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 

(SO2) and nitrogen oxides (NOX) 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) control27. Capture and storage options for carbon dioxide (CO2) 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, regional, and state emission limits. It is important 

to note that, besides the emission control options 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 

SO2 Control 

Technology Options 

NOX Control 

Technology Options 

Hg Control 

Technology Options 

CO2 Control 

Technology Options 

Limestone Forced 

Oxidation (LSFO) 

Scrubber 

Selective Catalytic 

Reduction (SCR) 

System 

Standard Activated 

Carbon Injection (SPACACI) System 

CO2 Capture and 

Sequestration 

Lime Spray Dryer 

(LSD) Scrubber 

Selective NonCatalytic Reduction 

(SNCR) System 

Modified Activated 

Carbon Injection 

(MPAC-ACI) System 

 

 Combustion Controls 

SO2 and NOX Control 

Technology Removal 

Cobenefits 

 

5.1 Sulfur Dioxide Control Technologies 

Two commercially available Flue Gas Desulfurization (FGD) technology options for removing the 

SO2 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 SO2 content exceeds 

3lb SO2/MMBtu, so this technology is provided only to plants which have the option to burn coals 

with sulfur content no greater than 3 lbs SO2/MMBtu. In EPA Base Casev.4.10 when a unit 

retrofits with an LSD SO2 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 SO2 emission control technologies are available to 

existing "unscrubbed" units. They are also available 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 

 

27The 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 are selected to be retrofitted by the model with 

scrubbers are given the maximum removal efficiencies 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 SO2 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 SO2/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% for 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 SO2 Controls Costs 

The Sargent and Lundy update of SO2 and NOx 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 SO2 and NOx 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 preparation, 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 modules 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 indicated in Table 5-3. The major variables 

affecting capital cost are unit size and the SO2 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 different coals have different typical heating values. 

Table 5-3 Capital Cost Modules and Their Governing Variables for SO2 and NOx Emission 

Controls 

Module 

Retrofit 

Difficulty 

(1 = 

average) 

Coal Rank 

Factor 

(Bit = 1, 

PRB = 1.05, 

Lignite = 1.07) 

Heat Rate

(Btu/kWh) 

SO2 Rate 

(lb/MMBtu) 

NOx Rate 

(lb/MMBtu)5

Unit 

Size 

(MW) 

SO2 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 

Plant1 X X X X 

NOx Emission Controls – SCR and SNCR 

SCR/SNCR 

Island2 X X X X3

 X 

Reagent 

Preparation3 X 

Air Heater 

Modification4 X X X X X 

Balance of 

Plant5

 – SCR X X X X 

Balance of 

Plant1

 – 

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, auxiliary 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, blowers, distributed control system (DCS), and reagent 

system. 

3

Only applies to SCR. 

4

On generating units that burn bituminous coal whose SO2 and content exceeds 3 lbs/MMBtu, air 

heater modifications used to control SO3 are needed in conjunction with the operation of SCR and 

SNCR. 

5

For SCR, the NOx rate is frequently expressed through the calculated NOx 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 engineering 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 proportional 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 control (often called the “parasitic load”). For a 

given coal rank and a pre-specified SO2 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 

SO2/MMBtu) of the coal (also referred to as the SO2 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 rate28. 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 previous 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 SO2 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: 

1 100

100

Capacity Penalty 1

1 Heat Rate Penalty ×

⎟

⎟

⎟

⎟

⎠

⎞

⎜

⎜

⎜

⎜

⎝

⎛

−

⎟

⎠

⎞ ⎜

⎝

⎛ −

=
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 unit 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 SO2 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. 
5-6 

Table 5-4 Illustrative Scrubber Costs (2007$) for Representative Sizes and Heat Rates under the Assumptions in E

Capacity (MW) 

100 300 500 700 

Scrubber Type Heat Rate (Btu/kWh) Capacity Penalty (%) Heat Rate Penalty (%) Variable O&M (mills/kWh) Capital Cost 

($/kW) 

Fixed 

O&M 

($/kW-yr)

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kW-yr) 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kW-yr)

Capital 

Cost 

($/kW) 

Fixe

($/k

LSFO Minimum Cutoff: ≥ 25 MW 

9,000 -1.5 1.53 1.66 747 22.5 547 10.5 473 7.8 430 7

Maximum Cutoff: None 10,000 -1.67 1.7 1.84 783 22.8 573 10.8 496 8.0 451 7Assuming 3 lb/MMBtu SO2Content Bituminous Coal 

