Steam Electric Power Generating Effluent 

Guidelines Rulemaking 

Enclosure III 

Supplemental Information Package for Tribal Consultations

February 24, 2012 
Enclosure III - Tribal Consultations Supplemental Information 

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1. BACKGROUND 

The U.S. Environmental Protection Agency is currently engaged in a rulemaking process 

to revise the effluent limitations guidelines and standards (ELGs) for the steam electric power 

generating point source category. The steam electric power generating ELGs are nationally 

applicable, technology-based discharge requirements. These ELGs are incorporated into NPDES 

discharge permits, and in control mechanisms for discharges to Publically Owned Treatment 

Works (POTWS). This document was prepared to facilitate a dialogue about the ELG 

rulemaking as part of the Tribal consultations. 

This document provides information about preliminary compliance cost estimates for 

pollution controls being considered as the technology basis for regulatory options. Additional 

information about the steam electric industry, the processes generating wastewater, and treatment 

technologies can be found in Steam Electric Power Generating Point Source Category: Final 

Detailed Study Report (EPA 821-R-09-008, October 2009), which presents information that EPA 

collected over the course of the detailed study. The report, as well as additional information 

about the progression of the rulemaking since its inception, is available at EPA’s project web site 

at http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm. 

The Steam Electric Power Generating ELGs apply to a subset of the electric power 

industry, namely those plants “primarily engaged in the generation of electricity for distribution 

and sale which results primarily from a process utilizing fossil-type fuel (coal, oil, gas) or 

nuclear fuel in conjunction with a thermal cycle employing the steam-water system as the 

thermodynamic medium.” (See 40 CFR 423.10) Figure 1 broadly depicts the various types of 

electric generating plants and identifies which are regulated by the Steam Electric Power 

Generating effluent guidelines. For more information on this industry and the processes used, see 

Chapter 3 of the Steam Electric Power Generating Point Source Category: Final Detailed Study 

Report (EPA 821-R-09-008, October 2009). 

Figure 1. Types of U.S. Electric Generating Units 

Electric Generating Plants

Industrial Non-Utilities Electric Generating Industry

(Utilities and Non-Utilities)

Steam Electric 

Power Generation

Non-Steam Electric 

Power Generation

Fossil or Nuclear Steam Electric 

Generating Plants

(Steam Electric Power Generating 

Point Source Category)

Non-Fossil and Non-Nuclear 

Steam Electric Generating Plants
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Section 304 (m) of the Clean Water Act (CWA) requires EPA to periodically review all 

effluent guidelines to determine whether revisions are warranted. During its 2005 annual review 

of discharges from point source categories, EPA’s analysis of publicly available data reported 

through the NPDES permit program and the Toxics Release Inventory (TRI) indicated that this 

industry sector ranks as one of the highest dischargers of toxic and nonconventional pollutants. 

Because of this, EPA initiated a more detailed study of the industry’s wastewater discharges by 

collecting data through facility inspections, wastewater sampling, a data request to a small subset 

of the industry, and secondary sources of information. 

Upon completing the detailed study in 2009, EPA determined that the current regulations 

have not kept pace with the significant changes that have occurred in this industry over the last 

three decades. The development of new technologies for generating electric power (e.g., coal 

gasification) and the widespread implementation of air pollution controls (e.g., flue gas 

desulfurization (FGD), selective catalytic reduction (SCR)) have altered existing or created new 

wastewater streams at many power plants. Wastewater discharges from power plants have been 

identified as the source for a number of environmental impacts to ground water and surface 

water, including contaminated drinking water and other effects. The main pollutants of concern 

for these discharges include metals (e.g., mercury, arsenic, selenium), nitrogen, and total 

dissolved solids (TDS). The environmental concerns include impacts to ground water and 

surface water, contaminated sediments and drinking water, fish mortality & non-lethal effects 

(e.g., altered populations), bioaccumulation in aquatic organisms, fish advisories, and risks to 

human health. More information about the potential environmental impacts is presented in 

Chapter 6 of Steam Electric Power Generating Point Source Category: Final Detailed Study 

Report (EPA 821-R-09-008, October 2009). EPA’s analysis of the wastewater discharges 

associated with steam electric power generating led the Agency to announce, in September 2009, 

the start of a rulemaking process. 

