### 5

- 1



# 5. Emission Control Technologies

EPA Base Case v.5.13 includes an update of emission control technology assumptions. EPA contracted

with engineering firm Sargent and Lundy to update and add to the retrofit emission control models

previously developed for EPA and used in EPA Base Case v.4 .10. EPA Base Case v.5.13 thus includes

updated assumptions regarding control options for sulfur dioxide ( SO 2 

### ), nitrogen oxides ( NO

x 

### ), mercury

(Hg), and particulate matter (PM). These emission control options are listed in Table 5

- 1 . They are

available in EPA Base Case v.5.13 for meeting existing and potential federal, regional, and state emission

limits. It is important to note that, besides the emission control opt ions shown in Table 5

- 1 and described

in this chapter, EPA Base Case v.5.13 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.5.13

SO 2 and HCl

Control

Tech nology

Options NO

x Control

Technology Options Mercury Control

Technology Options Particulate Matter

Control Technology

Options CO 2 Control

Technology

Options

Limestone Forced

Oxidation (LSFO)

Scrubber Selective Catalytic

Reduction (SCR)

System Activated Carbon

Injection (ACI) System Pulse

- Jet Fabric Filter

(FF) CO 2 Capture and

Sequestration

Lime Spray Dryer

(LSD) Scrubber Selective Non

Catalytic Reduction

(SNCR) System SO 2 and NO

x Control

Technology Removal

Co

- benefits Electrostatic

Precipitator (ESP)

Upgrade Adjustment Coal

- to

- Gas

Conversion

Dry Sorbent

Injection (DSI) Combustion Controls Heat Rate

Improvement

FGD Upgrade

Adjustment



### Detailed reports and example calculation worksheets for Sargent & Lundy retrofit emission control models

used by EPA are available in Attachments 5

- 1 through 5

- 7 at: www.epa.gov/airmarkets/progsregs/epa

ipm/BaseCasev513.html

.



## 5.1 Sulfur Dioxide Control Technologies

- Scrubbers

Two commercially available Flue Gas Desulfurization (FGD) “scrubber” technology options for removing

the SO 2 

### produced by coal

- fired power plants are offered in EPA Base Case v.5.13: Limestone Forced

Oxidation (LSFO)

— a wet FGD technology and Lime Spray D ryer (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 exce eds 3 lb s 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.5.13 when a unit retrofits with an LSD SO 2 

### scrubber, it loses the option of burni ng

certain high sulfur content coals (see Table 5

- 2 ).

In EPA Base Case v.5.13 the LSFO and LSD SO 2 

### 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 databas e of 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 unit s retrofitting with a scrubber.

### 5

- 2

Default SO 2 

### removal rates for wet and dry FGD were based on data reported in EIA 860 (2010). These

default removal rates were the average of all SO 2 

### removal rates for a dry or wet FGD as reported in EIA

860 (2010) for the FGD installation year.

To reduce the inciden ce of implausibly high, outlier removal rates, units whose reported EIA Form 860

(2010) SO 2 

### removal rates are higher than the average of the upper quartile of SO 2 

### removal rates across

all scrubbed units are instead assigned the upper quartile average unles s the reported EIA 860 rate was

recently confirmed by utility comments. One upper quartile removal rate is calculated across all

installation years and replaces any reported removal rate that exceeds it no matter the installation year.

Existing units not reporting FGD removal rates in form EIA 860 (2010) will be assigned the default SO 2 

### removal rate for a dry or wet FGD for that installation year.

As shown in Table 5

- 2 , for FGD retrofits installed by the model, the assumed SO 2 

### removal rates will be

96% for wet FGD and 92% for dry FGD. These are the average of the SO 2 

### removal efficiencies reported

in EIA 860 (2008) for dry and wet FGD installed in 2008 or later. These rates have been subjected to

numerous reviews from utilities and other stakeholders recently, so they remain unchanged and continue

to be used in EPA Base Case v.5.13.

