1OMB REVIEW DRAFTRegulatory Impact AnalysisFor EPA’s Proposed RegulationOf Coal Combustion ResiduesGenerated by the Electric Utility IndustryPrepared by:Mark Eads, Economist(703-308-8615;eads.mark@epa.gov)US Environmental Protection AgencyOffice of Resource Conservation & Recovery (ORCR)(formerly Office of Solid Waste)1200 Pennsylvania Avenue, NW (Mailstop 5305P)Washington DC, 20460 USA08 October 20092Table of ContentsAcknowledgements 4Executive Summary 5Chapter 1: Problem Statement 7Chapter 2: Potentially Affected Industrial Facilities & Waste Disposal Units 112A. Identity of Potentially Affected Industries 112B. Identity of Coal-Fired Electric Utility Plants 132C. Types of CCR Disposal Units 192D. Types of CCR Generated and Annual Quantities 222E. Size of CCR Disposal Units 27Chapter 3: Baseline CCR Management 283A. Cost of Baseline CCR Disposal 283B. Baseline Economic & Environmental Benefits of CCR Beneficial Use 51Chapter 4: Estimated Cost for RCRA Regulation of CCR Disposal 574A. EPA’s Prior Cost Estimates for Possible RCRA Regulation of CCR Disposal atElectric Utility Plants 574B. Regulatory Options Evaluated in this RIA 584C. Regulatory Cost Estimation Algorithms & Results 604C.1 Engineering Control Costs 614C.2 Ancillary Costs 654C.3 Sub-Option: Land Disposal Treatment Cost 75Chapter 5: Potential Distributional Effects 805A. Electricity Price Impact (Executive Order 13211) 805B. State-by-State Distribution ofRegulatory Costs 875C. Small Business Impact Analysis (RFA/SBREFA) 915D. Minority & Low-Income Population Statistics (Executive Order 12898) 995E. Child Population Statistics (Executive Order 13045) 1125F. Unfunded Mandates (UMRA) & Federalism Implications Analysis (Executive Order 13132) 120Chapter 6: Sensitivity Analyses 1266A. Alternative Discount Rates (0%, 3%, 7%) 1266B. Data Quality Uncertainty 1286C. Possible Impact on CCR Beneficial Uses 1316D. Price and Capacity Impacts on Commercial Hazardous Waste Landfills 1366E. Uncertainty in Land Disposal Treatment Sub-Option Cost Estimate 1386F. Other CCR Disposal Units Not Covered by the Proposed Rule 145Chapter 7: Potential Benefits ofCCR Disposal Regulation at Electric Utility Plants 1487A. Community Safety Benefits 1487B. Human Health Benefits 1617C. Ecological Benefits 1643Table of AppendicesNote: Because of its large number of pages (over 250), the Appendix is provided as a separate companion document to this RIA.Appendix A Chronology of EPA’s RegulatoryEvaluation of CCR (1978 to March 2009)Appendix B List of 495 Operating Electric Utility Plants Potentially Affectedby the CCR Rulemaking (2007)Appendix C Identity of 200 Entities Which Own the 495 Potentially Affected Electric Utility Plants (2007)Appendix D Baseline State Government Regulatory Requirements for CCR Disposal Units in Top-34 Coal Utility StatesAppendix E Baseline Engineering Controls Installed at CCR Disposal Unitsin the Electric Utility IndustryAppendix F Description of CCR Landfill & Surface Impoundment Engineering Control Cost ModelAppendix G Baseline Cost Estimates for CCRDisposal by the Electric Utility IndustryAppendix H Geological Conditionsat Electric Utility Industry CCR Disposal Unit LocationsAppendix I Incremental Regulatory CostEstimates for Compliance with theCCR Proposed Rule Regulatory OptionsAppendix J Electricity Price Impact Analysis Spreadsheet (Executive Order 13211)Appendix K Statement of Energy Effects (Executive Order 13211)Appendix L Small Entity Impact Data & Analysis Spreadsheet (RFA/SBREFA)Appendix M Minority & Low-Income Population Data (Executive Order 12898)Appendix N Child Population Data (Executive Order 13045)Appendix O UMRA Written StatementAppendix P List of Other Industries withCoal-Fired Electricity Plants Not Covered by the Proposed Rule or this RIAAppendix Q 1948-2008 US Historical Damage Cases Associated with Electric Utility Plant CCR Disposal Units4Acknowledgements•EPA Contractor Support & EPA Staff Assistance for this RIA•In 2009 under EPA contract EP-W-07-0011, work assignment 2-33, Industrial Economics Inc. (Cambridge MA) and its sub-contractorDPRA Inc (Minneapolis MN) provided support for estimating affected entities (Chapter 2), CCR disposal baseline engineering controlcosts (Chapter 3), and engineering control regulatory costs (Chapter 4)of this RIA.•EPA-ORCR Program Analysts RachelAlford, Christina Kager, and Cho-Yi Kwan helpedwith spreadsheets andmiscellaneous research.•Peer Review of this RIAAlthough RIAs do not normally require peer review according to EPA’s peer review guidance1, prior drafts of this RIA have been subject in2009 to three independent external reviewsoutside of ORCR, at least one of which(i.e., Economics Subgroup item 1 below) may beconsidered peer review. Peerreview is conducted by qualified individuals (or organizations) independent of those who performedthe work,and who are collectively equivalent in technical expertise (i.e., peers) to those whoperformed the original work. Peer reviewis an in-depthassessment of the assumptions, calculations, extrapolations,alternate interpretations, methodology, acceptance criteria, and conclusionspertaining to the specific major scientific and/or technical work productand of the documentation that supports them.1.Economics Subgroup: On 05 May 2009, ORCR convened an “Economics Subgroup2” in cooperation with EPA’s Office of Policy,Economics, and Innovation (OPEI). EPA established the Economics Subgroup process in May 2004, and it is required for all EPA“economically significant” rulemakings. All three prior (1988, 1999, 2005) EPA cost estimate studies of RCRA regulator optionsforCCR at electric utility plants indicated that the potential annualized compliance costs could begreater than the Executive Order 12866“economically significant” regulatory threshold of $100 million annual effect. The Subgroup consisted of six EPA employees: (1)Rachel Alford, Program Analyst, OSWER-ORCR-PMCAO-ERAS,(2). Mark Eads, Economist,OSWER-ORCR-PMCAO-ERAS, (3)Thomas Gillis, Economist, OA-OPEI-RAPD, (4) Robin Jenkins,Economist, OA-OPEI-NCEE-RPSD,(5) Kelly Maguire, Economist,OA-OPEI-NCEE-RPSD, and (6) Richard Mattick, OSWER-OAA-OPM.2.EPA-OPEI review: In Autumn 2009, ORCR provided the draft CCR proposed rule package including a draft of this RIA to EPA’sOffice of Policy, Economics & Innovation for reviewand comment prior to OMB-OIRA’s review.3.OMB review: OPEI provided the CCR proposed rule package including a draft of this RIA, to OMB-OIRAfor an abbreviated 60-dayreview (i.e., mid-Oct to mid-Dec 2009); 90-day reviews are specified under Executive Order 12866 (Section 6(b)(2)(B)).1EPA’s 2006 peer review guidance for RIAs states “Generally, if a RIA appliesaccepted, previously peer-reviewed methods in a straightforward manner, it would notundergo an additional peer review. RIAs prepared to support “major” or “economically significant” regulations typically do notutilize innovative or untried economicmethods. It is unnecessary toconduct peer reviews of straightforward applications or transfers of accepted, previously peer-reviewed economic methods or analyses. Theprocedures used to transfer or adapt an economic work product are generally established by separate economic guidance documentswhich have be peer reviewed.Therefore, RIAs that are developed using these procedures do notnormally undergo an additional peer review, even those prepared in support of “major” and“economically significant” rules. Source:Section 2.2.6 (page 35) of EPA Science Policy Council,“Peer Review Handbook”, 3rd Edition, document ID nr. EPA/100/B06/002, May 2006, http://www.epa.gov/peerreview/pdfs/Peer%20Review%20HandbookMay06.pdf.2EPA’s Economics Subgroup process is described at (a) EPA’sintranet: http://dchqdomino1.dcicc.epa.gov:9876/OA/OPEI/EconForumIntranet.nsf/pages/regreview.htmland (b) in Nov 2004 EPA Congressional testimony at http://www.epa.gov/ocir/hearings/testimony/108_2003_2004/2004_1117_slj.pdf5Executive Summary•Industrial Entities Potentially Affected by the RuleoElectric utility industry: The proposed rule establishes conditions for disposal of coalcombustion residues (CCR) and applies to an estimated (2007)495 coal-firedelectric utility plantsin NAICS 221112, located in 47 states. Non-utility coal-firedelectricity plants (e.g. operated by manufacturing industries,service industries,universities) are not included in the scope of the proposed rule.oWaste management industry: The rule may also affect industrial waste management companies (in NAICS 562211, 562212, 562219), and environmentalcleanup/remediation services industry (NAICS 562910)which offsite dispose or remediate CCR spills/releases.oIndustries which beneficially use CCR: At least14 industriesin the manufacturing, construction, agriculture, mining, and waste management sectors “beneficiallyuse” CCR for industrial applicationsas substitutes forother materials. Because all regulatory options maintain the 1980 RCRABevill exclusion for CCR beneficialuses, these industries are not expected to be impacted by theproposed rule. Potential indirecteffects could reduce future annual beneficial use by 4% to 42%.•Baseline CCR Disposal Practicesby the Electric Utility IndustryThe 495 electric utility plants generate an estimated141.2 million tons/year CCR(2005/2007 estimate) which is managed by either disposal or beneficial use:oDisposal: 94.2 million tons/year CCR disposed by 467 plants at a cost of$5.6 billion per yearusing one or more of three methods:1.311 plants use onsite landfills (56.8 million tons)2.158 plants use onsite surface impoundments (22.4 million tons)3.149 plants use offsite landfills (15.0 million tons)oBeneficial use: 47.0 million tons/year CCR from 272 plants used as material inputs by at least 14 industries, providing$24.6 billion/yearin national benefits:1.Economic benefits:$5.0 billion/yearenergy & water consumption savings, including $177 million/year CCR sales revenues to electricutility plants, and $2,300 million/year net cost savings for avoided purchase of higher price substitute materials by the 14 using industries2.Environmental benefits:$19.6 billion/yearin avoided air pollution emissions, including $365 million avoided greenhouse gas (GHG)emissions, plus 402 million tons/year avoided water pollution, and 25 million tons/year avoided solid waste generation.•Regulatory Options Evaluated in this RIAThis RIA evaluates the potential impacts ofthree optionsfor regulating CCR disposal, consisting of EPA’s preferred option identified in the proposed rule, plus twoalternative options. All options propose to replace the 1980 RCRA “Bevill exclusion” for CCR disposalwith new RCRA regulation, but retain the Bevill exclusion forCCR beneficial uses. Differences between the options are mainly their respective RCRA legal authoritiesand types of CCR disposal units affected.oOption 1: Subtitle C: (Preferred option). Regulate CCR disposal as RCRASubtitle C “K179 hazardous waste”, but with RCRA 3004(x) custom-tailoredengineering controls similar to EPA’s 1999 cement kiln dust (CKD) proposed rule, and with land disposal treatment standards (i.e., dewatering).oOption 2: Subtitle D: Regulate CCR disposal as RCRA Subtitle D “non-hazardouswaste” with the same engineering controls and treatment standards as 1.oOption 3: Hybrid C&D: Regulate wet CCR disposal (impoundments) under Option 1 and dry CCR disposal under Option 2.In addition to these options, the proposed rule presents two other approaches. One approach is the same as Option 2 but egregious violators would be regulated underOption 1. The second approach is the same as Option 2 in states which develop in 2-years an implementing program but the sameas Option 1 in all other states.Because both approaches are hybrids of Options 1 and 2, this RIA did not evaluatethem because their impacts would be expectedto fall between Options 1 and 2.•Potential Benefits of Proposed RCRA RegulationAlthough the 1976 RCRA statute does not require benefit-cost justification of RCRA regulations, this RIA presents a qualitativebenefit analysis for compliance withOMB’s 2003 “Circular A-4: Regulatory Analysis” best practices guidance. The expected benefits of RCRA regulation are reductionin future CCR disposal damagecases and associated damage costs to local community economies, human health, ecosystems, and the environment. Over the 61-year period 1948-2008 there have been66 confirmed damage cases involving CCR disposal units, an average frequency of1.1 cases per year. Based on incomplete economic damage data from those cases,and using the actual average per-acre cleanup cost from a 2008 damage case (TVA Kingston TN), indicates a minimum$117 to $152 millionper-year in baselineaverage annual damage costs. However, cleanup costs do not represent all damage cases or types of economic damages, so this isan underestimate of potential benefitsbecause it does not include costs for othereconomic damages: (1) local infrastructure(roadways, water supply, energy supply,sewerage, telecommunications), (2)business closures, (3) housing, community buildings (churches, schools), parks, (4) landscape aesthetic values, (5) human health, (6) ecosystems, (7) natural resources.6•Estimated Cost of RCRA Regulatory OptionsAs summarized in the Exhibit below, the potential nationwide cost of RCRA regulation ranges from$492 millionper year (Option 2 without the dewatering treatmentsub-option) to$2,274 millionper year (Option 1 with treatment) across the regulatory options.Summary of Annualized Cost Estimates for RCRA Regulation of CCR Disposal by the Electric Utility Industry($million average annual over 50-year period 2012-2061 @7% discount rate)Regulatory Compliance Cost ElementOption 1(Preferred option)RCRA Subtitle Chazardous wasteOption 2RCRA Subtitle Dnon-hazardous wasteOption 3Hybrid C & D:•RCRA Subtitle C for impoundments•RCRA Subtitle D for landfillsA. Regulatory Compliance Costs1. Engineering controls $491 $491 $4912. Ancillary costs $107 $1 $93. Sub-option: land disposal treatment dewatering $1,676 $1,676 $1,676Total cost without treatment (1+2) =$598 (+11%)*$492 (+9%)*$500 (+9%)*Total cost with treatment (1+2+3) =$2,274 (+41%)*$2,168 (+39%)*$2,176 (+39%)*B. Other Regulatory Costs Not Annualized in this RIA4. Added cost for cleanup of future CCR disposal unitfailures as RCRA Subtitle Chazardous remediation wasteAnnualized cost not est;$18 to $376 per eventNot applicableto this option ($0)Annualized cost not estimated;$18 to $376 per event5. Cost for RCRA Subtitle C facility-wide investigationsand facility-wide corrective actions if requiredAnnualized cost not est;$5.4 per caseNot applicableto this option ($0)Annualized cost not estimated;$5.4 per case* Percentages in this Summary Exhibit indicate increases in cost relative to the$5,556 millionper yearbaseline costfor non-regulated CCR disposal.•Regulatory Cost Estimation UncertaintiesThis RIA solely relied on secondary sources of information and data, many of which provided limited and uncertain information,requiring EPA to apply assumptions orrough estimation techniques for some numerical factors used in the cost calculations and associated numerical analyses of thisRIA. Five specific categories ofuncertainty factors identified in this RIA are:1.Data quality uncertainty: This factor includes uncertainty in data sources and data years regarding estimates of affected CCR tonnages and electricityplants.2.CCR beneficial use: Two countervailing uncertainty factors may constituteindirect effects of RCRA regulation of CCR disposal:oListing CCR as “hazardous waste” could create market stigma, state regulatory barriers, or regulatory compliance cost barrierswhich could reduce futurebeneficial use (e.g., non-encapsulated uses). Such reduction could increase economic demand and induce higher prices for substitute materials, effects notincluded in the cost estimates of this RIA.oOn the other hand, some electricity plants may minimize RCRA regulatory costs by increasing their supplies of future annual CCRquantities for beneficial uses.3.Landfill prices & capacity: Regulation of CCR as hazardous waste will require a nationalmix of (a) new RCRA Subtitle C permits for electricity plants,and (b)expansion of commercial hazardous waste landfill capacity. Short-term price hikes andcapacity constraints are not factored into the cost estimates in this RIA.4.Dewatering treatment: The cost estimate for this sub-option is based on extrapolation of an estimate developed by a single electric utility plant(TVA Kingston TN).Furthermore, plants recently or soon converting voluntarily todry disposal will reduce this regulatory cost. For example, TVAannounced in August 2009 aproposed plan to convert all 11 of its coal-fired electricity plants to dry disposalin absence of this regulation. If finalized, TVA’s plan could reduce the estimatedcost for this sub-option by roughly 7% (i.e., 11 of 495 plants).5.Incomplete cost elements: Because of lack of data or difficulty,this RIA did not formulate annualized costestimates for three regulatory elements: (a) CCRtank/container storage design and O&M requirements, (b) facility-wide corrective action, and (c) added cost for cleanup of future CCR disposal unit failures ashazardous remediation waste.7Chapter 1Problem StatementFor purpose of Federal rulemakings, the 1993 Executive Order 12866 “Regulatory Planning and Review” (Section 1(b)(1)) requireseachFederal regulatory agency to identify the problem that it intends to address, including where applicable, the failures of private markets or publicinstitutions that warrant new agency action, as well as to assess the significance ofthe problem. In line with this requirement, this chapterprovides a problem statement consisting of the institutional context (i.e., prior EPA actions), significance of the problem (i.e., evidence ofenvironmental damages), and characterization of market failure.1A. Institutional ContextThe EPA’s regulatory evaluation of coal combustion residues (CCR) dates back to 1978.In December 1978, the EPA proposed the firstindustrial hazardous waste regulations to implement Subtitle C (i.e., Sections 3001 to 3020) of the Resource Conservation and Recovery Act(RCRA). At that time, the EPA recognized that certain large-volume industrial wastes, includingwastes from the combustion offossil fuels(aka “CCR” as used in this RIA), might warrant special treatment under RCRA regulation. On18 December 1978, EPA proposed butdeferredand never finalized a relatively limited set of ten RCRA Subtitle C industrial hazardous waste regulations for the management of CCR.3Included in this deferral of hazardous waste requirements were six categories of industrial wastes --- which EPA termed “special wastes”4---until further study and assessment could be completed by EPA to determine their risk to human health and the environment. The six categoriesof 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 Bentsenand3Federal 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.4To learn more about these six “special wastes” see EPA’s special waste website at http://www.epa.gov/osw/nonhaz/industrial/special/index.htm8Bevill Amendments5which 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)):Exempted fossil fuel combustion waste;waste from the extraction, beneficiation,and processing of ores and minerals (including phosphate rock and overburden from uranium ore mining); and cement kiln dust.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.1B. Environmental DamagesA large environmental disaster associated with CCR occurred in 2008, which brought acute publicand Congressional attention onthis categoryof industrial wastes, resulting in a renewed call for EPA to complete its regulatory evaluation of CCR. On 22 December 2008, there was over abillion gallon (i.e., 5.4 million cubic yards) unintentional environmental release (spill) of fly ash sludge over 300 acres from a TennesseeValley Authority (TVA) coal-fired electricutility surface impoundment inKingston TN, causing significant damage to forty homes, a river andrecreational lake, roadways, gas pipeline, and a railroad, and attracting major citizen, national press, and Congressional interest in the subject ofCCR management and the urgent need for prevention of such future environmental damage.In the wake of this disaster, during her 14 January2009 Senate confirmation hearing, EPA Administrator-designate Lisa P. Jackson, testified6:“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,7there was growing Congressionalinterest for either the EPA with its existing RCRA regulatoryauthorities, or the Congress with potential new legislation, to regulate CCR disposal units:5These 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.asp6Lisa 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-d1962403eb767Source: Waste Business Journal, “EPA Vows to Act on Coal Waste,” 23 January 2009, http://www.wastebusinessjournal.com/news/wbj20090127B.htm9“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."”Just three weeks after the TVA’s Kingston Tennessee coal slurry impoundment disaster, House Natural Resources Committee Chairman NickRahall (D-WV) introduced legislation requiring federal standards toregulate the engineeringof coal ash impoundments.8Introduced on 14January 2009, the Coal Ash Reclamation and Environmental Safety Act of 2009 (H.R. 493) directs the Department of Interior to imposeuniform federal design, engineering, and performance standards on coal ash impoundmentsto avoid a repeat of the damage done inKingston.The legislation, which requires minimum design and stability standards for all surface impoundments constructed to hold coal ash, draws on theregulatory model for impoundments that is used for coal slurrymanagement under the Surface Mining Control and Reclamation Actof 1977(SMCRA).In a letter9dated 02 March 2009, the Environmental Integrity Project and Earthjustice, joined bythe National Resources Defense Council, 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.”10On 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.118Background information about the H.R. 493 legislation is available at:http://resourcescommittee.house.gov/index.php?option=com_content&task=view&id=439&Itemid=27The text of the 14 January 2009 H.R. 493 bill is available at: http://www.govtrack.us/congress/billtext.xpd?bill=h111-4939The 14-page letter is available at: http://www.environmentalintegrity.org/pubs/CCR%20Regulation%20Letter%20to%20EPA%20Administrator%20Lisa%20Jackson2.pdf10Source: http://www.environmentalintegrity.org/pub608.cfm11US Senate Resolution 64 is available at: http://www.govtrack.us/congress/bill.xpd?bill=sr111-64&tab=committees101C. 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 marketfailure: (1) externality, common property resource and public good, (2) market power, and (3) inadequateor asymmetric information. The CCR proposed rule which this RIA supports may be characterizedas addressing the “negative externality” ofenvironmental pollution and damages from CCRdisposal landfills and impoundments. As summarized in the “Benefits” chapter of this RIA,there are a number of historical and recentenvironmental damage cases which represent externalities in that some or all of thehuman healthand environmental costs may be external to the electric utilityplants (e.g., adverse health effect costs incurred by residentsin communitiessurrounding the plants). If implemented, theCCR proposed rule may be expected to reduce this market failure externality, by internalizing thecosts of improving and monitoring the physicalintegrity of CCR disposal units, in thecapital and operating costs incurred bythe electric plantsthemselves.11Chapter 2Potentially Affected Industrial Facilities & Waste Disposal Units2A. 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.12In 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’s North AmericanIndustrial Classification System” NAICS code 22 “Utilities” economic sector, andin that sector, as a subgroup of the 1,245 establishmentswithin the NAICS 221112 “Fossil FuelElectric Power Generation” industry:13NAICS 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 the Energy InformationAdministration (EIA) categorizationsystem for its coal combustion electric power sector statistics:14Electric 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.12Source: “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.pdf13Source: NAICS codes are defined at http://www.census.gov/cgi-bin/sssd/naics/naicsrch?chart=200714Source: EIA glossary of terms at http://www.eia.doe.gov/glossary/index.html12Independent 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.2.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 landfillsto which some or all of the estimated149 of the 495 electric utility plants may transport some or all of the 15 million tons per year CCR for offsitedisposal).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)15as of 2007 there are over 15 industries which “beneficially use” CCR forindustrial applications.These industrial applications arelisted below with corresponding NAICS16codes 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 Construction15Source: 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.pdf16NAICS = 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 industries134. 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 Mining11. 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. 