MEMORANDUM 

TO: Steam Electric Rulemaking Record 

FROM: TJ Finseth, ERG 

DATE: April 19, 2013 

SUBJECT: Methodologies for Estimating Costs and Pollutant Removals for Steam 

Electric ELG Regulatory Options 3a and 3b 

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 (ELGs) for the Steam Electric Power Generating Industry. EPA, with 

the support of ERG, collected data through survey responses, site visits, sampling episodes, and 

from individual power plants and equipment vendors to estimate compliance costs and pollutant 

loadings and corresponding pollutant removals associated with installing and operating the 

various technologies and practices that make up the regulatory options considered by EPA. EPA 

used these data to develop computerized costs and loadings models, which EPA used to calculate 

plant-specific compliance costs for all power plants that the data suggests would incur costs to 

comply with one or more of the proposed requirements associated with the regulatory options. 

The data and the methodologies used to estimate the compliance costs and pollutant loadings for 

each wastestream are described in EPA’s Incremental Costs and Pollutant Removals for 

Proposed Effluent Limitation Guidelines and Standards for the Steam Electric Generating Point 

Source Category (DCN SE01957). Additionally, the report includes the plant-specific costs and 

loadings output. As described in the report, EPA used the cost and loadings models estimate 

plant specific costs and loadings for each wastestream and five of the eight regulatory options 

(Options 1, 2, 3, 4, and 5). EPA then used the costs and loadings output from these five options 

to estimate the costs and pollutant loadings associated with Options 3a, 3b, and 4a. The purpose 

of this memorandum is to describe the methodology and calculations EPA used to estimate 

compliance costs and pollutant loadings and corresponding pollutant removals associated with 

Regulatory Options 3a and 3b. 

1.0 REGULATORY OPTION 3A

One of the eight regulatory options considered by EPA is referred to as Option 3a. Under Option 

3a, the proposed rule would establish BAT for the following wastestreams for all generating 

units except oil-fired generating units and small generating units (i.e., 50 MW or smaller) that 

include:1

 

1

 The proposed BAT limitations for nonchemical metal cleaning wastes apply to all generating units, including oilfired generating units and small generating units (i.e., 50 MW or smaller). 
Memorandum 

April 19, 2013 

Page 2 

 “Zero discharge” effluent limit for all pollutants in fly ash transport water and 

wastewater from flue gas mercury control systems; 

 Numeric effluent limits for mercury, arsenic, selenium and TDS in discharges of 

wastewater from gasification processes; 

 Numeric effluent limits for copper and iron in discharges of nonchemical metal 

cleaning wastes;2

 and 

 Effluent limits for bottom ash transport water and combustion residual leachate from 

landfills and surface impoundments that are equal to the current Best Practicable 

Control Technology Currently Available (BPT) effluent limits for these discharges 

(i.e., numeric effluent limits for TSS and oil and grease). 

As described in Section 9.2 of the Technical Development Document for the Proposed Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source 

Category, there are no incremental compliance costs associated with the proposed ELGs for 

gasification wastewater, flue gas mercury control wastewater, and nonchemical metal cleaning 

wastes because the technology bases are already current industry practice or because the industry 

is already meeting the limits or will be exempt from meeting the limits. Therefore, for Option 3a, 

the compliance costs, pollutant removals, and non-water quality impacts (NWQI) are equal to 

those estimated for dry fly ash handling for Options 3, 4, and 5. 

1.1 Option 3a Compliance Costs and Pollutant Removals

As described above, the Option 3a compliance costs and pollutant removals are equal to the 

estimated values associated with dry fly ash handling conversions estimated using EPA’s 

methodology described in Chapters 7 and 10 of EPA’s Incremental Costs and Pollutant 

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

Power Generating Guidelines report (DCN SE01957). Therefore, to estimate the Option 3a 

compliance costs and pollutant removals, EPA used the same fly ash values used to calculate the 

option-level compliance costs and pollutant removals for Option 3. Table 1-1 and Table 1-2 

present the compliance costs and pollutant removals for Option 3a. 

