### MEMORANDUM

TO: Steam Electric Rulemaking Record

FROM: TJ Finseth, ERG Deb Bartram, ERG Liz Sabol, ERG

DATE: 19 April 2013

SUBJECT: Steam Electric NSPS Costs Methodology

1. I NTRODUCTION /B ACKGROUND

ERG is providing technical support to the U.S. Environmental Protection Agency’s Office of Water, Engineering and Analysis Division (E AD) for development of effluent limitations guidelines and standards (ELG) for the Steam El ectric Power Generating Industry. EPA, with the support of ERG, developed estim ates of the industry costs to comply with various regulatory options. The estimates were prepared for both exis ting sources that would be subject to revised best available technology economically achieva ble (BAT) effluent limitations and new sources that would be subject to revised new source pe rformance standards (NSPS) effluent limitations. The purpose of this memorandum is to descri be the methodology and calculations used to estimate compliance costs for newly constructed un its or plants subject to the revised NSPS.

ERG evaluated the capital and operating and main tenance (O&M) costs associated with the proposed NSPS regulatory options. The costin g methodologies used in this NSPS costing analysis are the same as those used in estima ting costs for existing sour ces subject to revised BAT effluent limitations, except where noted below. For more information on the cost methodology for existing sources, see EPA’s Incremental Costs and Pollutant Removals for Proposed Effluent Limitation Guidelines and Sta ndards for the Steam Electric Power Generating Point Source Category [U.S. EPA, 2013]. However, the estimates of costs to comply with BAT were based on plant-specific characteristics, such as current treatment in place, wastewater flow rates, and ash generation rates. Because the NSPS analysis is fo r newly constructed units at new or existing plants, the specific characterist ics of the units are unknown. Therefore, ERG developed model units to estimate the NSPS costs. This memorandum describes ERG’s assumptions used for this NSPS costing analysis.

2. NSPS T ECHNOLOGY O PTIONS

EPA is considering regulatory op tions for the control of wastewat er discharges from new sources

associated with the construction of a new unit at an existing or new plan t. The technology bases for these options are:Memorandum April 19, 2013 Page 2

 FGD Wastewater

— Chemical Precipitation

— Chemical Precipitation and Biological Treatment

— Chemical Precipitation and Va por-Compression Evaporation

 Bottom Ash Transport Water

— Mechanical Drag System (MDS)

 Coal Combustion Residue (CCR) Landfill Leachate

— Chemical Precipitation

— Chemical Precipitation and Biological Treatment

There are no incremental NSPS costs fly ash tr ansport water because th e existing NSPS (40 CFR 423.15(g)) already requires no discharge of po llutants in fly ash transport water.

There are no incremental NSPS costs for the treat ment of gasification wastewater because the technology option being considered for NSPS is the technology that is curre ntly in place at the two currently operating IGCC units and the one IG CC unit that is currently being constructed. Because the treatment technology is standard practice in the i ndustry and because an IGCC unit is now being constructed using the proposed tr eatment technology, ERG believes that there is no barrier-to-entry for the proposed treatment technology.

There are no incremental NSPS costs for the tr eatment of flue gas me rcury control (FGMC) wastewater for the following three reasons:

1. The FGMC wastes are typi cally collected with the fly ash in the primary particulate collection device (e.g., fabric filter) and because the current NSPS regulation for fly ash transport water requires no discharge of wastewater pollutants, the FGMC wastes would be handled in the same fashion.

2. If the plant decided to remove most of the fly ash prior to injecting the sorbent for the mercury collection, then the plant w ould need an additional particulate

collection device to collect the FGMC waste; however, there is still some amount of fly ash that would be collected in the particulate collection device and would therefore, still be applicable to the N SPS regulation for fly ash transport water.

3. In the situation described for number 2 above, the plant would typically only collect the fly ash prior to injecting the sorbent for mercury collection if the plant was planning to sell the fly ash; ther efore, the plant would likely have an

additional revenue stream from the sale of the fly ash that would off-set the cost of the separate FGMC handling system.

There are no incremental NSPS costs for the tr eatment of nonchemical metal cleaning wastes because the proposed NSPS requirements are equal to the BPT requirements for existing sources.

