three plants comprise3% of the annual CCR impoundment disposaltonnage.SeeExhibit 4Hbelow for a list of these companies, their plant names, and associated CCR impoundment disposal annual tonnages. Futuredevelopments in the electric utility industry, including compliance with upcoming Clean Air Act and Clean Water Act regulationsunderdevelopment at EPA, will increase the dry disposal conversion trend. It is inappropriate to assign the costs of these conversions to the CCRproposed rule, because they would happen anyway, in absence of the rule.99TVA’s 20 August 2009 news release “TVA Coal Combustion Products Remediation Plan Proposed” announced that TVA plans “to convert all TVA wet ash and gypsumstorage to dry...over eight to 10 years.”. Recent plans to convert from wet CCR impoundment disposal to dry landfill disposal for electric utility plants operated by theDuke Energy Company, the Hoosier ElectricCooperative, and Vectren Southern Indiana Gas & Electric Company were reported 24 October 2009 by Mark Wilson of theCourier Press “Coal Ash Disposal Varies From Company to Company” at http://btop.courierpress.com/news/2009/oct/24/coal-ash-disposal-varies-from-company-tocompany/?print=1Westar Energy apparently converted to dry fly ash management by December 2006 according to “Coal Plant O&M: Retrofit Flyash-Handling System Pays Dividends,”Douglas J. Smith, Contributing Editor, Coal Power magazine, 01Nov 2007: http://www.coalpowermag.com/transportation/Coal-Plant-O-and-M-Retrofit-Flyash-HandlingSystem-Pays-Dividends_79.html96Exhibit 4HLists of Coal-Fired Electric Utility Plants With Active CCR Impoundments (as of 2005)Which are Either Voluntarily Planning to Convert to Dry Disposalor Voluntarily Planning to Close or Switch Away from Coal to Another Fuel Source (e.g., Natural Gas)Plants With CCR Impoundments Soon Converting to Dry Disposal*Coal-Fired Electric Utility Plants Closingor Switching Away From Coal Fuel with CCR Impoundments**A B C D E F G HCompany Name Plant Name State 2005 CCRPond Tons(1,000s)***Company Name Plant Name State 2005 CCRPond Tons(1,000s)***1. PSI Energy Inc (Duke Energy) Cayuga IN 210.9 1. Progress Energy Cape Fear NC 101.32. PSI Energy Inc (Duke Energy) Edwardsport IN 11.5 2. Progress Energy Lee NC 106.13. PSI Energy Inc (Duke Energy) R Gallagher IN 125.6 3. Progress Energy L V Sutton NC 166.04. PSI Energy Inc (Duke Energy) Wabash River IN 192.1 4. Progress Energy W H Weatherspoon NC 47.05. PSI Energy Inc (Duke Energy) Gibson IN 897.8 5. Duke Energy Company Buck NC 121.96. Tennessee Valley Authority Colbert TN 29.2 6. Duke Energy Company Dan River NC 28.57. Tennessee Valley Authority Widows Creek TN 852.8 7. Northern States (Xcel Energy) High Bridge MN 0.018. Tennessee Valley Authority Paradise TN 517.9 8. Northern States (Xcel Energy) Riverside MN 6.79. Tennessee Valley Authority Shawnee TN 61.110. Tennessee Valley Authority Bull Run TN 22.411. Tennessee Valley Authority Gallatin TN 180.512. Tennessee Valley Authority John Sevier TN 10.013. Tennessee Valley Authority Johnsonville TN 53.714. Tennessee Valley Authority Kingston TN 325.915. Southern Indiana Gas &Electric Company (Vectren)F B Culley IN 35.616. Southern Indiana Gas &Electric Company (Vectren)A B Brown IN 165.817. Hoosier Energy R E C Inc Frank E Ratts IN 39.818. Westar Energy Jeffrey EnergyCenterKS 184.1Subtotal impoundment tons for 18 plants listed above = 3,916.7 Subtotal for 8 plants listed above = 577.51% of 22.4 million tons 2005 wet disposal tonnage by 158 plants =17%% of 22.4 million tons 2005 wet disposal tonnage by 158 plants =3%Notes:* EPA-ORCR identified the 18 plants with recent plans toconvert from wet to dry CCR landfill disposal for electric utility plants operated by the Duke EnergyCompany, the Vectren Company, andthe Hoosier Electric Cooperative, from the 24 October 2009 news report by Mark Wilson of theCourier Press “Coal Ash DisposalVaries From Company to Company.” . The Westar Energy plant wasidentified by an EPA-ORCR staff person based on knowledge of that specific plant or company.** EPA identified the 8 plants switching from coal from SourceWatch websites:http://www.sourcewatch.org/index.php?title=Coal_plant_conversion_projectsand http://www.sourcewatch.org/index.php?title=Existing_U.S._Coal_Plants*** Source: Based on the 2005 DOE-EIA data.97oResult of Dry Conversion Cost UpdateThe result of this dry conversion cost update is displayed below in comparison to the initial conversion cost estimate. The adjusted costincorporates theaverage annual 1.1% decreasein CCR impoundment disposal tonnage calculated based on the 1996-2005 EIA data trend aspresented inExhibit 4Gabove, relative to the 2005 base year impoundment disposaltonnage of 22.4 million tons over the same 50-year period(i.e., 2012 to 2061) applied in the RIA. This adjustment provides a declining future CCR impoundment tonnage trend which wouldbeimpacted by the CCR proposed rule when it is implemented, rather than simply assigning to the rule a dry conversion cost for the entire 2005impoundment tonnage (i.e., 22.4 million tons) aswas done in the initial cost estimate.The cost adjustment using this trend involved two steps:Step 1: Assign a dry conversion cost to the extrapolation phase-out trend(i.e., 2006 to 2061) representing what the electric utilityindustry could be expected to incur in the futurein absence of the CCR rule. The results of this 1ststep are displayed in columns A1 toA4 ofExhibit 4Ibelow.Step 2: Re-estimate the phase-out cost underthis same industry trend but by adding the requirement under the CCR rule that allremaining CCR impoundment tonnage that is notprojected to be voluntarily phased-out within 5-years of the final rule’s adoption mustbe phased-out. This step incorporates three assumptions: (a)EPA promulgates the final ruleat the start of 2012, (b) state governmentsadopt the final rule 2-years later at end of 2013, and (c) the final rule allows a 5-year phase-out period which spans 2014 to2018. Theresults of this 2ndstep are displayed in columns B1 to B4 ofExhibit 4Ibelow.98Exhibit 4IAdjustment of Dry Conversion Cost Estimate to Account for Utility Industry's Voluntary Impoundment Phase-Out TrendA1A2A3A4 B1 B2 B3 B4A. Cost of Dry Conversion Trend Without CCR RuleB. Dry Conversion Cost if Mandated by CCR RuleIncremental added Incremental addedcost year-by-year ---- Mandatory cost year-by-year ----Projected Year-by-year regression trendline Regression trendline year-by-year mandatory Mandatorytrendline RIA 50-year End Regression trendline incremental dry conversion dry conversion Mandatory wet incremental dry conversion dry conversionyear period of of wet disposal phaseout conversion to dry cost projection cumulative cost phaseout within conversion to dry cost projection cumulative costcount analysis year (million tons/year) (million tons/year) without CCR rule without CCR rule 5-years of rule (million tons/year) with CCR rule with CCR rule12005 22.5 Base year Base year Base year 22.5 Base year Base year Base year2 2006 22.2 0.3 $22,122,377 $22,122,377 22.2 0.3 $22,122,377 $22,122,3773 2007 21.9 0.3 $22,122,377 $44,244,754 21.9 0.3 $22,122,377 $44,244,7544 2008 21.7 0.3 $22,122,377 $66,367,131 21.7 0.3 $22,122,377 $66,367,1315 2009 21.4 0.3 $22,122,377 $88,489,508 21.4 0.3 $22,122,377 $88,489,5086 2010 21.1 0.3 $22,122,377 $110,611,885 21.1 0.3 $22,122,377 $110,611,8857 2011 20.8 0.3 $22,122,377 $132,734,262 20.8 0.3 $22,122,377 $132,734,2628 1201220.5 0.3 $22,122,377 $154,856,640 20.5 0.3 $22,122,377 $154,856,6409 2 2013 20.2 0.3 $22,122,377 $176,979,017 20.2 0.3 $22,122,377 $176,979,01710 3 2014 19.9 0.3 $22,122,377 $199,101,394 19.9 4.0 $298,704,663 $475,683,68011 4 2015 19.6 0.3 $22,122,377 $221,223,771 19.6 4.0 $298,704,663 $774,388,34412 5 2016 19.3 0.3 $22,122,377 $243,346,148 19.3 4.0 $298,704,663 $1,073,093,00713 6 2017 19.0 0.3 $22,122,377 $265,468,525 19.0 4.0 $298,704,663 $1,371,797,67114 7 2018 18.7 0.3 $22,122,377 $287,590,902 18.7 4.0 $298,704,663 $1,670,502,33415 82019 18.40.3 $22,122,377 $309,713,279 0 0 $0 $1,670,502,33416 9 2020 18.1 0.3 $22,122,377 $331,835,656 0 0 $0 $1,670,502,33417 10 2021 17.8 0.3 $22,122,377 $353,958,033 0 0 $0 $1,670,502,33418 11 2022 17.5 0.3 $22,122,377 $376,080,410 0 0 $0 $1,670,502,33419 12 2023 17.2 0.3 $22,122,377 $398,202,787 0 0 $0 $1,670,502,33420 13 2024 16.9 0.3 $22,122,377 $420,325,164 0 0 $0 $1,670,502,33421 14 2025 16.6 0.3 $22,122,377 $442,447,541 0 0 $0 $1,670,502,33422 15 2026 16.4 0.3 $22,122,377 $464,569,919 0 0 $0 $1,670,502,33423 16 2027 16.1 0.3 $22,122,377 $486,692,296 0 0 $0 $1,670,502,33424 17 2028 15.8 0.3 $22,122,377 $508,814,673 0 0 $0 $1,670,502,33425 18 2029 15.5 0.3 $22,122,377 $530,937,050 0 0 $0 $1,670,502,33426 19 2030 15.2 0.3 $22,122,377 $553,059,427 0 0 $0 $1,670,502,33427 20 2031 14.9 0.3 $22,122,377 $575,181,804 0 0 $0 $1,670,502,33428 21 2032 14.6 0.3 $22,122,377 $597,304,181 0 0 $0 $1,670,502,33429 22 2033 14.3 0.3 $22,122,377 $619,426,558 0 0 $0 $1,670,502,33430 23 2034 14.0 0.3 $22,122,377 $641,548,935 0 0 $0 $1,670,502,33431 24 2035 13.7 0.3 $22,122,377 $663,671,312 0 0 $0 $1,670,502,33432 25 2036 13.4 0.3 $22,122,377 $685,793,689 0 0 $0 $1,670,502,33433 26 2037 13.1 0.3 $22,122,377 $707,916,066 0 0 $0 $1,670,502,33434 27 2038 12.8 0.3 $22,122,377 $730,038,443 0 0 $0 $1,670,502,33435 28 2039 12.5 0.3 $22,122,377 $752,160,821 0 0 $0 $1,670,502,33436 29 2040 12.2 0.3 $22,122,377 $774,283,198 0 0 $0 $1,670,502,33437 30 2041 11.9 0.3 $22,122,377 $796,405,575 0 0 $0 $1,670,502,33438 31 2042 11.6 0.3 $22,122,377 $818,527,952 0 0 $0 $1,670,502,33439 32 2043 11.3 0.3 $22,122,377 $840,650,329 0 0 $0 $1,670,502,33440 33 2044 11.0 0.3 $22,122,377 $862,772,706 0 0 $0 $1,670,502,33441 34 2045 10.8 0.3 $22,122,377 $884,895,083 0 0 $0 $1,670,502,33442 35 2046 10.5 0.3 $22,122,377 $907,017,460 0 0 $0 $1,670,502,33443 36 2047 10.2 0.3 $22,122,377 $929,139,837 0 0 $0 $1,670,502,33444 37 2048 9.9 0.3 $22,122,377 $951,262,214 0 0 $0 $1,670,502,33445 38 2049 9.6 0.3 $22,122,377 $973,384,591 0 0 $0 $1,670,502,33446 39 2050 9.3 0.3 $22,122,377 $995,506,968 0 0 $0 $1,670,502,33447 40 2051 9.0 0.3 $22,122,377 $1,017,629,345 0 0 $0 $1,670,502,33448 41 2052 8.7 0.3 $22,122,377 $1,039,751,722 0 0 $0 $1,670,502,33449 42 2053 8.4 0.3 $22,122,377 $1,061,874,100 0 0 $0 $1,670,502,33450 43 2054 8.1 0.3 $22,122,377 $1,083,996,477 0 0 $0 $1,670,502,33451 44 2055 7.8 0.3 $22,122,377 $1,106,118,854 0 0 $0 $1,670,502,33452 45 2056 7.5 0.3 $22,122,377 $1,128,241,231 0 0 $0 $1,670,502,33453 46 2057 7.2 0.3 $22,122,377 $1,150,363,608 0 0 $0 $1,670,502,33454 47 2058 6.9 0.3 $22,122,377 $1,172,485,985 0 0 $0 $1,670,502,33455 48 2059 6.6 0.3 $22,122,377 $1,194,608,362 0 0 $0 $1,670,502,33456 49 2060 6.3 0.3 $22,122,377 $1,216,730,739 0 0 $0 $1,670,502,33457 50 2061 6.0 0.3 $22,122,377 $1,238,853,116 0 0 $0 $1,670,502,334Summary Relative to 2005Column total = 16.5 $1,238,853,116 $35,307,313,810 22.2 $1,670,502,334 $77,993,470,971(56 years after base year)Average annual = $630,487,747 $1,392,740,553Present value (PV) = $4,321,186,852 $12,375,281,254Annualized PV value = $309,483,860 $886,318,954Summary Relative to 2010Column total = 15.3 $1,150,363,608 $35,086,090,039 21.1 $1,582,012,826 $77,772,247,201(52 years after update)Average annual = $674,732,501 $1,495,620,138Present value (PV) = $5,426,935,463 $15,984,210,270Annualized PV value = $391,493,777 $1,153,085,179Summary Relative to 2012Column total = 14.7 $1,106,118,854 $34,842,743,891 20.5 $1,537,768,072 $77,528,901,053(50 years same as RIA)Average annual = $696,854,878 $1,550,578,021Present value (PV) =$5,962,000,000 $18,049,000,000Annualized PV value = $432,005,623 $1,307,827,824Discount rate = 7%Added Cost for Conversion to Dry Disposal Under the CCR Proposed Rule Compared to Conversion Trend Without Rule:Present value (PV) =$12,087,000,000Annualized PV value = $875,822,201Percent reduction compared to October 2009 draft RIA dry conversion cost estimate:October 2009 draft RIA cost estimate = $23,200,000,000Reduction in cost estimate compared to RIA =-48%99As summarized below in comparison to theinitial cost estimate, the updated conversion cost is the difference in the step-1 cost to the electricutility industry for continuation of the phase-out trend without the CCR rule, comparedto the step-2 cost for mandatory phase-out with the rule.Dry conversion cost: Initial cost estimateUpdated cost estimateAverage annualized cost $1.676 billion/year$0.876 billion/year (48% reduction)Present value (PV) cost $23.2 billionPV $12.1 billion PV (48% reduction)The updated cost is also presented below after integrating the updated dry conversion cost back into the overall cost of the CCR proposed rulewhich contains two other cost categories as estimated for the Subtitle C option (i.e., $491 million/year for engineering control costs + $107million/year for ancillary regulatory costs).Rule total cost: (i.e., updated dry conversion cost + engineering control cost + ancillary cost)Initial cost estimateUpdated estimateAverage annualized cost $2.27 billion/year$1.47 billion/year (35% reduction)Present value (PV) cost $31.4 billion PV$20.3 billion PV (35% reduction)As shown above, the composite effect of the two cost update factors is they reduce the initial dry conversion cost estimate by48%, and reduceby35%the overall compliance cost estimate (i.e., dry conversion cost plus engineering controlcosts plus ancillary costs).oFactors Which May Accelerate the CCR Impoundment Phase-Out TrendFor the reasons described above,it is clear that thereis a significant past and continuing trend toward CCR impoundment phase-out at electricutility plants, regardless of the CCR rule, and that this trend will continue.Described below, EPA has identifiedseven factorswhichcorroborate continuation of this impoundmentphase-out trend, some ofwhich have been quantifiedin the cost adjustment:1. Industry conversions to dry CCR disposal: This factor corroborates the phase-out trend applied in the cost update. As discussedabove, there is a documented overtwo-decade long trend 1996 to 2019away from wet CCR disposal inthe electric utility industry.This trend consists of two parts: (a) the 1996-2005 historicaldata period, plus (b) the morerecent (2009) announcements of actualconversions which occurred between 2005 and 2009, and planned conversions to occur within the next 10 years (i.e., by 2019).According to one company (United Conveyor Corporation) who has been supplying dry disposal equipment and conversion services tothe electric utility industry, the main historical drivers for this voluntary shift havebeen (1) generating dry fly ash as a saleable coproduct to other industries for beneficialuses, and (2) decreasing the volume of fly ash going to impoundments to provide greatercapacity for bottom ash. Since then, concern over possible future environmental release liabilities associated with CCR impoundments,and pressure from individual state governments, has led electricutility companies to considerdry conversion. TVA is the mostprominent example of this trend which publicly announced100in 2009 it plans to convert its wet fly ash and wet bottom ash systems to100TVA’s 20 August 2009 news release is at http://www.tva.gov/news/releases/julsep09/ccprp_other.htm100dry disposal within the next eight to 10years (i.e. by 2019). Conversions of this sort are a current trend, and they will definitelycontinue, even in the absence of the CCR proposed rule. As summarized inExhibit 4Habove (columns A to D), EPA identified 18such plants constituting17%of the industry-wide wet CCR disposaltonnage as of 2005. It is inappropriate to attribute the wet disposalphase-out cost of the CCR proposed rule toplants independently moving to dry CCR disposal. At this point, EPA expects that mostplants will choose to move to dry disposalgiven the additional factors presented below.2. Plants switching to other fuels: EPA assumes this factor is reflected in the phase-outtrend applied to the cost update. Some coalfired electricity plants have since 2005 switched, or are planning to switch, some orall of their coal-fired boilers at certain plants, fromcoal to other fuels (e.g. natural gas) for reasons unrelated to the CCR proposed rule. Insuch cases, the cost of closure of their CCRdisposal impoundments should not beattributed to the cost of the proposed rule.This factor decreases the estimated cost of the rule,and particularly EPA’s estimated future costof phasing-out wet disposalattributable to the proposed rule. For example, basedonEPA’s recent internet search, as also displayed inExhibit 4Habove (columns E to H), EPA identified8 coal-fired electric utility plantsusing impoundments (as of 2005) representing3%of wet CCR disposal by the 158 plants, whichhave or plan to switch fuels at one ormore of their coal-firedelectricity generation boilers withinone or more plants, or to closeone or more of their coal-firedboilers orentire coal-fired plants.3. Lifespan expirationof existing CCR impoundments: This factor suggests a faster futurephase-out trend than applied in the costupdate, but is not applied in the cost update. Another factor which corroborates the future continuation of the electric utility industry’svoluntary phase-out of CCR impoundments, is the fact that existing (i.e., active, operational)CCR impoundments have distinctoperational lifespans. When an impoundmentreaches its end-of-lifespan, the electric utility plant must in that future year either addnew impoundment capacity by installing another impoundment, or convert to dry disposal by installing a landfill (or providing theirannual CCR for beneficial uses). For purpose ofestimating the “engineering cost” component (inChapter 4of this RIA), EPAassigned impoundment lifespan start years (i.e., year in which impoundment construction was completed and began receiving CCR),and future expected impoundment operationallifespan closure years, to each of the158 coal-fired plants with operational CCRimpoundments (as of 2005) identified in this RIA. For the most part, the impoundment start years were based on actual industryreported data from the references cited in this RIA. However,expected closure years were provided by industry for 78 of the 158plants; thus, EPA assigned expectedclosure years to the remainder 80 plants assuming a 40-year lifespan.Exhibit 4Jbelow presents asummary of the expected future closure years in relation to the remaining lifespanyears and associated impoundment tonnages whichare expected to reach end ofoperational lifespan in absence of the CCR rule.This summary indicates that all existing CCRimpoundments could be expected to reachend-of-lifespan by year 2051, and that20%of impoundments will have reached end-oflifespan by year 2018. According to the costupdate assumptions discussed in the 2ndupdate steps of prior section above, year 2018represents the 5thyear of the CCR final rule’s assumed 5-year phase-out period spanning 2014 to 2018, which also assumes the CCRfinal rule is promulgated by EPA at the start of 2012 and thatstate governments will adopt the rule 2-years later by the end of 2013.This lifespan expiration trend corroborates the assumed continuation ofthe phase-out trend depicted inExhibit 4I(column A1) whichindicates that17%of CCR impoundment tonnage may be expected to havephased-out by year 2018 (i.e., 18.7 million tons remainingby 2018 compared to 22.5 million tons in the analysis base year2005) in absence of the CCR rule.In fact, given that end-of-lifespanprovides companies with a low-cost opportunityto convert to dry disposal, the higher 20%end-of-lifespan percentage compared to the10117% phase-out trend suggest the future phase-out trend may beaccelerated compared to the 1.1% annual phase-out assumed based onthe 1996-2005 trend. For example, this result suggests that by 2018 the annual phase-out rate in that year could be1.3%(i.e.,(20%/17%) x 1.1%)).4. EPA’s Clean Air Act emissions standards:This factor is not quantified in the cost update. Whereexisting coal-fired electricutility plants put in new air emission scrubbing systems, EPA believes they will overwhelmingly rely on CCR management systemsthatdo not require wet disposal impoundments. Two of EPA’s upcomingClean Air Act (CAA) air pollution regulations may lead some coalplants to begin using large amounts of reagent to capture SO2 from boiler flue gas:•EPA’s Clean Air Mercury Rule (CAMR) which was vacated by the DC Circuit Court in 2007 compels EPA under the CAA Section112 to issue maximum achievable controltechnology (MACT) regulations for coal- and oil-fired electric utility units:http://www.epa.gov/ttn/atw/utility/utilitypg.html•EPA’s remanded Clean Air Interstate Rule (CAIR) was also vacated by the DC Circuit Court in 2007 but was later reinstated andremanded back to the Agency for further review/clarification: http://www.epa.gov/cairSuch plants would likely experience a significant increase in theamount of fly ash or wet FGD waste tonnage to be disposed, becausethe reactants are either captured with thefly ash or with the wet FGD waste. If these plants currently dispose of bottom ash,fly ash, orwet FGD waste in wet impoundments, the likelihood of significantly increased future disposal tonnages may prompt them to consider aswitch to dry disposal. Therefore, new CCRgenerated as a result of new Clean Air Act emissions requirements are very likely to causeplants to switch away from wet disposalindependent from the CCR proposed rule. EPAhas not quantified this factor for purposeofupdating the 2009 RIA regulatory costestimate in this RIA.5.EPA’s Clean Water Act effluent standards: This factor is not quantified in the cost update. EPA is currently developing newindustrial wastewater effluent regulations for coal-firedelectricity plants. These new regulations are likely to tighten significantlyexisting effluent limits. These new regulations will be one morefactor likely to influence plants to switch to dry disposal systems.6. State government implementation of rule: This factor is quantified inthe cost update. It recognizesthat states require two yearsfor their state legislatures or environmental regulatory programs to adopt new RCRA regulations such as the CCR final rule, which isnecessary for the rule to become federallyenforceable. In the initial cost estimate, EPA assumed that the CCR final rule would becomeeffective (i.e., adopted by states) in year 2012 and that dry conversion capital costs would allbe incurred in that single year. In contrastto that simple cost estimation framework, this cost update factor pushes the dry conversion cost2-years out into the future beginning in2014. The 5-year allowed dry conversion (i.e., impoundment phase-out) period is thus2014 to 2018. In reality, there is a furtherdistinction to be made. For states which operate EPA-authorizedRCRA regulatory programs (as of2005, EPA-authorized statescomprise 97% of the 22.4 million tons annual CCR impoundment disposal tonnage), they could have2-years adoption period. However,in non-authorized states (i.e., AK, IA),territories, and Indian country, the CCR rule becomes effective in 2012 by fact that EPA willimplement it directly. According to the 2005 EIA data, in this 2ndgroup there are four plants withimpoundments in IA plus one plant102with impoundment(s) on tribal land totaling 3% ofthe 22.4 million tons impoundment disposal in 2005.101Because this 2ndgroup onlycomprises a very small 3% fraction of the annual CCR impoundment disposal tonnage, and to avoidadding another layer of complexityto the cost update which would only resultin a very small (i.e., <5%) difference inupdated estimate, the cost update does notseparatelycalculate costs for both groups addressing under this factor, but applies implementation year to the entire 22.4 million tonnage. This 2-year final rule adoption cost-timing adjustment factor is highlighted inExhibit 4Iabove.7. 5-year impoundment phase-out period: This factor is quantified inthe cost update. It recognizesthat electric utility plants arelikely to incur dry conversion capital costs spread across eachof the years in the CCR rule’s5-year mandatedphase-out period, ratherthan incurring all dry conversion capital costin one year as was simply assumed in the initial cost estimate. This cost-timing adjustmentfactor is highlighted inExhibit 4Iabove.101As of 2005, the four IA plants are the George Neal North plant (50,200 tons/yearCCR impoundment disposal), the Lansing plant(24,000 tons/year), the Louisa plant(23,000 tons/year), and the Walter Scott Jr Energy Center plant (104,000 tons/year). The one plant located on tribal land is the Four Corners plant in NM (501,400tons/year).103Exhibit 4JRIA 50-yearperiodActual companyplanned or EPAestimated pondclosure yearCCR pond endof lifespan(tons/year)Cumulative pondlifespan end(tons/year)% pondtonnagephaseout2009 Total 0 0 0%2010 Total0 0 0%2011 Total 0 0 0%12012 Total481,300481,3002.1%2 2013 Total 40,400521,7002.3%3 2014 Total 634,7001,156,4005.2%4 2015 Total 599,4501,755,8507.8%5 2016 Total 2,021,7003,777,55016.9%6 2017 Total 189,3003,966,85017.7%72018 Total513,4004,480,25020%8 2019 Total 838,4005,318,65023.7%9 2020 Total 1,969,1607,287,81032.5%10 2021 Total 183,1007,470,91033.4%11 2022 Total 661,7008,132,61036.3%12 2023 Total 410,8008,543,41038.1%13 2024 Total 39,0008,582,41038.3%14 2025 Total 477,7009,060,11040.4%15 2026 Total 280,9009,341,01041.7%16 2027 Total 27,6009,368,61041.8%17 2028 Total 134,0009,502,61042.4%18 2029 Total 36,2009,538,81042.6%19 2030 Total 527,10010,065,91044.9%20 2031 Total 170,35010,236,26045.7%21 2032 Total 327,40010,563,66047.2%22 2033 Total 746,50011,310,16050.5%23 2034 Total 594,10011,904,26053.1%24 2035 Total 473,00012,377,26055.3%25 2036 Total 322,00012,699,26056.7%26 2037 Total 742,80013,442,06060.0%27 2038 Total 476,10013,918,16062.1%28 2039 Total 825,90014,744,06065.8%29 2040 Total 642,05015,386,11068.7%30 2041 Total 1,009,10016,395,21073.2%31 2042 Total 141,60016,536,81073.8%32 2043 Total 992,01017,528,82078.3%33 2044 Total 505,70018,034,52080.5%34 2045 Total 104,40018,138,92081.0%35 2046 Total 338,00018,476,92082.5%36 2047 Total 326,80018,803,72083.9%37 2048 Total 575,80019,379,52086.5%38 2049 Total 788,30020,167,82090.0%39 2050 Total 2,075,70022,243,52099.3%40 2051 Total 121,90022,400,000100.0%Column total (2005 base) =22,400,000Projection of Future CCR Pond Lifespan Closure Tonnage-5,000,00010,000,00015,000,00020,000,00025,000,000 20 1 2 To t al 20 1 4 To t al 20 1 6 Total 20 1 8 Total

2 02 0 Total

2 02 2 T o t a l

2 02 4 T o t a l

2 02 6 T o t a l 2028 Total 2030 To t a l 2032 To t al 2034 Total 2036 Total 2038 Total

2 04 0 Total

2 04 2 T o tal

2 04 4 T o t a l 2046 Total 2048 Total 2050 TotalProjection of Future Percentage of 2005 CCR Pond Disposal LifespanClosure0%10%20%30%40%50%60%70%80%90%100%

2 01 2 Total 2 01 4 T o t a l 2 0 1 6 T otal 2018 Total 2 020 Total 2 022 To t a l 2 0 24 Tot a l 2026 Total 2028 Total 2 0 30 T o t a l 2032 T o t a l