Table 1-1. Estimated Industry-Level Compliance Costs for Option 3a 

[In pre-tax 2010 dollars] 

Number of Plants 

Total Capital Cost 

($) 

Total O&M Cost 

($/year) 

10-Year Recurring Cost 

($/10-year)a 

66 $398,000,000 $177,000,000 ($20,700,000) 

a – The values in this column are negative because they represent cost savings. 

Note: Costs are rounded to three significant figures. 

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2011].

 

2

 As described in Section 8 of the Technical Development Document for the Proposed Effluent Limitations 

Guidelines and Standards for the Steam Electric Power Generating Point Source Category, EPA is proposing to 

exempt from new copper and iron BAT limitations any existing discharges of nonchemical metal cleaning wastes 

that are currently authorized without iron and copper limits. For these discharges, BAT limits would be set equal to 

BPT limits applicable to low volume wastes. 
Memorandum 

April 19, 2013 

Page 3 

Table 1-2. Estimated Pollutant Removals for Option 3a 

Total Industry Loading Total Industry Pollutant Removals a

Pounds/Year TWPE/Year Pounds/Year TWPE/Year 

5,030,000,000 5,830,000 471,000,000 2,490,000 

a - Compared to baseline. 

Note: Excludes loadings for BOD, COD, TDS, and TSS. 

Note: Removals are rounded to three significant figures. 

1.2 Option 3a Non-Water Quality Environmental Impacts

Option 3a non-water quality environmental impacts (NWQI) are equal to the values associated 

with dry fly ash handling conversions estimated using EPA’s methodology described in the 

memorandum “Steam Electric Effluent Guidelines Non-Water Quality Impacts” (DCN 

SE02025). These fly ash NWQI values are the same values used to calculate Option 3 NWQI for 

the following NWQI categories: 

 Energy requirements (measured as electrical energy usage (MWh)); 

 Fuel consumption (in gallons per year); 

 Air emissions associated with transportation (in tons per year); 

 Sludge production (in tons per year); and 

 Water intake reductions (in million gallons per year). 

Fly ash is a solid waste that is generated at steam electric power plants. The technology basis for 

Option 3a is to convert to a dry fly ash handling system, which does not alter the amount of ash 

generated by steam electric generating units. Therefore, the incremental increase in sludge 

production associated with Option 3a is zero tons per year (tpy). See DCN SE02957 for the 

plant-level NWQI estimates associated with electrical energy consumption, fuel consumption, 

and transportation air emissions for the conversion to a dry fly ash handling system. See DCN 

SE02980 for the plant-level water intake reductions associated with the conversion to a dry fly 

ash handling system. 

Additionally, EPA estimated air emissions associated with increased auxiliary energy required to 

operate the systems needed to comply with the new ELGs and the change in the profile of 

electricity generation due to relatively higher costs to generate electricity at plants incurring 

compliance costs for the proposed rule (as projected by the Integrated Planning Model (IPM)). 

Because the only difference between Options 2 and 3 is that under Option 3 plants would be 

required to meet the “zero discharge” requirements for fly ash transport water3

, EPA estimated 

industry-level Option 3a air emissions associated with auxiliary energy as the difference between 

the industry-level values calculated for Options 2 and 3. The air emissions associated with the 

change in industry profile projected by IPM4

 were only calculated for Options 3 and 4. Based on 

the values quantified for Option 3 for the changes to air emissions projected by IPM, EPA 

 

3

 Options 2 and 3 would establish the same numeric effluent limitations for arsenic, mercury, selenium, and nitratenitrite for all discharges of FGD wastewater, except for those associated with oil-fired units and small generating 

units (i.e., 50 MW or smaller). 

4

 It does not include an estimate for methane. 
Memorandum 

April 19, 2013 

Page 4 

calculated the range of emissions expected for NOx for Option 3a. The lower end of the range 

represents the emissions only associated with additional electricity and transportation. The upper 

end of the range also includes the changes to air emissions projected by IPM (based on Option 

3), which are larger than would be expected for Option 3a. Similarly, based on the values 

quantified for Option 3 for the changes to air emissions projected by IPM, which were negative, 

EPA decided not to include these IPM air emission changes in the calculated SOx and CO2

emissions for Option 3a. These SOx and CO2 emissions are considered maximum values because 

EPA expects that the air emission changes projected by IPM for Option 3a will also be negative 

(as they are for Options 3 and 4). Table 1-3 presents a summary of the industry-level NWQI 

estimated for Option 3a. 