There are no incremental NSPS costs for oil-fired units for the following reasons:

 Based on the data obtained from responses to the Questionnaire for the Steam

Electric Power Generati ng Effluent Guidelines (Steam Electric Survey), there are no oil-fired units that op erate wet FGD systems;Memorandum April 19, 2013 Page 3

 For the 25 oil-fired units th at reported generating bottom ash in the Steam Electric Survey, only three units reported some t ype of wet handling of the bottom ash;

and

 Based on Steam Electric Survey data, ERG de termined that no plants classified as “oil” or “combination” operate CCR landfills with leachate collection systems.

3. NSPS S CENARIOS

The construction of new generating units may occur at an existing power plant or at a new plant

construction site. The cost associated with co mplying with the proposed NSPS options will vary depending on the types of waste management system s already in place at existing plants and/or the assumed waste management system that woul d be installed in the absence of the proposed NSPS regulations. Therefore, ERG estimated cap ital and O&M costs for eight scenarios that represent the different types of operations that may be present at an existing power plant or assumed to be built at new power plants. Tabl e 1 presents the assumed plant and unit-level

characteristics for each of these scenarios:

Plant-Level Characteristics

 Plant Status . Identifies the status of the pl ant receiving the new source costs.

Because the new source costs reflect the in stallation of a new unit, the status of the plant can be identified as a new green field installation vers us existing plant.

 Impoundment . Identifies the different impoundment options applicable to a new or existing plant. These im poundment options include:

— No impoundment exists prior to construction of a new plant;

— No impoundment at an existing plant;

— An existing impoundment at an existi ng plant with capacity for additional CCR; or

— An existing impoundment at an ex isting plant with no capacity for

additional CCR.

 Landfill . For all new source cost estimates, ERG assumed that dry CCR material

would be stored in an onsite or offsite la ndfill. This characteristic identifies if the

landfill is assumed to be onsite or offsite.

Unit-Level Characteristics

 Type of FGD . Identifies the type of FGD scrubbe r (i.e., wet or dry) assumed to be servicing the new unit.

 Bottom Ash Handling . Identifies the type of botto m ash transport system (i.e., wet or dry) assumed for the new unit. ER G assumed that all new units will install

a MDS to collect bottom ash. This assu mption is reasonable because, of the approximately 50 coal-fired generating units that were built within the last 20 years, most (83%) manage their bottom as h without using wate r to transport the ash and as a result do not genera te bottom ash transport water.

 CCR Landfill Leachate . Identifies the type of handling for landfill leachate associated with the disposal of CCR ma terials generated by the new unit. ERG assumed that plants would either co mmingle leachate with wet FGD scrubberMemorandum April 19, 2013 Page 4

purge for treatment or treat just the leachate stream if the new unit was serviced by a dry FGD system.

Please note that the unit-level characteristics in Table 1 present the different technologies associated with the new unit only; existing units may operate differently and were not considered in the cost estimates. Based on each scenario, ERG determined whether NSPS costs for FGD, bottom ash, or leachate would be incurred.MemorandumApril 19, 2013Page 5Table 1. NSPS Costing ScenariosScenarioPlant-Level CharacteristicsNew Unit-Level CharacteristicsNSPS CostsPlantStatusImpoundmentLandfillType ofFGDBottom AshTransportCCR Landfill LeachateFGDBottomAshaLeachate1 New No ImpoundmentbOnsitecWet DryCommingled andTreated with FGD Yes No Yes2 New No ImpoundmentbOnsitecDry DryTreated as leachate only No NoYes3 Existing No Impoundment Onsite WetDryNA Yes NoNo4 ExistingExisting impoundment; nocapacity for additional CCR Onsite WetDryNAYes NoNo5 ExistingExisting impoundment;capacity for additional CCR Onsite WetDryNAYes NoNo6 Existing No Impoundment Offsite WetDryNAYes NoNo7 ExistingExisting impoundment; nocapacity for additional CCR Offsite WetDryNAYes NoNo8 ExistingExisting impoundment;capacity for additional CCR Offsite WetDryNAYes NoNoNote: All scenarios assume dry flyash handling because of the currentNSPS regulations (40 CFR 423.15(g)).NA: Not applicable. ERG assumed that only landfills built at new(i.e., greenfield) plants would be considered new sources forcombustion residual landfillleachate; therefore, only new plants will incur NSPS costs for combustion residual landfill leachate. In addition, ERG assumedthat existing plants with leachatecollection will be covered by the BAT regulations.a – ERG assumed that all new units (at both new and existing plants) will install a MDS to handle bottom ash regardless of theELGs based on informationprovided in the Steam Electric Survey. Additional information is provided in Section 6 of this memorandum.b – To comply with the proposed NSPS regulations, ERG assumed that new plants would not construct a new FGD impoundment but would instead construct atank-based treatment system.c – ERG assumed that new plants would construct an onsite landfill for disposal of combustion residuals.Memorandum April 19, 2013 Page 6

