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. INTRODUCTION/BACKGROUND 

ERG is providing technical support to the U.S. Environmental Protection Agency’s Office of 

Water, Engineering and Analysis Division (EAD) for development of effluent limitations 

guidelines and standards (ELG) for the Steam Electric Power Generating Industry. EPA, with 

the support of ERG, developed estimates of the industry costs to comply with various regulatory 

options. The estimates were prepared for both existing sources that would be subject to revised 

best available technology economically achievable (BAT) effluent limitations and new sources 

that would be subject to revised new source performance standards (NSPS) effluent limitations. 

The purpose of this memorandum is to describe the methodology and calculations used to 

estimate compliance costs for newly constructed units or plants subject to the revised NSPS. 

ERG evaluated the capital and operating and maintenance (O&M) costs associated with the 

proposed NSPS regulatory options. The costing methodologies used in this NSPS costing 

analysis are the same as those used in estimating costs for existing 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 

Proposed Effluent Limitation Guidelines and Standards 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 for newly constructed units at new 

or existing plants, the specific characteristics 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 TECHNOLOGY OPTIONS

EPA is considering regulatory options for the control of wastewater discharges from new sources 

associated with the construction of a new unit at an existing or new plant. 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 Vapor-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 transport water because the existing NSPS (40 CFR 

423.15(g)) already requires no discharge of pollutants in fly ash transport water. 

There are no incremental NSPS costs for the treatment of gasification wastewater because the 

technology option being considered for NSPS is the technology that is currently in place at the 

two currently operating IGCC units and the one IGCC unit that is currently being constructed. 

Because the treatment technology is standard practice in the industry and because an IGCC unit 

is now being constructed using the proposed treatment technology, ERG believes that there is no 

barrier-to-entry for the proposed treatment technology. 

There are no incremental NSPS costs for the treatment of flue gas mercury control (FGMC) 

wastewater for the following three reasons: 

1. The FGMC wastes are typically 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 would 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. 

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; 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 treatment 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 Generating Effluent Guidelines (Steam Electric Survey), there are 

no oil-fired units that operate wet FGD systems; 
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April 19, 2013 

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 For the 25 oil-fired units that reported generating bottom ash in the Steam Electric 

Survey, only three units reported some type of wet handling of the bottom ash; 

and 

 Based on Steam Electric Survey data, ERG determined that no plants classified as 

“oil” or “combination” operate CCR landfills with leachate collection systems. 

3. NSPS SCENARIOS

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

construction site. The cost associated with complying with the proposed 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 installed in the absence of the proposed 

NSPS regulations. Therefore, ERG estimated capital 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. 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 plant receiving the new source costs. 

Because the new source costs reflect the installation of a new unit, the status of 

the plant can be identified as a new greenfield installation versus existing plant. 

 Impoundment. Identifies the different impoundment options applicable to a new 

or existing plant. These impoundment options include: 

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

— No impoundment at an existing plant; 

— An existing impoundment at an existing plant with capacity for additional 

CCR; or 

— An existing impoundment at an existing 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 landfill. This characteristic identifies if the 

landfill is assumed to be onsite or offsite. 

Unit-Level Characteristics 

 Type of FGD. Identifies the type of FGD scrubber (i.e., wet or dry) assumed to 

be servicing the new unit. 

 Bottom Ash Handling. Identifies the type of bottom ash transport system (i.e., 

wet or dry) assumed for the new unit. ERG assumed that all new units will install 

a MDS to collect bottom ash. This assumption is reasonable because, of the 

approximately 50 coal-fired generating units that were built within the last 20 

years, most (83%) manage their bottom ash without using water to transport the 

ash and as a result do not generate bottom ash transport water. 

 CCR Landfill Leachate. Identifies the type of handling for landfill leachate 

associated with the disposal of CCR materials generated by the new unit. ERG 

assumed that plants would either commingle leachate with wet FGD scrubber 
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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. 
Memorandum 

April 19, 2013 Page 5 

Table 1. NSPS Costing Scenarios 

Scenario 

Plant-Level Characteristics New Unit-Level Characteristics 

Plant 

Status Impoundment Landfill 

Type of 

FGD 

Bottom Ash 

Transport CCR Landfill Leachate FGD 

1 New No Impoundment b Onsite c Wet Dry 

Commingled and Treated with FGD Ye

2 New No Impoundment b Onsite c Dry Dry Treated as leachate only No 3 Existing No Impoundment Onsite Wet Dry NA Ye4 Existing 

Existing impoundment; no capacity for additional CCR Onsite Wet Dry NA Ye

5 Existing 

Existing impoundment; capacity for additional CCR Onsite Wet Dry NA Ye

6 Existing No Impoundment Offsite Wet Dry NA Ye7 Existing 

Existing impoundment; no capacity for additional CCR Offsite Wet Dry NA Ye

8 Existing 

Existing impoundment; capacity for additional CCR Offsite Wet Dry NA Ye

Note: All scenarios assume dry fly ash handling because of the current NSPS 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 for combus

leachate; therefore, only new plants will incur NSPS costs for combustion residual landfill leachate. In addition, ERG assumed that exis

collection 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 the ELGs bprovided 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 wtank-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. SELECTION OF NSPS MODEL UNITS

ERG used data obtained from responses to the Steam Electric Survey and 2007 EIA data to 

identify all the coal-fired generating units that 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 costs. 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 for each of the three size 

categories. 