EPA first issued effluent guidelines for the Steam Electric Power Generating Point 

Source Category (i.e., the Steam Electric effluent guidelines) in 1974 with subsequent revisions 

in 1977 and 1982. The Steam Electric effluent guidelines are codified at 40 CFR Part 423 and 

include limitations for the following waste streams: 

• Once-through cooling water; 

• Cooling tower blowdown; 

• Fly ash transport water; 

• Bottom ash transport water; 

• Metal cleaning wastes; 

• Coal pile runoff; and 

• Low-volume waste sources, including but not limited to wastewaters from wet 

scrubber air pollution control systems, ion exchange water treatment systems, 

water treatment evaporator blowdown, laboratory and sampling streams, boiler 

blowdown, floor drains, cooling tower basin cleaning wastes, and recirculating 

house service water systems (sanitary and air conditioning wastes are not 

included) [40 CFR 423.11(b)]. 

The current effluent guidelines are summarized in Table 1. 
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Although the rulemaking may address aspects of the regulation that apply to all 

fossil/nuclear units covered by the existing effluent guidelines, the focus of the rulemaking is on 

the following wastes: 

• Flue gas desulfurization (FGD) wastewater from SO2 air pollution controls; 

• Discharges of fly ash and bottom ash transport water; 

• Leachate from ponds and landfills containing coal combustion residues; 

• Gasification wastewater from integrated gasification combined cycle (IGCC) 

plants; and 

• Wastewater associated with flue gas mercury controls (e.g., wastewater resulting 

from transporting/handling solids from activated carbon injection). 

In addition to evaluating possible requirements for the discharges identified above, EPA 

may also clarify the applicability of the existing steam electric ELGs to discharges from 

combined cycle generating units. EPA is also considering clarifications to the definition of 

“metal cleaning waste” and “chemical metal cleaning waste” to reduce confusion about the 

existing definitions. 

EPA expects that clarifications for combined cycle generating units (which would affect 

gas-fired generating units) and the definitions for metal cleaning wastes (which would apply to 

all fossil- and nuclear-fueled units) would result in negligible, if any, compliance costs. New 

requirements for FGD wastewater, fly and bottom ash wastewater, pond/landfill leachate, 

gasification wastewater, and wastewater from mercury controls or SCRs could result in 

compliance costs for some units that use coal or petroleum coke. Requirements for ash transport 

water could also result in compliance costs for some oil-fired generating units. 
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Table 1. Current Effluent Guidelines and Standards for the Steam Electric Power Generating Point S

Waste Stream Existing Sources that are Direct Dischargers New Sources that are Direct Dischargers Existin

are 

BPT a BAT a NSPS a P

All Waste Streams pH: 6-9 S.U. b PCBs: Zero discharge PCBs: Zero discharge pH: 6-9 S.U. b PCBs: Zero discharge PCBs: ZLow-Volume Wastes TSS: 100 mg/L; 30 mg/L Oil & Grease: 20 mg/L; 15 mg/L TSS: 100 mg/L; 30 mg/L Oil & Grease: 20 mg/L; 15 mg/L Fly Ash Transport TSS: 100 mg/L; 30 mg/L Oil & Grease: 20 mg/L; 15 mg/L Zero discharge Zero dis

(PSNS oNo limi

Bottom Ash Transport TSS: 100 mg/L; 30 mg/L Oil & Grease: 20 mg/L; 15 mg/L TSS: 100 mg/L; 30 mg/L Oil & Grease: 20 mg/L; 15 mg/L Once-Through Cooling Free Available Chlorine: 0.5 mg/L; 0.2 mg/L Total Residual Chlorine: If > 25 MW: 0.20 mg/L instantaneous maximum; If < 25 MW, equal to BPT Total Residual Chlorine: If > 25 MW: 0.20 mg/L instantaneous maximum; If < 25 MW, equal to BPT Cooling Tower Blowdown 

Free Available Chlorine: 0.5 mg/L; 0.2 mg/L 

Free Available Chlorine: 0.5 mg/L; 0.2 mg/L 126 Priority Pollutants: Zero discharge, except: Chromium: 0.2 mg/L; 0.2 mg/L Zinc: 1.0 mg/L; 1.0 mg/L 

Free Available Chlorine: 0.5 mg/L; /0.2 mg/L 126 Priority Pollutants: Zero discharge, except: Chromium: 0.2 mg/L; 0.2 mg/L Zinc: 1.0 mg/L; 1.0 mg/L 

126 PriodischargChromiZinc: 1.

Coal Pile Runoff TSS*: 50 mg/L instantaneous 

maximum 

 TSS*: 50 mg/L instantaneous 

maximum 

Metal Cleaning Wastes 

TSS: 100 mg/L; 30 mg/L Oil & Grease: 20 mg/L; 15 mg/L Copper: 1.0 mg/L; 1.0 mg/L Iron: 1.0 mg/L; 1.0 mg/L 