11,000 -1.84 1.87 2.03 817 23.2 598 11.0 517 8.2 470 7

LSD Minimum Cutoff: ≥ 25 MW 

9,000 -1.18 1.2 2.13 641 16.4 469 8.1 406 6.1 385 5

Maximum Cutoff: None 10,000 -1.32 1.33 2.36 670 16.7 491 8.3 424 6.3 403 5Assuming 2 lb/MMBtu SO2Content Bituminous Coal 

11,000 -1.45 1.47 2.60 698 17.0 511 8.5 442 6.5 420 5
5-7 

5.2 Nitrogen Oxides Control Technology 

The EPA Base Case v.4.10 includes two categories of NOx reduction technologies: combustion 

and post-combustion controls. Combustion controls reduce NOx 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 NOx emissions 

from the flue gas. All the specific combustion 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 controls already in place and allow appropriate 

additional combustion controls to be exogenously applied to generating units based on the NOx

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

Boiler Type Technology Capital

($/kW) 

Fixed 

O&M 

($/kWyr) 

Variable O&M

(mills/kWh) 

Low NOx Burner without Overfire Air 

(LNB without OFA) 45 0.3 0.07 Dry Bottom WallFired Low NOx Burner with Overfire Air 

(LNB with OFA) 61 0.4 0.09 

Low NOx Coal-and-Air Nozzles with 

Close-Coupled Overfire Air (LNC1) 24 0.2 0.00 

Low NOx Coal-and-Air Nozzles with 

Separated Overfire Air (LNC2) Tangentially- 33 0.2 0.03 

Fired Low NOx Coal-and-Air Nozzles with 

Close-Coupled and Separated 

Overfire Air (LNC3) 

38 0.3 0.03 

Vertically-Fired NOx 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 value 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 NOx Controls in EPA Base Case v.4.10 

Boiler Type Existing NOx

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 -- NOx 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. NOx reduction in an SCR 

system takes place by injecting ammonia (NH3) vapor into the flue gas stream where the NOx is 

reduced to nitrogen (N2) and water H2O 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 NOx in the gas 

stream reducing it to nitrogen gas and water vapor. Due to the presence of a catalyst, SCR can 

achieve greater NOx 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 NOx post-combustion control technology and provides a cross reference to information on 

cost assumptions. 

Table 5-7 Summary of Retrofit NOx 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 

NOx/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 SO2 control costs, Sargent and Lundy employed an engineering build-up of 

the capital, fixed and variable operating and maintenance components of cost to update postcombustion NOx control costs. This section describes the approach used for SCR. The next 

section treats SNCR. Detailed example cost calculation spreadsheets for both technologies can 

be found in Appendix 5-2. 

For cost calculation purposes the Sargent and Lundy methodology calculates plant specific NOx

removal efficiencies, i.e., the percent difference between the uncontrolled NOx rate29 for a model 

plant and the cost calculation floor NOx 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 NOx rate of 0.1667 

lb/MMBtu, and a cost calculation floor NOx 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 NOx 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, piping, and auxiliary power modification). Air preheater modification cost only applies for plants that burn bituminous coal whose SO2 content is 3 

lbs/MMBtu or greater, where SO3 control is necessary. Otherwise, there is no air pre-heat cost. 

For each of the four 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. All four capital cost 

modules, except reagent preparation, are functions of retrofit difficulty, coal rank, heat rate, and 

unit size. NOx rate (expressed via the NOx 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 SO2 rate becomes a factor in SCR cost for plants that 

combust bituminous coal with 3 lbs SO2/MMBtu or greater, where air pre-heater modifications are 

needed for SO3 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 NOX rate for a model plant in EPA Base Case v.4.10 is the 

capacity weighted average of the Mode 1 NOX rates of the generating units comprising the model 

plant. The meaning of “Mode 1 NOX rate” is discussed in section 3.9.2 and Appendix 3-1 (“NOX

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. NOx rates and heat 

rates are key determinates of reagent and steam costs, while NOx 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 SO2 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 NOx removal efficiencies. The illustrations include and identify plants that do and 

do not burn bituminous coal with 3 lbs SO2/MMBtu or greater. 
5-11 

Table 5-8 Illustrative Post Combustion NOX Controls for Coal Plants Costs (2007$) for Representative Sizes and H

