# Steam Electric Power Generating Effluent

Guidelines Rulemaking

Supplemental Information Package #2 for Federalism and Unfunded Mandates Reform Act (UMRA) Consultations

October 18, 2011Federalism/UMRA Supplemental Information – Package #2

1 1. B ACKGROUND

The U.S. Environmental Protection Agency is currently enga ged 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 pow er generating ELGs are nationally applicable, technology-based discharge requirements. Thes e ELGs are incorporated into NPDES discharge permits, and in control mechanisms for dischar ges to Publically Owned Treatment Works (POTWS). This document was prepared to facilitate a dialogue about the ELG rulemaking as part of the Federalism and Unfunded Mandates R eform Act (UMRA)

consultations.

This document provides information about preliminary compli ance cost estimates for pollution controls being considered as the technology basi s for regulatory options. Additional information about the steam electric industry, the pro cesses 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 rep ort, as well as additional information about the progression of the rulemaking since its inceptio n, is available at EPA’s project web site at http://water.epa.gov/scitech/wastetech/guide/steam_i ndex.cfm.

The Steam Electric Power Generating ELGs apply to a sub set of the electric power industry, namely those plants “primarily engaged in the gen eration 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 emplo ying the steam-water system as the thermodynamic medium.” (See 40 CFR 423.10) Figure 1 broadly de picts the various types of electric generating plants and identifies which are regul ated by the Steam Electric Power Generating effluent guidelines. For more information on t his industry and the processes used, see Chapter 3 of the Steam Electric Power Generating Point Source Category: Final Detail ed Study Report (EPA 821-R-09-008, October 2009).

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

Figure 1. Types of U.S. Electric Generating UnitsFederalism/UMRA Supplemental Information – Package #2

2 Section 304 (m) of the Clean Water Act (CWA) requires E PA to periodically review all effluent guidelines to determine whether revisions are warra nted. During its 2005 annual review of discharges from point source categories, EPA’s anal ysis of publicly available data reported through the NPDES permit program and the Toxics Release Inv entory (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 ha ve occurred in this industry over the last three decades. The development of new technologies for ge nerating electric power (e.g., coal gasification) and the widespread implementation of air pol lution controls (e.g., flue gas desulfurization (FGD), selective catalytic reduction (SC R)) have altered existing or created new wastewater streams at many power plants. Wastewater dis charges from power plants have been

identified as the source for a number of environmental im pacts to ground water and surface water, including contaminated drinking water and other effect s. The main pollutants of concern for these discharges include metals (e.g., mercury, arse nic, 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 or ganisms, fish advisories, and risks to human health. More information about the potential envir onmental impacts is presented in Chapter 6 of

Steam Electric Power Generating Point Source Category: Final Detail ed Study Report (EPA 821-R-09-008, October 2009). EPA’s analysis of the wastew ater 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 Electri c Power Generating Point Source Category (i.e., the Steam Electric effluent gu idelines) in 1974 with subsequent revisions in 1977 and 1982. The Steam Electric effluent guidelines are codi fied 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 was tewaters from wet scrubber air pollution control systems, ion exchange wa ter treatment systems, water treatment evaporator blowdown, laboratory and sam pling streams, boiler blowdown, floor drains, cooling tower basin cleaning wastes , and recirculating house service water systems (sanitary and air conditioni ng wastes are not included) [40 CFR 423.11(b)].

The current effluent guidelines are summarized in Table 1.Federalism/UMRA Supplemental Information – Package #2

3 Although the rulemaking may address aspects of the regulatio n 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 SO 2 air pollution controls;

• Discharges of fly ash and bottom ash transport water;

• Leachate from ponds and landfills containing coal combust ion residues;

• Gasification wastewater from integrated gasification c ombined cycle (IGCC) plants; and

• Wastewater associated with flue gas mercury controls (e .g., wastewater resulting from transporting/handling solids from activated carbon i njection).

In addition to evaluating possible requirements for the di scharges 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 clar ifications 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 genera ting units (which would affect gas-fired generating units) and the definitions for metal c leaning wastes (which would apply to all fossil- and nuclear-fueled units) would result in negli gible, if any, compliance costs. New requirements for FGD wastewater, fly and bottom ash w astewater, pond/landfill leachate, gasification wastewater, and wastewater from mercury c ontrols or SCRs could result in compliance costs for some units that use coal or petrol eum coke. Requirements for ash transport water could also result in compliance costs for some oi l-fired generating units.4

Federalism/UMRA Supplemental Information – Package #2Table 1. Current Effluent Guidelines and Standards for the Steam Electric Power Generating Point Source CategoryWaste StreamExisting Sources that are Direct DischargersNew Sources that are DirectDischargersExisting and New Sources thatare Indirect DischargersBPTaBATaNSPSaPSES and PSNSaAll Waste StreamspH: 6-9 S.U.bPCBs: Zero dischargePCBs: Zero dischargepH: 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 TransportTSS: 100 mg/L; 30 mg/LOil & Grease: 20 mg/L; 15 mg/LZero dischargeZero 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 RunoffTSS*: 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 CleaningWastesbelowChemicalSeeMetal Cleaning WastesaboveCopper: 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-chemicalSeeMetal Cleaning WastesaboveReservedReservedReservedSource: [40 CFR Part 423].5

Federalism/UMRA Supplemental Information – Package #2a – 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 chlorinerelease period. Discharge is limited to 2hrs/day/unit. Simultaneous discharge of chlorine from multiple units is prohibited. Limitations are applicable at the discharge from 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 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 to40 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 economicallyachievable.NSPS: New source performance standards.PSES: Pretreatment standards for existing sources.PSNS: Pretreatment standards for new sources.Federalism/UMRA Supplemental Information – Package #2