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”.17This RIAapplied three database filters to identify the subset of electricity plantswhich may potentially be affected by the proposed rule:•Database filter #1 of 3: Sorted the 2007 EIA-860 electricplant 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/or17The 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 EIA-860 data can be downloadedonline athttp://www.eia.doe.gov/cneaf/electricity/page/eia860.html. The DOE spreadsheet “existingunits2007” is available athttp://www.eia.doe.gov/cneaf/electricity/page/capacity/capacity.html.14distribution; 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 wastematerials; 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: Deleted all of the unitsthat did not use coal as either a primary or secondary energy source usingthe coal type codes displayed inExhibit 2Abelow. In addition to these five categories of coal, examples of other primary orsecondary energy sources reported by coal burning electric utility plantsare agriculture byproducts,distillate fuel oil, naturalgas, petroleum coke, propane, and wood & waste solids.Exhibit 2ATypes 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)18, 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.19Appendix Bpresents the list of 495 plants.2018OP = 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.19This RIA filtered out 11 out-of-service electricity plant identification codes: 508, 511, 996, 1732, 2341, 2468, 2529, 2531, 2908, 3419, and 55612.20In 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.pdf15For 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 2BandExhibit 2Cbelow, these 495 coal-fired electricutility plants are owned and operated by 200 entities which are listed inAppendix Cto 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 2007.21Exhibit 2BSummary 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.21Source: US Dept of Energy (DOE), Energy Information Administration (EIA) website at http://www.eia.doe.gov/cneaf/electricity/epa/epat2p2.html16Exhibit 2CState-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 117Exhibit 2CState-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 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 2Dbelow, 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 21plants18Exhibit 2DState-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 2DState-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.pdf192C. 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 the scope 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.22The 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 CCRdisposition data to the EIA-767 database.Schedule 3 of the EIA-767 database containsthe annual disposition of CCR in one ormore of thefollowing five forms of CCR management categories, according to annual tons disposed for each plant. EIA-767 does not containcounts ofCCR 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 site (this RIA assigns these tonnages as offsite commercial landfills)The 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 assumed to 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 beneficial uses. The total count of disposal methodsexceeds 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.22Source: The DOE-EIA Form 767 database is available for 5 years spanning 2001 to 2005 athttp://www.eia.doe.gov/cneaf/electricity/page/eia767.html. The EIA-767database includes annual data from organic-fueled or combustible renewable steam-electric plantswith a generator nameplate rating of 10 or more megawatts (MW)regardless of current ownership and/or operation. However, it contains annualtonnage CCR generation, CCR disposal, and CCR beneficial use data only for plants over100MW in size. The EIA terminated the EIA-767 database after year 2005. Beginning with calendar year 2007 data, two other surveys, the Form EIA-860 and the FormEIA-923, will collect most of the data formerly collected by FormEIA-767. No data will be collected for 2006. The followingweblink provides a crosswalk of the dataelements previously collected on the Form EIA-767 for 2005 withthe corresponding data elementsto be collected beginning withcalendar year 2007 on the Form EIA-860or the Form EIA-923: http://www.eia.doe.gov/cneaf/electricity/2008forms/consolidate.html20•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: Identified 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:onsite dug landfill, onsite pile landfill, or offsitelandfill. The cost model assignment was dependentupon the level of baseline engineering controlsassumed required by each plant’s state location and annual CCR disposal tonnage. The cost modelestimated 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-767database): 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.2323In 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”21•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)•116 plants Non-duplicativesub-total of these five offsite sub-categories33 plants: This estimate is based on the 132 electric utility 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:onsite dug landfill, onsite pile landfill, or offsite landfill. The cost model assignment was dependentupon the level of baseline engineering controlsassumed required by each plant’s state location andannual 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: ASTSWMOThe February-March 2009 ASTSWMO voluntary participation survey24of 42 states (which is incomplete coverage of the 47 states identified inthis RIA for the 495 coal-fired electric plants) estimates a total of 484 electric utility plant CCR disposal 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).· “Ash is recycled as a beneficial re-use product for flowable fill in the construction industry”24Source: 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.pdf22•Source #2 of 2: EPAIn March 2009 EPA sent letters25to 210 coal-fired electric plant facilities and owner companies in order to identify the location of CCRimpoundments and evaluate their structuralintegrity in the wake of the December 2008 CCR impoundment collapse and flooding atthe TVAKingston TN electricity plant. However, EPA mailed those letters under Comprehensive Emergency Response, Compensation and LiabilityAct (CERCLA) Section 104 authority, which prohibits the information collected from beingused for this RIA or other purposes not indicatedin CERCLA:“The authority of this subsection may be exercised only for the purposes of determining the needfor response, or choosing ortaking any response action under this subchapter, or otherwise enforcing the provisions of this subchapter.” (Source: CERCLASection 9604(e)(1) “Action Authorized”26)Although not used in this RIA other than for reference here, theresponses received to the March 2009 EPA letters resulted in identification of584 CCR impoundments units at electric utility plants. The letters did not collectinformation about CCR landfills272D. 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 type25Source: Additional information about these March 2009 EPA letters is available at http://www.epa.gov/osw/nonhaz/industrial/special/fossil/coalashletter.htm26CERCLA Section 9604 is available at http://frwebgate.access.gpo.gov/cgi-bin/usc.cgi?ACTION=BROWSE&TITLE=42USCC10327Source: EPA’s 584 CCR impoundment unit count is documented athttp://www.epa.gov/osw/nonhaz/industrial/special/fossil/surveys/faqs.htm#1823categories in the 2005 EIA 767 database. As estimated in this RIA and displayed below inExhibit 2G, the 495 electric utility plants generate141.2 million tonsof CCR.•>100 MW plants:Exhibit 2Ebelow 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., 337of the 495 electric plants).28112 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 report29“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 200530. However, the beneficial use estimate inExhibit 2Ebelow 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 2G), 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.•1 to 100 MW plants:Exhibit 2Fbelow 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. Plants between1 and 100 megawatts are not required toreport their disposal practices inthe 2005 EIA-767 database. Coal use andpercent ash content data from Schedule 4A of the 2005 EIA-767 database wereused to estimate ash generationquantities for 102 plants within this smaller size category. For 5 plants for which EIA-767 coal use data wereunavailable for 2005, coal use data from Schedule 4Aof the 2007 EIA-923 database were used to estimate CCR28In 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.29Source: 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=200830Source: 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.pdf24generation quantities for those 5 plants. FGDsludge generation data obtained from Schedule 831of the 2005 EIA767 database were used for 115 plants. Landfill (either on-site or off-site whicheveris more economical) is theassumed CCR disposal practice. No gypsum or other byproduct generation quantities were estimated. For plantsbetween 1 MW and 10 MW, ash generation quantities estimatedusing generator nameplatecapacity rating data fromthe 2007 DOE Form 860 database. This 1 MW to100 MW subtotal of 132 plants consists of:•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.31In 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.25Exhibit 2EAnnual CCR Disposition for NAICS 22Electric Utility Plants >100 MW Capacity (tons per year as of 2005)ABCDEF (A+...+E)ItemCCR 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 2FAnnual 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 2GAnnual CCR Disposition for NAICS22 Electric Utility Plants All Sizes (tons per year as of 2005)(Source:Exhibit 2F+Exhibit 2G)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%26Exhibit 2Hbelow 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 2HSummary 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.272E. 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:oDesigned as “combination fill landfills”3.8 million cubic yards capacity50% of the capacity excavated below grade40-year capacity (i.e., operating lifespan)32Per-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.oDesigned 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.32For 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.28Chapter 3Baseline CCR Management bythe Electric Utility IndustryThis chapter evaluates baseline (i.e., current) management of CCR by the electric utility industry. This baseline consists oftwo componentsdescribed in this chapter: CCR disposal and CCR beneficial use. This chapter firstpresents and evaluation of baseline designand technicaloperating conditions (i.e., “engineering controls” and “ancillary costs”) of CCR disposal units and an estimate of the associated costs to theelectric utility industry. A second section of this chapter characterizes baselineCCR beneficial use forCCR which is not disposed and anestimate of the associated net benefits to the national economy.3A. Cost of Baseline CCR DisposalThis chapter presents characterizing dataand estimates of the costs tothe electric utility industry and 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.Location/siting restrictions (6 types:water tables, floodplains, wetlands, faultareas, 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 disposal2912.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 disposalcosts 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.30The 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.oImpoundments: 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 CCR Disposal 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 Dof 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 placed within 50 feet of the unit. KSrecommends a minimum of one-down-gradient detection well every 500 feet.31•Monitoring Parameters:Two options for sampling include testing for chemical indicators and testing forRCRA 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 requireAppendix VIII constituent monitoring for impoundments [MO, PA, WV], and 10 states require RCRAAppendix 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 semiannual 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).323. 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.4. 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. Siting Restrictions (6 categories)State regulations for the top-25 coal usagestates (for electricity) were reviewed backin year 2000 for any siting restrictions. Theseregulations were not updated as part of this RIA. The following is a synopsis of state government siting restrictions on locating CCRsurface impoundments and landfills,according to six categories of siting restrictions (water table,floodplains, wetlands, fault areas, seismiczones, unstable karst terrain).33•7-1: Below the natural water table:oOf the 25 state regulations reviewed, fivestates have siting restrictions below the natural water table for surface impoundments: NC(4 feet above seasonal water table), ND (within aquifer), OK (ifless than 15 feet above ground-water table), WV (5 feet aboveground-water table), WY.oOf the 25 state regulations reviewed, eight states have sitingrestrictions 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:oOf the 25 state regulations reviewed, eightstates have siting restrictions in floodplains for surface impoundments: KS (underpermit),KY, MO (if closed with waste in place), NC, ND, OK (if dike not atleast 1 foot above 100-yearflood elevation), PA, WV.oOf the 25 state regulations reviewed, 20 states have siting 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, fivestates have siting restrictions in wetlandsfor surface impoundments: KY, MO (if closedwith waste in place), ND, PA, WV.oOf the 25 state regulations reviewed, 17 states that have siting 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 siting restrictions in fault areas for surface impoundments: MO (if closed withwaste in place), WV.oOf the 25 state regulations reviewed, seven states have sitingrestrictions in fault areas for landfills: AZ, CO, MO, OH, TN, WV andWI.•7-5: Seismic zones:oOf the 25 state regulations reviewed, two states have siting restrictions in seismicimpact areas for surface impoundments: includeMO (if closed with waste in place), WV.oOf the 25 state regulations reviewed, eightstates have siting restrictions in seismic impact areas for landfills: AZ, CO, IL,MO, OK (ifwithin 5 miles of epicenter of4.0 earthquakes), TN, WV, WI.•7-6: Karst areas:oOf the 25 state regulations reviewed, fivestates have siting 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 siting restrictions in unstableareas 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 (synthetic34cap), 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).9. 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 standardsNot evaluated in this RIA because of a lack of data about thebaseline count and conditions of CCR storage or treatment tanks,containers, andcontainment buildings atelectric utility plants•Industry Baseline CCR DisposalCharacterization FindingsAppendix Eof 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 currently comply with the engineering controls described in theChapter 4of this RIA forthe regulatory options).Exhibits 3A(for landfills) andExhibit 3A(for impoundments) below summarize the assignment of baselineconditions in this RIA for these 411 plants.35Exhibit 3ABaseline 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.36Exhibit 3BBaseline 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.37•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.33The cost model consists of two software components;Appendix Fto 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 theper-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 or33The 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 the Federal docket ID nr EPA-HQ-RCRA-2006-0796 for the CCR proposed ruleat:http://www.regulations.gov.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 1999.38impoundment 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: Based on relatively limited data, and/or olderdata (e.g., older than 2005), or meta-analysistransfer of results from other studies,or data from case studies, or based mostly on professional judgment assumptionsrather than data, for some of the major factors used in cost calculations.oScenario-based estimates: Applied in absence of data, case studies, orassumptions for purpose of illustrating potentiallower- and upper-bound costs (i.e., bounding estimates). EPA defines “scenarios” asqualitative projections of possiblefuture conditions based on variations inkey drivers of change, including social,technological, economic and institutionaldrivers. Scenario construction is a futures analysis method; as such, scenario-basedestimates do not strive to predict thefuture with absolute certainty, but to explore uncertainties, possible consequences, and possible outcomes.34•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.34“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.pdf39•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: Applied for calculating both net present value cost and average annualized cost for the engineering controlunit costsapplied in this RIA. Because both the annualized baseline cost and annualized incremental proposed rule costsestimated in this RIA consist of primarily (i.e., >95%) industry costrather than government cost, this RIA applies a 7%discount rate rather than a lower (e.g., 3%, 2%, 1% or 0%)discount rate to represent the opportunity cost of businesscapital investment and business expense financing (i.e., the average rate of return to corporate capital). This isconsistent with OMB’s 2003 Circular A-435(page 33) and 1992 Circular A-9436(page 8) which indicate that a 7%discount rate base-case should beused for regulatory analyses when regulation is expected 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, assumed tocontinue in the future by that plant.•Offsite disposal: If reported in baselineby any particular plant, assumed to continue in the future by that plant. Offsitedisposal landfillcost estimated under both baseline and regulatory options using the engineering control cost model. Truck operatingcost estimated separately outside of the model.•Existing unit closure: One set of years for the opening and closure of disposal units are assumed for each facility. If datafor initial year ofoperation were provided in the 1995 EPRIComanagement Survey, these data wereused. If the plant had more thanone 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 1990,352003 OMB Circular A-4: http://www.whitehouse.gov/omb/circulars_a004_a-4/361992 OMB Circular A-94: http://www.whitehouse.gov/omb/circulars_a094/40this 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, dug (i.e., combination landfill with 50% of wastebelow ground and 50% above ground), pile(i.e., 5 % of waste below ground and 95% above ground), or offsite isdetermined within the cost model. The cost for the most economical approach is assigned to that plant unlessavailable data specify otherwise.The choice is dependent upon on engineering control costs and the annual CCRdisposal rate.•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.41•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 to2-16) recommends a maximum of 150 feetspacing between down-gradient wells. EPA’s December 1980 SW-611Procedures Manual for Groundwater Monitoring 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 3Dbelow (row item 1) for baseline groundwater monitoring, by the count of electric utility plants estimated inExhibit 3A(row 1, column A) andExhibit 3B(row 1, column A)above to conduct that activity under state government requirements, yields an average annual per-plant (i.e., unitized) cost estimate of$64,000. In comparison, EPA’s most recent (2008) InformationCollection Request (ICR) No. 0959.13 “Ground-Water MonitoringRequirements” (renewal) for the RCRA Subtitle C 40 CFR 264.92and 265.92 TSDF “ground-water protection standard” provides an42estimate of $28,130 per year.37The $64,000 unitized cost for groundwater monitoring generated by the above assumptions applied in theengineering control cost model used for thisRIA is 2.3 times larger and more appropriate to this RIA because it reflects a larger number ofwells per-plant to monitor the groundwaterunder the larger sized CCR disposal units compared to the average sizes of other types ofindustrial waste disposal units.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 sheepsfoot rollers for regulatory scenarios including dustcontrols. A model cost assumption is thatfour passes are made by the roller in 6-inch lifts. Withthese 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 to37$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.pdf43assume 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 approximatelyfive 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 on trucks 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 estimatedby 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 the44road 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 mostcircumstances. 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,”45memorandum to George Garland, EPA, 30 April 1995. Additional supporting information obtained fromEPA “Estimating Costs for theEconomic Benefits of RCRA Noncompliance,” September 1997.7. Baseline siting/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 RIA46•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 LFs38o$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 3Cbelow.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 year38Source: 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.txt47Exhibit 3CSummary 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).13. 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.4814. 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:($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/year49•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:39(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) = $1.01 million per year16. Baseline enforcement inspectionNot estimated in this RIA.17. Baseline remediation of environmental releasesNot estimated in this RIA.39Source: Based on cost data from page 84 of January 2007 ASTSWMO report “State RCRA Subtitle CCore Hazardous Waste ManagementProgram ImplementationCosts Final Report” at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20Core%20Project.pdf50•Baseline CCR Disposal Cost Estimation ResultsExhibit 3Dbelow displays the average annualized costs for each of the baseline cost components, as well ason an average per-ton and perplant basis.Appendix Gprovides plant-by-plant and owner entity-by-entity estimates of baseline costs.Exhibit 3DIndustry Baseline Cost Estimates for CCR Disposalby Electric Utility Plants (Onsite + Offsite)($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. Siting/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 cost = $4,236 $1,320$5,556*Average 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)* Note: For purpose of validity check, in comparison to the baseline cost estimate in this Exhibit above, the 2005 DOE-EIA Form767 database (Schedule 3, Part B)indicates $5,890 million in annual capital and O&M cost reported by steam electric plants with nameplate capacity of 100 MW orgreater, including (a) $0.314 millionfor water pollution, (b) $0.193 million for solid waste, (c) $0.185 for other pollution, (d) $3,627 million capital expense forair pollution abatement, and (e) $1,546million for collection and disposal O&M costs for fly ash, bottom ash, and FGD. The $1,546 million is only 28% of the estimatein this Exhibit. However, the 2005DOE-EIA Form 767 cost data are associated with 179 coal-fired plants, which represent only 36% of the 495 coal-fired electric utility plants addressed by this RIA.513B. Baseline Economic & Environmental Benefits of CCR Beneficial UseAccording to CCR beneficial use market data compiled for year 200540as displayed below inExhibit 3E, and extrapolated in this RIA to 2009as displayed inExhibit 3Fbelow, 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 associated with baseline CCR beneficial use:1.Economic benefits: Baseline economic benefits are based on the entire annual tonnage of CCR beneficial use.2.Environmental benefits: Baseline environmental benefits are only based on the threecategories of encapsulated CCR beneficial uses(i.e., concrete, cement, and wallboard representing a sub-total of 58% of all CCR beneficial uses) which wereaddressed in a secondary study used as a reference inthis section of the RIA.The economic benefits estimated in this section are based on recentmarket prices. However, environmental benefits are based on a 2008study which applied a “lifecycle analysis” (LCA) methodology which involves estimating bothinternalized and externalized environmentalimpacts:“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 3Ebelow (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$2,477 million annual cost of substitute materials inthese 14 industrial applications (see Column I ofExhibit 3E).40Source: EPA Office of Solid Waste “Waste and Materials-Flow Benchmark Sector Report: Beneficial Use of Secondary Materials – Coal Combustion Products,” FinalReport, EPA report nr. 530-R-08-003, prepared by Industrial Economics Inc., 95 pages, 12 Feb 2008 at: http://www.epa.gov/osw/partnerships/c2p2/pubs/benuse07.pdf.The beneficial use market data cited in this source is summarizedfrom the American Coal Ash Association (ACAA) 2005 national survey of the electric utility industry.52Exhibit 3EEstimate of Annual Materials Cost Savings Benefit of CCR Generated by the Electric Utility Industry for Beneficial Use in Industrial ApplicationsABCDEF (C x E)GH (C x G)I (H – F)ItemIndustry Application2005 CCRbeneficial use(million tons)% of CCRbeneficial usemarketAverage marketprice paid electricplants*($/ton)Implied annual CCRsales revenues toelectric utility plantsAverage pricefor substitutematerial($/ton)Implied annualalternativematerials 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 Other 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)$1,8302009 updated estimates =62.09***$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.** Other minor uses include: (1) agricultural soil amendment forflue gas desulfurization gypsum, (2) road base foundation layer underlying pavements for bottom ash, (3)mine reclamation material as substitute for soil, (4) mineral filler in asphalt, (5) soil stabilizer, (6) snow and ice controlsubstitute for sand, and (7) mining.*** 2009 update estimated tonnage (Column C above) derived inExhibit 3Fof 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.53Exhibit 3FEstimate of 2009 CCR Beneficial Use Quantity (Short Tons)A. Actual Data:YearCCR Beneficial Use*(tons per year)% change% UseLinear Regression OutputActual = 2001 37,119,321 R-Squared 0.915Actual = 2002 45,523,256 22.6% 35% Standard Error 1,990,394Actual = 2003 46,384,405 1.9% 38% Observations 7Actual = 2004 49,089,818 5.8% 40%CoefficientsActual = 2005 49,612,541 1.1% 40% Intercept (5,487,554,786)Actual = 2006 54,203,170 9.3% 43% X Variable 2,762,393Actual = 2007 56,039,005 3.4% 43%* Source: Amer. Coal Ash Assoc http://acaa.affiniscape.com/displaycommon.cfm?an=1&subarticlenbr=3B. Trendline:YearRegression best fit% changeTrendline = 2001 39,994,500Trendline = 2002 42,756,900 6.9%Trendline = 2003 45,519,300 6.5%Trendline = 2004 48,281,600 6.1%Trendline = 2005 51,044,000 5.7%Trendline = 2006 53,806,400 5.4%Trendline = 2007 56,568,800 5.1%Trendline = 2008 59,331,200 4.9%Trendline = 200962,093,6004.7%Annual average growth rate =5.7%CCR Beneficial Use (2001-2009)30,000,00035,000,00040,000,00045,000,00050,000,00055,000,00060,000,00065,000,00070,000,0002001 2002 2003 2004 2005 2006 2007 2008 2009Year

