MEMORANDUM 

TO: Steam Electric Rulemaking Record 

FROM: Elizabeth Sabol, ERG 

 Thomas Finseth, ERG 

DATE: April 19, 2013 

SUBJECT: Steam Electric Effluent Guidelines – Evaluation of Potential 

Subcategorization Approaches 

The CWA requires EPA to consider a number of different factors when developing ELGs for a 

particular industry category (see Best Available Technology Economically Achievable (BAT) 

factors listed at Section 304(b)(2)(b), 33 U.S.C. §1314(b)(2)(B)). For BAT, in addition to the 

technological availability and economic achievability, these factors are the age of equipment and 

facilities involved, the process employed, the engineering aspects of the application of various 

types of control techniques, process changes, the cost of achieving such effluent reductions, nonwater quality environmental impact (including energy requirements), and such other factors the 

Administrator deems appropriate. One way EPA may take these factors into account is by 

dividing a point source category into groupings called “subcategories.” Regulating a category by 

subcategory, where warranted, ensures that each subcategory has a uniform set of effluent 

limitations that take into account technology availability and economic achievability and other 

relevant factors unique to that subcategory. 

The current steam electric ELGs do not divide plants or process operations into subcategories, 

although they do include different effluent requirements for cooling water discharges from plants 

with a total rated generating capacity of less than 25 megawatts (MW). For the proposed 

revisions, EPA directed ERG to evaluate whether subcategorization would be appropriate using 

information from the industry surveys, site visits, sampling, and other collection activities. ERG 

performed analyses to assess the influence of age, size, fuel type, and geographic location on the 

wastewaters generated, wastewater characteristics including discharge flow rates, and treatment 

technology availability at steam electric power plants to determine whether subcategorization 

was warranted. This memorandum describes the evaluations performed for fly ash transport 

water, bottom ash transport water, FGD wastewater, and combustion residual leachate.1

Attachment 1 presents additional information on the factors described above, as well as 

information associated with capacity utilization. 

 

1 ERG also evaluated whether subcategorization was warranted for IGCC wastewater, FGMC wastewater, and 

nonchemical metal cleaning wastes. However, because there are no incremental compliance costs for these wastes 

under the proposed ELGs, there is no basis for establishing subcategories for these discharges.
Memorandum 

April 19, 2013 

Page 2 

1.0 AGE

ERG analyzed generating units and power plants to evaluate how age affects the wastewater 

characteristics, processes in place, or the ability to install the treatment technologies evaluated as 

part of the proposed ELGs. To calculate the age of generating units at each plant, ERG first 

identified all the plants and generating units within the scope of the rulemaking using data 

reported in the Questionnaire for the Steam Electric Power Generating Effluent Guidelines

(Steam Electric Survey). ERG identified 1,537 operating generating units from data in the Steam 

Electric Survey, based on survey weighting, this represents 2,214 generating units. Because the 

Steam Electric Survey did not collect information regarding the age or year the generating units 

were built, ERG used data from the 2009 EIA database to determine the age of the generating 

units. ERG was able to match 1,151 of the 1,537 generating units identified in the survey 

responses to the 2009 EIA data. Based on survey weighting, this represents 1,615 of the 2,214 

generating units. ERG calculated the age of the units from the year 2009. For this analysis, ERG 

used the age of the oldest, operating generating unit to represent the age of the power plant. 

ERG determined that the age of operating steam electric generating units ranges from less than 

one year to over 60 years old. ERG used these age data along with data in the Steam Electric 

Survey to determine if age would affect the plants’ ability to comply with the proposed 

rulemaking. See Tables B1 through B5, in Attachment 1, for additional information regarding the 

age of coal-, petroleum coke- and oil-fired generating units within the scope of the rulemaking. 

1.1 Fly Ash Transport Water

For the proposed ELGs, EPA evaluated the following two technology options for fly ash 

transport water: 

 Set BAT equal to the current BPT requirements; and 

 Dry fly ash handling. 

Dry fly ash handling is already a well established technology within the industry, with over 64 

percent of the generating units collecting fly ash with only dry handling systems. Additionally, 

dry fly ash handling is the technology basis for the zero discharge standard for fly ash transport 

water for New Source Performance Standards (NSPS) in the current ELGs. The remaining units 

employ wet ash handling or both wet and dry ash handling. For this analysis, ERG evaluated the 

age of generating units for the following three types of handling systems: 

 Units with only a wet sluicing system; 

 Units with only a dry handling system; and 

 Units with both a wet sluicing and dry handling systems. 

ERG identified that approximately 854 of the 1,151 generating units for which age data were 

available collect fly ash. Based on survey weighting, this represents 867 generating units. Table 

1 shows the type of fly ash handling system relative to the age of the generating unit. The table 

clearly demonstrates that units built within the last twenty years almost exclusively use dry fly 
Memorandum 

April 19, 2013 

Page 3 

ash handling systems. This is not surprising, due to the current NSPS zero discharge requirement 

promulgated in 1982. The data also demonstrate that dry fly ash handling systems are used by 

numerous generating units in all age groups, including units that are more than 50 years old. 

Table 1. Age and Handling of Units Collecting Fly Ash 

Age of Unit 

Units with Only Wet 

Sluicing Systems 

Units with Only Dry 

Handling Systems 

Units with Both Wet and 

Dry Handling 

< 10 Years 0 [Redacted] 0 

10 - 20 Years 0 [Redacted] [Redacted] 

20 - 30 Years [Redacted] 82 18 

30 - 40 Years 29 109 50 

40 - 50 Years 54 113 36 

> 50 Years 119 162 45 

Note: The number of units is based on values reported in the 2009 survey, which were scaled to represent the 

industry as a whole using the industry-weighting factors discussed in Section 3.3 of the Steam Electric Technical 

Development Document (TDD) [U.S. EPA, 2013]. 

