### MEMORANDUM

TO: Steam Electric Rulemaking Record

FROM: Danielle Lewis, ERG

DATE: 30 September 2015

SUBJECT: Steam Electric NSPS Cost 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 ne w source performance standards (NSPS). 1 The purpose of this memorandum is to describe the methodology and cal culations used to estimate compliance costs for newly constructed units or plants subject to the revised NSPS/PSNS.

ERG evaluated the capital and operation and main tenance (O&M) costs associated with the NSPS regulatory options. 2 The costing methodologies used in this NSPS costing analysis are the same as those used in estimating costs for exis ting sources 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 Final Effluent Limitation Guidelines and Standards for the Steam Electric Power Generating Point Source Category [U.S. EPA, 2015a]. However, the estimates of costs to comply with BAT were based on plant-specific characteristics, such as curren t treatment in place, wastewater flow rates, and ash generation rates. Because the NSPS analysis is for newly constructed generating units at new or existing plants, the specific characterist ics of the units are unknown. Therefore, ERG developed model units to estimate the NSPS cost s. This memorandum describes the assumptions used for this analysis of costs to comply with NSPS.

1 EPA also estimated costs for plants to comply with pretreatment sta ndards for existing sources (PSES) and pretreatment standards for new sources (PSNS).

2 Whenever this memorandum refers to NSPS and NSPS regulatory option or technology options, it is also referring

to the same for PSNS.Memorandum September 30, 2015 Page 2

2. NSPS T ECHNOLOGY O PTIONS

EPA considered regulatory options for the contro l of wastewater discharges from new sources associated with the construction of a new gene rating unit at an existing or new plant. The technology bases for these options are:

 FGD Wastewater

— Chemical Precipitation

— Chemical Precipitation and Biological Treatment

— Chemical Precipitation and Evaporation

 Bottom Ash Transport Water

— Mechanical Drag System (MDS)

 Combustion Residual Leachate

— Chemical Precipitation

— Chemical Precipitation and Biological Treatment 3

There are no incremental NSPS costs for fly as h transport water because the existing NSPS (40 CFR 423.15(g)) already requires no disc harge of wastewater pollutants 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 three currently operating integrat ed gasification combined cycle (IGCC) units and the one IGCC unit that is currently being constructed will not discharge gasification wastewater. Because the treatment technology is standard practice in th e industry, there are no costs incremental to current practice and there is no barrier-to -entry for this treatment technology.

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

1. The FGMC wastes are typi cally collected with the fly ash in the primary particulate collection device (e.g., fabric fi lter); because the existing NSPS for fly ash transport water requires no discharge of wastewater pollu tants, 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 NSPS regulation for fly ash transport water. In this situation, the plant would typically on ly collect the fly ash prior to injecting the sorbent for mercury collection if the plant was planning to sell the fly ash; therefore, 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 combustion residual leachate from impoundments for the same reasons there are no incremental costs for combustion residual

3 ERG evaluated compliance costs associated with the tr eatment of combustion residu al leachate with chemical precipitation followed by biological treatment even though it was not part of any BAT regulatory option evaluated as part of the final ELGs.Memorandum September 30, 2015 Page 3 leachate from impoundments for current sour ces. As described in Section 9.2.4 of the Technical Development Document for the Limitations Guid elines and Standards for the Steam Electric Power Generating Point Source Category [U.S. EPA, 2015b], plants generating leachate from impoundments containing combustion residuals w ill likely use a different approach than installing chemical precipitati on, the technology basis, to comp ly with the ELGs. Existing sources are likely comply with the effluent limitations and standards for discharges of combustion residual leachate by r ecycling the leachate back to the impoundment where it was generated or using the leachate in a process that does not result in discharge to surface water (e.g., moisture conditioning) because it will cost less than installing the technology option to treat and discharge the wastewater. A new generati ng unit at either a new or an existing plant is likely to handle the combustion residual leachat e in the same manner. There would be no (or negligible) costs associated with recycling th e combustion residual impo undment leachate back to the impoundment because the plant will either: 1) repurpose an existing pump to transfer the wastewater back to the impoundment rather than pumping it to a discharge outfall or intermediate location prior to discharge; or 2) install a new pump to return the wastewater back to the impoundment. In the second case, the costs would likely be offset because the plant would no longer need to operate a separate impoundment (or other treatment system) to treat the wastewater to meet the previously established BP T effluent limitations prior to its discharge. Therefore, ERG determined that there is no barrier-to-entry for this treatment technology.