Tons CCR Per YearACAA actual dataTrendline54Exhibit 3Gbelow presents a 2004 state-by-state summaryof annual quantity of CCR beneficially used.Exhibit 3GState-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%31 NH 141,000 57,000 40%ABCDEItemState2004 CCRgeneration(short tons)2004 CCRbeneficial use(short tons)% CCRusedbeneficially32 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 2004 athttp://www.acaausa.org/associations/8003/files/2004_CCP_Survey(9-9-05).pdf55•Environmental Benefits Associated with CCR Beneficial UseFrom a materials lifecycle analysis perspective, CCR beneficial use generates net environmental benefits. Based on a 2008 lifecycle study41oftwo 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 3H. 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.Exhibit 3HBaseline Environmental Benefits from Current Beneficial Use of CCRABCDE (C x D)ItemEnvironmental impact indicatorEstimated* annual environmental impactsavings for 47% of CCR beneficial use tonnage(47% = 23.2 million tons in 2005)Unit values** for monetizingenvironmental impacts(updated to 2009$)Monetization ofenvironmental impacts($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 gas emissions(carbon dioxide + methane)11.5 million metric tons CO2 equivalentemissions avoided$5.20 to $58.23 per metric ton(midpoint = $31.71 per metric ton)$60 to $670(m.p. = $365)4 CO – carbon monoxide 9,200 metric tons emissions avoided Not Monetized Not Monetized5 NOx – nitrous oxides 30,400 metric tons emissions avoided $10,255 per metric ton $3126 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 Unspecified 26,200 metric tons emissions avoided $486,312 per metric ton $12,7419 Hg - mercury 0.584 metric tons emissions avoided $186,067 per metric ton $0.1010 Pb - lead 0.656 metric tons emissions avoided $186,067 per metric ton $0.12Subtotal (3 to 10) = $19,323 to $19,933(m.p. = $19,628)C. Other Environmental Impact Savings11 Waterborne wastes 2,446 short tons waste generation avoided(SM + BOD + COD + Cu + Hg + Pb + Se)Not Monetized Not Monetized12 Non-hazardous waste 27,991 short tons waste generation avoided Not Monetized Not MonetizedTotal all impacts (1 to 12) =$24,292 to $24,902Midpoint = $24,597($1,060 per ton CCR)41Source: 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.pdf56Exhibit 3H (continued)Baseline Environmental Benefits from Current Beneficial Use of CCRNotes:* Column C: Environmental impact estimates displayed above in Column C are based on only two of the 14 beneficial use industrial applications (i.e., 15.0million tons per year fly ash CCR used in concrete, plus 8.2 million tons per year FGD CCR used in wallboard). These estimatesare fromExhibit 5-3 (page 5-6)of “Waste and Materials-Flow Benchmark Sector Report: Beneficial Use of Secondary Materials – Coal Combustion Products,” prepared by IndustrialEconomics Inc for the EPA Office of SolidWaste, 12 Feb 2008; available athttp://www.epa.gov/osw/partnerships/c2p2/pubs/benuse07.pdf. This 2008 referencereport does not provide environmental impact estimates for the other 12 beneficial use industrial applications.** Column D: Unit values applied for monetization are from the following sources:A.Row 1 & Row 2: 2007 values from Exhibit 5-3 (page 5-6) of the Industrial Economics Inc reference report. Unit values updated for this RIA from 2007 to2009 using NASA’s Gross Domestic Product Deflator Inflation Calculator athttp://cost.jsc.nasa.gov/inflateGDP.htmlB.Row 3: 2007 unit value range of $5 to $56 from the 2007 column of Table III.H.6-3, page 29617 of the EPA and DOT-NHTSA “Proposed Rulemaking toEstablish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards,” Federal Register, Volume 74, No.186, 28 Sept 2009. For this RIA the range was updated from 2007 to 2009 dollars using NASA’s Gross Domestic Product Deflator Inflation Calculator athttp://cost.jsc.nasa.gov/inflateGDP.htmlC.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 aTon of Air Pollution” by Neal Fann, Charles Fulcher and Bryan Hubbell, in Air Quality, Atmosphere & Health,Volume 2, No.3, Sept 2009, pages 169-176. The dollar values from this report were updated from 2006 to 2009 using NASA’s Gross Domestic Product Deflator InflationCalculator athttp://cost.jsc.nasa.gov/inflateGDP.htmlD.Rows 12-13: Waterbornewastes and non-hazardous waste werenot monetized in the Feb 2008 EPA/Industrial Economics Inc. reference report cited abovefor Column C.57Chapter 4Estimated Cost for RCRA Regulation of CCR Disposal4A. EPA’s Prior Cost Estimates forPossible RCRA Regulation of CCR Disposal at Electric Utility PlantsEPA’s Office of Solid Waste (OSW, which EPA renamed as the ORCR effective 18 January2009), 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 itemizedcosts: 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 correctiveaction. 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.584B. Regulatory Options Evaluated in this RIAThis RIA evaluates the potential impacts ofthree options(labeled in this RIA as Option 1, Option 2, Option 3) for regulating CCR disposal,consisting of EPA’s preferred option (i.e., Option 1 below) identified in the Federal Registernotice for the CCR proposed rule, plus twoalternative options (i.e., Option 2 and Option 3 below). These options were initiallyidentified in theEPA-OSWER 17 April 2009 “CoalCombustion Residue Regulation” early guidance/options selection briefing for EPA Administrator Lisa Jackson, and the “preferredoption”(i.e., Option 1) was selected in her 13July 2009 “Early Guidance/Options Selection”memo to EPA’s CCR rulemaking workgroup. In additionto these main options, this RIA evaluates the land disposal treatment standard as a sub-option potentially applicable to each main option.Evaluation of three regulatory options isconsistent with OMB’s 2003 “Circular A-4: Regulatory Analysis” best practices guidance for Federalagencies.42All regulatory options are identical in two ways:1.Beneficial use: All options propose to replace the 1980 RCRA “Bevill exclusion” under 40 CFR 261.4(b)(4) for CCR disposalwith newRCRA waste regulation, but to retain the existing Bevill exclusion for CCR beneficial uses. EPA Administrator Lisa Jackson’s 13 July2009 Early Guidance/Options Selection memo (item 2, page 2) stipulated that beneficial uses of CCR will retain the Bevill exclusionand will not be subject to any regulation, either under Subtitle C or Subtitle D.2.Engineering controls: All options propose the same set ofnine custom-tailored engineering controls(i.e., technical design andoperating standards) for CCR disposal units.a.For purpose of launching this RIA in March 2009, the waste disposal “managementstandards” described in EPA’s August 1999cement kiln dust (CKD) proposed rule43were used in absence of uniquely defined controls specific to CCR disposal units. Thiswas a reasonable starting point because the CKD management standards are similar or identicalto the technical standardsdefined in the CCR proposed rule.b.Existing CCR landfills and impoundments are assumed to be exempted (“grandfathered”) from the bottom liner and leachatecollection requirementsof these controls.c.Otherwise all engineeringcontrols apply to future newly constructed units.The main differences between the optionsare their respective RCRA legal authoritiesand types of CCR disposal units affected.Option 1: Subtitle C (Preferred Option):•Regulate CCR disposal as RCRA Subtitle C “K179” listed hazardous waste. Subtitle C provides Federalenforceability.42Page 16 of OMB’s 2003 Circular A-4 directs Federal agenciesto analyze at least three options: http://www.whitehouse.gov/omb/assets/omb/circulars/a004/a-4.pdf43EPA’s 20 August 1999 CKD proposed rule (Federal Register, 67 pages) is available athttp://www.epa.gov/osw/nonhaz/industrial/special/ckd/ckd/ckd-fr.pdf59•Use RCRA 3004(x) authority to custom-tailor engineering controls (i.e., technicalstandards) for CCR disposal units.The following excerpt from Use RCRA Section 3004(x)44authority to custom-tailorengineering controls (i.e.,technical standards) for CCR disposal units.Option 2: Subtitle D:•Regulate CCR disposal as RCRA Subtitle D non-hazardous waste based on thesame engineering controls and LDRtreatment standards as Option 1.•Except under RCRA Section 7003 substantialendangerment authority, this option isnot Federally enforceable becauseRCRA Subtitle D directs EPA only to assist state governments under Subtitle D.45Option 3: Hybrid C&D:•Regulate wet CCR disposal (impoundments) same asOption 1 and dry CCR disposal same as Option 2.Sub-option: Subject CCR to land disposal treatment standards prior to disposal:•Dry CCR (landfills): Moisture conditioning and compaction to attain 95% dry density value.•Wet CCR (impoundments): Dewatering and dry disposal within 5 yearsafter rule’s effective date.In addition to the above options, the Federal Registernotice for the proposed rule presents two other regulatory approaches formulated by EPAin August 2009. One of the approaches is the same as Option2 but egregious violators wouldbe regulated under Option 1, and the secondapproach is the same as Option 2 in stateswhich develop in 2-years an implementing program but the same as Option 1 in all other states.Because both approaches are hybrids of Option 1 and Option 2, theyare not separately evaluated inthis RIA because their impacts would beexpected to fall between the impacts of Option 1 and Option 2as estimated in this RIA.44The 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 primarily from the combustion of coal or other fossilfuels... 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) andsection 3005(j), in the case of landfillsor surface impoundments receiving such solidwaste, to take into account the specialcharacteristics of such wastes, the practicaldifficulties associated with implementation of such requirements, and site-specific characteristics, including but not limitedto the climate, geology, hydrology and soilchemistry at the site, so long as suchmodified requirements assure protection of human health and the environment.”45Section 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.”604C. 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 in Chapter 3 of this RIA) is consistent with OMB’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 treatmentstandard sub-option, based onmany of thesame unit cost data sources and the same framework (i.e., 2009 price level, 50-year period of analysis, etc.), identified in the prior chapter ofthis RIA for baseline cost estimation. According to three methodological groupings, this RIA estimates three categories of regulatory 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.Location/siting restrictions (6 types:water tables, floodplains, wetlands, faultareas, 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.B.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 & recordkeeping61C.Sub-option: Land disposal treatment standards – may beapplied to any of the regulatory options: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 guidance46for attempting to measure such other economic effects for purpose of UMRA economicanalysis compliance. Based onthe 2008 US GDP of $14.42 trillion,47the 0.25% to 0.5% threshold is equal to $36 billion to $72 billion.4C.1 Regulatory Cost to Industry for RCRA “Engineering Controls”This RIA assumes that that same set ofRCRA 3004(x) custom-tailored engineering 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 in Chapter 3 for estimation of baseline engineering controlcosts. Furthermore, this RIAassumes that the engineering control costs aresimilarly specified in EPA’s cementkiln dust 20 August 1999 proposed rule.48This assumption was required to launch this RIA in March2009 prior to the initial draft ofthe CCR proposed rule itself. This RIA assumes that liners and leachate collection systemsrequirements applyonly to future new CCR landfills and impoundments. Offsite disposal costs are assumed unaffected under all regulatory optionsbecause offsiteCCR disposal units are assumed to be commercially-owned units(i.e., owned by the waste management industry) and assumed currently incompliance with the custom-tailored engineering controls. For engineering controls added to existing units the costs are addedto the remainingyears of the lifespan ofthe landfill or impoundment.1. Regulatory groundwater monitoring costSame cost estimation formula applied abovein Chapter 3 for baseline cost estimation.2. Regulatory bottom liner costSame cost estimation formula applied abovein Chapter 3 for baseline cost estimation.46Source: Section 4.B(3) of OMB’s 31 March 1995 guidance for implementing the UMRA (http://www.whitehouse.gov/omb/memoranda_1998/#1995) state that “Wewould note that such macro-economic effects tend to be measurable, in nation-wide econometric models, only if the economic impact of the regulation reaches 0.25 percentto 0.5 percent of Gross Domestic Product. A regulation with asmaller aggregate effect is highly unlikely to have any measurable impact in macro-economic terms unless itis highly focuses on a particular geographic region or economic sector.”47Source: 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.html48Federal Register, Vol.64, No.161, 20 Aug 1999, pp.45632-45697.623. Regulatory leachate collection costSame cost estimation formula applied abovein Chapter 3 for baseline cost estimation.4. Regulatory fugitive dust control costSame cost estimation formula applied abovein Chapter 3 for baseline cost estimation.5. Regulatory financial assurance costSame cost estimation formula applied abovein Chapter 3 for baseline cost estimation.6. Regulatory closure costsSame cost estimation formula applied abovein Chapter 3 for baseline cost estimation.7. Regulatory siting/location 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 Siting RestrictionsTo estimate the potential cost of siting restrictions, this RIA conducted a GIS analysisto determine which facilities may be affected by sitingrestrictions. As summarized below, the GIS analysis was conducted for three of thesix possible site restrictions (i.e., usingthree GIS-baseddatasets pertaining to fault areas, seismic zones, and karst 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 siting/location restriction costs. Onthe other hand, the average per-plant cost of $4.1 million applied below forestimating the potential cost of this regulatory element is over five-times higher than the $0.75 million49cost per-plant cost estimated byanother study for siting restriction mitigation involving karst mitigation and floodplain/wetland mitigation; this probably overly offsets thepossible cost underestimation in thisRIA 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 Hof 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 restriction49Source: $0.75 million siting restriction mitigation cost for a single electric utility plant is from page 10 (slide number TVA-00007496) of “Kingston Fossil Plant DecisionMatrix: Pond or Peninsula?,” 27 Jan 2005 Plant Managers Conference Room at http://www.tva.gov/kingston/tdec/pdf/TVA-00007487.pdf633. 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.50This 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.51,52•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 plantssare 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.535. Seismic zone restrictions:To identify seismic zones, we used USGS National Seismic HazardMaps, which gives peak horizontal acceleration at different probabilities ofexceedance in 50 years.54To run the seismic impact zone analysis, we identifiedthose facilities, including their buffers, which overlap withthe seismic impact zones that have a 10%or greater probability of exceeding a maximum horizontal acceleration of 10% the forceof gravity(i.e., 0.10 g) in 250 years.55The USGS data we used gives probabilities of exceedanceover 50 years; thus we used a data layer presenting 2%probability of exceedance, and assumed that this equates to a 10% probability ofexceedance 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,"50US Geological Survey, 2006, “Quarternary Fault and Fold Database for the United States” at:http//earthquakes.usgs.gov/regional/qfaults. File used: fitarc.shp51RCRA 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)).52Faults 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.53The 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.54U.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.55We used this threshold for seismic impact zones to be consistent with that used in RCRA’s municipal solid waste landfill location restrictions (40 CFR 258.14(a)(b)(1)).64which provides national-scale data on karst coverage.56Four 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 Plants to Meet Siting RestrictionsAccording to the above findings for the three siting/location criteriaevaluated in this RIA (i.e., fault areas, seismic zones,karst zones), amaximum count of 177 plants could be affected (this is the upper-end of the affectedplant counts across the three siting evaluations). Thepotential cost to these plants of the siting restrictions is estimated in this RIAusing the cost to retro-fit existing CCR disposal units and toprotect new CCR disposal units with a berm (aka levee). A berm is a type of engineering measure which may serve to demonstratethatengineering measures have been incorporated into disposal unit design to mitigate the potential adverse impacts disposal unitsmay have on,or be caused by, these six siting 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.oImpoundment 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.57oLandfill 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 the landfill (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 equivalent56U.S. Geological Survey, 1984, “Engineeringaspects of karst,” from USGS website: http://pubs.usgs.gov/of/2004/1352. File used:karst.shp.57For purpose of comparison to the $4.3 million (per impoundment) and $3.9 million (per landfill) siting restriction mitigationcost 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.pdf65oNew 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 abovein Chapter 3 for baseline cost estimation.9. Regulatory post-closure monitoring costSame cost estimation formula applied abovein Chapter 3 for 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 utilityplants4C.2 Regulatory Ancillary 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.11. Regulatory offsite disposal costs (hazmat trucking, RCRA manifests, RCRA TSDF permits for offsite)This pertains to Option 1 only. Assume thatSubtitle C options add extra cost to (a) truck hauling to offsite disposal, and (b) all offsite landfillsmust become RCRA Subtitle C permitted. This cost estimate does notinclude taxes/trans-state government fees associated with off-sitedisposal.11a & 11b. added truck hauling cost (Option 1 only)Assumptions:•Affects the 12% (15 million tons per year) annual CCR generation currently trucked offsite to non-haz LFs (2005)•6 miles average one-way trucking distance to offsite LFs5858Source: 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•$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. Manifest cost: (1.25 million truckloads) x ($53 per manifest per load average cost from EPA 2007 ICR 801.15) = $66million 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 permits for all offsiteCCR landfills under Subtitle C (i.e., Option 1 and Option 3)Assumptions:•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:($44059average RCRA Part A permit application cost per-plant per-year) + ($68,96060average 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/year•State government average cost per waste disposal permit:Average cost for state government review of RCRASubtitle C permits consists of four activities:61(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):59$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.pdf60$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.pdf61Source: 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.pdf67•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:Assume that the residual 18% of the non-inspected plants requireinspection over the 82% baseline inspection coverage.The per-plant cost for inspections is estimated in the Chapter 3 baseline above.•Cost Calculation:Industry cost: ($10,829/year per facility) x (18% not inspected) x (495 plants) = $0.96 million per 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 landfills$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:68State government RFI review, approval,oversight average cost per RFI = $76,00062(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 cost not estimated in thisRIA because high degree of uncertainty. Through a process called correctiveaction, RCRA Subtitle C requires RCRA-regulatedfacilities to investigate and clean-up releases of hazardous wastes or constituents to theenvironment identified in the RCRA facility-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.63State government cost for corrective measures study & corrective action review, approval,oversight is $117,300 per case.64The purpose of aCMS is to develop and evaluate the corrective action alternative(s) and to recommendthe corrective measure(s) be taken at thefacility.65As of 2008 the RCRA corrective action universe is about 3,800 sites nationwide.66Relative 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. Thecorrective action remedies usually involve mitigating damages tosurface water and groundwater.The General Accountability Office (GAO)reported67that 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 $4.327 million corrective actioncost per-facility. Updated68to 2009$ 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 this62Source: Divided the $2,200,600 annual RFI cost to 10 state governments by the 29 annual RFIs from page 82 of the January 2007ASTSWMO report “State RCRASubtitle C Core Hazardous Waste Management Program Implementation Costs Final Report” at:http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20Core%20Project.pdf63Source: RACER unit cost reported on p.38 of EPA’s 2000 “UnitCost Compendium” , document ID nr. EPA-HQ-RCRA-2002-0031-0429 at: http://www.regulations.gov64Source: derived from cost data contained on page 83 of theASTSWMO “State RCRA Subtitle C Core Hazardous Waste Management Program Implementation CostsFinal Report”, January 2007at: http://www.astswmo.org/files/publications/hazardouswaste/Final%20Report%20-%20RCRA%20Subtitle%20C%20Core%20Project.pdf65Source: “Corrective Measures Study Scope of Work”, EPA Region 3 at: http://www.epa.gov/reg3wcmd/ca/pdf/CMSATTC.pdf66Source: 3,800 corrective action cases represents EPA’s “2020 Corrective Action Universe” as identified on EPA Hazardous WasteCorrective Action Facility Informationwebsite at: http://www.epa.gov/waste/hazard/correctiveaction/facility/index.htm#202067Source: page 1 of USGeneral Accountability Office (GAO),“Hazardous Waste: Progress Underthe Corrective Action Program is Limited, But New Initiatives MayAccelerate Cleanups,” report nr. GAO/RCED-98-3, October 1997; http://www.gao.gov/archive/1998/rc98003.pdf68Updated from 1996$ to 2009$ using the NASA “Gross Domestic Product Deflator Inflation Calculator” at http://cost.jsc.nasa.gov/inflateGDP.html69requirement 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 disposal units will need new Subtitle C hazardous waste disposal permits under Option 1 andOption 3 (impoundments only).o411 of the 495 total electric utility plantscurrently dispose onsite(84 of the 495 plants solely dispose CCR offsite).•Industry average cost per waste disposal permit:o($44069average RCRA Part A permit application cost per-plant per-year) + ($68,96070average 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(411 plants) x ($208,200 per permit) = $85.57 millionAmortized industry cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $6.2 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:71(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.oState Cost Calculation:(411 electricity plants dispose CCR onsite) x($58,200 per Subtitle C permit per year) = $23.9 millionAmortized state cost with a capital recovery factor of 0.07246 (@7% discount rate & 50-years) = $1.7 million/year•Total Subtitle C permit cost (industry+ state government) = $7.9 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”69$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.pdf70$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.pdf71Source: 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.pdf70o1.6% average annual enforcement inspectionfrequency based on dividing the 11,965 LQG “large quantity 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 4Ibelow.71Exhibit 4ITwo 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 event7218. 