Because most units operating wet sluicing systems are likely to retrofit to a dry fly ash handling 

systems to comply with the proposed rulemaking, ERG also evaluated the age of plants and 

generating units that had initially installed wet-sluicing systems but subsequently retrofitted to 

dry fly ash handling systems. Using survey data and 2009 EIA data, ERG identified 

approximately 123 plants based on survey weighting that retrofitted at least one generating unit 

at the plant with a dry fly ash handling system. EPA identified nearly [Redacted] generating units 

that have retrofitted to dry fly ash handling systems. More than 270 of these generating units are 

at least 30 years old, including 115 units that are more than 50 years old. Approximately 40 

percent of generating units that have retrofitted to dry fly ash handling systems are at least 50 

years old. 

 

Table 2. Age of Fly Ash Handling Retrofit Units 

Age of Unit 

Units with Dry Handling Systems 

Only 

Units with Both Wet and Dry 

Handling 

< 10 Years 0 0 

10 - 20 Years 2 1 

20 - 30 Years [Redacted] 11 

30 - 40 Years 39 33 

40 - 50 Years 53 31 

> 50 Years 79 36 

Note: The number of units is based on values reported in the 2009 survey, which were scaled to represent the 

industry as a whole using the industry-weighting factors discussed in Section 3.3 of the Steam Electric TDD [U.S. 

EPA, 2013]. 
Memorandum 

April 19, 2013 

Page 4 

Based on these data, ERG determined that the age of the generating unit or plant (i.e., facility) 

has no affect on the feasibility of converting to a dry fly ash handling system. 

1.2 Bottom Ash

For the proposed ELGs, EPA evaluated the following two options for bottom ash transport 

water: 

 Set BAT equal to the current BPT requirements; and 

 Dry or closed-loop bottom ash handling. 

The technology options EPA is considering to achieve dry or closed-loop bottom ash handling 

include mechanical drag systems (MDS) and remote MDS. Information from the Steam Electric 

Survey and vendor data shows the number of plants installing mechanical drag systems on 

generating units is increasing. Using data collected in the Steam Electric Survey, ERG evaluated 

the age of generating units for the following three types of handling systems: 

 Units with only a wet sluicing system; 

 Units with only a dry handling system; and 

 Units with both a wet sluicing and dry handling systems. 

ERG identified that approximately 860 of the 1,151 generating units for which age data were 

available collect bottom ash. Based on survey weighting, this represents 875 generating units. 

Table 3 shows the type of bottom ash handling system, relative to the age of the generating units. 

The table shows that for units built in the last 20 years, dry ash handling is the predominant type 

of system employed. As the age of the units increase beyond 20 years, wet handling is more 

prevalent. However, the table clearly demonstrates that dry bottom ash handling systems are 

used by units in all age groups, including those units that are more than 50 years old. 

Table 3. Age and Handling of Units Collecting Bottom Ash 

Age of Unit 

Units with Wet Sluicing 

Systems Only 

Units with Dry Handling 

Systems Only 

Units with Both Wet and 

Dry Handling 

< 10 Years 2 [Redacted] 0 

10 - 20 Years [Redacted] [Redacted] 0 

20 - 30 Years 78 [Redacted] 0 

30 - 40 Years 162 [Redacted] 3 

40 - 50 Years 179 [Redacted] 1 

> 50 Years 276 [Redacted] 1 

Note: The number of units are based on values reported in the 2009 survey, which were scaled to represent the 

industry as a whole using the industry-weighting factors discussed in Section 3.3 of the Steam Electric TDD [U.S. 

EPA, 2013]. 
Memorandum 

April 19, 2013 

Page 5 

Because most units operating wet sluicing systems are likely to retrofit to dry or closed-loop 

bottom ash handling systems to comply with the proposed rulemaking, ERG also evaluated the 

age of plants and generating units that had initially installed wet-sluicing systems but 

subsequently retrofitted to dry or closed-loop bottom ash handling systems. Using survey data 

and 2009 EIA data, ERG identified approximately 21 plants based on survey weighting that 

retrofitted at least one unit at the plant with a dry or closed-loop bottom ash handling system, 

rather installing them at the time the generating unit was built. Table 4 presents the age of the 

generating units with retrofitted dry or closed-loop bottom ash handling systems and 

demonstrates that the age of the unit does not preclude installing dry or closed-loop bottom ash 

handling systems. All of the bottom ash retrofits were completed on generating units that are at 

least 10 years old. Approximately 33 percent of the retrofitted units are at least 50 years old. 

Table 4. Age of Bottom Ash Handling Retrofit Units 

Age of Unit Units with Dry Handling Systems Only 

< 10 Years 0 

10 - 20 Years [Redacted] 

20 - 30 Years [Redacted] 

30 - 40 Years 7 

40 - 50 Years [Redacted] 

> 50 Years 11 

Note: The number of units is based on values reported in the 2009 survey, which were scaled to represent the 

industry as a whole using the industry-weighting factors discussed in Section 3.3 of the Steam Electric TDD (U.S. 

EPA, 2012). 

Based on these data, ERG determined that there are no limitations to converting to a dry bottom 

ash handling system based on the age of the generating unit. 

1.3 FGD Wastewater

For the proposed ELGs, EPA evaluated the following technology options for FGD wastewater: 

 Set BAT equal to the current BPT requirements; 

 Chemical precipitation; 

 Chemical precipitation followed by biological treatment; and 

 Chemical precipitation followed by softening and vapor-compression evaporation. 

Based on information collected in the Steam Electric Survey, 2009 EIA data, site visits, and the 

sampling program, ERG determined that the age of the plant and generating unit(s) do not impact 

the plants’ ability to install the treatment technologies proposed as part of this rulemaking 

because the treatment system for the FGD wastewater is distinctly separate from the generating 

unit. The FGD wastewater is generated by the FGD system and transferred to a pond or 

wastewater treatment system. There is nothing associated with a plant’s age that would prevent 
Memorandum 

April 19, 2013 

Page 6 

the plant from being able to transfer the FGD wastewater to another location where a treatment 

system would be built (or to the same location where the existing treatment system could be 

upgraded or replaced). 