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 operat e wet FGD systems [ERG, 2015].

 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.

 Based on Steam Electric Survey data, ERG de termined that no plants classified as “oil” or “combination” operate 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 comp lying with the NSPS options will vary depending on the types of waste management systems already in place at existing plants and/or the assumed waste management system that would be inst alled in the absence of the NSPS regulations. Therefore, ERG estimated capital and O&M costs fo r nine scenarios that represent the different types of operations that may be present at an ex isting power plant or assumed to be built at new power plants. Table 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:Memorandum September 30, 2015 Page 4

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

— No impoundment is present at an existing plant;

— An impoundment is present at an existing plant with capacity for additional CCR; or

— An impoundment is present at an existing plant with no capacity for

additional CCR.

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

residuals would be stored in an onsite or offsite landfill. This characteristic

identifies if the landfill is a ssumed 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 generate bo ttom ash transport water. In addition,

because these are new unit constructions , the appropriate space requirements

needed under the boiler can be inco rporated into the unit’s design.

 Landfill Leachate . Identifies the type of handling for landfill leachate associated with the disposal of combustion resi duals generated by the new unit. ERG assumed that plants could either comm ingle leachate with wet FGD scrubber purge for treatment, treat leachate and wet FGD scrubber purge separately, or treat just the leachate stream if the ne w 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 NSPS cost estimates. Based on each scen ario, ERG determined whether NSPS costs for FGD wastewater, bottom ash transpor t water, or combustion residual leachate would be incurred.MemorandumSeptember 30, 2015Page 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 NoNo9 New No ImpoundmentbOnsitecWet DryTreated separately fromFGD Yes No YesNote: 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 leachate;therefore, only new plants will incur NSPS costs for combustion residual leachate from landfills. In addition, ERG assumed thatexisting 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 thenewly established BAT based oninformation provided in the Steam Electric Survey. Additional information is provided in Section 6 of this memorandum.b – To comply with the NSPS, ERG assumed that new plants would not construct a new FGD impoundment but would instead constructa tank-based treatmentsystem.c – ERG assumed that new plants would construct an onsite landfill for disposal of combustion residuals.Memorandum September 30, 2015 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. 4 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 costs. ERG split the 54 units into three different size categories. ERG used the median capacity va lues and rounded the values to be used as the models for the NSPS analysis. Table 2 presents the statistics for 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 m odel (IPM) [U.S. EPA, 2010]. 5 ERG additionally 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 the analysis to estimate NSPS costs, ERG also made the following assumptions regarding model unit operations: 6

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

4 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 NSPS requirements. The Steam Electric Survey data demonstrates that most oil-fired units do not generate or discharge ash transport water, nor do they generate or discharge FGD wastewater; therefore, the NSPS do not pose a barrier to entry for oil-fired generating units.

5 The information in the record for th e Steam Electric ELG rulemaking demonstrates that existing small units have been able to install and operate the same technologies (e.g., ash handling systems, FGD wastewater treatment systems) as large units. The same would hold true for new sources; therefore, basing these analyses on 600 MW and 1,300 MW units also provide the necessary information to determine whether the NSPS po se a barrier to entry for

small units.

6 The information in the record for th e Steam Electric ELG rulemaking demonstrat es that the results of these NSPS analyses also hold true for units with different characteristics, such as units that burn subbituminous coal or a blend of coals, units that burn petroleum coke or a blend of coal and petroleum coke, or cycling and peaking units.Memorandum September 30, 2015 Page 7

 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.

