### 5-1 

# 5 Emission Control Technologies EPA Base Case v.4.10 includes a major update of emission control technology assumptions. For this base case EPA contracted with engineering firm Sargent and Lundy to perform a complete bottom-up engineering reassessment of the cost and performance assumptions for sulfur dioxide (SO 2 

### ) and nitrogen oxides (NO X 

### ) emission controls. In addition to the work by Sargent and Lundy, Base Case v.4.10 includes two Activated Carbon Injections (ACI) options (Standard and Modified) for mercury (Hg) control 27 

### . Capture and storage options for carbon dioxide (CO 2 

### ) have also been added in the new base case.

These emission control options are listed in Table 5-1. They are available in EPA Base Case v.4.10 for meeting existing and potential federal, regi onal, and state emission limits. It is important to note that, besides the emission control opti ons shown in Table 5-1 and described in this chapter, EPA Base Case v.4.10 offers other compliance options for meeting emission limits. These include fuel switching, adjustments in the dispatching of electric generating units, and the option to retire a unit.

Table 5-1 Summary of Emission Control Technology Retrofit Options in EPA Base Case v.4.10 SO 2 

### Control Technology Options NO X 

### Control Technology Options Hg Control Technology Options CO 2 

### Control Technology Options Limestone Forced Oxidation (LSFO) Scrubber Selective Catalytic Reduction (SCR) System Standard ActivatedCarbon Injection (SPACACI) System CO 2 

### Capture and Sequestration

Lime Spray Dryer (LSD) Scrubber Selective NonCatalytic Reduction

(SNCR) System Modified Activated Carbon Injection (MPAC-ACI) System

Combustion Controls SO 2 

### and NO X 

### Control Technology Removal Cobenefits



# 5.1 Sulfur Dioxide Control Technologies Two commercially available Flue Gas Desulfurizat ion (FGD) technology options for removing the SO 2 

### produced by coal-fired power plants are offered in EPA Base Case v.4.10: Limestone Forced Oxidation (LSFO) — a wet FGD technology — and Lime Spray Dryer (LSD) — a semi-dry FGD technology which employs a spray dryer absorber (SDA). In wet FGD systems, the polluted gas stream is brought into contact with a liquid alkaline sorbent (typically limestone) by forcing it through a pool of the liquid slurry or by spraying it with the liquid. In dry FGD systems the polluted gas stream is brought into contact with the alkaline sorbent in a semi-dry state through use of a spray dryer. The removal efficiency for SDA drops steadily for coals whose SO 2 

### content exceeds 3lb SO 2 

### /MMBtu, so this technology is provided only to plants which have the option to burn coals with sulfur content no greater than 3 lbs SO 2 

### /MMBtu. In EPA Base Casev.4.10 when a unit retrofits with an LSD SO 2 

### scrubber, it loses the option of burning BG, BH, and LG coals due to their high sulfur content.

In EPA Base Case v.4.10 the LSFO and LSD SO 2 

### emission control technologies are available to existing "unscrubbed" units. They are also ava ilable to existing "scrubbed" units with reported removal efficiencies of less than fifty percent. Such units are considered to have an injection technology and classified as “unscrubbed” for modeling purposes in the NEEDS database of

27 

### The mercury emission controls options and assumptions in EPA Base Case v.4.10 do not reflect mercury control updates that are currently under way at EPA in support of the Utility MACT initiative and do not make use of data collected under EPA’s 2010 Information Collection Request (ICR).

### 5-2 existing units which is used in setting up the EPA base case. The scrubber retrofit costs for these units are the same as regular unscrubbed units retrofitting with a scrubber. Scrubber efficiencies for existing units were derived from data reported in EIA Form 767. In transferring this data for use in EPA Base Case v.4.10 the following changes were made. The maximum removal efficiency was set at 98% for wet scrubbers and 93% for dry scrubber units. Existing units reporting efficiencies above these levels in Form 767 were assigned the maximum removal efficiency in NEEDS v.4.10 indicated in the previous sentence.

As shown in Table 5-2, existing units that ar e selected to be retrofitted by the model with scrubbers are given the maximum removal efficienc ies of 98% for LSFO and 93% for LSD. The procedures used to derive the cost of each scrubber type are discussed in detail in the following sections.

Table 5-2 Summary of Retrofit SO 2 

### Emission Control Performance Assumptions Performance Assumptions Limestone Forced Oxidation (LSFO) Lime Spray Dryer (LSD)

Percent Removal 98% with a floor of 0.06 lbs/MMBtu 93% with a floor of 0.065 lbs/MMBtu Capacity Penalty Heat Rate Penalty Cost (2007$) Calculated based on characteristics of the unit: See Table 5-4 for examples Calculated based on characteristics of the unit: See Table 5-4 for examples Applicability Units ≥ 25 MW Units ≥ 25 MW Sulfur Content Applicability Coals ≤ 3 lbs SO 2 

### /MMBtu

Applicable Coal Types BA, BB, BD, BE, BG, BH, SA, SB, SD, LD, LE, and LG BA, BB, BD, BE, SA, SB, SD, LD, and LE

Potential (new) coal-fired units built by the model are also assumed to be constructed with a scrubber achieving a removal efficiency of 98% fo r LSFO and 93% for LSD. In EPA Base Case v.4.10 the costs of potential new coal units include the cost of scrubbers.

5.1.1 Methodology for Obtaining SO 2 

### Controls Costs The Sargent and Lundy update of SO 2 

### and NO x 

### control costs is notable on several counts. First, it brought costs up to levels seen in the marketplace in 2009. Incorporating these costs into EPA’s base case carries an implicit assumption, not universally accepted, that the run up in costs seen over the preceding 5 years and largely attributed to international competition, is permanent and will not settle back to pre-2009 levels. Second, a revised methodology, based on Sargent and Lundy’s expert experience, was used to build up the capital, fixed and variable operating and maintenance components of cost. That methodology, which employed an engineering build up of each component of cost, is described here and in the following sections. Detailed example cost calculation spreadsheets for both SO 2 

### and NO x 

### controls are included in Appendices 5-1 and 5-2 respectively. The Sargent and Lundy reports in which these spreadsheets appeared can be downloaded via links to the Appendices 5-1A , 5-1B, 5-2A, and 5-2B links found at www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html

. Capital Costs : In building up capital costs three separate cost modules were included for LSD and four for LSFO: absorber island, reagent prepar ation, waste handling (LSFO only), and everything else (also called “balance of plant”) with the latter constituting the largest cost module, consisting of fans, new wet chimney, piping, ductwork, minor waste water treatment, and other costs required for treatment. For each of the four modul es the cost of foundations, buildings, electrical equipment, installation, minor, physical and chemical wastewater treatment, and average retrofit difficulty were taken into account.

### 5-3 The governing cost variables for each module are i ndicated in Table 5-3. The major variables affecting capital cost are unit size and the SO 2 

### content of the fuel with the latter having the greatest impact on the reagent and waste handling facilities. In addition, heat rate affects the amount of flue gas produced and consequently the size of each of the modules. The quantity of flue gas is also a function of coal rank since di fferent coals have different typical heating values.

Table 5-3 Capital Cost Modules and Their Governing Variables for SO 2 

### and NO x 

### Emission Controls

Module Retrofit Difficulty (1 = average) Coal Rank Factor (Bi t 

### = 1, PRB = 1.05, Lignite = 1.07) Heat Rate (Btu/kWh) SO 2 

### Rate (lb/MMBtu) NO x 

### Rate (lb/MMBtu) 5 

### Unit Size (MW)

SO 2 

### Emission Controls – Wet FGD and SDA FGD

Absorber Island X X X X X

Reagent Preparation X X X X

Waste Handling X X X X

Balance of Plant 1 

### X X X X

NO x 

### Emission Controls – SCR and SNCR

SCR/SNCR Island 2 

### X X X X 3 

### X

Reagent Preparation 3 

### X

Air Heater Modification 4 

### X X X X X

Balance of Plant 5 

### – SCR X X X X

Balance of Plant 1


### – SNCR X X

Notes: 1 

### “Balance of plant” costs include such cost items as ID and booster fans, new wet chimneys, piping, ductwork, minor waste water treatment, aux iliary power modifications, and other electrical and site upgrades. 2 

### The SCR island module includes the cost of inlet ductwork, reactor, and bypass. The SNCR island module includes cost of injectors, blower s, distributed control system (DCS), and reagent system. 3 

### Only applies to SCR.
4 

### On generating units that burn bituminous coal whose SO 2 

### and content exceeds 3 lbs/MMBtu, air heater modifications used to control SO 3 

### are needed in conjunction with the operation of SCR and SNCR.
5 

### For SCR, the NO x 

### rate is frequently expressed through the calculated NO x 

### removal efficiency.

### 5-4 Once the key variables that figure in the cost of the four modules are identified, they are used to derive costs for each base module in equations developed by Sargent and Lundy based on their experience with multiple engineering projects. The base module costs are summed to obtain total bare module costs. This total is increased by 30% to account for additional engineering and construction fees. The resulting value is the capital, engineering, and construction cost (CECC) subtotal. To obtain the total project cost (TPC), the CECC subtotal is increased by 5% to account for owner’s home office costs, i.e., owner’s engineering, management, and procurement costs. The resulting sum is then increased by another 10% to build in an Allowance for Funds used During Construction (AFUDC) over the 3-year engi neering and construction cycle. The resulting value, expressed in $/kW, is the capital cost factor that is used in EPA Base Case v.4.10.

Variable Operating and Maintenance Costs (VOM) : These are the costs incurred in running the emission control device. They are proporti onal to the electrical energy produced and are expressed in units of $ per MWh. For FGD, Sargent and Lundy identified four components of VOM: (a) costs for reagent usage, (b) costs for waste generation, (c) make up water costs, and (d) cost of additional power required to run the c ontrol (often called the “parasitic load”). For a given coal rank and a pre-specified SO 2 

### removal efficiency, each of these components of VOM cost is a function of the generating unit’s heat rate (Btu/kWh) and the sulfur content (lb SO 2 

### /MMBtu) of the coal (also referred to as the SO 2 

### feed rate). For purposes of modeling, the total VOM includes the first three of these component costs. The last component – cost of additional power – is factored into IPM, not in the VOM value, but through a capacity and heat rate penalty as described in the next paragraph. Due to the differences in the removal processes, the per MWh cost for waste handling, makeup water, and auxiliary power tend to be higher for LSFO while reagent usage cost and total VOM (excluding parasitic load) are higher for LSD.