203 4 T otal

2 03 6 T otal 2 0 38 T o t a l 2 0 40 Total 2042 Total 2 04 4 Total 2 04 6 T o t a l 2 0 48 Tot a l 2050 T otal104Exhibit 4Kbelow summarizes the above regulatory cost estimates on an incremental basis (i.e., without including the “Baseline Costs”estimated inChapter 3of this RIA).Appendix Jpresents regulatory costs estimates for each of the 495 electric utility plants.Exhibit 4KSummary of Cost Estimates for the October 2009 Draft RIA Regulatory Options($millions in 2009 price level; average annual amortized @7% discount rate over 50-year period 2012 to 2061)RCRA Regulatory Cost ElementSubtitle CHazardous wasteSubtitle D(version 1)Hybrid C&DA. Engineering Controls (onsite):$491$491$4911. Groundwater monitoring $13 $13 $132. Bottom liners $95 $95 $953. Leachate collection $8 $8 $84. Fugitive dust controls $5 $5 $55. Water runon/runoff controls $2 $2 $26. Financial assurance $30 $30 $307. Disposal unit location restrictions $76 $76 $768. Closure capping to cover unit $255 $255 $2559. Post-closure groundwater monitoring $2 $2 $210. Storage design & operating standards Not estimated in thisRIA Not estimated in this RIA Not estimated in this RIAB. Other Ancillary Costs:$107$1$911. For offsite disposal (11a+11b+11c) =11a. RCRA manifest cost11b. Added operation for hazmat truck11c. Offsite LF RCRA Subtitle C permit$77$66$8$3$0Not relevantNot relevantNot relevant$0(offsite applies only to LFsso no incremental cost overbaseline)12. Structural integrity inspections $1 $1 $113. RCRA facility-wide investigation $7.6 Not relevant $2.414. RCRA facility-wide corrective action Not estimated in this RIA;historical average =$5.4 million per caseNot relevant Not estimated in this RIA;historical average =$5.4 million per case15. RCRA TSDF haz waste disposal permit $7 Not relevant $216. RCRA enforcement inspection $0.06 $0 $0.0217. Future added cleanup cost as “hazardous waste” Not estimated in this RIA:case studies indicate possible$18 to $376 million per caseNot relevant Not estimated in this RIA;case studies indicate possible$18 to $376 million per case18. EPA paperwork reporting/recordkeeping $13 Not relevant $4C. Land Disposal Restriction Dewatering Treatment$876 (updated)$876 (updated)$876 (updated)TOTAL ANNUALIZED COSTS(A+B+C) =Average cost per-ton (94.2 million tons disposed) =Average cost per-plant (467 disposing plants) =$1,474 per year (updated)($15.65 per ton)($3.16 million per plant)$1,368 per year (updated)($14.52 per ton)($2.93 million per plant)$1,376 per year (updated)($14.61 per ton)($2.95 million per plant)Note:Chapter 6of this RIA scales these cost estimates based on the October 2009 draft RIAoptions, to the 2010 regulatory options.1054C. State-by-State Distribution ofIncremental CCR Regulatory CostsExhibit 4Lbelow summarizes the distribution of estimated regulatory costs on a state-by-statebasis and by option. This state-by-statesummary is based on apportionment of nationwide average annualizedcost estimated for each regulatory option, according to state-by-stateannual CCR tonnage generated by the 495 coal-fired electricutility plants.Exhibit 4LState-by-State Distribution of Estimated Incremental Costs for the October 2009 Draft RIA Regulatory Options($million average annualized cost in 2009$ over 50-year period of analysis 2012 to 2061)ABCDEFGHItemState# of coalfiredelectricityplants2005 CCRgeneration bycoal-fired electricutility plants(tons/year)State % ofnationwide CCRgeneration(based onColumn D)Subtitle CHazardous wasteSubtitle D(version 1)Hybrid C&D:Subtitle C impoundmentsSubtitle D landfills1 AK 2 46,179 0.03% $0.4 $0.4 $0.42 AL 16 3,210,337 2.27% $33.5 $31.1 $31.23 AR 4 744,267 0.53% $7.8 $7.3 $7.34 AZ 8 3,334,030 2.36% $34.8 $32.3 $32.55 CA 6 159,927 0.11% $1.6 $1.5 $1.56 CO 12 1,704,433 1.21% $17.8 $16.6 $16.67 CT 0 172,280 0.12% $1.8 $1.6 $1.78 DC 0 0 0.00% $0.0 $0.0 $0.09 DE 2 251,205 0.18% $2.7 $2.5 $2.510 FL 15 6,132,345 4.34% $64.0 $59.4 $59.711 GA 13 6,077,700 4.30% $63.4 $58.9 $59.212 HI 1 58,968 0.04% $0.6 $0.5 $0.613 IA 15 1,136,289 0.80% $11.8 $11.0 $11.014 ID 0 0 0.00% $0.0 $0.0 $0.015 IL 17 3,856,748 2.73% $40.2 $37.4 $37.616 IN 33 8,798,845 6.23% $91.8 $85.3 $85.717 KS 8 1,495,099 1.06% $15.6 $14.5 $14.618 KY 31 9,197,567 6.51% $96.0 $89.1 $89.619 LA 3 1,614,800 1.14% $16.8 $15.6 $15.720 MA 0 363,150 0.26% $3.8 $3.6 $3.621 MD 4 1,932,740 1.37% $20.2 $18.8 $18.922 ME 1 48,000 0.03% $0.4 $0.4 $0.423 MI 24 2,369,673 1.68% $24.8 $23.0 $23.124 MN 20 1,525,979 1.08% $15.9 $14.8 $14.925 MO 20 2,679,742 1.90% $28.0 $26.0 $26.126 MS 6 1,229,400 0.87% $12.8 $11.9 $12.0106Exhibit 4LState-by-State Distribution of Estimated Incremental Costs for the October 2009 Draft RIA Regulatory Options($million average annualized cost in 2009$ over 50-year period of analysis 2012 to 2061)ABCDEFGHItemState# of coalfiredelectricityplants2005 CCRgeneration bycoal-fired electricutility plants(tons/year)State % ofnationwide CCRgeneration(based onColumn D)Subtitle CHazardous wasteSubtitle D(version 1)Hybrid C&D:Subtitle C impoundmentsSubtitle D landfills27 MT 5 1,830,624 1.30% $19.2 $17.8 $17.928 NC 27 5,504,531 3.90% $57.5 $53.4 $53.729 ND 9 3,038,100 2.15% $31.7 $29.4 $29.630 NE 6 614,473 0.44% $6.5 $6.0 $6.131 NH 1 176,900 0.13% $1.9 $1.8 $1.832 NJ 2 735,214 0.52% $7.7 $7.1 $7.233 NM 4 3,983,300 2.82% $41.6 $38.6 $38.834 NV 2 391,500 0.28% $4.1 $3.8 $3.935 NY 11 1,479,792 1.05% $15.5 $14.4 $14.436 OH 24 10,429,446 7.39% $108.9 $101.2 $101.737 OK 3 1,490,800 1.06% $15.6 $14.5 $14.638 OR 1 99,900 0.07% $1.0 $1.0 $1.039 PA 28 15,359,680 10.88% $160.4 $148.9 $149.740 RI 0 0 0.00% $0.0 $0.0 $0.041 SC 14 2,178,360 1.54% $22.7 $21.1 $21.242 SD 2 103,753 0.07% $1.0 $1.0 $1.043 TN 12 3,240,120 2.29% $33.8 $31.4 $31.544 TX 18 13,165,728 9.32% $137.4 $127.6 $128.245 UT 7 2,582,144 1.83% $27.0 $25.1 $25.246 VA 13 2,388,526 1.69% $24.9 $23.1 $23.347 VT 0 0 0.00% $0.0 $0.0 $0.048 WA 1 1,405,220 1.00% $14.7 $13.7 $13.849 WI 12 1,412,534 1.00% $14.7 $13.7 $13.850 WV 20 9,231,718 6.54% $96.4 $89.5 $90.051 WY 12 2,224,848 1.58% $23.3 $21.6 $21.7Totals =495141.2 million100%$1,474/year$1,368/year$1,376/year1074D. Cost Estimation UncertaintyThis section addresses OMB’s 2003 CircularA-4 “Regulatory Analysis” guidance (page 40)requirement for RIAs involving rules withexpected annual economic effects of $1 billion or more, to present a formal quantitative analysis of the uncertainties about benefit and costestimates. This section only addresses uncertainties with respect to cost estimates for both baseline cost and incremental costs for theregulatory options. Thissection first presentsthree specific examplesof data quality uncertainty factors in this RIA, followed by anoveralluncertainty factorto represent all such specific data qualityuncertainty factors combined (the threefactors below are not additive across theirlow- and high-end percentage range endpoints because such simple addition wouldrepresent unlikely compounding of these factors):•Specific Examples of Data QualityUncertainty Factors in This RIA1.CCR tonnage data:The baseline andregulatory cost estimates in this RIA are based on the annualCCR disposal and beneficial usetonnages reported by electric utilityplants to the 2005 DOE-EIA Form 767database. However, the DOE-EIA 767data reporting form102does not provide respondents witha definition for the “tons” collected in Schedule 3 of thedata reporting form. Because there are three numerical definitions of “ton” commonly usedin the US (i.e., short-ton= 2,000 pounds, long-ton = 2,200 pounds; and metric ton = 2,205 pounds), this factor potentially introduces-20% to+20%uncertainty range. For purpose of consistency withthe use of short-tons in most EPA RCRA programreports,103this RIA interprets CCR “tons” as short-tons.2.Data sources: Also with respect to CCR tonnage data, this RIA cites multiple possiblesources of data based on different publishedsources. For example, as displayed inExhibit 4Dof this RIA, one source (American Coal Ash Association)provides an industry survey-based estimate of CCR generation by electric utility plants in 2005 of 123.1 million tons.Whereas this RIA estimates 141.2 million tons CCR generation in 2005 based on data from the 2005 DOE-EIA Form767 database for plants >100 MW in size and based on supplemental estimates made in this RIA for <100 MW sizeplants. This data source inconsistency factor represents-13% to +15%uncertainty range.3.Data years: Information and data used to evaluate and estimatethe cost of baseline CCR disposal practices are from variouspublished sources dated 1995, 1996, and 2006. Furthermore, unit costs for CCR disposal unit engineering controlsapplied in this RIA are from different published data years such as 2000, 2004, and 2007. This RIA updatedhistorical data to 2009 price levels using various indexes, some of which werespecific to a particular type of unitcost, and other indexes were general (e.g.,GDP Price Deflator). The uncertaintyin accuracy of unit costs introducedby use of historical data isnot quantified.•Overall Data Quality Uncertainty Range102Instructions to the 2005 DOE-EIA Form 767 data reporting questionnaire (24 pages) are available athttp://www.eia.doe.gov/cneaf/electricity/forms/eia767/eia767instr.pdfA copy of the 2005 DOE-EIA 767 data reporting questionnaire (16 pages) is available at http://www.eia.doe.gov/cneaf/electricity/forms/eia767/eia767.pdf103One example of the standardized use of “short-tons” in EPA RCRAprogram reports is the RCRA Biennial Hazardous Waste Reports which are archived athttp://www.epa.gov/waste/inforesources/data/biennialreport/index.htm108The method applied to characterize the overalllevel of quantitative uncertainty in the cost estimates of this RIA, is based onthe 02 February2005 “Recommended Practice No. 18R-97: Cost Estimate Classification System as Applied inEngineering, Procurement, and Construction forthe Process Industries”104. This method is specifically applicable to cost estimates developed for mechanical and chemical process equipmentused for engineering, procurement and construction across a widevariety of industries includingthe electric utility industrysector (i.e., NAICScode 22). As summarized inExhibit 4Mbelow, this cost estimate classification systeminvolves five estimation categories (i.e., Class 1, Class2, Class 3, Class 4, Class 5) reflecting different relative (a) levels ofcost definition, (b) purposesand uses of cost estimates, (c) cost estimationmethodologies, (d) expected accuracy ranges, and (e)degrees of cost estimate preparation effort.Exhibit 4MSummary of Cost Estimation Classification System for Characterizing DataQuality Uncertainty in this RIAEstimateCategoryLevel of Detail(Quantity of Input Information & Data)Level of Effort(Time Required to Complete the Cost Estimate)Expected AccuracyRangeClass 5Very limited information (e.g., little more than proposed projecttype, location, and capacity).Very limited amount of time and with little effort, sometimesrequiring less than one hour FTE to prepare the cost estimate.-50% to +100%Class 41% to 5% complete, limited information (e.g., preliminaryengineered process and equipment lists) for purpose of alternativesanalysis, screening analysis, or demonstration of economicfeasibility.Sometimes requiring up to two months FTE for preparing thecost estimate.-30% to +50%Data quality uncertainty range applied in this RIA (i.e., between Class 3 and Class 4) =-25% to +40%Class 310% to 40% complete, semi-detailed information (e.g., processflow diagrams, equipment diagrams, layout drawings, engineeredprocess and equipment lists).May require up to nine months FTE to prepare the costestimate. -20% to +30%Class 2 30% to 70% complete, detailed information May require upto 1.5 years FTE to prepare the cost estimate. -15% to +20%Class 150% to 100% complete and full project definition (e.g., virtually allengineering and design documentation/plans)May require up to or over three years FTE to prepare the costestimate.-10% to +15%Because the bulk of the data collection andanalysis presented in this RIA was executed in a relatively short time (i.e., fivemonths) using semidetailed information for baseline CCR disposal conditions, disposal unit costs, and engineeringcontrol and ancillary costs forthe regulatoryoptions, the level of numerical uncertainty for the baseline cost and incremental costs for eachof the regulatory options estimated in this RIAmay be classified between a Class 3 and Class 4 type ofestimate (i.e., -25% to +40%), as displayed below inExhibit 4N.These uncertaintyranges represent a probability distribution about the cost estimates, and may be interpreted as the expected values (i.e., bestestimates) and lowend and high-end ranges about each cost estimate. Such quantitative indicators of uncertainty are identified in OMB’s CircularA-4 (pages 40,41) as acceptable for characterizing probability distributions for cost estimates involving major rules with possible annual economic effects of$1 billion or more for one or more regulatory options.104Recommended Practice No. 18R-97 (10 pages) published by the Association for the Advancement of Cost Engineering at: http://www.aacei.org/technical/rps/18r-97.pdf109Exhibit 4NCost Estimation Uncertainty with Overall Data Quality Uncertainty Factor Applied to the October 2009 Draft RIA Options($millions in 2009$)Cost Estimate Uncertainty IndicatorSubtitle CHazardous wasteSubtitle D(version 1)Hybrid C&D:Subtitle C for impoundmentsSubtitle D for landfillsBest estimate (w/updated LDR cost):$1,474/year (updated)$20,343 PV$1,368/year (updated)$18,880 PV$1,376/year (updated)$18,990 PV-25% uncertainty low-end $1,106/year$15,264 PV$1,026/year$14,160 PV$1,032/year$14,243 PV+40% uncertainty high-end $2,064/year$28,485 PV$1,915/year$26,429 PV$1,926/year$26,581 PVNote:PV = present value of averageannualized cost over 50-years @7% discount rate, calculated by multiplying the average annualizedcost by thepresent value factor = 13.801.Note:Chapter 6of this RIA scales these estimated costs based on the October 2009 draft RIA, to the 2010 regulatory options.110Chapter 5Potential Benefits of RCRA Regulation ofCCR Disposal in theElectric Utility IndustryExhibit 5Abelow displays social benefits associated with EPA’s RCRA regulatory program, a fewor many of which may be associated withany particular RCRA regulation. To a lesseror greater degree, a range of these benefit elements may be associated with futurebenefits fromRCRA regulation of CCR disposal, according to the unique physical and environmentalattributes at any particular CCR disposal site.Exhibit 5AHuman Health, Environmental, & Economic Benefits of the EPA RCRA Regulatory Program*Benefit Category (n = 6)Benefit Sub-ElementExamples (n = 36)1. Human Health ProtectionBenefits1A. Mortality Reduction-Examples1)Reduced risk of cancer fatality2)Reduced risk of acute fatality1B. Morbidity reduction-Examples1)Reduced risk of cancer2)Reduced risk of morbidity (e.g., asthma, nausea)2A. Market Ecological Values:1)Commercial fisheries2)Market recreational benefits(e.g., involving fees)3)Food4)Fuel5)Fiber6)Timber7)Fur/leather2. Ecological Protection Benefits2B. Non-Market Ecological Values & Amenities (examples):1)Non-market recreational benefits (e.g., w/out fees)2)Non-use values: existence, bequest, and quasi-optionvalues3. Indirect Ecosystem &Resource Conservation Benefits1)Climate moderation2)Flood moderation3)Groundwater recharge4)Sediment trapping5)Soil retention6)Nutrient cycling7)Pollination by wild species8)Biodiversity9)Water filtration10)Soil fertilization11)Pest control12)Reduced pressure on endangered species13)Avoided habitat destruction4. Avoided Economic Costs 1)Avoided costs of providing government mandatedalternate drinking water supplies2)Avoided costs associated with government mandatedcleanups of industrial waste accidents or spills5. Avoided Materials Damages,Improved Aesthetics, &Historical Preservation1)Aesthetic pleasure2)Improved taste, order, visibility3)Protection of resources with cultural and historic value4)Protection of constructed resources (e.g., buildings,infrastructure)6. Potential Long-Term Benefits(Sustainability)1)Avoided increases in damages related to changes inaffected populations2)Benefits associated with resource conservation3)Benefits associated withthe precautionary principle,protection from unforeseen issues4)Benefits from long-term increases in the value ofenvironmental quality* Source: Exhibit 1-1 of EPA Office of Solid Waste, “Approachesto Assessing the Benefits, Costs,and Impacts of the RCRA Subtitle C Program,” prepared byIndustrial Economics Inc., October 2000,111In contrast to theExhibit 5Alist of RCRA regulatory program benefits, because of time, data, and methodological limitations, the regulatorybenefits estimated in this RIA do not represent a complete list of expected benefitsof the CCR proposed rule. For example, the benefitsanalysis in this Chapter of the RIA does notestimate benefits of (a)reducing cancer risks associatedwith preventing direct effluent dischargesof CCR to surface waters, (b) ecological andecosystem benefits, (c) off-site CCR disposal regulatory benefits, or (d) non-cancer human healthprotection benefits. In contrastto this large number of possible benefit elements, this RIA monetizesonly three benefit categories consisting offive sub-elements.1.Groundwater Protection Benefits at CCR Disposal Sitesa.Human health protection benefits (i.e., benefitof preventing cancer from arsenic exposure)b.Groundwater remediation costs avoided2.CCR Impoundment Catastrophic Failure Benefitsa.Future cleanup costs avoided3.Benefits from Increase inFuture CCR Beneficial Usesa.Direct market benefits (economic benefits)b.Lifecycle social benefits (economic + environmental benefits)These monetized benefits are based on EPA’sinitial analysis using existing information and analytical techniques. EPA requests publiccomment on all data sources and analytical approaches usedin estimating the benefits presented in this Chapter.5A. Groundwater ProtectionBenefits (Avoided Future Cancer Risks & Groundwater Remediation Costs)This section estimates the potential future benefits of reducedhuman cancer risks and avoidedgroundwater contamination remediation costsassociated with controlling arsenic from onsite CCR landfills and surface impoundments. The estimates are based on EPA’s riskassessment,which predicts leaching behavior using SPLPand TCLP data. Recent research and damagecases indicate that these leaching testsunderestimate risks from dry disposal.105Human cancer risks avoided are based on the individual “excess” lifetime cancer probabilities estimatedbelow. This estimation follows an 8-step method which begins bycharacterizing the cancer risks and expected number of futurecancer risksfrom arsenic releases to groundwater fromCCR landfills and surface impoundments in theabsence of EPA or state action. It then proceeds tomonetize these cancers using accepted economicpractices. Next, a baseline is established for the operation of state regulatory and remedial105Recent EPA research demonstrates that CCR can leach significantly more aggressivelyunder different pHconditions potentiallypresent in disposal units. In a 2009EPA study of 34 electric utility plants, CCR from 19 facilities exceeded at least one of the 40 CFR Toxicity Characteristic regulatory values for at least one type of CCR(e.g., fly ash or FGD residue) at the self-generated pH of the material (source: EPAOffice of Research & Development, “Characterization of Coal Combustion Residuesfrom Electric Utilities – Leaching and Characterization Data,” EPA-600/R-09/151. Office of Research and Development, Air Pollution Control Division. Research TrianglePark, NC. December 2009). This behavior likely explains therapid migration of chemical constituents from CCR disposal sites like Chesapeake, VA and Gambrills, MD.See also EPA “Characterization of Mercury-Enriched Coal Combustion Residues from Electric Utilities Using Enhanced Sorbents forMercury Control,” EPA 600/R06/008. Office of Research and Development. Research Triangle Park, NC. January 2006; and EPA “Characterization of Coal Combustion Residues from Electric UtilitiesUsing Wet Scrubbers for Multi-Pollutant Control,” EPA/600/R-08/077. Office of Research and Development, Air Pollution Control Division. Research Triangle Park, NC.July 2008.112programs. Groundwater remediation costs andcancer costs under the baseline and eachregulatory option are then estimated. Finally, theaggregate benefits from each regulatory option (incremental to the baseline) are estimated.Step 1. Categorize CCR Disposal Units by TypeThis step begins with the baseline dataon CCR disposal (i.e., disposal unit liner types, annual CCRdisposal tonnages) contained inAppendixFof this RIA for the 495 coal-fired electric utility plants. A subtotal 84 of the 495 plants dispose CCR offsite only, and thus, no liner type isassigned to these facilitiesin this benefits analysis.106Some of the plants have multiple data entries because they were known to have multipleCCR disposal units on-site. This estimation step assigned only the riskiest disposal unit type and liner type combinations ofthose listed foreach such plant, which resulted in the six combinations displayed below inExhibit 5A-1.107This hierarchy was based on the 90thpercentile,trivalent arsenic cancer risks in the EPA-ORCR 2009 CCR risk report as follows,with those units posing the greatest risk appearing first.Appendix K1presents further information on CCR disposal unit liner types and associated data.These plants were then further divided by the type of waste disposed in the units; CCR only or co-managed wastes. The ratio offacilities thatonly dispose CCR compared to facilities that co-manage CCR with coal refuseis displayed below inExhibit 5A-1. These ratios allowed EPAto model a single number of potential cancer cases as a best estimate. The data used in the 2009 risk assessment108were from a 1995 EPRIsurvey. Thus, there is some uncertainty regarding the currentaccuracy of these ratios. To account for this uncertainty, EPAalso calculated abounding range of cancers based on the assumption that all facilities would dispose ofCCR only, and that all facilities wouldco-manage CCRwith coal refuse only.Exhibit 5A-1Categorization of CCR Disposal Unit TypesCCR Disposal Unit TypeCCR OnlyCo-managed1. Unlined Landfill 66% 34%2. Clay-Lined Landfill 74% 26%3. Composite-Lined Landfill 53% 47%4. Unlined Surface Impoundment 32% 68%5. Clay-Lined Surface Impoundment 48% 52%6. Composite-Lined Surface Impoundment 71% 29%106Note: 83 facilities in Exhibits E2 and E4 of the 2009 risk assessment are not assigned WMUs or liner types, 5 fewer than indicated in this RIA.107Multiple CCR disposal units at a single industrial facility willall affect the same surrounding population. To avoid duplication of population risks, the analysis used thesimplifying assumption that the human health risks will be drivenby the riskiest single WMU, when multiple waste management units are present, but populations aroundall WMUs are accounted for inAppendix K2of this RIA.108Source: EPA “Human and Ecological Risk Assessment of Coal Combustion Wastes,” Office of Resource Conservation and Recovery, December 7, 2009.113Step 2. Determine Potentially AffectedPopulations of Groundwater DrinkersWith information on the universe of facilities, WMUs, and liners nearby groundwater-drinking populations were assigned. To accomplish this,EPA first assigned latitude and longitude coordinates to the 495 sites based on its 2007eGRID database. Only a few sites were not in eGRID,and it is assumed that these sites were constructed since the 2007 eGRIDdata collection. Once latitude and longitude data were assigned, EPAused GIS data to ascertain the location ofprivate groundwater wells within a one-mileradius from the latitude and longitude coordinates, andthen the number of individuals drinking from those wells.109,110The data divide populations into adults (18 and older) and children, the sametwo populations examined in the 2009 risk assessment. Once these data wereattached to specific sites, they were aggregated based on theliner/WMU categories above.Aggregated data were then scaled toaccount for the missing population information and population growth. First, the data wasscaled up toaccount for the missing population data in thesites not identified in eGRID. There were 5 unlined landfills, 1 clay-lined landfill, and 7composite-lined landfills thathad onsite disposal but no eGRID data from which to determine the population. All surface impoundments hadthe necessary eGRID data. To account for these individuals, EPA made the assumption that these plants had populations similarto the plantsEPA had data for, since EPA had no data to suggest otherwise.111Thus, the population was scaled up bya scaling factor equal to the totalnumber of plants divided by the number of plants for which EPA had population data as follows:1)Unlined Landfills = 76/71 (~1.07)2)Clay-Lined Landfills = 28/27 (~1.04)3)Composite-Lined Landfills = 150/143 (~1.05)The populations were then scaled up to current population levels based on Census data, resulting in a scaling factor of 1.093.Once these preliminary population estimates were produced, it was also necessary to account for the size of the waste management unit. In the2009 risk assessment, WMUs were assumed to be square as a requirement of the model. Using the same assumption here, the actual1-mileradius around the square area of a WMU could be estimated by scaling the population density of the original 1-mile radius up tothe area 1-milearound a square WMU of average size. This led to scalingfactors of 1.81 and 2.56 for landfills and surface impoundments, respectively.Further discussion of this area-based scaling can be found inAppendix K2.In addition to accounting for the increased area in the 1-mile radius, EPA assumed thathalf of the receptors would be up-gradient and halfwould be down-gradient of the WMU. For the purposes of this assessment, populations were assumed to be equally distributed within the109This data was developed through the use of the 2000 census block data in combination with the 1990 census drinking water source data. For a further discussion ofpopulation development, seeAppendix K3of this RIA.110Municipal water systems using groundwater often rely on deeper aquifers, in which case they would be less susceptible to contamination from CCR releases. Therefore,these systems were not included inthe 2009 Risk Assessment or in this analysis. However, exposure through this pathway is possible, which means that these populationestimates could underestimate the population that is exposed to these wastes.111EPA does not account for CCR disposedoff-site as in the Gambrills MDand Chesapeake VA damage cases.114square whose center was the facilityWMU. This is illustrated inExhibit 5A-2below. It was also assumed that only down-gradientpopulations would be affected (red rectangle), and no up-gradient populations would be affected. This was accounted for by dividing the onemile population by two. The issue of surface waterbodies is addressed below.Appendix K3provides a detailed explanation of the derivationof the exposed population by plant. Overall, 715,855 individuals are potentially exposed to CCR. Of this total, 34,533 use private drinkingwater wells.WMUGroundwater FlowPotentiallyExposedPopulationUnexposedPopulationExhibit 5A-2Conceptual Model for Exposed Well-Drinking Population1-mileSurfaceWaterbodyContaminantPlume115Step 3. Apply EPA-ORCR 2009 Arsenic Groundwater Risk ResultsThis step involved determining themost appropriate individual riskfactors for use in estimating arsenic cancer population riskfor the estimatedpopulations residing near the CCR disposal sites. There are two sources of information on individual risks associated with arsenic exposure:IRIS 1998: Based on skin cancer incidence, asdata on skin cancer risks were available prior to the availability of quantitative data forinternal cancers. Skin cancer is a health endpoint associated withlower fatality risk than the internal cancers induced byarsenic. The skin cancer based risk assessments no longer represent the current state of the science for health riskassessment for arsenic. This RIA presents these estimates below for informational purposes only. This source describes adistribution of risks to a hypothetical individual who drinks water from a well located at a randomly selected point one miledown-gradient from the waste managementunit edge. The probabilistic risk estimates were “site-based” (that is, not sitespecific, but based roughly on 181 actualcoal-fired power plants that were operating in 1995). EPA has only the “peak”risks (i.e., those corresponding generally to the highest groundwater concentrations that are modeled to occur) available foranalysis because computer modeling of peak risks containgigabytes worth of information, and while EPA attempted tokeep track of risks up to 10,000 years of the computer model run, the data in theselarge files became corrupted and are nowunusable. However, below in this RIA EPA does extrapolatepopulation risks in other years. These other years are theyears between the cessation of operation of the landfill, or the years after the beginning of operation of the surfaceimpoundment, leading up to the years in which the “peak” risks occur at half ofthe modeled facilities.NRC 2001: The latest science on health risksassociated with arsenic exposure is from the National Research Council (NRC) report“Arsenic in Drinking Water: 2001 Update”112which reviewed the available toxicological, epidemiological, and riskassessment literature on the health effects of inorganic arsenic, building upon theNRC’s prior report, “Arsenic in DrinkingWater” (1999). The 2001 report, developed by an eminent committee of scientists with expertise in arsenic toxicology andrisk assessment provides a scientifically sound and transparent assessment of cancer risks from inorganic arsenic. EPA’sScience Advisory Board endorses these estimates and the IRISestimates are currently being updated to reflect this latestscience. Therefore, while IRIS estimates exist, because the more recent NRC scientific information is available, this RIArelies on the NRC information for analysisof the cancer risks associated with CCR.Appendix K4provides more detailedinformation on how this NRC research was used.For the purposes of initially estimating the expected number ofcancers (i.e., cancer risks) in Steps 3 and 4, this RIA appliedrisk resultsobtained with the latest (i.e., 1998) IRIS value. However, in Step 5 below, the 2001NRC research was used to update these cancer estimates.It should be noted that the 1998 IRIS skin cancer value does notexamine bladder and lung cancer incidence, and therefore is not a substitute forthe 2001 NRC cancer risk research in this area. To the extentthat the skin cancers estimatedby the IRIS value are not accounted for, this RIAmay underestimate total cancer incidence.112National Research Council, Arsenic in Drinking Water: 2001 Update, National Academy Press, 2001 at http://www.nap.edu/openbook.php?isbn=0309076293116This RIA extracted only those results fromthe EPA 2009 risk assessment to either represent (a) conventional CCR (i.e., fly ash, bottom ash,boiler slag, and flue gas desulphurizationwaste managed in the landfill or impoundment without mixing with other materials), or (b) CCR comanaged with coal refuse.113Of these results, only those for trivalent arsenic were used.114For the primary analysis, it was assumed that allarsenic was speciated in this manner. As noted in the EPA source data, arsenic III and arsenicV cancer risk results for unlined surfaceimpoundments that co-dispose CCR with coal refusewere not statisticallydifferent at the 90thpercentile, and these risks are likely to drive thepopulation risk estimates. A sensitivity analysis was conducted where all arsenic was assumed to be speciated in the arsenic Vstate. Thisanalysis is presented inAppendix K5. Finally, risks for both adult and child receptors were included so that each group would be accuratelyrepresented. Once all of these data were collected they were sorted by CCR disposal unit and liner type.This analysis reflects possible groundwaterand surface water interactions that could affect the population risk estimates. Insituations in whichthe modeled distance to a surface water body was less than the modeled distance to a drinking water well EPA assumed that the groundwaterplume is fully intercepted by a surface waterbody.115To this end, EPA extracted the model inputsfor the distance to groundwater wells and thedistance to surface waterbodies used in the EPA source, randomly selected from input distributions.116These two were then compared using alogical test in Microsoft Excel.This test returned a 0 if the surface waterbody was closer than thedrinking water well and 1if it was not.Thus, a 1 was a positive indication that the contaminant plume in thatmodel run reached the groundwater well.Finally, EPA extracted the exposure durationsused in each model run from the EPA-ORCR 2009 CCR risk report to capture the fraction of theindividual’s lifetime risk that was experienced in a one-year period. EPA accomplished this by matching the probabilistic exposure durationinputs, to their corresponding age category.Then, each probabilistic run was sortedto return the exposure duration of the adult and child agecategory. These Monte Carlo data constituted a weighted approachfor estimating individual human cancer risks. Population risk is typicallycalculated by multiplying risk results by the affected population.Since there were thousands ofequally valid model iterations, this RIAassigned each of these risks an equal weight in its final population risks by using the average of these individual risks.Individual risk estimation took into account the fact thatthe contaminant plumes might beintercepted by surface waterbodies by multiplying byeither 0 or 1 as identified above. Each ofthese risks was then divided by exposure duration to estimate the yearly cancer risk.117Once all ofthese risks were calculated for a given WMU/liner type they were summed and divided bythe number of iterations to give the average one yearincrement of risk for that WMU/liner typeat the peak risk. Thus, the final equation that was used for calculating average risks can be stated as:113Fluidized Bed Combustion waste results were not deemed appropriate for use for the reasons discussed in EPA “Human and Ecological Risk Assessment of CoalCombustion Wastes,” Office of Resource Conservation & Recovery, August 2009.114A 1981 Oak Ridge National Laboratory study states “As (III) islikely to be the predominant arsenic species in ash pore waterand groundwater.” Source: Turner, RalphR. “Oxidation State of Arsenic in Coal Ash Leachate,” Environmental Science & Technology, Vol.15, Number 9, September 2001.115Full interception will not occur in instances where the waterbody is shallow, the waterbody is man-made, or the facility is oriented perpendicular to the waterbody. Thissimplifying assumption serves to minimize the influence of the model runs in which interception may have occurred, but was notreflected in EPA “Human and EcologicalRisk Assessment of Coal Combustion Wastes,” Office of Resource Conservation & Recovery, August 2009.116For further discussion of how these distributions were developed, see Appendix C of EPA “Human and Ecological Risk Assessmentof Coal Combustion Wastes“ Officeof Resource Conservation and Recovery, Washington, DC, August 2009.117For further discussion of cancerrisks and exposure durations, seeAppendix K4of this RIA.117NEDnWELLREACHRISKniRISK∑×=Where:iRISK = Average increment of lifetime cancer risk from a 1-year exposureRISKn = Risk result for the nth model runWELLREACH = 0 if plume is intercepted by a surface water body, 1 otherwiseEDn = Exposure duration for the nth model runn = Iteration numberN = Number of iterationsThe results are presented inExhibit 5A-3below. For each, the results are presented for both adults and children under each of the WMU/linerscenarios. For full distributions ofindividual risks before averaging, seeAppendix K6– Distributions.Exhibit 5A-3Peak One Year Risks For CCR CancerConventional CCRCCR Co-managed With Coal RefuseLiner - ReceptorLandfillsImpoundmentsLandfillsImpoundmentsUnlined - Adult 6E-06 4E-055E-06 2E-04Unlined - Child 1E-05 1E-041E-05 4E-04Clay-Lined - Adult 3E-06 3E-052E-06 1E-04Clay-Lined - Child 7E-06 6E-054E-06 2E-04Step 4. Extrapolate Annual Cancer Risks from Peak Cancer RisksThe peak risks that were calculated occur well after cancers canfirst materialize. Thus, constraining the benefits to only the peak populationrisks significantly underestimates total cancersavoided. To compensate for this shortfall, this RIA formulated an approach illustrated inExhibit 5A-4below. The blue parabolic curve for population risk is based on the well concentrations over time in the results. While EPAcannot reconstruct the exactcurve due to data availability issues, a paraboliccurve represents groundwater contamination. From this shape it isclear that the peak population risks onlycapture a fraction of total population risks.Using an assumption of linear increases to the peak andlinear decreases from the peak, produced the simplified risk profile seen as a red line inExhibit 5A-4.118t = time to peak riskExhibit 5A-4 – Population Risk MethodTime (years)tt0 = WMU builttt0RtRt = peak population risk= Actual Risk Profile= Simplified Risk ProfilePopulation Risks At Peak OneYear Exposure Only119The constant slope allowed estimation of the population risks from each year’s exposure by assembling the model iteration timesto peak.118Dividing peak risks (y-value) by the time topeak (x-value), the slope of the time linewas determined for each WMU/liner typeas displayed inExhibit 5A-5below.Exhibit 5A-5Human Cancer Time Slope Factors For CCRSlopes For Conventional CCRSlopes For CCR Co-managed With Coal RefuseLiner - ReceptorLandfillsImpoundmentsLandfillsImpoundmentsUnlined - Adult1E-08 6E-07 8E-09 3E-06Unlined - Child2E-08 1E-06 2E-08 6E-06Clay-Lined - Adult5E-09 4E-07 3E-09 1E-06Clay-Lined - Child1E-08 7E-07 6E-09 3E-06Multiplying this slope by the number of years elapsed yields theyearly increment of individual risk for that year. Multiplying this averageincremental individual risk by the population exposed in each year119EPA estimated the number of cancers in each year. While this underestimates cancer incidence by the difference between the blue andred profiles it is the best estimate based on currently available data.As displayed inExhibit 5A-6below, this approach results in an estimatebetween 45 and 196 potential cancer cases over 75 years120as a resultof arsenic consumed through contaminated groundwaterusing EPA’s 1995 cancer slope factor (1.5 mg/kg/d-1) for arsenic based on skincancers. Using the ratios of conventional CCR co-managed with coal refuse a best estimate within this range is145 cancers.118Since these iterations were performed in later model runs they could not be tied to the specific model iterations used above.67% of the model runs had the nearestgroundwater well occurring beyond the nearest surface waterbody. Since the longer arrival times occur with longer travel distances, and these iterations tended to be theiterations that were intercepted, assumed that the 33% of model runs that were not intercepted are also the 33% of model runs with the shortest arrival times (i.e., shortestdistances). Taking the midpoint of these arrival times yielded the 16.5thpercentile.119This RIA inflated the future population each year based on the future projections made by the US Census Bureau. From that point on, this RIA assumed a constantannual growth rate equal to the growth rate in year 2050.120Seventy-five years were used for the analysis based on the 78year time to peak period, less two years states are allowed to adopt the rule’s provisions, and less anadditional year for installing groundwater monitoring. Seventy-eight years are the time at which the risks for typical unlinedand clay-lined surface impoundments that arenot intercepted by surface water will peak.Cancers occurring after year 78, though potentially significant, are unlikely to play a significant role when monetized becauseunder a 3% discount rate, benefits fall to ten percent of theirvalue at year 78, and at a 7% discount rate, benefits fall to 0.5% of their value at year78. These future cancerswill be further reduced by state regulations, detection of contamination, and a general trend away from wet handling.120Exhibit 5A-6Potential Future Human Cancer Cases fromthe Disposal of CCR Based on Arsenic Cancer-Slope Factor from EPA/IRISDisposal of Conventional CCRDisposal of CCRCo-Managed with Coal RefuseWMUAdultChildTotalsAdultChildTotalsUnlined Landfills 0.1 0.1 0.2 0.1 0.1 0.2Clay-Lined Landfills 0.1 0.1 0.2 0.0 0.0 0.0Unlined Surface Impoundments 20.1 16.3 36.4 98.1 67.6 166.7Clay-Lined Surface Impoundments4.8 3.5 8.3 17.6 12.6 309.2Totals 25.1 20.045115.8 80.3196Step 5. Estimate Arsenic Cancer Risks Using Recent NRC Science for ArsenicBased on the NRC data source, lifetime exposure to 10 ug/L arsenic in drinking water would leadto 23 excess male bladder cancers and 14excess male lung cancers per 10,000 people. Under the exposure factor assumptions usedby the NRC the equivalent cancer slopefactor (CSF)is 26 mg/kg/d-1. For details of how this cancerslope factor was calculated, seeAppendix K4– Cancer Calculations.121Exhibit 5A-7belowdisplays the population risk estimatesfor CCR disposal base on the NRC source.122Using the NRC (2001) cancer slope factor one wouldexpect between approximately 778 and 3,392 cancer cases over 75 years as a result of arsenic consumed through contaminated groundwater.Using the ratios of conventional CCR co-managed with coal refuse produces abest estimate within this range of2,509 cancers.Exhibit 5A-7Potential Future Human Cancer Cases from CCR Disposal Based on Arsenic Cancer-Slope Factor from NRCDisposal of Conventional CCRDisposal of CCRCo-Managed with Coal RefuseWMUAdultChildTotalsAdultChildTotalsUnlined Landfills 2 2 4 1 1 2Clay-Lined Landfills 1 1 2 1 1 2Unlined Surface Impoundments 348 281 629 1,696 1,169 2,865Clay-Lined Surface Impoundments 82 61 144305 218 523Totals 433 3457782,003 1,3893,392121EPA is currently in the process of revising the arsenic cancer slope factor in EPA’s Integrated Risk Information System (IRIS).122EPA also conducted a sensitivity analysisassuming the female cancer slope factor inAppendix K5of this RIA.121Step 6. Monetize Future Avoided Cancer Risk BenefitsReflecting the best science available, EPA used a point estimate of cancer cases avoided to monetize cancer risks.Appendix K4providesfurther explanation as to why the NRC science is considered more appropriate than the older skin cancer research that the current IRIS valuewas derived from. Because EPA has greater confidence in theNRC estimates, it chose to use the 2,509 cancers calculated aboveas the bestestimate. EPA also used the NRC ratio of 23 male bladder cancers to 14 male lung cancers to estimate how many of each type were likely tooccur in each year. That is, 62%, or 1,556cancers, are assumed to be bladder cancersand 38% or 953 are assumed to be lung cancers.Appendix K7shows the best estimate number of lung and bladder cancers in each yearthat was used in the remaining portions of this analysis.Since cancers are not all fatal, the nextstep was to estimate the number of cancers that are fatal and non-fatal. This was done separately foreach type of cancer using 5-year survivalrates from the EPA-ORCR 2009 CCR risk report.The 5-year survival rate used for bladder cancer is82% and the 5-year survival rate usedfor lung cancer is 14%. Thus, 1,276 (82%) ofbladder cancers are non-fatal and 280 (18%)are fatal. Forlung cancer, 133 (14%) are non-fatal and 820 (86%) are fatal. Again, thesecancers are spread over the 75 years of the analysis. In order tomonetize avoided cancer risks, this RIA applied the value of a statisticallife (VSL) plus the cost of terminal cancer treatments displayed inExhibit 5A-8below. To monetize avoided non-fatal cancer risks,this RIA used an estimatefrom Magat et al. (1996).123This study shows thata typical individual’s assessment of a non-fatal lymphoma risk reduction was the equivalentof 58.3% of a fatal lymphoma risk reduction.124Therefore, this RIA assumed individualsvalue non-fatal bladder and lung cancerrisk reduction in a similar manner.Exhibit 5A-8Unitized Monetary Values for Human Cancer Risks Applied in this RIAMonetized Value2008$Fatal cancers: value of statistical life (VSL)* $8,800,000Non-fatal cancers: 58.3% of VSL*$5,130,400Medical costs associated withfatal bladder cancer** $149,863Medical costs associated withfatal lung cancer** $87,703Notes:*Median VSL of $4.65 million (1997$) from Exhibit 7-3 (page 89) of EPA “Guidelines for Preparing Economic Analyses,” EPA 240-R-00-003, Sept 2000; converted for this RIA to 2008 dollars using the Consumer Price Index. In addition, projections of benefits infuture years are subject to income elasticity adjustments. These represent changes in valuation in relation to changes in realincome.For example, if, for every 1% increase in real income, a particular consumer’s willingness-to-pay for a particular item increases by 1%,this would be represented by an income elasticity of 1.0. Formost items, income elasticity values are actually less than 1, indicatingthat valuation of most items does not increase as fast as real income levels. To do so, applied the change in Gross Domestic Productper-capita between the original dollar yearof the estimates and 2008, and an income elasticity of 0.5 based on estimates fromViscusi,W. K. and Aldy, J. E. “The Value of a Statistical Life: A Critical Review of Market Estimatesthroughout the World,” Journal ofRiskand Uncertainty, Vol.27, 2003, pp. 15–76.** These costs reflect the inpatient hospital stays, skilled nursing facility stays, home health agency charges, physicians' services, andoutpatient and other medical services - in other words the treatment and maintenance costs. Costs are assumed to occur duringinitial123Magat, Wesley A., V. Kip Viscusi and Joel Huber "A Reference Lottery Metric for Valuing Health," Management Science, Vol.42, Issue 8, 1996, pp.1118 - 1130.124EPA acknowledges that alternative approaches to valuing non-fatal cancers are available. One such alternative is presented inAppendix K5of this RIA.122Exhibit 5A-8Unitized Monetary Values for Human Cancer Risks Applied in this RIAtreatment, maintenance care between initial and terminal treatment and terminal treatment during the final six months prior todeath:•Bladder cancer costs are based on survival and death rates each year for 20 years which captures most deaths frombladder cancer among those who are diagnosed with the disease.•Lung cancer costs are based on a 10 year time horizon during which most deaths are assumed to occur.The original figures in the 2001 EPA report are in 1996 dollars (source: EPA “The Cost of Illness Handbook,” Office of PollutionPrevention & Toxics, October 2001). These costs are updated for this RIA to 2008 dollars using the Medical Care Component of theConsumer Price Index.These values are further adjusted for cessation lag and income as described inAppendix K8. EPA used the cessation data of bladder cancersfrom arsenic in Chen and Gibb (2003)125to construct a Weibull curve approximating the lag time between reduced arsenic exposure andreduced cancer outcomes. Because this lag will reduce willingnessto pay compared to an immediate risk reduction, the value ofreducedstatistical cancers are 83% and 67% of whatthey would be using an unadjusted VSL (at a 3% and 7% discount rate, respectively.)This isdescribed in more detail inAppendix K8. For income, EPA projected per capita GDP, and usedthis combined with an income elasticity of 0.5income elasticity of 0.5 from Viscusi and Aldy (2003) to estimatethe growth in VSL until the exposure year. There has been economic debateover whether VSL should be adjusted to the year of exposure orthe year of the cancer. However, typically, it is not possibleto know when theexposure occurred. Because of the model usedhere, this RIA applied the VSL adjustmentat the time of exposure. The full table of VSLadjustment factors, as well as their derivation, is presented inmore detail inAppendix K8.Applying these nominal dollar values to the number of fatal and non-fatal bladder andlung cancers in each year, a current yearvalue foravoiding cancer risk was calculated for each of the 75 years. These values can be seen inAppendix K7. The present value (PV) of thesevalues is approximately $4,696 million at a 3%discount rate and $885 million at a 7% discount rate. This would reflect the value of avoidingfuture cancer risks assuming that no steps were taken to prevent contamination and theresulting cancers. However, as discussed below, this isnot realistic under baselinestate regulatory controls.Step 7. Account for Groundwater Remediation under the Baseline and Regulatory OptionsThe results above assume that arsenic is released from existing impoundments and landfills, without any controls (beyond the liners taken intoaccount in the model). The benefits of regulatory options would be reflected by lowerrates of cancer, resulting from the rule’s controls(including ground-water monitoring, permitting, corrective action, phase-out of surface impoundments, financial assurance, etc.).126The rulewill also have the benefits of reducing or eliminating groundwaterremediation cost, because groundwater releases are eliminated through125Source: Chen, C.W. & Gibb, H. “Procedures for Calculating Cessation Lag.” Regulatory Toxicology and Pharmacology,” Vol.38, Issue 2, 2003, pp.:157-65.126The two Subtitle D Options evaluated were: (1) Subtitle D —regulation of landfills and surface impoundments, with liners required for existing and new surfaceimpoundments, and new landfills and (2) Subtitle “D Prime” — regulation of landfillsand surface impoundments, with liners required only for new surface impoundmentsand landfills.123controls like surface-impoundment phase-out,or reduced because releases are caught earlier. These benefits, and how they relate, are describedin the section below.First, even in the absence of federal regulations, CCR disposal units will not leach and cause cancersin all cases estimated through theevaluation above. Even without federal regulation, there will befacilities that discover contamination and clean the contamination up beforecancers occur, either due to state regulations or good practice. Where exposures areidentified, this RIA assumed that the pathway will be cutoff (e.g., through provision of alternative water sources). Even facilities that fail to prevent contamination may detect that contamination andclean it up at a later time, although after exposure has occurred. This Step of theestimation attempted to account for thesepractices.To estimate the different speed and cost of groundwater remediation likely under the baselineand under the three regulatory scenarios (i.e.,Subtitle C, Subtitle D and Subtitle D Prime), this RIA beganby examining the differences acrossstates in groundwater monitoringrequirements pertaining to CCR disposal units, and focused on groundwater monitoring requirements because adequate monitoring is needed todetermine whether a release has occurred. This RIA assumes that, where releases of concern have been identified, and particularly wherepeople may be at risk, drinking water pathways will be cut offand alternative drinking water will be provided. Then calculated the percentageof CCR disposed by each state, and noted which of three levels of groundwater monitoring were required:1.No monitoring requirements2.Monitoring requirements for only futurenewly constructed CCR disposal units3.Monitoring requirements for both futurenew and existing CCR disposal unitsThen EPA tracked the percentage of total waste that was discarded by facilities in states requiring each of these three monitoring scenarios.Exhibit 5A-9below presents these percentages for states requiring at leastsome monitoring (categories 2 and 3 above) and states requiringmonitoring at exiting facilities (category 3 above). The first value in the table, 91%, is the percentage of CCR discarded inlandfills that imposesome form of monitoring requirements, whether for new landfillsonly, or for both new and existing landfills. 62% is the percent of CCRdiscarded in landfills that impose monitoring requirements on both new and existing CCR disposalunits (a subset of the 91%).127Percentagesare also provided for CCR that are managed in surface impoundments.Appendix K9provides these data for each individual state.127Some states may require monitoring only for off-site units; however, in the absence of a specific breakdown, EPA made the assumption that on-site units would bemonitored in all states that require monitoring.124Exhibit 5A-9State Government Groundwater Monitoring Requirements Assumed in this RIALandfillsSurface ImpoundmentsAny MonitoringRequirements(categories 2&3)Required at New andExisting Units(category 3)Any MonitoringRequirements(categories 2&3)Required at New andExisting Units(category 3)Percent of Facilities 91% 62% 48% 12%These percentages helped to determine when releases will be identified, and the likely cost ofcleanups or other remedies, whenreleases areidentified, under the baseline and three regulatory scenarios.Since all but 4 of the 2,509 cancers projected above result from surfaceimpoundments, only surface impoundment monitoring data were used in the calculations.128For the baseline scenario, it was assumed thatstates with the highest level of monitoring requirements (those requiring groundwatermonitoring at both new and existing units) wouldgenerally find groundwater contamination relatively early and would require preventive measures that would avoid cancers (e.g.,intercept theplume and/or put residents on municipal or bottled water). Thus, 12% of contamination that could occur would have already beendetected,and the resulting cancers prevented. To the extent that cleanupsand/or alternative water are required, that was considered part of the baseline.To model the Subtitle D option, EPA assumed that states with groundwater monitoring requirements atnew units, or with some coverage of theunits in question, would upgrade their existing programs to provide fuller coverage– because they already have a regulatory infrastructure –but other states with no programwould not. While states that do not currentlyregulate units would notchange their practicessimply becauseEPA issued national rules, EPA recognizes that facilities in these latter states willto a certain extent comply, to avoid citizens’ suits. However,EPA’s and states’ experience in implementing the RCRA program demonstrates that self-implementing ground-water monitoring programs areof limited reliability. Given these factors,the percentage of waste disposed of instates with some level of groundwater monitoring programs isa reasonable estimate of benefits for the subtitle D approach. Under these assumptions, contamination in states with monitoring requirementsfor only new units, as well as contaminationin states with monitoring requirements for new and existing units would be detected promptly.This leads to 48% of surface impoundment groundwater contaminationbeing detected before extensive damage has occurred, and therefore48% of cancers being prevented.Since the Subtitle “D Prime” option does notrequire the retrofitting ofexisting units, unlined surface impoundments would remain acontinuing source of release. However, the presence of a newnational rule accompanied by EPA support would lead at least somestates tomake such updates. Since the potentialrisks will fall somewhere between the Subtitle D option and the baseline, the midpointbetweenbaseline and the Subtitle D option (30%) waschosen as a best estimate. This leads to30% of contamination being immediately detected, andthus 30% of cancers being prevented.128Note, however, that considerable evidenceindicates that releases from dry disposalcan present significant risk as well, as demonstrated by EPA research on CCR leachrates at different pHs and the damage cases.125Finally, for Subtitle C, there would be federal oversight of the groundwater monitoringrequirement, and therefore this RIA assumes 100% offacilities would have contamination detected early. Looking forward, this would effectively prevent all cancers.129In addition, the technicalstandards of the subtitle C rule wouldlargely prevent future releases becausesurface impoundments wouldbe phased-out, and because newlandfills would require composite liners.Similarly, closure requirements would largely prevent releases after closure of bothtypes of units.Where releases of arsenic from disposal units occur in the future, they will be detected promptly after they occur under the proposed option, aswell as under the other options where good monitoring programs are inplace. In these cases, there may be response costs, butno cancer risks.On the other hand, if facilities do not haveadequate detection systems in place (andother adequate controls, e.g., liners, adequate closure, etc.),then detection will be delayed. This RIA assumes that releaseswill eventually be discovered, but that detection may be on a delayed basis. Toquantify this assumed that contamination would be discovered consistently until it was all discovered. Since the rate of discovery isunpredictable, further assumed detection would be at a constantrate, reaching 100% detection bythe final year of the analysis.130Thesediscoveries were assumed not to start for six years because the first percentile of time duration until peak risks for unlinedsurfaceimpoundments occurred. Restated, this profile assumes that facilitiesin states that require groundwater monitoring for existing units wouldgenerally find contamination in the future soon after it occurred, reducing response costs, and preventing cancer risks. But where monitoringand other controls were not adequate, releases would potentially go undetected for lengthy periods, causing cancers until the contamination waseventually detected and those residents switched to municipal or bottled drinking water. In addition, response costs would besignificantlyincreased. The present value of avoidingall of the risks in the baseline case isthe upper-bound on benefits, and this upperbound is reduced bydetection and groundwater remediation as described in this section. The risk reductionbenefit for each regulatory option is the differencebetween baseline risks and remaining risks under that option.These benefits, accounting for the detection and remediation, are presented inExhibit 5A-10below. Baseline expected cancer risks are accounting for detection and remediation, comparedto without taking these factorinto account. Further discussion ofthe cancer profile can be found inAppendix K7.This RIA projects a trend towards decreasedmanagement of CCR in surface impoundments.Facilities with surface impoundments have beenslowly moving from wet handling in impoundments to dry handling in landfills or to beneficial uses. While this trend could affect the profilediscussed above, it is unlikely to have asignificant effect on risks for two reasons. First, surface impoundments, to the extent they are closed,are typically closed with waste in place.Thus, they are likely to continue to leach beyond the 75-yearperiod modeled in the2009 riskassessment; this is particularly true in situations where theyare not lined (which are overwhelmingly the case) and where theyare located instates without strong regulation. In the latter case, closures are likely to be inadequate, leading tocontinued infiltration.Second, the releasesthat occurred before the surface impoundmentsare closed will continue to migrate until they reach the groundwater wells or until they areintercepted by a surface waterbody (again particularly in states without strong programs). Given the relatively very large size of the CCRimpoundments, and the presence ofa hydraulic head at least beforeclosure, these historic releases have the potential to be significant. Giventhese considerations, the closure of surface impoundments in states without regulations (e.g., corrective action, groundwater monitoring, etc.)would behave very similarly to active surface impoundments in termsof their risks to human healthand the environment. For this reason, theregulatory oversight in the options above was not modified for closed CCR disposal units.129Cancers from historic releases would not be affected, but the releases would be promptly identified and future exposures avoided.130Some releases are likely to go entirely undetected in the absence of groundwater monitoring and other controls. However, to put a reasonable limit around the analysis,this RIA assumed 100% detection.126Exhibit 5A-10Present Value of AvoidedHuman Cancer Risks Associated with CCR Disposal($millions present value over 50-years)Discount rateSubtitle CSubtitle DSubtitle D’@ 3% $1,825 $750 $375@ 7% $504 $207 $104The other major cost associated with groundwater contamination isthat of remediation or other response. To estimate that cost, EPA began byestimating the number of coal-fired electricutility plants that would require responses under various state environmental programs, based onthe 2009 risk assessment. In any particular situation, a statecould require remediation of asite involving potential drinking water to 10-4, 10-5,or 10-6levels. In addition, states may choose torequire groundwater remediation for groundwater that isnot a likely drinking watersource,because of ecological concerns.Exhibit 5A-11below shows the number of facilities potentially requiring cleanup. Since each estimate isequally acceptable under current state programs, the average is believed to be a bestestimate for how many electric utility plants will ultimatelyneed groundwater remediation so as not to overestimate the number of remediation events.Exhibit 5A-11Proportion of CCR Sites Requiring Remediation Based on State Cleanup LevelsClean All GroundwaterClean Only Drinkable GroundwaterStateCleanupLevels10-410-510-610-410-510-6AverageTotal LF 22 50 72 7 16 24 32Total SI 93 132 150 31 44 50 83These plant counts are based on the probabilistic model iterations from the 2009 risk assessmentwhich were used to estimate what fraction ofsites would leach at above various clean up levels. Typically, solid wastecleanups can be conducted at either 10-4, 10-5, or 10-6individualcancer risk levels.Exhibit 5A-12uses the PERCENTRANK function in Excel to estimate what percent of risk results fall at or below eachclean up level. For example, in the first cell ofExhibit 5A-12, the 78% means that 10-4is higher than 78% of the probabilistic results forunlined landfills with conventional ash.UL = UnlinedCL = Clay-LinedA = Conventionally Managed AshC = Co-managed AshLF = LandfillSI = Surface Impoundment127Exhibit 5A-12Percentile of Cleanup Levels inthe EPA-ORCR 2009 CCR Risk StudyClean Up LevelUL ALFCL ALFUL CLFCL CLFUL ASICL ASIUL CSICL CSI1.00E-04 78% 83% 74% 85% 46% 59% 30% 43%1.00E-05 55% 59% 42% 57% 15% 24% 12% 21%1.00E-06 36% 35% 18% 28% 5% 7% 3% 8%Model results equal to or above these percentiles would requirea state or federal cleanup. In other words, the percentage ofsites above thecleanup level displayed inExhibit 5A-13can be derived by subtracting the percents inExhibit 5A-12above from 100%. However, whilestates may require remediation of all groundwater, whether or not it is potable, theymay also choose not to on a site by sitebasis. As discussedin the EPA-ORCR 2009 CCR risk report, it is estimated that two-thirds of sites are located closerto a surface waterbody than to the nearestgroundwater well. Therefore, sites located on surface waterbodies may not be cleaned in some states. This 2/3 decrease is accounted for in thesecond set of values inExhibit 5A-13.Exhibit 5A-13Percent of Electric Utility Plants Requiring Future Groundwater RemediationClean Up LevelUL ALFCL ALFUL CLFCL CLFUL ASICL ASIUL CSICL CSIAssuming All Groundwater is Remediated1.00E-04 22% 17% 26% 15% 54% 41% 70% 58%1.00E-05 45% 41% 58% 43% 85% 76% 89% 79%1.00E-06 65% 65% 82% 72% 96% 93% 97% 93%Assuming Only Potable Groundwater is Remediated1.00E-04 7% 6% 8% 5% 18% 13% 23% 19%1.00E-05 15% 14% 19% 14% 28% 25% 29% 26%1.00E-06 21% 21% 27% 24% 32% 31% 32% 31%The number of utility plants with each type of CCR disposal, liner type, and management combination was calculated by taking theAppendixFplant data from this RIA and combining it with the conventional versus co-managed rates.128Exhibit 5A-14Estimated Number of Electric Utility Plants by CCR Disposal Unit TypeUL ALFCL ALFUL CLFCL CLFUL ASICL ASIUL CSICL CSI50 21 26 7 31 28 68 31Multiplying the number of facilities in each category fromExhibit 5A-14above by the percent of facilities requiring remediation inExhibit5A-13above yields the estimated numberof facilities that would lead tostate or federal clean ups inExhibit 5A-15below. These estimates ofthe number of facilities requiring cleanup does not account for anycleanups resulting from other constituents exceeding a hazard quotient of 1.Thus, this estimate may under-estimate the total number of cleanups.Exhibit 5A-15Number of Electric Utility Plants Requiring Future Groundwater RemediationClean Up LevelUL ALFCL ALFUL CLFCL CLFUL ASICL ASIUL CSICL CSIAssuming All Groundwater Is Remediated1.00E-04 11 4 7 1 17 11 47 181.00E-05 23 9 15 3 26 21 60 241.00E-06 32 14 21 5 30 26 66 29Assuming Only Potable Groundwater Is Remediated1.00E-04 4 1 2 0 6 4 16 61.00E-05 7 3 5 1 9 7 20 81.00E-06 11 5 7 2 10 9 22 9With the number of units requiring remediation, EPA estimated thecost of groundwater remediationunder the baseline and each regulatoryoption presented above. Groundwater remediation costs were estimated in two steps. First, EPA assumed contamination that might occur atsites in states with more stringent monitoring requirements, would be discovered promptly. Thissuggests that there is likelyto be lessremediation required than at the typical site. Thus, EPA assigned these sites the 25thpercentile remediation costs displayed inExhibit 5A-16below as the midpoint of the bottom half ofcosts. These future remediation events were spread evenly across all 75 years of the analysis.129Exhibit 5A-16Per-Site Groundwater Contamination Remediation Costs*Cost element category25thpercentile “early costs”75thpercentile “later costs”Capital Costs $6,075,900 $21,195,000Annual O&M $98,910 $1,413,000O&M at 3% discount rate** $1,978,242 $28,260,605O&M at 7% discount rate** $1,239,522 $17,707,453Total cost at 3% $8,054,142 $49,455,605Total cost at 7% $7,315,422 $38,902,453Notes:*Cost data from Exhibits 3 and 4 in EPA “Cost Analyses for Selected Groundwater CleanupProjects: Pump and Treat Systems and PermeableReactive Barriers,” Office of Solid Waste &Emergency Response, EPA-542-R-00-013. February 2001 at:http://www.epa.gov/tio/download/remed/542r00013.pdf**O&M costs were capitalized over 30 years at both a 3% and 7% discount rate for use in thetwo estimates. This was done to simplify spreadsheet calculations.For the remaining sites expected to require remediation, but lacking groundwater monitoring requirements, EPA assumed discoveryofcontamination would take longer. That is,CCR contamination would have migrated for some number of years,resulting in a largergroundwater plume to remediate, or more extensive remediation. EPA assigned these sites the 75thpercentile remediation costs as the midpointof the top half of costs. Since the first percentile time to peak results for unlined surface impoundments is six years, it isassumed that nodiscoveries and cleanups will be made in the first six years for these sites (three years once the two years for state adoptionand one year forgroundwater monitoring are considered). The costs are thus spread evenly over the remaining 72 years.The present value of theseremediations, accounting for the slow, but continued discovery of contaminated sites, is presented inExhibit 5A-17below. Further discussionof the discounted remediation costs for each year is presented inAppendix K10.Exhibit 5A-17Present Value of Future Groundwater Remediation Costs from CCR Contamination($ millions present value over 50-years)Discount RateSubtitle CSubtitle DSubtitle D’Baseline@ 3% $96 $1,016 $1,302 $1,587@ 7% $39 $336 $420 $504130Aggregate benefits from cancer risk reductions and avoided remediation costs are summarized inExhibit 5A-18below. These benefits arecalculated by subtracting the costs resulting under that option from thecosts resulting under the baseline (i.e., cost avoided).Exhibit 5A-18Present Value of Future Avoided Human Cancer Risks& Avoided Groundwater Remediation Cost Benefits($millions present value over 50-years)Subtitle CSubtitle DSubtitle D’@ 3% discountGroundwater Remediation Costs Avoided* $1,491 $571 $286Human Cancer Risks Avoided $1,825 $750 $375Total $3,316 $1,321 $661@ 7% discountGroundwater Remediation Costs Avoided* $466 $168 $84Human Cancer Risks Avoided $504 $207 $104Total $970 $375 $188Note:* Calculated by subtracting the present value future groundwater remediation cost estimated inExhibit5A-17for each regulatory option, from the estimatedbaseline present value in that same Exhibit.Step 8. Characterize CancerRisk Estimation UncertaintiesThere are a number of uncertainties associated with the annualized cancer estimates calculated in this RIA which are likely tounder-estimategroundwater protection benefits:•Estimates do not account for historic releasesat operating plants. These releases could lead to further migration and futurecancer riskswithout proper regulatory actions like groundwater monitoring.•A linear slope for individual cancer risk wasused to approximate the increase in cancer risks instead of the parabolic curve.•Approximately 18% of plants dispose ofCCR off-site only. Since these facilities were not accounted for, additional populations would beexposed to arsenic cancer risks from disposal as recently illustrated by the Gambrills, MD and Chesapeake, VA damage cases.•Three new research studies131(2006, 2008, 2009) from EPA’s Office ofResearch and Development, indicatesthat landfills may leach toxicmetals much faster than originally believed. The damage cases at Gambrills MD and Chesapeake VA resulted in groundwatercontamination much more quickly than would be expected, and are therefore consistent with this research.131The three new EPA studies are:1. “Characterization of Mercury-Enriched Coal Combustion Residues from Electric Utilities Using Enhanced Sorbents for Mercury Control,” EPA 600/R-06/008.Office of Research and Development. Research Triangle Park, NC. January 2006.131•Multiple CCR disposal units at a single electric utility plant will all affect the same population. The risk estimates do notaccount for anyadditive risks from multiple units. However, the populations around these units are accounted for as described inAppendix K2.•Multiple landfills could exist at some facilities. While the area ofmultiple surface impoundments was considered, the area ofmultiplelandfills was not considered because EPA did not have survey results for dry handling even though some facilities are known tohave morethan one CCR landfill onsite.•Residents on municipal water systems were not included in the 2009 risk assessment orin this analysis.However, exposure through thispathway is possible, which means this RIA likely under-estimated the human population that may be exposed to CCR.•Populations that are farther than 1-mile thatmay be within the plume were not included.•Some surface water bodies that this analysis assumes fully intercept the groundwater plume may infact only partially interceptthe plume,or not intercept it at all. This situation would be more likely to occur when surface water bodies are small or shallow with low flow rates,relative to the size of theaquifer underneath the CCR disposal unit, or are oriented such thatthey would not likely interceptthegroundwater plume.•Potential cancer cases resulting from consumption of recreationally-caught fish (contaminated by direct surface impoundment dischargesand leaching from groundwater to surface water)are not included in the calculations.•According to the EPA-ORCR 2009 CCR risk study, cancers can continuewell after the analysis ends,but these cancers were not calculatedin the population risk estimates.•The use of a 5-year survival rate does nottake into account those who may die from thecancer after year 5. Since some of theprojected 5-year cancer survivors would havedied in later years,they are undervalued in this assessment.•The estimated number of cleanups is based only on modeled arsenic contamination. It does not account for cleanups based on hazardquotients over 1 for toxic constituents with non-cancer endpoints.The following are some uncertainties that are likely tocause over-estimation of groundwater protection benefits:•Cancer risk estimates might includesome individuals who are down-gradient, but are outside the plume.•All arsenic was assumed to be present in the arsenic III state.Appendix K5contains an analysis in which all arsenic was assumed to bespeciated in the arsenic V state, and EPA concluded that even if someportion of arsenic was speciated in the arsenic V state,the finalresults would not significantly change.•The male CSF estimate from NRC (2001) was used instead of the female CSF.Appendix K5contains an analysis in which this femaleCSF was applied.•It is possible that some states would choose not to remediate CCR contamination above cleanup levels once local residents wereplaced onmunicipal or bottled water.2. “Characterization of Coal Combustion Residues from Electric Utilities Using Wet Scrubbers for Multi-Pollutant Control,” EPA/600/R-08/077. Office ofResearch and Development, Air Pollution Control Division. Research Triangle Park, NC. July 2008.3. “Characterization of Coal CombustionResidues from Electric Utilities – Leaching and Characterization Data,” EPA-600/R-09/151. Office of Research andDevelopment, Air Pollution Control Division. Research Triangle Park, NC. December 2009.132•Willingness to pay estimates for non-fatal cancers has been assignedlower values in some research. An alternative valuation for thesecancers is presented inAppendix K5.•Medical treatment costs for those dying of cancer would not occur until the cancer was first discovered.The following are some uncertainties thathave an unknown effect on the benefits:•This RIA assumed an evenly distributed population for establishing up-gradient and down-gradient populations, as well as for adjustingpopulation for the WMU area.•The latitude and longitude data of the WMU are uncertain.•State programs serve as a proxy for units managed well and units managed poorly. However, there could be some WMUs managed well instates without any program. Conversely,there could be some WMUs managed poorlyin states with an existing program.•State regulatory programs affecting CCR disposal may be different than summarized inAppendix Eof this RIA.•Remediation costs are very site-specific, and the 25thand 75thpercentile costs used here may overestimate or underestimate the trueremediation costs of any particular cleanup.For example, the cost of responses tonew releases caught early will sometimes bebelow theestimated costs. In other cases, even if contamination is identified early, those costs canexceed the 75th percentile estimates above.Responses at Gambrills MD and Chesapeake VA, two sites where CCRcontamination was identified relatively early, are examples ofsiteswhere actual groundwater remediation responses will far exceed the cost estimates.•This RIA assumed that discovery of CCR groundwater contamination and the resulting remediation costs would be incurred evenly over the75 year period for regulated facilities and evenly over the 72 years for unregulated facilities.However, experience under themunicipalsolid waste program indicates thatthe incorporation of lined units could reduce contamination over time.1335B. Benefit of Preventing Future CCR Impoundment Structural Failures (Avoided Cleanup Costs)In December 2008, a failure of a CCR impoundment at the Tennessee Valley Authority (TVA) Kingston Fossil Fuel Plant TN resultedin theenvironmental release of 5.4 million cubic yards of CCR. Thisimpoundment failure event illustrated the potential environmental damageseverity of structural failures involving CCR impoundments. This section of the RIA estimates future avoided impoundment failure cleanupcosts as a potential benefit of the CCR proposedrule, according to thefollowing 5-step method.Step 1. Characterize CCRImpoundment Release DataEPA began by examining the CCR impoundment survey data collectedin March and April 2009 by EPAunder the authority of Section104(e)of the Comprehensive Emergency Response, Compensation and Liability Act (CERCLA), from162 individual electric utility plants and from61 electric utility corporate headquarters offices. EPA obtained its list of facilities from a 2005 Department of Energy (DOE)Survey of coalburning electric utility facilities. EPAused DOE’s 2005 Energy Information Agency F767 database, which provides information on thedisposition of coal ash from coal burningelectricity producers. The database included "steam-electric plants with a generatornameplate ratingof 10 or more megawatts." The term “generator,” means the actual electric generator, not the wholeplant. A plant typically will have one ormore generators. EPA also sent the lettersto corporate offices of the electric utilities to make sure that all of their facilities were accounted fordue to limitations in the DOE survey. Based on information received in response to the initialletter to the utility corporateheadquartersoffices, on April 27, 2009, EPA sent information request letters to an additional 48 plants that had been identified by the corporate offices.Based EPA’s initial collation of the mail survey data, 42 CCR releases from impoundments were reported, all of which occurred within the last15 years (1995-2009), in response to Question 8of the survey questionnaire which askedfor electric power plants to report allCCRimpoundment releases which occurred withinthe last 10 years (i.e., 1999 to 2008).Exhibit 5B-1below presents a summary of these 42 CCRimpoundments release cases.Appendix K11provides additional information about these 42 release cases.134Exhibit 5B-12009 EPA Mail Survey Data for 42 Historical Release Events Involving CCR Impoundments at Coal-Fired Electric Utility PlantsItemOwner CompanyName of Coal-Fired Electric PlantName of CCR ImpoundmentCapacity(acre feet)Height(feet)YearInstalledCCR Release(gallons)ReleaseyearAge atrelease1 Allete Inc Clay Boswell Power Station Coal Pile Sump 1 20 1972 Unknown 2008 362 Ameren Energy Generating Co MeredosiaPower Station Fly Ash Pond 650 24 1968 500 2006 383 American Electric Power Cardinal Power Station Fly Ash Reservoir 2 11350 237 1987 Unknown 2004 174 City of Springfield Lakeside MetalCleaning Waste Basin4 1982 Unknown 1998 165 City of Springfield Lakeside MetalCleaning Waste Basin4 1982 Unknown 2009 276 Dominion Chesterfield Power StationLower (Old) Ash Pond 740 19 1964 Unknown 2005 417 Duke Energy Corp Walter C. BeckjordPower Station Ash Pond C 1400 50 1966 Unknown 1999 338 East Kentucky Power Coop Inc Dale PowerStation Dale Ash Pond #4 112 26 1977 Unknown 2008 319 First Energy Generation Corp Bruce Mansfield Power Station Lakeside Ash Pond 20 1957 Unknown10 Georgia Power Co Harllee BranchPower Station C 1240 83 1971 Unknown 2000 2911 Georgia Power Co Bowen PowerStation Ash Pond 3719 45 1968 Unknown 2002 3412 Georgia Power Co Bowen PowerStation Ash Pond 3719 45 1968 Unknown 2008 4013 Indianapolis Power & Light Co Eagle Valley Generating Station A/B/C Pond 1949 30,000,000 2007 5814 Indianapolis Power & Light Co Eagle Valley Generating Station A/B/C Pond 1949 30,000,000 2008 5915 Kansas City Power & Light Co LaCygne Generating Station Scrubber SludgePonds 6818 45 1971 Unknown 2007 3616 Kansas City Power & Light Co LaCygne Generating Station Scrubber SludgePonds 6818 45 1971 Unknown 2007 3617 Kansas City Power & Light Co LaCygne Generating Station Scrubber SludgePonds 6818 45 1971 Unknown 2009 3818 MidAmerican Energy Co Riverside GeneratingStation South Surface Impoundment 109 10 1967 Unknown 2002 3519 Northern Indiana Pub Serv Co R.M. Schahfer Power Station LittleBlue Run Dam 84300 388 1975 Unknown20 Northern States Power Co Sherburne County Power Station Pond No. 2 57 1984 600 2007 2321 PacifiCorp Naughton Power Station FGD Pond #2 382 25 1999 Unknown 2006 722 PacifiCorp Naughton Power StationNorth Ash Pond 2100 61 1973 11,100,000 2007 3423 PacifiCorp Dave Johnston Power Station Blowdown Canal 1 0 1972 14,400 2009 3724 PacifiCorp Jim Bridger Power Station FGD Pond #1 1340 32 1979 Unknown25 PacifiCorp Jim Bridger Power Station FGD Pond #2 11534 42 1990 Unknown26 PPL Generation, LLC PPL Montour PowerStation Detention Basin 53 8 1968 Unknown 2004 3627 PPL Generation, LLC PPL Martins Creek Power Station Ash Basin 4 40 43 1989 100,000,000 2005 1628 PPL Generation, LLC PPL Montour Power Station Ash Basin No. 1 40 1968 Unknown 2007 3929 PPL Montana LLC Colstrip Steam Electric Station Units 1 & 2 Stage Evaporation Ponds 4370 88 1992 100 1995 330 PPL Montana LLC Colstrip Steam Electric StationUnits 3 & 4 Effluent Holding Pond 17000 138 1983 Unknown 1999 1631 PPL Montana LLC Colstrip Steam Electric Station Units 1 & 2 Stage Evaporation Ponds 4370 88 1992 50 2000 832 PPL Montana LLC Colstrip Steam Electric Station Units 1 & 2 A Pond 245 25 1975 2,700 2003 2833 PPL Montana LLC Colstrip Steam Electric StationUnits 3 & 4 Effluent Holding Pond 17000 138 1983 Unknown 2004 2134 PPL Montana LLC Colstrip Steam Electric StationUnits 3 & 4 Effluent Holding Pond 17000 138 1983 Unknown 2005 2235 PPL Montana LLC Colstrip Steam Electric StationUnits 1 & 2 Stage Evaporation Ponds 4370 88 1992 2,000 2006 1436 Progress Energy Carolinas Inc W. H. Weatherspoon Power Station 1979Pond 28 1979 Unknown 2001 2237 Progress Energy Carolinas Inc Roxboro Power Station FGD Flush Pond 33 2008 Unknown 2008 038 Santee Cooper Winyah Power Station Unit 3 & 4 Slurry Pond 1190 30 1980 Unknown 2008 2839 Tennessee Valley Authority Kingston Power Station Dredge Pond 1955 1,100,000,000 2008 5340 Tennessee Valley Authority Widows Creek Power Station Gypsum Stack (Wet Stacking Area) 11157 75 1986 6,100,000 2009 2341 Xcel Energy PSCo Comanche Station Polishing Pond (#4) 12 0 1972 3,000 2007 3542 Xcel Energy PSCo Valmont StationWest Ash Settling Pond 16 0 1964 5,050 2008 44Minimum = 1 0 1949 50 1995 0Maximum = 84,300 388 2008 1,100,000,000 2009 59Mean (average) = 6,874 59 1976 85,148,560 2005 29Median = 1,750 42 1974 5,050 2007 32Column total (based on gallons releaseddata for 15 of the 42 events) = 1.277 billion135As displayed below inExhibit 5B-2, EPA was able to collect cost data on three of themost significant and recentrelease cases (i.e., casesresulting in the most gallons released):Exhibit 5B-2Cleanup Costs for Three Recent Environmental Releases Involving CCR ImpoundmentsItemOwner company nameCoal-fired electric utilityPlant name & locationImpoundmentrelease yearRelease volume(gallons)EPA-assigned costfor this RIA*1 PPL Generation LLC PPL Martins Creek Power Station PA(“Ash basin 4”)2005 100 million $37 million2 Tennessee Valley Authority (TVA) Kingston TN(“Dredge cell dike”)2008 1.1 billion(5.4 million cubic yards)$3.0 billion3 Tennessee Valley Authority (TVA) Widows Creek Power Station TN(“Gypsum stack”)2009 6.1 million $9.2 millionColumn totals = 1.2061 billion $3.0462 billion* Data sources:•Item 1: Page 29 of “Public Health Issues Surrounding Coal as an EnergySource,” Brian Schwartz, MD, MS, Department of Environmental Health Sciences, February2009 athttp://www.jhsph.edu/bin/g/f/Coal_and_public_health_Mar_2009.pdf•Item 2: $3.0 billion is EPA’s initial “socialcost” estimate assigned in this RIA to the December 2008 TVA Kingston TN impoundment release event. Social costrepresents the opportunity costs incurred by society, not justthe monetary costs for cleanup. OMB's 2003 "Circular A-4: Regulatory Analysis" (page 18) instructsFederal agencies to estimate "opportunity costs" for purpose of valuing benefits and costs in RIAs. This $3.0 billion social cost estimate is larger than TVA’s $933million to $1.2 billion cleanup cost estimate (i.e., TVA’s estimateas of 03 Feb 2010), because EPA’s social cost estimate consists of three other social cost elementsin addition to TVA’s cleanup cost estimate: (a) TVA cleanup cost, (b) response, oversight and ancillary costs associated with local, state, and other Federal agencies,(c) ecological damages, and (d) local(community) socio-economic damages.Appendix Qto this RIA provides EPA's documentation and calculation of these fourcost elements, which total $3.0 billion in social cost.Appendix Qto this RIA also provides an alternative, lower estimate of social costs, based on differentmodeling assumptions for capturing such costs.This alternative analysissuggests that TVA’s cleanupcosts alone may be close to the social costs associated with theKingston impoundment failure. EPAspecifically requests comment on this social costestimate, and will continue to develop this estimate for the final rule.•Item 3: 25 January 2010 e-mail entitled “TVA Widow’s Creek Clean Up Info”from Anda Ray, Sr. Vice President of TVA Environment & Technology and TVASustainablity Officer, to Jim Kohler, EPA-ORCR Environmental Engineer.136Given this limited data, this RIA attempted to quantify the likelihood and costs of future releasesusing a historical methodology. First,distinguished between three typesof historical CCR impoundment structural failures (i.e., releases):1.Catastrophic failures: Involving a billion gallons or more.These releases would havethe potential to cause as much or more damagethan occurred in December 2008 at TVA’s Kingston TN plant.2.Significant failures: Involving between a million and a billion gallons. These would be less than a complete failure, but still costly.TVA Widow’s Creek (6,100,000 gallons) and PPLMartin’s Creek (100,000,000 gallons) are thelowest and highest known releases inthis category, respectively. As an approximation, EPA assumes their costs should also bracket the costs of other significantreleases.132Thus, EPA estimates that the typical costs of a significant failure will be $23.1 million(the average of TVA Widow’sCreek and PPL Martin’s Creek).3.Seepage failures:Involving releases below one million gallons. While thesereleases can still be significant and present risks tohuman health and the environment, this RIA does not include these in this analysis, which under-estimates total costs using thishistorical methodology. These smaller seepsare common to earthen dams and are notnecessarily a problem unless the seepagevolume is increasing or the seepage becomes cloudy - indicating the possible transport of CCR through the embankment.Step 2. Fit a Distribution of Future Releases.For the two categories consisting of catastrophic and significant releases, this RIA estimates not only the cleanup costs of these events, but alsotheir frequency. Since relatively littledata are available, this RIA applies a Poisson distribution. The Poisson distribution is used when rarediscrete events, and not continuous functions, are being modeled. To be a Poisson process, the arrival ofevents must satisfystationarity, nonmultiplicity, and independence. Here, the events (releases) satisfy non-multiplicity because the probability of two or more events in a shortperiod of time is very small. They also satisfy independencebecause releases occurring in one time period are independent ofreleases in anyother time period. However, as these impoundments increase in age, it isquite likely that releasesmight increase over time,which wouldviolate the stationarity requirement. This potential problem isdealt with in Step 4 below. For the present, it will be assumed that releases occurat a constant rate in the future.In general, a Poisson distributioncan be represented by the equation:!)()(kettk 