 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 expects that the installa tion of a MDS for a newl y 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 expects 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 mechanical drag systems (which included a mixture of new units and retrofit installations). Because it had been over 14 ye ars since the company had submitted a proposal for a wet sluicing bottom ash system, they were unabl e to provide a comparison between the costs of a mechanical 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 systemsMemorandum September 30, 2015 Page 8

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%) reported operating wet sluicing systems and 44 of the 54 units (81%) reported operating dry systems [ERG, 2011]. 7

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 determined that plants would install dry bottom ash handling systems on a ll new units regardless of NSPS regulation. Therefore, ERG concluded that there would be no incremental costs attributable to the ELG for new source plants to install a MDS system and used a zero cost for bottom ash 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 between 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).

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;

7 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 September 30, 2015 Page 9

 350 MW Unit: 133,352 GPD;

 600 MW Unit: 217, 907 GPD;

 800 MW Unit: 291,597 GPD; and

 1,300 MW Unit: 471,652 GPD. 8

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 in th e absence of NSPS requirements. This amount of FGD solids 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 compliance costs associated with the various technology options using the methodology

described in EPA’s Incremental Costs and Pollutant Removals for Final Effluent Limitation Guidelines and Standards for the Steam El ectric Power Generating Point Source Category [U.S. EPA, 2015a].

8. C OMBUSTION R ESIDUAL L EACHATE F LOW R ATE C HARACTERISTICS

To estimate the NSPS costs associated with inst alling a combustion residual leachate wastewater treatment system for the model units, ERG estim ated the leachate flow associated with the disposal of the combustion residual generated fro m the new unit. Therefore, ERG performed an analysis using data reported in Part A and Part F of the Steam Electric Survey for existing plants. ERG evaluated the plant-level leachate volumes re ported for active landfills and compared that to the nameplate capacity for all the coal-fired steam electric ge nerating units at the plant to generate a relationship between the leachate flow and unit capac ity. Based on the analysis, the

median leachate GPD/MW was 49. 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 combustion residual landfill leachate fl ow rates were used to estimate compliance

costs associated with the va rious technology options using th e methodology described in EPA’s Incremental Costs and Pollutant Removals fo r Final Effluent Limitation Guidelines and Standards for the Steam Electric Powe r Generating Point Source Category [U.S. EPA, 2015a].

9. I MPOUNDMENT O PERATION C OST S AVINGS

EPA evaluated the capital and O&M costs associated with the N SPS regulatory options for steam electric power plants. For a plan t 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 comp ly with existing BPT requirements. In this case, ERG assumed that plants would constr uct a FGD impoundment (or expand an existing

8 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 September 30, 2015 Page 10 impoundment) to handle the FGD wastewater asso ciated 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 insta ll or expand a FGD impoundment and the operating costs for managing the wa stes in the impoundment.

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

the costs associated with the construction or expansion of a new or existing impoundment to store combustion residuals, the conveyance equipment used to tr ansport the combustion residuals to the impoundment, and small additional treatme nt equipment necessary for discharge (e.g., pH adjustment). The O&M savings associated with impoundment operation include the costs associated with the annual operation and ma intenance of the impoundment, the operation and maintenance of the conveyance system tran sporting 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 cost savings would be a pplicable to new units with wet FGD scrubbers for new plants, existing plants that do not cu rrently have an impoundment, and existing plants with existing impoundments that do not have the capacity for a dditional combustion residuals. ERG assumed that O&M cost savings would be app licable to all scenarios with units serviced by a wet FGD. Table 3 presents the impoundment ope ration cost savings for each scenario listed in Table 1. The methodology used to estimate th e O&M costs for the impoundment operation cost savings is described in EPA’s Incremental Costs and Pollutant Removals for Final Effluent Limitation Guidelines and Standards for the Steam Electric Power Generating Point Source Category [U.S. EPA, 2015a]. The methodology used to estimate the capital co st savings for the impoundment operation is described below.

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

Scenario Impoundment FGD Capital O&M 1 No Impoundment Yes Yes 2 No Impoundment NA NA 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 9 No Impoundment Yes Yes
NA – Not applicable

ERG estimated the incremental capital cost savings for the impoundment operation using information from two EPA studies evaluating th e economics of waste disposal at coal-fired power plants. ERG determined that a combina tion of the data presented in 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] could be used to estimate the capital costs associated with constructing or expanding a combustion residua l impoundment. ERG selected both data sourcesMemorandum September 30, 2015 Page 11
to combine unitized cost (annual dollar per ton of ash) inform ation with information on how costs vary based on plant size (i.e., capacity (MW)).