Capacity and Heat Rate Penalty : The amount of electrical power required to operate the FGD device is represented through a reduction in the amount of electricity that is available for sale to the grid. For example, if 1.6% of the unit’ s electrical generation is needed to operate the scrubber, the generating unit’s capacity is reduced by 1.6%. This is the “capacity penalty.” At the same time, to capture the total fuel used in generation both for sale to the grid and for internal load (i.e., for operating the FGD device), the unit’s heat rate is scaled up such that a comparable reduction (1.6% in the previous example) in the new higher heat rate yields the original heat rate 28 

### . The factor used to scale up the original heat rate is called “heat rate penalty.” It is a modeling procedure only and does not represent an increase in the unit’s actual heat rate (i.e., a decrease in the unit’s generation efficiency). Unlike prev ious base cases, which assumed a generic heat rate and capacity penalties for all installations, in EPA Base Case v.4.10 specific LSFO and LSD heat rate and capacity penalties are calculated for each installation based on equations developed by Sargent and Lundy that take into account the rank of coal burned, its SO 2 

### rate, and the heat rate of the model plant.

Fixed Operating and Maintenance Costs (FOM) : These are the annual costs of maintaining a unit. They represent expenses incurred regardless of the extent to which the emission control system is run. They are expressed in units of $ per kW per year. In calculating FOM Sargent and Lundy took into account labor and materials costs associated with operations, maintenance, and administrative functions. The following assumptions were made:

28 

### Mathematically, the relationship of the heat rate and capacity penalties (both expressed as positive percentage values) can be represented as follows:



## 100 1

100 Penalty Capacity 1 1 Penalty Rate Heat × ⎟ ⎟ ⎟ ⎟

⎠ ⎞

⎜ ⎜ ⎜ ⎜

⎝ ⎛

− ⎟ ⎠ ⎞ ⎜ ⎝ ⎛

− =

### 5-5 • FOM for operations is based on the number of operators needed which is a function of the size (i.e., MW capacity) of the generating uni t and the type of FGD control. For LSFO 12 additional operators were assumed to be required for a 500 MW or smaller installation and 16 for a unit larger than 500 MW. For LSD 8 additional operators were assumed to be needed.

• FOM for maintenance is a direct function of the FGD capital cost

• FOM for administration is a function of the FOM for operations and maintenance.

Table 5-4 presents the capital, VOM, and FOM costs as well as the capacity and heat rate penalty for the two SO 2 

### emission control technologies (LSFO and LSD) included in EPA Base Case v.4.10 for an illustrative set of generating units with a representative range of capacities and heat rates.5-6Table 5-4 Illustrative Scrubber Costs (2007$) for RepresentativeSizes and Heat Rates under the Assumptions in EPA Base Case v.4.10Capacity (MW)1003005007001000Scrubber TypeHeat Rate(Btu/kWh)CapacityPenalty(%)HeatRatePenalty(%)VariableO&M(mills/kWh)CapitalCost($/kW)FixedO&M($/kW-yr)CapitalCost($/kW)FixedO&M($/kW-yr)CapitalCost($/kW)FixedO&M($/kW-yr)CapitalCost($/kW)Fixed O&M($/kW-yr)CapitalCost($/kW)FixedO&M($/kW-yr)LSFOMinimum Cutoff:≥25 MW9,000-1.51.531.6674722.554710.54737.84307.23885.9Maximum Cutoff:None10,000-1.671.71.8478322.857310.84968.04517.44076.1Assuming 3lb/MMBtu SO2ContentBituminous Coal11,000-1.841.872.0381723.259811.05178.24707.64256.3LSDMinimum Cutoff:≥25 MW9,000-1.181.22.1364116.44698.14066.13855.33854.9Maximum Cutoff:None10,000-1.321.332.3667016.74918.34246.34035.54035.1Assuming 2lb/MMBtu SO2ContentBituminous Coal11,000-1.451.472.6069817.05118.54426.54205.74205.2

### 5-7 

# 5.2 Nitrogen Oxides Control Technology The EPA Base Case v.4.10 includes two categories of NO x 

### reduction technologies: combustion and post-combustion controls. Combustion controls reduce NO x 

### emissions during the combustion process by regulating flame characteristics such as temperature and fuel-air mixing. Postcombustion controls operate downstream of the combustion process and remove NO x 

### emissions from the flue gas. All the specific combus tion and post-combustion technologies included in EPA Base Case v.4.10 are commercially available and currently in use in numerous power plants.

5.2.1 Combustion Controls The EPA Base Case v.4.10 representation of combustion controls uses equations that are tailored to the boiler type, coal type, and combustion c ontrols already in place and allow appropriate additional combustion controls to be exogenously applied to generating units based on the NO x 

### emission limits they face. Characterizations of the emission reductions provided by combustion controls are presented in Table 3-1.3 in Appendix 3-1. The EPA Base Case v.4.10 cost assumptions for NO x 

### Combustion Controls are summarized in Table 5-5. Table 5-6 provides a mapping of existing coal unit configurations and incremental combustion controls applied in EPA Base Case v.4.10 to achieve state-of-the-art combustion control configuration.
Table 5-5 Cost (2007$) of NO x 

### Combustion Controls for Coal Boilers (300 MW Size)

Boiler Type Technology Capital ($/kW) Fixed O&M($/kWyr) Variable O&M (mills/kWh)

Low NO x 

### Burner without Overfire Air (LNB without OFA) 45 0.3 0.07Dry Bottom WallFired Low NO x 

### Burner with Overfire Air (LNB with OFA) 61 0.4 0.09
Low NO x 

### Coal-and-Air Nozzles with Close-Coupled Overfire Air (LNC1) 24 0.2 0.00

Low NO x 

### Coal-and-Air Nozzles with Separated Overfire Air (LNC2) 33 0.2 0.03 Tangentially- Fired Low NO x 

### Coal-and-Air Nozzles with Close-Coupled and Separated Overfire Air (LNC3) 38 0.3 0.03

Vertically-Fired NO x 

### Combustion Control 29 0.2 0.06 Scaling Factor The following scaling factor is used to obtain the capital and fixed operating and maintenance costs applicable to the capacity (in MW) of the unit taking on combustion controls. No scaling factor is applied in calculating the variable operating and maintenance cost. LNB without OFA & LNB with OFA = ($ for X MW Unit) = ($ for 300 MW Unit) x (300/ X

) 0.359 

### LNC1, LNC2 and LNC3 = ($ for X MW Unit) = ($ for 300 MW Unit) x (300/ X

) 0.359 

### Vertically-Fired = ($ for X MW Unit) = ($ for 300 MW Unit) x (300/ X

) 0.553


### where ($ for 300 MW Unit) is the val ue obtained using the factors shown in the above table and X

is the capacity (in MW) of the unit taking on combustion controls.

### 5-8 Table 5-6 Incremental Combustion NO x 

### Controls in EPA Base Case v.4.10 Boiler Type Existing NO x 

### Combustion Control Incremental Combustional Control

LNB OFA Cell NGR LNB AND OFA Cyclone -- OFA Stoker/SPR -- OFA

-- LNC3 LA LNC3 LNB CONVERSION FROM LNC1 TO LNC3 LNB + OFA CONVERSION FROM LNC1 TO LNC3 LNC1 CONVERSION FROM LNC1 TO LNC3 LNC2 CONVERSION FROM LNC2 TO LNC3 OFA LNC1 Tangential

ROFA LNB

Vertical -- NO x 

### Combustion Control - Vertically Fired Units

-- LNB AND OFA LA LNB AND OFA LNB OFA LNF OFA Wall

OFA LNB

5.2.2 Post-combustion Controls The EPA Base Case v.4.10 includes two post-combustion retrofit control technologies for existing coal units: Selective Catalytic Reduction (SCR) and Selective Non-Catalytic Reduction (SNCR). In EPA Base Case v.4.10 oil/gas steam units are eligible for SCR only. NO x 

### reduction in an SCR system takes place by injecting ammonia (NH 3 

### ) vapor into the flue gas stream where the NO x 

### is reduced to nitrogen (N2) and water H 2 

### O abetted by passing over a catalyst bed typically containing titanium, vanadium oxides, molybdenum, and/or tungsten. As its name implies, SNCR operates without a catalyst. In SNCR a nitrogenous reducing agent (reagent), typically ammonia or urea, is injected into, and mixed with, hot flue gas where it reacts with the NO x 

### in the gas stream reducing it to nitrogen gas and water vapor. Due to the presence of a catalyst, SCR can achieve greater NO x 

### reductions than SNCR. However, SCR costs are higher.

Table 5-7 summarizes the performance and applicability assumptions in EPA Base Case v.4.10 for each NO x 

### post-combustion control technology and provides a cross reference to information on cost assumptions.

Table 5-7 Summary of Retrofit NO x 

### Emission Control Performance Assumptions

Control Performance Assumptions Selective Catalytic Reduction (SCR) Selective Non-Catalytic Reduction

(SNCR) Unit Type Coal Oil/Gas Coal Pulverized Coal: 35% Percent Removal 90% down to 0.06 lb/MMBtu 80% Fluidized Bed: 50%
Size Applicability Units ≥ 25 MW Units ≥ 25 MW Units ≥ 25 MW

Costs (2007$) See Table 5-8 See Table 5-9 See Table 5-8

### 5-9 Potential (new) coal-fired, combined cycle, and IGCC units are modeled to be constructed with SCR systems and designed to have emission rates ranging between 0.01 and 0.06 lb NO x 

### /MMBtu. EPA Base Case v.4.10 cost assumptions for these units include the cost of SCR

5.2.3 Methodology for Obtaining SCR Costs for Coal Units As with the update of SO 2 

### control costs, Sargent and Lundy employed an engineering build-up ofthe capital, fixed and variable operating and maintenance components of cost to update postcombustion NO x 

### control costs. This section describes the approach used for SCR. The next section treats SNCR. Detailed example cost ca lculation spreadsheets for both technologies can be found in Appendix 5-2.