Table 1-3. Industry-Level Non-Water Quality Impacts Estimates for 

Option 3a 

Energy 

Electrical Energy Usage 112,004 MWh/year 

Fuel Consumption 2,867,770 gal/year 

Air Emissions 

NOX 88-1,090 tons/year 

SOX <84 tons/year 

CO2 <117,863 metric tons/year 

CH4 2.4 tons/year 

Sludge Production 

Sludge 0 tons/year 

Water Intake Water Reductions

Water Reduction 49,900 million gal/year 

2.0 REGULATORY OPTION 3B

One of the other eight regulatory options considered by EPA is referred to as Option 3b. Under 

Option 3b, the proposed rule would establish numeric effluent limits for mercury, arsenic, 

selenium, and nitrate-nitrite in discharges of FGD wastewater from certain steam electric plants 

(those with a total plant-level wet scrubbed capacity of 2,000 MW or greater5

). All other 

proposed Option 3b requirements are identical to the proposed 3a requirements described in 

Section 1.0. Because the proposed requirements under Option 3b are identical to Option 3a plus 

the additional requirements for FGD wastewater, the compliance costs, pollutant removals, and 

NWQI associated with Option 3b are equal to Option 3a plus the associated compliance costs, 

pollutant removals, and NWQI for the 17 plants operating wet FGD systems with a total plantlevel wet scrubbed capacity of 2,000 MW or greater. The compliance costs, pollutant removals, 

and NWQI for the 17 plants are equal to the estimated values for those plants for Option 2 

because Option 2 and Option 3b have the same technology basis for FGD wastewater. See 

Attachment 1 (DCN SE03881.A1) for the listing of the 17 FGD plants identified as needing to 

comply with the FGD wastewater requirements that would be established under Option 3b. 

 

5

 Total plant-level wet scrubbed capacity is calculated by summing the nameplate capacity for all of the units that 

are serviced by wet FGD systems.
Memorandum 

April 19, 2013 

Page 5 

2.1 Option 3b Compliance Costs and Pollutant Removals

Option 3b compliance costs and pollutant removals are equal to the estimated values associated 

with dry fly ash handling conversions plus the compliance costs and pollutant removals 

associated with chemical precipitations followed by biological treatment for the 17 plants 

operating wet FGD systems with a total plant-level wet scrubbed capacity of 2,000 MW or 

greater estimated using EPA’s methodology described in Chapters 6.1, 6.2, 7, and 10 of EPA’s 

Incremental Costs and Pollutant Removals for the Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Guidelines report (DCN SE01957). 

Therefore, to estimate the Option 3b compliance costs and pollutant removals, EPA used the 

same fly ash and FGD chemical precipitation followed by biological treatment values to 

calculate the option-level compliance costs and pollutant removals for Option 3; however, for the 

FGD chemical precipitation followed by biological treatment, only the 17 plants identified as 

needing to comply with the FGD wastewater requirements that would be established under 

Option 3b were summed to calculate the option-level values. 

Table 2-1 and Table 2-2 present the compliance costs and pollutant removals for Option 3b, 

which are equal to the sum of Option 3a plus the additional biological treatment compliance 

costs and pollutant removals for the 17 FGD plants identified as needing to comply with the 

FGD wastewater requirements that would be established under Option 3b. 

Table 2-1. Estimated Industry-Level Compliance Costs for Option 3b 

[In pre-tax 2010 dollars] 

Number of 

Plants 

Total Capital Cost 

($) 

Total O&M Cost 

($/year) 

6-Year Recurring 

Cost 

($/6-year) 

10-Year Recurring 

Cost 

($/10-year)a 

80 $998,000,000 $244,000,000 1,450,000 ($26,300,000) 

a – The values in this column are negative because they represent cost savings. 

Note: Costs are rounded to three significant figures. 

Note: All costs are indexed to 2010 dollars using RSMeans Historical Cost Indices [RSMeans, 2011].