The procedures used to der ive 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 in Base Case v.5.13

Performance

Assumptions Lime stone Forced Oxidation (LSFO) Lime Spray Dryer (LSD)

Percent Removal 96%

with a floor of 0.06 lbs/MMBtu 92%

with a floor of 0.08 lbs/MMBtu

Capacity Penalty

Calculated based on characteristics of the unit:

See 

### Table 5

- 3 Calculated based on characteristics

of the unit:

See 

### Table 5

- 3 Heat Rate Penalty

Cost (2011$)

Applicability Units ≥ 25 MW Units ≥ 25 MW

Sulfur Content

Applicability Coals ≤ 3 lbs SO 2 /MMBtu 1

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

LG, LH, PK and WC BA, BB, BD, BE, SA, SB, SD, SE,

LD, and LE

1 

### FBC units burning WC and PK fuels are provided with LSD retrofit options

Potential (new) coal

- fired units built by the model are also assumed to be constructed with a scrubber

achieving a removal efficiency of 96%. In EPA Base Case v.5.13 the costs of potential new coal units

include the cost of scrubbers.

5.1.1 Methodology for Obtaining SO 2 

### Controls Costs

Sargent and Lu ndy’s updated performance and cost models for wet and dry SO 2 

### scrubbers are

implemented in EPA Base Case v.5.13 to develop the capital, fixed O&M (FOM), and variable O&M

(VOM) components of cost. See Attachments 5

- 1 and 5

- 2 ( www.epa.go v/airmarkets/progsregs/epa

ipm/BaseCasev513.html ).

Capacity and Heat Rate Penalty : In IPM the amount of electrical power required to operate a retrofit

emission control device is represented through a reduction in the amount of electricity that is availab le 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 g eneration both for sale to the grid and for internal load (i.e., for operating

### 5

- 3

the control 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 24 

### . 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). In EPA Base

Case v.5.13 specific LSFO and LSD heat rate and capacity penalties are calculated for each installation

based on equations from the Sargent and Lundy models that take into account the rank of coal burned, its

uncontrolled SO 2 

### rate, and the heat rate of the mod el plant.

Table 5

- 3 presents the capital, VOM, and FOM costs as well as the capacity and heat rate penalty for two

SO 2 

### emission control technologies (LSFO and LSD) inc luded in EPA Base Case v.5.13 for an illustrative

set of generating units with a representative range of capacities and heat rates.

24 Mathematically, the relationship of the heat rate an d capacity penalties (both expressed as positive percentage

values) can be represented as follows:

### 5

- 4

Table 5

- 3 Illustrative Scrubber Costs (2011$) for Representative Sizes and Heat Rates under the Assumptions in EPA Base Case v.5.13

Scrubber

Type Heat Rate

(Btu/kWh) Capacity

Penalty

(%) Heat Rate

Penalty

(%) Variable O&M

(mills/kWh) Capacity (MW)

50 100 300 500 700 1000

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) Fixed

O&M

($/kW

yr) Capital

Cost

($/kW) Fixed

O&M

($/kW

yr) Capital

Cost

($/kW) Fixed

O&M

($/kW

yr)

LSFO 9,000

- 1.50 1.53 2.03 819 23.7 819 23.7 600 11.2 519 8.3 471 7.7 426 6.4

10,000

- 1.67 1.70 2.26 860 24.2 860 24.2 629 11.5 544 8.6 495 8.0 447 6.6

11,000

- 1.84 1.87 2.49 899 24.6 899 24.6 658 11.8 569 8.9 517 8.2 467 6.8

LSD 9,000

- 1.18 1.20 2.51 854 29.1 701 17.3 513 8.6 444 6.5 422 5.7 422 5.3

10,000

- 1.32 1.33 2.79 894 29.6 734 17.7 538 8.9 465 6.8 442 5.9 442 5.5

11,000

- 1.45 1.47 3.07 933 30.0 766 18.0 561 9.1 485 7.0 461 6.1 461 5.7

Note: The above cost estimates assume a boiler burning 3 lb/MMBtu SO 2 Content Bituminous Coal for LSFO and 2 lb/MMBtu SO 2 Content Bituminous Coal for LSD.

### 5

- 5



## 5.2 Nitrogen Oxides Control Technology

The EPA Base Case v.5.13 includes two categorie s 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. Post

- combustion controls

operate downstream of the combustion process and remove NO

x 

### emissions from the flue gas. All the

specific combustion and post

- combustion technologies included in EPA Base Case v.5.13 are

commercially available and currently in use in numerous power plants.