For cost calculation purposes the Sargent and Lundy methodology calculates plant specific NO x 

### removal efficiencies, i.e., the percent difference between the uncontrolled NO x 

### rate 29 

### for a model plant and the cost calculation floor NO x 

### rate corresponding to the predominant coal rank used at the plant ( 0.07 lb/MMBtu for bituminous and 0.05 lb/MMBtu for subbitumionus and lignite coals). For example, a plant that burns subbitumionus coal with an uncontrolled NO x 

### rate of 0.1667 lb/MMBtu, and a cost calculation floor NO x 

### rate of 0.05 lb/MMBtu would have a removal efficiency of 70%, i.e., (0.1667 – 0.05)/0.1667 = 0.1167/0.1667 = .70. The NO x 

### removal efficiency so obtained figures in the capital, VOM, and FOM components of SCR cost.

Capital Costs : In building up SCR capital costs, four separate cost modules were included: SCR island (e.g., inlet ductwork, reactor, and bypass), reagent preparation, air pre-heater modification, and balance of plan (e.g., ID or booster fans, pipi ng, and auxiliary power modification). Air preheater modification cost only applies for pl ants that burn bituminous coal whose SO 2 

### content is 3 lbs/MMBtu or greater, where SO 3 

### control is necessary. Otherwise, there is no air pre-heat cost. For each of the four modules the cost of foundati ons, buildings, electrical equipment, installation, and average retrofit difficulty were taken into account.

The governing cost variables for each module are indi cated in Table 5-3. All four capital cost modules, except reagent preparation, are functions of retrofit difficulty, coal rank, heat rate, and unit size. NO x 

### rate (expressed via the NO x 

### removal efficiency) affects the SCR and reagent preparation cost modules. Not shown in Table 5- 3, heat input (in Btu/hr) also impacts reagent preparation costs. As noted above, the SO 2 

### rate becomes a factor in SCR cost for plants that combust bituminous coal with 3 lbs SO 2 

### /MMBtu or greater, where air pre-heater modifications are needed for SO 3 

### control.

As with FGD capital costs, the base module costs for SCR are summed to obtain total bare module costs. This total is increased by 30% to account for additional engineering and construction fees. The resulting value is the capital, engineering, and construction cost (CECC) subtotal. To obtain the total project cost (TPC) the CECC subtotal is increased by 5% to account for owner’s home office costs, i.e., owner’s engineering, management, and procurement costs. Whereas the resulting sum is then increased by another 10% for FGD, for SCR it is increased by 6% to factor in an Allowance for Funds used During Construction (AFUDC) over the 2-year engineering and construction cycle (in contrast to the 3-year cycle assumed for FGD). The resulting value, expressed in $/MW, is the capital cost factor that is used in EPA Base Case v.4.10.

Variable Operating and Maintenance Costs (VOM) : For SCR Sargent and Lundy identified four components of VOM: (a) costs for the urea reagent, (b) costs of catalyst replacement and disposal, (c) cost of required steam, and (d) cost of additional power required to run the control

29 

### More precisely, the uncontrolled NO X 

### rate for a model plant in EPA Base Case v.4.10 is the capacity weighted average of the Mode 1 NO X 

### rates of the generating units comprising the model plant. The meaning of “Mode 1 NO X 

### rate” is discussed in section 3.9.2 and Appendix 3-1 (“NO X 

### Rate Development in EPA Base Case v.4.10).

### 5-10 (i.e., the “parasitic load”). As was the case for FGD, the last component – cost of additional power – is factored into IPM, not in the VOM value, but through a capacity and heat rate penalty as described earlier. Of the first three of these component costs, reagent cost and catalyst replacement are predominant while steam cost is much lower in magnitude. NO x 

### rates and heat rates are key determinates of reagent and steam costs, while NO x 

### rate (via removal efficiency), capacity factor, and coal rank are key drivers of catalyst replacement costs.

Capacity and Heat Rate Penalty : Unlike previous base cases, which assumed a generic heat rate and capacity penalties for all installations, in EPA Base Case v.4.10 specific SCR heat rate and capacity penalties are calculated for each installation based on equations developed by Sargent and Lundy that take into account the rank of coal burned, its SO 2 

### rate, and the heat rate of the model plant.

Fixed Operating and Maintenance Costs (FOM) : For SCR the following assumptions were made:

• FOM for operations is based on the assumption that one additional operator working half-time is required.

• FOM for maintenance is assumed to $193,585 (in 2007$) for generating units less than 500 MW and $290,377 (in 2007$) for generating units 500 MW or greater

• There was assumed to be no FOM for administration for SCR.

Table 5-8 presents the SCR and SNCR capital, VOM, and FOM costs and capacity and heat rate penalties for an illustrative set of coal generating units with a representative range of capacities, heat rates, and NO x 

### removal efficiencies. The illustrations include and identify plants that do and do not burn bituminous coal with 3 lbs SO 2 

### /MMBtu or greater.5-11Table 5-8 Illustrative Post Combustion NOXControls for Coal Plants Costs (2007$) for Representative Sizes and Heat Rates under theAssu Assumptions in EPA Base Case v.4.10Capacity (MW)1003005007001000Control TypeHeat Rate(Btu/kWh)CapacityPenalty(%)HeatRatePenalty(%)VariableO&M(mills/kWh)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)CapitalCost($/kW)FixedO&M($/kWyr)SCRMinimum Cutoff:≥25 MW9,000-0.540.541.152212.51770.81630.71550.51470.4Maximum Cutoff: NoneAssuming Bituminous Coal10,000-0.560.561.242402.51930.81780.71690.51620.4NOxrate: 0.5 lb/MMBtuSO2rate: 2.0 lb/MMBtu11,000-0.580.591.332582.52090.81930.71840.51760.4SNCR - Non-FBCMinimum Cutoff:≥25 MW9,0000.88451Maximum Cutoff: NoneAssuming Bituminous Coal10,0000.98471NOxrate: 0.5 lb/MMBtuSO2rate: 2.0 lb/MMBtu11,000-0.050.051.08481Size Not ModeledSNCR - Fluidized BedMinimum Cutoff:≥25 MW9,0000.88340.9180.4140.2110.290.1Maximum Cutoff: NoneAssuming Bituminous Coal10,0000.98350.9190.4140.2120.2100.1NOxrate: 0.5 lb/MMBtuSO2rate: 2.0 lb/MMBtu11,000-0.050.051.08360.9190.4140.2120.2100.1Note:If a coal plant burns bituminous coal with a SO2content above 3.0 lb/MMBtu then the capital costs will increasedue to the required air preheatermodification. For example, a100MW coal boiler with an SCR burning bituminous coal at a heat rate of 11,000 Btu/kWh and an SO2rate of 4.0 lb/MMBtu will have a capital cost of 296 $/kW, a 36 $/kW increase incapital costs from an identicalboiler burning coal with an SO2rate of 2.0 lb/MMBtu.

### 5-12 5.2.4 Methodology for Obtaining SCR Costs for Oil/Gas Steam units The cost calculations for SCR described in secti on 5.2.3 apply to coal units. For SCR on oil/gas steam units the cost calculation procedure employed in EPA’s most recent previous base case was used. However, capital costs were scaled up by 2.13 to account for increases in the component costs that had occurred since the assumptions were incorporated in that base case. All costs were expressed in constant 2007$ for consistency with the dollar year cost basis used throughout EPA Base Case v4.10. Table 5-9 shows that resulting capital, FOM, and VOM cost assumptions for SCR on oil/gas steam units. T he scaling factor for capital and fixed operating and maintenance costs, described in footnote 1, applies to all size units from 25 MW and up.

Table 5-9 Post-Combustion NO X 

### Controls for Oil/Gas Steam Units in EPA Base Case v.4.10 Post-Combustion Control Technology Capital ($/kW) Fixed O&M ($/kW-yr) Variable O&M (mills/kWh) Percent Removal SCR 1 

### 75 1.08 0.12 80%
Notes: The “Coefficients” in the table above are multip lied by the terms below to determine costs. “MW” in the terms below is the unit’s capacity in megawatts. This data is used in the generation of EPA Base Case v.4.0
1 

### SCR Cost Equations: SCR Capital Cost and Fixed O&M: (200/MW) 0.35 

### The scaling factors shown above apply up to 500 MW. The cost obtained for a 500 MW unit applies for units larger than 500 MW. Example for 275 MW unit: SCR Capital Cost ($/kW) = 75 * (200/275) 0.35 

### ≈ 67 $/kW SCR FOM Cost ($/kW-yr) = 1.08 * (200/275) 0.35 

### ≈ 0.97 $/kW-yr SCR VOM Cost (mills/kWh) = 0.12 mills/kWh Reference: Cost Estimates for Selected Applications of NO X



### Control Technologies on Stationary Combustion Boilers , Bechtel Power Corporation for US EPA, June 1997

5.2.5 Methodology for Obtaining SNCR Costs In the Sargent and Lundy cost update for SNCR a generic NO X 

### removal efficiency of 25% is assumed. However, the capital, fixed and variable operating and maintenance costs of SNCR on circulating fluidized bed (CFB) uni ts are distinguished from the corresponding costs for other boiler types (e.g. cyclone, and wall fired).

Capital Costs : Due to the absence of a catalyst and, with it, the elimination of the need for more extensive reagent preparation, the Sargent and Lundy engineering build up of SNCR capital costs includes three rather than four separate cost m odules: SNCR (injectors, blowers, distributive control system, reagent system), air pre-heater modification, and balance of plan (e.g., ID or booster fans, piping, and auxiliary power modifica tion). For CFB units, the SNCR and balance of plan module costs are 75% of what they are on ot her boiler types. The air pre-heater modification cost module is the same as for SCR and there is no cost difference between CFB and other boiler types. As with SCR the air heater modification cost only applies for plants that burn bituminous coal whose SO 2 

### content is 3 lbs/MMBtu or greater, where SO 3 

### control is necessary. Otherwise, there is no air pre-heat cost. For each of the three modules the cost of foundations, buildings, electrical equipment, installation, and average retrofit difficulty were taken into account.

The governing cost variables for each module are indicated in Table 5-3. Unit size affects all three modules. Retrofit difficulty, coal rank, and heat rate impact the SNCR and air heater modification modules. The SO 2 

### rate impacts the air pre-heater modification module. NO X 

### rate

### 5-13 (expressed via the NO X 

### removal efficiency) and heat input (not shown in Table 5-3) affect the balance of plan module.

The base module costs for SNCR are summed to obtain total bare module costs. This total is increased by 30% to account for additional engineeri ng and construction fees. The resulting value is the capital, engineering, and construction cost (CE CC) subtotal. To obtain the total project cost (TPC) the CECC subtotal is increased by 5% to account for owner’s home office costs, i.e., owner’s engineering, management, and procurement costs. Since SNCR projects are typically completed in less than a year, there is no Allowance for Funds used During Construction (AFUDC) in the SNCR capital cost factor that is used in EPA Base Case v.4.10.