See Chemical Metal Cleaning Wastes below 

See Chemical Metal Cleaning Wastes below 

See CheWastes 

Chemical See Metal Cleaning Wastes above Copper: 1.0 mg/L; 1.0 mg/L 

Iron: 1.0 mg/L; 1.0 mg/L 

TSS: 100 mg/L; 30 mg/L Oil & Grease: 20 mg/L; 15 mg/L Copper: 1.0 mg/L; 1.0 mg/L Iron: 1.0 mg/L; 1.0 mg/L 

Coppermaximu

Non-chemical See Metal Cleaning Wastes above Reserved Reserved Reserve

Source: [40 CFR Part 423]. 
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a – The limitations for TSS, oil & grease, copper, iron, chromium, and zinc are presented as daily maximum (mg/L); 30-day average (m

guidelines, where two or more waste streams are combined, the total pollutant discharge quantity may not exceed the sum of allowable 

each individual waste stream. BPT, BAT, and NSPS allow either mass- or concentration-based limitations. b – The pH limitation is not applicable to once-through cooling water. Free Available Chlorine: 0.5 mg/L; 0.2 mg/L - 0.5 mg/L instantaneous maximum, 0.2 mg/L average during chlorine release period. Dishrs/day/unit. Simultaneous discharge of chlorine from multiple units is prohibited. Limitations are applicable at the discharge from an icombination with the discharge from another unit. Total Residual Chlorine: 0.20 mg/L instantaneous maximum. Total residual chlorine (TRC) = free available chlorine (FAC) + combineTRC discharge is limited to 2 hrs/day/unit. TRC is applicable to plants ≥25 MW, and FAC is applicable to plants <25 MW. The TRC lithe discharge point to surface waters of the United States and may be subsequent to combination with the discharge from another unit. 126 Priority Pollutants: zero discharge - 126 priority pollutants from added maintenance chemicals (refer to App. A to 40 CFR 423). At discretion, compliance with the zero-discharge limitations for the 126 priority pollutants may be determined by engineering calculation

the regulated pollutants are not detectable in the final discharge by the analytical methods in 40 CFR part 136. TSS*: 50 mg/L instantaneous maximum on coal pile runoff streams. No limitation on TSS for coal pile runoff flows ≥10-year, 24-hour 

BPT: Best practicable control technology currently available. BAT: Best available control technology economically achievable. NSPS: New source performance standards. PSES: Pretreatment standards for existing sources. PSNS: Pretreatment standards for new sources. 
Enclosure III - Tribal Consultations Supplemental Information 

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2. TECHNOLOGY OPTIONS UNDER EVALUATION

EPA is evaluating several technology-based options for the control of wastewater 

discharges from power plants. With the exception of NSPS for fly ash transport water, the 

options for each waste stream are being considered for both existing sources and new sources. 

Revised ELGs for existing sources would be promulgated under Clean Water Act (CWA) 

provisions for best available technology economically achievable (BAT) and pretreatment 

standards for existing sources (PSES). [33 USC 1311(b); 33 USC 1314(b); 33 USC 1317(b)] 

Revised ELGs for new sources would be promulgated under CWA provisions for new source 

performance standards (NSPS) and pretreatment standards for new sources (PSNS). [33 USC 

1316(b); USC 1317(c)] No new NSPS requirements are being considered fly ash transport water 

since the current NSPS states “[t]here shall be no discharge of wastewater pollutants from fly ash 

transport water.” [40 CFR 423.15(g)] 

2.1 FGD Wastewater

Power plants use FGD scrubber systems to remove SO2 and other pollutants from stack 

emissions. In wet FGD scrubbers, the flue gas stream comes in contact with a liquid stream 

containing a sorbent, such as lime or limestone, which is used to transfer pollutants from the flue 

gas to the liquid stream. FGD scrubber system wastewaters, including the wastewater stream 

from dewatering and scrubber blowdown, contain elevated levels of metals (e.g., mercury, 

arsenic, selenium), nitrogen, and total dissolved solids. 

EPA identified and investigated wastewater treatment systems operated by steam electric 

plants for the treatment of FGD scrubber purge. Most plants currently discharging FGD 

wastewater use settling ponds; however, the use of more advanced wastewater treatment systems 

is increasing to a limited extent due to more stringent requirements imposed by some states on a 

site-specific basis. Figure shows the distribution of management/treatment for wastewater from 

wet FGD systems reported in the 2010 questionnaire for 150 plants. 