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 inspectionreporting, and item 13 RCRA facility-wide investigation (RFI) – include the cost of paperwork burden for thoseitems. In addition, certain features of the Subtitle C options of the proposed rulerequire four 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.72Applied 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 Paperwork 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 the K179 hazardous waste that is stored, treated, and/or disposed onsite, (2)descriptions oflocation, design, construction, operating methods, techniques, and practices for onsite K179 storage, treatment, and/or disposal, (3) contingencyplans for unanticipated damagesfrom K179 onsite storage, treatment and/or disposal, (4) maintaining qualifications of facilityownership, (5)maintaining continuity and financial responsibility of facility operation, and (6) personnel hazmat training. According to EPA’s most recent(2009) estimate the average per-facility paperwork burden is$27,350 per facility per year.73Applied to the 411 electric utility plants whichcurrently dispose onsite (i.e., 84 of the 495 plants solely dispose CCR offsite with other companies) yields an estimated costof $11.24 millionper year.oIndustry share of cost: (86%) x ($11.24 million/year) = $9.67 million/yearoState government share of cost: (14%)x ($11.24 million/year) = $1.57 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“RCRABiennial Report”). According to EPA’s most recent (2009) estimate, the average annualized per-facility response burden is $3,410 per year.74Extrapolated to 495 electric utility plants yields a cost estimate of$1.69 million per year.72$162 per year notification cost derived from EPA Information Collection Request (ICR) No. 0261.16 “Notification of Regulated Waste Activity (Renewal)”, FederalRegister, Vol.74, No.123, pages 31028-31029, 29 June2009; http://edocket.access.gpo.gov/2009/pdf/E9-15310.pdf73$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;http://edocket.access.gpo.gov/2009/pdf/E9-2467.pdf74$3,410 per facility per year average cost derived from EPA Information Collection Request (ICR) No. 0976.14 “2009 Hazardous Waste Report”, Federal Register,Vol.74, No.93, pages 22922-22924, 15 May 2009; http://edocket.access.gpo.gov/2009/pdf/E9-11410.pdf73oIndustry 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). The CCR propose rule proposes to add CCR listed as K179hazardous waste (i.e., Options 1, 3 and 4) to the CERCLA list ofhazardous substances and assign an RQ of one-pound, as well asallowing theuse of concentrations to determine RQthus resulting in a range of 1,294 pounds to 10,000,000 pounds for 12 chemicals. Using the total countof facilities (i.e., establishments) in the US manufacturing sector (NAICS 31, 32,33) plus the US waste management sector (NAICS 562) asrough indicators, there are 315,000industrial facilities in the US which may handle RQ-listed hazardous substances.75According to EPA’smost 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 facilities at an annual paperwork burden cost of $3.161 million.76Relative to this 300,000industrial facility universe,this annual count of RQ-reporting facilities represents an 8%fraction. Extrapolated to the 495electric utility plants yieldsa rough estimate of40 possible RQ reports per year,at a cost of $4,900 per year (i.e., (495 electric utility plants)x (8% RQ reports per year) x($122 per RQreport)).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 4Jbelow presents a summary of these “Ancillary Cost” elements numbered from 11 to 18.75315,000 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” athttp://www.census.gov/econ/census07/Not all manufacturing or waste management facilities necessarily handle hazardous substances so this is anover-estimate, but there are also other economic sectors (e.g.,mining, construction, utilities, transporters, and wholesalers), which handle hazardous substances not included in this facility count which offsets this over-estimate.76$122 per facility average cost derived from EPA Information Collection Request (ICR) No. 1049.11 “Notification of Episodic Releases of Oil and Hazardous Substances(Renewal); Federal Register, Vol.72, No.205, 24 Oct 2007, pp.60357-60358;http://edocket.access.gpo.gov/2007/pdf/E7-20934.pdf74Exhibit 4JSummary of “Ancillary Cost” Estimates Associated with RCRARegulation of CCR Disposal($millions averageannualized; 2009$)Ancillary Cost ElementApplicability toCCR Regulatory OptionsElectric UtilityIndustry CostState GovernmentRCRA-AuthorizedProgram CostRow TotalCost11. Ancillary offsite disposal costs Option1 $76.35 $0.63 $76.9812. Impoundment structural integrity inspections Option 1, Option 2, Option 3 $0.96 $0.054 $1.0113. RCRA facility-wide investigations (RFIs) Option 1, Option 3 $6.9 $0.7 $7.614. RCRA facility-wide corrective action Option 1, Option 3 Not estimated –historicalaverage cost =$5.4 million perfacilityNot estimated Not est.15. RCRA TSDF waste disposal permits Option 1, Option 3 $6.2 $1.7 $7.916. RCRA enforcement inspections Option 1, Option 3 $0 $0.063 $0.06317. Future disposal unit failure cleanupremediation as RCRA hazardous wasteOption 1, Option 3 Not est. – casestudy exampleNot est. – casestudy exampleNot est.18. EPA administrative reporting & recordkeeping18a. EPA regulated waste notification18b. RCRA TSDF general paperwork standards18c. RCRA haz waste biennial report18d. CERCLA RQ reportingOption 1, Option 3 Subtotal= $11.13$0.005$9.67$1.45$0.0042Subtotal= $1.81$0.0008$1.57$0.24$0.0007$12.94$0.0058$11.24$1.69$0.0049Column Totals by Option:Option 1 $101.5 $5.0$106.5Option 2 $0.96 $0.05$1.0Option 3* $8.04 $1.19$9.2* Option 3 costs for ancillary cost items 13, 14, 15, 16, 17, and 18 are proportioned only to the 158 plants with impoundmentsthat would beregulated under Subtitle C for this option,by the proportionate multiplier: (158 plants w/impoundments) / (495 total plants) =0.319754C.3 Sub-Option: Cost for the Land Disposal TreatmentStandard (i.e., dewatering CCR for dry disposal)As presented in the CCR proposed rule, thissub-option 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 Methods:Based 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.77Bottom 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 exampleinvolves a thickening tank, porousconveyor belt 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.783.Horizontal belt filters: According to a May 2009 technical paper79, 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 200980for 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 to77Source: March 2009 Basin Electric Power Cooperative examples at http://www.basinelectric.com/News_Center/Feature_Articles/Coal_ash_handling.html78Source: 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.pdf79Source: May 2009 horizontal belt filter technical paper byAlex Hohne at http://www.flyash.info/2009/036-hohne2009.pdf80Source: June 2009 Detroit Edison Monroe Power Plant example at http://www.headwaters.com/data/upimages/press/6.30.09MonroeAshRelease.pdf76collect 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.5.Integrated silo system: Integrated with precipitators, vacuum pumps and bag filter/receivers, as described in an engineering report81about 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 sub-option, because the first two studies are over 25-years old (1981 and 1985),and the 2009 study does not providesufficient details for verification of data and calculations. These three other studies are summarized in the“Sensitivity Analysis” Chapter of this RIA, as well as used toillustrate the magnitude of cost estimation uncertainty impliedby the otherstudies, compared to the estimate derived below in this section of the RIA.•Summary of 2005 TVA CCR Dry Disposal Cost Study•In August 2009 TVA announced a proposed plan to convert its wet 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.82Detailed 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.83The 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.8481Source: Dec 1997 NIPSC conversion report athttp://www.babcockpower.com/pdf/rst-145.pdf82Source: TVA news release “TVA Coal Combustion Products Remediation Plan Proposed”, 20 Aug 2009 http://www.tva.gov/news/releases/julsep09/ccprp_other.htm83Source: TVA 27 January 2005 plant managers conference slide presentation (25 pages) at:http://www.tva.gov/kingston/tdec/pdf/TVA-00007487.pdf. Wet disposal ispresented as “Option 1” and dry disposal is presented as “Option 2” in the TVA cost presentation. Additional details for the TVA cost estimates are available athttp://www.tva.gov/kingston/tdec/pdf/TVA-00007402.pdf84"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 (Source:http://www.tfhrc.gov/hnr20/recycle/waste/cfa52.htm). Conversion of this implied 1.4 to 3.0 range in fly ash specific gravities to tons-per-cubic-yard as follows:77•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 2Cof 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 ($43.7/ton per year conversion capitalcost) x (20 years capitalization period) x (1.174 price update multiplier85to 2009$ 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) = $1,676 million/yearExhibit 4Nbelow summarizes the above regulatory cost estimates on anincremental basis (i.e., withoutincluding the “Baseline Costs”estimated in Chapter 3 of this RIA).Exhibit 4Obelow summarizes the same regulatory costestimates sub-totaled(i.e., sub-aggregated)according to the nine different size/type categories of owner entities.Appendix Ipresents itemized plant-by-plant, incremental regulatorycosts estimates for theelectric utility plants.oLow-end: (1.4 g/cm3) / (0.000001 m3/cm3) x (0.764 m3/yd3) / (1000 g/kg) x (2.204 lbs/kg) / (2000 lbs/short ton) = 1.2 short tons per cubic yard.oHigh-end: (3.0 g/cm3) / (0.000001 m3/cm3) x (0.764 m3/yd3) / (1000 g/kg) x (2.204 lbs/kg) / (2000 lbs/short ton) = 2.5 short tons per cubic yard.851.174 price update multiplier represents 2009:to:2005 ratio in theEngineering-News Record Construction Cost Index: (8566 CCIfor July 2009) / (7297 CCI for 2005).78Exhibit 4NSummary of Regulatory Cost Estimates for RCRA Regulation of CCR Disposal by Electric Utility Plants($millions in 2009 price level; average annual amortized @7% discount rate over 50-year period 2012 to 2061)RCRA Regulatory Cost ElementOption 1(Preferred Option)Subtitle C hazardous wasteOption 2Subtitle Dnon-hazardous wasteOption 3Subtitle C for impoundmentsSubtitle D for landfillsA. 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. Siting/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 haz 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/records $13 Not relevant $4C. Sub-option: Land Disposal Treatment Standard$1,676$1,676$1,676TOTAL ANNUALIZED COSTS:Total cost w/out land disposal treatment (A+B) =Average cost per-ton (94.2 million tons disposed) =Average cost per-plant (467 disposing plants) =$598($6.35 per ton)($1.28 million per plant)$492($5.22 per ton)($1.05 million per plant)$500($5.31 per ton)($1.07 million per plant)Total cost with land disposal treatment (A+B+C) =Average cost per-ton (94.2 million tons disposed) =Average cost per-plant (467 disposing plants) =$2,274($24.14 per ton)($4.87 million per plant)$2,168($23.01 per ton)($4.64 million per plant)$2,176($23.10 per ton)($4.66 million per plant)79Exhibit 4OSummary of Regulatory Cost Estimates According to Electric Utility Plant Owner Entity Size/Type Category($millions in 2009 price level; average annual amortized @7% discount rate over 50-year period 2012 to 2061)Size/Type of Entity*Count of AllPlants inCategory***Option 1(Preferred Option)Subtitle C hazardous wasteOption 2Subtitle Dnon-hazardous wasteOption 3Subtitle C for impoundmentsSubtitle D for landfillsA. Without land disposal treatment sub-option:1. Non-Small City 27 plants $30.6 $27.1 $27.62. Non-Small Company 372 plants $460.8 $378.5 $384.73. Non-Small Coop 20 plants $37.5 $34.6 $35.14. Non-Small Federal 11 plants $23.4 $20.8 $21.25. Non-Small State** 13 plants $29.3 $27.1 $27.56. Small City 33 plants $2.0 $1.6 $1.67. 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***$598$492$500B. With land disposal treatment sub-option:1. Non-Small City 27 plants $46.9 $43.5 $43.92. Non-Small Company 372 plants $1,897.2 $1,815.0 $1,821.23. Non-Small Coop 20 plants $87.7 $84.8 $85.34. Non-Small Federal 11 plants $183.2 $180.7 $181.05. Non-Small State** 13 plants $41.6 $39.4 $39.86. Small City 33 plants $2.8 $2.5 $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$2,168$2,176Notes:* Size/Type classification methodology defined in Chapter 2 (Exhibit 2B) of this RIA.** State government costs include costs to (a) state government electric utility plants 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.80Chapter 5Potential Distributional EffectsThe purpose of this chapter is to addressOMB’s 2003 Circular A-4 “Regulatory Analysis” (page 14) requirement for RIAs to provide aseparate description of distributional effects for proposed regulations. OMB defines distributional effects as:“[T]he impact of a regulatory action acrossthe population and economy, divided up invarious ways (e.g., income groups, race, sex,industrial sector, geography).”This chapter presents six potential distributional effects for the estimated costs of the regulatory options within the scope of this RIA:A. Potential impact on electricity prices within electric utility plant customer service areas (Executive Order 13211)B. State-by-state distribution of average annualized costsC. Small business share of average annualized costs (RFA/SBREFA)D. Minority & low-income populations surrounding potentially affected electricutility plantsE. Child populations surrounding potentially affected electric utility plantsF. Unfunded Mandates (UMRA) & Federalismimplications analysis(Executive Order 13132)5A. Potential Impact on Electricity Prices (Executive Order 13211)The 2001 Executive Order 1321186“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-01-2787guidance 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:86The 18 May 2001 EO-13211 is available at: http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=2001_register&docid=fr22my01-133.pdf87OMB’s 13 July 2001 Memorandum M-01-27 is available at: http://www.whitehouse.gov/omb/memoranda_m01-27/81•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.•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 year88•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 5Abelow presents the findings of this energy price evaluation on a state-by-statebasis and in nationwide aggregate (i.e.,Exhibit 5A-1without the land disposal treatment sub-option,Exhibit 5A-2with the sub-option, andExhibit 5A-3summary). As displayed in the bottomrow ofExhibit 5A, none of the options have an expected nationwide average energy price increase >1%.Appendix Jpresents the plant-byplant calculation spreadsheet used for this electricity price impact analysis.88Source: 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.htm82Exhibit 5A-1State by State Breakoutof Average Electricity Price Increases Per OptionWithout Land Disposal Treatment Sub-OptionItemNumber ofPlantsStateMay 2009statewide averageelectricity price ($per kilowatt hour)Option 1Average PriceIncreaseOption 2Average PriceIncreaseOption 3Average PriceIncreaseAverage annualized cost (fromExhibit 4N) =$598$492$5001 2 AK $0.1518 1.30% 1.23% 1.25%2 10 AL $0.0856 0.205% 0.189% 0.192%3 3 AR $0.0762 0.238% 0.225% 0.228%4 6 AZ $0.1002 0.659% 0.622% 0.632%5 6 CA $0.1337 0.717% 0.676% 0.687%6 14 CO $0.0797 0.110% 0.006% 0.006%7 2 CT $0.1712 0.074% 0.000% 0.000%8 0 DC $0.13379 3 DE $0.1236 0.156% 0.127% 0.129%10 15 FL $0.1136 0.096% 0.077% 0.078%11 11 GA $0.0859 0.175% 0.163% 0.166%12 2 HI $0.1892 0.245% 0.171% 0.174%13 19 IA $0.0710 0.213% 0.198% 0.202%14 0 ID $0.060215 25 IL $0.0924 0.144% 0.099% 0.101%16 26 IN $0.0766 0.249% 0.207% 0.210%17 8 KS $0.0822 0.207% 0.190% 0.193%18 21 KY $0.0640 0.673% 0.593% 0.603%19 4 LA $0.0748 0.043% 0.040% 0.041%20 4 MA $0.1534 0.027% 0.000% 0.000%21 8 MD $0.1316 0.060% 0.017% 0.017%22 1 ME $0.1222 0.520% 0.346% 0.352%23 22 MI $0.0986 0.056% 0.052% 0.053%24 16 MN $0.0804 0.499% 0.471% 0.478%25 20 MO $0.0757 0.137% 0.116% 0.118%26 5 MS $0.0893 0.112% 0.106% 0.108%27 5 MT $0.0720 1.263% 1.193% 1.212%28 22 NC $0.0839 0.170% 0.148% 0.151%29 7 ND $0.0698 0.023% 0.012% 0.012%30 7 NE $0.0705 0.223% 0.206% 0.210%31 2 NH $0.1544 0.055% 0.004% 0.004%32 7 NJ $0.1421 0.118% 0.045% 0.045%33 3 NM $0.0769 0.788% 0.407% 0.414%34 2 NV $0.0960 0.548% 0.518% 0.526%83Exhibit 5A-1State by State Breakoutof Average Electricity Price Increases Per OptionWithout Land Disposal Treatment Sub-OptionItemNumber ofPlantsStateMay 2009statewide averageelectricity price ($per kilowatt hour)Option 1Average PriceIncreaseOption 2Average PriceIncreaseOption 3Average PriceIncrease35 13 NY $0.1543 0.024% 0.000% 0.000%36 26 OH $0.0930 0.169% 0.132% 0.134%37 6 OK $0.0698 0.121% 0.050% 0.051%38 1 OR $0.0751 0.212% 0.200% 0.204%39 34 PA $0.0960 0.270% 0.229% 0.232%40 0 RI $0.134341 14 SC $0.0826 0.038% 0.028% 0.028%42 2 SD $0.0742 0.098% 0.084% 0.086%43 7 TN $0.0860 0.013% 0.001% 0.001%44 19 TX $0.1019 0.074% 0.038% 0.039%45 6 UT $0.0690 0.355% 0.336% 0.341%46 16 VA $0.0916 0.137% 0.078% 0.079%47 0 VT $0.128248 1 WA $0.0684 0.000% 0.000% 0.000%49 17 WI $0.0918 0.067% 0.063% 0.064%50 16 WV $0.0668 0.687% 0.615% 0.625%51 9 WY $0.0602 0.365% 0.315% 0.320%Summary:Minimum = $0.0602 0.0000% 0.0000% 0.0000%Maximum = $0.1892 1.2982% 1.2259% 1.2459%Average = $0.0985 0.2709% 0.2259% 0.2296%Median = $0.0860 0.1691% 0.1316% 0.1337%Nationwide =$0.08840.209%0.172%0.175%84Exhibit 5A-2State by State Breakoutof Average Electricity Price Increases Per OptionWith Land Disposal Treatment Sub-OptionItemNumber ofPlantsStateMay 2009statewide averageelectricity price ($per kilowatt hour)Option 1Average PriceIncreaseOption 2Average PriceIncreaseOption 3Average PriceIncreaseAverage annualized cost (fromExhibit 4N) =$2,274$2,168$2,1761 2 AK $0.1518 1.30% 1.23% 1.25%2 10 AL $0.0856 1.43% 1.416% 1.419%3 3 AR $0.0762 0.293% 0.280% 0.283%4 6 AZ $0.1002 1.141% 1.103% 1.113%5 6 CA $0.1337 0.717% 0.676% 0.687%6 14 CO $0.0797 0.121% 0.017% 0.017%7 2 CT $0.1712 0.074% 0.000% 0.000%8 0 DC $0.13379 3 DE $0.1236 0.156% 0.127% 0.129%10 15 FL $0.1136 0.131% 0.112% 0.113%11 11 GA $0.0859 1.160% 1.149% 1.152%12 2 HI $0.1892 0.245% 0.171% 0.174%13 19 IA $0.0710 0.548% 0.534% 0.537%14 0 ID $0.060215 25 IL $0.0924 0.531% 0.486% 0.488%16 26 IN $0.0766 1.387% 1.345% 1.348%17 8 KS $0.0822 0.545% 0.529% 0.532%18 21 KY $0.0640 2.307% 2.227% 2.237%19 4 LA $0.0748 0.464% 0.462% 0.462%20 4 MA $0.1534 0.027% 0.000% 0.000%21 8 MD $0.1316 0.080% 0.037% 0.037%22 1 ME $0.1222 0.520% 0.346% 0.352%23 22 MI $0.0986 0.459% 0.454% 0.455%24 16 MN $0.0804 2.013% 1.985% 1.993%25 20 MO $0.0757 0.817% 0.796% 0.798%26 5 MS $0.0893 0.197% 0.191% 0.193%27 5 MT $0.0720 5.582% 5.512% 5.531%28 22 NC $0.0839 1.122% 1.100% 1.102%29 7 ND $0.0698 0.994% 0.982% 0.982%30 7 NE $0.0705 0.223% 0.206% 0.210%31 2 NH $0.1544 0.055% 0.004% 0.004%32 7 NJ $0.1421 0.118% 0.045% 0.045%33 3 NM $0.0769 2.103% 1.722% 1.729%34 2 NV $0.0960 0.548% 0.518% 0.526%85Exhibit 5A-2State by State Breakoutof Average Electricity Price Increases Per OptionWith Land Disposal Treatment Sub-OptionItemNumber ofPlantsStateMay 2009statewide averageelectricity price ($per kilowatt hour)Option 1Average PriceIncreaseOption 2Average PriceIncreaseOption 3Average PriceIncrease35 13 NY $0.1543 0.024% 0.000% 0.000%36 26 OH $0.0930 1.193% 1.155% 1.157%37 6 OK $0.0698 0.151% 0.080% 0.081%38 1 OR $0.0751 0.212% 0.200% 0.204%39 34 PA $0.0960 0.702% 0.661% 0.665%40 0 RI $0.134341 14 SC $0.0826 0.394% 0.384% 0.384%42 2 SD $0.0742 0.098% 0.084% 0.086%43 7 TN $0.0860 0.517% 0.504% 0.504%44 19 TX $0.1019 0.292% 0.255% 0.256%45 6 UT $0.0690 0.602% 0.583% 0.588%46 16 VA $0.0916 0.688% 0.628% 0.629%47 0 VT $0.128248 1 WA $0.0684 0.000% 0.000% 0.000%49 17 WI $0.0918 0.082% 0.077% 0.078%50 16 WV $0.0668 1.441% 1.369% 1.379%51 9 WY $0.0602 1.396% 1.346% 1.351%Summary:Minimum = $0.0602 0.0000% 0.0000% 0.0000%Maximum = $0.1892 5.5822% 5.5119% 5.5313%Average = $0.0985 0.7489% 0.7039% 0.7076%Median = $0.0860 0.5205% 0.4860% 0.4876%Nationwide =$0.08840.795%0.758%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).8989Source: 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.pdf86•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, assummarized inExhibit 5A-3below. Although none of the regulatory options exceed the 1% threshold ofEO 13211, because a number ofuncertainty factors listed in the SensitivityAnalysis Chapter of this RIA may increase the cost estimateupwards of 40% --- which could resultin a possible 100% regulatory cost pass-thruhigh-end estimate of x% (i.e., (0.795% for Option 1 with land disposal treatment)x (1.4) =1.113%), this RIA includes a “Statement of Energy Effect” (Appendix K), as required by Section 1 of EO 13211.Exhibit 5A-3Summary of Potential Future Increase inRetail Electricity Prices Charged byCoal-Fired Electric Utility PlantsRegulatory costestimate rangeOption 1(Preferred Option)Average priceincreaseOption 2Average priceincreaseOption 3Average priceincreaseLow-end from Exhibit 5A-1(without the land disposal treatment sub-option)0.209% 0.172% 0.175%High-end from Exhibit 5A-2(with the land disposal treatment sub-option)0.795% 0.758% 0.761%For actions likely to have a significantadverse energy effect, Section 2 of the EO13211 requires agencies to consider reasonable alternatives tothe action. Part 7 of OMB’s July 13, 2001 guidance (i.e., Memorandum M-01-27) for implementingEO 13211 lists seven examples ofalternatives, of which the fifth example “Alternative Levels of Stringency” is included in this RIA and the CCR proposed rule.The alternativeregulatory options and sub-option describedin this RIA represent alternative stringency levels of regulation, as evidenced bytheir terms andconditions, as well as the relatively broadrange in estimated industry and state/local government costs for each option. As displayed inExhibit 5A-3above, all options without the land disposal treatment sub-optionprovide less-stringentalternatives below the 1% threshold usedfor this evaluation, even with acost estimate uncertainty factorof +40% added (i.e., even ifthe average price increases forthe options aremultiplied by a high-end cost uncertainty factor of 1.40).875B. State-by-State Distribution ofIncremental CCR Regulatory CostsExhibit 5Bbelow summarizes the distributionof estimated regulatory costs on a state-by-state basisand by option (i.e.,Exhibit 5B-1forregulatory costs without the land disposal treatment sub-option, andExhibit 5B-2for costs with the sub-option). This state-by-state summaryis a simple apportionment of nationwide average annualized cost under each option according to state-by-state annual CCR tonnage generatedby the 495 coal-fired electric utility plants.Exhibit 5B-1State-by-State Distributionof Estimated Incremental Costs for Regulatory OptionsWithout Land Disposal Treatment Sub-Option($million average annualized cost in 2009$ over 50-year period of analysis 2012 to 2061)ABCDEFGHItemState# of coalfiredelectricityplants2005 CCRgeneration bycoal-firedelectric utilityplants (tons/year)State % ofnationwide CCRgeneration (basedon Column D)Option 1Subtitle Chazardous wasteOption 2Subtitle Dnon-hazardous wasteOption 3Subtitle C impoundmentsSubtitle D landfills1 AK 2 46,179 0.03% $0.2 $0.2 $0.22 AL 16 3,210,337 2.27% $15.7 $12.9 $13.13 AR 4 744,267 0.53% $3.0 $2.5 $2.54 AZ 8 3,334,030 2.36% $13.4 $11.0 $11.25 CA 6 159,927 0.11% $0.6 $0.5 $0.56 CO 12 1,704,433 1.21% $6.8 $5.6 $5.77 CT 0 172,280 0.12% $0.7 $0.6 $0.68 DC 0 0 0.00% $0.0 $0.0 $0.09 DE 2 251,205 0.18% $1.0 $0.8 $0.810 FL 15 6,132,345 4.34% $29.9 $24.6 $25.011 GA 13 6,077,700 4.30% $24.7 $20.3 $20.612 HI 1 58,968 0.04% $0.2 $0.2 $0.213 IA 15 1,136,289 0.80% $4.6 $3.8 $3.814 ID 0 0 0.00% $0.0 $0.0 $0.015 IL 17 3,856,748 2.73% $15.9 $13.1 $13.316 IN 33 8,798,845 6.23% $36.6 $30.1 $30.617 KS 8 1,495,099 1.06% $6.0 $4.9 $5.018 KY 31 9,197,567 6.51% $39.7 $32.6 $33.219 LA 3 1,614,800 1.14% $6.5 $5.3 $5.420 MA 0 363,150 0.26% $1.5 $1.2 $1.221 MD 4 1,932,740 1.37% $7.8 $6.4 $6.522 ME 1 48,000 0.03% $0.2 $0.2 $0.223 MI 24 2,369,673 1.68% $9.5 $7.8 $8.024 MN 20 1,525,979 1.08% $6.1 $5.0 $5.188Exhibit 5B-1State-by-State Distributionof Estimated Incremental Costs for Regulatory OptionsWithout Land Disposal Treatment Sub-Option($million average annualized cost in 2009$ over 50-year period of analysis 2012 to 2061)ABCDEFGHItemState# of coalfiredelectricityplants2005 CCRgeneration bycoal-firedelectric utilityplants (tons/year)State % ofnationwide CCRgeneration (basedon Column D)Option 1Subtitle Chazardous wasteOption 2Subtitle Dnon-hazardous wasteOption 3Subtitle C impoundmentsSubtitle D landfills25 MO 20 2,679,742 1.90% $10.8 $8.8 $9.026 MS 6 1,229,400 0.87% $4.9 $4.1 $4.127 MT 5 1,830,624 1.30% $7.3 $6.0 $6.128 NC 27 5,504,531 3.90% $22.8 $18.8 $19.129 ND 9 3,038,100 2.15% $12.2 $10.0 $10.230 NE 6 614,473 0.44% $2.5 $2.0 $2.131 NH 1 176,900 0.13% $0.7 $0.6 $0.632 NJ 2 735,214 0.52% $3.0 $2.4 $2.533 NM 4 3,983,300 2.82% $16.0 $13.2 $13.434 NV 2 391,500 0.28% $1.6 $1.3 $1.335 NY 11 1,479,792 1.05% $6.6 $5.4 $5.536 OH 24 10,429,446 7.39% $48.0 $39.5 $40.237 OK 3 1,490,800 1.06% $6.0 $4.9 $5.038 OR 1 99,900 0.07% $0.4 $0.3 $0.339 PA 28 15,359,680 10.88% $64.3 $52.9 $53.840 RI 0 0 0.00% $0.0 $0.0 $0.041 SC 14 2,178,360 1.54% $8.7 $7.2 $7.342 SD 2 103,753 0.07% $0.4 $0.3 $0.343 TN 12 3,240,120 2.29% $19.3 $15.9 $16.144 TX 18 13,165,728 9.32% $53.0 $43.6 $44.345 UT 7 2,582,144 1.83% $10.4 $8.5 $8.746 VA 13 2,388,526 1.69% $9.6 $7.9 $8.047 VT 0 0 0.00% $0.0 $0.0 $0.048 WA 1 1,405,220 1.00% $5.6 $4.6 $4.749 WI 12 1,412,534 1.00% $5.7 $4.7 $4.750 WV 20 9,231,718 6.54% $38.8 $31.9 $32.451 WY 12 2,224,848 1.58% $8.9 $7.3 $7.5Totals =495141.2 million100%$598$492$50089Exhibit 5B-2State-by-State Distributionof Estimated Incremental Costs for Regulatory OptionsWith Land Disposal Treatment Sub-Option($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)Option 1Subtitle Chazardous wasteOption 2Subtitle Dnon-hazardous wasteOption 3Subtitle C impoundmentsSubtitle D landfills1 AK 2 46,179 0.03% $0.7 $0.7 $0.72 AL 16 3,210,337 2.27% $51.7 $49.3 $49.53 AR 4 744,267 0.53% $12.0 $11.4 $11.54 AZ 8 3,334,030 2.36% $53.7 $51.2 $51.45 CA 6 159,927 0.11% $2.6 $2.5 $2.56 CO 12 1,704,433 1.21% $27.4 $26.2 $26.37 CT 0 172,280 0.12% $2.8 $2.6 $2.78 DC 0 0 0.00% $0.0 $0.0 $0.09 DE 2 251,205 0.18% $4.0 $3.9 $3.910 FL 15 6,132,345 4.34% $98.8 $94.2 $94.511 GA 13 6,077,700 4.30% $97.9 $93.3 $93.712 HI 1 58,968 0.04% $0.9 $0.9 $0.913 IA 15 1,136,289 0.80% $18.3 $17.4 $17.514 ID 0 0 0.00% $0.0 $0.0 $0.015 IL 17 3,856,748 2.73% $62.1 $59.2 $59.416 IN 33 8,798,845 6.23% $141.7 $135.1 $135.617 KS 8 1,495,099 1.06% $24.1 $23.0 $23.018 KY 31 9,197,567 6.51% $148.1 $141.2 $141.719 LA 3 1,614,800 1.14% $26.0 $24.8 $24.920 MA 0 363,150 0.26% $5.8 $5.6 $5.621 MD 4 1,932,740 1.37% $31.1 $29.7 $29.822 ME 1 48,000 0.03% $0.8 $0.7 $0.723 MI 24 2,369,673 1.68% $38.2 $36.4 $36.524 MN 20 1,525,979 1.08% $24.6 $23.4 $23.525 MO 20 2,679,742 1.90% $43.2 $41.1 $41.326 MS 6 1,229,400 0.87% $19.8 $18.9 $18.927 MT 5 1,830,624 1.30% $29.5 $28.1 $28.228 NC 27 5,504,531 3.90% $88.6 $84.5 $84.829 ND 9 3,038,100 2.15% $48.9 $46.6 $46.830 NE 6 614,473 0.44% $9.9 $9.4 $9.531 NH 1 176,900 0.13% $2.8 $2.7 $2.732 NJ 2 735,214 0.52% $11.8 $11.3 $11.390Exhibit 5B-2State-by-State Distributionof Estimated Incremental Costs for Regulatory OptionsWith Land Disposal Treatment Sub-Option($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)Option 1Subtitle Chazardous wasteOption 2Subtitle Dnon-hazardous wasteOption 3Subtitle C impoundmentsSubtitle D landfills33 NM 4 3,983,300 2.82% $64.1 $61.2 $61.434 NV 2 391,500 0.28% $6.3 $6.0 $6.035 NY 11 1,479,792 1.05% $23.8 $22.7 $22.836 OH 24 10,429,446 7.39% $168.0 $160.1 $160.737 OK 3 1,490,800 1.06% $24.0 $22.9 $23.038 OR 1 99,900 0.07% $1.6 $1.5 $1.539 PA 28 15,359,680 10.88% $247.4 $235.8 $236.740 RI 0 0 0.00% $0.0 $0.0 $0.041 SC 14 2,178,360 1.54% $35.1 $33.4 $33.642 SD 2 103,753 0.07% $1.7 $1.6 $1.643 TN 12 3,240,120 2.29% $52.2 $49.7 $49.944 TX 18 13,165,728 9.32% $212.0 $202.1 $202.945 UT 7 2,582,144 1.83% $41.6 $39.6 $39.846 VA 13 2,388,526 1.69% $38.5 $36.7 $36.847 VT 0 0 0.00% $0.0 $0.0 $0.048 WA 1 1,405,220 1.00% $22.6 $21.6 $21.749 WI 12 1,412,534 1.00% $22.7 $21.7 $21.850 WV 20 9,231,718 6.54% $148.7 $141.7 $142.351 WY 12 2,224,848 1.58% $35.8 $34.2 $34.3Totals =495141.2 million100%$2,274$2,168$2,176915C. 