4. S ELECTION OF NSPS M ODEL U NITS

ERG used data obtained from responses to th e Steam Electric Survey and 2007 EIA data to identify all the coal-fired generating units th at have been installed in the last 20 years. 1 Using these data, ERG identified 54 units ranging in size from 6.4 MW to 1,300 MW [ERG, 2011]. Based on the large range of sizes, ERG initially evaluated three different model units (i.e., small, medium, and large) for the estimation of NSPS co sts. Therefore, ERG split the 54 units into three different size categories. ERG used the median capacity values and rounded the values to be used as the models for the NSPS analysis. Table 2 presents the statistics fo r each of the three size categories.

Table 2. NSPS Model Units

Model Unit Size Category Reported 2009 Steam Electri c Survey and 2007 EIA Data

Model Unit Capacity (MW) Size Range Number

of Units Average Capacity

(MW) Median Capacity

(MW)

Small Less than 100 MW 30 61.3 69.4 70

Medium Between 100 and 600 MW 18 340.1 354.5 350 Large Greater than 600 MW 6 862.8 798.3 800
Source: [ERG, 2011]

After determining the model unit sizes, ERG determ ined that it would also be appropriate to evaluate model units that were 600 MW and 1,300 MW. ERG chose 600 MW because it is the size that EPA assumed would be installed for pote ntial new supercritical pul verized coal units for the integrated planning model (IPM) [U.S. EP A, 2010]. ERG additionall y chose to include a 1,300 MW model unit because it was th e largest unit identified from the 54 units that have been installed in the last 20 years.

5. M ODEL U NIT A SSUMPTIONS

As part of this analysis for the NSPS costing, ERG also made the following assumptions regarding model unit operations:

 NSPS costs assume the installation of one new unit (at a new or existing plant).

 All new units are assumed to be coal-fired generating units.

 All new units are assumed to burn bituminous coal based on an analysis of the Steam Electric Survey data that show 45% of all steam electric units classified as coal units burn bituminous coal (28% subbituminous, 23% combination of two or more coal types, 4% lignite/petroleum coke/waste coal). Additionally, 60% of the steam electric units serviced with a wet FGD system burn bituminous coal.

1 Less than 10 percent of existing oil units were installe d in the last 20 years. Therefore, ERG did not include scenarios for the construction of new oil-fired units, as described previously in Section 2. Furthermore, for the reasons specified in Section 2, any new oil-fired units that would be built would not incur incremental costs to comply with the proposed NSPS requirements.Memorandum April 19, 2013 Page 7

 All new units are assumed to be baseload units based on an anal ysis of the Steam Electric Survey data that shows 69% of the coal-fired units are classified as baseload. Therefore, ERG assumes that all new units will convey bottom ash six hours per day.

 All new units are assumed to be equipped with FGD scrubbers; wet FGD

scrubbers are assumed to be a wet limestone forced oxidation scrubber.

 All new units are assumed to operate fo r 330 days during the year based on an analysis of the Steam Electric Survey data for the 54 coal-fired units that were installed in the last 20 years. The me dian number of operating days for each of the three different size groups were as follows:

— 70 MW Unit: 322.5 days;

— 350 MW Unit: 331.5 days; and

— 800 MW Unit: 335.5 days [ERG, 2011].

ERG assumed that the 600 MW and 1,300 MW model sizes would also have a similar number of operating days.