5.2.1 Combu stion Controls

The EPA Base Case v.5.13 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 ap plied 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 A ttachment 3

- 1. The EPA Base Case v.5.13 cost assumptions for NO

x 

### Combustion

Controls are summarized in Table 5

- 4

. Table 3

- 11 provides a mapping of existing coal unit configurations

and incremental combustion contro ls applied in EPA Base Case v.5.13 when units under certain

conditions are assumed to achieve a state

- of

- the

- art combustion control configuration.

Table 5

- 4 Cost (2011$) of NO

x 

### Combustion Controls for Coal Boi lers (300 MW Size)

Boiler Type Technology Capital

($/kW) Fixed

O&M

($/kW

- yr) Variable

O&M

(mills/kWh)

Dry Bottom Wall

Fired Low NO

x Burner without Overfire Air (LNB without OFA) 48 0.3 0.07

Low NO

x Burner with Overfire Air (LNB with OFA) 65 0.5 0.09

Tangentially

- Fired Low NO

x Coal

- and

- Air Nozzles with Close

- Coupled

Overfire Air (LNC1) 26 0.2 0.00

Low NO

x Coal

- and

- Air Nozzles with Separated Overfire

Air (LNC2) 35 0.2 0.03

Low NO

x Coal

- and

- Air Nozzles with Close

- Coupled and

Separated Overfire Air (LNC3) 41 0.3 0.03

Vertically

- Fired NO

x Combustion Control 31 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 = ($/kW for X MW Unit) = ($/kW for 300 MW Unit) x (300/ X ) 0.359

LNC1, LNC2, and LNC3 = ($/kW for X MW Unit) = ($/kW for 300 MW Unit) x (300/ X ) 0.359

Vertically

- Fired = ($/kW for X MW Unit) = ($/kW for 300 MW Unit) x (300/ X ) 0.553

where ($/kW for 300 MW Unit) is a value from the above table and X is the capacity (in MW) of the unit taking on

combustion controls.



### 5.2.2 Post

- combustion NO

x 

### Controls

The EPA Base Case v.5.13 includes two post

- combustion retrofit NO

x 

### control technologies for existing

coal units: Selective Catalytic Reduction (SCR) and Selective Non

- Catalytic Reduction (SNCR). In EPA

Base Case v.5.13 oil/gas steam units are eligible for SCR only. NO

x 

### reduction in a SCR system takes

place by injecting ammonia (NH 3 

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

x 

### is reduced to nitrogen

(N 2 

### ) 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 w ithout a catalyst. In SNCR

a nitrogenous reducing agent (reagent), typically urea or ammonia, 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

### 5

- 6

to the presence o f a catalyst, SCR can achieve greater NO

x 

### reductions than SNCR. However, SCR costs

are higher than SNCR costs

.

Table 5

- 5 summarizes the performance and applicability assumptions in EPA Base Case v.5.13 for each

post

- combustion NO

x 

### control technology and provides a cross

- reference to information on cost

assumptions.

Table 5

- 5 Summary of Retrofit NO

x 

### Emission Control Perform ance Assumptions

Control Performance

Assumptions Selective Catalytic Reduction

(SCR) Selective Non

- Catalytic

Reduction

(SNCR)

Unit Type Coal Oil/Gas Coal

Percent Removal 90% 80% Pulverized Coal: 25%

Fluidized Bed: 50%

Rate Floor Bituminous: 0.07 lb/MMBtu

-- Pulverized Coal: 0.1 lb/MMBtu

Subbituminous and Lignite: 0.05

lb/MMBtu Fluidized Bed: 0.08 lb/MMBtu

Size Applicability Units ≥ 25 MW Units ≥ 25

MW Pulverized Coal: Units ≥ 25 MW

and ≤ 100 MW

Fluidized Bed: Units ≥ 25 MW

Costs (2011$) See Table 5

- 6 

### Illustrative Post

combustion NO x Control

Costs (2011$) for Coal Plants

for Representative Sizes and

Heat Rates under the

Assumptions in EPA Base

Case v.5.13 See 

### Table

5

- 7 See Table 5

- 6 

### Illustrative Post

combustion NO x Control Costs

(2011$) for Coal Plants for

Representative Sizes and Heat

Rates under the Assumptions

in EPA Base Case v.5.13

5.2.3 Methodology for Obtaining SCR Costs for Coal

Sargent and Lundy’s updated performance/cost models for SCR and SNCR technologies are

implemented in EPA Base Case v.5.13 to develop the capital, fixed O&M (FOM), and variable O&M

(VOM) components of cost. See Attachments 5

- 3 and 5

- 4 ( www.epa.gov/airmarkets/progsregs/epa

ipm/BaseCasev513.html ).