# λ



# λ−132This is a valid assumption if cleanup costs are closely correlated to tonnage released. Sincecost modeling software typically requires an input of gallons released, thecorrelation is likely strong.137Where:λ= Observed arrival rate (0.067for catastrophic, 0.333 for significant);133t = Time period being projected (50 years)e = Constant (2.71828183)k = Number of impoundmentrelease events projectedThe probabilities of a specific number offuture CCR impoundment catastrophic or significant releases are illustrated inExhibit 5B-2andExhibit 5B-3(cumulative distribution) below.Exhibit 5B-2Poisson Distribution (Lamda=0.067, T=50) (Lamda=0.333, T=50)0.0%2.5%5.0%7.5%10.0%12.5%15.0%17.5%20.0%22.5%0 5 10 15 20 25 30 35Events (K)

ProbabilityCatastrophicSignificant133λwas calculated by dividing the number of events observed between 1995 and 2009 by the 15-year time period.138Exhibit 5B-3Cumulative Distribution0.0%5.0%10.0%15.0%20.0%25.0%30.0%35.0%40.0%45.0%50.0%55.0%60.0%65.0%70.0%75.0%80.0%85.0%90.0%95.0%100.0%0 5 10 15 20 25 30 35Events

ProbabilityCatastrophicSignificant139Step 3. Calculate Future Impoundment Failure Avoided Cleanup Cost BenefitsAfter fitting a distribution of thenumber of releases likely to occur, EPA proceededto combine these with the cost data presented in Step 1above. This was done for the average case and three high-end cases (90th, 95th, and 99thpercentiles). For each case, the number of expectedreleases seen inExhibit 5B-4below was divided by 50 to get the expected number of releases per year. These events were then multiplied bytheir respective costs, and the catastrophic and significant release values were summed in each year.Exhibit 5B-4Projected Future CCR Impoundment ReleasesBased on 15-Year (1995-2009) Period of Historical CCR Impoundment Structural Failure CasesExpected Number ofRelease EventsType of CCRImpoundment Release99th%-ile95th%-ile90th%-ileAverageAssigned CostPer Failure EventCatastrophic 8 7 6 3 $3.0 billion*Significant 27 24 22 17 $23.1 million* Note: $3.0 billion is EPA’s initial “social cost” estimateassigned in this RIA to the December 2008 TVA KingstonTN impoundment release event. Social cost represents the opportunity costs incurred by society, not just the monetarycosts for cleanup. OMB's 2003 "Circular A-4: Regulatory Analysis" (page 18) instructs Federal agencies to estimate"opportunity costs" for purpose of valuing benefits and costsin RIAs. This $3.0 billion social cost estimate is largerthan TVA’s $933 million to $1.2 billioncleanup cost estimate (i.e., TVA’s estimate as of 03 Feb 2010), becauseEPA’s social cost estimate consists of three other social cost elements in addition to TVA’s cleanup cost estimate: (a)TVA cleanup cost, (b) response, oversight and ancillary costsassociated with local, state, and other Federal agencies,(c) ecological damages, and (d) local (community) socio-economic damages.Appendix Qto this RIA providesEPA's documentation and calculation of these four cost elements, which total $3.0 billion in social cost.Appendix Qto this RIA also provides an alternative, lower estimate ofsocial costs, based on different modeling assumptions forcapturing such costs. This alternative analysis suggests thatTVA’s cleanup costs alone may be close to the social costsassociated with the Kingston impoundment failure. EPA specifically requests comment on this social cost estimate,and will continue to develop this estimate for the final rule.However, EIA data indicate that there isa current trend among coal-fired power plants to switch from wet handling to dry handling. As seenbelow inExhibit 5B-5, this will lead to a decrease of approximately 300,000 tonsbeing disposed of in surface impoundments per year, orapproximately 1.3% of the initial 22.5 million tons in 2005. Since the tons disposedof (and similarly, the number of surfaceimpoundments)likely relate to the number of releases, these decreases are accounted for by using 2005 wet tonnage as a benchmark and assuming the quantityof wet tonnage declines 300,000 tons per year.The cost for each year is multiplied bythe remaining percent still handled wet.140Exhibit 5B-5Decreasing CCR Wet Disposal TrendYear% CCR StillDisposed WetYear% CCR StillDisposed WetYear% CCR StillDisposed Wet2005 100.0% 2024 75.2%2043 50.3%2006 98.7% 2025 73.9%2044 49.0%2007 97.4% 2026 72.6%2045 47.7%2008 96.1% 2027 71.2%2046 46.4%2009 94.8% 2028 69.9%2047 45.1%2010 93.5% 2029 68.6%2048 43.8%2011 92.2% 2030 67.3%2049 42.5%2012 90.9% 2031 66.0%2050 41.2%2013 89.5% 2032 64.7%2051 39.9%2014 88.2% 2033 63.4%2052 38.6%2015 86.9% 2034 62.1%2053 37.3%2016 85.6%2035 60.8% 2054 36.0%2017 84.3%2036 59.5% 2055 34.7%2018 83.0%2037 58.2% 2056 33.3%2019 81.7%2038 56.9% 2057 32.0%2020 80.4%2039 55.6% 2058 30.7%2021 79.1%2040 54.3% 2059 29.4%2022 77.8%2041 52.9% 2060 28.1%2023 76.5%2042 51.6% 2061 26.8%The final step in the calculation was to take the adjusted costs in each year and discount themby 3% and 7% to calculate the present value (PV)as displayed inExhibit 5B-6below. A full table of year-by-year costs can be found inAppendix K11. Approximately 97% of these costsresult from catastrophic releases, and theremaining 3% result from significant releases. It is importantto note that no costs are attributed to2012-2014 as the rule will not be adopted and implemented until 2015.However, all costs beginning in 2015 are assumed to be avoided undersubtitle C. Although facilitiesare given 5 years to phase out CCR impoundments under one of the proposed regulatory options,the otheroptions require regular inspectionsof CCR impoundments toprevent catastrophic or significant releases.For a subtitle D approach, expect delayedcompliance with the requirement that surface impoundments be lined and that existingunlinedsurface impoundments be closed if they aren’t lined when compared to compliance with the surface impoundment phaseout under subtitle C.Compliance will largely depend on the uncertainties of state regulations, the implementation of those regulations, and citizensuits. Also, sincesome facilities will line their surface impoundments instead of converting to dry handling, these facilitieswill continue to pose risks forcatastrophic failure even though they may no longer require cleanup costs for groundwater contamination. The percent of stateswith at least141some surface impoundment regulations, 48% as described inAppendix K9, is used as a proxy for the phase-out of existing impoundments.However, the 5.5% of those 48% that would retrofit with composite liners could still pose release risks. This results in 45% of the subtitle Cbenefits being realized in subtitle D.For the subtitle D prime approach, existingimpoundments will not need tobe lined, but can continueto operate until they close. Third-partyinspections of surface impoundmentswould be required under this option, but it isdifficult to predict the extent to which these inspectionswould actually occur and would decrease catastrophic failures. Inany case, the benefits of subtitle D prime would be less than those of subtitleD and greater than the baseline in terms ofcosts of catastrophic failures avoided. Thus, EPA used the midpoint as a best-estimate of theeffectiveness that these inspections would have, which results in 23% of the subtitle Cbenefits being realized in a subtitle Dprime approach.Exhibit 5B-6Estimate of Future CCR Impoundment Structural Failure Cleanup Costs AvoidedAs Benefits Under Three RCRA Regulatory Options(present value in $millions)Discount Rate99th%-ile95th%-ile90th%-ileAverageSubtitle C special waste3% $7,407 $6,483 $5,567 $3,1247% $4,177 $3,656 $3,140 $1,762Subtitle D (version 2)3% $3,333 $2,917 $2,505 $1,4067% $1,880 $1,645 $1,413 $793Subtitle “D Prime”3% $1,704 $1,491 $1,280 $7197% $961 $841 $722 $405Step 4. Account for Increasing CCR Impoundment Release TrendIn Step 2 above, it was noted that the arrival rate of releases mightviolate the stationarity requirement for Poisson distributions. This is due tothe trend of increasing release frequency based on the aging structure of the earthenimpoundments. EPA attempted to discern whether a timetrend was likely between releases and the average age of the surface impoundments. First, EPA limited the universe to the 38 releases that hadreported release dates within the past 15 years. Next, the number of releases in 2009 was scaled up to account for the fact that the EPA mailsurvey questionnaires were returned by June of 2009. Thus, thefour releases in 2009 were scaledup by 12 months/6 months, ora factor of 2.Using commission age and only those releases for which a releaseyear was known, EPA constructed the profile of releases in theyears rangingfrom 1995 to 2009 displayed inExhibit 5B-7below.142Exhibit 5B-7Summary of 15-Year (1995-2009) Period ofHistorical CCR Impoundment Structural FailuresYearCCR impoundmentaverage ageCount ofimpoundmentrelease events% of all CCRimpoundmentsreleasing1995 21.1 1 0.20%1996 21.5 0 0.00%1997 22.5 0 0.00%1998 23.5 1 0.19%1999 24.5 2 0.38%2000 25.3 2 0.38%2001 26.1 1 0.19%2002 27.0 2 0.37%2003 27.9 1 0.19%2004 28.7 3 0.55%2005 29.7 3 0.55%2006 30.5 3 0.55%2007 31.3 7 1.27%2008 32.3 8 1.45%2009 33.0 8 1.44%As can be seen in the table above, both the absolute number of releases and the percent of units with releases have increased over the past 15years. All five significant releases andthe catastrophic release at TVA Kingston TNhave happened since 2005. To account forthis potentiallack of stationarity, EPA conducted a sensitivity analysis withalternate values ofλ. Instead of looking at the last 15 years, EPA assumed thatthe previous 5-year period best reflects impoundment releases.Thus, in place of the earlier calculated lambda values (0.067 and 0.333) derivedby dividing the number of catastrophic andsignificant failures between1995 and 2009 by 15, EPA calculated higher lambdas (0.2and 1) bydividing the catastrophic and significant failures between 2005 and 2009 by 5. Using these new lambda values, but keeping thesame 50-yearforecast period, EPA derived the Poisson distribution seen in the two figures below.The probability of a specific number of catastrophic orsignificant releases is illustrated inExhibit 5B-8andExhibit 5B-9(cumulative distribution) below.143Exhibit 5B-8Poisson Distribution (Lamda=0.20, T=50) (Lamda=1.00, T=50)0.0%1.5%3.0%4.5%6.0%7.5%9.0%10.5%12.0%13.5%0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80Events (K)

ProbabilityCatastrophicSignificant144Exhibit 5B-9Cumulative Distribution0.0%5.0%10.0%15.0%20.0%25.0%30.0%35.0%40.0%45.0%50.0%55.0%60.0%65.0%70.0%75.0%80.0%85.0%90.0%95.0%100.0%0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80Events