Variable Operating and Maintenance Costs (VOM) : Sargent and Lundy identified two components of VOM for SNCR: (a) cost for the urea reagent and (b) the cost of dilution water. The magnitude of the reagent cost predominates the VOM with the cost of dilution water at times near zero. There is no capacity or heat rate penalty associated with SNCR since the only impact on power are compressed air or blower required for urea injection and the reagent supply system.

Capacity and Heat Rate Penalty : Unlike previous base cases, which assumed a generic heat rate and capacity penalties for all installations, in EPA Base Case v.4.10 specific SNCR heat rate and capacity penalties are calculated for each installation based on equations developed by Sargent and Lundy that take into account the rank of coal burned, its SO 2 

### rate, and the heat rate of the model plant.

Fixed Operating and Maintenance Costs (FOM) : The assumptions for FOM for operations and for administration are the same for SNCR as for SCR, i.e.,

• FOM for operations is based on the assumption that one additional operator working half-time is required.

• There was assumed to be no FOM for administration for SCR.

FOM for maintenance materials and labor was assumed to be a direct function of base module cost, specifically, 1.2% of those costs divided by the capacity of the generating unit expressed in kilowatts.

Detailed example cost calculation spreadsheets for SNCR can be found in Appendix 5-2.

5.2.6 SO 2 

### and NO x 

### Controls for Units with Capacities from 25 MW to 100 MW (25 M ≤ capacity < 100 MW) In EPA Base Case v.4.10 coal units with capacities between 25 MW and 100 MW are offered the same SO 2 

### and NO x 

### emission control options as larger units. However, for purposes of modeling, the costs of controls for these units are assumed to be equivalent to that of a 100 MW unit. This assumption is based on several considerations. First, to achieve economies of scale, several units in this size range are likely to be ducted to share a single common control, so the 100 MW cost equivalency assumption, though generic, would be technically plausible. Second, single units in this size range that are not grouped to achieve economies of scale are likely to have the option of hybrid multi-pollutant controls currently under development. 30 

### These hybrid controls achieve cost economies by combining SO 2 

### , NO X 

### and particulate controls into a single control unit. Singly, the costs of the individual control would be hi gher for units below 100 MW than for a 100 MW unit,

30 

### See, for example, the Greenidge Multi-Pollutant Control Project, which was part of the U.S. Department of Energy, National Energy Technology Lab’s Power Plant Improvement Initiative. A joint effort of CONSOL Energy Inc. AES Greenidge LLC, and Babcock Power Environmental, Inc., information on the project can be found at www.netl.doe.gov/technologies/coalpower/cctc/PPII/b ibliography/demonstration/environmental/bib _greenidge.html

.

### 5-14 but when combined in the Multi-Pollutant Te chnologies (MPTs) their costs would be roughly equivalent to the cost of individual controls on a 100 MW unit. While MPTs are not explicitly represented in EPA Base Case v.4.10, single units in the 25-100 MW range that take on combinations of SO 2 

### and NO X 

### controls in a model run can be thought of as being retrofit with an MPT.

Illustrative scrubber, SCR, and SNCR costs for 25-100 MW coal units with a range heats rates can be found by referring to the 100 MW “Capital Costs ($/kW)” and “Fixed O&M” columns in Table 5-4 and Table 5-8. The Variable O&M cost component, which applies to units regardless of size, can be found in the fifth column in these tables.


# 5.3 Biomass Co-firing Under most climate policies currently being discussed, biomass is treated as “carbon neutral,” i.e., a zero contributor of CO 2 

### to the atmosphere. The reasoning is that the CO 2 

### emitted in the combustion of biomass will be reabsorbed via photosynthesis in plants grown to replace the biomass that was combusted. Consequently, if a power plant can co-fire biomass and thereby replace a portion of fossil fuel, it reduces its CO 2 

### emissions by approximately the same proportion, although combustion efficiency losses may so mewhat diminish the proportion of CO 2 

### reduction. Roughly speaking, by co-firing enough biomass to produce 10% of a coal plant’s power output, a co-fired plant can realize close to an effective 10% reduction in CO 2 

### emitted.

Biomass co-firing is provided as a fuel choice for all coal-fired power plants in EPA Base Case v.4.10. However, logistics and boiler engineering considerations place limits on the extent of biomass that can be fired. The logistic cons iderations arise because it is only economic to transport biomass a limited distance from where it is grown. In addition, the extent of storage that can be devoted at a power plant to this relatively low density fuel is another limiting factor. Boiler efficiency and other engineering considerations, la rgely due to the relatively higher moisture content and lower heat content of biomass compared to fossil fuel, also plays a role in limiting the level of co-firing.

In EPA Base Case v.4.10 the limit on biomass co-firing is expressed as the percentage of the facility level power output that is produced from biomass. Based on analysis by EPA’s power sector engineering staff, a maximum of 10% of the facility level power output (not to exceed 50 MW) can be fired by biomass. In EPA Base Case v.4.10 “facility level” is defined as the set of generating units which share the same ORIS code 31 

### in NEEDS v.4.10.

The capital and FOM costs associated with biomass co-firing are summarized in Table 5-10. Developed by EPA’s power sector engineering staff 32 

### , they are on the same cost basis as the

31 

### The ORIS plant locator code is a unique identif ying number (originally assigned by the Office of Regulatory Information Systems from which the ac ronym derived). The ORIS code is given to power plants by EIA and remains unchanged under ownership changes.

32 

### Among the studies consulted in developing these costs were: (a) Briggs, J. and J. M. Adams, Biomass Combustion Options for Steam Generation , Presented at Power-Gen 97, Dallas, TX, December 9 – 11, 1997. (b) Grusha, J and S. Woldehanna, K. McCarthy, and G. Heinz, Long Term Results from the First US Low NOx Conversion of a Tangential Lignite Fired Unit , presented at 24th International Technical Conference on Coal & Fuel Systems, Clearwater, FL., March 8 – 11, 1999. (c) EPRI, Biomass Cofiring: Field Test Results: Summary of Results of the Bailly and Seward Demonstrations , Palo Alto, CA, supported by U.S. Depar tment of Energy Division of Energy Efficiency and Renewable Energy, Wa shington D.C.; U.S. Department of Energy Division Federal Energy Technology Center, Pittsburgh PA; Northern Indiana Public Service Company, Merrillville, IN; and GPU Generation, Inc., Johnstown, PA: 1999. TR-113903. (d) Laux S., J. Grusha, and D. Tillman, Co-firing of Biomass and Opportunity Fuels in Low NOx

### 5-15 costs shown in Table 4-16 which resulted from EPA’s comparative analysis of electricity sector costs as described in Chapter 4.

Table 5-10 Biomass Cofiring for Coal Plants Size of Biomass Unit (MW) 5 10 15 20 25 30 35 40 45 50 Capital Cost (2007$/kW From Biomass) 488 411 371 345 327 312 300 290 282 275 Fixed O&M (2007$/kW-yr) 24.2 16.2 11.7 9.4 8.0 11.1 9.9 8.9 8.1 7.5


### The capital and FOM costs were implemented by ICF in EPA Base Case v.4.10 as a $/MMBtu biomass fuel cost adder. The procedure followed to implement this was first to represent the discrete costs shown in Table 5-10 as conti nuous exponential cost functions showing the FOM and capital costs for all size coal generating uni ts between 0 and 50 MW in size. Then, for every coal generating unit represented in EPA Base Case 4.10, the annual payment to capital for the biomass co-firing capability was derived by multiplying the total capital cost obtained from the capital cost exponential function by an 11% capital c harge rate. (This is the capital charge rate for environmental retrofits found in Table 8-1 and discussed in Chapter 8.) The resulting value was added to the annual FOM cost obtained from the FOM exponential function to obtain the total annual cost for the biomass co-firing for each generating unit.

Then, the annual amount of fuel (in MMBtus) required for each generating unit was derived by multiplying the size of a unit (in MW) by its heat ra te (in Btu/kWh) by its capacity factor (in percent) by 8,760 hours (i.e., the number of hours in a year). Dividing the resulting value by 1000 yielded the annual fuel required by the generating unit in MMB tus. Dividing this number into the previously calculated total annual cost for biomass co-firing resulted in the cost of biomass co-firing per MMBtu of biomass combusted. This was represented in IPM as a fuel cost adder incurred when a coal units co-fires biomass.


# 5.4 Mercury Control Technologies As previously noted, the mercury emission controls options and assumptions in EPA Base Case v.4.10 do not reflect mercury control updates that are currently under way at EPA in support of the Utility MACT initiative and do not make use of data collected under EPA’s 2010 Information Collection Request (ICR). The following discussion is based on EPA’s earlier work on mercury controls.

For any power plant, mercury emissions depend on t he mercury content of the fuel used, the combustion and physical characteristics of t he unit, and the emission control technologies deployed. In the absence of emission policies that would require the installation of mercury emission controls, mercury emission reductions below the mercury content of the fuel are strictlydue to characteristics of the combustion process and incidental removal resulting from nonmercury control technologies, i.e., the SO 2 

### , NO X 

### , and particulate controls. While the base case itself does not include any federal mercury control policies, it does include some State mercury reduction requirements. IPM has the capability to model mercury controls that might be installed in response to such State mercury control policies. These same controls come into play in model runs that analyze possible federal mercury policie s relative to the base case. The technology specifically designated for mercury control in such policy runs is Activated Carbon Injection (ACI) downstream of the combustion process.

Burners, PowerGen 2000 - Orlando, FL, www.fwc.com/publications/tech_papers/powgen/pdfs/clrw_bio.pdf

. Tillman, D. A., Cofiring Biomass for Greenhouse Gas Mitigation , presented at Power-Gen 99, New Orleans, LA, November 30 – December 1, 1999. (e) Tillman, D. A. and P. Hus, Blending Opportunity Fuels with Coal for Efficiency and Environmental Benefit , presented at 25th International Technical Conference on Coal Utilization & Fuel Systems, Clearwater, FL., March 6 – 9, 2000

### 5-16 The following discussion is divided into three parts. Sections 5.4.1 and 5.4.2 treat the two factors that figure into the unregulated mercury emissions resulting under EPA Base Case v.4.10. Section 5.4.1 discusses how mercury content of fuel is modeled in EPA Base Case v.4.10. Section 5.4.2 looks at the procedure used in t he base case to capture the mercury reductions resulting from different unit and (non-mercury) cont rol configurations. Section 5.4.3 explains the mercury emission control options that are available under EPA Base Case v.4.10. A major focus is on the cost and performance features of Activated Carbon Injection. Each section indicates the data sources and methodology used.