Table 5

- 6 presents the SCR and SNCR capital, VOM, and F OM costs and capacity and heat rate

penalties for an illustrative set of coal generating units with a representative range of capacities and heat

rates

.

### 5

- 7

Table 5

- 6 Illustrative Post

- combustion NO

x 

### Control Costs (2011$) for Coal Plants for Representative Sizes and Heat Rates under the

Assumptions in EPA Base Case v.5.13

Control

Type Heat Rate

(Btu/kWh) Capacity

Penalty

(%) Heat Rate

Penalty

(%) Variable O&M

(mills/kWh) Capacity (MW)

100 300 500 700 1000

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) Fixed

O&M

($/kW

yr) Capital

Cost

($/kW) Fixed

O&M

($/kW

yr)

SCR 9,000

- 0.54 0.54 1.23 321 1.76 263 0.76 243 0.64 232 0.58 222 0.53

10,000

- 0.56 0 .56 1.32 349 1.86 287 0.81 266 0.69 255 0.63 244 0.57

11,000

- 0.58 0.59 1.41 377 1.96 311 0.87 289 0.73 277 0.67 265 0.62

SNCR

- Tangential 9,000

- 0.05 0.7 8 1.04 55 0.48 30 0.26 22 0.20 18 0.16 15 0.13

10,000 1.15 56 0.50 30 0.27 23 0.20 19 0.17 15 0.14

11,000 1.27 57 0.51 31 0.27 23 0.21 19 0.17 16 0.14

SNCR

-

Fluidized

Bed 9,000

- 0.05 0.78 1.04 41 0.36 22 0.20 17 0.15 14 0.12 11 0.10

10,000 1.15 42 0.37 23 0.20 17 0.15 14 0.12 12 0.10

11,000 1.27 43 0.38 23 0.21 17 0.15 14 0.13 12 0.10

Note: Assumes a boiler burning bituminous coal with an input NO

x rate of 0.5 lbs/MMBtu. The technology is applied to boilers larger than 25 MW.

### 5

- 8

5.2.4 Methodology for Obtaining SCR Costs for Oil/Gas Steam U nits

The cost calculations for SCR described in section 5.2.2 apply to coal units. For SCR on oil/gas steam

units the cost calculation procedure shown in Table 5

- 7 is used in EPA Base Case v.5.13. The scaling

factor for capital and fixed O&M costs, described in footnote a , applies to all size units from 25 MW and

up.

Table 5

- 7 Post

- Combustion NO

x 

### Controls for Oil/Gas Steam Unit s in EPA Base Case v.5.13

Post

- Combustion

Control Technology Capital

($/kW) Fixed O&M

($/kW

- yr) Variable O&M

($/MWh) Percent

Removal

SCR a 80 1.16 0.13 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.

Cost data are adjusted to 2011$ by EPA.

a 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) = 80 * (200/275) 0.35 ≈ 71.64 $/kW

SCR FOM Cost ($/kW

- yr) = 1.16 * (200/275) 0.35 ≈ 1.04 $/kW

- yr

SCR VOM Cost ($/MWh) = 0.13 $/MWh



### 5.2.5 Methodology for Obtaining SNCR C osts

In the Sargent and Lundy ’s 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) units are distinguished from the c orresponding costs for other boiler types (e.g.

cyclone, and wall fired). As with SCR an air heater modification cost applies for plants that burn

bituminous coal whose SO 2 

### content is 3 lbs/MMBtu or greater.

5.2.6 SO 2 

### and NO

x 

### Controls for Units with Capacitie s from 25 MW to 100 MW (25 M W ≤ capacity

< 100 MW)

In EPA Base Case v.5.13 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 for SCR, 50 MW for Dry

FGD, and 100 MW for Wet FGD

. These assumption s are based on s everal 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 minimum capacity cost equivalency assumption, though generic, would be

technically plausible. S econd, 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. 25



### 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 higher for units below 100 MW than

for a 100 MW unit, but when combined in the Multi

- Pollutant Technologies (MPTs) their costs would be

roughly equivale nt to the cost of individual controls on a 100 MW unit. While MPTs are not explicitly

represented in EPA Base Case v.5.13, 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 retr ofit ted with an MPT.

