### 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 (E AD) for development of effluent limitations guidelines and standards (ELGs) for the Steam Electric Power Generati ng Industry. EPA, with the support of ERG, collected da ta through survey responses, site visits, sampling episodes, and from individual power plants and equipment ve ndors 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 op tions considered by EPA. EPA used these data to develop computerized costs an d loadings models, which EPA used to calculate plant-specific compliance costs for all power plan ts that the data suggests would incur costs to comply with one or more of the proposed require ments 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 Sta ndards for the Steam Electric Generating Point Source Category (DCN SE01957). Additionally, the report in cludes 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 wastestr eam and five of the eight regulatory options (Options 1, 2, 3, 4, and 5). EPA then used the cost s and loadings output from these five options to estimate the costs and pollutant loadings a ssociated with Options 3a, 3b, and 4a. The purpose

of this memorandum is to describe the met hodology and calculations EPA used to estimate compliance costs and pollutant loadings and co rresponding pollutant removals associated with Regulatory Options 3a and 3b.

1.0 R EGULATORY O PTION 3 A

One of the eight regulatory options considered by EPA is referre d 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 cleani ng 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 pol lutants in fly ash transport water and wastewater from flue gas mercury control systems;

 Numeric effluent limits for mercury, arseni c, selenium and TDS in discharges of wastewater from gasi fication processes;

 Numeric effluent limits for copper and ir on in discharges of nonchemical metal cleaning wastes; 2 and

 Effluent limits for bottom ash transport wa ter and combustion residual leachate from landfills and surface impoundments that are e qual 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 th e 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 cu rrent industry practice or because the industry is already meeting the limits or will be exempt fr om 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 co sts and pollutant removals are equal to the

estimated values associated with dry fly ash handling conve rsions 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). Therefor e, 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 re movals for Option 3. Table 1-1 and Table 1-2 present the compliance costs and po llutant 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 nega tive 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 lim its. 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 Qualit y Environmental Impacts

Option 3a non-water quality environmental impact s (NWQI) are equal to the values associated with dry fly ash handling conversions estimat ed using EPA’s methodology described in the

memorandum “Steam Electric Effluent Guidel ines 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 tr ansportation (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 handli ng system, which does not alter the amount of ash generated by steam electric generating units. Therefore, the incremen tal increase in sludge production associated with Option 3a is zero tons per year (tpy). See DCN SE02957 for the plant-level NWQI estimates asso ciated with electrical energy consumption, fuel consumption, and transportation air emissions for the convers ion to a dry fly ash handling system. See DCN SE02980 for the plant-level water in take reductions associated with the conversion to a dry fly ash handling system.

Additionally, EPA estimated air emissions associat ed with increased auxi liary energy required to operate the systems needed to comply with th e new ELGs and the change in the profile of electricity generation due to rela tively higher costs to generate electricity at plants incurring compliance costs for the proposed rule (as proj ected by the Integrated Planning Model (IPM)). Because the only difference between Options 2 a nd 3 is that under Option 3 plants would be required to meet the “zero discharge” requirements for fly ash transport water 3 , 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 pr ofile projected by IPM 4 were only calculated for Options 3 and 4. Based on the values quantified for Option 3 for the cha nges 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 wast ewater, 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 th an would be expected for Option 3a. Similarly, based on the values quantified for Option 3 for the changes to air em issions projected by IPM, which were negative,

EPA decided not to include these IPM air em ission changes in the calculated SOx and CO 2 emissions for Option 3a. These SOx and CO 2 emissions are considered maximum values because EPA expects that the air emission changes projec ted by IPM for Option 3a will also be negative (as they are for Options 3 and 4). Table 1-3 pr esents a summary of th e industry-level NWQI estimated for Option 3a.

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

Energy

Electrical Energy Usag e 112,004 MWh/year

Fuel Consumption 2,867,770 gal/year

Air Emissions

NO X 88-1,090 tons/year

SO X <84 tons/year

CO 2 <117,863 metric tons/year

CH 4 2.4 tons/year

Sludge Production

Sludge 0 tons/year

Water Intake Water Reductions

Water Reduction 49,900 million gal/year

2.0 R EGULATORY O PTION 3 B

One of the other eight regulatory options considered by EPA is re ferred to as Option 3b. Under Option 3b, the proposed rule would establish num eric effluent limits for mercury, arsenic, selenium, and nitrate-nitrite in di scharges of FGD wastewater from certain steam electric plants (those with a total plant- level wet scrubbed capacity of 2,000 MW or greater 5 ). All other proposed Option 3b requirements are identical to the proposed 3a requirements described in Section 1.0. Because the proposed requirements unde r 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 greate r. 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) fo r the listing of the 17 FGD plan ts identified as needing to comply with the FGD wastewater requirement s 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 a nd pollutant removals associated with chemical precipitations follo wed by biological treatment for the 17 plants operating wet FGD systems with a total plan t-level wet scrubbed cap acity of 2,000 MW or greater estimated using EPA’s methodology descri bed in Chapters 6.1, 6.2, 7, and 10 of EPA’s Incremental Costs and Pollutant Removals for th e 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 precipitati on followed by biological treatment values to calculate the option-level compliance costs and po llutant 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 re quirements that would be established under Option 3b were summed to calculate the option-level values.

Table 2-1 and Table 2-2 present the complian ce costs and pollutant removals for Option 3b, which are equal to the sum of Option 3a plus the additional biologica l treatment compliance costs and pollutant removals for the 17 FGD plants identified as needing to comply with the FGD wastewater requirement s 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 nega tive 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 Qualit y Environmental Impacts

Option 3b NWQI are equal to the values associat ed with dry fly ash handling conversions plus the NWQI associated with biological treatm ent 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’sMemorandum 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 va lues 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 tr ansportation (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 th e categories above by summing the Option 3a NWQI and the FGD chemical precipitation follo wed by biological treatm ent NWQI associated with the 17 plants. See DCN SE02957 for the pl ant-level NWQI estimates associated with electrical energy consumption, fuel consump tion, and transportation air emissions for the conversion to a dry fly ash handling system a nd 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 conv ersion to a dry fly ash handling system and FGD wastewater recycle.

Additionally, EPA estimated air emissions associat ed with increased auxi liary 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 ai r 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 biologi cal treatment systems for Option 3b using the plant-specific values estimated for Option 2, but only for the 17 pl ants identified as needing to comply with the FGD wastewater requirement s under Option 3b (DCN SE02896). The total Option 3b air emissions were calculated by summi ng these two estimated values.

EPA also estimated air emissions associated w ith the change in indus try profile projected by

IPM 6 , which were only calculated for Options 3 an d 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 transp ortation. The upper end of the range also includes the changes to air emissions pr ojected by IPM (based on Option 3) , which are larger than would be expected for Option 3b. Similarly, based on th e values quantified for Option 3 for the changes to air emissions projected by IPM, which were negative, EPA decided no t to include these IPM air emission changes in the calculated SOx and CO 2 emissions for Option 3b. These SOx and

CO 2 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 indus try 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 Usag e 160,753 MWh/year

Fuel Consumption 2,903,656 gal/year

Air Emissions

NO X 110-1,110 tons/year

SO X <130 tons/year

CO 2 <164,318 metric tons/year

CH 4 3.1 tons/year

Sludge Production

Sludge 365,960 tons/year

Water Intake Water Reductions

Water Reduction 52,100 million gal/year