The current ELGs include these discharges within the definition of “low volume wastes.” 

EPA is considering establishing revised effluent limits for FGD wastewater based on the 

following technologies. 

Option 1 – No change 

No change to the current ELG requirements. 

Option 2 – Chemical precipitation 

Chemical precipitation involves removing metallic contaminants from aqueous solutions 

by converting soluble heavy metals to insoluble salts. The precipitated solids are then removed 

from solution by flocculation followed by sedimentation and/or filtration. EPA is evaluating 

chemical precipitation/iron co-precipitation specifically designed to target removal of mercury 

and arsenic. This system utilizes hydroxide precipitation (i.e., using calcium hydroxide (lime) as 

the precipitant to convert dissolved metals to insoluble metal hydroxides) followed by sulfide 

precipitation (using organosulfide as the precipitant to convert dissolved metals to insoluble 

metal sulfides). Ferric chloride and polymers are added to facilitate coagulation and removal of 

the precipitated solids. 
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Option 3 – Chemical precipitation with biological treatment

This option includes the chemical precipitation technology evaluated under Option 2, 

followed by a fixed film anoxic/anaerobic bioreactor treatment system. While the primary 

purpose of the bioreactor treatment system is to increase the removal of metals, particularly 

selenium, addition of a bioreactor is also effective in removing nitrates and sulfates. 

Option 4 – Chemical precipitation with vapor-compression evaporation

This option includes the chemical precipitation technology evaluated under Option 2, followed 

by a vapor-compression evaporation system that uses heat to evaporate the wastewater and 

generate a clean distillate stream. The key steps of the treatment process include pretreatment of 

the wastewater by chemical precipitation and softening, followed by sending the wastewater to a 

mechanical vapor compression brine concentrator (also referred to as a falling-film evaporator) 

and a forced-circulation crystallizer. In addition to the distillate that is generated as the water 

vapor cools, the process produces a solid by-product (i.e., crystallized salts) that would be 

disposed of in a landfill. 

Figure 2. Distribution of FGD Wastewater Treatment Systems Among Plants Operating 

Wet FGD Systems 

2.2 Fly Ash Transport Water

Fly ash is generated by pulverized coal furnaces and consists of very fine particles that 

are light enough to be entrained in the flue gas and carried out of the furnace. The fly ash 

particles that remain entrained in the flue gases are carried to the particulate control equipment, 

such as baghouses and electrostatic precipitators, for removal. The removed fly ash is collected 

in hoppers and then either pneumatically transferred as dry ash to silos for temporary storage or 

Settling Pond

Chemical

Precipitation

Biological

(Anoxic/Anaerobic)

Other

Zero Discharge
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sluiced with water to a surface impoundment (i.e., ash pond). Ash ponds discharge large volumes 

of fly ash wastewater containing significant levels of metals and nutrients. 

Over 70% of plants generating fly ash operate dry fly ash transport systems, while 

another 15% operate both wet and dry systems. In cases where a plant has both wet and dry 

handling, the wet handling system is a legacy system that was retained during conversion of the 

ash handling system and retained as a backup to the dry system. New source performance 

standards require “... no discharge of wastewater pollutants from fly ash transport water.” [40 

CFR Part 423.15] 

Option 1 – No change 

No change to the current ELG requirements. 

Option 2 – Zero discharge of fly ash transport water (Based on conversion to dry fly ash 

transport)

This option is based on the conversion of wet fly ash handling systems (specifically a wet 

fly ash sluicing system) to a dry vacuum fly ash handling system. This is the same technology 

basis used for NSPS requirements promulgated in 1982. The fly ash is initially collected in the 

hoppers of the particulate control system (e.g., electrostatic precipitator or baghouse) for both a 

wet and dry transport system. EPA is evaluating a dry handling system that uses a vacuum 

system to pneumatically transport the ash from the hopper to an intermediate storage location 

(e.g., a storage silo). The ash is then unloaded from the silo into trucks for transport to the final 

ash disposal destination (e.g., landfill or beneficial use). 

2.3 Bottom Ash Transport

Bottom ash is referred as the heavier ash that settles in the furnace or dislodged from 

furnace walls and that is collected at the bottom of the boiler. Bottom ash is usually hydraulically 

conveyed (i.e., sluiced with water) to either an ash pond or dewatering bin. In such a wet sluicing 

system, the hot bottom ash drops to the bottom of the furnace where it is quenched in a waterfilled hopper. Ash from the hopper is fed into a conveying line where it is diluted into slurry and 

pumped to the ash pond or dewatering bin. Some plants operate large settling ponds for bottom 

ash, while others use a system of relatively small ponds operating in series and/or parallel. The 

ash sent to a dewatering bin is separated from the transport water, then sent to a landfill or 

transported offsite. 