ProbabilityCatastrophicSignificant145With these new distributions, EPA performed the same calculationsas described in Step 3. The expected number of releases inExhibit 5B-10below was divided by 50 to get releases per year; these releaseswere multiplied by the cost per release; an adjustment was made to account forvoluntary switching to dry handling;and yearly values were discounted. A full exhibit of year-by-year costs can be found inAppendix K11.Exhibit 5B-10Projection of Future CCR Impoundment ReleasesBased on 5-Year (2005-2009) Historical CCR Impoundment Release CasesExpected Number ofRelease EventsType of CCRimpoundment releaseevent99th%-ile95th%-ile90th%-ileAverageCost per CCRimpoundment releaseeventCatastrophic 18 15 14 10 $3.0 billion*Significant 67 62 59 50 $23.1 million* Note: $3.0 billion is EPA’s initial “social cost” estimateassigned in this RIA to the December 2008 TVA KingstonTN impoundment release event. Socialcost represents the opportunity costs incurred by society, not just themonetary costs for cleanup. OMB's 2003 "Circular A-4:Regulatory Analysis" (page 18)instructs Federal agenciesto estimate "opportunity costs" for purpose of valuing benefits and costs in RIAs. This $3.0 billion social costestimate is larger than TVA’s $933 million to $1.2 billion cleanup cost estimate (i.e., TVA’s estimate as of 03 Feb2010), because EPA’s social cost estimate consists of three other socialcost elements in addition to TVA’s cleanupcost estimate: (a) TVA cleanup cost, (b) response, oversightand ancillary costs associated with local, state, and otherFederal agencies, (c) ecological damages, and (d) local (community) socio-economic damages.Appendix Qto thisRIA provides EPA's documentation and calculation of thesefour cost elements, which total $3.0 billion in socialcost.Appendix Qto this RIA also provides an alternative, lower estimate of social costs, based on differentmodeling assumptions for capturing such costs. This alternative analysis suggests thatTVA’s cleanup costs alonemay be close to the social costs associated with theKingston impoundment failure. EPA specifically requestscomment on this social cost estimate, and will continue to develop this estimate for the final rule.EPA estimated subtitle C (special waste) costs avoided that werebetween two and three times thecosts predicted in Step 3. This differencehelps to explain how significant the assumption of lambda, andthe potential non-stationarity of the data, can have on the final results.Sensitivity results were also calculated for subtitle D (version 2) and subtitle“D prime” approaches. As assumed above for the subtitle D(version 2) option, EPA expects delayed compliance with the requirement that surface impoundmentsbe lined and that existing unlined surfaceimpoundments be closed if they are not lined when compared tocompliance with the surface impoundment phaseout under subtitle C.Compliance will largely depend on the uncertainties of state regulations, the implementation of those regulations, and citizensuits. Also, sincesome facilities will line their surface impoundments instead of converting to dry handling, these facilitieswill continue to pose risks forcatastrophic failure even though they may no longer require cleanup costs for groundwater contamination. The percent of stateswith at leastsome surface impoundment regulations, 48% as described inAppendix K9,is used as a proxy for the phase-out of existing impoundments.However, the 5.5% of those 48% that would retrofit with composite liners could still pose release risks. This results in 45% of the subtitle C(special waste) benefits being realized in Subtitle D (version 2).146For the subtitle “D prime” approach, existing impoundments will not need to be lined,but can continue to operate until they close. Third-partyinspections of surface impoundmentswould be required under this option, but it isdifficult to predict the extent to which these inspectionswould actually occur and would decrease catastrophic failures. Inany case, the benefits of subtitle “D prime” would be less than those ofsubtitle D (version 2) and greaterthan the baseline in terms of costs of catastrophic failures avoided. Thus, this RIA used the midpoint as abest-estimate of the effectiveness that these inspections would have. This results in23% of the subtitle C (special waste) benefits beingrealized in a subtitle “D prime” approach.Exhibit 5B-11below presents the avoided cleanup costestimates for the three regulatory options(i.e., Subtitle C special waste, Subtitle D version 2,and Subtitle “D prime”).Exhibit 5B-11Future CCR Impoundment Structural Failure Cleanup Costs Avoided($millions present value over 50-years)Discount Rate99th%-ile95th%-ile90th%-ileAverageSubtitle C (special waste)3% $16,708 $13,966 $13,043 $9,3717% $9,423 $7,876 $7,356 $5,285Subtitle D (version 2)3% $7,519 $6,285 $5,869 $4,2177% $4,240 $3,544 $3,310 $2,378Subtitle “D Prime”3% $3,843 $3,212 $3,000 $2,1557% $2,167 $1,811 $1,692 $1,216Step 5. Estimate Future Avoided Cleanup Costs for Two Alternative Impoundment Failure Scenarios (Scenario #2 & #3)Not all of these releasesare likely to pose the type of catastrophic risks that were seen atTVA’s Kingston, TN plant. Catastrophic releases aremore likely where there is a high potentialfor impoundment materials to disperse over large areas. This ismost likely to occur at tallimpoundments. Thus, this RIA presents analternative assumption that the Kinston-like catastrophicreleases would only occur at these tallimpoundments. In addition, as age appears tobe a driving factor in releases, this analysis alsoassumed that Kingston-like catastrophic releaseswould occur at older impoundments. Particularly, 96 impoundmentsof the 584 covered in the 2009 EPA mail survey were at least40 feet talland at least 25 years old. The analysisbelow assumes that 10% - 20% of these impoundments could fail within the next 20 years. This isequivalent to the upper percentiles of failures predicted in Steps 3 and 4 above; howeverit moves the costs forward in time, to show thesensitivity of the benefits with respect to time.147Exhibit 5B-12Scenario #2: Cleanup Cost Estimates for CCRImpoundment CatastrophicFailures @ 10% Failures% of TonsBaselineYearCosts @3%(in millions)Costs @7%(in millions)% of TonsSubtitle CCosts @3%(in millions)Costs @7%(in millions)88.2% 2014 - - 88.2% - -86.9% 2015 $1,146 $1,022 70.6% $930 $83085.6% 2016 $1,095 $941 52.9% $677 $58284.3% 2017 $1,047 $866 35.3% $438 $36283.0% 2018 $1,001 $797 17.6% $213 $16981.7% 2019 $956 $733 0.0% $0 $080.4% 2020 $914 $67479.1% 2021 $873 $61977.8% 2022 $833 $56976.5% 2023 $796 $52375.2% 2024 $759 $48173.9% 2025 $724 $44172.6% 2026 $691 $40571.2% 2027 $659 $37269.9% 2028 $628 $34168.6% 2029 $598 $31367.3% 2030 $569 $28766.0% 2031 $542 $26364.7% 2032 $516 $24163.4% 2033 $491 $22162.1% 2034 $467 $202Baseline Total$15,305 $10,309 C Total $2,259 $1,943Given the costs above, the totalbenefits of a Subtitle C phase out over 5 years would be the difference between the potentialcatastrophicfailure costs under C and the catastrophic failure costs under the baseline. For the 20% “Scenario #3”, this figure is double,as displayed belowinExhibit 5B-13. For Subtitle D, it is assumed that the48% of states (by tonnage, as described inAppendix K9) that have at least someregulatory oversight currently, would enforce the retrofitting requirement. However,since 5.5% of impoundments already have compositeliners, these units would not be expected toclose. Thus 94.5% times 48% leads to anapproximately 45% of the Subtitle C benefits. ForSubtitle D prime, the requirement of dam safety inspections would be likely to resultin some amount catastrophic failure reduction between thebaseline and the Subtitle D approach. This RIA uses the midpoint, a 23% reduction, as a best estimate. While these estimatesare likely muchhigher than the actual benefits from preventing catastrophic failures, they do help todefine the upper bound of what is possible under currentpractices of mismanagement.148Exhibit 5B-13Avoided Future CCR Impoundment Catastrophic Failure Cleanup Costs($millions present value)ScenariosSubtitle CSpecial wasteSubtitle D(version 2)Subtitle “D Prime”Scenario #2: Assuming 10% of the 96 Impoundments Failat 3% $13,046 $5,918 $2,959at 7% $8,366 $3,795 $1,897Scenario #3: Assuming 20% of the 96 Impoundments Failat 3% $26,092 $11,836 $5,918at 7% $16,732 $7,590 $3,795Note:These future CCR impoundment failure cleanup costs avoided do not account foravoided costs from releases that are less than “catastrophic.”1495C. Induced Effect of RCRA Regulation on CCR Beneficial UseThis section assesses the potential effectsof the different regulatory options for disposal of CCR on the future annual quantities of CCRbeneficially used. It also estimates thevalues of social and economic impacts associated with baseline and different levels of beneficial use. Itestimates the expected increase in beneficial use from increasedcost of disposal of CCR and evaluates future changes in the beneficial use ofcoal combustion residuals (CCR) as a result of a potential “stigma” effect.5C1. Baseline Environmental &Economic Benefits of CCR Beneficial Use by Other IndustriesAccording to CCR beneficial use market datacompiled for year 2005 as displayed below inExhibit 5C-1, and extrapolated in this RIA to 2009as displayed inExhibit 5C-2below, 62 million tons of annual CCR generated by272of the 495 electric utility plants is not disposed, but isbeneficially used as material substitutes in at least14 industrial applications. The purpose of this section isto provide estimates of twocategories of baseline benefits associatedwith baseline CCR beneficialuse, consisting of five sub-elements (i.e., 1a, 1b, 2a,2b, 2c):1.Economic benefits: Economic benefits estimated in this section are based on recent market prices and include:a.Annual cost savings to over 14 CCR beneficial use industries in the form of reduced industrial raw andintermediate materials purchase prices relative topurchasing higher-priced substitute materials, comparedto paying electric utility plantslower prices for buying and using CCR as an industrial material.b.Cost savings to electric utility plants for avoidingthe cost of disposing CCR which is beneficially used.2.Lifecycle benefits: Lifecycle benefits as quantified in this RIA are based on market orsocial values assigned to the relativephysical consequences of using CCR compared to substitute industrial materials, through the entire “materialsflow” chain of the national economy which consists offive basic stages (1.raw materials extraction, 2.materials processing, 3. industrial manufacturing,4. product use, 5. product end-of-lifespandisposal/recycling). Three lifecyclephysical consequences are quantifiedin this RIA but not all monetized:a.Lifecycle resource consumption savings (water & energy consumption)b.Lifecycle air pollution emissions (GHG, CO, NOx, SOx, PM, Hg, Pb)c.Lifecycle wastes (wastewaters and solid wastes)Lifecycle benefits in this RIA are only based on three categories of CCRbeneficial uses (i.e., concrete,cement, and wallboard representing a sub-total of 58% of all CCR beneficial uses) which were addressed inthe prior 2008 study134used as a reference for this section of the RIA.134Source: EPA Office of Solid Waste “Waste and Materials-Flow Benchmark Sector Report: Beneficial Use of Secondary Materials – Coal Combustion Products,” FinalReport, EPA report nr. 530-R-08-003, prepared by Industrial Economics Inc., 95 pages, 12 Feb 2008 at: http://www.epa.gov/osw/partnerships/c2p2/pubs/benuse07.pdf.The beneficial use market data cited in this source is summarizedfrom the American Coal Ash Association (ACAA) 2005 national survey of the electric utility industry.150Lifecycle benefits encompass economic benefits so these two categories are not additivebut duplicative. Lifecycle benefits inthis RIA arebased on “lifecycle analysis” (LCA), a method which involves estimating both internalized (e.g., market priced) and externalized (e.g., costsnot captured in market prices)material flow consequences:“Life cycle analysis depictsthe production of materials ina system of complex physical outcomes, and can predict theincremental physical consequencesof a change in material inputs, technology, waste managementpractices, or price incentives.In LCA, as in reality, one change in thephysical system, such as the substitution offly ash for virginPortland cement, leadsto acorresponding cascade of economy-wide impactsand shifts. As inputs are substituted, technologies, physical outputs, andexposure pathways change. Using a range of modeling platforms and life cycle inventories to calculate the outputs associatedwith each incremental change, LCAcalculates the net result of all of these interactions, capturing the total incremental effect ofa change in operations on physical environmental impacts such as air emissions, and energy and water use.”•Economic Benefits ofCCR Beneficial UseAs estimated inExhibit 5C-1below (Column F), CCR used for beneficial use applications has an estimated annual US market value of$177millionper-year based on annual CCR sales revenue data supplied by 233electric utility plants tothe 2005 EIA-767 database, updatedin thisRIA to 2009. Based on comparison with the average higher pricesfor substitute industrial materials, using lower-priced CCR provides the USnational economy with$2,300 millionin annual net cost savings compared to the higher$2,477 million annual cost of substitute materials inthese 14 industrial applications (see Column I ofExhibit 5C-1).151Exhibit 5C-1Estimate of Annual Materials Cost Savings Benefit of CCR Generated by the Electric Utility Industry for Beneficial Use in Industrial ApplicationsA B C D E F (C x E) G H (C x G) I (H – F)Item Industry Application 2005 CCRbeneficial use(million tons)% of CCRbeneficial usemarket2005 averagemarket price paidelectric plants*($/ton)Implied annual CCRsales revenues toelectric utility plants2005 avg pricefor substitutematerial($/ton)2005 impliedannualalternativematerials costImplied annualUS national costsavings w/CCRbeneficial uses1 Construction concrete ingredientNAICS code 3273See 1A + 1B See 1A + 1B See 1A+ 1B See 1A + 1B See 1A +1B See 1A + 1B See 1A + 1B1A Direct ingredient: substitute for portionof Portland cement ingredient inconcrete mfgNAICS code 327316.35 33.0% $0 to $45 $0 to $735.8 million $80 $1,308 million $572.2 to $1,308million1B Indirect ingredient: raw feed blendedwith limestone or shale to makecement clinker to be ground intocement for concrete mfgNAICS code 32734.22 8.5% $0 to $45 $0 to $189.9 million $80 $337.6 million $147.7 to $337.6million2 Construction structural fill for buildingfoundations and embankmentsNAICS code 2389108.35 16.8% $1 $8.35 million $3$25.05 million $16.7 million3 Construction wall boardNAICS code 3274208.18 16.5% $0 to $8 $0 to $65.4 million $4.5 to $12 $36.8 to $98.2million$32.8 to $36.8million4 Waste stabilization (substitute for lime)NAICS code 56222.84 5.7% $15 to $25 $42.6 to $71.0 million $66 $187.4 million $116.4 to $144.8million5 Blasting gritNAICS code 2123221.63 3.3% Not reported Not reported Notreported Not estimated Not estimated6 Roofing granulesNAICS code 324122Included withgrit (row 5)Included withgrit (row 5)Not reported Not estimated Not reported Not estimated Not estimated7 Minor uses (n=7)** 8.04 16.2% $3 to $20 $24.1 to $160.8million$5 to $83 $40.2 to $667.3million$16.1 to $506.5millionColumn totals (2005) = 49.61 100%Impliedaverage (F/C)= $3$75 to $1,231 million(best estimate  =$149 million)Impliedaverage (H/C)= $40$1,935 to$2,624 million(best est.** ** =$1,979 million)$1,8302008 updated estimates =62***$177 million$2,477 million$2,300 million($37 per ton)Explanatory notes:Source: Data in columns C, E, and G are from “Waste and Materials-Flow Benchmark Sector Report:Beneficial Use of Secondary Materials – Coal Combustion Products,”EPA report nr. 530-R-08-003, prepared byIndustrial Economics Inc., 95 pages, 12 Feb 2008 at http://www.epa.gov/osw/partnerships/c2p2/pubs/benuse07.pdf* Average price includes “free on board” (FOB) shipping and insurance costs paid by the supplier from the point of manufactureto a specified destination.** Minor uses include: (1) agricultural soil amendment for fluegas desulfurization gypsum, (2) road base foundation layer underlying pavements for bottom ash, (3) minereclamation material as substitute for soil, (4) mineral fillerin asphalt, (5) soil stabilizer, (6) snow and ice control substitute for sand, and (7) mining.*** 2009 update estimated tonnage (Column C above) derived inExhibit 5C-2of 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 salesrevenues” from the DOE-EIA F767_PLANT database for 233 plants.“Best estimate” in Columns H and I derived by numerical interpolation of the ranges displayed based on the proportionate best estimate and range of Column F.152Exhibit 5C-22001-2008 Historical Trend in CCR Beneficial Use Quantity (Short Tons*)A. Actual Data:Year CCR Beneficial Use**(tons per year)% change % Use Linear Regression OutputActual = 2001 37,119,321 R-Squared 0.943Actual = 2002 45,523,256 +22.6%35% Standard Error 1,859,123Actual = 2003 46,384,405 +1.9% 38% Observations 8Actual = 2004 49,089,818 +5.8% 40%CoefficientsActual = 2005 49,612,541 +1.1% 40% Intercept 39,784,058Actual = 2006 54,203,170 +9.3% 43% X Variable 2,867,597Actual = 2007 56,039,005 +3.4% 43%Actual = 2008 60,593,660 +8.1% 46%Notes:* Tons source: Amer. Coal Ash Assochttp://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=3** “Beneficial use” data in this Exhibit correspond to the 15 categories defined in the ACAA dataset which do not match thedefinition (examples) of CCR beneficialuses in EPA-ORCR’s CCR proposed rule.B. Trendline:Year Regression best fit % changeTrendline = 2001 39,784,100Trendline = 2002 42,651,700 7.2%Trendline = 2003 45,519,300 6.7%Trendline = 2004 48,386,800 6.3%Trendline = 2005 51,254,400 5.9%Trendline = 2006 54,122,000 5.6%Trendline = 2007 56,989,600 5.3%Trendline = 2008 59,857,200 5.0%Projection = 2009 62,724,800 4.8%Annual average growth rate = 5.2%Annual CCR Beneficial Use Tons30,000,00035,000,00040,000,00045,000,00050,000,00055,000,00060,000,00065,000,0002001 2002 2003 2004 2005 2006 2007 2008 2009YearACAA actual dataTrendline153Exhibit 5C-3below presents a 2004 state-by-state summary ofannual quantity of CCR beneficially used.Exhibit 5C-3State-by-State Summary ofCCR Beneficial Use (2004*)ABCDEItemState2004 CCRgeneration(short tons)2004 CCRbeneficial use(short tons)% CCRusedbeneficially1 AK 43,000 Not reported NR2 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 NA9 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%ABCDEItemState2004 CCRgeneration(short tons)2004 CCRbeneficial use(short tons)% CCRusedbeneficially31 NH 141,000 57,000 40%32 NJ 600,000 112,000 19%33 NM 3,668,000 864,000 24%34 NV 825,000 314,000 38%35 NY 1,379,000 368,000 27%36 OH 6,980,000 2,290,000 33%37 OK 1,277,000 625,000 49%38 OR 95,000 81,000 85%39 PA 9,545,000 2,941,000 31%40 RI 0 0 NA41 SC 2,172,000 1,169,000 54%42 SD 105,000 28,000 27%43 TN 3,803,000 2,163,000 57%44 TX 12,943,000 4,395,000 34%45 UT 2,341,000 812,000 35%46 VA 2,442,000 203,000 8%47 VT 0 0 NA48 WA 2,301,000 1,683,000 73%49 WI 1,437,000 1,219,000 85%50 WV 7,220,000 2,401,000 33%51 WY 2,106,000 508,000 24%Totals = 129,001,000 44,653,000 35%Notes:* Source: DOE & EPA, “Coal Combustion Waste Management atLandfills and Surface Impoundments 1994-2004,” DOE/PI-0004, Aug2006, page 5 (Table 1) at:http://www.ead.anl.gov/pub/doc/coal_waste_report.pdfIn comparison, the ACAA reports that a 5% smaller amount of122,465,119 tons CCR was generated in 2004154•Lifecycle Benefits Associated with CCR Beneficial UseThe baseline (2005) material costsavings estimate displayed inExhibit 5C-1above is adjusted below to exclude the mining applications use,because mine-filling is not covered in the proposed rule.135As displayed inExhibit 5C-4below, subtracting 2.3% ofthe mining applicationsbeneficial use category decreased the baseline CCR beneficial use from49.6 million tons to 48.5 million tons (relative to 2005).Exhibit 5C-4Subtraction of Mining Application Minor Use from the Minor Use Categoryof the Material Cost Savings for CCR Beneficial UseCCR Beneficial Use Category(Minor Uses)CCR beneficialuse tons (2005)% of allCCR usesMaterials pricecost savings(million 2009$)1. Flowable fill 259,907 0.5% $10.72. Road base/sub-base 1,461,992 2.9% $60.03. Soil modification/stabilization 1,139,640 2.3% $46.84. Mineral filler in asphalt 140,838 0.3% $5.85. Snow & ice control 547,541 1.1% $22.56. Mining applications1,132,9452.3%$46.57. Agriculture 415,741 0.8% $17.18. Aggregate 872,776 1.8% $35.89. Miscellaneous minor uses 2,071,157 4.2% $85.1Sub-total Minor Uses = 8,042,537 16.2% $330.3Total All Uses (Major + Minor) = 49,612,541 100.0% $1,830Total Excluding Mining = 48,479,596 97.7%$1,783.5($37 per ton)From a materials lifecycle analysis perspective, CCR beneficial use generates net environmental benefits. Based on a 2008 lifecycle study136of two of the 14 CCR beneficial use industrial applications (i.e., concrete and wallboard) there are 12 environmental benefit categories with theannual magnitudes estimated below inExhibit 5C-5. This estimate of environmental benefitsis based on only 47% (i.e., 23.2 million tons) ofthe 49.62 million tons for the 2005 CCR beneficial use market as reported in that 2008 study. Thus, these estimates may understate annualenvironmental benefits of CCR beneficial uses. These net benefits are not additiveto the economic benefits, but encompass them.135As noted in the Federal Registernotice of EPA’s proposed CCR rule, minefilling will be addressed in an alternate rulemaking.136Source: Exhibit 5-3 of “Waste and Materials-Flow Benchmark Sector Report: Beneficial Use of Secondary Materials – Coal Combustion Products,” prepared byIndustrial Economics Inc for the EPA Office of Solid Waste, 12Feb 2008, 95 pages at http://www.epa.gov/osw/partnerships/c2p2/pubs/benuse07.pdf155To avoid double-counting of economic and social benefits, EPA evaluated the monetization of the energy, water, and air pollution-relatedimpacts for any such double counting. Based on this evaluation,this RIA concludes that each of the individual monetized estimates for theseimpacts are fully additive and do not double count benefits, with one exception regarding partial overlap between energy cost savings and thevalue of avoided SOx air emissions. For SOx, where there existsa cap and trade permit program, firms must pay to emit SOx. Aportion of theSOx emissions avoided from beneficially using CCR is from the energy sector. Under the presumption that the marginal costs ofabatementequal the value of marginal damages, the value of the portion of SOx emissions from the energy sector willbe reflected in theenergy costsavings. The portion of avoided SOx emissions that comes from sectors other than energy is notreflected in energy cost savings and thusshould be retained. However, separatelyadding a value for reduced SOx emissionslikely represents some amount of double counting.Unlike the SOx permit program, most regulation of NOx and particulate matter (PM) does not require firms to purchase permits topollute.Thus there is little to no overlap betweenthe external costs of these air pollutantsand energy costs. In addition, aside from limited stateprograms, GHG damages are not currently regulated and would not be reflected in the market price for energy. Thus, the benefits from NOx,particulates and GHG reductions are fully additive to private energy cost savings. Furthermore,for water use, the only benefits included arethe direct cost savings, and because the water savings in these cases are not associated with energy production, these savingsare not beingcaptured elsewhere. Reduced water use in the production process is a realcost savings that should bea component of total benefits.Therefore, this RIA concludes that thereis only a partial double counting between energy cost savings and the savings associated with reducedSOx emissions. No other beneficialuse benefits categories are affectedby this double counting issue. Thus,Exhibit 5C-5below hassubtracted the $1,491 million benefits attributable to SOx reductions from the environmental benefits estimate, resulting in anenvironmentalestimate of$22,980 million per year, or$474 per tonaverage lifecycle benefit, assigning zero values to tonnage otherthan concrete andwallboard. In addition tobaseline lifecycle benefits, there are an estimated$2,927 million per yearin baseline avoided disposal cost benefitsto the electric utility industry (i.e., (49.61 million tons CCR beneficial use in 2005) x ($59 per ton average baseline disposal cost estimated inExhibit 3Lof this RIA)), which constitutes a total of$25,907 million per year(relative to 2005 CCR beneficialuse tonnage), which is anaverage of$533 per tonnationwide baseline social benefits from CCR beneficial use.Exhibit 5C-5Estimate of Annual Baseline Lifecycle Benefits from CCR Beneficial Use(Based on 2005 CCR beneficial use tonnage)Benefit categoryPhysical quantity of environmental benefits for48.5 million tons annual CCR beneficial use w/out mining application*Unit monetizationvalues (2009$)**Estimated benefits($millions per year)A. Resource Consumption Savings1. Energy consumption 158 trillion BTU energy savings $0.00003093 per BTU $4,8882. Water consumption 32.1 billion gallons water savings $0.0025259 per gallon $81Subtotal (1+2) = $4,969B. Air Pollution Savings3. GHG - greenhouse gases 11.5 million metric tons CO2 equivalent emissions avoided $20.76 per metric ton $2394. CO – carbon monoxide 9,200 metric tons emissions avoided Not estimated Not estimated5. NOx – nitrous oxides 30,400 metric tons emissions avoided $10,255 per metric ton $312156Exhibit 5C-5Estimate of Annual Baseline Lifecycle Benefits from CCR Beneficial Use(Based on 2005 CCR beneficial use tonnage)Benefit categoryPhysical quantity of environmental benefits for48.5 million tons annual CCR beneficial use w/out mining application*Unit monetizationvalues (2009$)**Estimated benefits($millions per year)6. SOx – sulfur oxides 23,900 metric tons emissions avoided $62,375 per metric ton $1,4917. PM – particulate matter 9,704 metric tons emissions avoided $486,312 per metric ton $4,7198. Particles non-specified 26,200 metric tons emissions avoided $486,312 per metric ton $12,7419. Hg - mercury 0.584 metric tons emissions avoided Not estimated Not estimated10. Pb - lead 0.656 metric tons emissions avoided Not estimated Not estimatedSubtotal (3 to 10) = $19,502Subtotal air pollution savings excluding SOx & excluding mine-filling use = $18,011C. Other Environmental Savings11. Waterborne wastes2,446 short tons waste generation avoided(SM + BOD + COD + Cu + Hg + Pb + Se)Not estimated Not estimated12. Solid waste 27,991 short tons waste generation avoided Not estimated Not estimatedTotal (1 to 12) = $24,471Total annual lifecycle benefits (excluding SOx & excluding mine-filling use) =$22,980($474/ton)Notes:* Physical quantity of environmental benefits are based on onlytwo of the 14 beneficial use industrial applications (i.e., 15.0 million tons per year fly ash CCR used inconcrete, plus 8.2 million tons per year FGD CCR used in wallboard). These estimates are from Exhibit 5-3 (page 5-6) of “Wasteand Materials-Flow BenchmarkSector Report: Beneficial Use of Secondary Materials – Coal Combustion Products,” prepared by Industrial Economics Inc for theEPA Office of Solid Waste, 12 Feb2008; available athttp://www.epa.gov/osw/partnerships/c2p2/pubs/benuse07.pdf. This 2008 reference report does not provide environmental impact estimates for theother 12 beneficial use industrial applications.** Unit monetary values applied for monetization are from the following sources:•Row 1 & Row 2: 2007 values from Exhibit 5-3 (page 5-6) of the Industrial Economics Inc reference report. Unit values updated for this RIA from 2007 to 2009using NASA’s Gross Domestic Product Deflator Inflation Calculator athttp://cost.jsc.nasa.gov/inflateGDP.html•Row 3: Based on the September 2009 interim social cost of carbon (i.e., interim SCC) from Table III.H.6-3, page 29617 of the joint EPA and DOT-NHTSA“Proposed Rulemaking to Establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards,” Federal Register,Volume 74, No. 186, 28 Sept 2009. The value applied in this RIA is the $19.50 per ton median value from the $5 to $56 per tonrange displayed in the 2007column in that source. Furthermore, this RIA updated the 2007$ median value from 2007 to 2009 dollars using the NASA Gross Domestic Product DeflatorInflation Calculator at http://cost.jsc.nasa.gov/inflateGDP.html. EPA is aware that final SCC values were published on March 9, 2010 in conjunction with aDepartment of Energy final rule. EPA intends to use the finalSCC values for the CCR final rule RIA. The final SCC values arepublished in the Department ofEnergy, Energy Efficiency & Renewable Energy Building Technologies Program, "Small Electric Motors Final Rule Technical SupportDocument: Chapter 16 -Regulatory Impact Analysis", March 9, 2010 at http://www1.eere.energy.gov/buildings/appliance_standards/commercial/sem_finalrule_tsd.html).•Rows 4-10: Unit values from the report “The Influence of Location, Source, and Emission Type in Estimates of the Human Health Benefits of Reducing a Ton ofAir Pollution” by Neal Fann, Charles Fulcher and Bryan Hubbell, in Air Quality, Atmosphere & Health,Volume 2, No.3, Sept 2009, pages 169-176. The dollarvalues from this report were updated from 2006 to 2009 using NASA’s Gross Domestic Product Deflator Inflation Calculator athttp://cost.jsc.nasa.gov/inflateGDP.html•Rows 12-13: Waterborne waste and solid waste generation avoided benefits were not monetized in the 2008 Industrial Economics Inc. reference study cited above.1575C2. Potential Effect of RCRA Regulationof CCR Disposal on CCR Beneficial UseUnder the proposed regulation, the Bevill exemption still applies to quantities of CCR directed to certain beneficial uses so that these quantitiesdo not face increased disposal costs associated with Subtitle C or D regulation of disposed CCR. The increased costs of disposal of CCR as aresult of their regulation under RCRA subtitle C will create a strong economic and regulatory incentive for increased beneficial uses of CCR.In fact, EPA concludes that the increasedcosts of disposal of CCR under subtitle C ofRCRA, but not the beneficial use of CCR,will actuallyincrease their usage in non-regulated beneficial uses, simply as a result ofthe economics of supply and demand. The economicdriver -availability of a low-cost, functionally equivalent or often superior substitute for other raw materials - will continue to make CCR anincreasingly desirable product. Furthermore, it has been EPA’s experience in theRCRA hazardous waste regulations and elsewhere thatmaterial inevitably flows to less regulated applications.On the other hand, industry and state governmentstakeholders have asserted in lettersto EPA, that regulation of CCR as a RCRA“hazardouswaste” will impose a “stigma” on CCR beneficial use which will significantly curtail these uses. In their view, even an actionthat regulatesonly the disposal of CCR in landfills or surface impoundments ashazardous waste, but retains the Bevill exemption for beneficial uses, wouldhave this effect. Also, the states particularly have argued that, by operation of state law, the beneficial use of CCR would be prohibited undermany states’ beneficial use programs, if EPA wereto designate CCR as a hazardous waste when disposed.The purpose of this section of the RIA isto quantify both possibilities– i.e., an induced increase(Scenario #1) and an induced decrease(Scenario #2) -- in future CCR beneficial use, and to explain the basis for this RIAselecting the former (Scenario #1) as the“base case.”•Examples of Hazardous Waste Recycling Success Not “Stigma”EPA’s past experiences with the impacts ofRCRA regulation, and with how RCRA industrial hazardous wastesand other hazardous materialsare used and recycled, suggests that a “hazardous waste” designation of industrial secondary materials and wastes, does not impose asignificant barrier to its beneficial use (e.g., recycling), and that non-regulateduses generally increase as the costs of regulated disposalincrease. As summarized below, EPA’s experience has shown thatthe economic incentive of a highdisposal cost has outweighed anyhypothetical stigma effect in case after case of hazardous wasterecycling. Six examples listed below illustrate the point that a RCRA“hazardous waste” designation does not stand inthe way of a material’s (or waste’s) subsequent industrial recycling or reuse as a raw orintermediate material:1.Electric arc furnace dust:RCRA hazardous waste (waste code = K061), and yet itis a highly recycled material. Specifically, between2001 and 2007, approximately 42% to 51% of K061 was recycled asevidenced by Biennial Reporting System (BRS) data. Bothcurrently and historically, K061 has been usedas an ingredient in fertilizer, an input in making steel, and in the productionof zincproducts, including pharmaceutical materials.Slag from the smelting of K061 is inhigh demand for use in road construction.The useof slag is regulated under Pennsylvania’s beneficial use program, despite the fact thatit is derived from a listed hazardous waste. Infact, there is little doubtthat, without its regulation as ahazardous waste, a significantlygreater amount of K061 would bedivertedfrom recycling to disposal in non-hazardous landfills.1582.Electroplating wastewater sludge:Listed hazardous waste (F006) that is recycled for its copper, zinc, and nickel content for use in thecommercial market. In 2007, approximately 35% of F006 material was recycled according to BRS data. These materials are clearly inno way stigmatized in the marketplace.3.Chat:Superfund cleanup waste with lead contamination is used in road construction in Oklahoma and the surrounding areas. In thiscase, the very waste that has triggered an expensive Superfundcleanup is successfully offered inthe marketplace as a raw material inroad building. The alternative costs of disposal in this case are a significant driver in the beneficial use of this material,and theSuperfund origin of the materialhas not prevented its use.4.Used oil:Frequently a hazardous waste if disposed of, and is regulatedunder the RCRA subtitle C standards. While used oil that isrecycled is subject to a separate set ofstandards under subtitle C(and is not identified as a hazardous waste), “stigma” doesnot preventhome do-it-yourselfers from collecting usedoil, or automotive shops from acceptingit and sending it on for recovery. Collected usedoil may be re-refined, reused, or used as a fuel in boilers, often at the site where it is collected. One large commercial used oil handlerreports managing 500 million gallons of used oil a year.5.Spent etchants:Directly used as ingredients in the production of a copper micronutrient for livestock.6.Spent solvents:Generated from metals parts washing are directly used in the production of roofing shingles.And in all such cases, these materials aregenerally RCRA hazardous wastesbefore reclamation. Many materials widely used in homes todaycan be classified as “hazardous” materials,and many come with warning labels. For example, motor oil comes with warning labels. Gasolinewould be a characteristic hazardous wasteif disposed of, as would many common drain cleaners and household cleaners. Cathoderay tubemonitors for TVs and computers, as well as many fluorescent lampsare all hazardous wastes if disposed of. Fluorescent lamps (and CFLs) arepotentially hazardous when disposed of because of mercury. Mercury is an indispensable resource,and virtually all of the mercury used forlamps and other uses in the U.S. is derived from discarded mercury or mercury products – that is, from hazardous waste. Even products asunlikely as nicotine gum or dental amalgamwould be a hazardous waste when disposedof. Consumers are generally comfortable with theseproducts, and their regulatory status does not discourage their use.•Differing Views About Prospect of Future “Stigma”Stakeholders have also expressed the concern that standards-setting organizations might prohibit the use of CCR in specific products ormaterials in their voluntary standards.Recently, the American Standards and Testing Materials (ASTM) International CommitteeC09, and itssubcommittee, C09.24, in a December 23, 2009 letter to EPA indicated that ASTM would remove fly ash from the project specifications in itsconcrete standard if EPA determined thatCCR were a hazardous waste. However, ASTMstandards are developed through an open consensusprocess, and current standards cover the use of numerous hazardous materials in construction and other activities. For example, ASTMprovides specifications for the reuse of solvents and thus, by implication, does not appearto take issue withthe use of theserecycled wastes,despite their classification as hazardous wastes.137137For example, see ASTM Volume 15.05, Engine Coolants, Halogenated Organic Solvents and Fire Extinguishing Agents; Industrial and Specialty Chemicals, at orASTM D5396 - 04 Standard Specification for Reclaimed Perchloroethylene.159Others take a different view onhow standard-setting organizationswill react. Most notably, aUS Green Building Council representative hasbeen quoted in the New York Timesas saying that LEED incentives for using fly ash inconcrete would remain in place, even under an EPAhazardous determination. If the Green Building Council (along with EPA) continues to recognize fly ash as an environmentally beneficialsubstitute for Portland cement, EPA believes that the use of this material is unlikelyto decrease solely because of “stigma” concerns.In addition, Congress directed government agencies to increase their purchase of recycled-content products. Specifically, section 6002 ofRCRA requires EPA to designate products thatcan be made with recovered materialsand to recommend practices for buying these products.Once a product is designated, “procuring agencies”138are required to purchase it with the highestrecovered material content level practicableif they spend more than $10,000 a year on thatitem. EPA’s federal Comprehensive Procurement Guidelines (CPG), requiring the use of fly ashin cement for federally funded projects, would remain in place.Thus, any federal, state, or local agency carrying out federally fundedconstruction projects would continue to berequired to give a preference to fly ash as a Portland cement replacement.Finally, many state governments have argued that their statutes or regulations prohibit the use of hazardous wastes in their state beneficial useprograms, and therefore that, if EPA listsCCR as a hazardous waste (even if only for disposal), their use would be precluded in those states.EPA has reviewed the regulationsof 10 states with the highest consumption of fly ash and/or cement and concluded that while these states donot allow the use of hazardous waste in their beneficial use programs, CCR that are beneficially reused will remain Bevill-exempt solid wastes,or in some cases, would not be considered wastes at all andthus, the continued use of CCR underthese programs should not be affected by theproposed CCR rule. For EPA’s summary of 10 stategovernment CCR beneficialuse regulations, seeAppendix K12. For the above reasons,this RIA presents the increased future CCRbeneficial use (Scenario #1)as the “base case.” However,this RIA monetizes both scenarios (i.e.,induced increase and induced “stigma” decrease) using the following 10-step method.Step 1. Project Future Annual Tonnage CCR GenerationTo estimate the levels of CCR beneficial use, the first task was to project the future annual tonnage of CCR generated by the electric utilityindustry. The amount of CCR is likely toincrease proportionally, as utilities complywith new Clean Air Act requirements. Not reflecting thisproportional increase, this RIA relied on the EIA future forecast for coal burned by the electric utility industry.139As displayed inExhibit 5C6below, the EIA data extends out to the year 2035. However, to remain consistent with the other cost and benefit estimates, this RIA extendedthis trend out to the year 2061 based on regression-fit extrapolation using the following first-order regression of coal burnedas dependentvariable against year asindependent variable:138Procuring agencies include all federal agencies, and any state or local agency or government contractor that uses appropriatedfederal funds.139Source: Based on 2007 to 2035annual short tons coal consumption by electric power sector forecast data from the Energy Information Administration (EIA), “Year-byYear Reference Case Tables (2008-2035): Table 15 Coal Supply, Disposition, and Prices” from the report “Annual Energy Outlook 2010 Early Release,” December 14,2009 athttp://www.eia.doe.gov/oiaf/aeo. The EIA report presents a midterm projection and analysis of US energy supply, demand, and prices through 2035, based on theEIA’s National Energy Modeling System. Further information on the EIA’s projections is available at160xy10 

# β

β+=Where:y = Tons coal burned at time = xβ0= Tons coal burned at time = 0β1= Additional tons coalburned each year, on averagex = Time elapsed (years)Running the regression, calculated aβ0(or intercept) of 1,001,902,312; aβ1(or slope) of 6,082,277; and an R-squared (or fit) of 87%. Thisregression was used to extrapolate the EIA projection out to the year 2061 as displayed inExhibit 5C-7and as graphed inExhibit 5C-8below.Table 5C-6Coal Burned Forecast Data From EIAYearX = TimeElapsedY =EIA Projection(Tons Coal Burned)2007 0 1,045,140,1372008 1 1,041,599,9762009 2 951,846,2522010 3 970,887,2072011 4 1,025,782,2272012 5 1,049,056,5192013 6 1,057,912,8422014 7 1,069,233,1542015 8 1,044,051,8802016 9 1,053,579,2242017 10 1,052,420,6542018 11 1,062,561,6462019 12 1,071,914,0622020 13 1,073,440,3082021 14 1,090,903,9312022 15 1,098,539,6732023 16 1,102,742,0652024 17 1,096,057,1292025 18 1,115,724,2432026 19 1,111,202,0262027 20 1,121,313,4772028 21 1,131,518,6772029 22 1,128,823,1202030 23 1,146,826,7822031 24 1,149,894,0432032 25 1,160,750,9772033 26 1,156,721,8022034 27 1,161,479,7362035 28 1,182,647,705161Exhibit 5C-7EPA Extrapolation of EIA Projection to 2061YearTons BurnedYearTons Burned2007 1,001,902,312 2035 1,172,206,0652008 1,007,984,589 2036 1,178,288,3422009 1,014,066,866 2037 1,184,370,6192010 1,020,149,143 2038 1,190,452,8962011 1,026,231,420 2039 1,196,535,1732012 1,032,313,697 2040 1,202,617,4502013 1,038,395,974 2041 1,208,699,7272014 1,044,478,251 2042 1,214,782,0032015 1,050,560,527 2043 1,220,864,2802016 1,056,642,804 2044 1,226,946,5572017 1,062,725,081 2045 1,233,028,8342018 1,068,807,358 2046 1,239,111,1112019 1,074,889,635 2047 1,245,193,3882020 1,080,971,912 2048 1,251,275,665Exhibit 5C-7EPA Extrapolation of EIA Projection to 2061YearTons BurnedYearTons Burned2021 1,087,054,189 2049 1,257,357,9422022 1,093,136,466 2050 1,263,440,2192023 1,099,218,743 2051 1,269,522,4952024 1,105,301,019 2052 1,275,604,7722025 1,111,383,296 2053 1,281,687,0492026 1,117,465,573 2054 1,287,769,3262027 1,123,547,850 2055 1,293,851,6032028 1,129,630,127 2056 1,299,933,8802029 1,135,712,404 2057 1,306,016,1572030 1,141,794,681 2058 1,312,098,4342031 1,147,876,958 2059 1,318,180,7102032 1,153,959,235 2060 1,324,262,9872033 1,160,041,511 2061 1,330,345,2642034 1,166,123,788 Total 64,136,808,356162Exhibit 5C-8Extending EIA Projections900,000,000950,000,0001,000,000,0001,050,000,0001,100,000,0001,150,000,0001,200,000,0001,250,000,0001,300,000,0001,350,000,0001,400,000,0002007 2012 2017 2022 2027 2032 2037 2042 2047 2052 2057Year

Coal Burned (Tons)EIA ProjectionEPA Regression163Based on the most recent CCR beneficial use data from ACAA, EPA estimated the average tons of CCR generated for every ton of coal burnedby electric utility plants. For this calculation, this RIA only used the most recentdata year (2008) toestimate a conversionrate because overtime, the quantities of CCR generated per ton of coal combusted has steadily increased. Thus anaverage of recent years wouldnot reflect thistrend. The steady increase over time isdue to tightening of industrial air pollution regulations. This trend would likely continue in the futureas further facilities undergo new source review, or implement new Clean Air Act requirements under upcoming EPA rules like theClean AirInterstate Rule (CAIR) and the Clean AirMercury Rule (CAMR). Thus, the future annual tonnages of CCR estimated in this RIA are likelyunder-estimates. Dividing the 2008 tons of CCR generated (136 million tons) by the 2008 tons of coal burned by the electric power sector(1,042 million tons), EPA produced a CCR-to-coal relationship factorof 0.131. Applying this factorto the extrapolated coal consumptionprojection produced the future CCR generation scenario displayed below inExhibit 5C-9.Exhibit 5C-9Projected Future Annual CCR Generation by the Electric Utility Industry:Scenario Based on Extrapolation of EIA’s Projection of Electric Power SectorCoal Burned 2007-2035(Short Tons)YearCCRYearCCRYearCCRYearCCR2012 134,764,862 2025 145,087,115 2038 155,409,369 2051 165,731,6222013 135,558,881 2026 145,881,135 2039 156,203,388 2052 166,525,6422014 136,352,901 2027 146,675,154 2040 156,997,408 2053 167,319,6612015 137,146,920 2028 147,469,174 2041 157,791,427 2054 168,113,6812016 137,940,940 2029 148,263,193 2042 158,585,447 2055 168,907,7002017 138,734,959 2030 149,057,213 2043 159,379,466 2056 169,701,7202018 139,528,979 2031 149,851,232 2044 160,173,486 2057 170,495,7392019 140,322,998 2032 150,645,252 2045 160,967,505 2058 171,289,7592020 141,117,018 2033 151,439,271 2046 161,761,525 2059 172,083,7782021 141,911,037 2034 152,233,291 2047 162,555,544 2060 172,877,7982022 142,705,057 2035 153,027,310 2048 163,349,564 2061 173,671,8172023 143,499,076 2036 153,821,330 2049 164,143,5832024 144,293,096 2037 154,615,349 2050 164,937,603Appendix K5to this RIA presents alternative estimates of future CCR generation. These estimates take into account the recent increasingtrend in the ratio of tons CCR generated tothe tons coal combustion. For example,in year 2035 the constant ratio projectionabove yields avalue of 153 million tons CCR generated whereas the increasing ratio projection inAppendix K5yields a value of 191 million tons of CCRgenerated. While the exact magnitude of suchan increase is uncertain, there would beat least some increase as a result of increased airpollution controls. These includefuture changes due to EPA’s New Source Review (NSR), EPA’s Clean Air Interstate Rule (CAIR),andEPA’s Clean Air Mercury Rule (CAMR).164Step 2. Project Future Baseline Annual TonnageCCR Beneficial Use (Without RCRA Regulation)This step involves projecting the extent towhich CCR would be beneficially used in the absence of the proposed RCRA regulationof CCRdisposal (i.e., future baseline CCR beneficial use).Exhibit 5C-10below displays the recent (i.e., 2001to 2008) trend in annual tonnage ofCCR beneficial use, and as a percentage relative to annual CCR generation by the electric utility industry.Exhibit 5C-10Recent CCR BeneficialUse Trend (2001-2008)YearCCR Generation(short tons)CCR Beneficial Use(short tons)Fraction2001 117,930,542 37,119,321 31.5%2002 128,703,572 45,523,256 35.4%2003 121,744,571 46,384,405 38.1%2004 122,465,119 49,089,818 40.1%2005 123,126,093 49,612,541 40.3%2006 124,795,124 54,203,170 43.4%2007 131,127,693 56,039,005 42.7%2008 136,073,107 60,593,660 44.5%Source: American Coal Ash Association (ACAA) athttp://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=3If the recent trends in CCR generation and CCR beneficialuse continued in a linear fashion, more than 100% of CCR would be beneficiallyused before year 2061. Furthermore, a linear extrapolation for beneficial use would notbe appropriate because as more and more CCR is used,it would likely become increasingly difficult to use the remaining CCR due to saturation of local markets, competition betweenCCRgenerators, and other factors, depending onoverall macro-economic factors. Thus, for purpose of extrapolation to the 50-yearperiod-ofanalysis (2012 to 2061), this RIA insteadmodeled the recent trend data as an asymptotic, exponential function of the form:)*(11DXCBY+−=Where:Y = Percent of CCR beneficially usedX = Time elapsed relative to 2001B = 1.021C = 1.369D = 13.99165Beneficial uses of CCR have beenconsistently growing in the recent past. Since thepercent of CCR beneficially used has beengrowing, EPAsought to characterize that trend sothat the future percent beneficially used could be applied tothe future tons of CCR. TheACAA data from2001 to 2008 indicate that this trend was increasing. After running several regressions,EPA disposed of the typical trend fits for variousreasons. A first-order (linear)trend line was abandoned because it would have led to beneficial use above 100% well within the time-frame ofthe analysis. Higher order regressions led tooddities where beneficial use would trend away from 100% at some point in time.Once typicalfits were ruled out, EPA assumed that CCR beneficial use would not exceed 100% of CCR generated.140Instead, it would potentially becomemore and more difficult to use CCR as a higher percent went to beneficialuses, because of market limitations. Thus, it made sense to use anexponential curve that approached, but never crossed an asymptote of 100% beneficial use.To fit an exponential curve tothe 2001 to 2008 CCR beneficial use data, a spreadsheet calculation solver was programmed to minimize theresidual sum of squares between the actualand projected percent of CCR beneficial use by changing the regression equation variables B, C,and D. From solver result, B was set to 1.021, C was set to1.369, and D was set to 13.99. Using these values, the future CCRbeneficial useprojection as measured on a percentage basis relativeto CCR generation were estimated, as displayed inExhibit 5C-11andExhibit 5C-12below. The percentage of CCR beneficially used under the baseline (i.e., without RCRA regulation) isexpected to gradually approach, butnever reach 100% of CCR generation. By 2061at the end of the 50-year period-of-analysis, 88% of CCR would be beneficially used under thisprojection. While this is a relatively high number, current experiences in at least one US state and in at least 16 other countries (i.e., 15European countries + Japan), already demonstrate that very high CCR beneficial use rates of 90% and above are achievable:1.Wisconsin: Several companies are developing technologies to convert CCR into bricks usedin construction, and one such technologywas recently commercialized in Wisconsin.141Some of these technologieshave the potential for using100%CCR (fly ash) in brickproduction, as opposed to the conventional 30%-50%limit for replacing Portland cement in concrete.2.Europe: As of 2007, 15 European countries reported a CCR beneficial use rate of89%(i.e., 55.449 million metric tons beneficiallyused in 2007 in 24 industrial applications, out ofthe 62.094 million metric tons generated in 2007).1423.Japan: As of 2006, Japan reported aCCR beneficial use rate of97%(i.e., 10.657 million tons used in Japan in 2006 for 3 cementapplications, 6 civil engineering applications, 3 construction applications, 2 agriculture/forestry/fisheries applications, andat least threeother miscellaneous applications, out of the10.969 million tons CCR generated in Japan in 2006).143140The fact that some electric utility plants currently excavate previously disposed CCR for supplying to beneficial use marketssuggests this may be a limiting assumptionwhich could underestimate future potential growth of CCR beneficial use. For example, one electric utility company reported a106% CCR beneficial use rate in 2006 forits four electricity plants because it recovered CCR that it had previously disposed.141Source: “CalStar Gives Sneak Peek of Low-Carbon Brick Factory,” Cleantech Group, 27 Oct 2009 at http://cleantech.com/news/5217/calstar-flyash-low-carbon-brick142Source: Europe’s 2007 CCR beneficial use rate is reported by ECOBA (European Coal Combustion Products Association) which was founded in 1990 by Europeanenergy producers to deal with matters related to the usage of construction raw materials from coal. As of 2009, membership inECOBA consists of 24 companies andassociations from 15 countries in Europe, all generators of electricity and heat. ECOBA members represent over 86 % of total CCR generation by the 27 total Europeancountries. ECOBA’s 15 member countries are Belgium, Denmark,Finland, France, Germany, Greece,Ireland, Italy, Netherlands, Poland, Portugal, Romania, Russia,Spain, and United Kingdom. ECOBA’s 2007 CCR beneficial use rate is reported in “Production and Utilisation of CCPs in 2007 inEurope (EU 15)” at:http://www.ecoba.com/evjm,media/statistics/ECOBA_Stat_2007_EU15.pdf143Source: Japan’s 2006 CCR beneficial use rate is reported by the Japan Coal Energy Center (JCOAL) in Table 3-1 of “Status of Coal Ash Production” at:http://www.jcoal.or.jp/coaltech_en/coalash/ash01e.html166Exhibit 5C-11Projected Future Baseline CCR Beneficial UseMeasured as Percentageof CCR GenerationYear% Beneficial UseYear% Beneficial UseYear% Beneficial UseYear% Beneficial Use2001 33.22% 2016 56.67% 2031 71.89% 2046 81.76%2002 35.11% 2017 57.91% 2032 72.69% 2047 82.28%2003 36.96% 2018 59.10% 2033 73.47% 2048 82.79%2004 38.75% 2019 60.27% 2034 74.22% 2049 83.28%2005 40.49% 2020 61.39% 2035 74.95% 2050 83.75%2006 42.19% 2021 62.49% 2036 75.67% 2051 84.21%2007 43.83% 2022 63.56% 2037 76.36% 2052 84.66%2008 45.43% 2023 64.60% 2038 77.03% 2053 85.10%2009 46.98% 2024 65.60% 2039 77.68% 2054 85.52%2010 48.49% 2025 66.58% 2040 78.32% 2055 85.93%2011 49.95% 2026 67.53% 2041 78.94% 2056 86.33%2012 51.37% 2027 68.45% 2042 79.53% 2057 86.72%2013 52.76% 2028 69.35% 2043 80.12% 2058 87.10%2014 54.10% 2029 70.22% 2044 80.68% 2059 87.47%2015 55.41% 2030 71.07% 2045 81.23% 2060 87.82%2061 88.17%Japan’s 17 types of CCR beneficial use applications are listed for year 2003 in Table 1 “Breakdown of Fields for the EffectiveUse of Coal Ash” from “Part 2 CCTOverview Environmental Protection Technologies (Technologies to Effectively Use Coal Ash): 5C1. Coal Ash Generation Process andApplication Fields” athttp://www.brain-c-jcoal.info/cctinjapan-files/english/2_5C1.pdf167Exhibit 5C-12Beneficial Use Trend0.00%10.00%20.00%30.00%40.00%50.00%60.00%70.00%80.00%90.00%100.00%2001 2006 2011 2016 2021 2026 2031 2036 2041 2046 2051 2056 2061Year