Based on Steam Electric Survey and 2009 EIA data, ERG was able to identify 28 plants with 

2009 EIA age information that operate chemical precipitation systems to treat FGD wastewater 

in the steam electric industry. Additionally, ERG identified five plants with age information that 

operate chemical precipitation followed by biological treatment to treat FGD wastewater in the 

steam electric industry. ERG determined that 13 of the plants operating chemical precipitation 

systems to treat FGD wastewater are at least forty years old. Additionally, all five biological 

treatment systems are at plants at least 20 years old and one of the plants is more than 50 years 

old. 

Based on these analyses, ERG determined that age is not an appropriate basis for setting different 

effluent requirements for FGD wastewatwer. 

1.4 Leachate

For the proposed ELGs, EPA evaluated the following technology options for combustion 

residual leachate: 

 Set BAT equal to the current BPT requirements; 

 Chemical precipitation; and 

 Chemical precipitation followed by biological treatment. 

Similar to FGD wastewater, ERG does not expect the age of the plant, or generating unit(s) 

contributing to the combustion residual leachate, to affect the plant’s ability to install the 

treatment technologies proposed as part of this rulemaking because the treatment system is 

distinctly separate from the generating unit(s). The leachate is collected from the combustion 

residual landfill/surface impoundment and is conveyed, likely via pipe, to the site of the 

treatment system. There is nothing associated with a plant’s age that would prevent the plant 

from being able to transfer the leachate to another location where a treatment system would be 

built (or to the same location where the existing treatment system could be upgraded or 

replaced). Therefore, ERG determined that age is not an appropriate basis for setting different 

effluent requirements. 

2.0 SIZE

ERG analyzed the size (i.e., generating nameplate capacity in megawatts (MW)) of the 

generating units to determine if size has an impact on the wastewater characteristics, processes in 

place, or the ability to install the treatment technologies evaluated as part of the proposed ELGs. 

ERG determined the size of the generating units using data from Part A Section 6, Table A-8 of 

the Steam Electric Survey. For generating units that did not have reported nameplate capacities, 

ERG supplemented the Steam Electric Survey data with data from the 2009 EIA database. From 

the Steam Electric Survey, ERG identified 1,537 operating generating units from data in the 
Memorandum 

April 19, 2013 

Page 7 

Steam Electric Survey, based on survey weighting, this represents 2,214 generating units, with a 

steam turbine capacity, in MW. 

ERG determined that the reported generating unit capacities range from 2.4 MW to 1,400 MW. 

The size of the generating unit does not affect the plant’s ability to install a treatment system; 

however, ERG did assess how the cost per MW to comply with the ELG differs by the size of 

generating unit. 

The following subsections describe how the analyses were performed and the results of the 

analyses for each waste stream of interest. 

2.1 Fly Ash Transport Water

ERG estimated compliance costs for 197 generating units currently handling some or all of their 

fly ash with a wet sluicing system. The capacity of generating units operating wet sluicing fly 

ash collection systems ranges from 12.5 MW to 1,110 MW. Twenty units have capacities of 50 

MW or less. 

Fly ash annualized costs are calculated at the plant level, using unit-level input data.2

 ERG used 

the cost model outputs to generate unit-level annualized costs. The cost model outputs 

conveyance conversion costs at the unit level and silo, pugmill, water truck, transport, and 

disposal costs at the plant level. In order to estimate unit-level silo and pugmill costs, ERG first 

calculated the total wet produced fly ash tonnage per day for the plant. ERG then calculated the 

percentage of the total wet produced fly ash tonnage per day for each unit contributing to the 

total. Finally, ERG multiplied these percentages by the plant-level silo and pugmill costs to 

allocate the costs to the unit level. Additionally, ERG performed a similar analysis using the wet 

produced ash tonnage per year to allocate the water truck, transport, and disposal costs to the unit 

level. 

ERG also evaluated the annualized costs per MW for the fly ash conversion costs excluding the 

transport and disposal portion of the costs. ERG evaluated the costs excluding the transport and 

disposal portion because the capital and O&M costs can be substantially influenced by whether 

the plant uses an on-site or an off-site landfill. 

After estimating unit-level annualized costs for fly ash conversions, ERG calculated the resulting 

cost per MW for each generating unit. Table 5 presents the average annualized cost per MW for 

units greater than 50 MW and units less than or equal to 50 MW for both fly ash analyses. 

Figures 1 and 2 present the cost per MW as a function of the unit capacity (MW) for all 197 units 

incurring fly ash conversion costs for all cost components and excluding transport and disposal 

costs, respectively. 

 

2

 The annualized costs used in this analysis were estimated by ERG using a discount rate of 7% and a discounting 

period of 20 years. The annualized costs generated by EPA, which are the basis for the costs presented in the 

preamble and the Regulatory Impact Analysis for Proposed Effluent Limitations Guidelines and Standards for the 

Steam Electric Power Generating Point Source Category (EPA-821-R-13-005), were not used in this analysis; 

however, these annualized costs still represent the general trends and are informative to the analysis. 
Memorandum 

April 19, 2013 

Page 8 

Table 5. Cost Per MW for Fly Ash Handling Compliance Costs 

Costs 

Average $/MW for 

Units ≤ 50 MW 

Average $/MW for 

Units > 50 MW 

Fly Ash Compliance Costs (all cost components) 8,504 5,109 

Fly Ash Compliance Costs (excluding transport and disposal) 6,062 1,377 

Figure 1. Fly Ash Annualized Cost Per MW (All Cost Components) Compared to Unit 

Capacity (MW) 
Memorandum 

April 19, 2013 

Page 9 

Figure 2. Fly Ash Annualized Cost Per MW (Excluding Transport and Disposal) 

Compared to Unit Capacity (MW) 

2.2 Bottom Ash Transport Water

ERG estimated compliance costs for 581 generating units currently handling their bottom ash 

with a wet sluicing system. The capacity of units incurring bottom ash conversion costs ranges 

from 5 MW to 1,300 MW. There are 49 units that have capacities less than or equal to 50 MW. 

Additionally, for 53 units currently handling their bottom ash wet, ERG estimated costs for the 

plants to close the discharge of the bottom ash transport water (i.e., bottom ash management 

costs). Three of these units have capacities less than or equal to 50 MW. The units incurring 

bottom ash management costs are excluded from the remainder of this analysis. 