6. B OTTOM A SH M ECHANICAL D RAG S YSTEM C OSTS

As described in Section 1, ERG used the same costing methodology used to estimate the costs for existing sources to comply w ith the revised BAT effluent limitations to estimate these NSPS costs. However, ERG expected that the installa tion of a MDS for a newly constructed unit would be significantly less expensive than the installati on associated with a retr ofit system because the installation of a MDS for a new unit does not require any demolition of the bottom of the previous boiler. Additionally, ERG expected that the engineering costs for the design of the system should be significantly less expensive for a new instal lation compared to a retrofit system. To verify these expect ations, ERG contacted an engineer at Black & Veatch to discuss the installation of a mechanical drag system for a new unit. Based on the discussion, ERG

learned that Black & Veatch ha s not bid on or installed a wet sluicing system for bottom ash handling since 1997. In that same timeframe, Black & Veatch had submitted proposals for approximately 19 dry bottom ash handling systems (which included a mixture of new units and retrofit installations). Because it had been over 14 years since the company had submitted a proposal for a wet sluicing bottom ash system , they were unable to provide a comparison

between the costs of a mechan ical drag system versus a wet sluicing system. [Aron, 2011]

Based on the information obtained from the engineer at Black & Veatch re garding the number of wet sluicing bottom ash systems installed in the la st 14 years, ERG performed an analysis on the Steam Electric Survey data to determine the num ber of wet and dry bottom ash transport systems

that have been installed on new un its in the last 20 years. Base d on the analysis of the 54 units

used to estimate the size of the model units , ERG determined that 9 of the 54 units (17%)Memorandum April 19, 2013 Page 8

reported operating wet sluicing systems and 44 of the 54 units (81%) reported operating dry systems [ERG, 2011]. 2

As demonstrated from this analysis and from the information provided by the Black & Veatch engineer, the industry has in most instances in stalled dry bottom ash handling systems for units that have been built in the last 20 years. Base d on this analysis, ERG assumed that plants will install dry bottom ash handling systems on all new units regardless of pro posed NSPS regulation. Therefore, ERG did not include costs fo r a MDS system in this NSPS analysis.

7. E STIMATION OF FGD W ASTEWATER F LOW R ATE

To estimate the NSPS costs associated with inst alling a FGD wastewater treatment system for the model units, ERG estimated the FGD scrubber pur ge flow rate. As part of the FGD scrubber purge flow methodology, ERG developed a relations hip between the amount of coal burned per year, by the type of coal, to the FGD scrubber purg e flow rate using data from the Steam Electric Survey. Additionally, for plants that did not report the amount of coal burned in response to the Steam Electric Survey, ERG used survey data to develop a relationship be tween the capacity of the unit (MW) and the amount of coal burned per day. Therefore, ERG used the following two equations to estimate the FGD scrubber purge flow rate for the model units:

Amount of Coal Burned (tons/day) = 0.0014 (Capacity) 2 + 5.7189 (Cap acity) + 606.1

FGD Scrubber Purge Flow (gpd) = 0.1454 (Amount of Coal Burned) × 330

where: Capacity = The nameplate capacity (M W) of the unit, which is based on the size of the model unit (i.e., 70, 350, 600, 800, or 1,300 MW),

Amount of coal burned = The estimated amount of coal that the unit will burn in a given day based on the size of the unit (tons/day), and

FGD scrubber purge flow = The estimated amount of FGD wastewater that will be transferred to the FGD wastewater treatment system based

on the estimated amount of coal that the unit will burn in a year in gallons per day (gpd).

Based on these relationships, ERG used the fo llowing FGD scrubber purge flow rates in the NSPS costing analysis:

 70 MW Unit: 48,619 GPD;

 350 MW Unit: 133,352 GPD;

 600 MW Unit: 217, 907 GPD;

 800 MW Unit: 291,597 GPD; and

2 One unit did not report a bottom ash ha ndling system because the bottom ash is handled with the fly ash. Because this is a unique situation, ERG excluded the unit from this bottom ash installation analysis.Memorandum April 19, 2013 Page 9

 1,300 MW Unit: 471,652 GPD 3

.

In addition to using the FGD scrubber purge flow rate for estimating costs associated with NSPS,

ERG also used the calculated flow rates to es timate the amount of FGD solids that would be treated in an impoundment. This FGD solids amount was used to calculate the capital and O&M impoundment operation cost savings. The estimated FGD wastewater flow rate and the estimated

amount of FGD solids were used to estimate co mpliance costs associat ed with the various technology options using the me thodology described in EPA’s Incremental Costs and Pollutant Removals for Proposed Effluent Limitation Guid elines and Standards for the Steam Electric Power Generating Point Source Category [U.S. EPA, 2013].