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 guidance90: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 EntitiesConsistent with EPA’s RFA/SBREFAguidance (page 15), this RIA applies the following small size definitions:Small company: Based on the US Small Business size standard for NAICS code 221112 (fossil fuel electric utility plants): acompany which generates less than 4 millionmegawatt-hours electricity output per year.Small 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 apopulation of lessthan 50,000.Based on the nameplate megawatt (MW) capacity for all electricity generating units (including thosepowered by non-coal fuel types) at eachelectricity plant from the 2007 DOE-EIA 860 database, this RIAestimated annual megawatt-hours electricity generation capacitybymultiplying the nameplate capacity by (a) 365 days per year, and (b) 24 hours per day tocalculate each owner entity’s annual electricity90EPA’s RFA/SBREFA guidance: “EPA’s ActionDevelopment Process: Final Guidance forEPA 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.pdf92capacity.Appendix Cof 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”.91Exhibit 5Cbelow presents the resultant count and summary of the characteristics of the small electric utility entities as estimated in this RIA.Exhibit 5CSummary 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=en91It should be noted that some of the companies identified assmall 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.93•Step 2: Measures for Determining Economic Impacts on Small EntitiesAccording to Table 1 of EPA’s 2006 RFA/SBREFA small business impact analytic guidance, there arethe following suggested teststhat 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 Cof 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 Lto this RIA, for each small entity computed 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 C). 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 sectors92CU = 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.htm92DOE’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.html94•Step 3 & Step 4: Determine and document whether the proposed rule may be certified as having “No SISNOSE”Determined whether each regulatory option may have a “significant impact on a substantial number of small entities” (i.e., SISNOSE) whichmay become subject to the requirements ofthe proposed rule. This determination involved comparing the estimated regulatory compliancecosts for each entity as displayed inAppendix Iof this RIA, to the respective annual sales and revenues for each entity estimated in Step 2above. Numerically, this comparison involved calculating the percentageof regulatory compliance costs relative to annual sales and revenuesfor each company for each of the regulatory options. Then compared the percentage results for each small entity to the following three impactthresholds defined in Table 2 of EPA’s RFA/SBREFA analytic guidance.Exhibit 5Dbelow displays the numerical results of this analysis andthe suggested RFA/SBREFA impact interpretation according to the three thresholds.<1% threshold: Annualized regulatory costs may be less then 1% of annual sales or revenues 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 entities95Exhibit 5DEstimated 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 RevenuesOption 1(Preferred Option)Subtitle C hazardous wasteOption 2Subtitle Dnon-hazardous wasteOption 3Subtitle C for mpoundmentsSubtitle D for landfillsA. Count of Small Entities:Without land disposal treatment: $16.4 $3.9 $3.9Less than 1% 46 50 501% or greater 5 1 13% or greater 0 0 0With land disposal treatment: $17.3 $4.7 $4.8Less than 1% 46 50 501% or greater 5 1 13% or greater 0 0 0B. % of Small Entities:Without land disposal treatment:Less than 1% 90% 98% 98%1% or greater 10% 2% 2%3% or greater 0% 0% 0%With land disposal treatment:Less than 1% 90% 98% 98%1% or greater 10% 2% 2%3% or greater 0% 0% 0%C. SISNOSE Findings:Without land disposal treatment:Less than 1% Presumed No SISNOSE Presumed No SISNOSE Presumed No SISNOSE1% or greater Presumed No SISNOSE Presumed No SISNOSE Presumed No SISNOSE3% or greater Presumed No SISNOSE Presumed No SISNOSE Presumed No SISNOSEWith land disposal treatment: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 SISNOSE96•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)•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 202593,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 of service, which includes "prudently" incurredexpenses and a "fair" return on equity.949330% 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.pdf94Source: “Electric Utility Regulation” by Robert J.Michaels in the Concise Encyclopedia of Economics at:http://www.econlib.org/library/Enc1/ElectricUtilityRegulation.html97Based on the electricity ratemaking process described by the Pennsylvania PUC95as 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 ratesand 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 5Ebelow:96Exhibit 5ESummary 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:97•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)95Source: 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.pdf96Source: “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-states97Source: “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.pdf98•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.98oInelastic 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.99At 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 knowhow much they use or indeed how much electricity costs until after thefact. Thus consumers cannot react to high prices easilyby cuttingconsumption.100oCost 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.98Source: “Shocking Electricity Prices Follow Deregulation”, USA Today, 10 Aug 2007 at: http://www.usatoday.com/money/industries/energy/2007-08-09-powerprices_n.htm99Source: 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.pdf100Source: “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.htm995D. Minority & Low-Income Population Statistics(Executive Order 12898)Under the 1994 Executive Order (EO) 12898101it 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 CensusBureau “non-white” statistics•Low-income population: Numericallymeasured according to CensusBureau “individuals below poverty102level.”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 environmentaland 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 utilityplant customer service areas.101Source: 1994 Executive Order 12898 is available at: http://www.epa.gov/fedrgstr/eo/eo12898.htm102The 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.html100•Collection of Minority & Low-Income Demographic DataStep 1: Plant address 5-digit zip codes formedthe geographic basis for thisEJ population data collection. Because zip codes representirregularly shaped geographic areas, this zip code based data collection may be considered a “screening level” analysis. The US Bureauof Census uses over 33,000 “Zip Code Tabulation Areas” (ZCTA) for its Census counts of populationand other demographic statisticsbased on the US Postal Service’s over 42,000 nationwide zip codes.103Currently, there are no size restrictions limiting how large orsmall a ZCTA can be in terms of either a minimum/maximum numberof housing units or geographic area. Any particular ZCTA maybe as small as a few city blocks or may cover many square miles. Many ZIP codes are for villages, census-designated places, portionsof cities, or other entities that are not municipalities. The nationwide average zip code population is about 7,200 persons (i.e., (306.6million mid-2009 US population) / (42,500 zip codes)). The nationwide average zip codearea is about 83 square miles (i.e., (3,536,278square miles total US land and water area) / (42,500 zip codes)), which is a land areaequivalent to a five-mile radial distance (i.e., ((83sq.miles) / (3.1416))^0.5). In comparison, the radial area monitored for contamination in response to the December 2009 TVAKingston TN electric plant CCR spill is reportedly four miles,104and this average four-mile zip coderadial distance falls between the 1-mile to 15-mile radial distances used by EPA’s Superfund “HazardRanking System” (HRS) to define affected populations of siteshaving either (a) soil contamination only (1-mile), (b) groundwater and/or airborne contamination (4-miles),or (c) surface watercontamination (15-miles downstream). More information about EPA’s HRS is available athttp://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), retrieved population statisticsfor 464 (94%) of the 495 electric utility plants. For 42 plants(8%) there was no zip code Censusdata because the plants didnot havecomplete address data from DOE, orbecause the Census search engine did not have data for the zip code.Step 2: Collected statewide percentage data for minority and low-income subgroups for purpose of benchmark comparison to the plantby-plant sub-group population statistics.oCollected low-income population statewide percentages (3-year averages for 1998 to 2000) from the following CensusBureau website:http://www.census.gov/hhes/www/poverty/poverty00/tabled.pdfoCollected statewide percentages forwhite population sub-group (data year 2000) from the Census Bureau website:http://www.census.gov/prod/2001pubs/c2kbr01-4.pdf. Subtracting the percentage ofwhite population in each state from100% to produced the respective minority percentage for eachstate. For data year 2000, the Census Bureau expandedthe white population classification by collecting both data for people who claimed to be “white-only” and for people whoclaimed to be “mixed white”. Since the purpose of the EJ analysis is to evaluate all minorities, this step involvedcollecting the “white-only” data in order to calculate the minority percentage which includes people who reported to beof mixed race.Exhibit 5Fbelow displays the statewide Census datafor low-income and minority sub-populations.103Source: US Census Bureau ZIP Code Tabulation Area (ZCTA) Frequently Asked Questions at:http://www.census.gov/geo/ZCTA/zctafaq.html#Q10Nationwide totalzip code count is from the US Postal Service’s FAQ website at: http://zip4.usps.com/zip4/welcome.jsp104Source: 4 mile radial monitoring area reported by Waste & Recycling News, 13 Feb 2009; http://www.wasterecyclingnews.com/email.html?id=1234543579101Exhibit 5FStatewide 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%102•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, compared theplant zip code percentage minority and percentage low-income population data, to therespective statewide averagepercentages for each sub-group. This constituted the 1stlevel of data comparison.Step 4: For purpose of summary, aggregatedthe plant level population comparison data for each state as displayed inExhibit 5Gbelow. Thisconstituted the 2ndlevel of data comparison. There are no data displayed forDC, ID, RI or VT because there are no coal-fired electricutility plants in those states.Appendix Mof this RIA presents the plant-by-plant Censusdata on which this Exhibit is based. This stepalso involved aggregating the data across all 495 plants for comparison with the nationwide aggregate minority and low-incomepercentage benchmarks. This constituted the 3rdlevel of data comparison.Exhibit 5GMinority and Low-Income Population DataAggregated on State-by-State BasisABCDEF(E/D)G(Exh 5F)H(DxG)IJK(DxJ)L(Exh 5F)M(DxL)NGeneral Population DataLow Income Population Data (Below Poverty)Minority Population DataItemStateZIPcodecount2000populationresiding inelectric utilityplant zip codeareasCount ofplant zipcoderesidentsbelowpovertylevel% of plant zipcode residentsbelow povertylevelState %belowpovertylevelExpectedcount ofresidentsbelowpovertybased onstate%Count ofplants withzip% >state%povertylevel% ofplant zipcoderesidentsthat areminorityCount ofplant zipcoderesidentsthat areminorityStatewide %minorityExpectedcount ofminoritybased onstate%Count ofplantswith zip%> 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 ND103Exhibit 5GMinority and Low-Income Population DataAggregated on State-by-State BasisABCDEF(E/D)G(Exh 5F)H(DxG)IJK(DxJ)L(Exh 5F)M(DxL)NGeneral Population DataLow Income Population Data (Below Poverty)Minority Population DataItemStateZIPcodecount2000populationresiding inelectric utilityplant zip codeareasCount ofplant zipcoderesidentsbelowpovertylevel% of plant zipcode residentsbelow povertylevelState %belowpovertylevelExpectedcount ofresidentsbelowpovertybased onstate%Count ofplants withzip% >state%povertylevel% ofplant zipcoderesidentsthat areminorityCount ofplant zipcoderesidentsthat areminorityStatewide %minorityExpectedcount ofminoritybased onstate%Count ofplantswith zip%> 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 0104Exhibit 5GMinority and Low-Income Population DataAggregated on State-by-State BasisABCDEF(E/D)G(Exh 5F)H(DxG)IJK(DxJ)L(Exh 5F)M(DxL)NGeneral Population DataLow Income Population Data (Below Poverty)Minority Population DataItemStateZIPcodecount2000populationresiding inelectric utilityplant zip codeareasCount ofplant zipcoderesidentsbelowpovertylevel% of plant zipcode residentsbelow povertylevelState %belowpovertylevelExpectedcount ofresidentsbelowpovertybased onstate%Count ofplants withzip% >state%povertylevel% ofplant zipcoderesidentsthat areminorityCount ofplant zipcoderesidentsthat areminorityStatewide %minorityExpectedcount ofminoritybased onstate%Count ofplantswith zip%> 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 =256138105Step 5: Ratios: Compared the percentages of minority and low-income populations surrounding the plants totheir respective statewidebenchmark percentages and to the nationwide percentages of these populations as calculated in Step 4, by calculating numericalratiosbetween the plant zip code grouppopulations 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 5Hbelow displays the results.Exhibit 5HComparison 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 ComparisonItemStateCount ofplantsPercentLowIncomePopulationSurrounding PlantsStatewideLow-IncomePercentageDifferenceRatioPercentMinorityPopulationSurroundingPlantsStatewideMinorityPercentageDifferenceRatio1 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% 0.49106Exhibit 5HComparison 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 ComparisonItemStateCount ofplantsPercentLowIncomePopulationSurrounding PlantsStatewideLow-IncomePercentageDifferenceRatioPercentMinorityPopulationSurroundingPlantsStatewideMinorityPercentageDifferenceRatio26 MS 4 25.5% 15.5% 10.0% 1.65 51.6% 38.6% 13.0% 1.3427 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%0.87107•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) forwhich year 2000 Census plant address zipcode data are available are located in47states.oThe plant address zip code population surroundingthe 464 plants with zip code data is6.08 million, which is an average of13,091 surrounding 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.108oThe 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 zip code area comparedto the rest of the state.oStates with the largest difference in minority populations between the zip codes where the plants are located compared to the restof the state are as follows:1.Connecticut (45% vs. 18%)2.Arizona (44% vs. 25%)3.Oregon (39% vs. 13%)4.Tennessee (37% vs. 20%)5.Kansas (37% vs. 14%)•Plant level results:Using the plant-by-plant (i.e., itemized zipcode) basis, 138 plants (28%) have surrounding minority populations which exceed their statewideminority benchmark percentages, whereas 357plants (72%) have minority populations below their statewide benchmarks, which represents aplant zip code ratio of 0.39 (i.e., 138/357). Because thisratio is 61% less than 1.00 (i.e., 1.00 minus 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 zip code basis, 256 plants (52%) have surrounding low-income populations which exceed their respective statewide benchmarks,whereas 239 plants (48%) have surrounding low-income populations below their statewidebenchmarks, which represents a plant zipcode ratioof 1.07 (i.e., 256/239). Because this ratio is only slightly (7%) above 1.00, it indicates that a slightly disproportionate count of plants havesurrounding low-income population percentageswhich 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.109•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 zip codessurrounding 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 (i.e., Option 1 and Option 3) whereby fourdifferent fractions of CCR generation may be required to be disposed in RCRA Subtitle C permitted hazardous waste landfills rather than innon-hazardous 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).110•CCR fraction #3: Annual CCR generation which could also switch to offsite commercial RCRA-permitted landfills is the CCR whichiscurrently supplied for industrial beneficialuse applications, if such use becomescurtailed in part or in whole fromeither state government regulations or from marketstigma (47.0 million tons is beneficially used).•CCR fraction #4: Future cleanup of CCR disposal unit failures (e.g., impoundment collapse) would be require disposal in RCRApermitted hazardous waste landfills (the two CCR impoundmentrelease case studies inExhibit 4Iof this RIArepresent a range of 0.25 million to 3.3 million tons per failure event).One or more of these four potential shifts of CCR disposal from current non-hazardous landfills to hazardous waste 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 permits todispose K179 listedRCRA hazardous waste. A recent (2007) study determined that minorityand low-income populations disproportionately live near commercialhazardous waste facilities, althoughthe study included other types of commercial hazardous waste treatment and disposal facilities in additionto commercial hazardous waste landfills.105An example of such potential EJ concernsis a 2009 US national news item involving the decisionmade by the Tennessee Valley Authority (TVA) to train transport 3million tons of the TVA’s (Kingston TN electricity plant) December 2008CCR impoundment collapse site cleanup waste,350 miles away to a landfill in a ruralAlabama county which reportedly has about70%minority (African American) and 33% low-income residents.106However, this example serves to illustrate that EJ concernsare 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:107“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 and105Source: United Church of Christ, “Toxic Wastes and Race at Twenty 1987-2007”, March 2007,http://www.ucc.org/assets/pdfs/toxic20.pdf. This study evaluated andmade findings on minority and low-incomepopulation data within a 1.8-mile radius “host neighborhood” of 413 commercial hazardous waste facilities, compared to “nonhost” areas. The study (page x) found that“Host neighborhoods of commercial hazardous waste facilities are 56% people of color whereas non-hostareas are 30% ofcolor... Poverty rates in the host neighborhoods are 1.5 times greater than non-host areas (18% vs. 12%).”106Source: 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.html107Source: 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.htm111project 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.1125E. Child Population Statistics (ExecutiveOrder 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 follows108: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 codes formedthe geographic basis for thischild population data collection. Because zip codes representirregularly shaped geographic areas, this zip code based data collection may be considered a “screening level” analysis. The US Bureauof Census uses over 33,000 “Zip Code Tabulation Areas” (ZCTA) for its Census counts of populationand other demographic statisticsbased on the US Postal Service’s over 42,000 nationwide zip codes.109Currently, there are no size restrictions limiting how large orsmall a ZCTA can be in terms of either a minimum/maximum numberof housing units or geographic area. Any particular ZCTA maybe as small as a few city blocks or may cover many square miles. Many ZIP codes are for villages, census-designated places, portionsof cities, or other entities that are not municipalities. The nationwide average zip code population is about 7,200 persons (i.e., (306.6million mid-2009 US population) / (42,500 zip codes)). The nationwide average zip codearea is about 83 square miles (i.e., (3,536,278square miles total US land and water area)/ (42,500 zip codes)), which is a land area equivalent to a 5-mileradial distance (i.e., ((83sq.miles) / (3.1416))^0.5). In comparison, the radial area monitored for contamination in response to the December 2009 TVAKingston TN electric plant CCR spill is reportedly four miles,110and this average 5-mile zip coderadial distance falls between the 1-mile to 15-mile radial distances used by EPA’s Superfund “Hazard Ranking System” (HRS)111to define affected populations of siteshaving either (a) soil contamination only (1-mile), (b) groundwater and/or airborne contamination (4-miles),or (c) surface water108The 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.html109Source: US Census Bureau ZIP Code Tabulation Area (ZCTA) Frequently Asked Questions at:http://www.census.gov/geo/ZCTA/zctafaq.html#Q10Nationwide totalzip code count is from the US Postal Service’s FAQ website at: http://zip4.usps.com/zip4/welcome.jsp110Source: 4 mile radial monitoring area reported by Waste & Recycling News, 13 Feb 2009; http://www.wasterecyclingnews.com/email.html?id=1234543579111More background information about EPA’s HRS is availableat http://www.epa.gov/superfund/programs/npl_hrs/hrsint.htm.113contamination (15-miles downstream). Using the Census search engine Factfinder(http:factfinder.census.gov/home/saff/main.html?_lang=en), retrieved total population and people 18 and over for 464 (94%) of the 495electric utility plants. For 42 plants (8%)there was no zip code Census data becausethe plants did not have complete addressdata fromDOE or because the Census search engine did not have data for the zip code.Step 2: Collected 3-year (2005 to 2007) average statewide percentages for people 18 andolder data using the following website:http://factfinder.census.gov/jsp/saff/SAFFInfo.jsp?_pageId=gn10_select_stateas displayed inExhibit 5Ibelow.Exhibit 5IState-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%RowState% children in state30 NE 25.3%31 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%114•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, compared theplant zip code percentage children, to the respective statewide average percentage children.Step 4: For purpose of summary, aggregated theplant level children population comparisondata for each state as displayed inExhibit 5Jbelow. There are no data displayed for DC, ID, RI or VT becausethere are no coal-fired electricutility plants in those states.Appendix Nof this RIA presents the plant-by-plant Census data on which this Exhibit is based.Exhibit 5JState-by-State Child Population Datafor Coal-Fired Electric Utility PlantsGeneral Population DataChild Population DataItemCount ofplantunique zipcodesStateCount of plantzip codes whichhave Censuspopulation data2000 plantzip coderesidentpopulationChildpopulationcount (<18years) in plantzip codesChildpopulationpercentagein plant zipcodesStatewidepercentagechildpopulationExpectedchildren count inplant zip codes ifbased on state %If plantzip codechild% >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 ID115Exhibit 5JState-by-State Child Population Datafor Coal-Fired Electric Utility PlantsGeneral Population DataChild Population DataItemCount ofplantunique zipcodesStateCount of plantzip codes whichhave Censuspopulation data2000 plantzip coderesidentpopulationChildpopulationcount (<18years) in plantzip codesChildpopulationpercentagein plant zipcodesStatewidepercentagechildpopulationExpectedchildren count inplant zip codes ifbased on state %If plantzip codechild% >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 10116Exhibit 5JState-by-State Child Population Datafor Coal-Fired Electric Utility PlantsGeneral Population DataChild Population DataItemCount ofplantunique zipcodesStateCount of plantzip codes whichhave Censuspopulation data2000 plantzip coderesidentpopulationChildpopulationcount (<18years) in plantzip codesChildpopulationpercentagein plant zipcodesStatewidepercentagechildpopulationExpectedchildren count inplant zip codes ifbased on state %If plantzip codechild% >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 zip codes were compared to overall state percentages and thenationwide percentage of this sub-group population, by calculating ratios between the plant zip codechildren populationscompared to statewide and nationwidepercentages of children population.Exhibit 5Kbelow displays the results.Exhibit 5KComparison of Child Population Data on a State-by-State BasisItemStatePlantsPercentage ofZip CodePopulationunder 18Years OldStatewidePercentage ofChildren(Exhibit 5I)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% 1.46117Exhibit 5KComparison of Child Population Data on a State-by-State BasisItemStatePlantsPercentage ofZip CodePopulationunder 18Years OldStatewidePercentage ofChildren(Exhibit 5I)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% 1.06118Exhibit 5KComparison of Child Population Data on a State-by-State BasisItemStatePlantsPercentage ofZip CodePopulationunder 18Years OldStatewidePercentage ofChildren(Exhibit 5I)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 zip code) basis,(b) nationwide aggregationbasis, and (c) state-by-state aggregation basis.For purpose of determiningthe relative degree by which children may exceed these statewidepercentages, the percentages are compared as a numerical ratiowhereby aratio of 1.00 indicates that thechild population percentage livingnear a plant is equal to thestatewide average, a ratio greater than 1.00indicates the child population percentage near the plant is higher than the statewide population, and aratio less than 1.00 indicates the childpopulation is less than the respective statewide average.