5.4.1 Mercury Content of Fuels Coal : The assumptions in EPA Base Case v.4.10 on the mercury content of coal (and the majority of emission modification factors discussed below in Section 5.4.2) are derived from EPA’s “Information Collection Request for Electric Utility Steam Generating Unit Mercury Emissions Information Collection Effort” (ICR). 33 

### A two-year effort initiated in 1998 and completed in 2000, the ICR had three main components: (1) identifying all coal-fired units owned and operated by publicly-owned utility companies, Federal power agencies, rural electric cooperatives, and investor-owned utility generating companies, (2) obtaining “accurate information on the amount of mercury contained in the as-fired coal used by eac h electric utility steam generating unit . . . with a capacity greater than 25 megawatts electric [MWe]), as well as accurate information on the total amount of coal burned by each such unit,” and (3) obtaining data by coal sampling and stack testing at selected units to characterize mercury reductions from representative unit configurations.

The ICR second component resulted in more than 40,000 data points indicating the coal type, sulfur content, mercury content and other characte ristics of coal burned at coal-fired utility units greater than 25 MW. To make this data usable in EPA Base Case v.4.10, these data points were first grouped by IPM coal types and IPM coal suppl y regions. (IPM coal types divide bituminous, sub-bituminous, and lignite coal into different gr ades based on sulfur content. See Table 5-11.) Next, a clustering analysis was performed on the data using the SAS statistical software package. Clustering analysis places objects into groups or cl usters, such that data in a given cluster tend to be similar to each other and dissimilar to data in other clusters. The clustering analysis involved two steps. First, the number of clusters of me rcury concentrations for each IPM coal type was determined based on the range of mercury and SO 2 

### concentrations for that coal type. Each coal type used one, two or three clusters. To the great est extent possible the total number of clusters for each coal type was limited to keep the model size and run time within feasible limits. Second, the clustering procedure was used to group each coal type within each IPM coal supply region into the previously determined number of clusters and show the resulting mercury concentration for each cluster. The average of each cluster is the mercury content of coal finally used in EPA Base Case v.4.10 for estimating mercury emissions. IPM input files retain the mapping between different coal type-supply region combinations and the mercury clusters. Table 5-11 below provides a summary by coal type of the number of clusters and their mercury concentrations.

33 

### Data from the ICR can be found at http://www.epa.gov/ttn/atw/combust/utiltox/mercury.html

.

### 5-17 Table 5-11 Mercury Clusters and Mercury Content of Coal by IPM Coal Types Mercury Emission Factors by Coal Sulfur Grades (lbs/TBtu) Coal Type by Sulfur Grade

Cluster #1 Cluster #2 Cluster #3 Low Sulfur Easter Bituminous (BA) 3.19 4.37 -- Low Sulfur Western Bituminous (BB) 1.82 4.86 -- Low Medium Sulfur Bituminous (BD) 5.38 8.94 21.67 Medium Sulfur Bituminous (BE) 19.53 8.42 -- High Sulfur Bituminous (BG) 7.10 20.04 14.31 High Sulfur Bituminous (BH) 7.38 13.93 34.71 Low Sulfur Subbituminous (SA) 4.24 5.61 -- Low Sulfur Subbituminous (SB) 6.44 -- -- Low Medium Sulfur Subbituminous (SD) 4.43 -- -- Low Medium Sulfur Lignite (LD) 7.51 12.00 -- Medium Sulfur Lignite (LE) 13.55 7.81 -- High Sulfur Lignite (LG) 14.88 -- --

Oil, natural gas, and waste fuels : The EPA Base Case v.4.10 also includes assumptions on the mercury content for oil, gas and waste fuels, which were based on data derived from previous EPA analysis of mercury emissions from power plants. 34 

### Table 5-12 provides a summary of the assumptions on the mercury content for oil, gas and waste fuels included in EPA Base Case v.4.10.

Table 5-12 Assumptions on Mercury Concentr ation in Non-Coal Fuel in EPA Base Case v.4.10 Fuel Type Mercury Concentration (lbs/TBtu) Oil 0.48 Natural Gas 0.00 1


### Petroleum Coke 23.18 Biomass 0.57 Municipal Solid Waste 71.85
Geothermal

Resource 2.97 - 3.7

Note:
1 

### The values appearing in this table are rounded to two decimal places. The zero value shown for natural gas is based on an EPA study that found a mercury content of 0.00014 lbs/TBtu. Values for geothermal resources represent a range.

5.4.2 Mercury Emission Modification Factors Emission Modification Factors (EMFs) represent the mercury reductions attributable to the specific burner type and configuration of SO 2 

### , NO X 

### , and particulate matter control devices at an electric generating unit. An EMF is the ratio of outlet mercury concentration to inlet mercury concentration, and depends on the unit's burner type, particulate control device, post-combustion NO X 

### control and SO 2 

### scrubber control. In other words, the mercury reduction achieved (relative to

34 

### “Analysis of Emission Reduction Options for t he Electric Power Industry,” Office of Air and Radiation, US EPA, March 1999.

### 5-18 the inlet) during combustion and flue-gas treatment process is (1-EMF). The EMF varies by the type of coal (bituminous, sub-bituminous, and li gnite) used during the combustion process.

Deriving EMFs involves obtaining mercury inlet data by coal sampling and mercury emission data by stack testing at a representation set of coal units. As noted above, EPA's EMFs were initially based on 1999 mercury ICR emission test data. More recent testing conducted by the EPA, DOE, and industry participants 35 

### has provided a better understanding of mercury emissions from electric generating units and mercury capture in pollution control devices. Overall the 1999 ICR data revealed higher levels of mercury capture for bituminous coal-fired plants than for subbitumionus and lignite coal-fired plants, and significant captur e of ionic Hg in wet-FGD scrubbers. Additional mercury testing indicates that for bituminous coals, SCR systems have the ability to convert elemental Hg into ionic Hg and thus allow easier capture in a downstream wet-FGD scrubber. This improved understanding of mercury capture with SCRs was incorporated in EPA Base Case v.4.10 mercury EMFs for unit configurations with SCR and wet scrubbers.

Table 5-13 below provides a summary of EMFs used in EPA Base Case v.4.10. Table 5-14 provides definitions of acronyms for existing controls that appear in Table 5-13. Table 5-15 provides a key to the burner type designations appearing in Table 5-13.

5.4.3 Mercury Control Capabilities EPA Base Case v.4.10 offers two options for meeting mercury reduction requirements: (1) combinations of SO 2 

### , NO X 

### , and particulate controls which deliver mercury reductions as a cobenefit and (2) Activated Carbon Injection (ACI), a retrofit option specifically designed for mercury control. These two options are discussed below.

35 

### For a detailed summary of emissions test dat a see Control of Emissions from Coal-Fired Electric Utility Boilers: An Update, EPA/Office of Research and Development, February 2005. This report can be found at www.epa.gov/ttnatw01/utility/hgwhitepaperfinal.pdf

.

### 5-19 Table 5-13 Mercury Emission Modificati on Factors Used in EPA Base Case v.4.10

Burner Type Particulate Control Post Combustion

Control – NO X Post Combustion

Control -

SO 2 Bituminous EMF Subbitumionus EMF Lignite EMF

Cyclone Cold Side ESP SNCR None 0.64 0.97 0.93 Cyclone Cold Side ESP SNCR Wet FGD 0.46 0.84 0.58 Cyclone Cold Side ESP SNCR Dry FGD 0.64 0.65 0.93 Cyclone Cold Side ESP SCR None 0.64 0.97 0.93 Cyclone Cold Side ESP SCR Wet FGD 0.1 0.84 0.58 Cyclone Cold Side ESP SCR Dry FGD 0.64 0.65 0.93 Cyclone Cold Side ESP None Wet FGD 0.46 0.84 0.58 Cyclone Cold Side ESP None Dry FGD 0.64 0.65 0.93 Cyclone Cold Side ESP None None 0.64 0.97 0.93 Cyclone Cold Side ESP + FF SNCR Wet FGD 0.1 0.27 0.58 Cyclone Cold Side ESP + FF SCR None 0.11 0.27 1 Cyclone Cold Side ESP + FF SCR Wet FGD 0.1 0.27 0.58 Cyclone Cold Side ESP + FF SCR Dry FGD 0.4 0.95 0.91 Cyclone Cold Side ESP + FF None Wet FGD 0.1 0.27 0.58 Cyclone Cold Side ESP + FF None Dry FGD 0.4 0.95 0.91 Cyclone Cold Side ESP + FF None None 0.11 0.27 1 Cyclone Cold Side ESP + FGC SNCR None 0.64 0.97 0.93 Cyclone Cold Side ESP + FGC SNCR Wet FGD 0.46 0.84 0.58 Cyclone Cold Side ESP + FGC SNCR Dry FGD 0.64 0.65 0.93 Cyclone Cold Side ESP + FGC SCR None 0.64 0.97 0.93 Cyclone Cold Side ESP + FGC SCR Wet FGD 0.1 0.84 0.58 Cyclone Cold Side ESP + FGC SCR Dry FGD 0.64 0.65 0.93 Cyclone Cold Side ESP + FGC None Wet FGD 0.46 0.84 0.58 Cyclone Cold Side ESP + FGC None Dry FGD 0.64 0.65 0.93 Cyclone Cold Side ESP + FGC None None 0.64 0.97 0.93 Cyclone Cold Side ESP + FGC + FF SCR None 0.11 0.27 1 Cyclone Cold Side ESP + FGC + FF SCR Wet FGD 0.1 0.27 0.58 Cyclone Cold Side ESP + FGC + FF SCR Dry FGD 0.4 0.95 0.91 Cyclone Cold Side ESP + FGC + FF None Wet FGD 0.1 0.27 0.58 Cyclone Cold Side ESP + FGC + FF None Dry FGD 0.4 0.95 0.91 Cyclone Cold Side ESP + FGC + FF None None 0.11 0.27 1 Cyclone Fabric Filter SNCR None 0.11 0.27 1 Cyclone Fabric Filter SNCR Wet FGD 0.03 0.27 0.58 Cyclone Fabric Filter SNCR Dry FGD 0.4 0.95 0.91 Cyclone Fabric Filter SCR None 0.11 0.27 1 Cyclone Fabric Filter SCR Wet FGD 0.1 0.27 0.58 Cyclone Fabric Filter SCR Dry FGD 0.4 0.95 0.91 Cyclone Fabric Filter None Wet FGD 0.1 0.27 0.58 Cyclone Fabric Filter None Dry FGD 0.4 0.95 0.91 Cyclone Fabric Filter None None 0.11 0.27 1 Cyclone Hot Side ESP SNCR None 0.9 1 1 Cyclone Hot Side ESP SNCR Wet FGD 0.58 0.6 1 Cyclone Hot Side ESP SNCR Dry FGD 0.9 1 1 Cyclone Hot Side ESP SCR None 0.9 1 1 Cyclone Hot Side ESP SCR Wet FGD 0.1 0.8 1 Cyclone Hot Side ESP SCR Dry FGD 0.9 1 1