In the mechanical drag chain system, the bottom ash is collected in a water bath trough at 

the bottom of the boiler to cool the ash. The plant operates a drag chain that moves along the 

bottom of the trough and drags the bottom ash out of the boiler. At the end of the trough, the drag 

chain reaches an incline, which dewaters the bottom ash by gravity, draining the water back to 

the trough as the ash moves upward. The bottom ash is often conveyed to a nearby collection 

area, such as a small bunker outside the boiler building, from which it is loaded onto trucks and 

either sold for beneficial use or stored on-site in a landfill. 

Over 60% of plants generating bottom ash operate wet bottom ash transport systems, 

while approximately 30% operate only dry systems. 
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Option 1 – No change 

No change to the current ELG requirements. 

Option 2 – Zero discharge of bottom ash transport water (based on either complete 

recycle of transport water or conversion to dry bottom ash transport)

This option is based on the conversion of wet bottom ash handling systems (specifically a 

wet bottom ash sluicing system) to a dry bottom ash handling system such as a mechanical drag 

system, or a closed-cycle remote mechanical drag system. The mechanical drag system conveys 

the bottom ash out of the boiler to a nearby storage area. The remote mechanical drag system 

operates by sluicing the bottom ash to a water trough and sump located away from the boiler, 

where a stand-alone mechanical drag system is used to dewater the ash. The sluice water for the 

remote mechanical drag system is continually reused to prevent discharge of ash transport water, 

and the dewatered ash solids are landfilled or beneficially reused. 

2.4 Leachate from Landfills/Ponds Containing Coal Combustion Residuals

Coal combustion residues (CCR) comprise a variety of wastes from the coal combustion 

process, including fly ash, bottom ash, boiler slag, and FGD solids (e.g., gypsum and calcium 

sulfite). CCR may be stored at the plant in on-site landfills or surface impoundments. Leachate is 

the liquid that drains or leaches from a landfill or an impoundment. The two sources of landfill 

leachate are precipitation that percolates through the waste deposited in the landfill and the 

liquids produced from the CCR placed in the landfill. 

Figure 3 presents a diagram depicting the collection system for landfill leachate. In a 

lined landfill, the leachate collected from the landfill typically flows through a collection system 

consisting of ditches and/or underground pipes. From the collection system, the leachate is 

transported to a collection pond. Some plants discharge the effluent from these collection ponds 

directly to surface water, while other plants send the leachate to the ash pond. Surface 

impoundments may also have liners and collection systems similar to the landfills. Unlined 

ponds and landfills do not collect leachate migrating away from the pond/landfill. 

Option 1 – No change 

No change to the current ELG requirements. 

Option 2 – Chemical precipitation 

Chemical precipitation involves removing metallic contaminants from aqueous solutions 

by converting soluble heavy metals to insoluble salts. The precipitated solids are then removed 

from solution by flocculation followed by sedimentation and/or filtration. EPA is evaluating 

chemical precipitation/iron coprecipitation technology for the treatment of leachate from CCR 

landfills/ponds, specifically designed to target removal of mercury and arsenic. Note that this is 

the same Option 2 described above for FGD wastewater and that EPA is also evaluating cotreatment of FGD wastewater and landfill/pond leachate. 
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Option 3 – Chemical precipitation with biological treatment

This option includes the chemical precipitation technology evaluated under Option 2, 

followed by a fixed film anoxic/anaerobic bioreactor treatment system. The primary purpose of 

the bioreactor treatment system is to increase the removal of metals, particularly selenium, from 

the landfill/pond leachate; however, this treatment step is also effective in removing nitrate and 

sulfates. Note that this is the same Option 3 described above that EPA is evaluating for FGD 

wastewater and that EPA is also evaluating co-treatment of FGD wastewater and landfill/pond 

leachate. 