25 See, for example, the Greenidge Multi

- Pollutant Control Project, which was part of the U.S. Department of Energy,

National Energy Technology Lab’s Pow er Plant Improvement Initiative. A joint effort of CONSOL Energy Inc. AES

Greenidge LLC, and Babcock Power Environmental, Inc., the project is described in greater detail at

www.netl.doe.gov/technologies/coalpower/cctc/PPII/bibliography/demonstration/environmental/bib_greenidge.html

.

### 5

- 9

Illustrative SCR costs for 25

- 100 MW coal units with a range of heat rates can be found by referring to the

100 MW “Capital Costs ($/kW)” and “Fixed O&M” columns in Table 5

- 6 and i llustrative scrubber costs for

25

- 100 MW coal units with a range of heat rates can be found by referring to the LSFO 100 MW and LSD

50MW “Capital Costs ($/kW)” and “Fixed O&M” columns in Table 5

- 3 . 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

Biomass co

- firing is provided as a fuel choice for all coal

- fired power plants in EPA Base Case v.5.13.

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 given the low energy density of the fuel . 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 engin eering 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.5.13 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

m odeling projections . In EPA Base Case v.5.13 “facility level” is defined as the set of generating units

which share the same ORIS code 26 

### in NEEDS v.5.13.

The capital and FOM cost assumptions informing EPA Base Case v.5.13 regarding biomass co

- firing are

summarized in Table 5

- 8

, developed by EPA’s power sector engineering staff and updated to 2011$. 27



### Table 5

- 8 Biomass Co

- f iring for Coal Plants

Output From Biomass (MW) 5 10 15 20 25 30 35 40 45 50

Capital Cost (2011$/kW From Biomass) 521 439 396 368 349 333 320 309 301 293

Fixed O&M (2011$/kW

- yr) 25.8 17.3 12.5 10.0 8.5 11.8 10.6 9.5 8.6 8.0



### In order to economize on model space, instead of designing a biomass co

- firing “retrofit” modification for

units that would include direct representations of the capital and FOM costs shown in Table 5

- 8

. The

26 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 ownership changes.

27 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 , presen ted at 24th International Technical Conference on

Coal & Fuel Systems, Clearwater, FL., March 8

– 11, 1999.

(c) EPRI, Biomass Co

- firing : 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., Johnsto wn, PA: 1999. TR

- 113903.

(d) Laux S., J. Grusha, and D. Tillman, Co

- firing of Biomass and Opportunity Fuels in Low NOx Burners,

PowerGen 2000

- Orlando, FL, www.fwc.com/publicat ions/tech_papers/powgen/pdfs/clrw_bio.pdf

. (e) Tillman, D. A., Co

- firing Biomass for Greenhouse Gas Mitigation , presented at Power

- Gen 99, New

Orleans, LA, November 30

– December 1, 1999.

(f) Tillman, D. A. and P. Hus, Blending Opportunity Fuels with Coal for Eff iciency and Environmental Benefit

, presented at 25th International Technical Conference on Coal Utilization & Fuel Systems, Clearwater, FL.,

March 6

– 9, 2000

### 5

- 10

capital and FOM costs were implemented by in EPA Base Case v.5.13 as a $/MMBtu biomass fuel cost

adder. T he discrete costs shown in Table 5

- 8 are first represented as continuous exponential cost

functions showing the FOM and capital costs for all biomass outputs between 0 and 50 MW in size. Then,

for every coal generating unit represented in EPA Base Case 5.13, the annual paym ent to capital for the

biomass co

- firing capability was derived by multiplying the total capital cost obtained from the capital cost

exponential function by a 1 2.1 % capital charge rate for utility

- owned unit s and a 16.47% capital charge

rate for merchant units. 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 fo r 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 fu el required

by the generating unit in MMBtus. Dividing this number into the previously calculated total annual cost for

biomass co

- firing capability 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 unit co

- fires biomass. In this

manner, the model’s decision process for determining biomass consumption takes into account not just

the cost of the biomass fuel, but also the capital and FOM costs associated with bio mass co

- firing at the

units in question.