### 5-20 Burner Type Particulate Control Post Combustion

Control – NO X Post Combustion

Control -

SO 2 Bituminous EMF Subbitumionus EMF Lignite EMF

Cyclone Hot Side ESP None Wet FGD 0.58 0.6 1 Cyclone Hot Side ESP None Dry FGD 0.9 1 1 Cyclone Hot Side ESP None None 0.9 1 1 Cyclone Hot Side ESP + FF None None 0.11 0.27 1 Cyclone Hot Side ESP + FGC SNCR None 0.9 1 1 Cyclone Hot Side ESP + FGC SNCR Wet FGD 0.58 0.6 1 Cyclone Hot Side ESP + FGC SNCR Dry FGD 0.9 1 1 Cyclone Hot Side ESP + FGC SCR None 0.9 1 1 Cyclone Hot Side ESP + FGC SCR Wet FGD 0.1 0.8 1 Cyclone Hot Side ESP + FGC SCR Dry FGD 0.9 1 1 Cyclone Hot Side ESP + FGC None Wet FGD 0.58 0.6 1 Cyclone Hot Side ESP + FGC None Dry FGD 0.9 1 1 Cyclone Hot Side ESP + FGC None None 0.9 1 1 Cyclone No Control SNCR None 1 1 1 Cyclone No Control SNCR Wet FGD 0.45 0.6 1 Cyclone No Control SNCR Dry FGD 1 1 1 Cyclone No Control SCR None 1 1 1 Cyclone No Control SCR Wet FGD 0.1 0.7 1 Cyclone No Control SCR Dry FGD 1 1 1 Cyclone No Control None Wet FGD 0.45 0.6 1 Cyclone No Control None Dry FGD 1 1 1 Cyclone No Control None None 1 1 1 Cyclone PM Scrubber None None 0.8 1 1

FBC Cold Side ESP SNCR None 0.65 0.65 0.62
FBC Cold Side ESP SNCR Wet FGD 0.65 0.65 0.62
FBC Cold Side ESP SCR Wet FGD 0.1 0.84 0.62
FBC Cold Side ESP None Wet FGD 0.65 0.65 0.62
FBC Cold Side ESP None Dry FGD 0.45 0.45 1
FBC Cold Side ESP None None 0.65 0.65 0.62
FBC Cold Side ESP + FF SNCR None 0.05 0.43 0.43
FBC Cold Side ESP + FF SNCR Dry FGD 0.05 0.43 0.43
FBC Cold Side ESP + FF None Dry FGD 0.05 0.43 0.43
FBC Cold Side ESP + FF None None 0.05 0.43 0.43
FBC Cold Side ESP + FGC SNCR None 0.65 0.65 0.62
FBC Cold Side ESP + FGC SNCR Wet FGD 0.65 0.65 0.62
FBC Cold Side ESP + FGC SCR Wet FGD 0.1 0.84 0.62
FBC Cold Side ESP + FGC None Wet FGD 0.65 0.65 0.62
FBC Cold Side ESP + FGC None Dry FGD 0.45 0.45 1
FBC Cold Side ESP + FGC None None 0.65 0.65 0.62
FBC Cold Side ESP + FGC + FF SNCR None 0.05 0.43 0.43
FBC Cold Side ESP + FGC + FF SNCR Dry FGD 0.05 0.43 0.43
FBC Cold Side ESP + FGC + FF None Dry FGD 0.05 0.43 0.43
FBC Cold Side ESP + FGC + FF None None 0.05 0.43 0.43
FBC Fabric Filter SNCR None 0.05 0.43 0.43
FBC Fabric Filter SNCR Wet FGD 0.05 0.43 0.43
FBC Fabric Filter SNCR Dry FGD 0.05 0.43 0.43
FBC Fabric Filter SCR None 0.05 0.43 0.43

### 5-21 Burner Type Particulate Control Post Combustion

Control – NO X Post Combustion

Control -

SO 2 Bituminous EMF Subbitumionus EMF Lignite EMF

FBC Fabric Filter SCR Wet FGD 0.05 0.27 0.43
FBC Fabric Filter SCR Dry FGD 0.05 0.43 0.43
FBC Fabric Filter None Wet FGD 0.1 0.43 0.43
FBC Fabric Filter None Dry FGD 0.05 0.43 0.43
FBC Fabric Filter None None 0.05 0.43 0.43
FBC Hot Side ESP SNCR None 1 1 1
FBC Hot Side ESP SNCR Dry FGD 0.45 0.45 1
FBC Hot Side ESP None Dry FGD 0.45 0.45 1
FBC Hot Side ESP None None 1 1 1
FBC Hot Side ESP + FGC SNCR None 1 1 1
FBC Hot Side ESP + FGC SNCR Dry FGD 0.45 0.45 1
FBC Hot Side ESP + FGC None Dry FGD 0.45 0.45 1
FBC Hot Side ESP + FGC None None 1 1 1
FBC No Control SNCR None 1 1 1
FBC No Control SNCR Wet FGD 1 1 1
FBC No Control SNCR Dry FGD 0.45 0.45 1
FBC No Control SCR None 1 1 1
FBC No Control SCR Wet FGD 0.1 0.7 1
FBC No Control SCR Dry FGD 0.45 0.45 1
FBC No Control None Wet FGD 1 1 1
FBC No Control None Dry FGD 0.45 0.45 1
FBC No Control None None 1 1 1
PC Cold Side ESP SNCR None 0.64 0.97 1
PC Cold Side ESP SNCR Wet FGD 0.34 0.65 0.56
PC Cold Side ESP SNCR Dry FGD 0.64 0.65 1
PC Cold Side ESP SCR None 0.64 0.97 1
PC Cold Side ESP SCR Wet FGD 0.1 0.84 0.56
PC Cold Side ESP SCR Dry FGD 0.64 0.65 1
PC Cold Side ESP None Wet FGD 0.34 0.84 0.56
PC Cold Side ESP None Dry FGD 0.64 0.65 1
PC Cold Side ESP None None 0.64 0.97 1
PC Cold Side ESP + FF SNCR None 0.2 0.75 1
PC Cold Side ESP + FF SNCR Wet FGD 0.1 0.3 0.56
PC Cold Side ESP + FF SNCR Dry FGD 0.05 0.75 1
PC Cold Side ESP + FF SCR None 0.2 0.75 1
PC Cold Side ESP + FF SCR Wet FGD 0.1 0.3 0.56
PC Cold Side ESP + FF SCR Dry FGD 0.05 0.75 1
PC Cold Side ESP + FF None Wet FGD 0.3 0.3 0.56
PC Cold Side ESP + FF None Dry FGD 0.05 0.75 1
PC Cold Side ESP + FF None None 0.2 0.75 1
PC Cold Side ESP + FGC SNCR None 0.64 0.97 1
PC Cold Side ESP + FGC SNCR Wet FGD 0.34 0.65 0.56
PC Cold Side ESP + FGC SNCR Dry FGD 0.64 0.65 1
PC Cold Side ESP + FGC SCR None 0.64 0.97 1
PC Cold Side ESP + FGC SCR Wet FGD 0.1 0.84 0.56
PC Cold Side ESP + FGC SCR Dry FGD 0.64 0.65 1
PC Cold Side ESP + FGC None Wet FGD 0.34 0.84 0.56

### 5-22 Burner Type Particulate Control Post Combustion

Control – NO X Post Combustion

Control -

SO 2 Bituminous EMF Subbitumionus EMF Lignite EMF

PC Cold Side ESP + FGC None Dry FGD 0.64 0.65 1
PC Cold Side ESP + FGC None None 0.64 0.97 1
PC Cold Side ESP + FGC + FF SNCR None 0.2 0.75 1
PC Cold Side ESP + FGC + FF SNCR Wet FGD 0.1 0.3 0.56
PC Cold Side ESP + FGC + FF SNCR Dry FGD 0.05 0.75 1
PC Cold Side ESP + FGC + FF SCR None 0.2 0.75 1
PC Cold Side ESP + FGC + FF SCR Wet FGD 0.1 0.3 0.56
PC Cold Side ESP + FGC + FF SCR Dry FGD 0.05 0.75 1
PC Cold Side ESP + FGC + FF None Wet FGD 0.3 0.3 0.56
PC Cold Side ESP + FGC + FF None Dry FGD 0.05 0.75 1
PC Cold Side ESP + FGC + FF None None 0.2 0.75 1
PC Fabric Filter SNCR None 0.11 0.27 1
PC Fabric Filter SNCR Wet FGD 0.03 0.27 0.56
PC Fabric Filter SNCR Dry FGD 0.05 0.75 1
PC Fabric Filter SCR None 0.11 0.27 1
PC Fabric Filter SCR Wet FGD 0.1 0.27 0.56
PC Fabric Filter SCR Dry FGD 0.05 0.75 1
PC Fabric Filter None Wet FGD 0.1 0.27 0.56
PC Fabric Filter None Dry FGD 0.05 0.75 1
PC Fabric Filter None None 0.11 0.27 1
PC Hot Side ESP SNCR None 0.9 0.9 1
PC Hot Side ESP SNCR Wet FGD 0.58 0.75 1
PC Hot Side ESP SNCR Dry FGD 0.6 0.85 1
PC Hot Side ESP SCR None 0.9 0.9 1
PC Hot Side ESP SCR Wet FGD 0.1 0.8 1
PC Hot Side ESP SCR Dry FGD 0.6 0.85 1
PC Hot Side ESP None Wet FGD 0.58 0.8 1
PC Hot Side ESP None Dry FGD 0.6 0.85 1
PC Hot Side ESP None None 0.9 0.94 1
PC Hot Side ESP + FF SNCR None 0.11 0.27 1
PC Hot Side ESP + FF SNCR Wet FGD 0.03 0.27 0.56
PC Hot Side ESP + FF SNCR Dry FGD 0.05 0.75 1
PC Hot Side ESP + FF SCR None 0.11 0.27 1
PC Hot Side ESP + FF SCR Wet FGD 0.1 0.15 0.56
PC Hot Side ESP + FF SCR Dry FGD 0.05 0.75 1
PC Hot Side ESP + FF None Wet FGD 0.03 0.27 0.56
PC Hot Side ESP + FF None Dry FGD 0.05 0.75 1
PC Hot Side ESP + FF None None 0.11 0.27 1
PC Hot Side ESP + FGC SNCR None 0.9 0.9 1
PC Hot Side ESP + FGC SNCR Wet FGD 0.58 0.75 1
PC Hot Side ESP + FGC SNCR Dry FGD 0.6 0.85 1
PC Hot Side ESP + FGC SCR None 0.9 0.9 1
PC Hot Side ESP + FGC SCR Wet FGD 0.1 0.8 1
PC Hot Side ESP + FGC SCR Dry FGD 0.6 0.85 1
PC Hot Side ESP + FGC None Wet FGD 0.58 0.8 1
PC Hot Side ESP + FGC None Dry FGD 0.6 0.85 1
PC Hot Side ESP + FGC None None 0.9 0.94 1