Assu Assumptions in EPA Base Case v.4.10 

Capacity (MW) 

100 300 500 700 

Control Type Heat Rate (Btu/kWh) Capacity Penalty (%) Heat Rate Penalty (%) Variable O&M (mills/kWh) Capital Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Capital 

Cost 

($/kW) 

F

(

SCR Minimum Cutoff: ≥ 25 MW 

9,000 -0.54 0.54 1.15 221 2.5 177 0.8 163 0.7 155 

Maximum Cutoff: None Assuming Bituminous Coal 10,000 -0.56 0.56 1.24 240 2.5 193 0.8 178 0.7 169 NOx rate: 0.5 lb/MMBtu SO2 rate: 2.0 lb/MMBtu 

11,000 -0.58 0.59 1.33 258 2.5 209 0.8 193 0.7 184 

SNCR - Non-FBC Minimum Cutoff: ≥ 25 MW 

9,000 0.88 45 1 

Maximum Cutoff: None Assuming Bituminous Coal 

10,000 0.98 47 1 

NOx rate: 0.5 lb/MMBtu SO2 rate: 2.0 lb/MMBtu 

11,000 

-0.05 0.05 

1.08 48 1 

Size Not Modeled 

SNCR - Fluidized Bed Minimum Cutoff: ≥ 25 MW 

9,000 0.88 34 0.9 18 0.4 14 0.2 11 

Maximum Cutoff: None Assuming Bituminous Coal 10,000 0.98 35 0.9 19 0.4 14 0.2 12 NOx rate: 0.5 lb/MMBtu SO2 rate: 2.0 lb/MMBtu 11,000 

-0.05 0.05 

1.08 36 0.9 19 0.4 14 0.2 12 

Note:If a coal plant burns bituminous coal with a SO2 content above 3.0 lb/MMBtu then the capital costs will increase due to the required air preheater modificaMW coal boiler with an SCR burning bituminous coal at a heat rate of 11,000 Btu/kWh and an SO2 rate of 4.0 lb/MMBtu will have a capital cost of 296 $/kWcapital costs from an identical boiler burning coal with an SO2 rate 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 section 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. The 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 NOX 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 

SCR1 75 1.08 0.12 80% 

Notes:

The “Coefficients” in the table above are multiplied 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 NOX 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 NOX removal efficiency of 25% is 

assumed. However, the capital, fixed and variable operating and maintenance costs of SNCR on 

circulating fluidized bed (CFB) units 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 modules: 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 modification). For CFB units, the SNCR and balance of 

plan module costs are 75% of what they are on other 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 SO2 content is 3 lbs/MMBtu or greater, where SO3 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 SO2 rate impacts the air pre-heater modification module. NOX rate 
5-13 

(expressed via the NOX 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 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. 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 SO2 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 SO2 and NOx 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 SO2 and NOx 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 SO2, NOX and particulate controls into a single control unit. Singly, 

the costs of the individual control would be higher 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/bibliography/demonstration/environmental/bib

_greenidge.html. 
5-14 

but when combined in the Multi-Pollutant Technologies (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 SO2 and NOX 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 CO2 to the atmosphere. The reasoning is that the CO2 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 CO2 emissions by approximately the same proportion, 

although combustion efficiency losses may somewhat diminish the proportion of CO2 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 CO2 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 considerations 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, largely 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 code31 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 staff32, they are on the same cost basis as the 

 

31 The ORIS plant locator code is a unique identifying number (originally assigned by the Office of 

Regulatory Information Systems from which the acronym 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. Department of Energy Division of Energy 

Efficiency and Renewable Energy, Washington 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 continuous exponential cost functions showing the FOM 

and capital costs for all size coal generating units 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 charge 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 rate (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 MMBtus. 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 the mercury content of the fuel used, the 

combustion and physical characteristics of the 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 strictly 

due to characteristics of the combustion process and incidental removal resulting from nonmercury control technologies, i.e., the SO2, NOX, 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 policies 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 the base case to capture the mercury reductions 

resulting from different unit and (non-mercury) control 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 each 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 characteristics 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 supply regions. (IPM coal types divide bituminous, 

sub-bituminous, and lignite coal into different grades 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 clusters, 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 mercury concentrations for each IPM coal type was 

determined based on the range of mercury and SO2 concentrations for that coal type. Each coal 

type used one, two or three clusters. To the greatest 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. 

