### MEMORANDUM

TO: Steam Electric Rulemaking Record

FROM: Elizabeth Sabol, ERG Thomas Finseth, ERG

DATE: April 19, 2013

SUBJECT: Steam Electric Effluent Guidelin es – 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 Ava ilable 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 ec onomic achievability, these factor s are the age of equipment and facilities involved, the process employed, the engi neering aspects of the application of various types of control techniques, process changes, th e cost of achieving such effluent reductions, nonwater quality environmental impact (including ener gy requirements), and such other factors the Administrator deems appropriate. One way EPA may take these factor s into account is by dividing a point source category into groupings called “subcategor ies.” Regulating a category by subcategory, where warranted, ensures that each subcategory has a uniform set of effluent limitations that take into account technology ava ilability and economic ach ievability 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 e ffluent requirements for cooling water discharges from plants with a total rated generating capacity of le ss than 25 megawatts (MW). For the proposed revisions, EPA directed ERG to evaluate whether subcategorizat ion would be appropriate using information from the industry surveys, site visi ts, sampling, and other co llection activities. ERG performed analyses to assess the influence of age, size, fuel type, and geographic location on the wastewaters generated, wastewater characteristics including discha rge flow rates, and treatment technology availability at steam electric power plants to determ ine whether subcategorization was warranted. This memorandum describes the evaluations performed for fly ash transport water, bottom ash transport water, FGD wa stewater, 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 subcat egorization was warranted for IGCC wastewater, FGMC wastewater, and nonchemical metal cleaning wastes. However, because ther e are no incremental complia nce 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 A GE

ERG analyzed generating units and power plants to evaluate how age af fects the wastewater characteristics, processes in place, or the abilit y 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 id entified 1,537 operating generating units from data in the Steam Electric Survey, based on survey weighting, this represents 2,214 genera ting 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 data base 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, ope rating 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. ER G 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 Attachme nt 1, for additional info rmation regarding the age of coal-, petroleum coke- and oil-fired gene rating 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 curre nt BPT requirements; and

 Dry fly ash handling.

Dry fly ash handling is already a well established technology w ithin 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 followi ng 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 rela tive to the age of the generating unit. The table clearly demonstrates that units built within the last twenty years almost exclusively use dry flyMemorandum April 19, 2013 Page 3

ash handling systems. This is not surprising, du e 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 al l 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 [R edacted] [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 we re 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 ar e likely to retrofit to a dry fly ash handling systems to comply with the proposed rulemaki ng, 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 surv ey data and 2009 EIA data, ERG identified approximately 123 plants based on survey weighti ng 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 syst ems. More than 270 of these generating units are at least 30 years old, including 115 units that ar e 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 we re 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 convert ing to a dry fly ash handling system.

1.2 Bottom Ash

For the proposed ELGs, EPA evaluated the fo llowing 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 remo te MDS. Information from the Steam Electric Survey and vendor data shows th e number of plants installin g mechanical drag systems on generating units is increasing. Using data collect ed in the Steam Electric Survey, ERG evaluated the age of generating units for the follo wing 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 we ighting, this represents 875 generating units. Table 3 shows the type of bottom ash handling syst em, relative to the age of the generating units. The table shows that for units bui lt 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 demonstr ates that dry bottom ash handling systems are used by units in all age groups, including thos e 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 [Red acted] [Redacted] 0 20 - 30 Years 78 [Redacted] 0 30 - 40 Years 162 [Redacted] 3 40 - 50 Years 179 [Redacted] 1

> 50 Years 2 76 [Redacted] 1 Note: The number of units are based on values reported in the 2009 survey, which we re 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 th e 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 bo ttom 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 un its are at least 50 years old.

Table 4. Age of Bottom Ash Handling Retrofit Units

Age of Unit Units with Dry Hand ling 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 we re 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 th e age of the generating unit.

1.3 FGD Wastewater

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

 Set BAT equal to the cu rrent BPT requirements;

 Chemical precipitation;

 Chemical precipitation followe d by biological treatment; and

 Chemical precipitation followed by soften ing and vapor-compression evaporation.

