# Steam Electric Power Generating Effluent Guidelines Rulemaking

Enclosure III Supplemental Information Package for Tribal Consultations

February 24, 2012Enclosure III - Tribal Consultations Supplemental Information

1 1. B ACKGROUND

The U.S. Environmental Protection Agency is currently engaged in a rulemaking process to revise the effluent limitations guidelines a nd standards (ELGs) for the steam electric power generating point source category. The steam el ectric power generating ELGs are nationally applicable, technology-based discharge requirement s. These ELGs are incorporated into NPDES discharge permits, and in contro l 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 t echnology 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 cour se of the detailed study. The report, as well as additional information about the progression of the rulema king since its inception, is availa ble at EPA’s project web site at http://water.epa.gov /scitech/wastetech/guide/steam_index.cfm.

The Steam Electric Power Generating ELGs appl y to a subset of the electric power industry, namely those plants “pri marily 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 w ith 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 whic h are regulated by the Steam Electric Power Generating effluent guidelines. Fo r more information on this indus try 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 PlantsEnclosure III - Tribal Consultations Supplemental Information

2 Section 304 (m) of the Clean Water Act (CWA) requires EPA to periodically review all effluent guidelines to determine whether revisi ons 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 di schargers of toxic and nonconventional pollutants. Because of this, EPA initiated a more detailed study of the industry’s wastewater discharges by collecting data through faci lity 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 de termined 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 technolog ies for generating electric power (e.g., coal gasification) and the widespread implementa tion of air pollution c ontrols (e.g., flue gas desulfurization (FGD), selective catalytic reducti on (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 e nvironmental 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., merc ury, arsenic, selenium), nitrogen, and total dissolved solids (TDS). The environmental c oncerns include impacts to ground water and surface water, contaminated sediments and drinki ng water, fish mortalit y & non-lethal effects (e.g., altered populations), bioaccumulation in aqua tic organisms, fish advisories, and risks to human health. More information about the pote ntial 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 analys is 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 El ectric effluent guidelines) in 1974 with subsequent revisions in 1977 and 1982. The Steam Electric effluent guide lines 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 contro l systems, ion exchange water treatment systems, water treatment evaporator blowdown, la boratory and sampling streams, boiler blowdown, floor drains, cooling tower ba sin 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.Enclosure III - Tribal Consultations Supplemental Information

3 Although the rulemaking may address aspects of the regulation that apply to all fossil/nuclear units covered by th e existing effluent guidelines, th e focus of the rulemaking is on the following wastes:

• Flue gas desulfurization (FGD) wastewater from SO 2 air pollution controls;

• Discharges of fly ash and bottom ash transport water;

• Leachate from ponds and landfills containing coal combustion residues;

• Gasification wastewater from integrat ed gasification combined cycle (IGCC) plants; and

• Wastewater associated with flue gas me rcury controls (e.g., wastewater resulting from transporting/handling solids fr om activated carbon injection).

In addition to evaluating possible requiremen ts for the discharges identified above, EPA may also clarify the applicability of the ex isting steam electric ELGs to discharges from combined cycle generating units. EPA is also c onsidering clarifications to the definition of “metal cleaning waste” and “chemical metal cl eaning 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 fo r metal cleaning wastes (which would apply to

all fossil- and nuclear-fueled uni ts) would result in negligible, if any, compliance costs. New requirements for FGD wastewater, fly and bottom ash wastewater, pond/landfill leachate, gasification wastewater, and wa stewater from mercury contro ls 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 co sts for some oil-fired generating units.4 E