Bottom ash annualized costs are calculated at the plant level, using unit-level input data.3

 ERG 

used the cost model outputs to generate unit-level annualized costs. The cost model outputs 

conveyance and intermediate storage costs at the unit level and transport and disposal costs at the 

plant level. In order to estimate unit-level transport and disposal costs, ERG first calculated the 

total wet produced bottom ash tonnage per year for the plant. ERG then calculated the percentage 

of the total wet produced bottom ash tonnage per year for each unit contributing to the total. 

Finally, ERG multiplied these percentages by the plant-level transport and disposal costs to 

allocate the costs to the unit level. 

 

3

 The annualized costs used in this analysis were estimated by ERG using a discount rate of 7% and a discounting 

period of 20 years. The annualized costs generated by EPA, which are the basis for the costs presented in the 

preamble and the Regulatory Impact Analysis for Proposed Effluent Limitations Guidelines and Standards for the 

Steam Electric Power Generating Point Source Category (EPA-821-R-13-005), were not used in this analysis; 

however, these annualized costs still represent the general trends and are informative to the analysis. 
Memorandum 

April 19, 2013 

Page 10 

Similar to fly ash, ERG also evaluated the annualized costs per MW for the bottom ash 

conversion costs excluding the transport and disposal portion of the costs. ERG evaluated the 

costs excluding the transport and disposal portion because the capital and O&M costs can be 

substantially influenced by whether the plant uses an on-site or an off-site landfill. 

After estimating unit-level annualized costs for bottom ash conversions, ERG calculated the 

resulting cost per MW for each generating unit. Table 6 presents the average annualized cost per 

MW for units greater than 50 MW and units less than or equal to 50 MW for both bottom ash 

analyses. Figures 3 and 4 present the cost per MW as a function of the unit capacity (MW) for all 

581 units incurring bottom ash compliance costs for all cost components and excluding transport 

and disposal costs, respectively. 

Table 6. Dollar Per MW for Bottom Ash Handling Compliance Costs 

Costs 

Average $/MW for 

Units ≤ 50 MW 

Average $/MW for 

Units > 50 MW 

Bottom Ash Compliance Costs (all cost components) 35,623 7,424 

Bottom Ash Compliance Costs (excluding transport and disposal) 34,102 5,795 

Figure 3. Bottom Ash Annualized Cost Per MW (All Cost Components) Compared to Unit 

Capacity (MW) 
Memorandum 

April 19, 2013 

Page 11 

Figure 4. Bottom Ash Annualized Cost per MW (Excluding Transport and Disposal) 

Compared to Unit Capacity (MW) 

2.3 FGD Wastewater

ERG estimated compliance costs for 278 units serviced by a wet FGD system requiring further 

treatment of the FGD wastewater to comply with the proposed ELGs. The capacity of units 

serviced by wet FGD systems ranges from 50 MW to 1,300 MW. There is only one unit that has 

a capacity of less than or equal to 50 MW. For this analysis, ERG used the annualized costs for 

the chemical precipitation system followed by biological treatment technology option because it 

is the primary treatment technology evaluated in the proposed ELGs. 

Annualized costs for FGD wastewater treatment based on a chemical precipitation system 

followed by biological treatment are calculated at the plant-level because a single treatment 

system is used to treat the wastewater from multiple units.4

 ERG allocated costs to the unit level 

using a crosswalk between the wet FGD scrubbers at the plant and the generating units that they 

service. For plants with multiple FGD systems where each FGD system services only one unit, 

ERG apportioned the annualized costs based on the percentage of the total FGD scrubber purge 

flow contributed by each generating unit. For FGD systems that service more than one 

generating unit, ERG apportioned the annualized costs to the unit level based on the percentage 

of the capacity associated with each of the generating units serviced by the FGD system. For this 

 

4

 The annualized costs used in this analysis were estimated by ERG using a discount rate of 7% and a discounting 

period of 20 years. The annualized costs generated by EPA, which are the basis for the costs presented in the 

preamble and the Regulatory Impact Analysis for Proposed Effluent Limitations Guidelines and Standards for the 

Steam Electric Power Generating Point Source Category (EPA-821-R-13-005), were not used in this analysis; 

however, these annualized costs still represent the general trends and are informative to the analysis. 
Memorandum 

April 19, 2013 

Page 12 

analysis, ERG excluded plants where multiple units were serviced by more than one FGD 

scrubber because there was no way to appropriately apportion the costs to the individual units 

without making assumptions that could skew the analysis. This resulted in the exclusion of six 

plants and 16 generating units. 

Similar to ash, ERG also evaluated the annualized cost per MW for the FGD wastewater 

treatment system excluding transport and disposal portion of the costs. ERG evaluated the costs 

excluding the transport and disposal portion because the capital and O&M costs can be 

substantially influenced by whether the plant uses an on-site or an off-site landfill. 

After estimating unit-level annualized costs for FGD wastewater treatment, ERG calculated the 

resulting cost per MW for each generating unit receiving a cost. Table 7 presents the average 

annualized dollar per MW for units greater than 50 MW and units less than or equal to 50 MW 

for both FGD analyses. Figures 5 and 6 present the cost per MW as a function of unit capacity 

(MW) for all 260 units incurring FGD wastewater treatment costs for all cost components and 

excluding transport and disposal costs, respectively. 

Table 7. Dollar Per MW for FGD Treatment Technology Option 

Costs 

Average $/MW 

for Units ≤ 50 

MW1 

Average $/MW 

for Units > 50 

MW 

FGD Wastewater Treatment Compliance Costs (all cost components) 33,645 4,935 

FGD Wastewater Treatment Compliance Costs (excluding transport and 

disposal) 33,081 4,579 

1

 Represents only one plant. 
Memorandum 

April 19, 2013 

Page 13 

Figure 5. FGD Biological Treatment Annualized Cost Per MW Compared to Unit Capacity 

(MW) 

Figure 6. FGD Biological Treatment Annualized Cost Excluding Transport and Disposal 

Per MW Compared to Unit Capacity (MW) 

2.4 Leachate

Based on the available data and current methodology for estimating compliance costs for 

combustion residual leachate treatment, ERG was unable to calculate unit-level costs without 

making assumptions that could skew the analysis. However, ERG speculates that plants with 

smaller units will have lower leachate flows compared to plants with larger units (assuming all 

things equal regarding geographic location, rainfall, etc). Based on the principles of economies 

of scale, ERG believes that the small units would have higher costs per MW to treat the leachate 

using a chemical precipitation system. For example, a small and a large chemical precipitation 

system will both require system operators and it is likely that no more operators would be 

required for the large system compared with the small system. 