Beneficial Use (%)ActualProjected168Applying the percent of CCR beneficially usedin each year to the quantities of CCR shown above, the following future annual tons ofbeneficially used CCR may be expected as displayed below inExhibit 5C-13. The monetized value of this future baseline projection is:PV @3% discountPV @7% discountEconomic value: $102,290 million PV $51,170 million PVLifecycle social value: $1,554,323 million PV $777,541 million PVExhibit 5C-13Baseline Projected Future CCR Beneficial Use(Short Tons)YearCCR Beneficial UseYearCCR Beneficial UseYearCCR Beneficial UseYearCCR Beneficial Use2012 69,234,181 2025 96,599,301 2038 119,713,602 2051 139,569,0372013 71,516,427 2026 98,514,244 2039 121,345,430 2052 140,985,2022014 73,767,022 2027 100,404,645 2040 122,958,473 2053 142,387,1392015 75,986,563 2028 102,270,993 2041 124,553,122 2054 143,775,1552016 78,175,638 2029 104,113,770 2042 126,129,762 2055 145,149,5492017 80,334,827 2030 105,933,448 2043 127,688,769 2056 146,510,6162018 82,464,703 2031 107,730,494 2044 129,230,513 2057 147,858,6442019 84,565,827 2032 109,505,366 2045 130,755,358 2058 149,193,9182020 86,638,755 2033 111,258,513 2046 132,263,659 2059 150,516,7132021 88,684,034 2034 112,990,378 2047 133,755,767 2060 151,827,3022022 90,702,202 2035 114,701,396 2048 135,232,025 2061 153,125,9522023 92,693,789 2036 116,391,994 2049 136,692,7702024 94,659,318 2037 118,062,592 2050 138,138,332Step 3. Estimate Potential Induced Effectof RCRA Regulationon CCR Beneficial UseAfter establishing a future baseline of CCRbeneficial use annual tonnage, this stepinvolved formulating three alternative scenarios wherebyfuture CCR beneficial use under RCRA regulation of CCR disposal could either:oScenario #1: Increase in beneficial useoScenario #2: DecreaseoScenario #3: Remain unchanged from baseline169Increases due to increased disposal costs were estimated first and constitute the “base case” of this RIA. By increasing disposal costs, electricutility plants face an “avoided disposal cost incentive” to ship their CCR farther for beneficial uses by other industries; that is, utilities would bewilling to pay more transportation costs to avoid the higher disposal costs. Thus, RCRA regulation of CCR disposal would likely open newmarkets at farther transport distances, or increase purchases by existing markets. The effect ofthis stimulus would be to increase CCRbeneficial use. The concept of “avoided disposal cost incentive” is recognized and defined by the American Coal Ash Association (ACAA) onits website as follows:“If a [coal-fired electric utility] plant markets its [CCR] into commercial applications, then disposalof this [CCR] is notrequired. Not only is a revenue stream created for the [coal-fired electricity plant]but also the need to dispose of the [CCR] isavoided. As discussed above, disposal isnot just the transportation and placement of [CCR] in a disposal site. The need forfuture space is a concern. If [CCR is] marketed, then theneed to develop future [CCR disposal] sites (including landacquisition, permitting, design and construction costs) is avoided .... It is not uncommon for a company to help offset the costsof transportation or placement at construction sites by providing the contractor or trucking firm a paymentof some sort. Forexample, if the cost of disposal at a plant is normally four dollarsa ton, then the company mayarrange a payment of fourdollars or less to the contractors to covertransportation and placement costs. Thedifference between the amount of thispayment and the cost of disposal is also referred to as“avoided disposal costs.” Source: ACAA Frequently Asked Question nr.14 webpage at: http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=5#Q14On the other hand, some stakeholders have claimed that a Subtitle C “hazardous waste” approach would have a “stigma” effect onCCR,reducing their use. That is, dueto the label of “hazardous waste,” some purchasers of CCR might opt to turn down the CCR formoreexpensive substitutes in fear that the CCR might either harm their sales or create liability, and generators might be reluctantto provide thematerial to users because of liability concerns. The final alternative, that beneficial use quantities remain the same, results in no net costs orbenefits for the Subtitle C approach because it is assumed that the baseline trend plays out the same as it would absent a rule. Thus, no furtheranalysis of this option was necessary.The two alternative Scenario analyses (i.e., Scenario #1, Scenario #2) in thissection build upon the ACAA’s historical CCR beneficial usedata.144ACAA data on the beneficial use was modified to remove theuse of CCR in minefilling applications because the proposed rule doesnot address minefilling operations. Excluding100% of the ACAA reported quantity of CCR used in minefilling results in a reduction of 1.13million tons per year in the amount beneficially used. As a result, the 2005 quantity of beneficial use relied upon for our analyses is 48.5million tons per year of CCR, rather than the original 49.6 million tons per year reported by ACAA.144Source: Historical CCR beneficial use data from the AmericanCoal Ash Association (ACAA) “Coal Combustion Products -- Production & Use Statistics” webpage at:http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=3170Step 4: Estimate Potential Induced Increasein Future CCR Beneficial Use (Scenario #1)Under the assumptions and numerical framework described below, this RIA estimates that the Subtitle C option would initially induce anincrease of 28% in CCR beneficial uses. This growth estimate is a generalized, aggregate estimate across all 15 existing CCR beneficial usemarkets. Due to a lack of available data (i.e., market location, elasticity, cross-elasticity, etc.), this estimate does not take into account uniqueeconomic supply or economic demand conditions in any single marketor for any particular beneficial use, relative to the generalized aggregateestimate. However, key uses, such as use of fly ash as a Portland cement replacement, have great opportunity for increased use, far above 28%in the initial year. For example, if flyash use in concrete increased to a 30% replacement rate for Portland cement (a very reasonablereplacement rate, consistent with currentspecifications), fly ash usage could increase by more than 100% from the 14 million tons usedannually at current replacement rates of 10%to 12%. One of the main barriers to this increase usage is transportation costs.Because EPA didnot have specific data on this market, this RIA does not specifically quantify it; however, it is exactly the type of use thatincreased disposalcosts could foster.The method presented below may be characterized as a "Raw Material Cost Method" which represents the 1ststage of the generalized 4-stagematerials flow lifecycle (MFL) through the economy. This 4-stageMFL conceptual framework has been integrated into existing cost modelingsoftware systems145used by government agencies and the private sector, and consists of the followingfour material flowcradle-to-grave orcradle-to-cradle stages:1stMFL stage: Raw materials acquisition2ndMFL stage: Product manufacturing3rdMFL stage: Product use, re-use, maintenance4thMFL stage: Recycling, waste managementThis method evaluates the difference in raw material acquisition cost under two alternative conditions. The first condition (Baseline) representscurrent conditions without RCRA regulation of CCR disposal. The second condition (Subtitle C) represents future conditions with RCRAregulation for CCR disposed by electric utilities.The economic mechanism in this estimation method, which affectsdifferent raw material acquisition costs under the two alternative conditions,is the “avoided disposal cost incentive” described above. In other words, it is the avoided disposal cost under RCRA regulation compared tothe industry’s baseline disposal cost. Thisdifference in cost is an incremental costrelative to baseline. From an economicstandpoint, thisrepresents an incremental economic incentiveto electric utility plants to reduce oreliminate CCR disposal, thereby reducing or avoiding newregulatory compliance costs by increasing their future annual supply of CCR to beneficial use markets. This “avoided disposal cost incentive”induced by RCRA regulation has already been anticipatedin 2009 by at least one CCRbeneficial use industry (bold faceadded for emphasis):145Example cost modeling/estimation software systems using this 4-stage framework are 1. FAST, 2. EE Energy/ Environment Life-Cycle Assessments, 3. EPA EnviroAccounting Method, and 4. TEAM (Tools for Environmental Analysisand Mangement); source: “Table 3-1. Overview of Life-Cycle Stages and Costs Considered bySoftware Systems and Tools” at http://www.p2pays.org/ref/01/00047/00047e.htm171“Using [coal] fly ash in building materials isnothing new, as it’s already incorporated in products including Portland cementand asphalt concrete. However, it’s estimatedthat 65 percent of fly ash from coal-fired power plants worldwide goes tolandfills, with the U.S. reporting a slightlylower 57 percent, according to the AmericanCoal Ash Association. Kane said thekey to CalStar’s products is that they offer the same performance as aesthetics as traditional bricks, but without the energy use.Currently, the cost to buy a ton of fly ash in the U.S. ranges from about $5 to $30, butthat could change as fly ash disposalfaces tighter government restrictions, he said. “The cost tosend fly ash to landfills willgo up, and utilities will be facedwithfinding the most beneficial use,” Kane said.”146The baseline average “raw material acquisition cost” is $94.50/ton, consisting of CCR price, CCR disposal cost, and CCR transportation cost:1.CCR price:Price paid to electric utility plants by beneficial useindustries for the purchase of CCR. ACAA identifies 15 industrialbeneficial use markets involving thebeneficial use of CCR, many of which involve the construction industry.147The average price paidby these industries to electric utility plants is $3.00 per ton, acrossa reported range of$0 to $45 per ton.1482.CCR disposal cost:Cost to the electric utilityindustry for disposing CCR. Thisfactor also represents the “avoided disposal costincentive” in the sense that this is an “avoided cost” to the electric utility industry forCCR tonnages beneficially used by otherindustries. A unitized “total cost” ($ per ton) for CCR disposal consisting of botha 50-year amortized capital cost for CCR disposalunits plus a 50-year amortized O&M costs for CCR disposal is used to monetize this cost factor.149The average baseline CCR disposalcost is $59/ton (source:Exhibit 3L). This is additive to the “CCR price” element because it represents a subsidy by electricity plants.3.CCR transport cost:Average one-way CCR transport distance between electric utility plants and their CCR beneficial use customerindustries. This method does not explicitlydistinguish whether the transport cost ispaid by the electric utility plants or by thebeneficial use industries.150Average CCR transport cost from electric utilityplants to beneficial use sites is estimated at($0.26/mile/ton)151x (125 miles)152= $32.50/ton.146Source: Cleantech Group, “CalStar Gives Sneak Peek of Low-Carbon Brick Factory,” 29 Oct 2009 at http://cleantech.com/news/5217/calstar-flyash-low-carbon-brick147ACAA lists 15 beneficial use markets: concrete, cement, flowable fill, structural fill/embankments, road base/sub-base, soil modification, mineral filler in asphalt,snow/ice control, blasting grit/roofing granules, mining applications, gypsum panel products, waste stabilization/solidification, agriculture, construction aggregate, andmiscellaneous uses.148$3 per-ton CCR price is from Column E ofExhibit 5C-1; this price represents the tonnage-weighted average across a reported price range of $0 to $45 per ton CCR.149Although in the short-run (< 3 years), marginal business decisions may be made relative to short-term O&M costs, long-term (>3 years) business decisions usuallyconsider both amortized capital costs and O&M costs.150The CCR price data used to monetize the CCR price factor above are reportedly based on “FOB” prices which may include some portion of transport cost(e.g., transportvehicle loading to a trans-shipment location).151$0.26 per-ton-per-mile is the midpoint of the $0.15 to $0.37 per-ton-per-mile range reported in “Estimation of the Marginal Greenhouse Gas Abatement Curve for theBeneficial Use of Fly Ash as a Substitute for Portland Cementin Ready-Mix Concrete Production,” EPA Office of Resource Conservation and Recovery (ORCR), 19 June2009, page 11.152125 miles is the midpoint of the 100 to 150 mile range reported in footnote 74 on page 4-8 of EPA’s 03 June 2008 “Report to Congress: Study on Increasing the Usageof Recovered Mineral Components in Federal Funded Projects Involving Procurement of Cement or Concrete to Address the Safe, Accountable, Flexible, EfficientTransportation, Equity Act: A Legacy for Uses by the EPA, the Department of Transportation (DOT) and the Department of Energy (DOE),” report nr. EPA530-R-08-007,available at http://www.epa.gov/waste/conserve/tools/cpg/products/cement2.htm.172In comparison to these baseline “raw materials acquisition cost” elements, CCR disposal costs are estimated to be $83/ton for the Subtitle Coption (source:Exhibit 4K). While this represents a 44% increase ($26/ton) over the baseline disposalcost of $59/ton, this ignores the CCRprice and the transportation costelements. Factoring these components in, the $26/ton increaserepresents a 28% increase above the totalbaseline raw material cost of $94.50/ton. This RIA applies this 28% growthfactor to represent demand elasticity153assumptions of:+0.64 with respect to the CCR “avoided disposal cost incentive” factor (i.e., +28%/+44%).+1.00 with respect to total “raw material acquisition cost” consisting of all three cost factors included (i.e., +28%/+28%).This RIA applies the elasticity estimate of 1.0 in reference to the “raw material acquisition cost” to represent the potential increase in CCRbeneficial use by 28% over the baseline under the Subtitle C option. The other regulatory options are proportionately adjustedbelow. Incomparison to historical annual percentagechanges in CCR beneficial usetonnages, this 28% increaseis a reasonable assumptionas it fallsbetween the -22.6% decrease and +55.2% increase min-max range (annual mean = +8.2%increase) over the 43year period 1966 to 2008,154asdisplayed inExhibit 5C-14below.Exhibit 5C-14Historical Annual Percentage Change in CCR Beneficial Use (1966-2008)ABCDEF (E/C)GItemYearCCR generation(tons)CCR disposal(tons)CCR beneficialuse (tons)Percent CCRbeneficial useAnnual % change inCCR beneficial use tons1 1966 26,000,000 22,000,000 4,000,000 15%2 1967 28,000,000 23,000,000 5,000,000 18% 25.0%3 1968 30,000,000 24,000,000 6,000,000 20% 20.0%4 1969 31,500,000 26,000,000 5,500,000 17% -8.3%5 1970 39,000,000 33,200,000 5,800,000 15% 5.5%6 1971 41,500,000 32,500,000 9,000,000 22% 55.2%7 1972 46,000,000 38,000,000 8,000,000 17% -11.1%8 1973 50,000,000 41,500,000 8,500,000 17% 6.3%9 1974 59,000,000 50,000,000 9,000,000 15% 5.9%10 1975 60,000,000 50,000,000 10,000,000 17% 11.1%11 1976 62,000,000 50,000,000 12,000,000 19% 20.0%12 1977 67,000,000 53,000,000 14,000,000 21% 16.7%13 1978 68,000,000 52,000,000 16,000,000 24% 14.3%14 1979 75,500,000 60,000,000 15,500,000 21% -3.1%15 1980 66,000,000 54,000,000 12,000,000 18% -22.6%16 1981 68,000,000 51,500,000 16,500,000 24% 37.5%153In economics, the elasticity of supply indicates the responsiveness of the quantity of a product or service supplied to the market relative to a change in its price (i.e., (%change in quantity supplied) / (% change in its price)). Similarly, the elasticity of demand indicates the responsiveness of the quantity of market demand for a product orservice relative to a change in its price (i.e., (% change in quantity demanded) / (% change in its price)).154Historical CCR beneficial use data for 1966-2008 from ACAAat http://www.acaa-usa.org/associations/8003/files/Revised_1966_2007_CCP_Prod_v_Use_Chart.pdf173Exhibit 5C-14Historical Annual Percentage Change in CCR Beneficial Use (1966-2008)ABCDEF (E/C)GItemYearCCR generation(tons)CCR disposal(tons)CCR beneficialuse (tons)Percent CCRbeneficial useAnnual % change inCCR beneficial use tons17 1982 65,000,000 51,000,000 14,000,000 22% -15.2%18 1983 64,000,000 51,000,000 13,000,000 20% -7.1%19 1984 69,000,000 53,000,000 16,000,000 23% 23.1%20 1985 66,000,000 48,000,000 18,000,000 27% 12.5%21 1986 67,500,000 53,000,000 14,500,000 21% -19.4%22 1987 82,000,000 63,000,000 19,000,000 23% 31.0%23 1988 83,000,000 62,500,000 20,500,000 25% 7.9%24 1989 87,000,000 69,500,000 17,500,000 20% -14.6%25 1990 86,000,000 64,000,000 22,000,000 26% 25.7%26 1991 88,000,000 65,500,000 22,500,000 26% 2.3%27 1992 82,000,000 62,000,000 20,000,000 24% -11.1%28 1993 88,000,000 69,000,000 19,000,000 22% -5.0%29 1994 89,000,000 66,000,000 23,000,000 26% 21.1%30 1995 92,000,000 68,000,000 24,000,000 26% 4.3%31 1996 102,000,000 76,000,000 26,000,000 25% 8.3%32 1997 104,000,000 74,500,000 29,500,000 28% 13.5%33 1998 108,000,000 77,000,000 31,000,000 29% 5.1%34 1999 107,000,000 74,000,000 33,000,000 31% 6.5%35 2000 108,500,000 76,500,000 32,000,000 29% -3.0%36 2001 117,930,542 80,811,221 37,119,321 31% 16.0%37 2002 128,703,572 83,180,316 45,523,256 35% 22.6%38 2003 121,744,571 75,360,166 46,384,405 38% 1.9%39 2004 122,465,119 73,375,301 49,089,818 40% 5.8%40 2005 123,126,093 73,513,552 49,612,541 40% 1.1%41 2006 124,795,124 70,591,954 54,203,170 43% 9.3%42 2007 131,127,693 75,088,688 56,039,005 43% 3.4%43 2008 136,073,107 75,479,44760,593,66045% 8.1%Minimum annual %= -22.6%Maximum annual % = 55.2%Median annual % = 6.4%Mean annual % = 8.2%Overall percent growth = 1414.8%Average annual compound growth = 6.5%174This is a limiting analysis because it does notinclude other developments that may beexpected increasingly to push CCR to beneficial use:1.Aspects of the proposed CCR rule: This analysis does not take into account that some RCRA regulatory options for CCR disposalrequire electricity plants to move to drymanagement of CCR, either through changesto air pollution control strategies or throughdrying of CCR after they have been generated. This will make the materialmore amenable to beneficial uses.2.The analysis is based on current market conditions: It does not take into account new technologies and products now being developed,for example, involving the useof CCR in brick construction.155An increased “avoided disposal cost incentive” could be a great boonto such new beneficial use technologies, applications, and products.•Comparison of “Raw Materials Acquisition Cost Method” to “Travel Cost Method”The method applied above involvedthree cost components of the “raw material acquisition cost,” not just in relation tothe transportation costcomponent, which is relatively narrowerapproach that can be called a “Transportation Cost Method.” Compared to this other method, the rawmaterial acquisition cost method provides a smaller estimate of effect because theincremental cost is evaluated relative to abroader set of coststhereby translating numerically into a smaller percentage change, rather than relative to only one cost factor which would translate into arelatively larger percentage change. This methodological difference may be illustrated by using the calculation numbers applied above, to onlythe transportation cost factor. Using a simplistic transportation distance model which uses the CCR disposal unit cost ($ perton) to determinethe average circular radius of a CCR transportation market between electricity utility plant suppliers of CCR and their beneficial userscustomers, the increase in transport distance would be calculated as follows (relative to the 2005 49.6 million tons CCR beneficially used asreported by the ACAA):•Baseline transportation cost (without CCR rule)($0.26/mile/ton) x (125 miles one-way average CCR transport distance) x (49.6 milliontons/year beneficial use in 2005) = $1,612million/year transport cost•Hypothetical new transportation cost (with rule)Transport subsidy equivalency =($85/ton avoided disposalcost under rule) – ($59/ton avoideddisposal cost without rule) = $26/tonsubsidy equivalency(49.6 million tons/year beneficial use) x ($26/ton subsidyequivalency) = $1,290 million per year subsidy equivalency•Hypothetical new transport distance:[($1,612 million/year) + ($1,290 million/year)]/ (49.6 million tons per year beneficial use) / ($0.26/mile/ton) = 225 milesPercentage increase in transport distance:[(225 miles) – (125 miles)] / (125 miles) = 80% increase in radial transport distance155Several companies are developing technologies to convert CCR intobricks used in construction, and one such technology was recently commercialized at a power plantin Wisconsin. Some of these technologies have the potentialfor using 100% CCR (fly ash) in brick production, as opposed to the conventional 30%-50% limit forreplacing Portland cement in concrete.175•Hypothetical expansion of CCR customer delivery area:Baseline customer area @125 miles radial transportdistance = (3.1415 x (125 miles)^2) = 49,100 square milesExpanded customer area @225 miles radial transportdistance = (3.1415 x (225 miles)^2) = 159,000 square milesIncremental increase in customer area= (159,000 – 49,100 sq. miles) / (49,100 sq.miles) = 124% increase in delivery areaStep 5: Estimate Hypothetical “Stigma” Decrease in Future CCR Beneficial Use (Scenario #2)A number of industry and state government stakeholders have asserted to the EPA,that designating CCR as a hazardous waste (even if thedesignation is only applicable tothose CCR that are disposed of) would create a“stigma” that would reduce or curtail or eliminate thebeneficial use of CCR. This RIA presentsan alternative stigma effectscenario in an effort toevaluate what countervailing impact that“stigma” may have on the increased beneficialuse of CCR estimated in this RIA above. This potential reduction scenario assumes differentpotential impacts in three categories of beneficial CCR usage (uses covered in the CPGs, consolidated uses, and unconsolidateduses). Fordocumentation of the calculationsdiscussed in this section, seeAppendix K13.•“Stigma” on CCR in Consolidated Uses Specifiedin Comprehensive Procurement GuidelinesFirst, some uses for CCR involve the production of specific products thatare expressly covered bythe federal Comprehensive ProcurementGuidelines (CPGs), which require procuring agencies that spend more than $10,000 a year on an item to buy products containing recoveredmaterials. Procuring agencies are federal,state, and local agencies, and their contractors, that use appropriated federal funds. For example, if acounty agency spends more than $10,000 a yearon an EPA-designated item and part of thatmoney is from appropriated federal funds, then theagency must purchase that item made from recovered materials.156As such, if there were any impacts due to stigma, EPA believes that themarkets for these uses are less likely to be affected by a hazardous waste label for CCR. CCRcategories currently covered under the CPGsinclude concrete/concrete products/grout, flowable fill, and blastinggrit/roofing granules.According to U.S. Census data, the public portion of total construction spending equaled 20.7%in 2005, 21.4% in 2006, 24.6% in2007, andhad swelled to 35.4% by Nov. 2009 (likely in direct relationship to the current stateof the economy and current federal stimulus spending).Similarly, U.S. EPA (2008d) estimates that for concrete projects, the cement demand attributable to federal concrete projects reflectsapproximately 20% of the annual total demand. EPA then apportioned the amounts of CCR usage into a public construction vs. a privateconstruction split. Based on the Census Bureau and EPA data,157EPA established a 25% / 75% split of the totals for these products, such that25% of the total usage is recognizedas accruing to public construction and 75 % to private construction.156Agencies may elect not to purchase designated items when thecost is unreasonable; inadequate competition exists; items are not available within a reasonable period oftime; or items do not meet the agency'sreasonable performance specifications.157Source: EPA “Report to Congress: Study on Increasing the Usage of Recovered Mineral Components in Federal Funded Projects Involving Procurement of Cement orConcrete to Address the Safe, Accountable, Flexible, Efficient Transportation, Equity Act: A Legacy for Uses by the EPA, the Department of Transportation (DOT) and theDepartment of Energy (DOE),” EPA530-R-08-007, June 3, 2008 at: http://www.epa.gov/waste/conserve/tools/cpg/products/cement2.htm176Given that the public procurement of theseproducts should continue because of theirCPG designation, this RIA assumed that there will be nonegative impact on the public portion of CCRusage. That is, the demand for CPG productsmade from CCR will be the same as itcurrently isfor the public portion of the construction market. However,this RIA assumes a 50% reduction of total private uses.158This results in anestimated 6.8 million tons per year reduction in CCRuse for this category of beneficial uses.•“Stigma” for CCR in Other Consolidated UsesNot all consolidated uses of CCR are covered under federal CPGs. Thus, this scenario also estimated the potential impacts on the use of CCRin non-CPG, consolidated uses. These CCR categories include blended cement/raw feed for clinker, mineral filler in asphalt, gypsum panelproducts, waste stabilization/solidification,and miscellaneous/other. In the case ofCCR used in blended cement, mineral filler – asphalt,gypsum for wallboard, and miscellaneous/otherapplications, this RIA assumed that 50% ofthese uses will be reduced. Thus, thepotentialreductions in this category willtotal 6.8 million tons per year.For the use of CCR in waste stabilization/solidification applications, this RIA assumed that stigma will not have a negative impact. For thisuse, the CCR are already being used in a waste management context.The CCR are used in secure landfills to immobilize wastes typically morehazardous than the CCR themselves. Therefore, this RIA projectsno reduction in the future annual tonnage of CCR used for thispurpose.•“Stigma” for Unconsolidated UsesIn addition to the consolidated uses ofCCR discussed above, CCR can be employed in unconsolidated uses. For some of these uses, the CCRproducts may be more similar to the disposed material proposed tobe regulated. In addition, theyhave typically not been chemically fixedwithin a product. As a result, stigma concerns may be more plausible. Markets that involveunconsolidated uses of CCR includestructuralfill/embankments, road base/sub-base, soil modification/stabilization, snow/ice control, aggregate, agriculture, and miscellaneous/other. Forpurpose of the sensitivity analysis, thisRIA assumed a potential reduction of 80%.159This results in an additional 11.1 million tons per yearreduction of beneficially used CCR. Byadding the 6.8 million tons from CPG consolidated uses, to the 6.8 million tons from non-CPGconsolidated uses, plus the 11.1 million tons from unconsolidated uses, this RIA estimates that asevere stigma effect would lead to a 51%reduction of beneficial use.158The 50% reduction is considered a worst-case assumption because these materials provide significant value at competitive costs– for example, concrete that includes flyash typically performs better than non-CCR concrete, and is likelyto retain favorable treatment under Leadership in Energy andEnvironmental Design (LEED). Inaddition, academic studies of “stigma” associated with products rarely leads to decreased usage to this extent.159EPA has assumed this high “stigma” effectbecause a number of the usesmay appear close to the disposal scenario, e.g., structural fills. Also, it is widely recognizedthat CCR in unconsolidated uses may present risks, if used inthe wrong conditions. (Indeed, EPA takes comment on unconsolidated uses in the preamble to the CCRproposed rule due to the increased potential for risks.) Someof these uses are likely to be particularly sensitive to publicconcerns and liability concerns. These includeagricultural uses and dispersive uses, like use of bottom ash or boiler slag for ice and snow control. Therefore, if stigma does have a role to play, EPA believes it isreasonable to assume it will be significant for unconsolidated uses. Even for the purposes of a worst-case sensitivity analysis, however, EPA believes that, given thesuccess of many of these uses in states with rigorous beneficial use programs, “stigma” will not completely eliminate such uses; therefore, it has estimated a decrease of80%.177Step 6: Apply Estimated Induced EffectScenarios to Baseline CCR Beneficial UseApplying the first effect (increase in the sale of CCR due to a decrease in price), EPA noted thata 28% increase with an elasticity of 1.0 wouldmakes sense when there is ample room for growth. But as themarket becomes more and more saturated, it is less and less likelythat unitelasticity would apply. Instead,the elasticity is likely todecrease with increasing saturation. To account for this, the beneficial use increasewas set to 28% of either the existing beneficial use tonnage, or to 28% of the remaining CCR tonnage, whichever was less. In other words,once beneficial use was greater than 50% oftotal CCR, the increase would be constrained to 28% of what was left over after beneficial use wasaccounted for. EPA also accounted for the fact that the price change would not fully affect themarket until the rule (and therefore the costs)had been phased in. Full implementation was assumed to occur by 2019. However, industry would undoubtedly likely attempt to prepare forthese increased costs as soon as a final rule was passed, and therefore the beneficial use increases were assumed to linearly approach 28% by2019. The projected tons of beneficial use under Subtitle C are shown in Exhibit 28 below.As seen below, subtitle C in EPA’s analysis would drive more CCRtoward beneficial use due to the increased costs of disposal.However, asdiscussed in Step 4 above, there is alsothe possibility that there would be a stigmaassociated with the “hazardous waste” designation. Here thebeneficial use of CCR would be 49% of the baseline due to stigma. Since the maximum CCR beneficially used is less than 50% ofall CCR,the constraint imposed on the straight 28%increase would not be necessary. Thus,once the full 51% decrease and 28% increaseare accountedfor, the future CCR beneficial use annual tonnages are calculated as displayed below inExhibit 5C-15.178Exhibit 5C-15Two Alternative Scenarios of Projected Future CCR Beneficial Use 2012-2061(Short Tons)YearScenario #1:w/out StigmaScenario #2:w/StigmaYearScenario #1:w/out StigmaScenario #2:w/Stigma2012 71,527,755 33,924,749 2037 128,297,364 82,753,1602013 75,999,399 36,206,995 2038 129,708,417 84,404,1702014 80,338,539 38,457,590 2039 131,105,658 86,035,9972015 84,549,013 40,677,131 2040 132,489,375 87,649,0412016 88,634,566 42,866,206 2041 133,859,848 89,243,6902017 92,598,855 45,025,395 2042 135,217,354 90,820,3302018 96,445,450 47,155,270 2043 136,562,164 92,379,3372019 100,177,835 49,256,395 2044 137,894,545 93,921,0812020 101,892,669 51,329,323 2045 139,214,759 95,445,9252021 103,587,595 53,374,602 2046 140,523,061 96,954,2272022 105,263,001 55,392,770 2047 141,819,704 98,446,3342023 106,919,270 57,384,357 2048 143,104,936 99,922,5922024 108,556,775 59,349,885 2049 144,378,997 101,383,3382025 110,175,889 61,289,868 2050 145,642,128 102,828,9002026 111,776,973 63,204,812 2051 146,894,561 104,259,6052027 113,360,387 65,095,213 2052 148,136,525 105,675,7702028 114,926,484 66,961,561 2053 149,368,245 107,077,7072029 116,475,608 68,804,337 2054 150,589,942 108,465,7232030 118,008,102 70,624,016 2055 151,801,831 109,840,1172031 119,524,301 72,421,062 2056 153,004,125 111,201,1842032 121,024,534 74,195,934 2057 154,197,031 112,549,2122033 122,509,126 75,949,081 2058 155,380,753 113,884,4852034 123,978,394 77,680,946 2059 156,555,491 115,207,2812035 125,432,652 79,391,964 2060 157,721,441 116,517,8702036 126,872,208 81,082,562 2061 158,878,794 117,816,520Step 7: Estimate Potential Induced Effects on Future Annual Tonnages of CCR Beneficial UseExhibit 5C-16below shows beneficial use projected under Subtitle C. Beneficial use under the increasing disposal cost scenario would leadtoan increase of 28% above the baseline estimate. However, as the market becomes more and moresaturated, it will likely becomeharder toincrease beneficial use. Thus, the increase is constrained to 28% of the remaining unused CCR. The elasticity column represents the effectivepercent change in quantity for each percent change in price oncethis constraint has been accounted for. While the elasticityis assumed toinitially be 1.0, the effectof market saturation drivesthat elasticity towards zeroover time as seen below.179Exhibit 5C-16Scenario #1: Increase in Future CCR Beneficial Use Under the Subtitle C OptionYearCCR generation(tons)% beneficial useBeneficial use(tons)%increaseIncreased beneficialuse (tons)Increase w/o minefilling (tons)Impliedelasticity2012 134,764,862 53.08% 71,527,755 3.31% 2,293,574 2,241,198 0.952013 135,558,881 56.06% 75,999,399 6.27% 4,482,972 4,380,599 0.902014 136,352,901 58.92% 80,338,539 8.91% 6,571,517 6,421,451 0.852015 137,146,920 61.65% 84,549,013 11.27% 8,562,450 8,366,919 0.802016 137,940,940 64.26% 88,634,566 13.38% 10,458,928 10,220,089 0.762017 138,734,959 66.75% 92,598,855 15.27% 12,264,028 11,983,968 0.732018 139,528,979 69.12% 96,445,450 16.95% 13,980,748 13,661,485 0.692019 140,322,998 71.39% 100,177,835 18.46% 15,612,008 15,255,494 0.662020 141,117,018 72.20% 101,892,669 17.61% 15,253,914 14,905,577 0.632021 141,911,037 72.99% 103,587,595 16.81% 14,903,561 14,563,225 0.602022 142,705,057 73.76% 105,263,001 16.05% 14,560,799 14,228,291 0.572023 143,499,076 74.51% 106,919,270 15.35% 14,225,480 13,900,629 0.552024 144,293,096 75.23% 108,556,775 14.68% 13,897,458 13,580,097 0.522025 145,087,115 75.94% 110,175,889 14.05% 13,576,588 13,266,555 0.502026 145,881,135 76.62% 111,776,973 13.46% 13,262,729 12,959,864 0.482027 146,675,154 77.29% 113,360,387 12.90% 12,955,743 12,659,887 0.462028 147,469,174 77.93% 114,926,484 12.37% 12,655,491 12,366,492 0.442029 148,263,193 78.56% 116,475,608 11.87% 12,361,839 12,079,545 0.422030 149,057,213 79.17% 118,008,102 11.40% 12,074,654 11,798,919 0.412031 149,851,232 79.76% 119,524,301 10.95% 11,793,807 11,524,485 0.392032 150,645,252 80.34% 121,024,534 10.52% 11,519,168 11,256,118 0.382033 151,439,271 80.90% 122,509,126 10.11% 11,250,612 10,993,695 0.362034 152,233,291 81.44% 123,978,394 9.72% 10,988,015 10,737,095 0.352035 153,027,310 81.97% 125,432,652 9.36% 10,731,256 10,486,198 0.332036 153,821,330 82.48% 126,872,208 9.00% 10,480,214 10,240,889 0.322037 154,615,349 82.98% 128,297,364 8.67% 10,234,772 10,001,052 0.312038 155,409,369 83.46% 129,708,417 8.35% 9,994,815 9,766,574 0.302039 156,203,388 83.93% 131,105,658 8.04% 9,760,228 9,537,345 0.292040 156,997,408 84.39% 132,489,375 7.75% 9,530,902 9,313,255 0.282041 157,791,427 84.83% 133,859,848 7.47% 9,306,725 9,094,198 0.272042 158,585,447 85.26% 135,217,354 7.20% 9,087,592 8,880,069 0.262043 159,379,466 85.68% 136,562,164 6.95% 8,873,395 8,670,764 0.252044 160,173,486 86.09% 137,894,545 6.70% 8,664,032 8,466,182 0.242045 160,967,505 86.49% 139,214,759 6.47% 8,459,401 8,266,224 0.232046 161,761,525 86.87% 140,523,061 6.24% 8,259,402 8,070,792 0.222047 162,555,544 87.24% 141,819,704 6.03% 8,063,938 7,879,791 0.222048 163,349,564 87.61% 143,104,936 5.82% 7,872,911 7,693,126 0.212049 164,143,583 87.96% 144,378,997 5.62% 7,686,228 7,510,706 0.20180Exhibit 5C-16Scenario #1: Increase in Future CCR Beneficial Use Under the Subtitle C OptionYearCCR generation(tons)% beneficial useBeneficial use(tons)%increaseIncreased beneficialuse (tons)Increase w/o minefilling (tons)Impliedelasticity2050 164,937,603 88.30% 145,642,128 5.43% 7,503,796 7,332,440 0.192051 165,731,622 88.63% 146,894,561 5.25% 7,325,524 7,158,239 0.192052 166,525,642 88.96% 148,136,525 5.07% 7,151,323 6,988,016 0.182053 167,319,661 89.27% 149,368,245 4.90% 6,981,106 6,821,687 0.182054 168,113,681 89.58% 150,589,942 4.74% 6,814,787 6,659,166 0.172055 168,907,700 89.87% 151,801,831 4.58% 6,652,282 6,500,372 0.162056 169,701,720 90.16% 153,004,125 4.43% 6,493,509 6,345,224 0.162057 170,495,739 90.44% 154,197,031 4.29% 6,338,387 6,193,644 0.152058 171,289,759 90.71% 155,380,753 4.15% 6,186,835 6,045,554 0.152059 172,083,778 90.98% 156,555,491 4.01% 6,038,778 5,900,878 0.142060 172,877,798 91.23% 157,721,441 3.88% 5,894,139 5,759,541 0.142061 173,671,817 91.48% 158,878,794 3.76% 5,752,842 5,621,471 0.13Exhibit 5C-17below shows beneficial use projected under Subtitle C with a worst-case stigma assumption. Increased beneficial use under theincreasing disposal costs of a Subtitle C rule are not accounted for. However, as soon as the rule becomes effective in 2012,the Scenario #2 ofthis RIA simulates a stigma effect which decreases the tons beneficially used by 51%. Once the disposal cost effect is fully captured by 2019,and the market has adjusted to stigma,beneficial use is assumed to grow atthe same rate it would have otherwise.Exhibit 5C-17Scenario #2: Decrease in Future CCR BeneficialUse Because of Stigma Under Subtitle C OptionYearCCR generationtons% beneficial useBeneficial usetons%DecreaseDecrease tonsDecrease w/outmine filling tons2012 134,764,862 25.17% 33,924,749 -51.00% -35,309,432 -33,342,8592013 135,558,881 26.71% 36,206,995 -49.37% -35,309,432 -33,342,8592014 136,352,901 28.20% 38,457,590 -47.87% -35,309,432 -33,342,8592015 137,146,920 29.66% 40,677,131 -46.47% -35,309,432 -33,342,8592016 137,940,940 31.08% 42,866,206 -45.17% -35,309,432 -33,342,8592017 138,734,959 32.45% 45,025,395 -43.95% -35,309,432 -33,342,8592018 139,528,979 33.80% 47,155,270 -42.82% -35,309,432 -33,342,8592019 140,322,998 35.10% 49,256,395 -41.75% -35,309,432 -33,342,8592020 141,117,018 36.37% 51,329,323 -40.75% -35,309,432 -33,342,8592021 141,911,037 37.61% 53,374,602 -39.81% -35,309,432 -33,342,8592022 142,705,057 38.82% 55,392,770 -38.93% -35,309,432 -33,342,8592023 143,499,076 39.99% 57,384,357 -38.09% -35,309,432 -33,342,8592024 144,293,096 41.13% 59,349,885 -37.30% -35,309,432 -33,342,8592025 145,087,115 42.24% 61,289,868 -36.55% -35,309,432 -33,342,859181Exhibit 5C-17Scenario #2: Decrease in Future CCR BeneficialUse Because of Stigma Under Subtitle C OptionYearCCR generationtons% beneficial useBeneficial usetons%DecreaseDecrease tonsDecrease w/outmine filling tons2026 145,881,135 43.33% 63,204,812 -35.84% -35,309,432 -33,342,8592027 146,675,154 44.38% 65,095,213 -35.17% -35,309,432 -33,342,8592028 147,469,174 45.41% 66,961,561 -34.53% -35,309,432 -33,342,8592029 148,263,193 46.41% 68,804,337 -33.91% -35,309,432 -33,342,8592030 149,057,213 47.38% 70,624,016 -33.33% -35,309,432 -33,342,8592031 149,851,232 48.33% 72,421,062 -32.78% -35,309,432 -33,342,8592032 150,645,252 49.25% 74,195,934 -32.24% -35,309,432 -33,342,8592033 151,439,271 50.15% 75,949,081 -31.74% -35,309,432 -33,342,8592034 152,233,291 51.03% 77,680,946 -31.25% -35,309,432 -33,342,8592035 153,027,310 51.88% 79,391,964 -30.78% -35,309,432 -33,342,8592036 153,821,330 52.71% 81,082,562 -30.34% -35,309,432 -33,342,8592037 154,615,349 53.52% 82,753,160 -29.91% -35,309,432 -33,342,8592038 155,409,369 54.31% 84,404,170 -29.49% -35,309,432 -33,342,8592039 156,203,388 55.08% 86,035,997 -29.10% -35,309,432 -33,342,8592040 156,997,408 55.83% 87,649,041 -28.72% -35,309,432 -33,342,8592041 157,791,427 56.56% 89,243,690 -28.35% -35,309,432 -33,342,8592042 158,585,447 57.27% 90,820,330 -27.99% -35,309,432 -33,342,8592043 159,379,466 57.96% 92,379,337 -27.65% -35,309,432 -33,342,8592044 160,173,486 58.64% 93,921,081 -27.32% -35,309,432 -33,342,8592045 160,967,505 59.30% 95,445,925 -27.00% -35,309,432 -33,342,8592046 161,761,525 59.94% 96,954,227 -26.70% -35,309,432 -33,342,8592047 162,555,544 60.56% 98,446,334 -26.40% -35,309,432 -33,342,8592048 163,349,564 61.17% 99,922,592 -26.11% -35,309,432 -33,342,8592049 164,143,583 61.77% 101,383,338 -25.83% -35,309,432 -33,342,8592050 164,937,603 62.34% 102,828,900 -25.56% -35,309,432 -33,342,8592051 165,731,622 62.91% 104,259,605 -25.30% -35,309,432 -33,342,8592052 166,525,642 63.46% 105,675,770 -25.04% -35,309,432 -33,342,8592053 167,319,661 64.00% 107,077,707 -24.80% -35,309,432 -33,342,8592054 168,113,681 64.52% 108,465,723 -24.56% -35,309,432 -33,342,8592055 168,907,700 65.03% 109,840,117 -24.33% -35,309,432 -33,342,8592056 169,701,720 65.53% 111,201,184 -24.10% -35,309,432 -33,342,8592057 170,495,739 66.01% 112,549,212 -23.88% -35,309,432 -33,342,8592058 171,289,759 66.49% 113,884,485 -23.67% -35,309,432 -33,342,8592059 172,083,778 66.95% 115,207,281 -23.46% -35,309,432 -33,342,8592060 172,877,798 67.40% 116,517,870 -23.26% -35,309,432 -33,342,8592061 173,671,817 67.84% 117,816,520 -23.06% -35,309,432 -33,342,859182Exhibit 5C-18below shows the projected future annual CCRgeneration and three trends inbeneficial use (i.e., scenario #1 increase withoutstigma, scenario #2 decrease with stigma, and scenario #3 no change in relation to the increasingbaseline trend). Scenario #1assumes that theincreased cost of disposal from regulation will induce the electric utility industry to seek outadditional CCR beneficial usemarkets therebyincreasing future annual beneficial use ofCCR above the increasing baseline trend. Experiences with the EPA RCRA Subtitle C hazardouswaste program indicate that industry often increases annual recycling and materials recovery rates after RCRA regulation (e.g.,after EPA haslisted certain types and sources of secondaryindustrial materials as RCRA “hazardous wastes”). Thus, EPA regards the increased beneficialuse Scenario #1 as the most likely outcome. A second curve in the Exhibit below displays the Scenario #2 decreased CCR beneficial usestigma effect under the Subtitle C regulatory option (this RIAdoes not apply scenario #2 under the Subtitle D options). The Exhibit alsopresents Scenario #3 in which future annual CCR beneficial use is projected to continue on its recent upwardly increasing trendline without anyinduced future change as a result of the CCR rule. The futureannual beneficial use tonnagesfor both scenario #1 and scenario#2 are estimatedin this RIA incrementally relativeto the scenario #3 baseline trend.183Exhibit 5C-18Beneficial Use Trends015,000,00030,000,00045,000,00060,000,00075,000,00090,000,000105,000,000120,000,000135,000,000150,000,000165,000,000180,000,0002012 2017 2022 2027 2032 2037 2042 2047 2052 2057Year