Based on information collected in the Steam Elect ric 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 propose d 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 th e FGD system and transferred to a pond or wastewater treatment system. There is nothing asso ciated with a plant’s age that would preventMemorandum April 19, 2013 Page 6

the plant from being able to transfer the FGD wastewater to another lo cation where a treatment system would be built (or to the same locati on 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. A dditionally, 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 fo rty 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 basi s 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 cu rrent BPT requirements;

 Chemical precipitation; and

 Chemical precipitation follo wed 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 conv eyed, likely via pipe, to the site of the treatment system. There is nothing associated wi th a plant’s age that would prevent the plant from being able to transfer the leachate to an other location where a trea tment system would be built (or to the same location where the exis ting treatment system could be upgraded or replaced). Therefore, ERG determined that age is not an appropriate basi s for setting different effluent requirements.

2.0 S IZE

ERG analyzed the size (i.e., generating name plate capacity in megawatts (MW)) of the generating units to determine if size has an impact on the wastewater charact eristics, processes in place, or the ability to install the treatment tec hnologies 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 th at did not have report ed 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 ope rating generating units from data in theMemorandum 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 anal yses were performed an d the results of the analyses for each waste stream of interest.

2.1 Fly Ash Transport Water

ERG estimated compliance costs for 197 generating un its currently handling some or all of their fly ash with a wet sluicing system. The capacity of generating units ope rating 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 ca lculated at the plant level, using unit-level input data. 2 ERG used the cost model outputs to gene rate unit-level annualized co sts. 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 pr oduced fly ash tonnage per day fo r 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. Additionall y, 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 as h conversion costs excluding the transport and disposal portion of the costs. ER G evaluated the costs excluding the transport and disposal portion because the cap ital and O&M costs can be substa ntially influenced by whether the plant uses an on-site or an off-site landfill.

After estimating unit-level annualized costs for fl y ash conversions, ERG calculated the resulting cost per MW for each generating unit. Table 5 pres ents the average annualized cost per MW for units greater than 50 MW and un its less than or equal to 50 MW for both fly ash analyses. Figures 1 and 2 present the cost per MW as a fu nction 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 estimat ed 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 fo r 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 ge neral 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 (A ll 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 generati ng units currently handling their bottom ash with a wet sluicing system. The capacity of uni ts incurring bottom ash conversion costs ranges from 5 MW to 1,300 MW. There are 49 units that ha ve 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 as h transport water (i.e., bottom ash management costs). Three of these units have capacities le ss than or equal to 50 MW. The units incurring bottom ash management costs are excluded fr om the remainder of this analysis.

Bottom ash annualized costs are ca lculated 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 un it level and transport and disposal costs at the plant level. In order to estimate unit-level transp ort and disposal costs, ERG first calculated the total wet produced bottom ash tonnage per year fo r the plant. ERG then cal culated the percentage of the total wet produced bottom ash tonnage per year for each unit cont ributing to the total. Finally, ERG multiplied these percentages by the pl ant-level transport and disposal costs to allocate the costs to the unit level.

3 The annualized costs used in this analysis were estimat ed 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 fo r 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 ge neral 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 tran sport and disposal portion of the costs. ERG evaluated the costs excluding the transport and disposal por tion because the capital and O&M costs can be substantially influenced by whether the plant us es 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. Ta ble 6 presents the average annualized cost per MW for units greater than 50 MW and units le ss 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 comp liance costs for all cost com ponents 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 se rviced 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 precipitatio n system followed by biological tr eatment 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-le vel 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 gene rating 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 th e 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 co sts 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 estimat ed 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 fo r 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 ge neral 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 appropriate ly apportion the costs to the individual units without making assumptions that could skew the an alysis. This resulted in the exclusion of six plants and 16 generating units.

Similar to ash, ERG also evaluated the annua lized cost per MW fo r the FGD wastewater treatment system excluding transport and disposal portion of the costs. ERG evaluated the costs excluding the transport and di sposal portion because the ca pital and O&M costs can be substantially influenced by whether the plant us es 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 th e cost per MW as a fu nction of unit capacity (MW) for all 260 units incurring FGD wastewater treatment costs for all cost components and excluding transport and dispos al costs, respectively.

Table 7. Dollar Per MW for FGD Treatment Technology Option

Costs Average $/MW
for Units ≤ 50

MW 1 Average $/MW for Units > 50
MW
F GD Wastewater Treatment Compliance Cost s (all cost components) 33,645 4,935
F GD Wastewater Treatment Compliance Costs (excluding transport and d isposal) 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 me thodology for estimating compliance costs for combustion residual leachate treatment, ERG wa s 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, rainfa ll, etc). Based on the principles of economies of scale, ERG believes that the small units woul d have higher costs per MW to treat the leachate using a chemical precipitation system. For exampl e, 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 co mpared with the small system.