Additionally, ERG reviewed two plants that operate one generating unit with an on-site landfill 

for the disposal of combustion residuals. The steam electric unit at one plant has a capacity of 

approximately 115 MW, has a leachate flow rate of 30,000 gpd, and has an annualized leachate 

treatment cost of approximately $700,000. The cost per MW for this plant to treat the leachate is 

$6,086/MW. The other plant operates a unit with a capacity of 725 MW, has a leachate flow rate 

of 105,000, and has an annualized leachate treatment cost of approximately $1,400,000. The 

dollar per MW for this plant to treat leachate is $1,931/MW. 
Memorandum 

April 19, 2013 

Page 14 

2.5 Evaluation of a Larger Size Threshold

In addition to evaluating whether different effluent limits based on size of plant or generating 

unit are warranted, ERG also reviewed the number of small businesses and municipalities that 

would be affected by size thresholds. Table 8 presents the number of units that would incur 

compliance costs under Regulatory Options 3 and 4, including those units owned by small 

businesses and municipalities. Table 9 presents the number of plants, including those owned by 

small businesses or municipalities, that would avoid incurring compliance costs for one or more 

generating units (i.e., compliance costs would be either partially or completely avoided) by a size 

threshold of 50 MW or 100 MW. For example, under Regulatory Option 4, moving from a size 

threshold of less than or equal to 50 MW to a size threshold of less than or equal to 100 MW, 

would result in an additional 95 generating units not needing to meet the more stringent BAT 

requirements; however, only 10 of those units are associated with small businesses and 15 are 

associated with municipalities. The data show that the increase in the size threshold has only a 

minor affect on the number of small businesses and municipalities that would incur compliance 

costs under Regulatory Options 3 and 4. Attachment 1 also contains additional information for 

different size thresholds evaluated in ERG’s analysis. 

Table 8. Count of Generating Units and Plants Incurring Costs as Part of Regulatory 

Options 3 and 4 

Type of Count Regulatory Option 3 Regulatory Option 4 

Unit 

Total 417 743 

Small 15 40 

Municipality 20 62 

Plant 

Total 169 297 

Small 12 22 

Municipality 11 28 

Note: The number of plants and units are based on values reported in the 2009 survey, which were scaled to 

represent the industry as a whole using the industry-weighting factors discussed in Section 3.3 of the Steam Electric 

TDD [U.S. EPA, 2013]. 

 
Memorandum 

April 19, 2013 

Page 15 

Table 9. Count of Generating Units and Plants Excluded from Regulatory Options 3 and 

4 Based on Size Thresholds 

Type of Count 

Regulatory Option 3 Regulatory Option 4 

Units ≤ 50 

MW 

Units ≤ 100 

MW 

Units ≤ 50 

MW 

Units ≤ 100 

MW 

Unit 

Total 20 52 56 151 

Small 7 9 18 28 

Municipality 5 9 25 40 

Plant – Any 

Removals a

Total 13 26 33 74 

Small 5 7 11 16 

Municipality 2 5 12 17 

Plant – Complete 

Removals b

Total 8 16 13 38 

Small 5 7 8 14 

Municipality 2 4 5 12 

Note: The number of plants and units are based on values reported in the 2009 survey, which were scaled to 

represent the industry as a whole using the industry-weighting factors discussed in Section 3.3 of the Steam Electric 

TDD [U.S. EPA, 2013]. 

a – ERG defines “any removals” as plants that have at least one unit within the capacity threshold that will be 

removed from the population of units incurring costs. 

b – ERG defines “complete removals” as plants that will be completely removed from the population of plants 

incurring costs because all units at the plant are within the capacity threshold. 

3.0 FUEL TYPE

ERG analyzed the fuel type of generating units, included in the scope of the rule, to determine if 

fuel type has an effect on the wastewater characteristics, processes in place, or the ability to 

install the treatment technologies evaluated as part of the proposed ELGs. Using data from the 

Steam Electric Survey, ERG classified generating units by fuel type based on the following 

hierarchy: coal, petroleum coke, oil, gas, and nuclear. For example, if a unit burns both coal and 

gas then it was categorized as coal, even if coal was reported as generating less electricity 

compared to other fuel groups. ERG identified 247 plants and 743 generating units, based on 

survey weighting, incurring costs to comply with Regulatory Options 3 and 4 considered by 

EPA. All 743 generating units incurring compliance costs are classified as coal, petroleum coke, 

or oil fuel types. Because ERG did not identify any gas or nuclear units incurring costs for the 

proposed ELGs, different effluent discharge requirements were not needed for these units. 

ERG determined that oil-fired units currently discharge fly and bottom ash transport water; 

however, oil-fired units do not operate wet FGD systems. ERG determined that the waste 

streams most influenced by fuel-type are fly and bottom ash transport water, because the quantity 

and quality of ash generated from oil-fired units is different from those generated from coal- and 

petroleum-coke fired units. 

For this reason, ERG evaluated the characteristics of oil-fired units to determine if different 

effluent discharge requirements would be appropriate for oil-fired units. The generating unit 

characteristics ERG reviewed as part of this analysis include age, unit type, total days of 
Memorandum 

April 19, 2013 

Page 16 

operation, and capacity utilization for oil-fired units. Using data from the Steam Electric Survey 

and the 2009 EIA database, ERG determined that over 60 percent of oil-fired units are 30 to 50 

years old. Additionally, a total of 25 percent of the oil-fired units are greater than 50 years old. 

ERG also determined that over 75 percent of all oil-fired units are cycling, intermediate, or 

peaking units; compared to only 30 percent of coal-fired units that are cycling, intermediate, or 

peaking. Additionally, ERG determined that over half of oil-fired units in the industry operated 

less than 30 calendar days in 2009; compared to an average of 261 operating days for all coalfired units. 