 

33Data 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 

Coal Type by Sulfur Grade Grades (lbs/TBtu) 

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 Concentration in Non-Coal Fuel in EPA Base Case 

v.4.10 

Fuel Type Mercury Concentration (lbs/TBtu) 

Oil 0.48 

Natural Gas 0.001

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 SO2, NOX, 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 

NOX control and SO2 scrubber control. In other words, the mercury reduction achieved (relative to 

 

34“Analysis of Emission Reduction Options for the 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 lignite) 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 participants35 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 capture 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 SO2, NOX, 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 data 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 Modification Factors Used in EPA Base Case v.4.10 

Burner 

Type Particulate Control 

Post 

Combustion 

Control – 

NOX

Post 

Combustion 

Control - 

SO2

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 – 

NOX

Post 

Combustion 

Control - 

SO2

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 – 

NOX

Post 

Combustion 

Control - 

SO2

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 – 

NOX

Post 

Combustion 

Control - 

SO2

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 – 

NOX

Post 

Combustion 

Control - 

SO2

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 – 

NOX

Post 

Combustion 

Control - 

SO2

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 – 

NOX

Post 

Combustion 

Control - 

SO2

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 boilers. 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 SO2 and NOX Retrofits 

In EPA Base Case v.4.10, units that install SO2, NOX, 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 characteristics, and the specific configuration of SO2, NOX, 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, SO2 scrubbers and particulate controls. The absence of a 

federal mercury emission reduction policy means that these controls appear in the base case in 

response to SO2, NOX, or particulate limits or state-level mercury emission requirements. 

However, in future model runs where mercury limits are present these same SO2 and NOX

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 mercury 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 SO2 and NOX 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 alternative ACI configurations: Standard Powered 

Activated Carbon (SPAC), Modified Powered Activated Carbon (MPAC), or SPAC in combination 

with a fabric filter. The MPAC option exploits the discovery that by converting elemental mercury 

to oxidized mercury, halogens (like chlorine, iodine, 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 

TOXECONTM 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. 
5-28 

Table 5-16 Illustrative Activated Carbon Injection Costs (2007$) for Representative Sizes under the Assumption

v.4.10 

Capacity (MW) 

100 300 500 

Control Type 

Capacit

y 

Penalty 

(%) 

Heat Rate 

Penalty 

(%) 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Variable 

O&M cost 

(mills/kWh)

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kW

-yr) 

Variable 

O&M cost 

(mills/kWh) 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/k

W-yr)

Variable 

O&M cost 

(mills/kWh) 

C

($

MPAC_BaghouseMinimum Cutoff: ≥ 25 MW Maximum Cutoff: None Assuming Bituminous Coal 

-0.43 0.43 3 0.1 0.16 2 0.05 0.17 2 0.04 0.17 

MPAC_CESP Minimum Cutoff: ≥ 25 MW Maximum Cutoff: None Assuming Bituminous Coal

-0.43 0.43 8 0.1 0.57 6 0.1 0.61 5 0.1 0.61 

SPAC_BaghouseMinimum Cutoff: ≥ 25 MW Maximum Cutoff: None Assuming Bituminous Coal

-0.43 0.43 5 0.1 0.22 4 0.1 0.23 3 0.1 0.23 

SPAC_ESPMinimum Cutoff: ≥ 25 MW Maximum Cutoff: None Assuming Bituminous Coal

-0.43 0.43 27 0.5 2.29 21 0.3 2.46 18 0.3 2.44 

SPAC_ESP+ToxeconMinimum Cutoff: ≥ 25 MW Maximum Cutoff: None Assuming Bituminous Coal

-0.43 0.43 269 4.3 2.44 202 2.5 2.61 176 2.1 2.59 
5-29 

The applicable ACI option depends on the coal type burned, its SO2 content, the boiler and 

particulate control type and, in some instances, consideration of whether an SO2 scrubber (FGD) 

system or SCR NOx 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 SO2 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 category 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 Calculation Worksheets for SO2 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 Calculation Worksheets for NOx PostCombustion Control Technologies in EPA Base Case v.4.10 
Appendix 5-2.2 
Appendix 5-2.3 
Appendix 5-2.4