9.1 Impoundment Capital Costs

ERG estimated the incremental capital cost savings for an impoundment receiving FGD combustion residuals using the calculated co mbined unitized cost values for impoundment capital costs, described in the Impoundment Unitized Capital Costs section (Section 9.2), and a plant MW factor, described in the Impoundment Capacity Factors section (Section 9.3).

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.

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.Memorandum September 30, 2015 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.

9.2 Impoundment Unitized Capital Costs

This section explains how ERG calculated the impoundment unitized capital cost (in $/ton) used in the equations to estimate impoundment capital costs described in Section 9.1. ERG calculated impoundment capital costs using unitized cost data provided in U.S. EPA/TVA’s 1981 study report. The 1981 U.S. EPA/TVA stu dy is a report that compares capital and O&M costs for five different methods of ash dispos al at a 500 MW coal-fired pow er plant. For the impoundment unitized cost values, ERG used the costs in th e 1981 U.S. EPA/TVA study associated with the wet sluicing of ash to a surface impoundment without water recycl e 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 (dollar per ton) based on combined as h tonnage. The capital costs are presented as plant total costs for the wet ha ndling of fly ash, bottom ash, and combined ash, separately. The costs also include unitized cost s per ton of fly, bottom, or combined ash. The costs are also presented 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.

 (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 5 presents the fly ash, bottom ash, and combined ash unitized cost, calculated by dividing the revised total capital costs by total ash tonnage.Memorandum September 30, 2015 Page 13

9.3 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.MemorandumSeptember 30, 2015Page 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 September 30, 2015 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

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 applicable

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 Final Effluent Limitation Guidelines and Standards for the Steam Electric Powe r Generating Point Source Category [U.S. EPA, 2015a], 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.Memorandum September 30, 2015 Page 16 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 2015; $2010)

Regulatory Option

A B C D E F

1 NA NA NA NA NA NA

2 NC NC NC NC [Redacted] [Redacted]

3 [Redacted] 5,480,000 5,480,000 5,480,000 [Redacted] [Redacted]

4 [Redacted] 5,480,000 5,480,000 5,480,000 [Redacted] [Redacted]

5 [Redacted] 5,730,000 5,730,000 5,730,000 [Redacted] [Redacted]

6 [Redacted] 6,000,000 6,000,000 6,000,000 [Redacted] [Redacted]

7 [Redacted] 6,000,000 6,000,000 6,000,000 [Redacted] [Redacted]

8 [Redacted] 6,250,000 6,250,000 6,250,000 [Redacted] [Redacted]

9 NA NA NA NA [R edacted] [Redacted] NA – Not applicable. NC – No associated compliance costs. Note: Annualized over 20 years at 7 percent discount rate.

11. R EFERENCES

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.

ERG. 2011. Eastern Research Group, Inc. Charac teristics of New Generating Units and NSPS Analyses. (30 December). DCN SE02983.

ERG. 2015. Eastern Research Group, Inc. Steam Electric Technical Questionnaire Database. (30 September). DCN SE05903.

U.S. EPA/TVA. 1981. U.S. Environmental Protect ion Agency and Tennessee Valley Authority.
Economics of Ash Disposal at Coal-fired Power Plants. (October). DCN SE02970.

U.S. EPA. 1985. U.S. Environmental Protection Agency. Full-Scale Fiel d Evaluation of Waste
Disposal from Coal-fired Electric Generating Plants. (August). DCN SE02971.

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

U.S. EPA. 2015a. U.S. Envi ronmental Protection Agency. Incremental Costs and Pollutant Removals for Final Effluent Li mitation Guidelines and Standards for the Steam Electric Power Generating Point Source Category . (30 September). DCN SE05831.

U.S. EPA. 2015b. Environmental Protection Agency. Technical Development Document for the
Limitations Guidelines and Standards for th e Steam Electric Power Generating Point Source
Category . (30 September). DCN SE5904.