Additionally, ERG reviewed two plants that opera te one generating unit with an on-site landfill for the disposal of combustion residuals. The st eam 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 cap acity 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 effl uent limits based on size of plant or generating unit are warranted, ERG also reviewed the numbe r of small businesses and municipalities that would be affected by size thresholds. Table 8 pr esents the number of units that would incur compliance costs under Regulatory Options 3 an d 4, including those units owned by small businesses and municipalities. Ta ble 9 presents the number of pl ants, including those owned by small businesses or municipalities, that would av oid incurring compliance costs for one or more generating units (i.e., compliance co sts 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 si ze 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 ar e associated with small businesses and 15 are associated with municipalities. The data show th at 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 ev aluated 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-weight ing 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 Plan ts 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-weight ing 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 F UEL T YPE

ERG analyzed the fuel type of generating units, in cluded in the scope of the rule, to determine if fuel type has an effect on the wastewater charac teristics, processes in place, or the ability to install the treatment technologies evaluated as part of the propos ed ELGs. Using data from the Steam Electric Survey, ERG classified generatin g units by fuel type based on the following hierarchy: coal, petroleu m coke, oil, gas, and nuclear. For exam ple, 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 cost s 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 requir ements 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 F GD 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 un its to determine if different effluent discharge requirements would be appr opriate for oil-fired uni ts. The generating unit characteristics ERG reviewed as part of this analysis include age, unit type, total days ofMemorandum April 19, 2013 Page 16

operation, and capacity utilization for oil-fired un its. 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 th e oil-fired units are greater than 50 years old.

ERG also determined that over 75 percent of a ll oil-fired units are cy cling, intermediate, or peaking units; compared to only 30 percent of coal -fired units that are cy cling, 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 require ments 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 ye arly electricity generation ba sed on generating unit capacity. Over 75 percent of the oil-fired units have a calculat ed capacity utilization factor less than 25 percent. Alternatively, over 60 percent of coal-f ired units have a calcu lated capacity utilization factor over 50 percent.

Based on the analysis, ERG determined that the oil-fired units are gene rally 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 a nd operating the treatment technologies evaluated as part of the proposed ELGs and that the costs would be affordab le for most of the plants, ERG believes that companies may choose to shut th ese oil-fired units down instead of making the investment to comply with the ELGs. If th ese units were shut down, it could reduce the flexibility that grid operato rs have during peak demand.

ERG also evaluated whether it would be appropria te 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 obt ained during site vi sits, 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 G EOGRAPHIC L OCATION

ERG analyzed the geographic location of the genera ting units, included in the scope of the rule, to determine if geographic locati on has an impact on the wastewater characteristics, processes in place, or the ability to install the treatment tec hnologies evaluated as part of the proposed ELGs. ERG determined the geographic location of the ge nerating units using res ponses from the Steam Electric Survey. Based on an analysis of the Steam Electric Survey da ta, ERG found that wet FGD systems, both wet and dry fly ash handli ng systems, and both wet and dry bottom ash handling systems are located through the United St ates and that the geogr aphic location of theMemorandum April 19, 2013 Page 17

plant by itself does not affect the wastewater charact eristics, the processes in place, or the ability to install the treatment technologies ev aluated 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 tr eatment of FGD wastewater for plants currently operating wet FGD systems. Figure 7 presents a map of all plan ts 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 alle viated by operating heat ex changers 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 pl ant does not impact the plant’s ability to retrofit dry fly ash or bottom ash handling systems for un its currently wet sluici ng ash. Figures 9 and 11 show the plant-level fly and bottom ash hand ling 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 handli ng 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 SystemsMemorandum April 19, 2013 Page 19

Figure 9. Plant-Level Fly Ash Transport Systems

Figure 10. Plant-Level Fly Ash Dr y Retrofit Transport SystemsMemorandum April 19, 2013 Page 20

Figure 11. Plant-Level Botto m Ash Transport Systems

Figure 12. Plant-Level Bottom Ash Dr y Retrofit Transport Systems

### Attachment 1Attachment 1 April 19, 2013 Page A1



## Fuel Types for Steam Elec tric 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 al so 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 th e count of total units. The remainder of the tables in this attachment also present counts of steam electric genera ting units for different subset s 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 co al, even if coal was reported as generating less electricity compared to other fuel groups. Units were th en categorized by the type of fuel burned. The fuel types presented in the remainder of the tables in this a ttachment 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 Un its, 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 Co ke-, and Oil-Fired Units with Generating Capacities ≤ 200 MW