8. L EACHATE F LOW R ATE C HARACTERISTICS

To estimate the NSPS costs associated with instal ling a leachate wastewater treatment system for the model units, ERG estimated the leachate flow associated with the disposal of the CCR generated from the new unit. Therefore, ERG perfor med an analysis using data reported in Part A and Part F of the Steam Electric Survey. ER G evaluated the plant-level leachate volumes reported for active landfills and co mpared that to the nameplate capacity for all the coal-fired steam electric generating units at the plant to ge nerate a relationship betw een the leachate flow and unit capacity. Based on the analysis, th e median GPD/MW was 49.18. Based on this relationship, ERG used the following leachate flow rates in the NSPS costing analysis:

 70 MW Unit: 3,443 GPD;

 350 MW Unit: 17,214 GPD;

 600 MW Unit: 29,508 GPD;

 800 MW Unit: 39,347 GPD; and

 1,300 MW Unit: 63,934 GPD.

The estimated landfill leachate flow rates were used to estimate co mpliance costs associated with the various technology options using the methodology described in EPA’s Incremental Costs and Pollutant Removals for Proposed Effluent Lim itation Guidelines and St andards for the Steam Electric Power Generating Point Source Category [U.S. EPA, 2013].

9. I MPOUNDMENT O PERATION C OST S AVINGS

EPA is evaluating the capital and O&M costs associated with the proposed NSPS regulatory options for steam electric power plants. For a plant to comply with the NSPS regulatory options being considered, plants would have to install a FGD wastewater treatment system. In the absence of such new NSPS requirements, however , the plant would comply with existing BPT requirements. In this case, ERG assumed that plants would construct a FGD impoundment (or expand an existing impoundment) to handle the FGD wastewater associated with a new unit. Therefore, the incremental cost associated with the NSPS options would be the cost of the new system(s) minus the capital cost it would have taken to install or expand a FGD impoundment and the operating costs for managi ng the wastes in the impoundment.

3 For the 1,300 MW unit, ERG believes that the FGD flow ra te would be more similar to the flow rate calculated based on two 650 MW units, as compared to one 1,300 MW. Therefore, the value used for the 1,300 MW unit was calculated using a capacity of 650 MW and multiplying the resultant flow by two.Memorandum April 19, 2013 Page 10

As part of the NSPS cost estimates, ER G evaluated the capital and O&M impoundment operation cost savings for each NSPS scenario. The capital impoundment savings include the

costs associated with the cons truction or expansion of a new or existing impoundment to store combustion residuals, the conveyance equipment us ed to transport the co mbustion residuals to the impoundment, and small additional treatment equipment necessary for discharge (e.g., pH adjustment). The O&M impoundment operation savi ngs include the costs associated with the annual operation and maintenance of the impoundm ent, the operation and maintenance of the conveyance system transporting the combustion residuals to the impoundment, and any annual

costs associated with additional treatment prior to discharge (e.g., pH adjustment).

ERG assumed the capital impoundment operation cost savings would be applicable to new units with wet FGD scrubbers for new plants, existi ng plants that do not currently have an impoundment, and existing plants with existing im poundments that do not have the capacity for

additional combustion residuals. ERG assumed that O&M impoundment operation cost savings would be applicable to all scenarios with units serviced by a wet FGD. Table 3 presents the impoundment operation cost savings for each scen ario listed in Table 1. The methodology used to estimate the O&M costs for the impoundment operation cost savings is described in EPA’s Incremental Costs and Pollutant Removals fo r Proposed Effluent Limitation Guidelines and Standards for the Steam Electric Powe r Generating Point Source Category [U.S. EPA, 2013]. The methodology used to estimate the capital cost for the impoundment operation cost savings in

described below.

Table 3. Summary of Capital and O&M Impoundment Operation Cost Savings

Scenario Impoundment FGD Capital O&M 1 No Impoundment Yes Yes 2 No Impoundment No No 3 No Impoundment Yes Yes 4 Existing impoundment; no capacity for additional combustion residuals Yes Yes 5 Existing impoundment; capacity for additional combustion residuals No Yes 6 No Impoundment Yes Yes 7 Existing impoundment; no capacity for additional combustion residuals Yes Yes 8 Existing impoundment; capacity for additional combustion residuals No Yes

ERG estimated the incremental capital impoundmen t operation cost savings using information from two EPA studies evaluating the economics of waste disposal at co al-fired power plants.