### 5-23 Burner Type Particulate Control Post Combustion

Control – NO X Post Combustion

Control -

SO 2 Bituminous EMF Subbitumionus EMF Lignite EMF

PC Hot Side ESP + FGC + FF SNCR None 0.11 0.27 1
PC Hot Side ESP + FGC + FF SNCR Wet FGD 0.03 0.27 0.56
PC Hot Side ESP + FGC + FF SNCR Dry FGD 0.05 0.75 1
PC Hot Side ESP + FGC + FF SCR None 0.11 0.27 1
PC Hot Side ESP + FGC + FF SCR Wet FGD 0.1 0.15 0.56
PC Hot Side ESP + FGC + FF SCR Dry FGD 0.05 0.75 1
PC Hot Side ESP + FGC + FF None Wet FGD 0.03 0.27 0.56
PC Hot Side ESP + FGC + FF None Dry FGD 0.05 0.75 1
PC Hot Side ESP + FGC + FF None None 0.11 0.27 1
PC No Control SNCR None 1 1 1
PC No Control SNCR Wet FGD 0.58 0.7 1
PC No Control SNCR Dry FGD 0.6 0.85 1
PC No Control SCR None 1 1 1
PC No Control SCR Wet FGD 0.1 0.7 1
PC No Control SCR Dry FGD 0.6 0.85 1
PC No Control None Wet FGD 0.58 0.7 1
PC No Control None Dry FGD 0.6 0.85 1
PC No Control None None 1 1 1
PC PM Scrubber SNCR None 0.9 0.91 1
PC PM Scrubber SCR None 0.9 1 1
PC PM Scrubber None None 0.9 0.91 1
Stoker Cold Side ESP SNCR None 0.65 0.97 1
Stoker Cold Side ESP SNCR Wet FGD 0.34 0.73 0.56
Stoker Cold Side ESP SNCR Dry FGD 0.65 0.65 1
Stoker Cold Side ESP SCR None 0.65 0.97 1
Stoker Cold Side ESP SCR Wet FGD 0.1 0.84 0.56
Stoker Cold Side ESP SCR Dry FGD 0.65 0.65 1
Stoker Cold Side ESP None Wet FGD 0.34 0.84 0.56
Stoker Cold Side ESP None Dry FGD 0.65 0.65 1
Stoker Cold Side ESP None None 0.65 0.97 1
Stoker Cold Side ESP + FGC SNCR None 0.65 0.97 1
Stoker Cold Side ESP + FGC SNCR Wet FGD 0.34 0.73 0.56
Stoker Cold Side ESP + FGC SNCR Dry FGD 0.65 0.65 1
Stoker Cold Side ESP + FGC SCR None 0.65 0.97 1
Stoker Cold Side ESP + FGC SCR Wet FGD 0.1 0.84 0.56
Stoker Cold Side ESP + FGC SCR Dry FGD 0.65 0.65 1
Stoker Cold Side ESP + FGC None Wet FGD 0.34 0.84 0.56
Stoker Cold Side ESP + FGC None Dry FGD 0.65 0.65 1
Stoker Cold Side ESP + FGC None None 0.65 0.97 1
Stoker Fabric Filter SNCR None 0.11 0.27 1
Stoker Fabric Filter SNCR Wet FGD 0.03 0.27 0.56
Stoker Fabric Filter SNCR Dry FGD 0.1 0.75 1
Stoker Fabric Filter SCR None 0.11 0.27 1
Stoker Fabric Filter SCR Wet FGD 0.1 0.27 0.56
Stoker Fabric Filter SCR Dry FGD 0.1 0.75 1
Stoker Fabric Filter None Wet FGD 0.1 0.27 0.56
Stoker Fabric Filter None Dry FGD 0.1 0.75 1

### 5-24 Burner Type Particulate Control Post Combustion

Control – NO X Post Combustion

Control -

SO 2 Bituminous EMF Subbitumionus EMF Lignite EMF

Stoker Fabric Filter None None 0.11 0.27 1
Stoker Hot Side ESP SNCR None 1 1 1
Stoker Hot Side ESP SNCR Wet FGD 0.58 1 1
Stoker Hot Side ESP SNCR Dry FGD 1 1 1
Stoker Hot Side ESP SCR None 1 1 1
Stoker Hot Side ESP SCR Wet FGD 0.1 0.8 1
Stoker Hot Side ESP SCR Dry FGD 1 1 1
Stoker Hot Side ESP None Wet FGD 0.58 1 1
Stoker Hot Side ESP None Dry FGD 1 1 1
Stoker Hot Side ESP None None 1 1 1
Stoker Hot Side ESP + FGC SNCR None 1 1 1
Stoker Hot Side ESP + FGC SNCR Wet FGD 0.58 1 1
Stoker Hot Side ESP + FGC SNCR Dry FGD 1 1 1
Stoker Hot Side ESP + FGC SCR None 1 1 1
Stoker Hot Side ESP + FGC SCR Wet FGD 0.1 0.8 1
Stoker Hot Side ESP + FGC SCR Dry FGD 1 1 1
Stoker Hot Side ESP + FGC None Wet FGD 0.58 1 1
Stoker Hot Side ESP + FGC None Dry FGD 1 1 1
Stoker Hot Side ESP + FGC None None 1 1 1
Stoker No Control SNCR None 1 1 1
Stoker No Control SNCR Wet FGD 0.58 1 1
Stoker No Control SNCR Dry FGD 1 1 1
Stoker No Control SCR None 1 1 1
Stoker No Control SCR Wet FGD 0.1 0.7 1
Stoker No Control SCR Dry FGD 1 1 1
Stoker No Control None Wet FGD 0.58 1 1
Stoker No Control None Dry FGD 1 1 1
Stoker No Control None None 1 1 1
Stoker PM Scrubber None None 1 1 1
Other Cold Side ESP SNCR None 0.64 0.97 1
Other Cold Side ESP SNCR Wet FGD 0.34 0.73 0.56
Other Cold Side ESP SNCR Dry FGD 0.64 0.65 1
Other Cold Side ESP SCR None 0.64 0.97 1
Other Cold Side ESP SCR Wet FGD 0.1 0.84 0.56
Other Cold Side ESP SCR Dry FGD 0.64 0.65 1
Other Cold Side ESP None Wet FGD 0.34 0.84 0.56
Other Cold Side ESP None Dry FGD 0.64 0.65 1
Other Cold Side ESP None None 0.64 0.97 1
Other Cold Side ESP + FGC SNCR None 0.64 0.97 1
Other Cold Side ESP + FGC SNCR Wet FGD 0.34 0.73 0.56
Other Cold Side ESP + FGC SNCR Dry FGD 0.64 0.65 1
Other Cold Side ESP + FGC SCR None 0.64 0.97 1
Other Cold Side ESP + FGC SCR Wet FGD 0.1 0.84 0.56
Other Cold Side ESP + FGC SCR Dry FGD 0.64 0.65 1
Other Cold Side ESP + FGC None Wet FGD 0.34 0.84 0.56
Other Cold Side ESP + FGC None Dry FGD 0.64 0.65 1
Other Cold Side ESP + FGC None None 0.64 0.97 1

### 5-25 Burner Type Particulate Control Post Combustion

Control – NO X Post Combustion

Control -

SO 2 Bituminous EMF Subbitumionus EMF Lignite EMF

Other Fabric Filter SNCR None 0.45 0.75 1
Other Fabric Filter SNCR Wet FGD 0.03 0.27 0.56
Other Fabric Filter SNCR Dry FGD 0.4 0.75 1
Other Fabric Filter SCR None 0.11 0.27 1
Other Fabric Filter SCR Wet FGD 0.1 0.27 0.56
Other Fabric Filter SCR Dry FGD 0.4 0.75 1
Other Fabric Filter None Wet FGD 0.1 0.27 0.56
Other Fabric Filter None Dry FGD 0.4 0.75 1
Other Fabric Filter None None 0.11 0.27 1
Other Hot Side ESP SNCR None 1 1 1
Other Hot Side ESP SNCR Wet FGD 0.58 1 1
Other Hot Side ESP SNCR Dry FGD 1 1 1
Other Hot Side ESP SCR None 1 1 1
Other Hot Side ESP SCR Wet FGD 0.1 0.8 1
Other Hot Side ESP SCR Dry FGD 1 1 1
Other Hot Side ESP None Wet FGD 0.58 1 1
Other Hot Side ESP None Dry FGD 1 1 1
Other Hot Side ESP None None 1 1 1
Other Hot Side ESP + FF None None 0.11 0.27 1
Other Hot Side ESP + FGC SNCR None 1 1 1
Other Hot Side ESP + FGC SNCR Wet FGD 0.58 1 1
Other Hot Side ESP + FGC SNCR Dry FGD 1 1 1
Other Hot Side ESP + FGC SCR None 1 1 1
Other Hot Side ESP + FGC SCR Wet FGD 0.1 0.8 1
Other Hot Side ESP + FGC SCR Dry FGD 1 1 1
Other Hot Side ESP + FGC None Wet FGD 0.58 1 1
Other Hot Side ESP + FGC None Dry FGD 1 1 1
Other Hot Side ESP + FGC None None 1 1 1
Other Hot Side ESP + FGC + FF None None 0.11 0.27 1
Other No Control SNCR None 1 1 1
Other No Control SNCR Wet FGD 0.58 0.7 1
Other No Control SNCR Dry FGD 1 1 1
Other No Control SCR None 1 1 1
Other No Control SCR Wet FGD 0.1 0.7 1
Other No Control SCR Dry FGD 1 1 1
Other No Control None Wet FGD 0.58 0.7 1
Other No Control None Dry FGD 1 1 1
Other No Control None None 1 1 1
Other PM Scrubber None None 0.9 0.91 1