CCRs (Short Tons)CCRs GeneratedBaseline BUSubtitle C BUSubtitle C w/Stigma184Step 8: Monetize Potential InducedEffects on Future CCR Beneficial UseBased on multiplying a unitized averagemonetized social benefit value of$559 per tonconsisting of (a) the $474 per ton unitized lifecyclebenefit value, plus the (b) $85 per ton average avoided disposal cost estimated for the subtitle Coption, to the 50-year (i.e., 2012 to 2061)projected future baseline tonnage displayed inExhibit 5C-18above, produces an estimated future baseline social benefit value from CCRbeneficial use of:PV @3% discountPV @7% discountFuture baseline economic value: $102,290 million PV $51,170 million PVFuture baseline lifecycle socialvalue*: $1,554,323 million PV $777,541 million PV(* Includes avoided CCR disposalcost to electric utility industry)•Monetization of Scenario #1 (InducedIncrease in CCR Beneficial Use)Exhibit 5C-19below provides an estimate of the potentialincrease in future annual tonnage and economic and socialbenefits associated withCCR beneficial uses (not including minefilling)that could occur as a result of the CCR proposed rule. This quantity is incrementally calculatedeach year as the quantity projected under the Subtitle C option(without stigma), less the quantity projected under the baseline.Exhibit 5C-19Scenario #1: Benefit from Future Increase in CCRBeneficial User Under Subtitle C “Special Waste”Nominal Benefits(Millions)Discounted Benefits@ 3% (Millions)Discounted Benefits@ 7% (Millions)YearCCR BeneficialUse Increase(tons)EconSocialEconSocialEconSocial2012 2,241,198 $82 $1,253 $82 $1,253 $82 $1,2532013 4,380,599 $161 $2,449 $156 $2,377 $151 $2,2892014 6,421,451 $236 $3,590 $223 $3,384 $206 $3,1352015 8,366,919 $308 $4,677 $282 $4,280 $251 $3,8182016 10,220,089 $376 $5,713 $334 $5,076 $287 $4,3592017 11,983,968 $441 $6,699 $380 $5,779 $314 $4,7762018 13,661,485 $503 $7,637 $421 $6,396 $335 $5,0892019 15,255,494 $561 $8,528 $456 $6,934 $350 $5,3112020 14,905,577 $548 $8,332 $433 $6,578 $319 $4,8502021 14,563,225 $536 $8,141 $411 $6,239 $291 $4,4282022 14,228,291 $523 $7,954 $389 $5,918 $266 $4,0432023 13,900,629 $511 $7,771 $369 $5,614 $243 $3,6922024 13,580,097 $500 $7,591 $350 $5,324 $222 $3,3712025 13,266,555 $488 $7,416 $332 $5,050 $203 $3,077185Exhibit 5C-19Scenario #1: Benefit from Future Increase in CCRBeneficial User Under Subtitle C “Special Waste”Nominal Benefits(Millions)Discounted Benefits@ 3% (Millions)Discounted Benefits@ 7% (Millions)YearCCR BeneficialUse Increase(tons)EconSocialEconSocialEconSocial2026 12,959,864 $477 $7,245 $315 $4,790 $185 $2,8102027 12,659,887 $466 $7,077 $299 $4,542 $169 $2,5652028 12,366,492 $455 $6,913 $284 $4,308 $154 $2,3422029 12,079,545 $444 $6,753 $269 $4,085 $141 $2,1382030 11,798,919 $434 $6,596 $255 $3,874 $128 $1,9512031 11,524,485 $424 $6,442 $242 $3,674 $117 $1,7812032 11,256,118 $414 $6,292 $229 $3,484 $107 $1,6262033 10,993,695 $404 $6,146 $217 $3,304 $98 $1,4842034 10,737,095 $395 $6,002 $206 $3,132 $89 $1,3552035 10,486,198 $386 $5,862 $195 $2,970 $81 $1,2372036 10,240,889 $377 $5,725 $185 $2,816 $74 $1,1292037 10,001,052 $368 $5,591 $176 $2,670 $68 $1,0302038 9,766,574 $359 $5,460 $167 $2,532 $62 $9402039 9,537,345 $351 $5,331 $158 $2,400 $56 $8582040 9,313,255 $343 $5,206 $150 $2,276 $52 $7832041 9,094,198 $335 $5,084 $142 $2,157 $47 $7152042 8,880,069 $327 $4,964 $135 $2,045 $43 $6522043 8,670,764 $319 $4,847 $128 $1,939 $39 $5952044 8,466,182 $311 $4,733 $121 $1,838 $36 $5432045 8,266,224 $304 $4,621 $115 $1,742 $33 $4962046 8,070,792 $297 $4,512 $109 $1,651 $30 $4522047 7,879,791 $290 $4,405 $103 $1,565 $27 $4132048 7,693,126 $283 $4,301 $98 $1,484 $25 $3762049 7,510,706 $276 $4,199 $93 $1,406 $23 $3432050 7,332,440 $270 $4,099 $88 $1,333 $21 $3132051 7,158,239 $263 $4,002 $83 $1,263 $19 $2862052 6,988,016 $257 $3,906 $79 $1,198 $17 $2612053 6,821,687 $251 $3,813 $75 $1,135 $16 $2382054 6,659,166 $245 $3,723 $71 $1,076 $14 $2172055 6,500,372 $239 $3,634 $67 $1,019 $13 $1982056 6,345,224 $233 $3,547 $64 $966 $12 $1812057 6,193,644 $228 $3,462 $60 $916 $11 $1652058 6,045,554 $222 $3,380 $57 $868 $10 $1502059 5,900,878 $217 $3,299 $54 $822 $9 $1372060 5,759,541 $212 $3,220 $51 $779 $8 $1252061 5,621,471 $207 $3,142 $49 $738 $8 $114Present Value $9,806 $149,001 $5,560 $84,489186•Monetization of Potential “Stigma” Decrease in CCR Beneficial Use (Scenario #2)The$559 per tonsocial benefit value estimated above isthe proper estimate for increased beneficialuse because this RIA assumes that allbeneficial uses will increase in equal proportions. However, it would not be appropriate to apply this same dollar estimate todecreasedbeneficial use from stigma because differentuses decrease by different amounts, and therefore the decreasein benefits would not necessarilyequal the 51% decrease in tons.Based on the breakdown of beneficial uses displayed below inExhibit 5C-20, these individual use categorylosses were summed to create a weighted average benefit reduction of 42%. However,on a tonnage basis 51% of beneficial use tons arereduced. Dividing the weighted value by the unweighted value for each ton lost, the benefits decreased by only 82% of the average $559/ton,or $458/ton. This average unitized social benefits value is used to monetize the estimated tons lost from the stigma Scenario#2.Exhibit 5C-20Calculation of the “Stigma” Adjustment Factor for the CCR Beneficial Use Reduction Scenario #2Beneficial Use Industrial CategoryCCR BeneficialUse (2005 tons)Disposal CostSavings(millions)Life CycleBenefits(millions)TotalBenefits(millions)Percent Lost FromStigmaBenefits Lost(millions)1. Concrete/concrete products/grout 16,353,331 $1,390 $17,593 $18,983 37.5% $7,118.62. Blended cement/raw feed for clinker 4,215,234 $358 Not estimated $358 50% $179.03. Flowable fill 259,907 $22 Not estimated$22 37.5% $8.34. Structural fill/embankments 8,349,999 $710 Not estimated$710 80% $568.05. Road base/sub-base 1,461,992 $124 Not estimated$124 80% $99.26. Soil modification/stabilization 1,139,640 $97 Not estimated$97 80% $77.67. Mineral filler in asphalt 140,838 $12 Not estimated$12 50% $6.08. Snow & ice control 547,541 $47 Not estimated$47 80% $37.69. Blasting grit/roofing granules 1,633,407 $139 Not estimated$139 37.5% $52.110. Gypsum panel products (wallboard) 8,178,079 $695 $5,387 $6,082 50% $3,041.011. Waste stabilization/solidification 2,839,954 $241 Not estimated$241 0% $0.012. Agriculture 415,741 $35 Not estimated$35 80% $28.013. Aggregate 872,776 $74 Not estimated$74 80% $59.214. Miscellaneous other 2,071,157 $176 Not estimated$176 65% $114.4Weighted Total = 48,479,596 $4,120 $22,980 $27,100 42% $11,382Unweighted Total = 48,479,596 $4,120 $22,980 $27,100 51% $13,821Adjustment Factor =0.82Exhibit 5C-21below provides an estimate of the beneficial use decrease scenario. This quantity is calculated each year as the quantityprojected under subtitle C (with stigma) less the quantityprojected under the baseline.187Exhibit 5C-21Scenario #2: Cost of Potential Future Reductionin CCR Beneficial Use Under Subtitle C with “Stigma”Nominal Costs(Millions)Discounted Costs@ 3% (Millions)Discounted Costs@ 7% (Millions)YearCCR BeneficialUse Decrease(Short Tons)EconomicSocialEconomicSocialEconomicSocial2012 -33,342,859 -$1,269 -$15,816 -$1,269 -$15,816 -$1,269 -$15,8162013 -33,342,859 -$1,269 -$15,816 -$1,232 -$15,355 -$1,186 -$14,7812014 -33,342,859 -$1,269 -$15,816 -$1,196 -$14,908 -$1,109 -$13,8142015 -33,342,859 -$1,269 -$15,816 -$1,162 -$14,474 -$1,036 -$12,9102016 -33,342,859 -$1,269 -$15,816 -$1,128 -$14,052 -$968 -$12,0662017 -33,342,859 -$1,269 -$15,816 -$1,095 -$13,643 -$905 -$11,2762018 -33,342,859 -$1,269 -$15,816 -$1,063 -$13,245 -$846 -$10,5392019 -33,342,859 -$1,269 -$15,816 -$1,032 -$12,860 -$790 -$9,8492020 -33,342,859 -$1,269 -$15,816 -$1,002 -$12,485 -$739 -$9,2052021 -33,342,859 -$1,269 -$15,816 -$973 -$12,122 -$690 -$8,6032022 -33,342,859 -$1,269 -$15,816 -$944 -$11,768 -$645 -$8,0402023 -33,342,859 -$1,269 -$15,816 -$917 -$11,426 -$603 -$7,5142024 -33,342,859 -$1,269 -$15,816 -$890 -$11,093 -$564 -$7,0222025 -33,342,859 -$1,269 -$15,816 -$864 -$10,770 -$527 -$6,5632026 -33,342,859 -$1,269 -$15,816 -$839 -$10,456 -$492 -$6,1342027 -33,342,859 -$1,269 -$15,816 -$815 -$10,152 -$460 -$5,7322028 -33,342,859 -$1,269 -$15,816 -$791 -$9,856 -$430 -$5,3572029 -33,342,859 -$1,269 -$15,816 -$768 -$9,569 -$402 -$5,0072030 -33,342,859 -$1,269 -$15,816 -$746 -$9,290 -$376 -$4,6792031 -33,342,859 -$1,269 -$15,816 -$724 -$9,020 -$351 -$4,3732032 -33,342,859 -$1,269 -$15,816 -$703 -$8,757 -$328 -$4,0872033 -33,342,859 -$1,269 -$15,816 -$682 -$8,502 -$307 -$3,8202034 -33,342,859 -$1,269 -$15,816 -$662 -$8,254 -$287 -$3,5702035 -33,342,859 -$1,269 -$15,816 -$643 -$8,014 -$268 -$3,3362036 -33,342,859 -$1,269 -$15,816 -$624 -$7,780 -$250 -$3,1182037 -33,342,859 -$1,269 -$15,816 -$606 -$7,554 -$234 -$2,9142038 -33,342,859 -$1,269 -$15,816 -$589 -$7,334 -$219 -$2,7232039 -33,342,859 -$1,269 -$15,816 -$571 -$7,120 -$204 -$2,5452040 -33,342,859 -$1,269 -$15,816 -$555 -$6,913 -$191 -$2,3792041 -33,342,859 -$1,269 -$15,816 -$539 -$6,711 -$178 -$2,2232042 -33,342,859 -$1,269 -$15,816 -$523 -$6,516 -$167 -$2,0782043 -33,342,859 -$1,269 -$15,816 -$508 -$6,326 -$156 -$1,9422044 -33,342,859 -$1,269 -$15,816 -$493 -$6,142 -$146 -$1,8152045 -33,342,859 -$1,269 -$15,816 -$479 -$5,963 -$136 -$1,6962046 -33,342,859 -$1,269 -$15,816 -$465 -$5,789 -$127 -$1,5852047 -33,342,859 -$1,269 -$15,816 -$451 -$5,621 -$119 -$1,4812048 -33,342,859 -$1,269 -$15,816 -$438 -$5,457 -$111 -$1,3842049 -33,342,859 -$1,269 -$15,816 -$425 -$5,298 -$104 -$1,294188Exhibit 5C-21Scenario #2: Cost of Potential Future Reductionin CCR Beneficial Use Under Subtitle C with “Stigma”Nominal Costs(Millions)Discounted Costs@ 3% (Millions)Discounted Costs@ 7% (Millions)YearCCR BeneficialUse Decrease(Short Tons)EconomicSocialEconomicSocialEconomicSocial2050 -33,342,859 -$1,269 -$15,816 -$413 -$5,144 -$97 -$1,2092051 -33,342,859 -$1,269 -$15,816 -$401 -$4,994 -$91 -$1,1302052 -33,342,859 -$1,269 -$15,816 -$389 -$4,848 -$85 -$1,0562053 -33,342,859 -$1,269 -$15,816 -$378 -$4,707 -$79 -$9872054 -33,342,859 -$1,269 -$15,816 -$367 -$4,570 -$74 -$9232055 -33,342,859 -$1,269 -$15,816 -$356 -$4,437 -$69 -$8622056 -33,342,859 -$1,269 -$15,816 -$346 -$4,308 -$65 -$8062057 -33,342,859 -$1,269 -$15,816 -$336 -$4,182 -$60 -$7532058 -33,342,859 -$1,269 -$15,816 -$326 -$4,060 -$56 -$7042059 -33,342,859 -$1,269 -$15,816 -$316 -$3,942 -$53 -$6582060 -33,342,859 -$1,269 -$15,816 -$307 -$3,827 -$49 -$6152061 -33,342,859 -$1,269 -$15,816 -$298 -$3,716 -$46 -$574Present Value -$33,639 -$419,145 -$18,744 -$233,549Step 9: Estimate Potential Induced Effect on CCR Beneficial Use of the Other RCRA Regulatory OptionsThe analysis above demonstrates the valuation of beneficial use effects using only the subtitle C option.However, the resultsmay beextrapolated to the other regulatory options.Exhibit 5C-22below displays the beneficial use effectscenarios linearly extrapolated in relationto the result of subtitle C based on the potential increase in CCR disposal cost. Inother words, the ratio of the disposal cost estimated underthose other scenarios to the subtitle C disposal cost can be applied to the beneficial use benefits underthose alternative options.Exhibit 5C-22Potential Induced Effect of RCRA Regulation on Future CCR Beneficial Use: 2 Scenarios($millions present value @7%)ComponentSubtitle C Special wasteSubtitle D (version 2)Subtitle “D prime”Assumed scaling ratios relative to C value = 100% 40% 16%Scenario #1: Increase in Beneficial Use (Base Case)Percentage increase relative to baseline = +11% +4% +2%Economic market value +$5,560 +$2,224 +$890Lifecycle social value+$84,489 +$33,796 +$13,518Scenario #2: Decrease in Beneficial UsePercentage increase relative to baseline = -18% N/A N/AEconomic market value -$18,744 N/A N/ALifecycle social value -$233,549 N/A N/A189Step 10: Quantify Potential Capacity Impacts onCommercial Subtitle C Waste Landfills (Under Scenario #2)For Scenario #2 estimated above involving a potential future reduction in annual CCR beneficial use, such loss would require additionaldisposal of 33.3 milliontons CCR annually (source:Exhibit 5C-16) which will likely createfour future industrial waste disposal problems:1.Annual disposalrate exceedance: Relative to the 33.3 million lost beneficial use annnual tonnages, there is amuch smaller quantity of2 million tons per year of RCRA-regulated hazardous waste which is currently disposedin RCRA Subtitle C permitted onsite (captive)and offsite (commercial) landfills in the US.160This implies a potential 1,665% annual increase (i.e., 16.65 times larger) in demand forhazardous waste landfill capacity.2.Limited geographic availability: There are currently 19 to 24 commercial hazardouswaste landfills operating in 15 to 17 states.161However, the CCR which is currently beneficially used is generated by 272 electric utility plants located in 41 states.162Thus disposalat commercial hazardous waste landfills would require out-of-state shipment involvingat least 24 to 26 states which do not havecommercial hazardous waste landfills.3.Remaining disposal capacity exceedance: The 19 to 24 commercial hazardous waste landfills have an available total remaining capacityof 21.7 million to 25.4 million tons hazardous waste.163The additional 33.3 million tons per year of CCR beneficial use needingdisposal under the Scenario #2 will consume this entireremaining total capacity within less than one year.4.Increase landfill prices: In addition, such a large increasein nationwide economic demand for commercial hazardous waste landfillscould drive-up landfill tipping fees which recently (2004) ranged between $61and $139 per ton nationwide ($90 per ton nationalaverage).164As verification of this potential effect onlandfill prices, a recent(August 2009) market study165of the US commercial160Source: 2 million tons per year is based on the annual average of landfill tonnages reported for years 2001 (2.09 million tons), 2003 (1.68 million tons), 2005 (2.04million tons), and 2007 (1.94 million tons) in EPA’s “RCRA National Analysis Biennial Hazardous Waste Report” athttp://www.epa.gov/waste/inforesources/data/biennialreport/index.htm161Source: 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 wastelandfill count and 17 state identities as listed in the HazardousWaste Consultant“2007 Directory ofUS Commercial Hazardous Waste Management Facilities,” Vol.25, Issue 1, 2007, pp.4.1 to4.44. The 17 states are AL, AR, CA, CO,ID, IL, IN, LA, MI, NV, NJ, NY,OH, OK, OR, TX, UT.•Source #2 of 2: As compiled 02 Oct 2009by EPA OSWER-ORCR staff (Cpan Lee, Environmental Scientist), this available remainingcapacity estimate is based onthree sources: (a) actual capacity estimates provided to OSWER-ORCR by facilities in April-Sept 2009, (b) information providedto OSWER-ORCR by EPA Regionsand States in April/May 2009, and (c) capacity estimates developed by OSWER-ORCR using 1995-2007 RCRA Biennial Report data. The 15 States are AL, CA, CO,ID, IL, IN, LA, MI, NV, NY, OH, OK, OR, TX, and UT.162The 41 states are AL, AR, AZ, CO, DE, FL, GA, IA, IL, IN, KS,KY, LA, MA, MD, MI, MN, MO, MS, MT, NC, ND, NE, NH, NJ, NM, NV,NY, ,OH, OK, OR, SC,SD, TN, TX, UT, VA, WA, WI, WV, WY.163Source: 02 Oct 2009 estimates by EPA OSWER-ORCR staff (Cpan Lee,Environmental Scientist) cited in a prior footnote in this section of the RIA.164Source: US commercial hazardous waste landfill prices for bulk hazardous waste withouttreatment reported bythe EnvironmentalTechnology Council (ETC) “May2004 Incinerator and Landfill Cost Data” website at http://www.etc.org/costsurvey8.cfm165Source: Page 10 of “HazardousWaste Industry Review 2008-2009,” Joan Berkowitz and Robert Crisp, Farkas Berkowitz & Company, August 2009;http://www.farkasberkowitz.com/marketresearch.htm190hazardous waste industry, provides the following empirical evidence of price increasesby commercial hazardous waste landfillsinresponse to annual increases in landfill disposal tonnage:“On average, the number of surveyed landfill firms thatincreased prices exceeds the number that received highervolumes in 2008. Volumes increased for 50 percent of respondents and decreased for 42 percent, but 67 percent raisedprices and 33 percent left prices unchanged. The survey did notask how much, if any, of the reported price increase wasdue to fuel surcharges. The survey did determine that 92percent of respondents applied fuel surcharges, but fuelsurcharges cannot account for all of theprice increases because the surcharges cover increased costs, and 77 percent ofrespondents reported increased [profit] margins.”191Chapter 6Comparison of Regulatory Benefits to CostsSection 6A of this Chapter presents a series of exhibits which summarize and compare the results of the costand benefit estimates presented inChapter 4andChapter 5, respectively, scaled to the three 2010regulatory options. Section 6B of thisChapter provides explanation of thescaling method and factors applied.6A. Comparison of Regulatory Benefits toCosts Based on Alternative Discount RatesThe series of sixExhibits 6A to 6Fbelow summarize cost and benefits according to the three alternative beneficial use scenarios (i.e., inducedincrease, induced decrease, and no change), and according to the two OMB-prescribed alternative discount rates of 7% and 3% foruse in RIAs:7% discount rate: The 7% discount rate asa “base case” to represent the financialopportunity cost (i.e., borrowing cost) to affectedbusinesses, which is consistent with OMB’s 2003 Circular A-4 guidance166(page 33), and with OMB’s 1992Circular A-94 guidance167(page 8) which indicate that a 7% discount rate “base case” should be used forregulatory analyses when regulation isexpected to primarily and directlyaffect businesses and industries.3% discount rate: This is a second mandatory discount rate specified in OMB’s 2003 Circular A-4 guidance (page 34).In these six summary exhibits below, the comparison of regulatory benefits to costs involves two numerical comparisons:1.Net benefits (i.e., benefits minus costs)2.Benefit/cost ratios (i.e., benefits divided by costs)Two alternative discount rates:Three alternative CCR beneficial use impact scenarios:7% discount rate(base case in this RIA)3% discount rateScenario #1: Induced increase (base case)Exhibit 6A Exhibit 6BScenario #2: Induced decreaseExhibit 6C Exhibit 6DScenario #3: No changeExhibit 6E Exhibit 6F166OMB’s 17 Sept 2003 Circular A-4 “Regulatory Analysis” guidance is available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/167OMB’s 29 Oct 1992 Circular A-94 “Guidelinesand Discount Rates for Benefit-Cost Analysis of Federal Programs,” is available athttp://www.whitehouse.gov/omb/rewrite/circulars/a094/a094.html192Exhibit 6AComparison of Regulatory Benefits to Costs Under Scenario #1– Induced Beneficial Use Increase @7% Discount Rate – Detailed Summary($Millions in 50-Year Present Values @2009$ Prices)CostsSubtitle C “Special Waste”Subtitle D (version 2)Subtitle “D prime”1. Engineering Controls $6,780 $3,254 $3,2542. Ancillary Costs $1,480 $5 $53. Dry Conversion $12,089 4,836 $0Total Costs (1+2+3) = $20,349 $8,095 $3,259Benefits4. Groundwater Protection Benefits* $970 $375 $188Count of Human Cancer Risks Avoided** 726 296 148Monetized Value of Human Cancer Risks Avoided $504 $207 $104Groundwater Remediation Costs Avoided $466 $168 $845. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Econ. Benefits Social benefitsScenario #1 @7% discount rate =$5,560$84,489$2,224$33,796$890$13,5186. CCR Impoundment Failure Costs AvoidedIf Based on Extrapolated Recent Failure Cases $1,762 $793 $405If Based on 10% Future Failures $8,366 $3,795 $1,897If Based on 20% Future Failures $16,732 $7,590 $3,7957. Non-quantified Benefits*** Q R STotal Benefits (4+5+6):Total Benefits w/Extrapolated Recent Failure Cases= $8,292 $87,221 $3,392$34,964 $1,483 $14,111Total Benefits @10% Future Failures = $14,896 $93,825 $6,394 $37,966 $2,975 $15,603Total Benefits @20% Future Failures = $23,262 $102,191 $10,189 $41,761 $4,873 $17,501Net Benefits (Total Benefits minus Total Costs)Net Benefits w/Extrapolated Recent Failure Cases =($12,057)$66,872($4,703)$26,869($1,776)$10,852Net Benefits @10% Future Failures =($5,453)$73,476($1,701)$29,871($284)$12,344Net Benefits @20% Future Failures = $2,913 $81,842 $2,094 $33,666 $1,614 $14,242Benefit/Cost Ratio (BCR)BCR w/Extrapolated Recent Failure Cases = 0.407 4.286 0.419 4.319 0.455 4.330BCR @10% Future Failures = 0.732 4.611 0.790 4.690 0.913 4.788BCR @20% Future Failures = 1.143 5.022 1.259 5.159 1.495 5.370Notes:* Cancer risk reflects the arsenic groundwater pathway only anddoes not include other human health mortality or morbidity risks from non-carcinogens, nor do theyreflect ecological and socio-economic damages that could occur. Thus, the benefits are underestimated in this RIA.** Cancer risks avoided are based on National Academy of Science (2001) data, which representsrecent scientific information.*** Q>R>S; For example, non-quantified ecological benefits could add 159%, and socio-economic benefits could add 24%, comparedto avoided cleanup cost benefit.193Exhibit 6BComparison of Regulatory Benefits to Costs Under Scenario #1 – Induced Beneficial Use Increase @3% Discount Rate($Millions in 50-Year Present Values @2009$ Prices)CostsSubtitle C “Special Waste”Subtitle D (version 2)Subtitle “D prime”1. Engineering Controls $12,640 $6,067 $6,0672. Ancillary Costs $2,759 $9 $93. Dry Conversion $22,538 $9,016 $0Total Costs (1+2+3) = $37,938 $15,092 $6,076Benefits4. Groundwater Protection Benefits* $3,316 $1,321 $661Count of Human Cancer Risks Avoided** 726 296 148Monetized Value of Human Cancer Risks Avoided $1,825 $750 $375Groundwater Remediation Costs Avoided $1,491 $571 $2865. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Econ. Benefits Social benefitsScenario #1 @3% discount rate =$9,806$149,001$3,922$59,600$1,569$23,8406. CCR Impoundment Failure Costs AvoidedIf Based on Extrapolated Recent Failure Cases $3,124$1,406 $719If Based on @ 10% Future Failures $13,046 $5,918 $2,959If Based on @ 20% Future Failures $26,092 $11,836 $5,9187. Non-quantified Benefits*** Q R STotal Benefits (4+5+6):Total Benefits w/Extrapolated Recent Failure Cases= $16,246 $155,441 $6,649$62,327 $2,949 25,220Total Benefits @10% Future Failures = $26,168 $165,363 $11,161 $66,839 $5,189 $27,460Total Benefits @20% Future Failures = $39,214 $178,409 $17,079 $72,757 $8,148 $30,419Net Benefits (Total Benefits minus Total Costs)Net Benefits w/Extrapolated Recent Failure Cases =($21,692)$117,503($8,443)$47,235($3,127)$19,144Net Benefits @10% Future Failures =($11,770)$127,425($3,931)$51,747($887)$21,384Net Benefits @20% Future Failures = $1,276 $140,471 $1,987 $57,665 $2,072 $24,343Benefit/Cost Ratio (BCR)BCR w/Extrapolated Recent Failure Cases = 0.428 4.097 0.441 4.130 0.485 4.151BCR @10% Future Failures = 0.690 4.359 0.740 4.429 0.854 4.519BCR @20% Future Failures = 1.034 4.703 1.132 4.821 1.341 5.006Notes:* Cancer risk reflects the arsenic groundwater pathway only anddoes not include other human health mortality or morbidity risks from non-carcinogens, nor do they reflectecological and socio-economic damages that could occur.Thus, the benefits are underestimated in this RIA.** Cancer risks avoided are based on National Academy of Science (2001) data, which representsrecent scientific information.*** Q>R>S.194Exhibit 6CComparison of Regulatory Benefits to Costs Under Scenario#2 – Induced Beneficial Use Decrease @7% Discount Rate($Millions in 50-Year Present Values @2009$ Prices)CostsSubtitle C “Special Waste”Subtitle D (version 2)Subtitle “D prime”1. Engineering Controls $6,780 $3,254 $3,2542. Ancillary Costs $1,480 $5 $53. Dry Conversion $12,089 4,836 $0Total Costs (1+2+3) = $20,349 $8,095 $3,259Benefits4. Groundwater Protection Benefits* $970 $375 $188Count of Human Cancer Risks Avoided** 726 296 148Monetized Value of Human Cancer Risks Avoided $504 $207 $104Groundwater Remediation Costs Avoided $466 $168 $845. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Econ. Benefits Social benefitsScenario #2 @7% discount rate =($18,744)($233,549)$0 (no impact)$0 (no impact)$0 (no impact)$0 (no impact)6. CCR Impoundment Failure Costs AvoidedIf Based on Extrapolated Recent Failure Cases $1,762 $793 $405If Based on 10% Future Failures $8,366 $3,795 $1,897If Based on 20% Future Failures $16,732 $7,590 $3,7957. Non-quantified Benefits*** Q R STotal Benefits (4+5+6):Total Benefits w/Extrapolated Recent Failure Cases =($16,012)($230,817)$1,168 $1,168 $593 $593Total Benefits @10% Future Failures =($9,408)($224,213)$4,170 $4,170 $2,085 $2,085Total Benefits @20% Future Failures =($1,042)($215,847)$7,965 $7,965 $3,983 $3,983Net Benefits (Total Benefits minus Total Costs)Net Benefits w/Extrapolated Recent Failure Cases =($36,361)($251,166)($6,927)($6,927)($2,666)($2,666)Net Benefits @10% Future Failures =($29,757)($244,562)($3,925)($3,925)($1,174)($1,174)Net Benefits @20% Future Failures =($21,391)($236,196)($130)($130)$724 $724Benefit/Cost Ratio (BCR)BCR w/Extrapolated Recent Failure Cases =(0.787) (11.343)0.144 0.144 0.182 0.182BCR @10% Future Failures =(0.462) (11.018)0.515 0.515 0.640 0.640BCR @20% Future Failures =(0.051) (10.607)0.984 0.984 1.222 1.222Notes:* Cancer risk reflects the arsenic groundwater pathway only anddoes not include other human health mortality or morbidity risks from non-carcinogens, nor do theyreflect ecological and socio-economic damages that could occur. Thus, the benefits are underestimated in this RIA.** Cancer risks avoided are based on National Academy of Science (2001) data, which representsrecent scientific information.*** Q>R>S.195Exhibit 6DComparison of Regulatory Benefits to Costs Under Scenario#2 – Induced Beneficial Use Decrease @3% Discount Rate($Millions in 50-Year Present Values @2009$ Prices)CostsSubtitle C “Special Waste”Subtitle D (version 2)Subtitle “D prime”1. Engineering Controls $12,640 $6,067 $6,0672. Ancillary Costs $2,759 $9 $93. Dry Conversion $22,538 $9,016 $0Total Costs (1+2+3) = $37,938 $15,092 $6,076Benefits4. Groundwater Protection Benefits* $3,316 $1,321 $661Count of Human Cancer Risks Avoided** 726 296 148Monetized Value of Human Cancer Risks Avoided $1,825 $750 $375Groundwater Remediation Costs Avoided $1,491 $571 $2865. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Econ. Benefits Social benefitsScenario #2 @3% discount rate =($34,946)($435,419)$0 (no impact)$0 (no impact)$0 (no impact)$0 (no impact)6. CCR Impoundment Failure Costs AvoidedIf Based on Extrapolated Recent Failure Cases $3,124 $1,406 $719If Based on 10% Future Failures $13,046 $5,918 $2,959If Based on 20% Future Failures $26,092 $11,836 $5,9187. Non-quantified Benefits*** Q R STotal Benefits (4+5+6):Total Benefits w/Extrapolated Recent Failure Cases =($28,506) ($428,979)$2,727 $2,727 $1,380 $1,380Total Benefits @10% Future Failures =($18,584) ($419,057)$7,239 $7,239 $3,620 $3,620Total Benefits @20% Future Failures =($5,538) ($406,011)$13,157 $13,157 $6,579 $6,579Net Benefits (Total Benefits minus Total Costs)Net Benefits w/Extrapolated Recent Failure Cases =($66,443) ($466,917) ($12,365) ($12,365) ($4,696) ($4,696)Net Benefits @10% Future Failures =($56,521) ($456,995) ($7,853) ($7,853) ($2,456) ($2,456)Net Benefits @20% Future Failures =($43,475) ($443,949) ($1,935) ($1,935)$503 $503Benefit/Cost Ratio (BCR)BCR w/Extrapolated Recent Failure Cases =(0.751) (11.307)0.181 0.181 0.227 0.227BCR @10% Future Failures =(0.490) (11.046)0.480 0.480 0.596 0.596BCR @20% Future Failures =(0.146) (10.702)0.872 0.872 1.083 1.083Notes:* Cancer risk reflects the arsenic groundwater pathway only anddoes not include other human health mortality or morbidity risks from non-carcinogens, nor do theyreflect ecological and socio-economic damages that could occur. Thus, the benefits are underestimated in this RIA.** Cancer risks avoided are based on National Academy of Science (2001) data, which representsrecent scientific information.*** Q>R>S.196Exhibit 6EComparison of Regulatory Benefits to Costs Under Scenario#3 – No Change to Beneficial Use @ 7% Discount Rate($Millions in 50-Year Present Values @2009$ Prices)CostsSubtitle C “Special Waste”Subtitle D (version 2)Subtitle “D prime”1. Engineering Controls $6,780 $3,254 $3,2542. Ancillary Costs $1,480 $5 $53. Dry Conversion $12,089 4,836 $0Total Costs (1+2+3) = $20,349 $8,095 $3,259Benefits4. Groundwater Protection Benefits* $970 $375 $188Count of Human Cancer Risks Avoided** 726 296 148Monetized Value of Human Cancer Risks Avoided $504 $207 $104Groundwater Remediation Costs Avoided $466 $168 $845. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Econ. Benefits Social benefitsScenario #3 @7% discount rate =$0 (no change)$0 (no change)$0 (no change)$0 (no change)$0 (no change)$0 (no change)6. CCR Impoundment Failure Costs AvoidedIf Based on Extrapolated Recent Failure Cases $1,762 $793 $405If Based on 10% Future Failures $8,366 $3,795 $1,897If Based on 20% Future Failures $16,732 $7,590 $3,7957. Non-quantified Benefits*** Q R STotal Benefits (4+5+6):Total Benefits w/Extrapolated Recent Failure Cases = $2,732 $2,732 $1,168 $1,168$593 $593Total Benefits @10% Future Failures = $9,336$9,336 $4,170 $4,170 $2,085 $2,085Total Benefits @20% Future Failures = $17,702 $17,702 $7,965 $7,965 $3,983 $3,983Net Benefits (Total Benefits minus Total Costs)Net Benefits w/Extrapolated Recent Failure Cases =($17,617) ($17,617) ($6,927) ($6,927) ($2,666) ($2,666)Net Benefits @10% Future Failures =($11,013) ($11,013) ($3,925) ($3,925) ($1,174) ($1,174)Net Benefits @20% Future Failures =($2,647) ($2,647) ($130) ($130)$724 $724Benefit/Cost Ratio (BCR)BCR w/Extrapolated Recent Failure Cases = 0.134 0.134 0.144 0.144 0.182 0.182BCR @10% Future Failures = 0.459 0.459 0.515 0.515 0.640 0.640BCR @20% Future Failures = 0.870 0.870 0.984 0.984 1.222 1.222Notes:* Cancer risk reflects the arsenic groundwater pathway only anddoes not include other human health mortality or morbidity risks from non-carcinogens, nor do theyreflect ecological and socio-economic damages that could occur. Thus, the benefits are underestimated in this RIA.** Cancer risks avoided are based on National Academy of Science (2001) data, which representsrecent scientific information.*** Q>R>S.197Exhibit 6FComparison of Regulatory Benefits to Costs Under Scenario#3 – No Change to Beneficial Use @ 3% Discount Rate($Millions in 50-Year Present Values @2009$ Prices)CostsSubtitle C “Special Waste”Subtitle D (version 2)Subtitle “D prime”1. Engineering Controls $12,640 $6,067 $6,0672. Ancillary Costs $2,759 $9 $93. Dry Conversion $22,538 $9,016 $0Total Costs (1+2+3) = $37,938 $15,092 $6,076Benefits4. Groundwater Protection Benefits* $3,316 $1,321 $661Count of Human Cancer Risks Avoided** 726 296 148Monetized Value of Human Cancer Risks Avoided $1,825 $750 $375Groundwater Remediation Costs Avoided $1,491 $571 $2865. Induced Impact on CCR Beneficial Use Econ. benefits Social benefits Econ. benefits Social benefits Econ. Benefits Social benefitsScenario #3 @3% discount rate =$0 (no change)$0 (no change)$0 (no change)$0 (no change)$0 (no change)$0 (no change)6. CCR Impoundment Failure Costs AvoidedIf Based on Extrapolated Recent Failure Cases $3,124$1,406 $719If Based on 10% Future Failures $13,046 $5,918 $2,959If Based on 20% Future Failures $26,092 $11,836 $5,9187. Non-quantified Benefits*** Q R STotal Benefits (4+5+6):Total Benefits w/Extrapolated Recent Failure Cases= $6,440 $6,440 $2,727$2,727 $1,380 $1,380Total Benefits @10% Future Failures = $16,362 $16,362 $7,239 $7,239 $3,620 $3,620Total Benefits @20% Future Failures = $29,408 $29,408 $13,157 $13,157 $6,579 $6,579Net Benefits (Total Benefits minus Total Costs)Net Benefits w/Extrapolated Recent Failure Cases =($31,498) ($31,498) ($12,365) ($12,365) ($4,696) ($4,696)Net Benefits @10% Future Failures =($21,576) ($21,576) ($7,853) ($7,853) ($2,456) ($2,456)Net Benefits @20% Future Failures =($8,530) ($8,530) ($1,935) ($1,935)$503 $503Benefit/Cost Ratio (BCR)BCR w/Extrapolated Recent Failure Cases = 0.170 0.170 0.181 0.181 0.227 0.227BCR @10% Future Failures = 0.431 0.431 0.480 0.480 0.596 0.596BCR @20% Future Failures = 0.775 0.775 0.872 0.872 1.083 1.083Notes:* Cancer risk reflects the arsenic groundwater pathway only anddoes not include other human health mortality or morbidity risks from non-carcinogens, nor do theyreflect ecological and socio-economic damages that could occur. Thus, the benefits are underestimated in this RIA.** Cancer risks avoided are based on National Academy of Science (2001) data, which representsrecent scientific information.*** Q>R>S.1986B. Factors Applied for Scaling Benefits andCosts to the Three 2010 Regulatory OptionsThe regulatory compliance cost estimation presented inChapter 4of this RIA was initially formulated with reference to the October 2009draft RIA regulatory options. Furthermore,the regulatory benefits evaluation inChapter 5of this RIA was based only on the 2010 regulatoryoptions. To resolve this inconsistency inscope between the two different sets of regulatory options evaluated for costs and for benefits,respectively, this RIA applies the scaling factors (i.e., percentage extrapolation multipliers) displayed below inExhibit 6F.The cost analysis presented inChapter 4of this RIA is built upon a detailed (i.e., plant-by-plant for all 495 coal-fired electric utility plants)engineering cost model which estimated "engineering control" costs associated with the RCRA 3004(x) custom-tailored technical standards ofthe 2009 regulatory options (i.e., SubtitleC "hazardous waste" option, Subtitle D non-hazardous waste option requiring composite liners fornew CCR disposal units, and a "hybrid" C/D option). Although the engineering control costs were the same for each of the threeOctober 2009options, "ancillary costs" differed accordingto whether an option was formulated in reference to Subtitle C or to Subtitle D authority. Forexample, only the Subtitle C "hazardous waste" option and the Subtitle C component ofthe "Hybrid C/D" option required the costassociatedwith manifesting offsite shipments of CCR between coal-fired electric utility plants and offsite CCR disposal locations. The October 2009draft RIA presented the "dry conversion cost" element as a separable "sub-option"for both the Subtitle C and Subtitle D options.However, in 2010 EPA identified a different set of three regulatoryoptions to describe in the proposed rule and evaluate in RIA (i.e., Subtitle C"special waste" option with wet disposalphase-out, Subtitle D option which in effect would phase-out wet CCR disposal by requiringretrofitting existing impoundmentswith composite liners, and a Subtitle "D prime" option requiring liners only for new disposal units). Inorder to meet EPA’s end-of-March 2010internal deadline for completing the 2nddraft of this RIA, EPA did not revised theChapter 4costanalysis or theChapter 7supplemental analyses, but applied scaling factors for bridging the cost estimates to the 2010 options. Numerically,the scaling factors represent alternative compliance rate assumptions in relation to the 2009 draft RIA’sSubtitle C "hazardouswaste" option asa reference case for both cost and benefit estimate scaling tothe three 2010 regulatory options.The scaling factors assume less complianceunder the non-Federally enforceable SubtitleD based options compared to the Federally-enforceable Subtitle C option. Section6B of this RIAprovides the numerical values assigned tothe scaling factors on an itemized basis according to the separate cost element and benefit elementcategories, for each of the three 2010 regulatory options.Exhibit 6FScaling Factors (Extrapolation Multipliers) Applied in this RIA toEstimate the Costs & Benefitsof the 2010 Regulatory Options for CCR DisposalEconomic Impact CategorySubtitle CSpecial WasteSubtitle D(version 2)Subtitle“D prime”Regulatory Compliance Costs:1. Engineering control costs 100% 48% 48%2. Ancillary costs 100% 48% 48%3. Dry conversion costs 100% 40% 0%Regulatory Benefits:199Exhibit 6FScaling Factors (Extrapolation Multipliers) Applied in this RIA toEstimate the Costs & Benefitsof the 2010 Regulatory Options for CCR DisposalEconomic Impact CategorySubtitle CSpecial WasteSubtitle D(version 2)Subtitle“D prime”1. Groundwater contamination prevention benefits:Groundwater remediation costs avoided 100% 48% 30%Monetized value of human cancer risks avoided 100% 48% 30%2. Impoundment structural failure cleanup costs avoided 100% 45% 23%3. Induced impact on CCR beneficial use:Scenario #1: Induced increaseScenario #2: Induced decreaseScenario #3: No change100%100%Not relevant40%None (0%)Not relevant16%None (0%)Not relevantThe following two sub-sections (6B.1 and 6B.2) provide explanation and documentation of thescaling factors displayed inExhibit 6Fabove.6B.1 Regulatory Cost Scaling FactorsoEngineering control costs:For both RCRA subtitle C and subtitle D, the engineering control costs would be identical under bothoptions. However, state governments are notrequired to develop comparable programsunder RCRA Subtitle D rules, and statescannot enforce Federal subtitle D rules.In addition, because of the nature of subtitle D authority, individual requirements (e.g.,groundwater monitoring, impoundment closure) will be more generic, allowing industry great latitude in complying. Thus,actual costs under Subtitle D optionswill be lower than under Subtitle C, becausefacilities would not be expected to comply tothe same extent. In estimating future annual tons of CCR thatmight be managed under new standards, and the extent to whichthey would be similar under theSubtitle C option, this RIA applies the percentageof tons of CCR disposed in states withgroundwater monitoring requirements as a way to estimate the likely costs incurred by industry for the other options. Althoughthe engineering control cost category consists of 10 cost elements as defined inthis RIA, the percentage of states withgroundwater monitoring programs is a reasonable surrogate indicatorbecause states imposing groundwater monitoringrequirements indicates which states will generally address specific units, and whichare likely to upgrade their programs undersubtitle D, if EPA were to issue a national subtitle D rule.In those states, management standards may significantly improve,although not to the level of subtitle C for the reasons discussedabove. On the other hand, certainly some facilities in stateswithout programs will choose to comply with the national regulation (taking full advantage of the more generic nature of thefederal D standards). Taking these two factors together, using the percentage ofCCR disposed in states with groundwatermonitoring programs provides a reasonable estimate of the extent towhich facilities will take steps to comply with the nationalstandards, and therefore of the costs of compliance. For thefederally-enforceable subtitle Coption, the cost recognizes thatallstates (100%) will be required by the CCR rule to install groundwater monitoring (and all other engineering controls). For boththe non-federally enforceable subtitle D andthe “D prime” options, the cost estimates assume that the 48% of waste disposed ofin states that currently require surface impoundments to havegroundwater monitoring (either for new units only or for new and200existing units) will generally upgrade their programs, improving compliance, and that a modest number of facilities in otherstates would independently make efforts tocomply – giving an overall estimate of 48%.This 48% is applied as a scaling factormultiplier to estimate engineering control costs for both the Subtitle D and “D prime” in relation to the Subtitle C engineeringcost estimate.oAncillary costs: The RIA separately estimated “ancillary” costsunder both Subtitle C and Subtitle D assuming 100%nationwide adoption. For the Subtitle Dor “D prime” options, the cost estimate only includes inspections of surfaceimpoundments by qualified engineers. The same logic applies to this requirement asit does to the engineering controls, andtherefore this RIA applied the same 48% scaling factor multiplier relative to the Subtitle D ancillary cost estimates.oDry conversion costs: For the dry conversion cost, 40% isonly applied as a scaling multiplier under the Subtitle D optionbecause the “D prime” option does not require dry conversion. The 40% value is calculated inExhibit 6Gbelow, which isbased in part on assuming that the costfor retrofitting or building new impoundmentsis 63% of the cost of dry conversion underSubtitle C as calculated inExhibit 6Hbelow.Exhibit 6GEstimate of Subtitle D (version 2) Impoundment Liner Retrofit or Build New Lined Impoundment CostABCDEFG (D x F x 63%**)RowYearCount of existingelectric utilityplants withimpoundmentsSubtitle Cspecial waste:Dry Conversion CostPercent existing CCRimpoundmentswith compositeliners*Percent of CCRimpoundmentswithoutcomposite linersSubtitle D (v.2):Must Retrofit orBuild New LinedImpoundments1 2012 158 $22,984,000,000 5.5% 94.5% $13,709,900,0002 2013 158 $0 5.5% 94.5% $03 2014 158 $0 5.5% 94.5% $04 2015 158 $0 5.5% 94.5% $05 2016 158 $0 5.5% 94.5% $06 2017 158 $15,800,000 5.5% 94.5% $9,400,0007 2018 158 $15,800,000 5.5% 94.5% $9,400,0008 2019 158 $15,800,000 5.5% 94.5% $9,400,0009 2020 158 $15,800,000 5.5% 94.5% $9,400,00010 2021 158 $15,800,000 5.5% 94.5% $9,400,00011 2022 158 $15,800,000 5.5% 94.5% $9,400,00012 2023 158 $15,800,000 5.5% 94.5% $9,400,00013 2024 158 $15,800,000 5.5% 94.5% $9,400,00014 2025 158 $15,800,000 5.5% 94.5% $9,400,00015 2026 158 $15,800,000 5.5% 94.5% $9,400,00016 2027 158 $15,800,000 5.5% 94.5% $9,400,00017 2028 158 $15,800,000 5.5% 94.5% $9,400,00018 2029 158 $15,800,000 5.5% 94.5% $9,400,00019 2030 158 $15,800,000 5.5% 94.5% $9,400,00020 2031 158 $15,800,000 5.5% 94.5% $9,400,000201Exhibit 6GEstimate of Subtitle D (version 2) Impoundment Liner Retrofit or Build New Lined Impoundment CostABCDEFG (D x F x 63%**)RowYearCount of existingelectric utilityplants withimpoundmentsSubtitle Cspecial waste:Dry Conversion CostPercent existing CCRimpoundmentswith compositeliners*Percent of CCRimpoundmentswithoutcomposite linersSubtitle D (v.2):Must Retrofit orBuild New LinedImpoundments21 2032 158 $15,800,000 5.5% 94.5% $9,400,00022 2033 158 $15,800,000 5.5% 94.5% $9,400,00023 2034 158 $15,800,000 5.5% 94.5% $9,400,00024 2035 158 $15,800,000 5.5% 94.5% $9,400,00025 2036 158 $15,800,000 5.5% 94.5% $9,400,00026 2037 158 $15,800,000 5.5% 94.5% $9,400,00027 2038 158 $15,800,000 5.5% 94.5% $9,400,00028 2039 158 $15,800,000 5.5% 94.5% $9,400,00029 2040 158 $15,800,000 5.5% 94.5% $9,400,00030 2041 158 $15,800,000 5.5% 94.5% $9,400,00031 2042 158 $15,800,000 5.5% 94.5% $9,400,00032 2043 158 $15,800,000 5.5% 94.5% $9,400,00033 2044 158 $15,800,000 5.5% 94.5% $9,400,00034 2045 158 $15,800,000 5.5% 94.5% $9,400,00035 2046 158 $15,800,000 5.5% 94.5% $9,400,00036 2047 158 $15,800,000 5.5% 94.5% $9,400,00037 2048 158 $15,800,000 5.5% 94.5% $9,400,00038 2049 158 $15,800,000 5.5% 94.5% $9,400,00039 2050 158 $15,800,000 5.5% 94.5% $9,400,00040 2051 158 $22,984,000,000 5.5% 94.5% $13,709,900,00041 2052 158 $15,800,000 5.5% 94.5% $9,400,00042 2053 158 $15,800,000 5.5% 94.5% $9,400,00043 2054 158 $15,800,000 5.5% 94.5% $9,400,00044 2055 158 $15,800,000 5.5% 94.5% $9,400,00045 2056 158 $15,800,000 5.5% 94.5% $9,400,00046 2057 158 $15,800,000 5.5% 94.5% $9,400,00047 2058 158 $15,800,000 5.5% 94.5% $9,400,00048 2059 158 $15,800,000 5.5% 94.5% $9,400,00049 2060 158 $15,800,000 5.5% 94.5% $9,400,00050 2061 158 $15,800,000 5.5% 94.5% $9,400,000Non-discounted total cost = $46,663,000,000 $27,833,000,000Non-discounted average cost = $933,000,000 $557,000,000Present value cost (@7% disc.) = $23,167,000,000 $13,819,000,000Average annualized cost (@7%) =$1,679,000,000$1,001,000,000Percent reduction in annualized cost compared to Subtitle C Option conversion cost =40%Notes:202Exhibit 6GEstimate of Subtitle D (version 2) Impoundment Liner Retrofit or Build New Lined Impoundment CostABCDEFG (D x F x 63%**)RowYearCount of existingelectric utilityplants withimpoundmentsSubtitle Cspecial waste:Dry Conversion CostPercent existing CCRimpoundmentswith compositeliners*Percent of CCRimpoundmentswithoutcomposite linersSubtitle D (v.2):Must Retrofit orBuild New LinedImpoundments* 5.5% existing impoundments with composite liners based on EPA’s 2000 CCR regulatory determination and on the August 2006joint EPA-DOE survey report.