ERG determined that a combination of the da ta presented in both studies, the 1981 U.S.

EPA/TVA Economics of Ash Disposal at Coal-fired Power Plants [U.S. EPA/TVA, 1981] and

the 1985 U.S EPA Full-Scale Field Evaluation of Waste Disposal from Coal-fired Electric Generating Plants [U.S. EPA, 1985] studies, could be used to estimate the capital costs associated with constructing or expanding a combustion residual impoundment. ERG selected both data sources to combine unitized cost (annu al dollar per ton of ash) information with information on how costs vary based on plant size (i.e., capacity (MW)).Memorandum April 19, 2013 Page 11

Impoundment Capital Costs

ERG estimated the incremental capital impoundmen t operation cost savings for FGD combustion residuals at a plant using the calculated combin ed unitized cost values for impoundment capital costs, described in the Impoundment Unitized Capital Costs section, and a plant MW factor,

described in the Impoundment Capacity Factors section.

First, ERG calculated the plant-specific capacity factor, based on plant size in MW, and the plant-specific unitized cost. The values for thes e equations were developed using the two reports described above and are explai ned in more detail in the Impoundment Unitized Capital Costs and

the Impoundment Capacity Factors sections, respectively.

Plant Capacity Factor = 5.606 x (Plant Size) -0.27

Plant-Specific Unitized Cost ($/ton) = (Impoundment Capital Unitized Cost) x (Plant Capacity Factor)

where: Plant Size = Size of the plant in MW. For FGD wastewater costs, the MW value is the plant nameplate capacity from Question A1-13 in the Steam Electric Survey, and

Impoundment Capital Unitized Cost = The 2010 unitized capital cost ($/ton)

to construct and maintain a combustion residual impoundment presented in

Table 5. EPA used the unitized cost value $277.28 per dry ton of FGD

combustion residual material.

Next, ERG calculated the in cremental impoundment capital costs for new or expanding impoundments for the four applicable new sour ce costing scenarios. For FGD impoundment capital costs, ERG had to estimate the amount of combustion residuals (in tons) using FGD wastewater flow, in gpd, and an average total su spended solids (TSS) c oncentration from EPA’s FGD wastewater sampling program.

FGD Impoundment Capital Costs = (-1) x (Pla nt-Specific Unitized Cost) x [(FGD Scrubber Purge Flow) x (Average TSS Concentration) x (3.785 L/gal) x (0.001 g/mg) x (1.102 x 10 -6
tons/g) x (365 dpy)]

where: FGD Scrubber Purge Flow = The pl ant-specific FGD scrubber purge flow (gpd) estimated to be entering the FGD impoundment in gallons per day determined as described in Section 7, andMemorandum April 19, 2013 Page 12

Average TSS Concentration = The av erage influent TSS concentration, in mg/L, for FGD wastewater treatment influent sampled as part of the EPA sampling program. These data also include long-term monitoring data from all applicable plants. The average influent TSS concentration value is 16,513 mg/L.

Impoundment Unitized Capital Costs

This subsection explains how ER G calculated the impoundment uniti zed capital cost (in $/ton) used in the equations to estimate imp oundment capital costs described in the Impoundment Capital Costs section. ERG calculated impoundment cap ital costs using unitized cost data provided in U.S. EPA/TVA’s 1981 study report. The 1981 U.S. EP A/TVA study is a report that compares capital and O&M costs for five differentmethods of ash disposal at a 500 MW coalfired power plant. For the im poundment unitized cost values, ERG used the costs in the 1981 U.S. EPA/TVA study associated with the wet sl uicing of ash to a surface impoundment without water recycle scenario described in the study [U .S. EPA/TVA, 1981]. ERG used the cost and ash tonnage data from the 1981 study to calculate a unitized cost (dolla r per ton) based on combined ash tonnage. The capital costs are presented as plant total costs for the wet handling of fly ash, bottom ash, and combined ash, separately. The cost s also include unitized costs per ton of fly, bottom, or combined ash. The costs are also pr esented for each of the following modular process

areas:

 (1) Collection: includes the ash hoppers, a portion of the water supply systems,
and the fly ash pneumatic systems including the vacuum producers;

 (2) Transportation: includes the air se parators, a portion of the water supply
systems, ash pumps, the pipeline systems, trucks, storage silos and moisturizers,
the bottom ash dewatering bins, and the removal of ash from temporary
impoundments;

 (3) Disposal Site: includes impoundment s and landfills, including all mobile
equipment except that used to load and haul ash; and

 (4) Water Treatment and Recycle: incl udes the treatment systems, pumps and
return lines, and the bottom ash water systems.