Figure 3. Diagram of Landfill Leachate Collection 

2.5 Mercury Control System Wastewater

Some plants have or plan to install systems to control the emission of mercury via flue 

gas. The vast majority of these systems report handling mercury control solid waste in a dry 

manner. Eight plants have reported handling such wastes in a wet system. Typically, these plants 

inject activated carbon into the flue gas either upstream or downstream of the ESP and the 

carbon and mercury waste is collected with their fly ash. These wet systems tend to be ash sluice 

systems that combine the mercury control wastes with the fly ash sluiced to an ash pond. In some 

cases, the plants report treating their coal with an oxidant that works to fully oxidize mercury 

when the coal is burned. The oxidized mercury is then removed in their normal air pollution 

controls and handled with ash or FGD wastewater. 
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2.6 Gasification Wastewater

Currently, there are two operating IGCC plants in the U.S. and a third plant scheduled to 

come on line soon. These plants treat their gasification wastewater using a vapor-compression 

evaporation system that uses heat to evaporate the wastewater and generate a clean distillate 

stream. The distillate stream is either discharged or reused in plant operations. 

Option 1 – No change 

No change to the current ELG requirements. 

Option 2 – Vapor-compression evaporation 

The gasification process at integrated gasification combined cycle (IGCC) facilities 

produces a wastewater purge stream (grey water). The treatment option being considered for the 

grey water is vapor compression evaporation followed by crystallization, producing an aqueous 

stream (distillate) and solid by-products (crystallized salts). The solids would be sent to a landfill 

for disposal. This is equal to the current level of treatment operated by IGCC facilities and would 

result in no incremental compliance costs. 

Option 3 – Vapor-compression evaporation plus cyanide destruction 

Similar to Option 2, but would also add a treatment step (such as hypochlorite addition) 

to reduce levels of cyanide in the discharge. Incremental compliance costs, if any, would be 

minimal. 

2.7 Model Plant Results

Table 2 presents a preliminary estimate of compliance costs associated with EPA’s 

technology options for three model plants ranging in size from 50 MW to 600 MW. 
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Table 2. Treatment Option Costs for Model Plants (Preliminary Estimates, October 201

1. Three "model plants" are presented to provide insight to the potential compliance costs for regulatory options under consideration. Th

(MW) noted in the table header are approximate values. 2. Estimated costs do not reflect offsetting cost reductions associated with ceasing operation of an existing settling pond or avoiding ins

to comply with the current effluent limits at 40 CFR part 423. 3. Leachate costs are based on construction of a stand-alone treatment system for leachate flow. Actual costs may be lower if leachate iwastewater. 4. Annualized costs sum the operating and maintenance (O&M) costs and annualized capital costs, using a 7% interest rate and a 20-yeequipment. "Option 1" for all waste streams presumes no change to the current ELG limits, which are based on a settling pond. CP: Chemical precipitation treatment. CP + Bio: Chemical precipitation plus biological treatment. CP + Evap: Chemical precipitation plus evaporation. Fly ash no discharge: Based on conversion to a dry vacuum ash handling system. Bottom ash no discharge: Based on conversion to a mechanical drag system.

Capital Cost

Annual O&M 

Cost

Annualized 

Cost Capital Cost

Annual O&M 

Cost

Annualized 

Cost Capital Cost

 (2010 $) (2010 $) (2010 $) (2010 $) (2010 $) (2010 $) (2010 $) 

FGD Option 1: No change to ELG --- --- --- --- --- --- --- 

FGD Option 2: CP $4,869,000 $430,000 $889,000 $8,314,000 $866,000 $1,652,000 $15,391,000 FGD Option 3: CP + Bio $9,823,000 $727,000 $1,654,000 $14,335,000 $1,216,000 $2,569,000 $23,610,000 FGD Option 4: CP + Evap $27,949,000 $1,524,000 $4,162,000 $35,247,000 $2,784,000 $6,112,000 $50,527,000 Fly Ash Option 1: No change to ELG --- --- --- --- --- --- --- Fly Ash Option 2: "No discharge" $1,732,000 $164,000 $328,000 $2,189,000 $900,000 $1,107,000 $2,750,000 Bottom Ash Option 1: No change to ELG --- --- --- --- --- --- --- Bottom Ash Option 2: "No discharge" $2,465,000 $610,000 $878,000 $6,199,000 $864,000 $1,484,000 $12,024,000 Leachate Option 1: No change to ELG --- --- --- --- --- --- --- Leachate Option 2: CP $3,981,000 $145,000 $521,000 $6,740,000 $529,000 $1,165,000 $8,244,000 Leachate Option 3: CP + Bio $6,987,000 $412,000 $1,072,000 $11,935,000 $838,000 $1,964,000 $14,216,000 

ELG Option

Model Plant 1 (approx 50-100 MW) Model Plant 2 (approx 250-350 MW) Model Plan