** EPA estimated the capital and annual O&M costs for the Subtitle D requirement for either retrofitting or building new CCRimpoundments with composite liners, by assuming that the costfor those requirements are 63% of the $23.167 billion present valuecost for dry conversion under the Subtitle C option. This 63% cost scaling factor is calculated inExhibit 6Hof this RIA.Exhibit 6HReference Data for Calculation of "63% Cost Scaling Factor" Applied in Exhibit 6GCapital costO&M costRow totalPercentCapital costPercentDry Coal Ash Management (35-year lifespan cost in 1980$)1 In-plant handling system $19,500,000 $693,100,000 $712,600,00076% $19,500,00023%2 Conveyance (transport) $10,364,000 $116,996,000 $127,360,00014% $10,364,00012%3 Disposal (lined landfill) $53,952,000 $39,926,000 $93,878,00010% $53,952,00064%Total = $83,816,000 $850,022,000 $933,838,000100% $83,816,000100%Wet Coal Ash Management (35-year lifespan cost in 1980$)1 In-plant handling system $8,500,000 $302,121,000 $310,621,00069% $8,500,0009%2 Conveyance (transport) $31,954,000 $42,140,000 $74,094,00016% $31,954,00034%3 Disposal (lined impoundment) $52,906,000 $14,448,000 $67,354,00015% $52,906,00057%63%*Total = $93,360,000 $358,709,000 $452,069,000100% $93,360,000100%Source: Based on cost data for an example 2600 megawatt (MW) nameplate capacity electric utility plant from pages B-8 (dry) and C-9 (wet) of theEPA/TVA joint study “Economic Analysis ofWet Versus Dry Ash Disposal Systems: Interagency Energy/Environment R&D Program Report,” report nr.EPA-600/7-81-013, January 1981:http://nepis.epa.gov/Exe/ZyPURL.cgi?Dockey=20006ORT.txt* EPA estimated the capital and annual O&Mcosts for the Subtitle D requirement for either retrofitting or building new CCR impoundments withcomposite liners, by assuming that the cost for those requirements are 63% of the $23.167 billion present value cost for dry conversion under the Subtitle Coption. This 63% cost scaling factoris calculated in this exhibit.6B.2 Regulatory Benefits Scaling FactorsoGroundwater contamination benefits: Percentages are based on an examination of state programs related to groundwatermonitoring requirements as described inChapter 5of this RIA. The percentages given inExhibit 6Fabove refer only to theinput values to the estimation of groundwater protection benefits presented inChapter 5of this RIA. For the Subtitle C option,all states will be required by the rule to have groundwatermonitoring in place so that 100% offacilities over the baseline would203detect contamination early andthus human cancers would be prevented. For the Subtitle D option,48% of CCR are placed insurface impoundments in states with groundwater monitoring in place for new units only (or for new and existing units). It islikely that these states with some level of attention to groundwater monitoring would increasetheir attention (e.g., because theyalready have a RCRA program infrastructure) to groundwater monitoring,providing for much more effective systems, whileother states would tend not to (although some individual facilities within those states would upgrade groundwater monitoring tosome extent). Thus, this RIA estimates that overall, the newregulation would result in 48% offacilities detecting contaminationearly and 48% of cancers would be prevented. For the Subtitle D prime option, retrofitting existing units would not be required,and therefore existing and future releaseswould continue to occur from unlinedsurfaced impoundments.Currently 12% ofCCR are placed in surface impoundments in states with groundwater monitoring. Some ofthese states would certainly upgradetheir regulations, but given that surface impoundments would remain a potential source ofrelease in all states, the Subtitle Dprime option is less protective of groundwaterthan the Subtitle D option. Since this fraction is likely to fall between 48% and12%, the mid-point of 30% was chosen as a best estimate for the D prime option.oImpoundment structural failure cleanup costs avoided: This factor is not based on estimates of percentages of states likely toimplement the new requirements (which for subtitle D would require liners for existing surface impoundments); it is unlikelythat many states will choose to implement this requirement. Instead, compliance will not be enforceable, and will be left up toself-imposed schedules of industry or citizens suits. While most impoundments mayeventually close, it will be a lengthyprocess. As a general estimate, throughdelaying closures and lengthening the process, industry maybe able to reduce costs by50%. In addition, since 5.5% of surface impoundments have compositeliners already, they would remain in place, and thereforewould not incur costs. Taking these figures together, this RIA applies a 45% scaling factor for this benefit.oInduced impact on CCR beneficial uses:Under Scenario #1 induced increase in beneficial use, beneficial uses are assumed tobe linear with respect to total costsbecause increases in usage are directly proportional to the cost of the regulatoryoptions. Therefore, under the Subtitle Doption, the net reduction in total costs compared to the Subtitle C option is 40%. Under the Subtitle “D prime” option,since the dry conversion costs are 0%, anet result of 16% was applied. This percentage was derived by dividing theSubtitle “D prime” option cost bythe total cost of Subtitle C.Under Scenario #2 induced decrease in beneficial use, for the reasons described inSection 5C of this RIA, this RIAassumes that potential induced future decrease on beneficial use only applies tothe Subtitle C regulatory option, not tothe Subtitle D-based options.Under Scenario #3 no change in beneficial use (relative tobaseline), there is no impacts under any of the regulatoryoptions, so no scaling assumptions are applied.204Chapter 7Supplemental Analyses Required byCongressional Statutes orWhite House Executive OrdersNote: The computations presented in thisChapter are based on the cost estimatesfor the October 2009 draft RIA regulatoryoptions using the larger dry conversion cost estimateprior to its update inChapter 4. Because the high-end cost of the October2009 draft RIA regulatory options (i.e., for the Subtitle C “hazardouswaste” option) is larger thanthe high-end cost for the2010options (i.e., for the Subtitle C “specialwaste” option), the effects estimated in this Chapter are proportionately over-estimated.7A. Electricity Price Impact(Executive Order 13211)The 2001 Executive Order 13211168“Actions Concerning Regulations that SignificantlyAffect Energy Supply, Distribution, or Use” requiresFederal agencies to evaluate and prepare a statement on any potential adverse effects of economically-significant rulemakings on energysupply, distribution or use, including:•Shortfall in energy supply•Energy price increases•Increased use of foreign energy suppliesThe OMB’s 13 July 2001 Memorandum M-01-27169guidance for implementing this Executive Order identifies nine numerical indicators(thresholds) of potential adverse energy effects, three of which are relevant for evaluation in this RIA:•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 energydistribution cost, this RIA evaluated thepotential impactof the CCR regulatory options on electricity prices relative to the 1%threshold of both indicatorsas an indicator of “other similarly adverseoutcome”. This RIA calculated the potentialincrease in statewide electricity prices that the industry compliance costs mightinduce under eachCCR regulatory option. This calculation involved plant-by-plant annual revenue estimates and annualized compliance cost estimates, andrespective statewide average electricity prices for the495 electric utility plants, according to the following four steps.168The 18 May 2001 EO-13211 is available at: http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=2001_register&docid=fr22my01-133.pdf169OMB’s 13 July 2001 Memorandum M-01-27 is available at: http://www.whitehouse.gov/omb/memoranda_m01-27/205•Step 1: Downloaded the annual million megawatt capacity data for each of the 495 plants from the DOE-EIA website (2007), andestimated annual electricity output for each plant,by multiplying the capacity data by three factors:o365 operating days per yearo24 operating hours per dayo86.8% capacity utilization per year170•Step 2: Estimated the annual electricity sales revenue for eachplant by multiplying the estimated annual electricity output sold by eachplant (from Step 1), by the respective statewide average retail price (May 2009) of electricity forall sectors (i.e., residential, commercial,industrial, transportation) from DOE-EIA athttp://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 electricity sales revenue foreach plant, to obtain a hypothetical future annual revenue target, which represents a 100% cost pass-thru scenario. This simple scenariorepresents an upper-bound case of potential electricity price increase. Furthermore, ifthis 100% cost pass-thru is averaged over the entireelectricity supply in each state, not justaveraged over the 495 coal-fired electricity plants as donein this RIA, the potential percentageincrease in electricity pricewould be less than this upper-bound case presented in this RIA.•Step 4: Divided the hypothetical future annual revenue target by the estimated annualelectricity output for each plant, to obtain ahypothetical future (higher) target price for each plant, which incorporates the added regulatorycost. Compared the higher target price tothe current price to calculate thepotential price increase ona percentage basis foreach of the 495 plants.Exhibit 7Abelow presents the findings of this energy price evaluation on a state-by-state basis. As displayed in the bottom row ofExhibit7A, none of the options have an expected nationwide average energy price increase >1%.Appendix Lpresents the plant-by-plant calculationspreadsheet used for this electricity price impact analysis.Exhibit 7AState by State Breakoutof Average Electricity Price Increases Per OptionItemNumber ofPlantsStateMay 2009statewide averageelectricity price ($per kilowatt hour)Subtitle Chazardous wasteAverage PriceIncreaseSubtitle D(version 1)Average PriceIncreaseC - impoundmentsD - landfillsAverage PriceIncreaseAverage annualized cost (fromExhibit 4F) =$2,274$492$2,1761 2 AK $0.1518 1.30% 1.23% 1.25%2 10 AL $0.0856 1.43% 0.189% 1.419%170Source: 86.8% capacity utilization is the 1972-2008 annual average published in the 15 May 2009 Federal Reserve Statistical Release G.17 “Industrial Production &Capacity Utilization” data for Utilities at http://www.federalreserve.gov/releases/g17/Current/default.htm206Exhibit 7AState by State Breakoutof Average Electricity Price Increases Per OptionItemNumber ofPlantsStateMay 2009statewide averageelectricity price ($per kilowatt hour)Subtitle Chazardous wasteAverage PriceIncreaseSubtitle D(version 1)Average PriceIncreaseC - impoundmentsD - landfillsAverage PriceIncrease3 3 AR $0.0762 0.293% 0.225% 0.283%4 6 AZ $0.1002 1.141% 0.622% 1.113%5 6 CA $0.1337 0.717% 0.676% 0.687%6 14 CO $0.0797 0.121% 0.006% 0.017%7 2 CT $0.1712 0.074% 0.000% 0.000%8 0 DC $0.13379 3 DE $0.1236 0.156% 0.127% 0.129%10 15 FL $0.1136 0.131% 0.077% 0.113%11 11 GA $0.0859 1.160% 0.163% 1.152%12 2 HI $0.1892 0.245% 0.171% 0.174%13 19 IA $0.0710 0.548% 0.198% 0.537%14 0 ID $0.060215 25 IL $0.0924 0.531% 0.099% 0.488%16 26 IN $0.0766 1.387% 0.207% 1.348%17 8 KS $0.0822 0.545% 0.190% 0.532%18 21 KY $0.0640 2.307% 0.593% 2.237%19 4 LA $0.0748 0.464% 0.040% 0.462%20 4 MA $0.1534 0.027% 0.000% 0.000%21 8 MD $0.1316 0.080% 0.017% 0.037%22 1 ME $0.1222 0.520% 0.346% 0.352%23 22 MI $0.0986 0.459% 0.052% 0.455%24 16 MN $0.0804 2.013% 0.471% 1.993%25 20 MO $0.0757 0.817% 0.116% 0.798%26 5 MS $0.0893 0.197% 0.106% 0.193%27 5 MT $0.0720 5.582% 1.193% 5.531%28 22 NC $0.0839 1.122% 0.148% 1.102%29 7 ND $0.0698 0.994% 0.012% 0.982%30 7 NE $0.0705 0.223% 0.206% 0.210%31 2 NH $0.1544 0.055% 0.004% 0.004%32 7 NJ $0.1421 0.118% 0.045% 0.045%33 3 NM $0.0769 2.103% 0.407% 1.729%34 2 NV $0.0960 0.548% 0.518% 0.526%35 13 NY $0.1543 0.024% 0.000% 0.000%36 26 OH $0.0930 1.193% 0.132% 1.157%37 6 OK $0.0698 0.151% 0.050% 0.081%38 1 OR $0.0751 0.212% 0.200% 0.204%39 34 PA $0.0960 0.702% 0.229% 0.665%207Exhibit 7AState by State Breakoutof Average Electricity Price Increases Per OptionItemNumber ofPlantsStateMay 2009statewide averageelectricity price ($per kilowatt hour)Subtitle Chazardous wasteAverage PriceIncreaseSubtitle D(version 1)Average PriceIncreaseC - impoundmentsD - landfillsAverage PriceIncrease40 0 RI $0.134341 14 SC $0.0826 0.394% 0.028% 0.384%42 2 SD $0.0742 0.098% 0.084% 0.086%43 7 TN $0.0860 0.517% 0.001% 0.504%44 19 TX $0.1019 0.292% 0.038% 0.256%45 6 UT $0.0690 0.602% 0.336% 0.588%46 16 VA $0.0916 0.688% 0.078% 0.629%47 0 VT $0.128248 1 WA $0.0684 0.000% 0.000% 0.000%49 17 WI $0.0918 0.082% 0.063% 0.078%50 16 WV $0.0668 1.441% 0.615% 1.379%51 9 WY $0.0602 1.396% 0.315% 1.351%Summary:Minimum = $0.0602 0.0000% 0.0000% 0.0000%Maximum = $0.1892 5.5822% 1.2259% 5.5313%Average = $0.0985 0.7489% 0.2259% 0.7076%Median = $0.0860 0.5205% 0.1316% 0.4876%Nationwide =$0.08840.795%0.172%0.761%Because this price analysis isbased only on the 495 potentially affected coal-fired electric utility plants (with 333,500 megawatts nameplatecapacity) rather than on all electric utility and independent electricity producerplants in each stateusing other fuels suchas natural gas,nuclear, hydroelectric, etc. (with678,200 megawatts nameplate capacity), these price effects are higher than would be if the regulatory costswere averaged over the entireelectric utility and independent electricity producer supply (totaling 1,011,700 megawatts, not counting the76,100 megawatts of combined heatand electricity producers).171•Electricity Impact FindingsOn a nationwide basis for all 495 plants, compared to the estimated average electricity price of $0.0884 per kilowatt-hour across the 495 plants,the 100% regulatory cost pass-thru scenario may increase prices for the 495 plants by0.172% to 0.795%across the regulatory options. Noneof the regulatory options exceed the 1% threshold of EO 13211, thus thisRIA does not include a “Statement of Energy Effect” aswould berequired by Section 1 of EO 13211 if the price impactindicator as estimated in this RIA exceeded 1%.171Source: 2007 megawatt nameplate capacity data from the Energy Information Administration “Table 2.3. Existing Capacity by Producer Type, 2007” athttp://www.eia.doe.gov/cneaf/electricity/epa/epaxlfile2_3.pdf2087B. Small Business Impact Analysis (RFA/SBREFA)According to the requirements of the 1980Regulatory Flexibility Act (RFA) as amended by the 1996 Small Business Regulatory EnforcementFairness Act (SBREFA), Federal regulatory agencies are required to make initial determinations if proposed regulatory actions may have a“significant economic impact on a substantial number of small entities”(SISNOSE). Small entities include small businesses, smallorganizations, and small governmental jurisdictions. Agenciesare required to conduct a Regulatory Flexibility Screening Analysis (RFSA) tomake this determination. This section of the RIA presentsthe methodology and findings for the RFSA conducted for the proposedrule.Unless Agencies are able to certify that a particular regulatoryaction is not expected to havea SISNOSE, the RFA/SBREFA requires a formalanalysis of the potential adverse economic impacts on small entities, completion ofa Small Business Advocacy Review Panel (proposed rulestage), preparation of a Small Entity Compliance Guide (final rule stage), and Agency review of the rule within 10 years of promulgation.The small business impact analysis of this RIA follows the fouranalytic steps described in EPA’s RFA/SBREFA analysis guidance172:Step 1: Determine which small entitiesare subject to the rule’s requirementsStep 2: Select appropriate measures for determining economic impacts on these small entities and estimate those impactsStep 3: Determine whether the rule may be certified asnot having a significant impact on small entities (SISNOSE)Step 4: Document the screeninganalysis and include the appropriateRFA statements in the preamble•Step 1: Identification of Small EntitiesThe scope of entities addressed by this analysis includes the affected coal-fired electric utility plants in NAICS code 221112.Not included inthe scope of this RFA/SBREFA analysis are offsite commerciallandfills which currently receiveand dispose CCR generated by electric utilityplants. EPA’s RCRA statute does not provide EPA with authorityto collect information from solid waste facilities; it only provides EPA withauthority to collect information from RCRA-regulated hazardous waste management facilities (via the RCRA biennial report). EPAdoes notknow the identity, company size, or other information about the offsite landfills currently used by the electric utility industry. Therefore, thisRFA/SBREFA analysis is limited to only electric utility plants. Consistent with EPA’s RFA/SBREFA guidance (page 15), this RIAapplies thefollowing small size definitions for ownerentities of electric utility plants:Small company: Based on the US Small Business size standard for NAICS code 221112 (fossil fuel electric utility plants): acompany which generates less than 4 millionmegawatt-hours electricity output per year.172EPA’s RFA/SBREFA guidance: “EPA’s Action Development Process:Final Guidance for EPA Rulewriters: Regulatory Flexibility Act as amended by the SmallBusiness Regulatory Enforcement Fairness Act”, EPA Office of Policy, Economics & Innovation, Nov 2006, 105 pages:http://www.epa.gov/sbrefa/documents/rfaguidance11-00-06.pdf209Small government: Based on the RFA/SBREFA’s definition (5 US Code section 601(5)) of small government jurisdiction as thegovernment of a city, county, town, township, village, school district, or special district with population <50,000.Based on the nameplate megawatt (MW) capacity for all electricity generating units (including those powered by non-coal fuel types) at eachelectricity plant from the 2007 DOE-EIA 860 database, this RIA estimated annual megawatt-hours electricity generation capacitybymultiplying the nameplate capacity by (a) 365 days per year, and (b) 24 hours per day to calculateeach owner entity’s annual electricitycapacity.Appendix Dof this RIA indicates the assigned size of the owner companyor city government for each electric utility plant accordingto two size categories: “Small” or “Non-small”.173Exhibit 7Bbelow presents the resultant count and summary of the characteristics of thesmall electric utility entitiesas estimated in this RIA.Exhibit 7BSummary of Characteristics ofSmall Electric Utility EntitiesABCDE (D / B)Small Entity Sub-CategoriesCount of coalfired electricutility plants(2005/2007)Estimated count ofowner entities(2005/2007)Estimated 2007 annualmegawatt hours (mwh)capacity for all electricityplants owned by allentitiesEstimated 2009annual electricitysales for all entities($millions/year)2009 average annualelectricity salesrevenue per entity($millions/year)1. Small City Government 33 33 34.0 $2,592 $78.52. Small Company 12 11 10.6 $948 $86.23. Small Cooperative 6 6 12.0 $947 $157.84. Small County Government 1 1 0.3 $23 $23Summary:All small entities =52 plants(11%)51 entities(26%)56.8(1%)$4,509(1%)$88.4All non-small entities = 443 plants(89%)149 entities(74%)5,380.5(99%)$419,056(99%)$2,812.5All entities (non-small + small) = 495 plants 200 entities 5,437 million mwh* $423,565** $2,118Notes:* Annual electricity generationcapacity based on all electric plants and types of electric generation units (e.g. coal-fired,oil-fired, hydropower, nuclear,wind, biomass, etc.) owned by these companies, not just coal-fired electricity generation capacity.** $423.6 billion per year annual electricity sales estimated in this RIA is 73% of the $581.6 billion per year total revenuesreported for NAICS code 22(Utilities sector) in the 2007 Economic Census at: http://factfinder.census.gov/servlet/IBQTable?_bm=y&-geo_id=D&-ds_name=EC0700A1&-_lang=en173It should be noted that some of the companies identified as small using the SBA size standard for NAICS 22 and the utility code specification in the 2007 EIA 860database to identify each corporate entity may be subsidiaries ofa larger holding company (classified under a different NAICS)rather than a larger power company. Inaddition some of these power companies may have merged. For example, State Line is owned by Dominion Resources of Virginia, Northeastern Power is owned by SuezEnergy North America, Inc. (SEGNA), Rio Bravo Poso and Rio Bravo Jasmin are owned by the North American Power Group, Ltd (NAPG), TES Filer City Station LP isowned by TONDU, Public Service Enterprise Group (PSEG) and Excelon are merged. This approach likely overstates the number of small entities.210•Step 2: Measures for Determining Economic Impacts on Small EntitiesAccording to Exhibit 1 of EPA’s 2006 RFA/SBREFA small business impact analytic guidance, there are the following suggested tests that maybe used to determine if small entities maybe significantly impacted by a proposed rule:•Small business impact tests:oSales test: Annualized compliance costs as a percentage of salesoCash flow test:Debt-financed capital compliance costs relative to current cash flowoProfit test: Annualized compliance costs as a percentage of profits•Small government impact tests:oRevenue test: Annualized compliance costs asa percentage of annual government revenuesoIncome test: Annualized compliance costs tohousehold (per capita) asa percentage of median household (per capita) incomeBased on annual electricity generation data for the small owner entities in the electric utility industry identified inAppendix Dof this RIA, theannual sales/annual revenue test was used for this analysis. As itemized and estimated for each owner entity in the spreadsheets presented asAppendix Mto this RIA, for each small entity EPAcomputed the respective sales revenue test percentages by the equation below:(AEGC x 1,000) x (ASP) x (CU) = annual $sales or $revenues per small entityWhere:AEGC = Annual electricity generation capacity per-entity in annual million megawatts(per-entity megawatt data is displayed inAppendix D). This estimate involved downloading the annualmillion megawatt capacity data for each of the 495electricity plants from the DOE-EIA website (2007), and then multiplying the capacity data by two factors:o365 operating days per yearo24 operating hours per dayASP = February 2009 average statewide retail price to ultimate consumers for electricity (i.e., cents per kilowatt-hour) for therelevant state or states applicable tothe location of electric plants owned by eachcompany; electricity price reflects thecomposite price charged to residential, commercial, industry andtransportation sectors174CU = 86.8% electric utility industry capacity utilization from 1972-2008 average reported by the 15 May 2009 Federal ReserveStatistical Release G.17 “Industrial Production & Capacity Utilization”data for Utilities at:http://www.federalreserve.gov/releases/g17/Current/default.htm174DOE’s Energy Information Administration (EIA)publishes state-by-state average retail electricity prices for four end-user sectors (i.e., residential, commercial,industrial, transportation) and on a composite basis at: http://www.eia.doe.gov/cneaf/electricity/epm/table5_6_a.html211•Step 3 & Step 4: Determine and document whether the proposed rule may be certified as having “No SISNOSE”EPA determined whether each regulatory optionmay have a “significant impact on a substantial number of small entities” (i.e.,SISNOSE)which may become subject to the requirements of the proposed rule. This determination involved comparing the estimated regulatorycompliance costs for each entity as displayed inAppendix Jof this RIA and as summarized inExhibit 7Cbelow (small entity row items 6, 7,8, 9), to the respective annual sales and revenues for each entity estimated in Step 2 above. Numerically, this comparison involved calculatingthe percentage of regulatory compliance costs relative to annual sales and revenues for each company for each of the regulatoryoptions. Thencompared the percentage results for each small entity to the following three impact thresholds defined in Table 2 of EPA’s RFA/SBREFAanalytic guidance.Exhibit 7Dbelow displays the numerical results of this analysisand the suggested RFA/SBREFA impact interpretationaccording to the three thresholds.<1% threshold: Annualized regulatory costs may be less then 1% of annual sales or revenues for small entities1% or more threshold: Annualized regulatory costs may be 1% or more of annual sales or revenues for affected small entities3% or more threshold: Annualized regulatory costs may be 3% or more of annual sales or revenues for affected small entitiesExhibit 7CSummary of Regulatory Cost Estimates According to Electric Utility Plant Owner Entity Size/Type Category($millions in 2009 price level; average annual amortized @7% discount rate over 50-year period 2012 to 2061)Size/Type of Entity*Count of plantsin category***Subtitle CHazardous wasteSubtitle D(version 1)Subtitle C for impoundmentsSubtitle D for landfills1. Non-Small City 27 plants $46.9 $27.1 $43.92. Non-Small Company 372 plants $1,897.2 $378.5 $1,821.23. Non-Small Coop 20 plants $87.7 $34.6 $85.34. Non-Small Federal 11 plants $183.2 $20.8 $181.05. Non-Small State** 13 plants $41.6 $27.1 $39.86. Small City 33 plants $2.8 $1.6 $2.57. Small Company 12 plants $4.1 $1.9 $2.08. Small Coop 6 plants $10.4 $0.3 $0.39. Small County 1 plant $0.004 $0.004 $0.004Total all 9 categories =495 plants***$2,274$492$2,176Notes:* Size/Type classification methodology defined according toExhibit 3Bof this RIA.** State government costs include costs to (a) state government electric utility plants regulatorycosts, plus (b) state government RCRA-authorizedprograms for option implementation.*** The total count of coal-fired electric utility plants is shown in the Exhibit; however, only a sub-total of 467 of the 495may incur theseregulatory costs because 28 plants solely supply their CCR for beneficial uses.212Exhibit 7DEstimated Impact of Regulatory Options on Small Entities (RFA/SBREFA Analysis Results)($millions average annualized direct costs @7% discount rate over 50-year period 2012-2061)Cost as Percentage ofAnnual Electricity RevenuesSubtitle CHazardous wasteSubtitle D(version 1)Subtitle C for impoundmentsSubtitle D for landfillsA. Count of Small Entities:Annualized cost on small entities:* $17.3 $3.8 $4.8Less than 1% 46 50 501% or greater 5 1 13% or greater 0 0 0B. % of Small Entities:Less than 1% 90% 98% 98%1% or greater 10% 2% 2%3% or greater 0% 0% 0%C. SISNOSE Findings:Less than 1% Presumed No SISNOSE Presumed No SISNOSE Presumed No SISNOSE1% or greater Presumed No SISNOSE Presumed No SISNOSE Presumed No SISNOSE3% or greater Presumed No SISNOSE Presumed No SISNOSE Presumed No SISNOSE* Source:Costs for each option based on total cost for the four small entity categories displayed as rows 6 + 7 + 8 + 9 fromExhibit 7C.•Limitations of RFA/SBREFA DeterminationNot included in the RFA/SBREFAanalysis of this RIA aretwo factorsunique to the electric utility industry, which may reduce the smallentity impacts relative to theestimates above in this RIA:•Factor #1 of 2: According to the 2007 DOE-EIA databaseon electric utility plants, two-thirds of the coal-fired electricity generationunits at electric utility plants owned by small entities can switch to at least one of six other fuels:1.Agricultural byproducts (database code = AB)2.Distillate fuel oil (DFO)3.Natural gas (NG)4.Petroleum coke (PC)5.Propane (PG)6.Wood & wood waste solids (WDS)213•Factor #2 of 2: The small business impact analysis in this RIA applies the full industry compliance cost to the revenue and sales tests.However, because consumer demand for electricity is (a) highly price-inelastic and (b) projected go grow by 30% by year 2025175,electric utility plants may be expected topass-thru much, if not all,of their regulatory costs (pending state government utility ratehike approval). The next section of this RIA evaluates the possibility of regulatory compliance cost pass-thru.•Compliance Cost Pass-Thru AnalysisoAbility to Raise Electricity PricesTraditionally, the electric utilityindustry has functioned as a regulated monopoly, providing essential electrical services under an exclusivefranchise in exchange for having rates closely regulated by State public utility commissions (PUCs; sometimes called PSC publicservicecommissions) and the Federal Energy Regulatory Commission (FERC). The FERC regulates rates charged for sales of bulk power betweenutilities, even if they are in the samestate. It also regulates the pricing and use of transmission for wheeling, and asset transfers, includingmergers. In most states (California de-regulated electricity in 1998), the PUCs/PSCs set allowable rates upon application by the utility, withother affected parties allowed to present testimony. By law the utility must recover its cost ofservice, which includes "prudently" incurredexpenses and a "fair" return on equity.176Based on the electricity ratemaking process described by the Pennsylvania PUC177as a case example, when an electric utility company seeks aprice increase (aka rate hike), it must file a request with the PUC showing the proposed new rates and effective date, and mustprove that theincrease is needed. The utility also mustnotify customers at least 60 days in advance. The notice must include the amount ofthe proposed rateincrease, the proposed effective date, and how much more the ratepayer can expect to pay. Underthe law, the utility is entitled to recovery ofits reasonably incurred expenses and a fairreturn on its investment. The PUC evaluates each utility’s request for a rate increase based on thosecriteria. During the investigation, hearings are held before anAdministrative Law Judge (ALJ) atwhich the evidence in support of the rateincrease is examined and expert witnesses testify. In addition,consumers are offered an opportunity to voice their opinions and give testimony.Briefs may be submitted by the formal parties. A recommendation to the PUC is made by the ALJ. Finally, the matter is broughtbefore theCommissioners for a vote and final decision. Together with the60-day notice period, the rate increase process takes about nine months.Recent (2008) examples of requested or PUC-approved electricity rate hikes are summarized inExhibit 7Ebelow:17817530% additional electricity demand forecst for year 2025 relative toyear 2005, from slide 17 of “Energy & Water: Emerging Issues and Trands” by Richard Kottenstetteand Mike Hightower, Sandia National Laboratories, at: http://www.ct-si.org/Summit2007/spk/RKottenstette.pdf176Source: “Electric Utility Regulation” by Robert J.Michaels in the Concise Encyclopedia of Economics at:http://www.econlib.org/library/Enc1/ElectricUtilityRegulation.html177Source: 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.pdf178Source: “Recent Examples of Rate Increases in Vertically Integrated States”, The Compete Coalition, Washington DC, 05 November2008 at:http://www.competecoalition.com/resources/recent-examples-rate-increases-vertically-integrated-states214Exhibit 7ESummary of 2008 US Electricity Price HikesItemStateEffective dateRequested or approved price hike1 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 allowingmultiple electric suppliers, not just amonopolyelectricity supplier, to compete and set their own retail prices in those state markets. As of 2003, 18 states have deregulated and six states maysoon deregulate:179•Deregulated states (18): AZ, CT, DE, DC, IL, ME, MD, MA, MI, NH, NJ, NY, OH, OR, PA, RI, TX, VA(11 of these states no longer have a price cap)•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 to2006, prices increased 36% duringthat period in 11 of the 18 deregulated stateswhere rate caps expired, suggesting greaterpricing flexibility inderegulated states.180oInelastic Demand for ElectricityAt the wholesale level, as a result of technological and regulatory barriers, the majority ofelectricity pricing plans do notallow end users to seeand react to the actual marketvalue of their electricity consumption/ conservation. Since end-users do not face the real-timemarket price inmaking their consumption decisions, there islittle demand reaction to changes inreal time wholesale electricity prices.181At the retail level,consumer demand for electricity has been largely inelastic. Thelack of real time metering at the retail level means that consumers don't know179Source: “Status of State ElectricIndustry Restructuring Activity as of February 2003”, US Dept of Energy, Energy InformationAdministration at:http://www.eia.doe.gov/cneaf/electricity/chg_str/restructure.pdf180Source: “Shocking Electricity Prices Follow Deregulation”, USA Today, 10 Aug 2007 at: http://www.usatoday.com/money/industries/energy/2007-08-09-powerprices_n.htm181Source: page 1 of “Demand Responsiveness in Electricity Markets”, Ronald Lafferty et al., Office of Markets, Tariffs and Rates, 15 Jan 2001 at:http://www.naseo.org/committees/energyproduction/documents/demand_responsiveness_in_electricity_markets.pdf215how much they use or indeed how much electricity costs until after thefact. Thus consumers cannot react to high prices easilyby cuttingconsumption.182oCost Pass-Thru ConclusionBased on the above three cost pass-thru factors consisting of (a) 20 examples of recent (2008) PUC-regulated rate hikes which average almost19% per company which far exceeds the 1% and 3% SISNOSE screening analysis thresholds defined by EPA’s guidance, (b) 11 of the18deregulated states which have de-regulated the price of electricity, and (c) the fact that consumer demand for electricity hasbeen relativelyinelastic, this RIA concludes that it is likely that electric utility suppliers could pass-thru all, or nearly all, of the future average annualregulatory compliance costs for the CCR proposedrule such that a significant impacton small entities and non-small entities would not occur.182Source: “Power Price Volatility and Risk Management: An Introduction”, Anne Ku, Sept 2000 (this is the original, unedited article, later submitted to Global EnergyBusinessmagazine Sept/Oct 2000) at: http://www.analyticalq.com/energy/volatility/default.htm2167C. Minority & Low-Income Population Statistics(Executive Order 12898)Under the 1994 Executive Order (EO) 12898183it is the responsibility of Federal agencies tothe greatest extent practicable and permitted bylaw, and consistent with the principles set forth in the reporton the National Performance Review, each Federal agency shall make achievingenvironmental justice (EJ) part of itsmission by identifying and addressing, as appropriate, disproportionately high and adverse human healthor environmental effects of its programs, policies, and activities on (a)minoritypopulations and (b)low-incomepopulations. Although notdefined in EO 12898, for purpose of this RIA the following definitions are applied:•Minority population: Numericallymeasured according to Census Bureau “non-white” statistics (does notinclude Hispanics).•Low-income population: Numericallymeasured according to CensusBureau “individuals below poverty184level.”Furthermore, section 3-302(b) of EO 12898 provides a trigger which indicates that Federal agencies shall collect and evaluate EJ data for anyfacilities or sites expected to have “substantial environmental,human health, or economic effect”when such facilities or sites become subjectto “substantial” Federal environmental action:“In connection with the development and implementation of agencystrategies in section 1-103 ofthis order, each Federalagency, whenever practicable and appropriate, shall collect, maintain and analyze information on the race, national origin,income level, and other readily accessible and appropriate information for areas surrounding facilities or sites expected to havesubstantialenvironmental, human health, or economiceffecton the surrounding populations, when such facilities or sitesbecome the subject of a substantial Federal environmental administrative or judicial action. Such information shall be madeavailable to the publicunless prohibited by law.”The EO 12898 does not establish quantitative thresholds for “substantial effect”on the surrounding populations, nor does thisRIA formulate aquantitative threshold. This RIA uses the(1) CCR disposal baseline environmental and human health hazards (e.g., damage cases), and (2) theenvironmental and human health protection objectives described inthe CCR proposed rule, as indicators of “substantial effect”.For thatreason, this section of the RIA presents anEJ data collection and analysis involving a 5-step process to compare minority andlow-incomepopulation data for each electric utilityplant location, to respective statewide population data, to identify whether these two population subgroups disproportionately reside in geographic areas where electric utility plants are located. Inaddition, this RIA identifies two other possibleaffects of the CCR proposed rule on (a) environmental justice populations surrounding offsitelandfills which may receive CCR,and (b)environmental justice populations within electric utility plant customer service areas.183Source: 1994 Executive Order 12898 is available at: http://www.epa.gov/fedrgstr/eo/eo12898.htm184The US Census Bureau defines “poverty”following the Office of Management and Budget's (OMB) Statistical Policy Directive 14.The Census Bureau uses a set ofmoney income thresholds that vary by family size and composition todetermine who is in poverty. If a family’s total income isless than the family’s threshold, then thatfamily and every individual in it is considered in poverty.Poverty income thresholds are available at http://www.census.gov/hhes/www/poverty/threshld/thresh08.html217•Collection of Minority & Low-Income Demographic DataStep 1: Plant address 5-digit “Zip CodeTabulation Areas” (ZCTAs) formed the geographic basis for this EJ population data collection.Because ZCTAs represent irregularly shapedgeographic areas, this ZCTA based data collection may be considered a “screening level”analysis. The US Bureau of Census usesover 33,000 ZCTA for its Census counts of population and other demographic statistics basedon the US Postal Service’s over 42,000 nationwide ZCTAs.185Currently, there are no size restrictions limiting how large or small aZCTA can be in terms of either a minimum/maximum number of housing units or geographic area. Any particular ZCTA may be assmall as a few city blocks or may cover many square miles. Many ZCTAs are for villages, census-designated places, portions ofcities,or other entities that are not municipalities. The nationwide average ZCTA population is about 7,200 persons (i.e., (306.6 million mid2009 US population) / (42,500 ZCTAs)). Thenationwide average ZCTA area is about 83square miles (i.e., (3,536,278 square milestotal US land and water area)/ (42,500 ZCTAs)), which is a land area equivalentto a five-mile radial distance (i.e., ((83 square miles) /(3.1416))^0.5). In comparison, the radial area monitored for contamination in response to the December 2009 TVA Kingston TNelectric plant CCR spill is reportedly four miles,186and this average four-mile ZCTA radial distance falls between the 1-mile to 15-mileradial distances used by EPA’s Superfund “Hazard Ranking System” (HRS) to define affected populations of sites having either (a) soilcontamination only (1-mile), (b) groundwaterand/or airborne contamination (4-miles),or (c) surface water contamination (15-milesdownstream). More information about EPA’s HRS is available at http://www.epa.gov/superfund/programs/npl_hrs/hrsint.htm.Using the Census search engine Factfinder (http:factfinder.census.gov/home/saff/main.html?_lang=en), EPA retrieved populationstatistics for 464 (94%) of the 495 electricutility plants. For 42 plants (8%) therewas no ZCTA Census data because the plants did nothave complete address data from DOE, or because the Census search engine did not have data for the ZCTA.Step 2: EPA collected statewide percentagedata for minority and low-income subgroupsfor purpose of benchmark comparison to theplant-by-plant sub-grouppopulation statistics.oEPA collected low-income population statewide percentages (3-year averages for 1998 to 2000) from the followingCensus Bureau website:http://www.census.gov/hhes/www/poverty/poverty00/tabled.pdfoEPA collected statewide percentages for white population sub-group (data year 2000) from the Census Bureau website: .EPA then subtracted the percentage ofwhite population in each state from 100%to produce the respective minoritypercentage for each state. For data year 2000, the CensusBureau expanded the white population classification bycollecting both data for people who claimed to be “white-only” and for people who claimed to be “mixed white”. Sincethe purpose of the EJ analysis is to evaluate all minorities, thisstep involved collecting the “white-only” data in order tocalculate the minority percentage which includes people who reported to be of mixed race.Exhibit 7Fbelow displaysthe statewide Census data for low-income and minority sub-populations.185Source: US Census Bureau ZIP Code Tabulation Area (ZCTA) Frequently Asked Questions at: Nationwide total ZCTA count is fromthe US Postal Service’s FAQwebsite at: http://zip4.usps.com/zip4/welcome.jsp186Source: 4 mile radial monitoring area reported by Waste & Recycling News, 13 Feb 2009; http://www.wasterecyclingnews.com/email.html?id=1234543579218Exhibit 7FStatewide Benchmark Data on Low-Income and Minority Populations (2000)ItemStateLow 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%ItemStateLow Income %Minority %29 ND 12.7% 7.6%30 NE 10.7% 10.4%31 NH 7.6% 4.0%32 NJ 8.1% 27.4%33 NM 19.3% 33.2%34 NV 10.1% 24.8%35 NY 14.7% 32.1%36 OH 11.1% 15.0%37 OK 14.1% 23.8%38 OR 12.9% 13.4%39 PA 9.8% 14.6%40 RI 10.2% 15.0%41 SC 12.0% 32.8%42 SD 9.4% 11.3%43 TN 13.4% 19.8%44 TX 14.9% 29.0%45 UT 8.1% 10.8%46 VA 8.1% 27.7%47 VT 10.3% 3.2%48 WA 9.5% 18.2%49 WI 9.0% 11.1%50 WV 15.8% 5.0%51 WY 11.1% 7.9%Min = 7.3% (MD) 3.1% (ME)Max = 19.3% (NM) 75.7% (HI)National =11.9%24.9%219•Comparison of Minority & Low-Income Populations Surrounding Electric Utility Plantsto Statewide BenchmarksStep 3, Step 4 and Step 5 of this evaluation described below involved three complementary levels of data comparisons. All three comparisonsalso involved two complementary numerical comparisons, one based on calculating numerical percentages and the other on numerical ratios:1.Plant level: Plant-by-plant disaggregateddata comparison to statewide benchmarks2.State level: State-by-state aggregated plant data comparison to statewide benchmarks3.Nationwide level: Nationwide aggregated plantdata comparison to nationwide benchmarks•Calculation of Three Alternative Demographic Statistics Comparison MethodsStep 3: On a plant-by-plant basis, EPA compared the plant ZCTA percentage minorityand percentage low-income population data, to therespective statewide average percentages for each sub-group. This constituted the 1stlevel of data comparison.Step 4: For purpose of summary,EPA aggregated the plant level population comparison data for each state as displayed inExhibit 7Gbelow.This constituted the 2ndlevel of data comparison. There are no data displayed for DC, ID, RI orVT because there are no coal-firedelectric utility plants in those states.Appendix Nof this RIA presents the plant-by-plant Census data on which this Exhibit is based.This step also involved aggregating thedata across all 495 plants for comparison with the nationwide aggregate minority and lowincome percentage benchmarks. This constituted the 3rdlevel of data comparison.Exhibit 7GMinority and Low-Income Population DataAggregated on State-by-State BasisABCDEF(E/D)G(Exh 7F)H(DxG)IJK(DxJ)L(Exh 7F)M(DxL)NGeneral Population DataLow Income Population Data (Below Poverty)Minority Population DataItemStateZCTAcount2000populationresiding inelectric utilityplant ZCTAareasCount ofplantZCTAresidentsbelowpovertylevel% of plantZCTAresidentsbelow povertylevelState %belowpovertylevelExpectedcount ofresidentsbelowpovertybased onstate%Count ofplants withZCTA% >state%povertylevel% ofplantZCTAresidentsthat areminorityCount ofplant ZCTAresidentsthat areminorityStatewide %minorityExpectedcount ofminoritybased onstate%Count ofplantswithZCTA% >state%minoritylevel1 AK 2 18,552 2,284 12.31% 8.40% 1,558 1 31.95% 5,928 30.70% 5,695 12 AL 9 82,854 20,331 24.54% 14.70%12,180 6 42.17% 34,942 28.90% 23,945 43 AR 3 11,786 1,214 10.30% 15.80%1,862 0 7.74% 912 20.00% 2,357 04 AZ 6 34,941 7,433 21.27% 13.50%4,717 5 43.70% 15,270 24.50% 8,561 35 CA 4 112,895 24,749 21.92% 14.00%15,805 5 45.22% 51,049 40.50% 45,722 26 CO 15 214,095 29,395 13.73% 8.50%18,198 10 17.88% 38,275 17.20% 36,824 87 CT 2 42,716 6,427 15.05% 7.70%3,289 1 45.14% 19,284 18.40% 7,860 18 DC ND220Exhibit 7GMinority and Low-Income Population DataAggregated on State-by-State BasisABCDEF(E/D)G(Exh 7F)H(DxG)IJK(DxJ)L(Exh 7F)M(DxL)NGeneral Population DataLow Income Population Data (Below Poverty)Minority Population DataItemStateZCTAcount2000populationresiding inelectric utilityplant ZCTAareasCount ofplantZCTAresidentsbelowpovertylevel% of plantZCTAresidentsbelow povertylevelState %belowpovertylevelExpectedcount ofresidentsbelowpovertybased onstate%Count ofplants withZCTA% >state%povertylevel% ofplantZCTAresidentsthat areminorityCount ofplant ZCTAresidentsthat areminorityStatewide %minorityExpectedcount ofminoritybased onstate%Count ofplantswithZCTA% >state%minoritylevel9 DE 3 46,925 3,979 8.48% 9.90%4,646 1 28.86% 13,543 25.40% 11,919 110 FL 13 224,502 23,866 10.63% 12.10%27,165 5 20.76% 46,617 22.00% 49,390 311 GA 9 202,973 29,461 14.51% 12.50% 25,372 4 42.66% 86,581 34.90% 70,838 412 HI 1 25,054 1,150 4.59% 10.60%2,656 0 78.17% 19,584 75.70% 18,966 113 IA 14 324,050 31,434 9.70% 7.90%25,600 13 7.02% 22,744 6.10% 19,767 914 ID ND15 IL 23 455,834 83,407 18.30% 10.50%47,863 14 41.46% 188,970 26.50% 120,796 816 IN 17 323,323 25,460 7.87% 8.30%26,836 10 6.96% 22,488 12.50% 40,415 217 KS 6 59,517 7,718 12.97% 10.50%6,249 4 36.76% 21,881 13.90% 8,273 318 KY 17 255,033 32,497 12.74% 12.50% 31,879 7 8.48% 21,615 9.90% 25,248 219 LA 4 30,381 7,546 24.84% 18.50%5,620 3 45.16% 13,721 36.10% 10,968 220 MA 3 95,798 14,420 15.05% 10.10%9,676 1 20.69% 19,819 15.50% 14,849 121 MD 7 101,141 10,622 10.50% 7.30%7,383 4 12.39% 12,527 36.00% 36,411 122 ME 1 6,748 1,037 15.37% 9.80% 661 1 1.30% 88 3.10% 209 023 MI 20 383,284 30,735 8.02% 10.20%39,095 8 10.56% 40,477 19.80% 75,890 224 MN 15 187,012 20,910 11.18% 7.80%14,587 10 10.78% 20,157 10.60% 19,823 325 MO 19 251,484 24,714 9.83% 9.80%24,645 10 7.47% 18,794 15.10% 37,974 226 MS 4 69,209 17,675 25.54% 15.50%10,727 3 51.63% 35,735 38.60% 26,715 227 MT 5 53,209 8,441 15.86% 16.00%8,513 2 13.25% 7,050 9.40% 5,002 428 NC 16 238,874 37,388 15.65% 13.20%31,531 9 34.49% 82,397 27.90% 66,646 1229 ND 5 27,087 2,440 9.01% 12.70% 3,440 1 4.40% 1,193 7.60% 2,059 030 NE 6 79,313 8,992 11.34% 10.70%8,486 2 11.38% 9,027 10.40% 8,249 231 NH 2 53,302 4,355 8.17% 7.60% 4,051 2 5.40% 2,877 4.00% 2,132 232 NJ 6 119,286 17,958 15.05% 8.10%9,662 3 43.96% 52,438 27.40% 32,684 333 NM 4 17,491 4,638 26.52% 19.30%3,376 3 55.72% 9,746 33.20% 5,807 334 NV 3 8,471 823 9.72% 10.10% 8561 15.75% 1,334 24.80% 2,101 135 NY 13 226,416 29,187 12.89% 14.70% 33,283 3 17.42% 39,451 32.10% 72,680 336 OH 23 391,705 42,242 10.78% 11.10% 43,479 7 12.24% 47,953 15.00% 58,756 237 OK 6 30,357 6,117 20.15% 14.10% 4,280 4 38.84% 11,791 23.80% 7,225 138 OR 1 3,884 596 15.35% 12.90% 501 1 39.19% 1,522 13.40% 520 139 PA 28 167,254 15,499 9.27% 9.80%16,391 15 6.61% 11,048 14.60% 24,419 340 RI ND41 SC 12 222,414 28,746 12.92% 12.00%26,690 8 31.40% 69,831 32.80% 72,952 642 SD 2 30,508 1,763 5.78% 9.40%2,868 1 5.55% 1,694 11.30% 3,447 0221Exhibit 7GMinority and Low-Income Population DataAggregated on State-by-State BasisABCDEF(E/D)G(Exh 7F)H(DxG)IJK(DxJ)L(Exh 7F)M(DxL)NGeneral Population DataLow Income Population Data (Below Poverty)Minority Population DataItemStateZCTAcount2000populationresiding inelectric utilityplant ZCTAareasCount ofplantZCTAresidentsbelowpovertylevel% of plantZCTAresidentsbelow povertylevelState %belowpovertylevelExpectedcount ofresidentsbelowpovertybased onstate%Count ofplants withZCTA% >state%povertylevel% ofplantZCTAresidentsthat areminorityCount ofplant ZCTAresidentsthat areminorityStatewide %minorityExpectedcount ofminoritybased onstate%Count ofplantswithZCTA% >state%minoritylevel43 TN 8 158,267 26,572 16.79% 13.40%21,208 4 37.38% 59,159 19.80% 31,337 144 TX 17 98,402 14,147 14.38% 14.90%14,662 10 22.41% 22,052 29.00% 28,537 345 UT 6 34,209 3,885 11.36% 8.10%2,771 6 5.22% 1,784 10.80% 3,695 046 VA 15 220,800 21,822 9.88% 8.10% 17,885 11 37.78% 83,411 27.70% 61,162 1147 VT ND48 WA 1 21,842 3,394 15.54% 9.50%2,075 1 9.54% 2,083 18.20% 3,975 049 WI 13 178,705 23,577 13.19% 9.00%16,083 8 12.00% 21,446 11.10% 19,836 450 WV 13 64,771 15,577 24.05% 15.80%10,234 11 6.45% 4,179 5.00% 3,239 251 WY 8 69,736 6,439 9.23% 11.10%7,741 1 4.92% 3,428 7.90% 5,509 0Summary:Column totals 430 6,076,410783,06212.9%11.9%658,33624021.7%1,317,89524.9%1,241,38212918.9%-5.8%Min = 4.6% 7.3% 1.3% 3.1%Max = 26.5% 19.3% 78.2% 75.7%Extrapolated to 495 plants =256138222Step 5: Ratios: EPA compared the percentages of minority and low-income populationssurrounding the plants to their respectivestatewidebenchmark percentages and to the nationwide percentages of these populations as calculated in Step 4, by calculating numericalratiosbetween the plant ZCTA group populations compared to statewide and nationwide percentages of minority and low-incomepopulations. The purpose of these ratios isto indicate the relative degree by which the percentages are below or above the statewidepercentages.Exhibit 7Hbelow displays the results.Exhibit 7HComparison of Minority and Low-Income Populations NearCoal-Fired Electric Utility Plants to Statewide PercentagesABCDEF (D–E)G (D/E)HIJ (H–I)K (I/J)Low-Income Data ComparisonMinority Data ComparisonItemStateCountofplantsPercentLow-IncomePopulationSurroundingPlantsStatewideLow-IncomePercentage(Exhibit 7F)DifferenceRatioPercentMinorityPopulationSurroundingPlantsStatewideMinorityPercentage(Exhibit 7F)DifferenceRatio1 AK 2 12.3% 8.4% 3.9% 1.47 32.0% 30.7% 1.3% 1.042 AL 9 24.5% 14.7% 9.8% 1.67 42.2% 28.9% 13.3% 1.463 AR 3 10.3% 15.8% -5.5% 0.65 7.7% 20.0% -12.3% 0.394 AZ 6 21.3% 13.5% 7.8% 1.58 43.7% 24.5% 19.2% 1.785 CA 5 21.9% 14.0% 7.9% 1.57 45.2% 40.5% 4.7% 1.126 CO 15 13.7% 8.5% 5.2% 1.62 17.9% 17.2% 0.7% 1.047 CT 2 15.0% 7.7% 7.3% 1.95 45.1% 18.4% 26.7% 2.458 DC NR NA NA NA NA NA NA NA NA9 DE 3 8.5% 9.9% -1.4% 0.86 28.9% 25.4% 3.5% 1.1410 FL 14 10.6% 12.1% -1.5% 0.88 20.8% 22.0% -1.2% 0.9411 GA 9 14.5% 12.5% 2.0% 1.16 42.7% 34.9% 7.8% 1.2212 HI 1 4.6% 10.6% -6.0% 0.43 78.2% 75.7% 2.5% 1.0313 IA 17 9.7% 7.9% 1.8% 1.23 7.0% 6.1% 0.9% 1.1514 ID NR NA NA NA NA NA NA NA NA15 IL 25 18.3% 10.5% 7.8% 1.74 41.5% 26.5% 15.0% 1.5616 IN 19 7.9% 8.3% -0.4% 0.95 7.0% 12.5% -5.5% 0.5617 KS 7 13.0% 10.5% 2.5% 1.24 36.8% 13.9% 22.9% 2.6418 KY 19 12.7% 12.5% 0.2% 1.02 8.5% 9.9% -1.4% 0.8619 LA 4 24.8% 18.5% 6.3% 1.34 45.2% 36.1% 9.1% 1.2520 MA 4 15.1% 10.1% 5.0% 1.49 20.7% 15.5% 5.2% 1.3321 MD 8 10.5% 7.3% 3.2% 1.44 12.4% 36.0% -23.6% 0.3422 ME 1 15.4% 9.8% 5.6% 1.57 1.3% 3.1% -1.8% 0.4223 MI 23 8.0% 10.2% -2.2% 0.79 10.6% 19.8% -9.2% 0.5324 MN 15 11.2% 7.8% 3.4% 1.43 10.8% 10.6% 0.2% 1.0225 MO 19 9.8% 9.8% 0.0% 1.00 7.5% 15.1% -7.6% 0.4926 MS 4 25.5% 15.5% 10.0% 1.65 51.6% 38.6% 13.0% 1.34223Exhibit 7HComparison of Minority and Low-Income Populations NearCoal-Fired Electric Utility Plants to Statewide PercentagesABCDEF (D–E)G (D/E)HIJ (H–I)K (I/J)Low-Income Data ComparisonMinority Data ComparisonItemStateCountofplantsPercentLow-IncomePopulationSurroundingPlantsStatewideLow-IncomePercentage(Exhibit 7F)DifferenceRatioPercentMinorityPopulationSurroundingPlantsStatewideMinorityPercentage(Exhibit 7F)DifferenceRatio27 MT 6 15.9% 16.0% -0.1% 0.99 13.2% 9.4% 3.8% 1.4128 NC 19 15.7% 13.2% 2.5% 1.19 34.5% 27.9% 6.6% 1.2429 ND 7 9.0% 12.7% -3.7% 0.71 4.4% 7.6% -3.2% 0.5830 NE 6 11.3% 10.7% 0.6% 1.06 11.4% 10.4% 1.0% 1.0931 NH 2 8.2% 7.6% 0.6% 1.08 5.4% 4.0% 1.4% 1.3532 NJ 6 15.1% 8.1% 7.0% 1.86 44.0% 27.4% 16.6% 1.6033 NM 4 26.5% 19.3% 7.2% 1.37 55.7% 33.2% 22.5% 1.6834 NV 3 9.7% 10.1% -0.4% 0.96 15.7% 24.8% -9.1% 0.6335 NY 13 12.9% 14.7% -1.8% 0.88 17.4% 32.1% -14.7% 0.5436 OH 24 10.8% 11.1% -0.3% 0.97 12.2% 15.0% -2.8% 0.8237 OK 6 20.2% 14.1% 6.1% 1.43 38.8% 23.8% 15.0% 1.6338 OR 1 15.3% 12.9% 2.4% 1.19 39.2% 13.4% 25.8% 2.9239 PA 31 9.3% 9.8% -0.5% 0.95 6.6% 14.6% -8.0% 0.4540 RI NR NA NA NA NA NA NA NA NA41 SC 12 12.9% 12.0% 0.9% 1.08 31.4% 32.8% -1.4% 0.9642 SD 2 5.8% 9.4% -3.6% 0.61 5.6% 11.3% -5.7% 0.4943 TN 8 16.8% 13.4% 3.4% 1.25 37.4% 19.8% 17.6% 1.8944 TX 18 14.4% 14.9% -0.5% 0.96 22.4% 29.0% -6.6% 0.7745 UT 6 11.4% 8.1% 3.3% 1.40 5.2% 10.8% -5.6% 0.4846 VA 16 9.9% 8.1% 1.8% 1.22 37.8% 27.7% 10.1% 1.3647 VT NR NA NA NA NA NA NA NA NA48 WA 1 15.5% 9.5% 6.0% 1.64 9.5% 18.2% -8.7% 0.5249 WI 15 13.2% 9.0% 4.2% 1.47 12.0% 11.1% 0.9% 1.0850 WV 16 24.0% 15.8% 8.2% 1.52 6.5% 5.0% 1.5% 1.2951 WY 9 9.2% 11.1% -1.9% 0.83 4.9% 7.9% -3.0% 0.62Summary:Min = 4.6% 7.3% -6.0% 0.43 4.4% 3.1% -23.6% 0.34Max = 26.5% 19.3% 10.0% 1.95 78.2% 75.7% 26.7% 2.92Nationwide = 464 12.9% 11.9% 1.0%1.0821.7% 24.9% -3.2%0.87224•Minority & Low-Income Demographic FindingsBelow is a summary of the three alternative but complementary comparison approaches based on thesame minority and low-income populationdata: (a) itemized plant-by-plantbasis, (b) nationwide aggregation basis, and (c) state-by-state aggregation basis. For purpose of determining therelative degree by which either group livingnear the 495 plants may exceed their respective statewide population percentages,the percentagesare compared as a numerical ratio whereby a ratio of 1.00 indicates that the group population percentage living near a plant isequal to thestatewide average, a ratio greater than 1.00 indicates the grouppopulation percentage near the plant is higher than the statewide population, and aratio less than 1.00 indicates the group population isless than the respective statewide average.