For this analysis, ERG used the capital cost da ta for all modular process areas excluding (1) collection. ERG excluded the collection process ar ea because the capital co sts associated with ash hoppers are still applicable ev en after implementation of the proposed rule (i.e., there are no cost savings).

Table 4 presents the re-calculated totals for the capital costs, excl uding the (1) collection modular process area, land, and working capit al costs. ERG excluded land based on the assumption that the plant already owned the land for the impoundment. ERG also excluded working capital because this analysis is not focu sed on invested capital expenses. ERG combined the fly ash and bottom ash costs to determine a combined combustion resi dual unitized cost for the impoundment operation cost savings calculati ons for FGD combustion residuals. Table 5Memorandum April 19, 2013 Page 13

presents the fly ash, bottom ash, and combined ash unitized cost, calculated by dividing the revised total capital costs by total ash tonnage.MemorandumApril 19, 2013Page 14Table 4. Revised Modular Capital Costs byProcess Area Associated With the Wet Sluicing of Ash to an ImpoundmentWithout Water RecycleCost CategoryFly Ash Process Areas1,000 dollars (1982)Bottom Ash Process Areas1,000 dollars (1982)Fly Ash andBottom AshProcess Areas1,000 dollars (1982)234RevisedSubtotal234RevisedSubtotalRevised SubtotalDirectMaterial Costs 44 0 12 56 110 0 3 113 169Installation Costs 871 8,509 42 9,422 841 2,127 11 2,979 12,401Services, Utilities, Miscellaneous 37 340 2 379 38 85 1 124 503IndirectEngineering Design andSupervision 58 176 3 237 59 44 1 104 341Architect and Engineering 28 90 2 120 30 22 0 52 172Construction Expense 95 708 6 809 99 177 2 278 1,087Contractor Fees 58 441 3 502 59 111 1 171 673OtherContingency 119 1,026 7 1,152 123 257 2 382 1,534Allowance for Start-up andModifications 105 0 6 111 108 0 2 110 221Interest During Construction 203 1,762 12 1,977 212 440 3 655 2,632TotalTotal Capital Investment 1,618 13,052 95 14,765 1,679 3,263 26 4,968 19,733Source: [U.S. EPA/TVA, 1981]. See original version of the table in Appendix B, Table B-11.Memorandum April 19, 2013 Page 15

Table 5. Calculated Unitized Cost Values

Type of Cost Total Capital Cost

(1982 $) Ash Tonnage 1982 Index 1982

Unitized Cost ($/ton) 2010 Index 2010

Unitized Cost ($/ton)

Fly Ash 14,765,000 137,280 76.1 107.55 183.5 259.34

Bottom Ash 4,968,000 34,320 76.1 144.76 183.5 349.05

Combined 19,733,000 171,600 76.1 114.99 183.5 277.28

Impoundment Capacity Factors

Next, ERG calculated factors for estimating capital unitized costs for differe nt sized plants, using data presented in EPA’s report Full-Scale Field Evaluation of Wa ste Disposal from Coal-fired Electric Generating Plants [U.S. EPA, 1985]. The data ERG used from the 1985 study are presented in Table 6, which presents the calcula ted cost factors relativ e to a 500 MW plant for fly and bottom ash. From these data, ERG calcula ted the average of the fly ash and bottom ash

cost factors relative to the 500 MW plant to get a “combined ” cost factor, which ERG used for

the FGD combustion residuals. Th e calculated values are presented in the “Combined ($/kW)” rows in Table 6. ERG generated the following equa tion to estimate cost factors for combustion residual handling based on plant size (MW):

Plant MW Factor = 5.606 x (Plant Size) -0.27

where: Plant Size = Size of the plant in MW.