Table 2. NSPS Model Units 

Model Unit 

Size Category 

Reported 2009 Steam Electric Survey and 2007 EIA Data 

Model Unit 

Size Range Capacity (MW)

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 determined 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 potential new supercritical pulverized coal units for 

the integrated planning model (IPM) [U.S. EPA, 2010]. ERG additionally chose to include a 

1,300 MW model unit because it was the largest unit identified from the 54 units that have been 

installed in the last 20 years. 

5. MODEL UNIT ASSUMPTIONS

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 installed 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 analysis 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 for 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 median 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. BOTTOM ASH MECHANICAL DRAG SYSTEM COSTS

As described in Section 1, ERG used the same costing methodology used to estimate the costs 

for existing sources to comply with the revised BAT effluent limitations to estimate these NSPS 

costs. However, ERG expected that the installation of a MDS for a newly constructed unit would 

be significantly less expensive than the installation associated with a retrofit 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 installation compared to a retrofit 

system. To verify these expectations, 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 has 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 mechanical drag system versus a wet sluicing system. [Aron, 2011] 

Based on the information obtained from the engineer at Black & Veatch regarding the number of 

wet sluicing bottom ash systems installed in the last 14 years, ERG performed an analysis on the 

Steam Electric Survey data to determine the number of wet and dry bottom ash transport systems 

that have been installed on new units in the last 20 years. Based 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%) 
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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 installed dry bottom ash handling systems for units 

that have been built in the last 20 years. Based on this analysis, ERG assumed that plants will 

install dry bottom ash handling systems on all new units regardless of proposed NSPS regulation. 

Therefore, ERG did not include costs for a MDS system in this NSPS analysis. 

7. ESTIMATION OF FGD WASTEWATER FLOW RATE

To estimate the NSPS costs associated with installing a FGD wastewater treatment system for 

the model units, ERG estimated the FGD scrubber purge flow rate. As part of the FGD scrubber 

purge flow methodology, ERG developed a relationship between the amount of coal burned per 

year, by the type of coal, to the FGD scrubber purge 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 (Capacity) + 606.1 

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

where: 

Capacity = The nameplate capacity (MW) 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 following 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 handling 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 GPD3. 

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

ERG also used the calculated flow rates to estimate 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 compliance costs associated with the various 

technology options using the methodology described in EPA’s Incremental Costs and Pollutant 

Removals for Proposed Effluent Limitation Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category [U.S. EPA, 2013]. 

8. LEACHATE FLOW RATE CHARACTERISTICS

To estimate the NSPS costs associated with installing 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 performed an analysis using data reported in Part 

A and Part F of the Steam Electric Survey. ERG evaluated the plant-level leachate volumes 

reported for active landfills and compared that to the nameplate capacity for all the coal-fired 

steam electric generating units at the plant to generate a relationship between the leachate flow 

and unit capacity. Based on the analysis, the 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 compliance costs associated with 

the various technology options using the methodology described in EPA’s Incremental Costs and 

Pollutant Removals for Proposed Effluent Limitation Guidelines and Standards for the Steam 

Electric Power Generating Point Source Category [U.S. EPA, 2013]. 

9. IMPOUNDMENT OPERATION COST SAVINGS

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 managing the wastes in the impoundment. 

 

3

 For the 1,300 MW unit, ERG believes that the FGD flow rate 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, ERG evaluated the capital and O&M impoundment 

operation cost savings for each NSPS scenario. The capital impoundment savings include the 

costs associated with the construction or expansion of a new or existing impoundment to store 

combustion residuals, the conveyance equipment used to transport the combustion residuals to 

the impoundment, and small additional treatment equipment necessary for discharge (e.g., pH 

adjustment). The O&M impoundment operation savings include the costs associated with the 

annual operation and maintenance of the impoundment, 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, existing plants that do not currently have an 

impoundment, and existing plants with existing impoundments 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 scenario 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 for Proposed Effluent Limitation Guidelines and 

Standards for the Steam Electric Power 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 impoundment operation cost savings using information 

from two EPA studies evaluating the economics of waste disposal at coal-fired power plants. 