 

ERG also reviewed the capacity utilization for oil-fired units versus other units in the industry to 

determine if different effluent discharge requirements would be appropriate for oil-fired units. 

For this analysis, ERG defines capacity utilization as the percent of actual electricity generated in 

2009 compared to the potential yearly electricity generation based on generating unit capacity. 

Over 75 percent of the oil-fired units have a calculated capacity utilization factor less than 25 

percent. Alternatively, over 60 percent of coal-fired units have a calculated capacity utilization 

factor over 50 percent. 

Based on the analysis, ERG determined that the oil-fired units are generally older and operate 

intermittently (i.e., they are peaking, cycling, or intermediate units). While ERG recognizes that 

these oil-fired units are capable of installing and operating the treatment technologies evaluated 

as part of the proposed ELGs and that the costs would be affordable for most of the plants, ERG 

believes that companies may choose to shut these oil-fired units down instead of making the 

investment to comply with the ELGs. If these units were shut down, it could reduce the 

flexibility that grid operators have during peak demand. 

ERG also evaluated whether it would be appropriate to establish different effluent discharge 

requirements based on the type of coal used at a plant. Based on the responses reported in the 

Steam Electric Survey and information obtained during site visits, ERG found that 

approximately 22 percent of generating units burn a blend of different types of coal within a 

single generating unit, some plants burn different coals in different units, and some plants switch 

the types of coal burned in the generating units based on the cheapest sources available. For 

these reasons, the type of coal used at a plant is not an appropriate basis for setting different 

effluent requirements. 

4.0 GEOGRAPHIC LOCATION

ERG analyzed the geographic location of the generating units, included in the scope of the rule, 

to determine if geographic location has an impact on the wastewater characteristics, processes in 

place, or the ability to install the treatment technologies evaluated as part of the proposed ELGs. 

ERG determined the geographic location of the generating units using responses from the Steam 

Electric Survey. Based on an analysis of the Steam Electric Survey data, ERG found that wet 

FGD systems, both wet and dry fly ash handling systems, and both wet and dry bottom ash 

handling systems are located through the United States and that the geographic location of the 
Memorandum 

April 19, 2013 

Page 17 

plant by itself does not affect the wastewater characteristics, the processes in place, or the ability 

to install the treatment technologies evaluated as part of the proposed ELGs. 

ERG determined that the location of the plant does not impact the plant’s ability to install the 

treatment technologies for the treatment of FGD wastewater for plants currently operating wet 

FGD systems. Figure 7 presents a map of all plants operating a wet scrubber in the United States. 

Figure 8 presents a map of the plants currently treating the FGD wastewater with chemical 

precipitation and/or biological treatment, as well as those plants not discharging FGD 

wastewater. Figures 7 and 8 show that chemical precipitation systems are being operated in all 

the general regions where wet FGD systems are being operated. While Figure 8 shows that the 

biological treatment system is only operating in one state (i.e., North Carolina), there is no 

reason that the system could not be installed at other locations. Potential concerns regarding 

temperatures in the north and south can be alleviated by operating heat exchangers to cool the 

wastewater or locating the system in a building to prevent the biological material from freezing 

during the winter. 

ERG also determined that the location of the plant does not impact the plant’s ability to retrofit 

dry fly ash or bottom ash handling systems for units currently wet sluicing ash. Figures 9 and 11 

show the plant-level fly and bottom ash handling systems operating in the United States, 

respectively. Additionally, Figures 10 and 12 show the locations where plants have retrofitted fly 

and bottom ash handling units to dry systems, respectively. Figures 10 and 12 show that the 

conversions to dry fly ash and bottom ash handling systems have occurred all over the country. 

Based on these analyses, geographic location is not an appropriate basis for setting different 

effluent requirements. 
Memorandum 

April 19, 2013 

Page 18 

Figure 7. Plants Operating Wet FGD Scrubber Systems 

Figure 8. Wastewater Treatment at Plants Operating Wet FGD Scrubber Systems 
Memorandum 

April 19, 2013 

Page 19 

Figure 9. Plant-Level Fly Ash Transport Systems 

Figure 10. Plant-Level Fly Ash Dry Retrofit Transport Systems 
Memorandum 

April 19, 2013 

Page 20 

Figure 11. Plant-Level Bottom Ash Transport Systems 

Figure 12. Plant-Level Bottom Ash Dry Retrofit Transport Systems
Attachment 1
Attachment 1 

April 19, 2013 

Page A1 

 

Fuel Types for Steam Electric Generating Units 

Table A1. Distribution of Generating Fuel Type and Capacity Threshold 

Unit Fuel Type a

Number of Generating Units 

≤50MW ≤100 MW ≤150 MW ≤200 MW 

Total Units 

(All Sizes) 

Coal or Petroleum Coke 149 305 431 570 1,095

Oil [Redacted] [Redacted] [Redacted] [Redacted] 91

Total [Redacted] [Redacted] [Redacted] [Redacted] 1,186

Note: Table A1 includes a complete count of steam electric generating units operated in 2009, weighted from data 

reported in the Steam Electric Survey. Table A1 also includes the count of units that fall in the ≤ 50 MW or ≤100 

MW size groups. Each of these size groups is a subset of the count of total units. The remainder of the tables in this 

attachment also present counts of steam electric generating units for different subsets of operating characteristics, 

and exclude units for which data were missing. For this reason, only Table A1 includes the full count of all steam 

electric generating units. 

a – Units were first classified by fuel group based on the following hierarchy: coal, oil, gas, and nuclear. For 

example, if a unit burns both coal and gas then it was categorized as coal, even if coal was reported as generating 

less electricity compared to other fuel groups. Units were then categorized by the type of fuel burned. The fuel types 

presented in the remainder of the tables in this attachment were classified using the same approach. 
Attachment 1 

April 19, 2013 

Page A2 

Age of Steam Electric Generating Units

Table B1. Distribution for All Coal-, Petroleum Coke-, and Oil-Fired Units 

Unit Fuel Type 

Number of Generating Units, by Age (in 2009) 

<10 Years 

10-20 

Years 

20-30 

Years 

30-40 

Years 

40-50 

Years 

>50 

Years 

Coal or Petroleum Coke [Redacted] 35 106 181 202 314

Oil 2 0 5 23 12 15

Total [Redacted] 35 111 204 214 329

Note: The age of each generating unit was not requested in the Steam Electric Survey; therefore, Table B1 only 

includes [Redacted] generating units that were able to be matched to publicly available EIA data. 