Table 6. Cost Factors Re lative to 500 MW Plant

Type of Cost Plant Size (MW) Min Range 1982 $ Max Range 1982 $ Average 1982 $ Average Cost

Factor Relative

to 500 MW Plant

Fly ($/kW) 250 17.4 32.1 24.75 1.17

Fly ($/kW) 500 14.8 27.4 21.1 1.00

Fly ($/kW) 1000 12.5 23.4 17.95 0.85

Fly ($/kW) 2000 10.7 19.8 15.25 0.72

Bottom ($/kW) 250 8.6 15.9 12.25 1.25

Bottom ($/kW) 500 6.8 12.8 9.8 1.00

Bottom ($/kW) 1000 5.5 10.2 7.85 0.80

Bottom ($/kW) 2000 4.4 8.1 6.25 0.64

Combined ($/kW) 250 NA NA NA 1.21

Combined ($/kW) 500 NA NA NA 1.00

Combined ($/kW) 1000 NA NA NA 0.83

Combined ($/kW) 2000 NA NA NA 0.68
NA: Not applicableMemorandum April 19, 2013 Page 16

10. NSPS C OSTING R ESULTS

Using the assumptions described in this memo randum and the methodologies described in EPA’s Incremental Costs and Pollutant Removals fo r Proposed Effluent Limitation Guidelines and Standards for the Steam Electric Powe r Generating Point Source Category [U.S. EPA, 2013], ERG calculated the estimated compliance costs for the model units for each NSPS costing scenario and each regulatory option. Attachment 1 to this memorandum presents the capital and

O&M costs for each NSPS scenario and each mode l unit for the different combinations of treatment technologies. Table 7 pr esents the estimated incremen tal annualized compliance costs for a 1,300 MW plant to comply with each of the different regulatory options for each NSPS costing scenario.

Table 7. Total Annualized Compliance Costs by NSPS Scenario and Regulatory Option for the 1,300 MW Model Unit

NSPS Costing

Scenario Total Annualized Compliance Costs (as of 2014; $2010)

Regulatory Option

1 a 2 3 4 5

1 [Redacted] 5,200,000 5,200,000 6,500,000 19,000,000

2 NA NA NA 1,000,000 1,000,000

3 [Redacted] 5,200,000 5,200,000 5,200,000 14,200,000

4 [Redacted] 5,200,000 5,200,000 5,200,000 14,200,000

5 [Redacted] 5,500,000 5,500,000 5,500,000 14,400,000

6 [Redacted] 5,800,000 5,800,000 5,800,000 18,400,000

7 [Redacted] 5,800,000 5,800,000 5,800,000 18,400,000

8 [Redacted] 6,000,000 6,000,000 6,000,000 18,600,000
NA – Not applicable: no as sociated compliance costs. Note: Annualized over 20 years at 7 percent discount rate. a – The Regulatory Option 1 NSPS compliance costs are redacted to prevent disclosing confidential business information. The Regulatory Option 1 costs would be lower than the Regulatory Option 2 costs.

11. R EFERENCES

U.S. EPA. 2010. Updates to EPA Base Case v3.02 EISA Using the Integrated Planning Model. (July). DCN SE02981.

U.S. EPA. 2013. Incremental Costs and Pollutant Remova ls for Proposed Effluent Limitation Guidelines and Standards for the Steam El ectric Power Generating Point Source Category . (19 April). DCN SE01957.

Aron, Mark. 2011. Telephone Conversation with Ma rk Aron, Black & Veatch and TJ Finseth, Eastern Research Group, Inc. “Bottom Ash Installations.” (20 December). DCN SE02982.

Eastern Research Group, Inc. (ERG). 2011. Char acteristics of New Generating Units and NSPS Analyses. (30 December). DCN SE02983.Memorandum April 19, 2013 Page 17

U.S. EPA and Tennessee Valley Authority (TVA) . 1981. Economics of Ash Disposal at Coalfired Power Plants. (October). DCN SE02970.

U.S. EPA. 1985. Full-Scale Field Evaluation of Waste Disposal from Coal-fired Electric
Generating Plants. (August). DCN SE02971.Attachment 1

NSPS Capital and O&M Costs for Each NSPS Costing Scenario and Model Unit[CBI Information has been removed from this section.]