nclosure III - Tribal Consultations Supplemental InformationTable 1. Current Effluent Guidelines and Standards for theSteam Electric Power Generating Point Source CategoryWaste StreamExisting Sources thatare Direct DischargersNew Sources that are DirectDischargersExisting and New Sources thatare Indirect DischargersBPTaBATaNSPSaPSES and PSNSaAll Waste Streams pH: 6-9 S.U.bPCBs: Zero dischargePCBs: Zero discharge pH: 6-9 S.U.bPCBs: Zero dischargePCBs: Zero dischargeLow-VolumeWastesTSS: 100 mg/L; 30 mg/LOil & Grease: 20 mg/L; 15 mg/LTSS: 100 mg/L; 30 mg/LOil & Grease: 20 mg/L; 15 mg/LFly Ash Transport TSS: 100 mg/L; 30 mg/LOil & Grease: 20 mg/L; 15 mg/LZero discharge Zero discharge(PSNS only)No limitation for PSESBottom AshTransportTSS: 100 mg/L; 30 mg/LOil & Grease: 20 mg/L; 15 mg/LTSS: 100 mg/L; 30 mg/LOil & Grease: 20 mg/L; 15 mg/LOnce-ThroughCoolingFree Available Chlorine: 0.5mg/L; 0.2 mg/LTotal Residual Chlorine:If >25 MW: 0.20 mg/Linstantaneous maximum;If < 25 MW, equal to BPTTotal Residual Chlorine:If >25 MW: 0.20 mg/Linstantaneous maximum;If < 25 MW, equal to BPTCooling TowerBlowdownFree Available Chlorine: 0.5mg/L; 0.2 mg/LFree Available Chlorine: 0.5mg/L; 0.2 mg/L126 Priority Pollutants: Zerodischarge, except:Chromium: 0.2 mg/L; 0.2 mg/LZinc: 1.0 mg/L; 1.0 mg/LFree Available Chlorine: 0.5mg/L; /0.2 mg/L126 Priority Pollutants: Zerodischarge, except:Chromium: 0.2 mg/L; 0.2 mg/LZinc: 1.0 mg/L; 1.0 mg/L126 Priority Pollutants: Zerodischarge, except:Chromium: 0.2 mg/L; 0.2 mg/LZinc: 1.0 mg/L; 1.0 mg/LCoal Pile Runoff TSS*: 50 mg/L instantaneousmaximumTSS*: 50 mg/L instantaneousmaximumMetal CleaningWastesTSS: 100 mg/L; 30 mg/LOil & Grease: 20 mg/L; 15 mg/LCopper: 1.0 mg/L; 1.0 mg/LIron: 1.0 mg/L; 1.0 mg/LSeeChemical Metal CleaningWastesbelowSeeChemical Metal CleaningWastesbelowSeeChemical Metal CleaningWastesbelowChemical SeeMetal Cleaning Wastesabove Copper: 1.0 mg/L; 1.0 mg/LIron: 1.0 mg/L; 1.0 mg/LTSS: 100 mg/L; 30 mg/LOil & Grease: 20 mg/L; 15 mg/LCopper: 1.0 mg/L; 1.0 mg/LIron: 1.0 mg/L; 1.0 mg/LCopper: 1.0 mg/L (dailymaximum)Non-chemical SeeMetal Cleaning Wastesabove Reserved Reserved ReservedSource: [40 CFR Part 423].5 E

nclosure III - Tribal Consultations Supplemental Informationa – The limitations for TSS, oil & grease, copper, iron, chromium, and zinc are presented as daily maximum (mg/L); 30-day average (mg/L). For all effluentguidelines, where two or more waste streams are combined, the total pollutant discharge quantity may not exceed the sum of allowable pollutant quantities foreach 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.Discharge is limited to 2hrs/day/unit. Simultaneous discharge of chlorine from multiple units is prohibited. Limitations are applicable at the dischargefrom an individual unit prior tocombination with the discharge from another unit.Total Residual Chlorine: 0.20 mg/L instantaneous maximum. Total residual chlorine (TRC) = free available chlorine (FAC) + combined residual chlorine (CRC).TRC 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 limitation is applicable atthe discharge point to surface waters of the United States and may be subsequentto combination with the discharge from anotherunit.126 Priority Pollutants: zero discharge - 126 priority pollutants from added maintenance chemicals (refer to App. A to 40 CFR 423). At the permitting authority'sdiscretion, compliance with the zero-discharge limitations for the 126 priority pollutants may be determined by engineering calculations, which demonstrate thatthe 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 rainfall event.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

6 2. T ECHNOLOGY O PTIONS U NDER E VALUATION

EPA is evaluating several technology-based options for the control of wastewater discharges from power plants. With the excepti on of NSPS for fly as h transport water, the options for each waste stream are being consid ered 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 econom ically 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 prom ulgated 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 ar e being considered fl y ash transport water since the current NSPS states “[t] here shall be no discharge of wa stewater pollutants from fly ash transport water.” [40 CFR 423.15(g)]

2.1 FGD Wastewater

Power plants use FGD scrubber systems to remove SO 2 and other pollutants from stack emissions. In wet FGD scrubbers, the flue gas st ream comes in contact with a liquid stream containing a sorbent, such as lime or limestone, whic h is used to transfer pollutants from the flue gas to the liquid stream. FGD sc rubber system wastewaters, incl uding the wastewater stream from dewatering and scrubber blowdown, contai n elevated levels of metals (e.g., mercury, arsenic, selenium), nitrogen, and total dissolved solids.