Note: Numbers represent weighted survey results. 

Table B2. Distribution for Coal-, Petroleum Coke-, and Oil-Fired Units with Generating 

Capacities ≤200 MW 

Unit Fuel Type 

Number of Generating Units, by Age (in 2009) 

<10 Years 

10-20 

Years 

20-30 

Years 

30-40 

Years 

40-50 

Years >50 Years 

Coal or Petroleum Coke 3 26 18 18 98 270

Oil 2 0 0 [Redacted] 6 14

Total 5 26 18 [Redacted] 104 284

Note: The age of each generating unit was not requested in the Steam Electric Survey; therefore, Table B2 only 

includes [Redacted] generating units ≤200 MW that were able to be matched to publicly available EIA data. 

Note: Numbers represent weighted survey results. 

Table B3. Distribution for Coal-, Petroleum Coke-, and Oil-Fired Units with Generating 

Capacities ≤150 MW 

Unit Fuel Type 

Number of Generating Units, by Age (in 2009) 

<10 Years 

10-20 

Years 

20-30 

Years 

30-40 

Years 

40-50 

Years >50 Years 

Coal or Petroleum Coke 3 23 16 12 [Redacted] 195

Oil 2 0 0 [Redacted] 5 14

Total 5 23 16 [Redacted] [Redacted] 208

Note: The age of each generating unit was not requested in the Steam Electric Survey; therefore, Table B3 only 

includes [Redacted] generating units ≤150 MW that were able to be matched to publicly available EIA data. 

Note: Numbers represent weighted survey results. 
Attachment 1 

April 19, 2013 

Page A3 

 

Table B4. Distribution for Coal-, Petroleum Coke-, and Oil-Fired Units with Generating 

Capacities ≤100 MW 

Unit Fuel Type 

Number of Generating Units, by Age (in 2009) 

<10 Years 

10-20 

Years 

20-30 

Years 

30-40 

Years 

40-50 

Years >50 Years 

Coal or Petroleum Coke 3 20 15 9 [Redacted] 121

Oil 2 0 0 [Redacted] 5 14

Total 5 20 15 [Redacted] [Redacted] 135

Note: The age of each generating unit was not requested in the Steam Electric Survey; therefore, Table B4 only 

includes [Redacted] generating units ≤100 MW that were able to be matched to publicly available EIA data. 

Note: Numbers represent weighted survey results. 

Table B5. Distribution for Coal-, Petroleum Coke-, and Oil-Fired Units with Generating 

Capacities ≤50 MW 

Unit Fuel Type 

Number of Generating Units, by Age (in 2009) 

<10 

Years 

10-20 

Years 

20-30 

Years 

30-40 

Years 

40-50 

Years >50 Years 

Coal or Petroleum Coke 1 6 5 6 [Redacted] [Redacted]

Oil 2 0 0 [Redacted] 5 7

Total 3 6 5 [Redacted] [Redacted] [Redacted]

Note: The age of each generating unit was not requested in the Steam Electric Survey; therefore, Table B5 only 

includes [Redacted] generating units ≤50 MW that were able to be matched to publicly available EIA data. 

Note: Numbers represent weighted survey results. 
Attachment 1 

April 19, 2013 

Page A4 

 

Capacity Utilization of Steam Electric Generating Units – 25% 

Cutoff

Table C1. Distribution for All Coal-, Petroleum Coke-, and Oil-Fired Units 

Unit Fuel Type 

Number of Generating Units, by Capacity Utilization 

0-25% >25% 

Coal or Petroleum Coke 185 904

Oil 70 [Redacted]

Total 255 [Redacted]

Note: Table C1 only includes [Redacted] generating units with both a reported steam electric capacity and reported 

electricity generation greater than zero in 2009 in survey responses. 

Note: Numbers represent weighted survey results.

Table C2. Distribution for Coal-, Petroleum Coke-, and Oil-Fired Units with Generating 

Capacities ≤200 MW 

Unit Fuel Type 

Number of Generating Units, by Capacity Utilization 

0-25% >25% 

Coal or Petroleum Coke 168 398

Oil [Redacted] [Redacted]

Total [Redacted] [Redacted]

Note: Table C2 only includes [Redacted] generating units with both a reported steam electric capacity and reported 

electricity generation greater than zero in 2009 in survey responses. 

Note: Numbers represent weighted survey results.

Table C3. Distribution for Coal-, Petroleum Coke-, and Oil-Fired Units with Generating 

Capacities ≤150 MW 

Unit Fuel Type 

Number of Generating Units, by Capacity Utilization 

0-25% >25% 

Coal or Petroleum Coke 141 286

Oil [Redacted] 14

Total [Redacted] 300

Note: Table C3 only includes [Redacted] generating units with both a reported steam electric capacity and reported 

electricity generation greater than zero in 2009 in survey responses. 

Note: Numbers represent weighted survey results.
Attachment 1 

April 19, 2013 

Page A5 

 

Table C4. Distribution for Coal-, Petroleum Coke-, and Oil-Fired Units with Generating 

Capacities ≤100 MW 

Unit Fuel Type 

Number of Generating Units, by Capacity Utilization 

0-25% >25% 

Coal or Petroleum Coke 112 189

Oil [Redacted] 14

Total [Redacted] 203

Note: Table C4 only includes [Redacted] generating units with both a reported steam electric capacity and reported 

electricity generation greater than zero in 2009 in survey responses. 

Note: Numbers represent weighted survey results.