•General population findingso464 plants (i.e., 94% of the 495 universe) for which Censusplant address zip code dataare located in 47 states.oThe plant address zip code population surrounding these plants is 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 of children within the plant address zip code areascompared to the statewide percentages.oStates with the largest difference in the children population between the zip codes where the plants are located compared tothe statewide percentages are as follows:1.Oregon (36% vs. 23%)1192.Hawaii (33% vs. 22%)3.New Mexico (32% vs. 26%)4.Arizona (33% vs. 26%)5.California (32% vs. 26%)oA sub-total 291 plants (63%) have surrounding children populations which exceed their respective statewide percentage.•Plant level results:Using the plant-by-plant (i.e. itemized zipcode) basis, 310 plants (63%) have surrounding child populations which exceed theirstatewidechildren benchmark percentages, whereas 185 plants (37%) have children populations below their statewide benchmarks, which represents aplant zip code ratio of 1.68 (i.e., 310/185).Since this ratio is much greater than1.00, this finding indicates that a highlydisproportionate countof plants have surrounding child population percentages which exceed their statewide benchmark.•State level results:Using the state-by-state aggregation basis,the percentage of child populations surrounding the 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 zip code area compared to therest of the state suggesting a disproportionatesurrounding 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 zip codessurrounding 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 humanhealth hazards and risks fromelectric utilityCCR disposal units, and the expected futurebenefits of the regulatory options, may have a disproportionately higher effect onchildpopulations.1205F. 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 5L, 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 5Mbelow, 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 O.121•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 5L, the proposed rule mightimpose four types of direct costs on the 60 state/local government ownerentities identified inExhibit 5Mbelow:•State/local government owned electric utility plants:1.Engineering control costs for CCR disposalunits located at electric utility plants owned bystate/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 5Lare 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 guidance112for 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 more1132.1% 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.]112The 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.pdf113Although 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.122•Findings for UMRA Impact andFederalism Implication TestsBased on estimated regulatory costs onstate/local governments displayed inExhibit 4O(Chapter 4) of this RIA under each regulatory option,Exhibit 5Lbelow displays whether the costspotentially 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 >$25 million state/local government test; all options <1%state/local government testHowever, for consistency with the RFA/SBREFA small business impactanalysis presented in a separate section above in this RIA,this RIAestimates it is highly likely that the direct compliance costsunder each option may be passed-thru to electricity plant customers in the form ofhigher electricity prices. The feasibility of such a compliance cost pass-thruscenario is evaluated and confirmed by the information presentedin the RFA/SBREFA small businessimpact section of this RIA.Exhibit 5LUMRA and Federalism Tests for CCR Disposal Regulatory Options($millions average annualized costs @7% discount rate over 50-years 2012 to 2061, 2009$)Type of Direct Compliance CostOption 1(Preferred Option)Subtitle Chazardous wasteOption 2Subtitle Dnon-hazardous wasteOption 3Subtitle C for impoundmentsSubtitle D for landfillsA. Without land treatment disposal sub-option:$598$492$500UMRA Test:1. Private sector $100 million direct cost threshold test $512.7 $415.3 $422.12. State/local government $100 million direct cost threshold test* $67.3 $55.9 $57.9Federalism Test:1. $25 million threshold test: sub-total State/Local govt cost $67.3 $55.9 $57.92. 1% Test: State/local govt cost as percentage of State/Localgovernment electric utility annual revenues0.158% 0.131% 0.136%B. With land treatment disposal sub-option:$2,274$2,168$2,176UMRA Test:1. Private sector $100 million direct cost threshold test $1,999.4 $1,902.0 $1,908.82. State/local government $100 million direct cost threshold test* $96.7 $85.3 $91.6Federalism Test:1. $25 million threshold test: sub-total State/Local govt cost $96.7 $85.3 $91.62. 1% Test: State/local govt cost as percentage of State/Localgovernment electric utility annual revenues0.227% 0.200% 0.215%* Note: Remainder Federal government costs represent costs associated with Federally-owned electric utility plants (i.e., Tennessee Valley Authority) whichare not subject to either the UMRA or Federalism tests. Therefore, the sub-total private sector direct cost plus the state/local government direct cost does notadd-up to the total annual cost estimate under each option; the remainder cost is for the Federally-owned plants.123Exhibit 5MList 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 data from 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 AuthJefferies 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 PowerPark 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 City124Exhibit 5MList 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 data from 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 City125Exhibit 5N (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 data from 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.126Chapter 6Sensitivity AnalysesThis chapter describes and estimates the magnitude ofsix major uncertainty, variable, and scope factorsin the formulations and calculationsof the cost estimates and associated quantitative analyses presented in the previous chapters of this RIA. The sensitivity analysis factors are:A.Alternative discount ratesB.Data quality uncertaintyC.Possible impact on baseline CCR beneficial usesD.Price and capacity impacts on commercial hazardous waste landfillsE.Uncertainty in land disposal treatment sub-option cost estimateF.Other CCR disposal units not covered by the proposed rule6A. Alternative Discount Rates (0%, 3%, 7%)Because the annualized average costs --- toboth industry and to state governments --- estimated in this RIA were formulated inthe firstinstance as uniform average annual costs, their numerical dollar values are not sensitive to alternativediscount rates over the 50-year period ofanalysis applied in this RIA. However, some of the average annualized costs involve capitalinvestments (e.g., one time costsfor installation ofengineering controls), and capital costs are sensitive to discount rates because this RIA converted (i.e., annualized) capitalcosts into averageannualized equivalent costs overthe 50-year period of analysis, using a 7% discount rate. For annualization of such one-timecosts, this RIAapplied a 7% discount rate to represent the financial opportunity cost (i.e., borrowing cost) to affectedbusinesses, which isconsistent withOMB’s 2003 Circular A-4 (page 33) and 1992 Circular A-94 (page 8) which indicate thata 7% discount rate base-case should be used forregulatory analyses when regulation isexpected to primarily and directlyaffect businesses and industries.For purpose of this discount rate sensitivity analysis, alternative discount rates are not applied to the micro-formulations for each type of capitaland other one-time cost estimated in this RIA, but to the present value calculations of the overall (i.e., aggregate) average annualized cost foreach regulatory option over the 50-year period of analysis applied in this RIA.Exhibit 6Abelow presents the results according to threealternative discount rates (i.e.,0% non-discounted, 3%, and 7%).These three alternative discountrates are identified in OMB’s 2003 CircularA-4 guidance114(page 45) for purpose of RIA discount rate sensitivity analyses.114OMB’s 17 Sept 2003 Circular A-4 “Regulatory Analysis” guidance is available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/127Exhibit 6ADiscount Rate Sensitivity Analysis for Average Annual Values of Estimated Regulatory Options($millions per year over 50-year period of analysis 2012 to 2061)Alternative Discount RatesOption 1(Preferred Option)•Subtitle C hazardouswasteOption 2•Subtitle D nonhazardous wasteOption 3•Subtitle forimpoundments•Subtitle D for landfillsA. Without land treatment disposal sub-option:7% (base case for this RIA)$598$492$5003% $321 $264 $2680% (not discounted) $165 $136 $138B. With land treatment disposal sub-option:7% (base case for this RIA)$2,274$2,168$2,1763% $1,220 $1,163 $1,1670% (not discounted) $628 $598 $6011286B. Data Quality 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. Because this RIA does not monetize benefits, this section only addresses uncertaintieswith respect to cost estimates for bothbaseline cost and incremental costs for the regulatory options. This section first presentsthree specific examplesof data quality uncertaintyfactors in this RIA, followed by anoverall uncertainty factorto represent all such specific data quality uncertainty factors combined (thethree factors below are not additive acrosstheir low- and high-end percentage range endpoints because such simple addition would representunlikely compounding of these factors):•Specific Examples of Data QualityUncertainty Factors in This RIA1.CCR tonnage data:As described respectively in Chapter 3 and Chapter 4 of this RIA, the baseline and regulatory option engineeringcost estimates are based on the annual CCRdisposal and beneficial use tonnages reported by electric utility plants tothe 2005 DOE-EIA Form 767 database. However, the DOE-EIA 767 data reporting form115does not providerespondents with a definition for the “tons” collected in Schedule 3 of the data reporting form. Because there arethree numerical definitions of “ton” commonly usedin the US (i.e., short-ton = 2,000 pounds, long-ton = 2,200pounds; and metric ton = 2,205 pounds), this factor potentially introduces-20% to +20%uncertainty range. Forpurpose of consistency with the use of short-tons in mostEPA RCRA program reports,116this 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 2Dof 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.115Instructions 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.pdf116One 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.htm129•Overall Data Quality Uncertainty RangeThe 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”117. 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 6Bbelow, this cost estimate classification system involves 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 6BSummary of Cost Estimation Classification Systemfor CharacterizingData Quality 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 6C.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 40,117Recommended 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.pdf13041) as acceptable for characterizing probability distributions for cost estimates involving major rules with possible annual economic effects of$1 billion or more for one or more regulatory options.Exhibit 6CCost Estimation Uncertaintywith Overall Data Quality Uncertainty Factor Applied($millions average annualized costs over 50-year period 2012-2061 in 2009$)Cost Estimate Uncertainty IndicatorOption 1(Preferred Option)•Subtitle C hazardouswasteOption 2•Subtitle D nonhazardous wasteOption 3•Subtitle C for impoundments•Subtitle D for landfillsA. Without land disposal treatment sub-option:Best estimate (average annualized cost)$598$492$500-25% uncertainty low-end $448 $369 $375+40% uncertainty high-end $837 $689 $700B. With land disposal treatment sub-option:Best estimate (average annualized cost)$2,274$2,168$2,176-25% uncertainty low-end $1,706 $1,626 $1,632+40% uncertainty high-end $3,184 $3,035 $3,0461316C. Potential Impact on Baseline CCR Beneficial UsesThe 2003 OMB Circular A-4 “Regulatory Analysis” (page 26) recommends that Federal agencies look beyond the direct benefits anddirectcosts of rulemakings and consider any important ancillary benefits and countervailingrisks (i.e., indirect effects). The OMBCircular definesancillary benefit as a favorableimpact of the rule that is typically unrelated or secondary tothe purpose of the rulemaking,while acountervailing risk is an adverse economic, health, safety, or environmental consequence that may occur due to a regulation that is not alreadyestimated and accounted for in the directcost of the regulation. This section identifies and quantifies a potential countervailing impact of theproposed rule on CCR beneficial use.Described below arefive hypothetical scenariosfor potential impact of RCRA regulation on the annual tonnage of baseline CCR beneficialuse. One of the five scenarios (i.e., Scenario #5) portrays an increase in future beneficial use, whereas all of the other four scenarios (i.e.,Scenarios #1 to #4) portray future reductions in beneficial use ranging from4% to 42%potential loss in annual beneficial use, depending uponregulatory option and scenario. Relative tothe 62 million tons of annual CCR beneficial use estimated in this RIA for 2009 inExhibit 3Fofthis RIA, the 4% to 42% scenario-based loss range represents2.5 million to 26 million tons peryear potential loss in beneficial use.In addition to the change in associated economic and environmentalbenefits of change in beneficial use, the coal-fired electric utility industrywould also be faced with a change in annual CCR disposal cost associatedwith the affected beneficial use tonnages. After description of eachbeneficial use impact scenario,Exhibit 6Dpresents a summary of (a) percentage change for each scenario, (b) associated change in economicbenefits, (c) associated change in environmental benefits, and (d) associated change in future annual CCR disposal cost.•Scenario #1 of 5: Market Stigma (non-quantified loss under Option 1 & Option 3)This potential source of beneficial market loss was identified by the American CoalAsh Association (ACAA) indicated in a 09 April 2009letter addressed to the EPA Administrator which asserted thepossibility of stigma resulting from RCRA Subtitle C regulation:“Any designation of [CCRs] ashazardous wastes would have significant and long-lasting effectsupon this nation’s willingnessto beneficially use or reuse fly ash orbottom ash in sustainable construction applications. Even a “contingent” Subtitle Capproach would have the same effect, as the industry would consider a contingent classification the equivalent to full SubtitleC... Either designation wouldunnecessarily stigmatize [CCRs].”This hypothetical market loss scenario is also conceptually feasible inlight of a number of studieswhich have documented andmeasured thephenomenon of hazardous waste stigma in relation to property value loss.118According to published theories summarized in a recent review119118For example, one study of hazardous waste stigma impact on property values is “Stigma: The Psychology and Economics of Superfund” prepared by William Schulze etal. for the EPA under contract nr. CR 824393-01-0, July 2004, 241 pages, at: http://yosemite.epa.gov/ee/epa/eerm.nsf/vwGA/8B86459E07EC7DCB85256F4E00672D65132of hazard stigma, when a place or a productis stigmatized, its economic value may decrease to levels below what one would expect when onetakes into account the actual riskassociated with it. Consequently, the potential economic impact of product stigma may be measured as thedifference between the market price and the lower (i.e., perceived risk adjusted) price which consumers are willing to pay (ifsuch informationis available), or the reduction in consumerdemand and sales/revenues or market asset value. Adverse market effects on products resultingfrom hazard stigma may be particularly acute, because according to psychological andanthropological research, people are veryconcernedabout even minute exposuresto carcinogenic substances.•Scenario #2 of 5: Restrictions on“Use Constituting Disposal” (42% loss under Option 1; 7% loss under Option 3)For Option 1: The proposed CCR regulatory options based on RCRA Subtitle C propose to changethe regulatory status of CCR to K179 listedhazardous waste. Because some beneficial uses (e.g., non-encapsulated uses) might become considered under 40 CFR 261.2(c)(1) or understate regulations, as by-products used ina manner constituting disposal (i.e.,UCD “use constituting disposal”) by:•Direct placement on the land, or•Used to produce products that are applied toor placed on the land or are otherwise contained in products that are applied to or placedon the land.This scenario estimates that 42% of baseline beneficial uses might become subject to Federal or state regulations or restrictions affectingbeneficial uses of hazardous wastes. Thisestimate is based on 58% of CCR beneficialuses which may be considered non-UCD because theyrepresent encapsulated applications: cement (33.0%), concrete(8.5%), and wallboard (16.5%). The added cost of meeting 40 CFR266 SubpartC RCRA hazardous waste beneficial use regulations (addressed by the next Scenario #3),or state regulatory restrictions on UCDor nonencapsulated uses, or perception of new legal liabilities by industries beneficially using CCR, ormarket stigma, could resultin loss of this 42%.For Option 3: Applying this scenarioto only the fraction of wet CCR usedas an input/ ingredient for beneficial uses. In absence of dataonhow much wet CCR annual tonnage goes to beneficial uses, this RIA assumes that the 16%wet CCR disposal tonnage (relative to total CCRannual disposal), is a proxy for that factor. Applying the 42% from above to 16% implies a beneficial use loss of 4% (i.e., (42% reduction) x(16% wet CCR) = 7% loss).•Scenario #3 of 5: Added Cost of RCRA Regulation of Beneficial Use (33% lossunder Option 1; 5% loss under Option 3)This scenario is a variation built upon Scenario #2 above “use constituting disposal” whereby someUCD might continue if cost-effective.119Source: Howard Kunreuther & Paul Slovic, “Coping with Stigma: Challenges and Opportunities,” Risk: Health, Safety & Environment, Vol. 269, Summer 1999, page339 at: http://opim.wharton.upenn.edu/risk/downloads/01-07-HK.pdf133For Option 1: The added cost for meeting the 40 CFR 266 Subpart C hazardouswaste regulations for hazardous waste use constituting disposal(UCD) is estimated at $26 per ton of hazardous waste.120At an average $13 per ton price for purchasing CCR for beneficialuse applications(source: Column E ofExhibit 3E), this additional Subtitle C regulatory cost couldincrease the price of CCR by 200% to $39 per ton, forindustries which use CCR for beneficial use applications. The implied higher Subtitle C regulatedprice of $39 per ton is still less than theoverall estimated $46 per ton average purchase price for substitutevirgin materials for beneficialuses (source: Column H ofExhibit 3E), butthe $39 per ton price is higher than threebeneficial use categories --- constructionfill (16.8% of market), wallboard (16.5%of market), and45% of the minor uses (16.2%) --- of whichconstruction fill and minor uses might beconsidered non-encapsulated UCD, thereby implying thatthe higher regulated price could result in loss of33% of beneficial use markets (i.e., 16.8% + 16.2%).For Option 3: Applying this scenarioto only the fraction of wet CCR usedas an input/ ingredient for beneficial uses. In absence of dataonhow much wet CCR annual tonnage goes to beneficial uses, this RIA assumes that the 16%wet CCR disposal tonnage (relative to total CCRannual disposal), is a proxy for that factor. Applying the 33% from above to 16% implies a beneficial use loss of 4% (i.e., (33% reduction) x(16% wet CCR) = 5% loss). However, it islikely that most all baseline CCR suppliedfor beneficial uses is dewatered by electricity plants.•Scenario #4 of 5: State regulatory barriers (25% loss under Option 1; 4% loss under Option 3)For Option 1: On 08 July 2009, EPA ORCR received comments from EPA Region 5 that CCR disposalregulatory options based on RCRASubtitle C hazardous waste regulations, could reduce CCR beneficial use in at least three (MN, OH,WI) of the six states in Region 5 for thefollowing reason:"Several [EPA] Region 5 states have submitted comments to EPA indicating that a hazardous waste listing will significantlyaffect their beneficial use programs. Somestates questioned whether theywould be able to continueapproving beneficial use of[CCR] if they were considered hazardouswhen disposed because their beneficial use programs can only apply to nonhazardous waste.... Region 5 states have objected to a hybridapproach and believe it would still create barriers to theirbeneficial use programs. A few of our states (OH, MN, WI)can not apply their beneficial use programs to hazardous wastes.”In ORCR’s 16 April 2009 study “State GovernmentCoal Combustion Waste Beneficial Use Programs and RCRA Hazardous Waste” availablefrom the docket for the CCR proposed rule, EPA ORCR reviewed state waste management and industrial waste beneficial use regulations in 10states with relatively large annual tonnage generation of CCR (i.e., FL, GA, IA, IL,IN, MN, PA, TX, UT, WI). Based on 2007 DOE-EIA datapresented inExhibit 2Bof this RIA, these 10 states represent 188 (i.e., 38%) of the 495 NAICS 221112 coal-fired electric utility plants and 63million (i.e., 42%) of the 149 million annual tons CCR generation (estimated in this RIA for 2007). The review revealed that six states (FL, IL,120Source: Using recycling/recovery as a proxy for beneficial use,based on cost estimates for RCRA hazardous waste recycling/recovery presented in EPA ORCR’s“Regulatory Impact Analysis: USEPA’s 2008 Final Rule Amendmentsto the Industrial Recycling Exclusions of the RCRA Definition of Solid Waste”, 25 Sept 2008available athttp://www.regulations.gov/fdmspublic/component/main?main=DocumentDetail&d=EPA-HQ-RCRA-2002-0031-0602. The $26/ton average cost is derivedfrom this source by dividing its estimated $106.4 million/year baseline cost (source: DSW RIA Exhibit 6C) for compliance with Subtitle C hazardous waste recycling/recovery regulations pertaining to 4.13 million tons/year hazardous waste currently plus prospectively recycled/recovered (source: DSW RIA Exhibit 4G + Exhibit 5K).134MN, PA, TX, WI) limit industrial waste beneficial use to non-hazardous wastes. Combining Region 5’s three states with the sixstates of thisApril 2009 study suggest that at least sevenstates (i.e., FL, IL, MN, OH, PA, TX, WI),which this RIA applies as a CCR beneficial usereduction scenario for this Option. Based on 2007 DOE-EIA data presented inExhibit 2BandExhibit 3G, respectively, these seven statesaccount for 126 (i.e., 25%) of the 495 electric utility plantsand account for 15 million tons(i.e., 25%) of the 60 million tons of US nationwideannual CCR beneficial use (2007). This analysis suggests a potential 25% future loss inbeneficial use for the Subtitle C Option 1.For Option 3: Applying this scenarioto only the fraction of wet CCR usedas an input/ ingredient for beneficial uses. In absence of dataonhow much wet CCR annual tonnage goes to beneficial uses, this RIA assumes that the 16%wet CCR disposal tonnage (relative to total CCRannual disposal), is a proxy for that factor. Applying the 25% state government restrictions identified inscenario #4 above to 16% implies abeneficial use loss of 4% (i.e., (25% state restriction) x (16%wet CCR) = 4% loss).•Scenario #5 of 5: Regulationavoidance (non-quantified increase)As estimated in Chapter 4 of this RIA, each regulatory option is expected to impose compliance costs on electric utility plants. Given the factthat 28 of the 495 potentially affected plants solely provide CCRfor beneficial uses, some additional plants may also attemptto eliminate CCRdisposal by solely providing their CCR to beneficial use applications, to avoid compliance costs. For example, one economic mechanismwhich plants may use to affect such a switchover from CCR disposal toincreased CCR beneficial useby some electricity plants,would be tooffer their CCR to other industries for free, which some plants currently do as evidenced by the zero ($0) low-end market prices of the priceranges displayed for three beneficialuse categories (i.e., concrete, cement,wallboard) displayed in Column E ofExhibit 3E. This RIA did notattempt to quantify this scenario, but as estimated inExhibit 3F, CCR beneficial use has been growing anaverage annual rate of 5.7% between2001 and 2009, which indicates growing national economic demand for CCR in beneficial usesmight not be a constraint on such additionalfuture growth.135Exhibit 6D($millions average annualized in 2009$)A. Possible percentage change inCCR beneficial use annual tonnageB. Possible change in nationaleconomic & environmental benefitsC. Possible change in CCR disposal costto electricity plants*CCR Beneficial UseRCRA Regulatory ImpactScenarioOption 1Option 2Option 3Option 1Option 2Option 3Option 1Option 2Option 3Baseline w/out RCRAregulation62.1 million tons/year$24,597 per year$5,556 per year1. Market stigma Decrease notest.0% Decrease notest.Decrease notest.$0 Decrease notest.Decrease notest.$0 Decrease notest.2. Restrictions on “useconstituting disposal” (UCD)-42%(-26.1 mill.)0% -7%(-4.3 mill.)-$10.331 $0 -$1,747 +$2,219 $0 +$3663. Added cost for UCDregulatory compliance-33%(-20.5 mill.)0% -5%(-3.1 mill.)-$8,117 $0 -$1,230 +$1,743 $0 +$2644. State regulatory barriers -25%(-15.5 mill.)0% -4%(-2.5 mill.)-$6,149 $0 -$984 +$1,318 $0 +$2135. Regulation avoidance Increase notest.0% Increase notest.Increase notest.$0 Increase notest.Decrease notest.$0 Decrease notest.Notes:NA = Not applicable because potential impacton CCR beneficial use assumed in this RIA as only relevantto Subtitle C hazardouswaste based regulatory options (i.e.,Option 1 and Option 3).