6 2. T ECHNOLOGY O PTIONS U NDER E VALUATION

EPA is evaluating several technology-based options for th e control of wastewater discharges from power plants. With the exception of NSP S 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 Cl ean Water Act (CWA) provisions for best available technology economically a chievable (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 pr ovisions for new source performance standards (NSPS) and pretreatment standards fo r new sources (PSNS). [33 USC 1316(b); USC 1317(c)] No new NSPS requirements are being conside red fly ash transport water since the current NSPS states “[t]here shall be no di scharge 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 SO 2 and other pollutants from stack emissions. In wet FGD scrubbers, the flue gas stream co mes in contact with a liquid stream containing a sorbent, such as lime or limestone, which i s used to transfer pollutants from the flue gas to the liquid stream. FGD scrubber system wastewater s, including the wastewater stream from dewatering and scrubber blowdown, contain elevated lev els of metals (e.g., mercury, arsenic, selenium), nitrogen, and total dissolved solids.

EPA identified and investigated wastewater treatment syste ms operated by steam electric plants for the treatment of FGD scrubber purge. Most plant s currently discharging FGD wastewater use settling ponds; however, the use of more a dvanced wastewater treatment systems is increasing to a limited extent due to more stringent re quirements imposed by some states on a site-specific basis. Figure shows the distribution of m anagement/treatment for wastewater from wet FGD systems reported in the 2010 questionnaire for 150 plants

.

The current ELGs include these discharges within the def inition of “low volume wastes.” EPA is considering establishing revised effluent limits for F GD 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 salts. Th e precipitated solids are then removed from solution by flocculation followed by sedimentation and/or filtration. EPA is evaluating chemical precipitation/iron co-precipitation specifica lly 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 met al 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 f acilitate coagulation and removal of the precipitated solids.Federalism/UMRA Supplemental Information – Package #2

7 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 treat ment 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 hea t to evaporate the wastewater and generate a clean distillate stream. The key steps of t he treatment process include pretreatment of the wastewater by chemical precipitation and softening, f ollowed 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., c rystallized 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 ca rried out of the furnace. The fly ash particles that remain entrained in the flue gases are car ried 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 orFederalism/UMRA Supplemental Information – Package #2

8 sluiced with water to a surface impoundment (i.e., ash po nd). 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 wh ere a plant has both wet and dry handling, the wet handling system is a legacy system tha t was retained during conversion of the ash handling system and retained as a backup to the dry syste m. 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 handli ng 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., electr ostatic precipitator or baghouse) for both a wet and dry transport system. EPA is evaluating a dry han dling system that uses a vacuum system to pneumatically transport the ash from the hoppe r 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 th e 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 fur nace 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 pon ds operating in series and/or parallel. The ash sent to a dewatering bin is separated from the trans port 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 o perates 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 ofte n conveyed to a nearby collection area, such as a small bunker outside the boiler buildi ng, 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 bott om ash transport systems, while approximately 30% operate only dry systems.Federalism/UMRA Supplemental Information – Package #2

9 Option 1 – No change

No change to the current ELG requirements.

Option 2 – Zero discharge of bottom ash transport water (based on either comple te 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 hand ling 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 are a. The remote mechanical drag system operates by sluicing the bottom ash to a water trough an d sump located away from the boiler, where a stand-alone mechanical drag system is used to dewat er the ash. The sluice water for the remote mechanical drag system is continually reused to pre vent discharge of ash transport water,

and the dewatered ash solids are landfilled or beneficial ly reused.

2.4 Leachate from Landfills/Ponds Containing Coal Combustion Resid uals

Coal combustion residues (CCR) comprise a variety of wa stes 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 la ndfills 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 landfi ll typically flows through a collection system consisting of ditches and/or underground pipes. From the col lection 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 contami nants from aqueous solutions by converting soluble heavy metals to insoluble salts. Th e 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 an d that EPA is also evaluating cotreatment of FGD wastewater and landfill/pond leachate

.Federalism/UMRA Supplemental Information – Package #2

10 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 treat ment system. The primary purpose of the bioreactor treatment system is to increase the rem oval of metals, particularly selenium, from the landfill/pond leachate; however, this treatment st ep is also effective in removing nitrate and sulfates. Note that this is the same Option 3 described a bove that EPA is evaluating for FGD wastewater and that EPA is also evaluating co-treatmen t 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 t he 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 upstrea m or downstream of the ESP and the carbon and mercury waste is collected with their fly a sh. These wet systems tend to be ash sluice systems that combine the mercury control wastes with t he fly ash sluiced to an ash pond. In some cases, the plants report treating their coal with an o xidant that works to fully oxidize mercury when the coal is burned. The oxidized mercury is then re moved in their normal air pollution

controls and handled with ash or FGD wastewater.Federalism/UMRA Supplemental Information – Package #2

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 gasificat ion wastewater using a vapor-compression evaporation system that uses heat to evaporate the wast ewater 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 com bined cycle (IGCC) facilities produces a wastewater purge stream (grey water). The treat ment option being considered for the grey water is vapor compression evaporation followed by cr ystallization, producing an aqueous stream (distillate) and solid by-products (crystallized sa lts). The solids would be sent to a landfill for disposal. This is equal to the current level of treat ment 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 (s uch 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 co sts associated with EPA’s technology options for three model plants ranging in si ze from 50 MW to 600 MW.Federalism/UMRA Supplemental Information – Package #2

12Table 2. Treatment Option Costs for Model Plants (Preliminary Estimates, October 2011)1. Three "model plants" are presented to provide insight tothe 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 reductions associated with ceasing operation of an existing settling pond or avoiding 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 rateand a 20-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&MCostAnnualizedCost Capital 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)