Table C5. Distribution for Coal-, Petroleum Coke-, and Oil-Fired Units with Generating 

Capacities ≤50 MW 

Unit Fuel Type 

Number of Generating Units, by Capacity Utilization 

0-25% >25% 

Coal or Petroleum Coke [Redacted] 86

Oil [Redacted] 12

Total [Redacted] 98

Note: Table C5 only includes [Redacted] generating units with both a reported steam electric capacity and reported 

electricity generation greater than zero in 2009 in survey responses. 

Note: Numbers represent weighted survey results.
Attachment 1 

April 19, 2013 

Page A6 

 

Capacity Utilization of Steam Electric Generating Units – 15% 

Cutoff

Table D1. Distribution for All Coal-, Petroleum Coke-, and Oil-Fired Units 

Unit Fuel Type 

Number of Generating Units, by Capacity Utilization 

0-15% >15% 

Coal or Petroleum Coke 124 965

Oil 52 [Redacted]

Total 176 [Redacted]

Note: Table D1 only includes [Redacted] generating units with both a reported steam electric capacity and reported 

electricity generation greater than zero in 2009 in survey responses. 

Note: Numbers represent weighted survey results.

Table D2. Distribution for Coal-, Petroleum Coke-, and Oil-Fired Units with Generating 

Capacities ≤200 MW 

Unit Fuel Type 

Number of Generating Units, by Capacity Utilization 

0-15% >15% 

Coal or Petroleum Coke 116 450

Oil [Redacted] [Redacted]

Total [Redacted] [Redacted]

Note: Table D2 only includes [Redacted] generating units with both a reported steam electric capacity and reported 

electricity generation greater than zero in 2009 in survey responses. 

Note: Numbers represent weighted survey results.

Table D3. Distribution for Coal-, Petroleum Coke-, and Oil-Fired Units with Generating 

Capacities ≤150 MW 

Unit Fuel Type 

Number of Generating Units, by Capacity Utilization 

0-15% >15% 

Coal or Petroleum Coke 105 322

Oil [Redacted] 24

Total [Redacted] 346

Note: Table D3 only includes [Redacted] generating units with both a reported steam electric capacity and reported 

electricity generation greater than zero in 2009 in survey responses. 

Note: Numbers represent weighted survey results.
Attachment 1 

April 19, 2013 

Page A7 

 

Table D4. Distribution for Coal-, Petroleum Coke-, and Oil-Fired Units with Generating 

Capacities ≤100 MW 

Unit Fuel Type 

Number of Generating Units, by Capacity Utilization 

0-15% >15% 

Coal or Petroleum Coke 91 210

Oil [Redacted] 24

Total [Redacted] 234

Note: Table D4 only includes [Redacted] generating units with both a reported steam electric capacity and reported 

electricity generation greater than zero in 2009 in survey responses. 

Note: Numbers represent weighted survey results.

Table D5. Distribution for Coal-, Petroleum Coke-, and Oil-Fired Units with Generating 

Capacities ≤50 MW 

Unit Fuel Type 

Number of Generating Units, by Capacity Utilization 

0-15% >15% 

Coal or Petroleum Coke [Redacted] 95

Oil [Redacted] 19

Total [Redacted] 114

Note: Table D5 only includes [Redacted] generating units with both a reported steam electric capacity and reported 

electricity generation greater than zero in 2009 in survey responses. 

Note: Numbers represent weighted survey results.
Attachment 1 

April 19, 2013 

Page A8 

 

Age Distribution of Steam Electric Generating Units Based on 

Capacity Utilization – 15% Cutoff 

Table E1. Distribution for All Coal-, Petroleum Coke-, and Oil-Fired Units for Units with 

a Capacity Utilization ≤15 Percent 

Unit Fuel Type 

Number of Generating Units, by Age (in 2009) 

<10 

Years 

10-20 

Years 

20-30 

Years 

30-40 

Years 

40-50 

Years >50 Years 

Coal or Petroleum Coke 0 3 5 4 15 [Redacted]

Oil 0 0 1 17 10 10

Total 0 3 6 21 25 [Redacted]

There are [Redacted] units that have a capacity utilization of ≤15 percent; only [Redacted] units could be matched to 

the EIA data. 

Table E2. Distribution for All Coal-, Petroleum Coke-, and Oil-Fired Units for Units with 

a Capacity Utilization >15 Percent 

Unit Fuel Type 

Number of Generating Units, by Age (in 2009) 

<10 Years 

10-20 

Years 

20-30 

Years 

30-40 

Years 

40-50 

Years 

>50 

Years 

Coal or Petroleum Coke [Redacted] 32 101 177 187 245

Oil 2 0 4 5 3 5

Total [Redacted] 32 105 182 190 250

There are [Redacted] units that have a capacity utilization of >15 percent; only [Redacted] units could be matched to 

the EIA data. 
Attachment 1 

April 19, 2013 

Page A9 

 

Age Distribution of Steam Electric Generating Units Based on 

Capacity Utilization – 25% Cutoff 

Table F1. Distribution for All Coal-, Petroleum Coke-, and Oil-Fired Units for Units with a 

Capacity Utilization ≤25 Percent 

Unit Fuel Type 

Number of Generating Units, by Age (in 2009) 

<10 

Years 

10-20 

Years 

20-30 

Years 

30-40 

Years 

40-50 

Years >50 Years 

Coal or Petroleum Coke 0 [Redacted] 7 6 [Redacted] [Redacted]

Oil 0 0 1 19 10 15

Total 0 [Redacted] 8 25 [Redacted] [Redacted]

There are [Redacted] units that have a capacity utilization of ≤25 percent; only [Redacted] units could be matched to 

the EIA data. 

Table F2. Distribution for All Coal-, Petroleum Coke-, and Oil-Fired Units for Units with a 

Capacity Utilization >25 Percent 

Unit Fuel Type 

Number of Generating Units, by Age (in 2009) 

<10 Years 

10-20 

Years 

20-30 

Years 

30-40 

Years 

40-50 

Years 

>50 

Years 

Coal or Petroleum Coke [Redacted] 27 99 175 179 212

Oil 2 0 4 3 3 0

Total [Redacted] 27 103 178 182 212

There are[Redacted] units that have a capacity utilization of >25 percent; only [Redacted] units could be matched to 

the EIA data.