Unit Fuel Type Number of Generating Un its, 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 Co ke-, and Oil-Fired Units with Generating Capacities ≤ 150 MW

Unit Fuel Type Number of Generating Un its, 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 Co ke-, and Oil-Fired Units with Generating Capacities ≤ 100 MW

Unit Fuel Type Number of Generating Un its, 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 Co ke-, and Oil-Fired Units with Generating Capacities ≤ 50 MW

Unit Fuel Type Number of Generating Un its, 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 El ectric Generating Units – 25% Cutoff

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

Unit Fuel Type Number of Generating Unit s, 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 w ith both a reported steam electric capacity and reported electricity generation greater than zer o in 2009 in survey responses. Note: Numbers represent weighted survey results.

Table C2. Distribution for Coal -, Petroleum Coke-, and Oil-F ired Units with Generating Capacities ≤ 200 MW

Unit Fuel Type Number of Generating Unit s, 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 w ith both a reported steam electric capacity and reported electricity generation greater than zer o in 2009 in survey responses. Note: Numbers represent weighted survey results.

Table C3. Distribution for Coal -, Petroleum Coke-, and Oil-F ired Units with Generating Capacities ≤ 150 MW

Unit Fuel Type Number of Generating Unit s, 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 w ith both a reported steam electric capacity and reported electricity generation greater than zer o 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-F ired Units with Generating Capacities ≤ 100 MW

Unit Fuel Type Number of Generating Unit s, 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 w ith both a reported steam electric capacity and reported electricity generation greater than zer o in 2009 in survey responses. Note: Numbers represent weighted survey results.

Table C5. Distribution for Coal -, Petroleum Coke-, and Oil-F ired Units with Generating Capacities ≤ 50 MW

Unit Fuel Type Number of Generating Unit s, 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 w ith both a reported steam electric capacity and reported electricity generation greater than zer o in 2009 in survey responses. Note: Numbers represent weighted survey results.Attachment 1 April 19, 2013 Page A6



## Capacity Utilization of Steam El ectric Generating Units – 15% Cutoff

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

Unit Fuel Type Number of Generating Unit s, 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 w ith both a reported steam electric capacity and reported electricity generation greater than zer o in 2009 in survey responses. Note: Numbers represent weighted survey results.

Table D2. Distribution for Coal -, Petroleum Coke-, and Oil-F ired Units with Generating Capacities ≤ 200 MW

Unit Fuel Type Number of Generating Unit s, 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 w ith both a reported steam electric capacity and reported electricity generation greater than zer o in 2009 in survey responses. Note: Numbers represent weighted survey results.

Table D3. Distribution for Coal -, Petroleum Coke-, and Oil-F ired Units with Generating Capacities ≤ 150 MW

Unit Fuel Type Number of Generating Unit s, 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 w ith both a reported steam electric capacity and reported electricity generation greater than zer o 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-F ired Units with Generating Capacities ≤ 100 MW

Unit Fuel Type Number of Generating Unit s, 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 w ith both a reported steam electric capacity and reported electricity generation greater than zer o in 2009 in survey responses. Note: Numbers represent weighted survey results.

Table D5. Distribution for Coal -, Petroleum Coke-, and Oil-F ired Units with Generating Capacities ≤ 50 MW

Unit Fuel Type Number of Generating Unit s, 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 w ith both a reported steam electric capacity and reported electricity generation greater than zer o in 2009 in survey responses. Note: Numbers represent weighted survey results.Attachment 1 April 19, 2013 Page A8



## Age Distribution of Steam Electr ic Generating Units Based on Capacity Utilization – 15% Cutoff

Table E1. Distribution for All Coal-, Petroleu m Coke-, and Oil-Fired Units for Units with a Capacity Utilization ≤ 15 Percent

Unit Fuel Type Number of Generating Un its, 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-, Petroleu m Coke-, and Oil-Fired Units for Units with a Capacity Utilization >15 Percent

Unit Fuel Type Number of Generating Un its, 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 Electr ic 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 Un its, 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 [Red acted] 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 Un its, 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.