* Potential increase in annual disposal cost estimated as midpoint between two alternative CCR disposal sub-scenarios:•Onsite disposal: Cost estimate consists of two elements:o#1: RCRA Subtitle C permitting and lateral expansion of existing onsite landfills @$59 per ton baseline cost estimated inExhibit 3Dof this RIA.o#2: Incremental unit cost for regulatory options estimated inExhibit 4Nof this RIA without land disposal treatment (assumes all CCR currently suppliedto beneficial uses is dewatered by electricity plants prior todelivery to industrial users).Option 1: $6.35 per ton Option 3: $5.31 per tono#1+#2: Total unit cost applied for onsite disposal: Option 1 = $65.35 per ton Option 3: $64.31 per ton•Offsite disposal: Cost estimate consists of two elements from which the midpoint isapplied in this Exhibit:o#1: Landfill cost: @$61 to $139 per ton (midpoint = $100 per ton) foroffsite commercial hazardouswaste landfills (bulk wastewithout treatment) asreported in May 2004 by the Environmental Technology Council national survey athttp://www.etc.org/costsurvey8.cfmo#2: Trucking & manifesting cost: $5/ton average unit cost based on calculations from cost items 11A and 11B of the “Ancillary Costs” elements inChapter 4 of this RIA (i.e., ($74.1 million/year) / (15 million tons/year associated with the Gambrills MD case study)).o#1+#2: Total unit cost applied for offsite disposal = $105 per ton•Midpoint applied between onsite & offsite disposal sub-scenarios:oOption 1: $85.18 per ton (rounded to $85 per ton)oOption 3: $84.66 per ton (rounded to $85 per ton)1366D. Price and Capacity Impacts onCommercial Hazardous Waste LandfillsFor the scenarios estimated in the prior section of this chapter involving an estimated range of 4%to 42% potential future loss of CCRbeneficial use under the Subtitle C options(i.e., Option 1 and Option 3), such loss would require additional disposal of 2.5 million to 26 milliontons annually (i.e., (62.1 million tons peryear beneficial use estimate for 2009) x (4% to 42%)), which will likely create four future disposalproblems:1.Annual disposalrate exceedance: Relative to the range of 2.5 million to 26 million lost beneficial use annnual tonnages, there is a muchsmaller quantity of 2 million tons per yearof RCRA-regulated hazardous waste which iscurrently disposed in RCRA Subtitle Cpermitted onsite (captive) and offsite(commercial) landfills in the US.121This implies a potential 25% to 1,300% annual increase indemand for hazardous waste landfill capacity.2.Limited geographic availability: There are currently 19 to 24 commercial hazardouswaste landfills operating in 15 to 17 states.122However, the CCR which is currently beneficially used is generated by 272 electric utility plants located in 41 states.123Thus 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.124The 62.1 million tons per year of CCRbeneficial use (estimated for 2009) willconsume this entire remaining total capacity within one-half year or less.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 national121Source: 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.htm122Source: 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.123The 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.124Source: 02 Oct 2009 estimates by EPA OSWER-ORCR staff (Cpan Lee,Environmental Scientist) cited in prior footnote in this section of the RIA.137average).125As verification of this potential effect onlandfill prices, a recent(August 2009) market study126of the US commercialhazardous 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.”125Source: 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.cfm126Source: Page 10 of “HazardousWaste Industry Review 2008-2009,” Joan Berkowitz and Robert Crisp, Farkas Berkowitz & Company, August 2009;http://www.farkasberkowitz.com/marketresearch.htm1386E. Uncertainty in Land Disposal Treatment Sub-Option Cost EstimateThere are two sources of uncertainty for thisuncertainty factor: (1) uncertainty in the future count of electric utility plants potentially affectedby this sub-option, and (2) uncertainty in the equipment/process modification cost to affected plants for complying with this sub-option. Themagnitude of each uncertainty source is estimated separately below in this section.6E.1 Uncertainty in Plants Potentially Affected by This Sub-OptionChapter 4 of this RIA estimates the potential annualized costs for regulatory engineering controls, ancillary regulatory costs,and the landdisposal treatment requirement based on the electric utility plant counts, CCR disposal methods (i.e., onsite or offsite landfills, impoundmentsor beneficial use) and associated CCR annual tonnages fromthe 2005 DOE-EIA Form 767 databasesupplemented with the 2007 DOE-EIAForm 860 database. However, with respect tothe land disposal treatmentcost estimate in this RIA, since 2005 some plants mayhave alreadyvoluntarily eliminated wet CCR disposal, orare planning to eliminate wet disposal.For example, in August 2009 the TennesseeValleyAuthority (TVA) announced a proposed plan toeliminate wet CCR disposal (i.e., to convertto dry disposal) atall 11 of its coal-fired electricutility plants over the next eight to ten years.127TVA’s 11 plants represent 7% of the estimated 158 plant count using impoundments as of2005; if TVA voluntarily converts its 11 plants, the cost of the land disposal treatment sub-option attributable to the CCR proposed rule, maybe over-estimated byat least 7%in this RIA.6E.2 Uncertainty in the Per-Plant Equipment/Process Modification Cost for This Sub-OptionIn addition to the 2005 Tennessee Valley Authority (TVA) cost studyreferenced and applied in Chapter 4 of this RIA for estimating the perplant equipment/process modification cost for compliance with theland disposal treatment option,EPA ORCR is aware of three other relatedcost studies (1981, 1985, and 2009) which are summarized in this section below. The first two studies provide cost estimates on a per-plantbasis for a few plant sizes, and the 2009 study provides a nationwide cost estimate. This RIA did not apply these other studies because the firsttwo are over 25-years old (i.e., 1981 and 1985)and the third study does not provide sufficient details for verification of data and calculations.These studies are summarized below and used as a basis for formulating alternative nationwide cost estimates for the land disposal treatmentsub-option, for the purpose of illustrating the potential magnitude ofuncertainty in this RIA’s cost estimate in relation to these other studies.•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.128127Source: 20 August 2009 TVA press release at http://www.tva.gov/news/releases/julsep09/ccprp_other.htm128Source: 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=139•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 system cost 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)129Dry disposal $2.19 to $4.50 $4.81 to $9.87Wet disposal $1.86 to $5.68 $4.08 to $12.46•Using the EPA ORCR 2009$ updated unit cost midpoints displayed above yields the following rough cost 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 cost130: (22.4 million tons per year wet CCR disposal for conversion at 158 plants) x [(($4.81 to $9.87 per ton drydisposal unitized present value cost)x (59.4% dry O&M fraction)) – (($4.08 to $12.46per ton wet disposal unitized present&EndTime=&SearchMethod=3&TocRestrict=n&Toc=&TocEntry=&QField=pubnumber%5E%22600781013%22&QFieldYear=&QFieldMonth=&QFieldDay=&UseQField=pubnumber&IntQFieldOp=1&ExtQFieldOp=1&XmlQuery=&File=D%3A%5Czyfiles%5CIndex%20Data%5C81thru85%5CTxt%5C00000000%5C20006ORT.txt&User=ANONYMOUS&Password=anonymous&SortMethod=h%7C-&MaximumDocuments=10&FuzzyDegree=0&ImageQuality=r75g8/r75g8/x150y150g16/i425&Display=p%7Cf&DefSeekPage=x&SearchBack=ZyActionL&Back=ZyActionS&BackDesc=Results%20page&MaximumPages=1&ZyEntry=1&SeekPage=x1291980$ costs from the 1981 TVA/EPA studyupdated by EPA ORCR to 2009$ using the GDP calculator at http://cost.jsc.nasa.gov/inflateGDP.html140value cost) x (31.6% wet O&M fraction))]x (45 years dry disposal operationalperiod 2017-2061 which assumed to begin 5years after 2012 final 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.131•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,EPRI, and other organizations.Exhibit 6Ebelow displays the unitized capital costs andExhibit 6Fbelow 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 6EandExhibit 6F, 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 6E) = $6,810 million capital cost130O&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-11.131Source: 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=x141Annual 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 6F) = -$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 6EComparison of Unitized Capital Costs for Wet and Dry CCR DisposalSource: 1985 EPA Study; $/kWPlant 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) = 2.239142Exhibit 6FComparison of Annual O&M Costs for Wet and Dry CCR DisposalSource: 1985 EPA Study; $/dry metric tonPlant 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) = 2.239143•Study #3 of 3: 2009 USWAG•On 11 June 2009 the Utility Solid Waste Action Group (Jim Roewer,Executive Director) emailed toORCR (Matt Hale, Director) a 14-page cost study USWAG sponsored by the EOP Group Inc., containing an estimate of $39,000million present value (PV) for conversionto dry disposal: “Cost Estimates for Closure of Ash Ponds atFossil Fuel Power Generation Facilities”, prepared in 2009 by EOPGroupInc. USWAG/EOP’s $39,000 million PV estimate uses a 3% discountrate over 20 years with a 10-year implementation period, andconsists 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) = $2,698 million per yearExhibit 6Gbelow presents a summary of the extrapolated cost estimates based on the per-plantcost findings from these three alternativecoststudies, compared to the cost estimate based on the 2005TVA cost study applied in Chapter 4 of this RIA.144Exhibit 6GSummary of Cost EstimatesBased on Three AlternativeStudies 1981,1985, 2009Compared to the Cost Estimateof Chapter 4 in this RIA($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$2,698 $105 to $2,698Row 3 implied uncertainty range compared to estimate based on 2005 TVA study =-94% to +61%*Note:Annualized over a 50-yearperiod @7% discount rate.1456F. Other CCR Disposal Units NotCovered 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:132•Inactive units: CCR impoundments and landfills not in operation orreceiving CCR. Inactive impoundments may receive CCR in thefuture, 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).133These 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).This 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 (source:MSHA “Supporting Statement” for Information Collection Request(ICR) 1219-0015 “Refuse Pilesand Impoundment Structures,Recordkeeping and Reporting Requirements”, March 2008: http://www.msha.gov/regs/fedreg/paperwork/2004/04-24046.pdf), which implies132Source: 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=030908251X133Source: Counts of 1,600 active coal waste impoundments and 670 inactive or abandoned coal waste impoundments from the prior footnoted source.146954 remainder active coal slurry impoundments (i.e., 1,600 – 646 = 954). Of these, this RIA estimates at least 158 active impoundments at 158electric utility plants, which impliesthat a fraction of 796 otheractive coal waste impoundments (i.e., 954 – 158 = 796) maybe located atelectric power plants in non-utility industries (see the next sub-section below on “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 6H, based 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 Pof 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 undereach 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 theproposed rule could increase the costestimates for each regulatory option by upto 28% (i.e., (495 + 139) / (495)).Source #2: EPA’s 2002 analysis134of 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 2Dof 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%.134Source: “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:.147Exhibit 6HIdentity 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#q5148Chapter 7Potential Benefits of CCR Disposal Regulation atElectric Utility PlantsThe potential benefits of CCR regulation identified in this chapter are based on three categories of risks which the proposed regulation isformulated to reduce, thereby providingfuture hazard risk reduction benefits:•Community safety benefits•Human health benefits•Ecological benefitsThe first category is largely based on engineering information from secondary published sources135and on EPA’s collection of historicaldamage cases associated with CCR disposalunits located at coal-firedelectric utility plants, and the second and third categories are based onsummary from EPA’s 2007 draft risk assessment for CCR disposal units.7A. Community Safety Benefits•Causes of Failures Involving Industrial Surface ImpoundmentsThousands of large industrial surface impoundments worldwide contain billions of tonsof mineral extraction and processing industry wastes.Over their operational lifespans, mostsurface impoundments are raised sequentially using the "upstream" construction method, following thelevel of the impounded waste duringthe filling process. This method, while available at low cost, implies a number of specific hazards forstructural stability. These hazards require assessment, monitoring and control during siting, construction, and operation of high-volume surfaceimpoundments. Examples of possible failuremechanisms (i.e., failure causes) are:136135EPA is aware of one additional published study not otherwise cited or applied in this RIA, which provides monetized estimatesof two potential community safety andhuman health benefits for EPA regulation of CCR disposal units: arecent (June 2009) report published by the Institute for Policy Integrity (IPI) provides an estimate of (a)reduced future cleanup costs associatedwith a reduction in the future probabilityof catastrophic failure of CCR impoundments,and (b) monetary value of reduced humanexposure to chemicals leaching from CCR disposal units. However, the IPI report doesnot derive a nationwide, average annualized future value for these potential benefitsfrom its presentation of single facility-based estimates. Source:“No More Excuses: The Economic Case for Coal Ash Regulation,” J.Scott Holladay, Institute for PolicyIntegrity, New York University School of Law, Policy Brief No.3, June 2009,40 pages at http://www.policyintegrity.org/publications/documents/NoMoreExcuses.pdf136Source: The following website provides color animations of these major failure mechanisms: “Safety of Tailings Dams,” WorldInformation Service on Energy (WISEis an information and networking center for citizens and environmental organizations concerned about nuclear energy, radioactive waste, radiation, and related issues):http://www.wise-uranium.org/mdas.html#DISAST149•Weak base: If the soil or rock at shallow depth below the dam is too weak to support the impoundment, movement along a failureplane will occur. This may result in partial or complete failure of the dam.•Earthquakes: During cyclic mechanical stressas experienced during seismic events, theslurries (including the material used for theimpoundment) may liquefy.•Over-filling: Excessive rises inthe level of the water ponding inthe impoundment can also causefailures. This level rise canbe causedby inflow from heavy rainfall or melting snow, or by overfilling or overtopping withexcessive slurry water.•Seepage: Piping occurs if seepage within or beneath the impoundment causes erosion along its flowpath. Excessive piping mayresult in local or general structural failure of the impoundment.•Overbuild: If the sides of an impoundment are raised too fast to add capacity, structural failure can occur from excessive porepressure within the impoundment.•Failures Involving Industrial Surface Impoundments in the USAAccording to one historical review137of “major failures” involving industrial surfaceimpoundments, in the USA, 28 of the 88 worldwidehistorical major failures (i.e., 32%) occurred in 13 states (AZ, CO, FL, KY, MD, MS, MT, NC, NM, NV, TN,TX, WV), representinganaverage annual rate of 0.6 major failuresper years (i.e., (28 incidents) / (48 yearhistorical period)). The 28 major failures involved thefollowing 9 industries:1.NAICS 21211 coal mining (n = 5)2.NAICS 212234 copper ore mining (n = 3)3.NAICS 212221 gold ore mining (n = 2)4.NAICS 212231 lead ore & zincore mining (n = 1)5.NAICS 212321 construction sand &gravel mining (n = 1)6.NAICS 212291 uranium ore mining (n = 2)7.NAICS 212399 gypsum mining, mica mining (n = 2)8.NAICS 221112 fossil fuel electric power generation138(n = 1)9.NAICS 325312 phosphate fertilizermanufacturing (n = 11)•Damage Cases Involving Electric Utility Industry CCR Surface Impoundments137Source: “Chronology of Major Tailings Dam Failures” at: http://www.wise-uranium.org/mdaf.html138This is the NAICS that is applicable to EPA’s CCR proposed rule.150The scope of the regulatory options addressedin this RIA is limited to NAICS 22 coal-fired electric utility plants. However,there are historicaleconomic, environmental, and human health damages, and baselinerisks associated with at leasttwo other out-of-scope categories ofimpoundments located at electricity utility plants:•Damages & risks from impoundments similar in size to those in other out-of-scope industries:One recent example is the 08 March 2009 pipeline rupture at a western Maryland paper mill (NAICS code 3221) that generates itsownelectricity, which spilled approximately 4,000 gallons of slurried coal ashinto the North Branch of the Potomac River, about 120 milesnorthwest of Washington DC. The Maryland spill occurred at New Page Corp., which powers its paper mill in Luke MD with a 60megawatt coal-fired plant and pipes slurried coal ash to a storage lagoon that it owns and operates across the river in West Virginia.The lagoon has a capacity of roughly 1.2 million gallons. (Source: The Bureau of National Affairs, Daily Environment Report, 11March 2009, Vol.45, page A-13: http://www.bna.com/products/ens/bder.htm).•Damages & risks from other types of out-of-scope secondarymaterials generated by the utility electricity industry:An example of this second category is the January 9, 2009, Tennessee Valley Authority (TVA) coalwaste spill at its Widows Creekplant in northeast Alabama, less than three weeks after the enormous Tennessee coal ash spill atTVA's Kingston Fossil Plant.Thespill, which TVA said originated from a gypsum treatment operation, released about 10,000 gallons of toxic gypsum material, some ofwhich spilled into Widows Creek and the nearby Tennessee River. Gypsum ponds contain limestone spray from smokestack scrubbers,which trap sulfur dioxide emissions beforethey are released into the air and turn them into sludgeand solid waste.Under the 1980 Bevill amendment for the “special waste” categories of the Solid Waste Disposal Act (also known as RCRA from its1976amendment), EPA was statutorily required to examine “documentedcases in which danger to human health or the environment has beenproved” from the disposal of the coal combustion residues. After publishing the1988 Report to Congress on “Wastes from the Combustion ofCoal by Electric Utility Power Plants139,” EPA received alleged damage cases from citizens and groups from 1988 to February 2005. EPAgathered or received information on 135 possible damage cases and has evaluated 85 of these cases. Of the 85 cases evaluated,EPAdetermined that 24 were proven cases of damage.140Forty-three cases were determined to bepotential damages to ground water or surfacewater and 18 cases were determined to be rejected. The 67 proven and/or potential damage caseswere reported in the July 2007EPA “Coal139EPA -OSWER1988 Report to Congress: “Waste from the Combustion of Coal by Electric Utility Power Plants,” report nr. EPA/530-SW-88-002, available fromhttp://www.regulations.govas document ID nr. EPA-HQ-RCRA-1988-0094-0035, 500 pages. The companion Appendices are available as document ID nr. EPA-HQRCRA-1988-0094-0036.140EPA applied the following three criteria for classification of thedamage cases in the July 2007 CCR damage case report. Thesecriteria are from EPA’s May 2000Regulatory Determination (Federal Register, Vol. 65, p. 32224):•Documented exceedances of primary MCLs orother health-based standards measured inground water at sufficient distance from thewaste management unit toindicate that hazardous constituents have migrated to the extent that they could cause human health concerns, and/or•Where a scientific study demonstrates there is documented evidence of another type of damage to human health or the environment(e.g., ecological damage), and/or•Where there has been an administrative ruling or court decision with an explicit finding of specific damage to human health orthe environment. In cases of comanagement of CCRs with other industrial waste types, CCRsmust be clearly implicated in the reported damage.These three criteria resulted in 24 proven damage cases and 43potential damage cases, for a total of 67 damage cases listed inthe July 2007 report.151Combustion Waste Damage Case Assessment” report available athttp://www.publicintegrity.org/assets/pdf/CoalAsh-Doc1.pdfdocket ID nr.EPA-HQ-RCRA-2006-0796. The damage cases span the 61-year historical period from 1948 to 2008.For purpose of summarizing these historicalCCR damage cases in this RIA, this RIA presents a summary of the quantitative characteristics(i.e., physical and cost indicators) reported in the documentation for some of the cases listedin the July 2007 damage case report, updated withtwo more recent damage cases. The followingsteps describe how the quantitative indicators were obtained for summary in this RIA.Step 1:Reviewed the 67 damage cases in July 2007report to determine and obtain the quantitative indicators reportedin the cases.Because only a small number of the writtencase descriptions in the 2007 report contained quantitative information, searchedfor background documentation for the cases in the July2007 report, which yielded the following documents:•Memorandum from November 29, 2000 toDennis Ruddy, EPA from Pat Ransom and Rich Pierce, SAIC entitledReview of Causative Factors for Coal Combustion Waste Damage Cases•Memorandum from April 20, 2000 to Dennis Ruddy, EPA fromJennifer Cohen and Pat Ransom, SAIC entitledAdditional Information Regarding FossilFuel Combustion Waste Damage Cases•Memorandum from April 20, 2000 to Dennis Ruddy, EPA fromJennifer Cohen and Pat Ransom, SAIC entitledRationale and Conclusions Regarding Commenter-Identified Fossil Fuel Combustion Waste Damage Cases•Memorandum March 5, 2003 to Dennis Ruddy, EPA from Pat Ransom and Sara Dennis, SAIC entitled Final RevisedReport on Resolution of 18 Previously Indeterminate Candidate Damage CasesStep 2:Obtained information about three additional CCR damage cases not listed in the July 2007damage case report: (a) theDecember 2008 TVA Kingston TN damage case, (b) the January 2008 Constellation Energy Gambrills MD damage case,and (c) the August 2005 PPL Martins Creek PApower plant damage case. Furthermore,in the Step 1 review of the July2007 report, identified four cases which apparently pertain mainly to oil waste release damages rather than to CCR damages(i.e., FP&L Port Everglades, FP&L Rivera, FPC P.L. Bartow, Brayton Point).Addition of the three recent cases andsubtraction of the fouroil cases resulted in66 relevant CCR damage cases from 1948 to 2008(i.e., 27 proven damagecases including TVA TN, Martins Creek PA, Gambrills MD, plus 39 potential CCR damage cases).Step 3: Review of the July 2007 report, background documents, and threerecent cases resulted in the data elements listed below forwhich some cases contained data.Appendix Qof this RIA presents a table of thedata extracted from these damage cases.1.Case ID number2.State location3.Site name4.Active or inactiveCCR disposal unit5.Reference year (i..e., year associated with contamination event or year of contamination discovery)6.Type of CCR disposal unit involved7.Lined or unlined CCR disposal unit1528.CCR disposal unit onsite or offsite9.Site acres10.CCR disposal unit operating lifespan11.Tons CCR released12.Acres of contamination13.First year of cleanup14.Count of homes damaged15.Off-site contamination16.Fish kill•Summary of Electric Utility CCRDisposal Damage Case FindingsExhibit 7Abelow provides a state-by-state count of damage cases and count of associated CCR disposal units in the 22 states that had provenor potential damage cases reported in EPA’s July 2007 “Coal Combustion Waste DamageCase Assessment” report. Although the July2007report contains 85 cases, not all ofthem are actually relevant to CCR disposal units, as explained above.Exhibit 7AState-by-State Count of Historical CCR Disposal Damage Cases1948-2008ItemStateCount of CCRdamage casesCount of CCR disposal unitsidentified in damage cases1 AZ 1 12 FL 1 13 GA 1 14 IA 1 15 IL 8 86 IN 7 77 KY 1 18 MA 3 39 MD 2 310 MI 1 311 MN 1 112 NC 3 313 ND 3 414 NY 4 415 OH 3 316 PA 2 217 SC 2 3153Exhibit 7AState-by-State Count of Historical CCR Disposal Damage Cases1948-2008ItemStateCount of CCRdamage casesCount of CCR disposal unitsidentified in damage cases18 TN 5 519 TX 3 320 VA 2 321 WI 11 1122 WY 1 2Column totals=66(average = 1.08cases per year)73(average = 1.20 disposalunits per damage case•Of the total of 66 damage cases there were:o30 known off-site contamination caseso21 known on-site contamination caseso15 cases that did not statewhether the contamination was on-site or off site.•As counted inExhibit 7Bbelow, four different typesof CCR disposal units were involved in the damage cases:o24 impoundments (aka ponds, settling basins,dams, embankments, constructed wetlands)o21 landfills (this includes at leastone case in which the CCR landfill wasformerly a “gravel quarry pit”)o5 sand & gravel pits (aka quarries)o1 ash pileo22 units not classifiedThe count of 73 CCR disposal units does notinclude all units associatedwith the 66 damage cases because some cases indicatedthere weremultiple units but did not provide a count of units. For exampleif the word “ponds” was used in some damage cases but it wasnot clear howmany ponds were related to thosecases; only one pond was counted inExhibit 7Bbelow. According to operational status there were:•Active: 7 active CCR disposal units (i.e., 29% of known operating status units)•Inactive: 18 inactive CCR disposal units (i.e., 71% of known operating status units). This RIA assumed a CCR disposal unit wasinactive if the unit was stated in the damage case as no longer being used for disposalor if a cap was placed on the unit.