EPA identified and investigated wastewater tr eatment systems operated by steam electric plants for the treatment of FGD scrubber pur ge. Most plants curre ntly discharging FGD wastewater use settling ponds; howev er, the use of more advanced wastewater treatment systems is increasing to a limited extent due to more st ringent requirements imposed by some states on a site-specific basis. Figure show s the distribution of management/t reatment for wastewater from wet FGD systems reported in the 2010 questionnaire for 150 plants.

The current ELGs include these discharges with in the definition of “low volume wastes.” EPA is considering establishing revised efflue nt 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 in v olves removing metallic contaminants from aqueous solutions by converting soluble heavy metals to insoluble sa lts. The precipitated so lids are then removed from solution by flocculation followed by sediment ation and/or filtration. EPA is evaluating chemical precipitation/iron co-preci pitation specifically designed to target removal of mercury and arsenic. This system utilizes hydroxide pr ecipitation (i.e., using calc ium 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 coa gulation and removal of the precipitated solids.Enclosure III - Tribal Consultations Supplemental Information

7 Option 3 – Chemical precipitati on with biologic al treatment

This option includes the chemical precipi tation technology evaluated under Option 2, followed by a fixed film anoxic/anaerobic bior eactor treatment system . While the primary purpose of the bioreactor treatment system is to increase the removal of metals, particularly selenium, addition of a bioreact or is also effective in rem oving nitrates and sulfates.

Option 4 – Chemical precipitation with vapor-compression evaporation

This option includes the chemical precipitati on 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 preci pitation and softening, followed by sending the wastewater to a mechanical vapor compression brine concentrator (a lso 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-prod uct (i.e., crystallized salts) that would be disposed of in a landfill.

Figure 2. Distribution of FGD Wastewater T reatment 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 partic ulate control equipment, such as baghouses and electrostatic precipitators , for removal. The removed fly ash is collected in hoppers and then either pneuma tically transferred as dry ash to silos for temporary storage or Settling Pond

Chemical
Precipitation Biological (Anoxic/Anaerobic) Other Zero DischargeEnclosure III - Tribal Consultations Supplemental Information

8 sluiced with water to a surface impoundment (i .e., ash pond). Ash ponds discharge large volumes of fly ash wastewater containing signif icant levels of metals and nutrients.

Over 70% of plants generating fly ash opera te 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 syst em that was retained during conversion of the ash handling system and retained as a bac kup to the dry system. New source performance standards require “... no discha rge of wastewater pollutants fro m 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 initia lly collected in the hoppers of the particulate control system (e.g., el ectrostatic precipitator or baghouse) for both a wet and dry transport system. EPA is evaluati ng 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 ofthe furnace where it is quenched in a waterfilled hopper. Ash from the hopper is fed into a conve ying 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 sma ll 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 botto m ash is collected in a water bath trough at

the bottom of the boiler to cool the ash. The plant operates a dr ag 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 as h is often conveyed to a nearby collection area, such as a small bunker outside the boiler bui lding, 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.Enclosure III - Tribal Consultations Supplemental Information

9 Option 1 – No change

No change to the current ELG requirements.

Option 2 – Zero discharge of bottom ash tr ansport water (based on either complete recycle of transport water or conversion to dry bottom ash transport)

This option is based on the conversion of we t bottom ash handling systems (specifically a wet bottom ash sluicing system) to a dry bottom as h handling system such as a mechanical drag system, or a closed-cycle remote mechanical dr ag system. The mechanical drag system conveys the bottom ash out of the boiler to a nearby stor age area. The remote mechanical drag system operates by sluicing the bottom ash to a water tr ough 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 di scharge of ash transport water, and the dewatered ash solids are landfilled or beneficially reused.