ERG determined that a combination of the data 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 (annual 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 impoundment operation cost savings for FGD combustion 

residuals at a plant using the calculated combined 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 these equations were developed using the two reports 

described above and are explained 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 incremental impoundment capital costs for new or expanding 

impoundments for the four applicable new source 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 suspended solids (TSS) concentration from EPA’s 

FGD wastewater sampling program. 

FGD Impoundment Capital Costs = (-1) x (Plant-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 plant-specific FGD scrubber purge flow (gpd) 

estimated to be entering the FGD impoundment in 

gallons per day determined as described in 

Section 7, and 
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April 19, 2013 

Page 12 

 Average TSS Concentration = The average 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 ERG calculated the impoundment unitized capital cost (in $/ton) 

used in the equations to estimate impoundment capital costs described in the Impoundment 

Capital Costs section. 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 study is a report that 

compares capital and O&M costs for five different methods of ash disposal at a 500 MW coalfired power plant. For the impoundment unitized cost values, ERG used the costs in the 1981 

U.S. EPA/TVA study associated with the wet sluicing 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 (dollar 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 costs also include unitized costs 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 separators, 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 impoundments and landfills, including all mobile 

equipment except that used to load and haul ash; and 

 (4) Water Treatment and Recycle: includes the treatment systems, pumps and 

return lines, and the bottom ash water systems. 

For this analysis, ERG used the capital cost data for all modular process areas excluding (1) 

collection. ERG excluded the collection process area because the capital costs associated with 

ash hoppers are still applicable even after implementation of the proposed rule (i.e., there are no 

cost savings). 

Table 4 presents the re-calculated totals for the capital costs, excluding the (1) collection 

modular process area, land, and working capital 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 focused on invested capital expenses. ERG combined 

the fly ash and bottom ash costs to determine a combined combustion residual unitized cost for 

the impoundment operation cost savings calculations for FGD combustion residuals. Table 5 
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April 19, 2013 

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presents the fly ash, bottom ash, and combined ash unitized cost, calculated by dividing the 

revised total capital costs by total ash tonnage. 
Memorandum 

April 19, 2013 Page 14 

Table 4. Revised Modular Capital Costs by Process Area Associated With the Wet Sluicing of Ash to a

Without Water Recycle 

Cost Category 

Fly Ash Process Areas 

1,000 dollars (1982) 

Bottom Ash Process Areas 

1,000 dollars (1982) 

2 3 4 

Revised 

Subtotal 2 3 4 

Revised 

Subtota

Direct Material Costs 44 0 12 56 110 0 3 113 Installation Costs 871 8,509 42 9,422 841 2,127 11 2,979 Services, Utilities, Miscellaneous 37 340 2 379 38 85 1 124 Indirect Engineering Design and Supervision 58 176 3 237 59 44 1 104 Architect and Engineering 28 90 2 120 30 22 0 52 Construction Expense 95 708 6 809 99 177 2 278 Contractor Fees 58 441 3 502 59 111 1 171 Other Contingency 119 1,026 7 1,152 123 257 2 382 Allowance for Start-up and Modifications 105 0 6 111 108 0 2 110 Interest During Construction 203 1,762 12 1,977 212 440 3 655 Total Total Capital Investment 1,618 13,052 95 14,765 1,679 3,263 26 4,968 

Source: [U.S. EPA/TVA, 1981]. See original version of the table in Appendix B, Table B-11.
Memorandum 

April 19, 2013 

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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 different sized plants, using 

data presented in EPA’s report Full-Scale Field Evaluation of Waste 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 calculated cost factors relative to a 500 MW plant for 

fly and bottom ash. From these data, ERG calculated 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. The calculated values are presented in the “Combined ($/kW)” 

rows in Table 6. ERG generated the following equation 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 Relative 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
Memorandum 

April 19, 2013 

Page 16 

10. NSPS COSTING RESULTS

Using the assumptions described in this memorandum and the methodologies described in EPA’s 

Incremental Costs and Pollutant Removals for Proposed Effluent Limitation Guidelines and 

Standards for the Steam Electric Power 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 model unit for the different combinations of 

treatment technologies. Table 7 presents the estimated incremental 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 

1a 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 associated 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. REFERENCES

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 Removals for Proposed Effluent Limitation 

Guidelines and Standards for the Steam Electric Power Generating Point Source Category. (19 

April). DCN SE01957. 

Aron, Mark. 2011. Telephone Conversation with Mark Aron, Black & Veatch and TJ Finseth, 

Eastern Research Group, Inc. “Bottom Ash Installations.” (20 December). DCN SE02982. 

Eastern Research Group, Inc. (ERG). 2011. Characteristics 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.]