•Unknown: 48 CCR disposal units involved in the damage caseswere not clearly defined aseither activeor inactive.Exhibit 7B,Exhibit 7CandExhibit 7Dbelow summarize the quantitative data from the damage cases.154Exhibit 7BState-by-State Counts of CCR Disposal Units Involve d in the 1948-2008 Damage Cases (61-year historical period)ABCDEFGHItemStateLandfillPond (aka impoundmentor settling basin)Sand, GravelPit or QuarryAshPileUnknownTypeRow Totals1AZ0100 0 12FL00001 13GA0100 0 14IA1000 0 15IL2100 5 86IN2200 3 77KY1000 0 18MA3000 0 39MD1110 0 310MI1000 2 311MN0000 1 112NC0100 2 313ND0301 0 414NY1000 3 415OH1100 1 316PA1100 0 217SC0200 1 318TN0300 2 519TX0300 0 320VA0210 0 321WI5230 1 1122WY2000 0 2Column Totals =(% of known types)21(41%)24(47%)5(10%)1(2%)2273(51 known disposalunit types)Counts if proportionatelyextrapolated to all 73 units30 34 7 1 073Average annual frequencyOver 61-year historicalperiod 1948-20080.49 0.56 0.12 0.021.20155Exhibit 7CPhysical Characteristics of CCR Disposal Damage Cases (1948-2008)Data TypeSite AcresCCR DisposalUnit OperatingLifespan (years)Tons of CCRReleased fromDisposal UnitAcres ofContaminationNumber ofHomesDamagedMaximum 235 23 10.0 million* 275 55Minimum 8.5 8 80 13 40Count of cases with data 9 8 2 3 2Average per case 75 14 5.0 million 103 48* Note: 10.0 million tons represents the reported 5.4 million cubic yard release December 2008 at the TVA Kingston TN plant,multiplied by 1.85 short tons per cubic yard average density for all types of coal ash.Exhibit 7DSummary of Types of CCR Disposal Damage Case Contamination (1948-2008)Type of ContaminationProven Damage CasesPotential DamageCasesRow Totals(% of known types)Ground Water 18 25 43 (69%)Surface Water 10 3 13 (21%)Wetlands 4 0 4 (7%)Dust 2 0 2 (3%)Unknown Type of Contamination 2 13 15Totals = 34 4177* (62 known types)* Note: Some damage cases had multiple types of contamination so the total count of types of contamination in this tableexceed the total count of damage cases.Although the 1976 RCRA statute doesnot require benefit-cost justification of RCRA regulations, OMB’s 2003 “Circular A-4: RegulatoryAnalysis” best practices guidancestates (pages 18 and 27) that:“[RIAs] should discuss the expected benefits and costs of the selected regulatoryoption and any reasonablealternatives... Youshould monetize quantitative estimates wheneverpossible.... If you are not able to quantify the effects [benefits and costs], youshould present any relevant quantitative information along with a description of theunquantified effects,such as ecologicalgains, improvements in quality of life, and aesthetic beauty.”The historical damage case summary information provided inExhibit 7A, Exhibit 7CandExhibit 7Dabove may be used to formulate a semiquantitative estimate of baseline average annual damage cases and associated damage costs. The expected benefits of RCRA regulation arepotential reduction in the baseline frequency of cases and costs. Over the 61-year period 1948-2008 there have been 66 confirmed damagecases involving CCR disposal units, which represents a baseline average frequency of1.08 cases per year (i.e., (66 cases) / (61 years)). Based156on incomplete economic damage data from those cases, and using the actual average per-acre cleanup cost from a 2008 damage case(TVAKingston TN), indicates the following baselineaverage annual damage costs for cleanup:(1.08 cases per year) x (31% known cases involving surface water, wetlands, dust requiring cleanup, which excludes 69% of knowncases that only involved groundwater contamination) x (average 103 acres contamination per damage case) x ($3.4 million to $4.4million per acre)141=$117 million to $152 million per year.However, cleanup costs do not represent all economic damages, sothis is an underestimate because it does not include baselinecosts for atleast eight other categories of economic damages:1.Damages to local infrastructure (roadways, water supply, energy supply, sewerage, telecommunications)2.Lost sales and service revenues from business closures (temporary or permanent)3.Lost employment from business closures (temporary or permanent)4.Damages to housing, community buildings (churches, schools), parks5.Damages to landscape aesthetic values6.Damages to human health7.Damages to ecosystems8.Damages to environmental attributes (e.g., natural resources)141Initially (Feb 2009), TVA estimated the cost of clean-up for the Kingston TN plant coal ash spill (22 Dec 2008) could cost between $525 million and $825 million. Thecost depended on the disposal method of the 5.4 million cubicyards of ash that spilled affecting 275 acres. The range does not include costs for items such as regulatoryactions, litigation or long-term environmental remediation. Source: Waste & Recycling News, 13 Feb 2009;http://www.wasterecyclingnews.com/email.html?id=1234543579 On 18 Aug 2009,TVA published a revised estimate of cleanup costs:“Due to the uncertainty at this timeof the final methods of remediation, a range of reasonable estimates has been developed by cost category and either the known amounts, most likely scenarios, or the lowend of the range for each category has been accumulated to determine the total estimate. The range of estimated costs varies from approximately $933 million toapproximately $1.2 billion.” This implies an average unitized cost for clean-up of $3.4 million to $4.4 million per acre. .Source: page 13 of “TVA 10Q Filing for Q3FY2009”, 18 Aug 2009 at http://www.tva.gov/kingston/admin_record/pdf/51.pdf157Exhibit 7Ebelow provides a summary of the state location, name of electric utility plant, type of CCRdisposal unit, type ofcontamination, and types of chemical contaminants identified for each of the 66 damage cases involving at least 73 CCR disposalunits.Exhibit 7EUnit-by-Unit Summary of 1948-2008 CCR Damage Cases Involving at Least 73 CCR Disposal UnitsABCDEFRowitemStateDamage casesite name(Electricity plant)Type of CCR disposalunit involved in damageType ofcontaminationChemical contaminants reported in damage case1 MA Salem Acres Site landfillGroundwater,wetlandspolycyclic aromatic hydrocarbons (PAHs), PCBs,dioxins/furans, volatile organic compounds (VOCs),chromium, arsenic, beryllium, vanadium, thallium2 MA City of Beverly/Vitale Brothers Fly Ash Pit landfillGroundwater,surface water, dust arsenic,iron, manganese, selenium3 NY Don Frame Trucking, Inc. FlyAsh Landfill Groundwater lead4 VA Virginia Electric Power Co. Possum Point pond cadmium, nickel5 VA Virginia Electric Power Co. PossumPoint pond Groundwater cadmium, nickel6 MDPEPCO Morgantown Generating StationFaulkner Off-site Disposal FacilitylandfillGroundwater,surface water,wetlands7 MDPEPCO Morgantown Generating StationFaulkner Off-site Disposal Facility pondGroundwater,surface water,wetlands8 VAVirginia Power Yorktown Power StationChrisman Creek DisposalSite sand & gravel pitGroundwater,surface watervanadium, selenium, arsenic, beryllium, chromium,copper, molybdenum, nickel9 NC Hyco Lake Roxboro pond selenium10 GA Georgia Power Company Plant Bowen pond Surface water11 TNDOE Oak Ridge Y-12 Plant Chestnut RidgeOperable Unit 2 DOE Oak Ridge Reservation,Oak Ridgepond Surface waterAl, Fe, Cu, As, Ca, Mn, K, Na, Ba, Ca, Cr, Pb, Mg,V, Zn, Hg, Se12 SC South Carolina Electric & Gas Canadys Plant pond Groundwater nickel13 SC South Carolina Electric & Gas Canadys Plant pond arsenic14 NC Belews Lake selenium15 SC U.S. DOE Savannah River Project16 WIDairyland Power Cooperative E.J. StonemanGenerating Station Ash Disposal Pond pond Groundwater sulfate, boron17 WI WEPCO Highway 59 Landfill sand & gravel pitWetland, groundwatersulfate, boron, manganese, chloride, iron, arsenicchloride, selenium18 WI Alliant Nelson Dewey Ash Disposal Facility Settling basins Groundwater arsenic, selenium, sulfate, boron, fluoride, sulfate19 WI WEPCO Cedar-Sauk Landfill sand & gravel pitGroundwater,wetland selenium, sulfate, boron,20 WI WEPCO Port Washington Facility Quarry Groundwater boron, selenium158Exhibit 7EUnit-by-Unit Summary of 1948-2008 CCR Damage Cases Involving at Least 73 CCR Disposal UnitsABCDEFRowitemStateDamage casesite name(Electricity plant)Type of CCR disposalunit involved in damageType ofcontaminationChemical contaminants reported in damage case21 MILansing Board of Water& Light NorthLansing Landfill landfill Groundwater lithium, manganese, potassium, selenium22 MILansing Board of Water & Light NorthLansing LandfillNA (not used fordisposal)23 MILansing Board of Water& Light NorthLansing Landfill lithium, manganese, potassium, selenium24 INNIPSCO Yard 520 Landfill Site Township ofPineslandfill Groundwater benzene, arsenic, manganese, boron, lead25 TX Brandy Branch Reservoircooling reservoirreceived discharge fromash ponds Surface water selenium26 TXSouthwestern Electric Power Company WelshReservoircooling reservoirdischarge from an opensettling pondSurface water selenium27 TX Texas Utilities Electric Martin LakeReservoir ponds Surface water selenium28 NDBasin Electric Power Cooperative W.J.Station Surface Impoundment impoundment Groundwater29 NDCooperative Power Association/ UnitedPower Creek Station Surface Impoundmentspond30 NDCooperative Power Association/ UnitedPower Creek Station Surface Impoundments pond Groundwater arsenic, selenium, sulfate, chloride, boron31 MARezendes South Main Street Ash Landfill,Freetown landfill Groundwater sulfates, manganese, iron, aluminum32 NYAES Creative Resources Weber Ash DisposalSiteGroundwater sulfate, manganese, iron, aluminum and pH33 NYCentral Hudson Gas and Electric CorporationDanskammer Waste Management Facilitysulfate, sulfide, dissolved solids, turbidity, iron,magnesium, manganese, sodium, boron, and pH34 NY C.R. Huntley Fly ash Landfill landfill Groundwaterarsenic, iron, manganese, sulfate, total dissolvedsolids35 PA Elrama Plant landfill Groundwater cadmium36 TNTennessee Valley Authority Bull Run SteamPlant, Oak Ridge Surface wateraluminum, calcium, iron, sulfate37 TNTennessee Valley Authority Widows CreekFossil Fuel Plant AlabamaGroundwater cadmium, chromium38 TNTennessee Valley Authority Colbert FossilFuel Plant, Alabamaimpoundment Groundwater cadmium,sulfate, chromium, selenium39 NC Duke Power Allen Steam Generating Plant Groundwater manganese, iron40 KY Cinergy East Bend Scrubber Sludge Landfill landfill dissolved solids, iron, sulfate159Exhibit 7EUnit-by-Unit Summary of 1948-2008 CCR Damage Cases Involving at Least 73 CCR Disposal UnitsABCDEFRowitemStateDamage casesite name(Electricity plant)Type of CCR disposalunit involved in damageType ofcontaminationChemical contaminants reported in damage case41 FL Florida Power and Light Lansing Smith Plant Ground watercadmium, chromium, fluoride, sulfate, chloride,manganese42 ILCommonwealth Edison Powerton PlantMahoney Landfill Pekin Tazewell Countylandfill Ground water cadmium, lead, nitrate, iron, manganese, sulfate43 MNXcel Energy Southern Minnesota MunicipalPower Agency Sherburne County (Sherco)Generating Plant Beckerarsenic, cadmium, chromium, fluoride, lead, andnitrate, chloride, copper, iron, manganese, sulfate,zinc44 WI Alliant Rock River Ash Disposal FacilityGround water arsenic, mercury, sulfate, iron45 IN Michigan City Site, Michigan City pond Ground water arsenic46 IN Bailly Generating Station pond Groundwater arsenic, lead, cadmium47 WI Alliant Edgewater 1-4 Ash Disposal Site landfill Ground water boron, sulfate, iron, chloride48 WIWisconsin Power Supply Co (WPSC) PulliamAsh Disposal Site landfill Ground water sulfate, manganese, iron49 IL Central Illinois Light Co Duck Creek Stationsulfate, total dissolved solids, chloride, manganese,iron50 IL Illinois Power Co. Hennepin Power Station Groundwater sulfate, total dissolved solids51 IL Illinois Power Co Havanna Power Plant impoundment manganese, sulfate52 WIDairyland Power Alma On-site Fly AshLandfilllandfill Groundwater sulfate, manganese53 WIDairyland Power Alma Off-site Fly AshLandfill landfill sulfate, manganese, boron54 IL Illinois Power Vermillion Power Station Groundwater sulfate, total dissolved solids55 ILCentral Illinois Public Service CompanyHutsonville Power Station Groundwater sulfate, total dissolved solids, manganese56 ILIllinois Power Company Wood River PowerStationGroundwatersulfate, total dissolved solids, chloride, manganese,iron57 IN R.M. Schahfer Generating Station sulfate58 ILCoffeen/White & Brewer Trucking Fly AshLandfill landfill Sulfate, total dissolved solids, manganese59 INSouthern Indiana Gas and Electric Company(SIGECO) A.B. Brown Generating StationSulfate total dissolved solids, chloride, pH60 OHCincinnati Gas & Electric Co MiamiviewLandfill landfill Sulfate61 INIndiana Power & Light Peterburg GeneratingStation sulfate, total dissolved solids62 INHoosier Energy Mermon Generating StationCoal Combustion Waste Landfilllandfill Groundwater barium, chromium, cadmium, lead, sulfate, chloride160Exhibit 7EUnit-by-Unit Summary of 1948-2008 CCR Damage Cases Involving at Least 73 CCR Disposal UnitsABCDEFRowitemStateDamage casesite name(Electricity plant)Type of CCR disposalunit involved in damageType ofcontaminationChemical contaminants reported in damage case63 OH Cinergy W.C. Beckjord Station Groundwater sulfate64 WI Lemberger Landfill landfillGround water,surface watervolatile organic compound, arsenic, barium,chromium, cadmium, lead65 OH Conesville Fixed FGD Sludge Landfill pondlead off-site, (chromium, sulfate, arsenic, cadmium,selenium on-site)66 IA Muscatine County Landfilllandfill sulfate, selenium67 WY Dave Johnston Power Plant landfill Ground water cadmium, manganese, sulfate68 WY Dave Johnston Power Plant landfill69 NDMontana Dakota Utilities R.M. HeskettStation pile Ground water sulfate, boron70 AZArizona Public Service Co. Cholla SteamElectric Generating Stationpond Groundwater sulfate, total dissolved solids, chloride, fluoride71 TN TVA pond Surface water arsenic72 PA Martin's Creek PA Power Plant Pond Surface water73 MD Constellation Energy Gambrills MD quarry Groundwater, dustArsenic, beryllium, sulfate, Mn, lead, cadmium,thallium, aluminum, manganeseNote: Blank cells in this table indicate that information was not readily available.1617B. Human Health BenefitsThis section describes some of the humanhealth hazard risks which RCRA regulation ofCCR disposal may reduce. This section ofthe RIA isbased on information published in EPA’s 1998 and 2009 CCR riskassessment studies referenced in the Federal Registerannouncement for theCCR proposed rule. Complete references and details for thesummarized information below are provided in those studies.Human health risks to human individuals may occur from exposure to chemical constituents in CCR. Exposure may occur through anumber ofexposure routes. Potential chemical constituent releases from CCR landfills andsurface impoundments include:•Leaching of CCR to ground water•Overland transport of CCR from erosion and runoff•Air emissions of CCRThe potential of exposure from any one of these exposure pathwaysfor a particular chemical isdependent on the physical and chemicalcharacteristics of the chemical, the properties of the waste stream, and the environmental setting. EPA conducted a peer-reviewed riskassessment of potential human health risks from CCR constituents leaching to groundwater that subsequently migrates either to anearbydrinking water well, or to nearby surface water, and is ingestedas drinking water or through fish consumption. EPA also performedpreliminary analysis of human health effects from constituentsthat have eroded or run off fromwaste management units, and ofhuman healtheffects from breathing windblown particulate matter from landfill disposal.Longstanding EPA policy is for EPA risk assessments to includea characterization of risks attwo points on a distribution, orrange, of riskestimates:•Central tendency risk estimate: Represents conditions likely to be encountered in atypical exposure situation•High-end risk estimate: Representsconditions likely to be encounteredby individuals with higher exposures.142Examples of factors that wouldinfluence a nearby resident’s exposure are the residence’s distancefrom a CCR disposal unit, and anindividual’s behavioror activity patterns. In EPA’s 1998 CCR risk assessment the high end risk estimates were developed using95thpercentileinput values for certain variables,while in EPA’s 2009 risk assessment the high end risk estimates are the 90thpercentile estimates from aprobabilistic analysis.The comparisons that EPA uses to judge whether either a high-endor central tendency estimated riskis of concern are the riskcriteria.142For additional information about risk estimation see EPA’s “Guidance for Risk Characterization”, 1995 athttp://www.epa.gov/OSA/spc/pdfs/rcguide.pdf, which statesthat “For the Agency's purposes, high endrisk descriptors are plausible estimates of the individual risk for those persons atthe upper end of the risk distribution” or with“exposure above about the 90th percentile of the population distribution.” The 50th percentile represents the “central tendency” estimate of the risk distribution.162•Cancer risk: For purpose of evaluating actual or potential human individual cancer risk, EPA’s risk criteria are in the rangeof one in onemillion (i.e., 0.000001 or 1.0 x 10^-6) “excess” probability of developing cancer during a lifetime, to one in ten thousand (i.e., 0.0001),143with one in one hundred thousand (i.e., 0.00001)being the “point of departure” for listing a waste as a RCRA hazardous waste under the 40CFR 261 Subpart B listing criteria.•Non-cancer risk: For human non-cancer hazard,the risk criterion is an estimated exposure above the level at which no adversehealtheffects would be expected to occur. Therisk is expressed as a ratio of the estimated exposure to the exposure at which it islikely that therewould be no adverse health effects; thisratio is also called a hazardquotient (HQ), and a risk of concern equates to a HQ greater than one,or in certain cases of drinking water exposure, water concentrations above the Maximum Contaminant Level (MCL) established under theSafe Drinking Water Act.The exposure pathways for humans that EPA has evaluated for CCR landfills and surface impoundments are nearby residents’ groundwateringestion and air inhalation, and fish consumption by recreational fishers:•Ground Water IngestionChemical constituents can leach from CCRsin landfills and impoundments into the ground water and subsequently be ingested by individualswho rely on well water. Some ofthe chemical constituents (e.g., arsenic) thatwere modeled in EPA’s risk assessment exceededthe riskcriteria, including the “point of departure” for listing as a hazardous waste, for the high end receptor. Additionally, the Agency has provenevidence that such potentially toxic constituents have leached from CCR disposal units into ground water at levels exceeding primary drinkingwater standards. Comparing the results from the 2009 risk assessment with the CCR damage cases indicates that the risk assessment estimatesgroundwater exceedances for some of the same constituents found inthe damage cases (i.e., arsenic, boron, cadmium, lead, molybdenum, andselenium).•Air InhalationAir emissions from CCR disposal sites canoriginate from CCR unloading operations, CCR spreading and compacting operations, resuspension of particulates from vehiculartraffic, and from wind erosion. Air inhalation exposures may cause adverse human health effects,either due to inhalation of small-diameter(less than 10 microns) “respirable” particulate matter that causes adverse effects such as triggeredasthma attacks or increased mortality (and for which National Ambient Air Quality Standards for particulate matter have been established,under the Clean Air Act), or due to toxic effects of these respirable particles. AtCCR landfills, the highest estimated riskvalue was anindividual excess lifetime risk of 4 in one million for farmers, due to inhalation of chromium (all chromium present in the particulate matterwas assumed to be in the more toxic, hexavalent form). ForCCR impoundments, the highest risk value was 2 in one million for the farmer(again assuming all chromium present was hexavalent).143See 40 CFR 300.430.163•Fish ConsumptionExposure for this pathway stems from human consumption of fishthat are caught in surface waterbodies, such as streams, rivers, and lakeslocated near CCR landfills or surface impoundments. There are several ways in which a nearby surface water body, and consequently the fishin that water body, could become contaminated due to CCR disposal activities:•Runoff and erosion from the CCRlandfill or surface impoundment•Direct deposition of airborneCCR particles (i.e., CCR dust)•Migration of CCR contaminated groundwater from underneaththe CCR disposal units intothe nearby surface water•Direct discharge (effluent) from CCR impoundments – either intentional (e.g., NPDES permitted) discharges or unintentional (e.g.,structural failure with flooding release) dischargesFor example – although it did not cover electric utility plants in itsnational survey design --EPA’s 2001 national inventorysurvey of industrialsurface impoundments144states that out of the entire group of non-hazardous, industrial surface impoundments from non-Bevill exempteconomic sectors, an estimated 25% of allof these facilities had anindustrial waste disposalimpoundment overtopping event which occurredwhere there is significant precipitation,or impoundment structural failure. Anestimated 20% of the population of non-hazardous industrialimpoundments has fishable water bodies within 150 meters (i.e., about one-tenth of amile) of the impoundment. And approximately 20% ofimpoundments with fishable water bodies within 150 metersexperienced an impoundment overtopping event.Once CCR constituents are in surface waters,fish may absorb the dissolved constituents during normal respiration across the gills. In addition,contaminants that concentrate in the sediments may be introduced into fish through the food chain. Contaminants can accumulatein fish fromeither or both of these exposure vehicles depending on the chemical’s potential for bio-concentration and bio-accumulation.EPA’s 2009 risk assessment addresses potentialhuman health risks from eating fish thatare contaminated due to the third potential surfacewater contamination mechanism: contaminated groundwater thatmigrates from underneath the CCR landfill or impoundment and affectsnearby surface water bodies.•The high end results from this assessment indicate that arsenic migrating from surface impoundments may pose cancer risks in the range ofconcern (individual excesslifetime cancer risk of two in onehundred thousand for unlined units and seven in one million for clay-linedunits).•The high end non-cancer hazard estimate for selenium migrating from unlined surface impoundmentswas above the HQ risk criterion of1.0.•The central tendency results from this assessment do not indicate cancer or non-cancerrisks in the range of concern.144Source: Page 2-26 (section 2.3.2.4) of EPA OSWER “IndustrialSurface Impoundments in the UnitedStates,” report nr. EPA530-R-01-005, March 2001,http://www.epa.gov/waste/hazard/tsd/ldr/icr/index.htm1647C. Ecological BenefitsThis section describes some of the ecological hazard risks which RCRA regulation of CCRdisposal may reduce. This section is also based oninformation published in EPA’s 1998 and 2009 CCR risk assessment studies. Complete references and details for the informationsummarizedbelow are available in those studies. For ecological non-cancer hazards that are modeled, the risk criterion is a hazard quotient that representsimpacts on individual organisms, with a riskof concern being an estimated hazard quotient either greater than one. In some instances EPA alsoconsidered documented evidence of ecological harm, such as field studies published in peer-reviewed scientific literature. Such evidence issufficient to determine adverse ecologicaleffects in lieu of or in addition tomodeling potential ecological risks.Two types of exposures can occur for ecological receptors:•Exposures in which ecological receptorsinhabit a CCR disposal unit directly•Exposures in which CCR or its chemical constituents migrate,or move, out of the CCR disposal unit and contaminate nearby soil,surfacewater, or sedimentFor exposures in which ecologicalreceptors directly inhabit aCCR disposal unit, EPA’s 1998 risk assessment found that seven chemicalconstituents present in utility CCR managed in impoundments may pose adverse effectson organisms that inhabit those impoundments:1.Aluminum (amphibians)2.Arsenic (birds)3.Boron (amphibians)4.Cadmium (mammals)5.Lead (mammals)6.Mercury (birds)7.Selenium (mammals & amphibians)There are at least seven recent(i.e., 1978-2002) references in peer-reviewed scientific literature specific to CCR managed insurfaceimpoundments that confirm and extend EPA’s 1998 risk assessmentresults showing deformities and reproductive effects in amphibians livingon or near CCR disposal sites and other impacts on aquatic organisms and communities.In addition, seven of the 24 (i.e., 29%) proven damages to surface water identified in EPA’s July 2009 CCR damage case report wereecological damages to fish, frogs, and other wildlifeas a result of discharges from CCR impoundments.•In five of these seven cases, lakes constructed as cooling watersources for coal-fired power plants received discharges from the plants’CCR settling ponds containing elevated levels of selenium resultingin elevated levels of selenium in fish in the lakes.•In another damage case, CCR was disposed of in a nearby quarryfrom 1967 to 1990. Concentrations of selenium, arsenic, and possiblythallium were elevated in largemouth bass from the quarry relative to bass from anothernearby site and some fish from the quarry had165deformed bony structures. Higher concentrations of arsenic, selenium and lead were also found in small animals around a CCR pond thanin animals from a reference site.•Finally, at another site, CCR wassluiced (transported in water) tosettling basins. A continuousflow of sluice water exitedthe basins into aswamp which discharged into a stream. Observations of bull frog tadpoles inhabiting the settling basins and swamp revealed deformitiesand impaired swimming and predator avoidance abilities. Many studies suggested that effects were caused by the properties of CCR (e.g.,low pH; siltation; high soluble salts concentration; pozzolanic action), aswell as the trace metals in the CCR.