2.4 Leachate from Landfills/Ponds Cont aining Coal Combustion Residuals

Coal combustion residues (CCR) comprise a va riety 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-si te landfills or surface impoundments. Leachate is the liquid that drains or leaches from a landf ill or an impoundment. Th e two sources of landfill leachate are precipitation that percolates thr ough the waste deposited in the landfill and the liquids produced from the CCR placed in the landfill.

Figure 3 presents a diagram depicting the co llection system for la ndfill leachate. In a lined landfill, the leachate coll ected 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 disc harge the effluent from these collection ponds directly to surface water, while other plan ts send the leachate to the ash pond. Surface impoundments may also have liners and collecti on 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 metall ic contaminants from aqueous solutions by converting soluble heavy metals to insoluble sa lts. The precipitated so lids are then removed from solution by flocculation followed by sediment ation and/or filtration. EPA is evaluating chemical precipitation/iron copr ecipitation technology for the treatment of leachate from CCR landfills/ponds, specifically designed to target removal of mercury a nd arsenic. Note that this is the same Option 2 described above for FGD wast ewater and that EPA is also evaluating cotreatment of FGD wastewat er and landfill/pond leachate.Enclosure III - Tribal Consultations Supplemental Information

10 Option 3 – Chemical precipitati on with biologic al treatment

This option includes the chemical precipi tation technology evaluated under Option 2, followed by a fixed film anoxic/anaerobic bioreac tor 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, th is treatment step is also effective in removing nitrate and

sulfates. Note that this is th e same Option 3 described above that EPA is evaluating for FGD wastewater and that EPA is also evaluating co-treatment of FGD wa stewater and landfill/pond

leachate.

Figure 3. Diagram of Landfill Leachate Collection

2.5 Mercury Control System Wastewater

Some plants have or plan to install system s to control the emission of mercury via flue gas. The vast majority of these systems repor t 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 eith er upstream or downstream of the ESP and the carbon and mercury waste is collect ed with their fly ash. These wet systems tend to be ash sluice systems that combine the mercury control wastes w ith 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.Enclosure III - Tribal Consultations Supplemental Information

11 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 gasi fication wastewater us ing a vapor-compression evaporation system that uses heat to evaporate the wastewater and genera te 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 in tegrated gasification combined cycle (IGCC) facilities produces a wastewater purge stre am (grey water). The treatment option being considered for the grey water is vapor compression evaporation fo llowed by crystallization, producing an aqueous stream (distillate) and solid by-pr oducts (crystallized salts). The so lids 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 evapor ation plus cyanide destruction

Similar to Option 2, but would also add a tr eatment 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 asso ciated with EPA’s technology options for three model plants ranging in size from 50 MW to 600 MW.E nclosure III - Tribal Consultations Supplemental Information

12Table 2. Treatment Option Costs for Model Plants (Preliminary Estimates, October 2011)1. Three "model plants" are presented toprovide insight to the potential compliance costs for regulatory options under consideration. The generation capacity(MW) noted in the table header are approximate values.2. Estimated costs do not reflect offsetting cost reductionsassociated with ceasing operationof an existing settling pond oravoiding installation of a settling pondto 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 is co-treated with FGDwastewater.4. Annualized costs sum the operating and maintenance (O&M) costs and annualized capital costs, using a 7% interest rate and a20-year service life for theequipment."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 CostAnnual O&MCostAnnualizedCostCapital CostAnnual O&MCostAnnualizedCost Capital CostAnnual O&MCostAnnualizedCost(2010 $)(2010 $) (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 $1,784,000 $3,237,000FGD Option 3: CP + Bio$9,823,000 $727,000 $1,654,000 $14,335,000 $1,216,000 $2,569,000 $23,610,000 $2,247,000 $4,476,000FGD 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 $5,463,000 $10,232,000Fly 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 $1,928,000 $2,188,000Bottom 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 $1,761,000 $2,966,000Leachate 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 $846,000 $1,625,000Leachate Option 3: CP + Bio$6,987,000 $412,000 $1,072,000 $11,935,000 $838,000 $1,964,000 $14,216,000 $1,193,000 $2,535,000ELG OptionModel Plant 1 (approx 50-100 MW) Model Plant 2 (approx 250-350 MW) Model Plant 3 (approx 500-600 MW)