### 5-26 Table 5-14 Definition of Acronyms for Existing Controls Acronym Description ESP Electro Static Precipitator - Cold Side HESP Electro Static Precipitator - Hot Side ESP/O Electro Static Precipitator - Other

FF Fabric Filter FGD Flue Gas Desulfurization - Wet DS Flue Gas Desulfurization - Dry SCR Selective Catalytic Reduction PMSCRUB Particulate Matter Scrubber

Table 5-15 Key to Burner Type Designations in Table 5-13 “PC” refers to conventional pulverized coal boile rs. Typical configurations include wall-fired and tangentially fired boilers (also called T-fired boilers). In wall-fired boilers the burner’s coal and air nozzles are mounted on a single wall or opposing walls. In tangentially fired boilers the burner’s coal and air nozzles are mounted in each corner of the boiler.

“Cyclone” refers to cyclone boilers where air and crushed coal are injected tangentially into the boiler through a “cyclone burner” and “cyclone barrel” which create a swirling motion allowing smaller coal particles to be burned in suspension and larger coal particles to be captured on the cyclone barrel wall where they are burned in molten slag.

“Stoker” refers to stoker boilers where lump coal is fed continuously onto a moving grate or chain which moves the coal into the combustion zone in which air is drawn through the grate and ignition takes place. The carbon gradually burns off, leaving ash which drops off at the end into a receptacle, from which it is removed for disposal.

“FBC" refers to “fluidized bed combustion” where solid fuels are suspended on upward-blowing jets of air, resulting in a turbulent mixing of gas and solids and a tumbling action which provides especially effective chemical reactions and heat transfer during the combustion process.

“Other" refers to miscellaneous burner types including cell burners and arch- , roof- , and vertically-fired burner configurations

.

### 5-27 Mercury Control through SO 2 

### and NO X 

### Retrofits In EPA Base Case v.4.10, units that install SO 2 

### , NO X 

### , and particulate controls, reduce mercury emissions as a byproduct of these retrofits. Section 5.4.2 described how EMFs are used in the base case to capture the unregulated mercury emissions depending on the rank of coal burned, the generating unit’s combustion characteristi cs, and the specific configuration of SO 2 

### , NO X 

### , and particulate controls (i.e., hot and cold-side electrostatic precipitators (ESPs), fabric filters (also called “baghouses”) and particulate matter (PM) scrubbers). These same EMFs would be available in mercury policy runs to characterize the mercury reductions that can be achieved by retrofitting a unit with SCR, SNCR, SO 2 

### scrubbers and particulate controls. The absence of a federal mercury emission reduction policy means t hat these controls appear in the base case in response to SO 2 

### , NO X 

### , or particulate limits or state-level mercury emission requirements. However, in future model runs where mercury limits are present these same SO 2 

### and NO X 

### controls could be deliberately installed for mercury control if they provide the least cost option for meeting mercury policy limits.

Activated Carbon Injection (ACI) The technology specifically designated for mercur y control is Activated Carbon Injection (ACI) downstream of the combustion process in coal fired units. A comprehensive ACI update, which will incorporate the latest field experience through 2010, is being prepared by Sargent and Lundy (the same engineering firm that developed the SO 2 

### and NO X 

### control assumptions used in EPA Base Case v.4.10). It will be incorporated in a future EPA base case. The ACI assumptions in the current base case release are the result of a 2007 internal EPA engineering study.

Based on this study, it is assume that 90% removal from the level of mercury in the coal is achievable with the application of one of three al ternative ACI configurations: Standard Powered Activated Carbon (SPAC), Modified Powered Activated Carbon (MPAC), or SPAC in combination with a fabric filter. The MPAC option exploits t he discovery that by converting elemental mercury to oxidized mercury, halogens (like chlorine, i odine, and bromine) can make activated carbon more effective in capturing the mercury at the high temperatures found in industrial processes like power generation. In the MPAC system, a small amount of bromine is chemically bonded to the powdered carbon which is then injected into the flue gas stream either upstream of both the particulate control device (ESP or fabric filter) and the air pre-heater (APH), between the APH and the particulate control device, or downstream of both the pre-existing APH and particulate control devices but ahead of a new dedicated pulsed-jet fabric filter. (The latter is known as the TOXECON TM 

### approach, an air pollution control process patented by EPRI.)

Table 5-16 presents the capital, FOM, and VOM costs as well as the capacity and heat rate penalty for the five Hg emission control technologies included in EPA Base Case v.4.10 for an illustrative set of generating units with a representative range of capacities.5-28Table 5-16 Illustrative Activated Carbon Injection Costs (2007$)for Representative Sizes under the Assumptions in EPA Base Casev.4.10Capacity (MW)100300500700Control TypeCapacityPenalty(%)HeatRatePenalty(%)CapitalCost($/kW)FixedO&M($/kWyr)VariableO&M cost(mills/kWh)CapitalCost($/kW)FixedO&M($/kW-yr)VariableO&M cost(mills/kWh)CapitalCost($/kW)FixedO&M($/kW-yr)VariableO&M cost(mills/kWh)CapitalCost($/kW)FixedO&M($/kW-yr)VariableO&M cost(mills/kWh)MPAC_BaghouseMinimum Cutoff:≥25 MWMaximum Cutoff: NoneAssuming BituminousCoal-0.430.4330.10.1620.050.1720.040.1720.030.16MPAC_CESPMinimum Cutoff:≥25 MWMaximum Cutoff: NoneAssuming BituminousCoal-0.430.4380.10.5760.10.6150.10.6150.10.59SPAC_BaghouseMinimum Cutoff:≥25 MWMaximum Cutoff: NoneAssuming BituminousCoal-0.430.4350.10.2240.10.2330.10.2330.10.23SPAC_ESPMinimum Cutoff:≥25 MWMaximum Cutoff: NoneAssuming BituminousCoal-0.430.43270.52.29210.32.46180.32.44170.32.39SPAC_ESP+ToxeconMinimum Cutoff:≥25 MWMaximum Cutoff: NoneAssuming BituminousCoal-0.430.432694.32.442022.52.611762.12.591612.02.54

### 5-29 The applicable ACI option depends on the coal type burned, its SO 2 

### content, the boiler and particulate control type and, in some instances, consideration of whether an SO 2 

### scrubber (FGD) system or SCR NO x 

### post-combustion control are present. Table 5-17 shows the ACI assignment scheme used in EPA Base Case v.4.10 to achieve 90% mercury removal.

Table 5-17 Assignment Scheme for Mercury Emissions Control Using Activated Carbon Injection (ACI) in EPA Base Case v.4.10 Applicability of Activated Carbon Injection

Coal Type SO 2 

### in Coal (lb/MMBtu) Boiler Type Particulate Control Type FGD System SCR System Toxecon Required? ACI Type With 90% Hg

Reduction Bit/Sub-bit/ Lig < 1.6 Non-CFB CS-ESP or BH (no FGC) -- No No MPAC
Bit/Sub-bit/ Lig -- Non-CFB CS-ESP or BH (no FGC) LSD -- No MPAC
Bit/Subbit/Lig -- CFB CS-ESP or BH (no FGC) -- -- No MPAC

Bit < 1.6 Non-CFB CS-ESP Non-LSD Yes No SPAC Bit ≥ 1.6 Non-CFB CS-ESP or BH -- -- No SPAC Sub-bit/Lig ≥ 1.6 Non-CFB CS-ESP -- -- Yes SPAC Sub-bit/Lig ≥ 1.6 Non-CFB BH -- -- No SPAC Bit/Sub-bit/ Lig -- Non-CFB HESP -- -- Yes SPAC
Bit/Sub-bit/ Lig -- -- HESP or CSESP (with FGC) -- -- Yes SPAC
Bit/Sub-bit/ Lig < 1.6 Non-CFB BH No Yes No MPAC
Bit/Sub-bit/ Lig < 1.6 Non-CFB CS-ESP (no FGC) No Yes No MPAC
Bit/Sub-bit/ Lig -- -- No Control -- -- Yes SPAC
Bit/Sub-bit/ Lig < 1.6 -- BH Non-LSD Yes No SPAC

Sub-bit/ Lig < 1.6 -- CS-ESP (no FGC) Non-LSD Yes Yes SPAC
Bit/Subbit/Lig -- -- Cyclone -- -- Yes SPAC

Notes: Legends: ACI Activated carbon injection If the existing equipment provides 90% Hg removal, no ACI system is required.
BH Baghouse Bit Bituminous coal "--" means that the categor y type has no effect on the ACI application.
CFB Circulating fluidized-bed boiler

CS-ESP Cold side electrostatic precipitator FGC Flue gas conditioning HESP Hot electrostatic precipitator

Lig Lignite

MPAC Modified powdered activated carbon
SPAC Standard powdered activated carbon Sub-bit Subbituminous coal

### Appendix 5-1.1 

# Appendix 5-1 Example Cost Ca lculation Worksheets for SO 2



# Control Technologies in EPA Base Case v.4.10

### Appendix 5-1.2

### Appendix 5-1.3

### Appendix 5-1.4

### Appendix 5-2.1 

# Appendix 5-2 Example Cost Ca lculation Worksheets for NO x



# PostCombustion Control Technologies in EPA Base Case v.4.10

### Appendix 5-2.2

### Appendix 5-2.3

### Appendix 5-2.4