•General population findings:o464 plants (i.e., 94% of the 495 universe) for which year 2000 Census plant address ZCTA data are available are located in 47states.oThe plant address ZCTA population surrounding the 464 plants with ZCTA data is6.08 million, which is an average of 13,091surrounding population per plant.•Low-income population findings:o0.78 millionlow-income population surrounding the 464 plants represents12.9%of the 6.08 million total surroundingpopulations; this is higher than the11.9%national percentage.oState-by-state low-income population percentages surrounding these plants rangefrom 4.6% in HI to 26.5% in NM.oExtrapolated and aggregated across all 495 plants, 256 plants (52%) have surrounding populations which exceed their statewidebenchmark percentage of low-income population.oThe ratios of low-income population percentages surrounding these plants range from0.43 to 1.95, and the average of the ratioscompared to the national average ratio of the low-income population is 1.08.oApproximately 29 of the 47 states (62%) have higher percentages of low-income populations compared to their respectivestatewide benchmarks.oStates with the largest difference in low-income populations surrounding the plants compared to their statewide benchmarks are:1.Mississippi (26% vs. 16%)2.Alabama (25% vs. 15%)3.Illinois (18% vs. 11%)4.New Jersey (15% vs. 8%)5.Connecticut (15% vs. 8%)•Minority population findings:o1.32 millionminority population surroundingthe 464 plants represents21.7%of the 6.08 million total surrounding populations;this is lower than the24.9%national minority population.225oThe state-by-state range ofminority population percentages surrounding these plants ranges from1.3% in ME to 78.2% in HI.oExtrapolated and aggregated across all 495 plants, 138 plants (28%) have surrounding populations which exceed their statewidebenchmark minority percentage of population.oThe ratio of minority population percentages surrounding these plants range from 0.34 to 2.92, and the average of the ratioscompared to the national average ratioof the minoritypopulation is 0.87.oApproximately 24 of the 47 states (51.1%)have disproportionately high percentagesof minority populationswithin the plantaddress ZCTA area compared to the rest of the state.oStates with the largest difference in minority populations between the ZCTA where the plants are located compared to the rest ofthe state are as follows:1.Connecticut (45% vs. 18%)2.Arizona (44% vs. 25%)3.Oregon (39% vs. 13%)4.Tennessee (37% vs. 20%)5.Kansas (37% vs. 14%)•Plant level results:Using the plant-by-plant (i.e., itemized ZCTA) basis, 138 plants (28%) have surrounding minority populations which exceed theirstatewideminority benchmark percentages, whereas 357plants (72%) have minority populations below their statewide benchmarks, which represents aplant ZCTA ratio of 0.39 (i.e., 138/357). Because this ratio is 61% less than 1.00 (i.e., 1.00minus 0.39), this finding indicates that only arelatively small count of plants have surrounding minority population percentages which disproportionately exceed their statewide benchmarks.Also on a plant-by-plant ZCTA basis, 256 plants (52%) have surrounding low-income populations which exceedtheir respective statewidebenchmarks, whereas 239 plants (48%) havesurrounding low-income populations below their statewide benchmarks, which representsa plantZCTA ratio of 1.07 (i.e., 256/239). Because this ratio is only slightly (7%) above 1.00, it indicates that a slightly disproportionate count of plantshave 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 plants werecompared totheir respective statewide population benchmarks. From this, state ratios revealed that 24 ofthe 47 states (51%) have higherminoritypercentages, and 29 of the 47 states (62%) have higher low-income percentages surrounding the 495 plants, suggesting a slightlydisproportionatehigher minority surrounding population and a relatively large disproportionate, higherlow-income surrounding population. However, incomparison to the other two numerical comparisons, this state-by-state count approachdoes not include numerically-weighting ofstate plantcounts or state surrounding populations, which explains why this comparison method yieldsa different numerical result. This method illustrateshow population comparison results may besensitive to the comparison method.226•Nationwide results:Using the nationwide aggregation basis across all 495 plants in all 47 states where the plants are located, 6.08 million peoplelive in ZCTAsurrounding the plants, which include a sub-total of 1.32 million (21.7%) minority and a sub-total of 0.8 million (12.9%) low-income populationgroups. A comparison of these percentagesto the national benchmark averages acrossall states of 24.9% minority and 11.9% low-income,represents a minority ratio of 0.87 (i.e.,21.7%/24.9%) and a low-income ratio of1.08 (i.e., 12.9%/11.9%). These nationwide aggregate ratiosindicate a slightly lower disproportionate minority population surrounding the 495plants, and a slightly higher disproportionate low-incomepopulation surrounding the plants.Comparison of nationwide population sub-totals for all plantsfor each demographic group compared to theexpected value based on statewide averages, reveals that:o+18.9%additional low-income residents near the plants comparedto the expected low-incomepopulation based on statewideaverages (i.e., 783,062 low-income population for all 464 plantscompared to 658,336 expectedcount if based on statewideaverages.)o-5.8%less minority residents near the plantscompared to the expected minority population based on statewide averages (i.e.,1,317,896 minority population for all 464 plantscompared to 1,241,382 expected count ifbased on statewide averages).These three alternative comparisonsindicate that the current (baseline) environmental and humanhealth hazards and risks fromelectric utilityCCR disposal units, and the expected futurebenefits of the regulatory options, may have a disproportionately lower effect on minoritypopulations and may have a disproportionatelyhigher effect on low-income populations.•Other Potentially Affected Minority & Low-Income PopulationsThere are two other potentialdifferential effects of the regulatory options on two other population groups: (a) populations surrounding offsiteCCR landfills, and (b) populations within the customerservice areas of the 495 electric utility plants.oOffsite CCR LandfillsThe potential effect on offsite landfillsinvolves the RCRA Subtitle Cbased regulatory options whereby four different fractions of CCRgeneration may be required to be disposedin RCRA Subtitle C permitted landfills rather than in non-RCRA permitted waste landfills:•CCR fraction #1: Electric utility plants may switch the managementof CCR, in whole or in part,from current onsite disposal tooffsitecommercial RCRA-permitted hazardous waste landfills (56.8 million is disposed inonsite landfills, and 22.4 million isdisposed in onsite impoundments, totaling 79.2 million tons disposed onsite).•CCR fraction #2: Some or all of the CCR whichis currently disposed in offsite landfillsthat do not have RCRA Subtitle C permits mayalso switch to RCRA-permitted commercial hazardous wastelandfills if the current receiving landfills do not obtainRCRA Subtitle C permits (15.0 million tons is disposed offsite).227•CCR fraction #3: Annual CCR generation which is currently supplied for industrialbeneficial use applications could also switchtooffsite commercial RCRA Subtitle C permitted landfills if suchuse becomes curtailed in partor in whole from eitherstate government regulations or from market stigma (47.0 million tons is beneficially used).•CCR fraction #4: Future cleanup of CCR disposal unit failures (e.g., impoundment collapse) would require disposal in RCRA Subtitlepermitted waste landfills (the two CCRimpoundment release case studies inExhibit 4Aof this RIA represent a rangeof 0.25 million to 3.3 million tons per failure event).One or more of these four potential shifts of CCR disposal from current non-hazardous landfills to hazardous waste landfills, could have adisproportionate effect on populations surrounding these locations, and inparticular, minority andlow-income populations surroundingcommercial hazardous waste facilities, if current landfills operated by electric utility plants do not obtain future Subtitle Cpermits (Option 1).A recent (2007) study determined that minority and low-income populations disproportionately live near commercial hazardous wastefacilities, although the study included other types of commercial hazardous wastetreatment and disposal facilities in additionto commercialhazardous waste landfills.187An example of such potential EJ concerns is a 2009US national news item involving the decision made by theTennessee Valley Authority (TVA) to train transport 3 million tonsof the TVA’s (Kingston TN electricity plant) December 2008 CCRimpoundment collapse site cleanup waste, 350miles away to a landfill in a rural Alabama county which reportedly has about 70%minority(African American) and 33% low-income residents.188However, this example serves to illustrate that EJ concerns are not necessarilyconclusive or shared by all affected EJpopulations, as evidenced by the following remarks made to news reporters by the Alabama countygovernment officials and county residents:189“To county leaders, the train’s loads, whichwill total three million cubic yards of coalash from a massive spill at a power plantin east Tennessee last December [2008],are a tremendous financial windfall. A per-ton “host fee” that the landfill operatorspay the county will add more than $3 million to the county’s budget of about $4.5 million. The ash has created more than 30jobs for local residents in a county where the unemployment rate is 17 percent and a third of all households are below thepoverty line. A sign on the door of the landfill’s scale house says job applications are no longer being accepted — 1,000 weremore than enough. But some residents worry that their leaders are taking a short-term view, andthat their community has beentoo easily persuaded to take on a wealthier, whiter community’sproblem.... County leaders, who are mostly black, bristle ataccusations of environmental injustice, saying that the ash is perfectlysafe and that criticism hasbeen fostered by outsiders, oreven competitors who wanted the ash disposalcontract for themselves..... Bob Deacy,vice president of clean strategies and187Source: United Church of Christ, “Toxic Wastes and Race at Twenty 1987-2007”, March 2007. . This study evaluated and made findings on minority and low-incomepopulation data within a 1.8-mile radius “host neighborhood” of 413 commercial hazardous waste facilities,compared to “non-host” areas. The study(page x) found that“Host neighborhoods of commercialhazardous waste facilities are 56% people of color whereas non-host areas are 30% of color...Poverty rates in the host neighborhoodsare 1.5 times greater than non-host areas (18% vs. 12%).”188Source: Shaila Dewan, “Clash in Alabama Over Tennessee Coal Ash,” The New York Times, 30 Aug 2009 at http://www.nytimes.com/2009/08/30/us/30ash.html189Source: 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” athttp://www.wastebusinessjournal.com/news/wbj20090901D.htm228project development for the Tennessee Valley Authority, whose Kingston Fossil Plant was the siteof the ash spill that coveredalmost 300 acres of land and waterways, said Arrowhead [Alabama landfill] was chosen because it was reachable by traininstead of truck, because it underbid othersites and because, unlike closer landfills, it had the capacity to handle all the ash.”oElectricity Service Area CustomersA third potential effect of the regulatory options described in today’snotice is the priceof electricity supplied by some orall of the affected 495electric utility plants could increase to cover the cost of regulatory compliance.Thus customers in electric utility serviceareas couldexperience price increases, although the RIA estimates that future potential price increasescould be expected to be below 1% increase relativeto the $0.0900 per kilowatt hour national average price (February 2009) for all four customer sectors (i.e., residential, commercial, industrial,and transportation). The RIA for today’s action did not evaluate the customerservice area populations for the 495 plants.2297D. Child Population Statistics (Executive Order 13045)•Purpose of Child Population Data AnalysisUnder Executive Order (EO) 13045 of 21 April 1997, Federal Agenciesshall make it a high priority (a) to identify and assess environmentalhealth and safety risks that may disproportionately affect children, and (b) shall ensure that its policies, programs, activities, and standardsaddress disproportionate risks to children that result from environmental health or safety risks. Although the EO does not define children, theUS Census Bureau defines “children” as follows190:Children: The term "children"... are all persons under 18 years, excluding peoplewho maintain households, families, orsubfamilies as a reference person or spouse.The purpose of this section is not to evaluate children risks,but to evaluate whether disproportionate percentages of childrenlive near electricutility plants. This analysis involvesa 5-step process for comparing children population data for each electric utility plantlocation, to statewidechildren population data to identify whether children disproportionately reside in geographic areas where electric utility plants are located.•Collection of Child Demographic DataStep 1:Plant address 5-digit “Zip Code Tabulation Areas” (ZCTAs) formed the geographicbasis for this child population data collection.Because ZCTAs represent irregularly shapedgeographic areas, this ZCTA based data collection may be considered a “screening level”analysis. The US Bureau of Census usesover 33,000 ZCTAs for its Census counts ofpopulation and other demographic statisticsbasedon the US Postal Service’s over 42,000 nationwide ZCTAs.191Currently, there are no size restrictions limiting how large or small aZCTA can be in terms of either a minimum/maximum number of housing units or geographic area. Any particular ZCTA may be assmall as a few city blocks or may cover many square miles. Many ZCTAs are for villages, census-designated places, portions ofcities,or other entities that are not municipalities. The nationwide average ZCTA population is about 7,200 persons (i.e., (306.6 million mid2009 US population) / (42,500 ZCTAs)). Thenationwide average ZCTA area is about 83square miles (i.e., (3,536,278 square milestotal US land and water area) /(42,500 ZCTAs)), which is a land area equivalentto a 5-mile radial distance (i.e., ((83 squaremiles) /(3.1416))^0.5). In comparison, the radial area monitored for contamination in response to the December 2009 TVA Kingston TNelectric plant CCR spill is reportedly four miles,192and this average 5-mile ZCTA radial distance falls between the 1-mile to 15-mileradial distances used by EPA’s Superfund “Hazard Ranking System” (HRS)193to define affected populationsof sites having either (a)soil contamination only (1-mile), (b) groundwater and/or airbornecontamination (4-miles), or (c) surface water contamination (15-miles190The 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.html191Source: US Census Bureau ZIP Code Tabulation Area (ZCTA) Frequently Asked Questions.: Nationwide total ZCTA count is from the US Postal Service’s FAQwebsite at: http://zip4.usps.com/zip4/welcome.jsp192Source: 4 mile radial monitoring area reported by Waste & Recycling News, 13 Feb 2009; http://www.wasterecyclingnews.com/email.html?id=1234543579193More background information about EPA’s HRS is availableat http://www.epa.gov/superfund/programs/npl_hrs/hrsint.htm.230downstream). Using the Census search engine Factfinder (http:factfinder.census.gov/home/saff/main.html?_lang=en), EPA retrievedtotal population and people 18 and over for 464 (94%) of the 495 electric utility plants. For 42 plants (8%) there was no ZCTACensusdata because the plants did not have complete address data from DOE or because the Census search engine did not have data for theZCTA.Step 2: EPA collected 3-year (2005 to2007) average statewide percentages for people 18 and older data as displayed inExhibit 7Ibelow.Exhibit 7IState-by-State Data on ChildPopulations (2005-2007 Average)RowState% children in state1 AK 27.0%2 AL 24.4%3 AR 24.8%4 AZ 26.4%5 CA 25.9%6 CO 24.7%7 CT 23.7%8 DC 19.5%9 DE 23.9%10 FL 22.3%11 GA 26.5%12 HI 22.3%13 IA 23.9%14 ID 27.3%15 IL 25.1%16 IN 25.1%17 KS 25.2%18 KY 23.9%19 LA 25.4%20 MA 22.5%21 MD 24.4%22 ME 21.5%23 MI 24.6%24 MN 24.5%25 MO 24.4%26 MS 26.3%27 MT 23.2%28 NC 24.4%29 ND 22.5%30 NE 25.3%RowState% children in state31 NH 23.1%32 NJ 24.0%33 NM 25.6%34 NV 25.8%35 NY 23.2%36 OH 24.2%37 OK 24.9%38 OR 23.2%39 PA 22.6%40 RI 22.3%41 SC 24.2%42 SD 24.8%43 TN 24.1%44 TX 27.7%45 UT 30.9%46 VA 23.9%47 VT 21.6%48 WA 23.9%49 WI 23.8%50 WV 21.5%51 WY 24.0%Max (UT) 30.9%Min (DC) 19.5%Nationwide24.7%231•Comparison of Child Populations Living Near Electric Utility Plants to Statewide BenchmarksStep 3, Step 4 and Step 5 of this evaluation described below involved three complementary levels of data comparisons. All three comparisonsalso involved two complementary numerical comparisons, one based on calculating numerical percentages and the other based on calculatingnumerical ratios:1.Plant level: Plant-by-plant disaggregateddata comparison to statewide benchmarks2.State level: State-by-state aggregated plant data comparison to statewide benchmarks3.National level: National aggregated plantdata comparison to statewide benchmarksStep 3: On a plant-by-plant basis, EPA compared the plant ZCTA percentage children,to the respective statewide average percentage children.Step 4: For purpose of summary,EPA aggregated the plant level children populationcomparison data for each state as displayedinExhibit 7Jbelow. There are no data displayed for DC, ID, RI or VT becausethere are no coal-fired electricutility plants in those states.Appendix Oof this RIA presents the plant-by-plant Census data on which this Exhibit is based.Exhibit 7JState-by-State Child Population Datafor Coal-Fired Electric Utility PlantsGeneral Population DataChild Population DataItemCount ofplantuniqueZCTAdsStateCount of plantZCTAs whichhave Censuspopulation data2000 plantZCTAresidentpopulationChildpopulationcount (<18years) in plantZCTAsChildpopulationpercentagein plantZCTAsStatewidepercentagechildpopulationExpectedchildren count inplant ZCTAs ifbased on state %If plantZCTAchild% >statechildren%1 2 AK 2 18,552 5,188 27.96% 27.00% 5,009 22 9 AL 9 82,854 21,978 26.53% 24.40% 20,216 43 3 AR 3 11,786 3,359 28.50% 24.80% 2,923 34 6 AZ 6 34,941 11,526 32.99% 26.40% 9,224 55 5 CA 4 112,895 36,285 32.14% 25.90% 29,240 56 15 CO 15 214,095 49,190 22.98% 24.70% 52,881 117 2 CT 2 42,716 10,743 25.15% 23.70% 10,124 18 NA DC9 3 DE 3 46,925 11,169 23.80% 23.90% 11,215 110 14 FL 13 224,502 55,025 24.51% 22.30% 50,064 1111 9 GA 9 202,973 50,964 25.11% 26.50% 53,788 512 1 HI 1 25,054 8,158 32.56% 22.30% 5,587 113 17 IA 14 324,050 77,708 23.98% 23.90% 77,448 1514 NA ID232Exhibit 7JState-by-State Child Population Datafor Coal-Fired Electric Utility PlantsGeneral Population DataChild Population DataItemCount ofplantuniqueZCTAdsStateCount of plantZCTAs whichhave Censuspopulation data2000 plantZCTAresidentpopulationChildpopulationcount (<18years) in plantZCTAsChildpopulationpercentagein plantZCTAsStatewidepercentagechildpopulationExpectedchildren count inplant ZCTAs ifbased on state %If plantZCTAchild% >statechildren%15 25 IL 23 455,834 129,772 28.47% 25.10% 114,414 1416 19 IN 17 323,323 83,594 25.85% 25.10% 81,154 1417 7 KS 6 59,517 16,532 27.78% 25.20% 14,998 618 19 KY 17 255,033 63,012 24.71% 23.90% 60,953 1519 4 LA 4 30,381 8,617 28.36% 25.40% 7,717 420 4 MA 3 95,798 23,078 24.09% 22.50% 21,555 121 8 MD 7 101,141 23,529 23.26% 24.40% 24,678 522 1 ME 1 6,748 1,561 23.13% 21.50% 1,451 123 23 MI 20 383,284 94,994 24.78% 24.60% 94,288 1324 15 MN 15 187,012 46,208 24.71% 24.50% 45,818 525 19 MO 19 251,484 60,084 23.89% 24.40% 61,362 1226 4 MS 4 69,209 19,867 28.71% 26.30% 18,202 427 6 MT 5 53,209 14,115 26.53% 23.20% 12,344 528 19 NC 16 238,874 57,728 24.17% 24.40% 58,285 629 7 ND 5 27,087 7,411 27.36% 22.50% 6,095 430 6 NE 6 79,313 20,853 26.29% 25.30% 20,066 431 2 NH 2 53,302 10,713 20.10% 23.10% 12,313 032 6 NJ 6 119,286 29,806 24.99% 24.00% 28,629 433 4 NM 4 17,491 5,656 32.34% 25.60% 4,478 334 2 NV 2 8,471 1,827 21.57% 25.80% 2,186 135 13 NY 13 226,416 57,612 25.45% 23.20% 52,529 936 24 OH 23 391,705 101,253 25.85% 24.20% 94,793 1437 6 OK 6 30,357 8,513 28.04% 24.90% 7,559 638 1 OR 1 3,884 1,378 35.48% 23.20% 901 139 31 PA 28 167,254 36,581 21.87% 22.60% 37,799 1340 NA RI41 12 SC 12 222,414 60,391 27.15% 24.20% 53,824 1042 2 SD 2 30,508 7,510 24.62% 24.80% 7,566 143 8 TN 8 158,267 40,682 25.70% 24.10% 38,142 444 18 TX 17 98,402 27,471 27.92% 27.70% 27,257 745 6 UT 6 34,209 11,769 34.40% 30.90% 10,571 446 16 VA 15 220,800 55,824 25.28% 23.90% 52,771 1047 NA VT48 1 WA 1 21,842 5,514 25.24% 23.90% 5,220 149 15 WI 13 178,705 36,428 20.38% 23.80% 42,532 10233Exhibit 7JState-by-State Child Population Datafor Coal-Fired Electric Utility PlantsGeneral Population DataChild Population DataItemCount ofplantuniqueZCTAdsStateCount of plantZCTAs whichhave Censuspopulation data2000 plantZCTAresidentpopulationChildpopulationcount (<18years) in plantZCTAsChildpopulationpercentagein plantZCTAsStatewidepercentagechildpopulationExpectedchildren count inplant ZCTAs ifbased on state %If plantZCTAchild% >statechildren%50 16 WV 13 64,771 10,946 16.90% 21.50% 13,926 1051 9 WY 8 69,736 19,732 28.30% 24.00% 16,737 6Summary:Total 464 429 6,076,4101,541,85425.37% 24.70%1,480,8312914.1%Min= 16.90% 21.50%Max= 35.48% 30.90%Extrapolated to 495 plants =310Step 5: The percentage of children population surrounding the plant ZCTAs were compared to overall state percentages and thenationwide percentage of this sub-group population, by calculating ratios betweenthe plant ZCTA children populationscompared to statewide and nationwidepercentages of children population.Exhibit 7Kbelow displays the results.Exhibit 7KComparison of Child Population Data on a State-by-State BasisItemStatePlantsPercentage ofZCTAPopulationUnder 18Years OldStatewidePercentage ofChildren(Exhibit 7I)DifferenceRatio1 AK 2 28.0% 27.0% 1.0% 1.042 AL 9 26.5% 24.4% 2.1% 1.093 AR 3 28.5% 24.8% 3.7% 1.154 AZ 6 33.0% 26.4% 6.6% 1.255 CA 5 32.1% 25.9% 6.2% 1.246 CO 15 23.0% 24.7% -1.7% 0.937 CT 2 25.1% 23.7% 1.4% 1.068 DC NR NA NA NA NA9 DE 3 23.8% 23.9% -0.1% 1.0010 FL 14 24.5% 22.3% 2.2% 1.1011 GA 9 25.1% 26.5% -1.4% 0.9512 HI 1 32.6% 22.3% 10.3% 1.46234Exhibit 7KComparison of Child Population Data on a State-by-State BasisItemStatePlantsPercentage ofZCTAPopulationUnder 18Years OldStatewidePercentage ofChildren(Exhibit 7I)DifferenceRatio13 IA 17 24.0% 23.9% 0.1% 1.0014 ID NR NA NA NA NA15 IL 25 28.5% 25.1% 3.4% 1.1316 IN 19 25.9% 25.1% 0.8% 1.0317 KS 7 27.8% 25.2% 2.6% 1.1018 KY 19 24.7% 23.9% 0.8% 1.0319 LA 4 28.4% 25.4% 3.0% 1.1220 MA 4 24.1% 22.5% 1.6% 1.0721 MD 8 23.3% 24.4% -1.1% 0.9522 ME 1 23.1% 21.5% 1.6% 1.0823 MI 23 24.8% 24.6% 0.2% 1.0124 MN 15 24.7% 24.5% 0.2% 1.0125 MO 19 23.9% 24.4% -0.5% 0.9826 MS 4 28.7% 26.3% 2.4% 1.0927 MT 6 26.5% 23.2% 3.3% 1.1428 NC 19 24.2% 24.4% -0.2% 0.9929 ND 7 27.4% 22.5% 4.9% 1.2230 NE 6 26.3% 25.3% 1.0% 1.0431 NH 2 20.1% 23.1% -3.0% 0.8732 NJ 6 25.0% 24.0% 1.0% 1.0433 NM 4 32.3% 25.6% 6.7% 1.2634 NV 2 21.6% 25.8% -4.2% 0.8435 NY 13 25.4% 23.2% 2.2% 1.1036 OH 24 25.8% 24.2% 1.6% 1.0737 OK 6 28.0% 24.9% 3.1% 1.1338 OR 1 35.5% 23.2% 12.3% 1.5339 PA 31 21.9% 22.6% -0.7% 0.9740 RI NR NA NA NA NA41 SC 12 27.2% 24.2% 3.0% 1.1242 SD 2 24.6% 24.8% -0.2% 0.9943 TN 8 25.7% 24.1% 1.6% 1.0744 TX 18 27.9% 27.7% 0.2% 1.0145 UT 6 34.4% 30.9% 3.5% 1.1146 VA 16 25.3% 23.9% 1.4% 1.0647 VT NR NA NA NA NA48 WA 1 25.2% 23.9% 1.3% 1.06235Exhibit 7KComparison of Child Population Data on a State-by-State BasisItemStatePlantsPercentage ofZCTAPopulationUnder 18Years OldStatewidePercentage ofChildren(Exhibit 7I)DifferenceRatio49 WI 15 20.4% 23.8% -3.4% 0.8650 WV 16 16.9% 21.5% -4.6% 0.7951 WY 9 28.3% 24.0% 4.3% 1.18Min = 16.9% 19.5% -4.6% 0.79Max = 35.5% 30.9% 12.3% 1.53Nationwide = 464 25.4% 24.7% 0.7%1.03•Child Population Data FindingsBelow is a summary of the three alternative but complementarycomparison approaches based on the same children population data:(a) plantby-plant (i.e., itemized ZCTA) basis, (b) nationwide aggregation basis, and (c) state-by-state aggregation basis.For purpose of determining therelative degree by which children may exceed these statewide percentages, the percentages are compared as a numerical ratio whereby a ratioof 1.00 indicates that the childpopulation percentage living near a plant is equal to the statewide average, a ratio greater than 1.00 indicates thechild population percentage nearthe plant is higher than thestatewide population, and a ratioless than 1.00 indicates the child population isless than the respective statewide average.•General population findingso464 plants (i.e., 94% of the 495 universe) for which Censusplant address ZCTA dataare located in 47 states.oThe plant address ZCTA population surrounding these plantsis 6.08 million, which is an average of 13,091 surroundingpopulation per plant.•Child population findingsoThe sub-total number of children surrounding these 464 plantsis 1.54 million (i.e., 25.4% of 6.08 million). In comparison,the national average of the childpopulation in the US is 24.7%.oThe ratios of the children population percentages surrounding these plants rangefrom 0.79 to 1.53, and the average of theratios compared to the national averageratio of the low-income population is 1.03.o27 of the 47 states (57%) have disproportionately high percentages ofchildren within the plant address ZCTAs compared tothe statewide percentages.oStates with the largest difference in the children population between the ZCTAs where the plantsare located compared tothe statewide percentages are as follows:1.Oregon (36% vs. 23%)2362.Hawaii (33% vs. 22%)3.New Mexico (32% vs. 26%)4.Arizona (33% vs. 26%)5.California (32% vs. 26%)oA sub-total of 291 plants (63%) have surrounding children populations which exceed their respective statewide percentage.•Plant level results:Using the plant-by-plant (i.e. itemized ZCTA) basis, 310 plants(63%) have surrounding child populations which exceed their statewidechildren benchmark percentages, whereas 185 plants (37%) have children populations below their statewide benchmarks, which represents aplant ZCTA ratio of 1.68 (i.e., 310/185). Since this ratio ismuch greater than 1.00, this finding indicates that a highly disproportionate count ofplants 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 plantswere compared to their respectivestatewide population benchmarks. The state-by-state ratios revealed that approximately 27 of the 47 states (57%) have disproportionatepercentages of children within the plant address ZCTA comparedto the rest of the state suggesting a disproportionate surrounding childpopulation. However, in comparison to theother two numerical comparisons above, thisstate-by-state count approach does not includenumerically-weighting of state plant counts or state surrounding populations, which explains why this comparison method yieldsa differentnumerical result. This method illustrates how population comparison results maybe 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 peoplelive in ZCTAssurrounding the plants, which include a sub-total of 1.54 million children (25.4%). Comparison of this percentage to the national aggregatebenchmark across all states of 24.7% children yields a ratio of 1.03 (i.e., 25.4%/24.7%).This ratio indicates a slightly higher disproportionatechild population surrounding the 495 plants.Comparison of the nationwide child population sub-total for all plants reveals that+4.1%additional children reside near the plants, compared to theexpected child population if based on state averages (i.e., 1,541,854 children livingnear the 464 plants compared to1,480,831 expected children count).These three alternative comparisonsindicate that the current (baseline) environmental and human health hazards and risks fromelectric utilityCCR disposal units, and the expected futurebenefits of the regulatory options, may have a disproportionately higher effect onchildpopulations.2377E. Unfunded Mandates (UMRA) & Federalism Implications Analysis (Executive Order 13132)•UMRAAmong its other purposes and Federal agencyrulemaking requirements, Title II of the 1995Unfunded Mandates Reform Act (UMRA; 2U.S.C. 1531-1538), requires Federal agencies, unless otherwise prohibitedby law, to assess the effects of their regulatory actions on State,local, and tribal governments and on the private sector, to determine whether any proposed rulemaking:“...is likely to result in promulgation of anyrule that includes any Federal mandate thatmay result in the expenditure by State,local, and tribal governments, in the aggregate, or by the private sector, of$100 million or more in any one year.”Section 202 of UMRA requires Federal agencies which propose rules that are likelyto exceed this $100 million expenditure threshold on eitherthe private sector or on state/local/tribal governments, to prepare a “WrittenStatement” containing the following five components, and supplythe Written Statement to OMB as well assummarize it in the Federal Registernotice (aka “preamble”) for the proposed rule:1.Identification of the applicable authorizing Federal law2.Qualitative and quantitative assessment of the anticipated costs andbenefits of the rule including the costs and benefits to State, local,and tribal governments or the private sector, and an analysis of whether Federal resources may be available to pay these costs3.Estimates of future compliance costs and any disproportionatebudgetary effects4.Estimates of effects on the national economy such as productivity, economic growth, employment, job creation, internationalcompetitiveness5.Description and summary of agency’s priorconsultation with elected representatives ofthe affected State, local and tribal governments.Section 202 of UMRA allows Federal agenciesto prepare the “Written Statement “in conjunction with or as a part of any other statement oranalysis. Accordingly, the purpose of this section of the RIA isto determine whether the regulatory options evaluated in thisRIA exceed thisUMRA direct cost threshold.Findings: The private sector andthe state/local government sharesof direct compliance costs under each option are displayed below inExhibit 7L, which indicates that:Private sector cost test: All of the regulatory options areexpected to result in expenditures of $100 million or more in theaggregate for the private sector, in any one year (i.e., 139 companies and cooperatives of the total200 owner entities).State/local/tribalgovernment cost test: None of the regulatory options are expected to result in expenditures of $100million or more for State, local, and tribal governments inthe aggregate in any one year(there are 60 state/localgovernment owner entities identified inExhibit 7Mbelow, no known tribal owner entities, plus one Federal owner).According to the private sector test finding, EPA has prepared an “UMRA Written Statement” which is attached to this RIA asAppendix P.238•Federalism (Executive Order 13132)The 1999 Federalism Executive Order 13132 (Federal Register, Vol.64, No. 153, 10 Aug 1999) furthersthe policies of the 1995 UnfundedMandates Reform Act (UMRA) by establishing federalism principles, federalism policymaking criteria, and a state/local governmentconsultation process for the development of Federal regulations that have federalism implications. Federalism implications refers toregulations and other Federal policies and actions that have substantial directeffects on states, on the relationship betweenthe Federalgovernment and the states, or on the distribution of power and responsibilities among the various levels of government.For purpose of complying with the Section6 consultation process of EO13132, this section of the RIA evaluates whether the CCRregulatoryoptions may “impose substantial direct compliance costs” on state/local governments. As summarized inExhibit 7L, the proposed rule mightimpose four types of direct costs on the 60 state/local government ownerentities identified inExhibit 7Mbelow:•State/local government owned electric utility plants:1.Engineering control costs for CCR disposalunits located at electric utility plants ownedby state/local governments.2.Ancillary costs for CCR disposal units located at electric utility plants owned by state/local governments.3.Conversion to dry disposal costs for CCR disposal units located at electricity utility plants owned by state/local governments.•State government environmental agencies:4.Regulatory implementation, administration,and enforcement costs to RCRA-authorized state government programs/agencies.Consistent with the “direct cost”scope of EO 13132, not included inExhibit 7Lare potential indirect costs inthe form of potential lost annualrevenues to electricity plantsassociated with potential reductions in CCR sold by plants for beneficial use under the three Subtitle C options forwhich such an possible indirect effect is estimated in this RIA.EPA’s 2008 guidance194for compliance with EO 13132 describes two numerical methods(i.e., numerical tests) for evaluating whether an EPArule 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 $25 million or more1952.1% test: Annualized direct compliance costs faced by state/local governments is likely to equal or exceed 1% of their annual revenues*[* Note: Page 29 of “Attachment A: Guidance for Implementing the Federalism 1% Test” to EPA’s Nov 2008 “Guidance on ExecutiveOrder 13132: Federalism” defines small government “general revenue” as “made up of intergovernmental revenue plus revenue fromtheir own sources and excludes utility, liquor store and employee retirement revenue.” However, given that the CCR proposed ruleaffects electric utilityindustry, this RIA applies the “1%Test” in relation to only State/local government electric utility annual revenue.]194The two methods are from page 6 of “EPA’s Action Development Process -- Guidance on Executive Order 13132: Federalism,” OPEI Regulatory Development Series,Nov 2008, 62 pages at http://intranet.epa.gov/adplibrary/documents/federalismguide11-00-08.pdf195Although one of the stated purposes of EO 13132 in its first paragraph is “to further the policies of the 1995 Unfunded Mandates Reform Act (UMRA), EPA’s $25million annual direct cost trigger is 75% lower than the $100 million annual direct cost trigger prescribed in Section 202 of UMRA.239•Findings for UMRA Impact andFederalism Implication TestsBased on estimated regulatory costs onstate/local governments displayed inExhibit 4Bof this RIA for each regulatory option,Exhibit 7Lbelow displays whether the costs potentially exceed the UMRA and Federalism thresholds defined above.oUMRA finding: All options >$100 millionprivate sector test; all options <$100 million state/local government testoFederalism finding: All options >$25 million state/local government test; all options <1%state/local government testHowever, for consistency with the RFA/SBREFA small business impactanalysis presented in a separate section above in this RIA,this RIAestimates it is highly likely that the direct compliance costsunder each option may be passed-thru to electricity plant customers in the form ofhigher electricity prices. The feasibility of such a compliance cost pass-thruscenario is evaluated and confirmed by the information presentedin the RFA/SBREFA small businessimpact section of this RIA.Exhibit 7LUMRA and Federalism Tests for CCR Disposal Regulatory Options($millions average annualized costs @7% discount rate over 50-years 2012 to 2061, 2009$)Type of Direct Compliance CostSubtitle CHazardous wasteSubtitle D(version 1)Subtitle C for impoundmentsSubtitle D for landfillsAverage annualized cost (source:Exhibit 5F):$2,274$492$2,176UMRA Test:1. Private sector $100 million direct cost threshold test $1,999.4 $415.3 $1,908.82. State/local government $100 million direct cost threshold test* $96.7 $55.9 $91.6Federalism Test:1. $25 million threshold test: sub-total State/Local govt cost $96.7 $55.9 $91.62. 1% Test: State/local govt cost as percentage of State/Localgovernment electric utility annual revenues0.227% 0.131% 0.215%* Note:Remainder Federal government costs represent costs associated with Federally-owned electric utility plants (i.e., Tennessee Valley Authority) which are notsubject to either the UMRA or Federalism tests. Therefore, the sub-total private sector direct cost plus the state/local government direct cost does not add-upto the total annual cost estimate under each option; the remainder cost is for the Federally-owned plants.240Exhibit 7MList of 74 Coal-Fired Electric Utility Generation Plants Which EPA Estimates Are Owned by 60 State/Local GovernmentsSource: Compiled by EPA-OSWER-ORCR based on 2007 datafrom the US Energy Information Administration*ItemOwner Entity NameElectric Utility Plant NameStateOwner EntitySize/Type**1 Grand River Dam Authority GRDA OK Non-Small State2 Lower Colorado River Authority Fayette Power Project TX Non-Small State3 Nebraska Public Power District Gerald Gentleman NE Non-Small State4 Nebraska Public Power District Sheldon NE Non-Small State5 Omaha Public Power District Nebraska City NE Non-Small State6 Omaha Public Power DistrictNorth Omaha NE Non-Small State7 Platte River Power Authority Rawhide CO Non-Small State8 Salt River Project Coronado AZ Non-Small State9 Salt River Project Navajo AZ Non-Small State10 South Carolina Pub Service Auth Cross SC Non-Small State11 South Carolina Pub Service Auth Dolphus M Grainger SC Non-Small State12 South Carolina Pub Service Auth Jefferies SC Non-Small State13 South Carolina Pub Service Auth Winyah SC Non-Small State14 American Municipal Power-Ohio, Inc Richard Gorsuch OH Non-Small City15 Ames City of Ames Electric Services Power Plant IA Non-Small City16 City of Columbia Columbia MO Non-Small City17 City of Hamilton Hamilton OH Non-Small City18 City of Lakeland C D McIntosh Jr FL Non-Small City19 City of Owensboro Elmer Smith KY Non-Small City20 City of Springfield Dallman IL Non-Small City21 City of Springfield Lakeside IL Non-Small City22 City Utilities of Springfield James River Power Station MO Non-Small City23 City Utilities of Springfield Southwest Power Station MO Non-Small City24 Colorado Springs City of Martin Drake CO Non-Small City25 Colorado Springs City of Ray D Nixon CO Non-Small City26 Gainesville Regional Utilities Deerhaven Generating Station FL Non-Small City27 Independence City of Blue Valley MO Non-Small City28 Independence City of Missouri City MO Non-Small City29 JEA Northside Generating Station FL Non-Small City30 JEA St Johns River Power Park FL Non-Small City31 Kansas City City of Nearman Creek KS Non-Small City32 Kansas City City of Quindaro KS Non-Small City33 Lansing Board of Water and Light Eckert Station MI Non-Small City34 Lansing Board of Water and Light Erickson Station MI Non-Small City35 Los Angeles City of Intermountain Power Project UT Non-Small City36 Orlando Utilities Comm Stanton Energy Center FL Non-Small City37 Rochester Public Utilities Silver Lake MN Non-Small City241Exhibit 7MList of 74 Coal-Fired Electric Utility Generation Plants Which EPA Estimates Are Owned by 60 State/Local GovernmentsSource: Compiled by EPA-OSWER-ORCR based on 2007 datafrom the US Energy Information Administration*ItemOwner Entity NameElectric Utility Plant NameStateOwner EntitySize/Type**38 San Antonio City of J K Spruce TX Non-Small City39 San Antonio City of J T Deely TX Non-Small City40 Vineland City of Howard Down NJ Non-Small City41 Crisp County Power Comm Crisp Plant GA Small - County42 Austin City of Austin Northeast MN Small City43 Board of Water Electric & Communications Muscatine Plant #1 IA Small City44 Cedar Falls Utilities Streeter Station IA Small City45 City of Dover Dover OH Small City46 City of Grand Haven J B Sims MI Small City47 City of Holland James De Young MI Small City48 City of Jasper Jasper 2 IN Small City49 City of Logansport Logansport IN Small City50 City of Marquette Shiras MI Small City51 City of Marshall Marshall MO Small City52 City of Menasha Menasha WI Small City53 City of Orrville Orrville OH Small City54 City of Painesville Painesville OH Small City55 City of Richmond Whitewater Valley IN Small City56 City of Shelby Shelby Municipal Light Plant OH Small City57 City of Sikeston Sikeston Power Station MO Small City58 City of Virginia Virginia MN Small City59 Crawfordsville Electric Light & Power Crawfordsville IN Small City60 Fremont City of Lon Wright NE Small City61 Grand Island City of Platte NE Small City62 Greenwood Utilities Commission Henderson MS Small City63 Hastings City of Whelan Energy Center NE Small City64 Henderson City Utility Commission Henderson I KY Small City65 Hibbing Public Utilities Commission Hibbing MN Small City66 Jamestown Board of Public Utilities S A Carlson NY Small City67 Manitowoc Public Utilities Manitowoc WI Small City68 Michigan South Central Power Agency Endicott Station MI Small City69 New Ulm Public Utilities Commission New Ulm MN Small City70 Pella City of Pella IA Small City71 Peru City of Peru IN Small City72 Texas Municipal Power Agency Gibbons Creek TX Small City73 Willmar Municipal Utils Commission Willmar MN Small City74 Wyandotte Municipal Service Commission Wyandotte MI Small City242Exhibit 7M (Continued)List of 74 Coal-Fired Electric Utility Generation Plants Which EPA Estimates Are Owned by 60 State/Local GovernmentsSource: Compiled by EPA-OSWER-ORCR based on 2007 datafrom the US Energy Information Administration*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 ORCRbased on business type disclosed in ownername or plant-by-plant internet researchontype of ownership. Size class determined according to the following numerical criteria consistent with EPA’s Nov 2006 guidanceforRegulatory Flexibility Act (RFA) Small Business Regulatory Enforcement FairnessAct (SBREFA) compliance:• Small non-government = Based on the US Small Business Administration NAICS code 221112 small business size standard of<4 million megawatt hours per year total annual electricity generation by all plants owned by the entity.• Non-small non-government = Entity’s total annual electricity generation >4 million megawatt hours per year.• Small government = Based on the RFA’s definition (5 US Code section 601(5)) of “small government jurisdiction” as thegovernment of a city, county, town, township, village, school district, or special district with a population less than 50,000.• Non-small government = Entity’s jurisdiction population with more than 50,000 people.