Table 2-2. Estimated Pollutant Removals for Option 3b 

Total Industry Loading Total Industry Pollutant Removals a

Pounds/Year TWPE/Year Pounds/Year TWPE/Year 

4,590,000,000 4,920,000 916,000,000 3,400,000 

a - Compared to baseline. 

Note: Excludes loadings for BOD, COD, TDS, and TSS. 

Note: Removals are rounded to three significant figures. 

2.2 Option 3b Non-Water Quality Environmental Impacts

Option 3b NWQI are equal to the values associated with dry fly ash handling conversions plus 

the NWQI associated with biological treatment for the 17 plants operating wet FGD systems 

with a total plant-level wet scrubbed capacity of 2,000 MW or greater estimated using EPA’s 
Memorandum 

April 19, 2013 

Page 6 

methodology described in the memorandum “Steam Electric Effluent Guidelines Non-Water 

Quality Impacts” (DCN SE02025). These fly ash and FGD chemical precipitation followed by 

biological treatment NWQI values are the same values used to calculate Option 3 NWQI for the 

following NWQI categories: 

 Energy requirements (measured as electrical energy usage (MWh)); 

 Fuel consumption (in gallons per year); 

 Air emissions associated with transportation (in tons per year); 

 Sludge production (in tons per year); and 

 Water intake reductions (in million gallons per year). 

EPA estimated Option 3b NWQI for each of the categories above by summing the Option 3a 

NWQI and the FGD chemical precipitation followed by biological treatment NWQI associated 

with the 17 plants. See DCN SE02957 for the plant-level NWQI estimates associated with 

electrical energy consumption, fuel consumption, and transportation air emissions for the 

conversion to a dry fly ash handling system and installation/operation of a FGD chemical 

precipitation followed by biological treatment system. See DCN SE02980 for the plant-level 

water intake reductions associated with the conversion to a dry fly ash handling system and FGD 

wastewater recycle. 

Additionally, EPA estimated air emissions associated with increased auxiliary energy required to 

operate the systems needed to comply with the new ELGs. As described in Section 1.2, EPA 

used the difference in estimated industry-level air emissions between Options 2 and 3 to estimate 

the increase in industry-level air emissions from auxiliary energy associated with Option 3a (i.e., 

dry fly ash handling conversions). EPA estimated the air emissions associated with the FGD 

chemical precipitation and biological treatment systems for Option 3b using the plant-specific 

values estimated for Option 2, but only for the 17 plants identified as needing to comply with the 

FGD wastewater requirements under Option 3b (DCN SE02896). The total Option 3b air 

emissions were calculated by summing these two estimated values. 

EPA also estimated air emissions associated with the change in industry profile projected by 

IPM6

, which were only calculated for Options 3 and 4. Based on the values quantified for Option 

3 for the changes to air emissions projected by IPM, EPA calculated the range of emissions 

expected for NOx for Option 3b. The lower end of the range represents the emissions only 

associated with additional electricity and transportation. The upper end of the range also includes 

the changes to air emissions projected by IPM (based on Option 3), which are larger than would 

be expected for Option 3b. Similarly, based on the values quantified for Option 3 for the changes 

to air emissions projected by IPM, which were negative, EPA decided not to include these IPM 

air emission changes in the calculated SOx and CO2 emissions for Option 3b. These SOx and 

CO2 emissions are considered maximum values because EPA expects that the air emission 

changes projected by IPM for Option 3b will also be negative (as they are for Options 3 and 4). 

Table 2-3 presents a summary of the industry level NWQI estimated for Option 3b. 

 

6

 It does not include an estimate for methane. 
Memorandum 

April 19, 2013 

Page 7 

Table 2-3. Industry-Level Non-Water Quality Impacts Estimates for 

Option 3b 

Energy 

Electrical Energy Usage 160,753 MWh/year 

Fuel Consumption 2,903,656 gal/year 

Air Emissions 

NOX 110-1,110 tons/year 

SOX <130 tons/year 

CO2 <164,318 metric tons/year 

CH4 3.1 tons/year 

Sludge Production 

Sludge 365,960 tons/year 

Water Intake Water Reductions

Water Reduction 52,100 million gal/year