Chapter 11 discusses factors related to the delivered cost of biomass fuel in EPA Base Case v.5.13.



## 5.4 Mercury Control Technologies

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

activated carbon injection (ACI) , mercury emission reductions below the mercury content of the fuel are

strictly due to characterist ics of the combustion process and incidental removal resulting from other

pollution control technologies, e

. g ., the SO 2 

### , NO

x 

### , and particulate matter controls. The following

discussion is divided into three parts. Sections 5.4.1 and 5.4.2 explain the two factors that determine

mercury emissi ons that result from unit configurations lacking ACI under EPA Base Case v.5.13. Section

5.4.1 discusses how mercury content of fuel is modeled in EPA Base Case v.5.13. Section 5.4.2 looks at

the procedure used to capture the mercury reduct ions resulting from different unit and (non

- mercury)

control configurations. Section 5.4.4 explains the mercury emission control options that are available

under EPA Base Case v.5.13. Each section indicates the data sources and methodology used.

5.4.1 Mercury Content of Fuels

Coal : The assumptions in EPA Base Case v.5.13 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 Co llection

Effort” (ICR). 28 

### 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 coo peratives, 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 electr ic [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.

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

. In 2009, EPA collected some additional information regarding mecury through the Collection Effort for New and

Existing Coal

- and Oil

- Fired Electricty Utility Steam Generating Units (EPA ICR No.2362.01 (OMB Control Number

2060

- 0631), however the information collected was not similarly comprehensive and was thus not used to update

mercury assumptions in this EPA base case.

### 5

- 11

The ICR 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, these data points were first grouped by IPM coal types and IPM coal supply regions. IPM coal

types divide bituminous, subbituminous, and lignite coal into different grades based on sulfur content.

Oil, natural gas, and waste fuels : The EPA Base Case v.5.13 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. 29 

### Table 5

- 9 provides a summary of the assumptions on the

mercury content for oil, gas and waste fuels included in EPA Base Case v.5.13.

Table 5

- 9 Assumptions on Mercury Concentration in Non

- Coal Fuel in EPA Base Case v.5.13

Fuel Type Mercury Concentration (lbs/TBtu)

Oil 0.48

Natural Gas 0.00 a

Petroleum Coke 2.66 b

Biomass 0.57

Municipal Solid Waste 71.85

Geothermal Resource 2.97

- 3.7

Note:

a 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 0.000138 lbs/TBtu. Values for geothermal resources represent a range.

b A previous computational error in the mercury emission factor for petroleum coke as presented in Table 6

- 3 of the EPA report

titled Control of Mercury Emissions from Coal

- fired Electric Utility Boilers: Interim Report Including Errata, 3

- 21

- 02 was corrected

(from 23.18 lbs/TBtu to 2.66 lb/TBtu) based on re

- examination of the 1999 ICR data for petroleu m coke and implementation of a

procedure for flagging and excluding outlier values above the 95 percentile value.



### 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 conc entration 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 the inlet) during combustion and flue

- gas

treatment process is (1

- EMF). The EMF varies by the type of coal (bituminous, subbituminous, and

lignite) used during the combustion process.

Deriving EMFs involves obtaining mercury inlet data by coal sampling and mercury emission data by

sta ck testing at a representative 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 30 

### has provided a better understanding of merc ury 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 subbituminous and lignite coal

- fired plants, and

s ignificant 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 u nderstanding of mercury capture with SCRs is

incorporated in EPA Base Case v.5.13 mercury EMFs for unit configurations with SCR and wet

scrubbers.

29 Analysis of Emission Reduction Options for the Electric Power Indust ry,” Office of Air and Radiation, US EPA,

March 1999.

30 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 f ound at

www.epa.gov/ttnatw01/utility/hgwhitepaperfinal.pdf

.

### 5

- 12

Table 5

- 10 below provides a summary of EMFs used in EPA Base Case v.5.13. Table 5

- 11 provides

definitions of acronyms for existing controls that appear in

### 5

- 13

Table 5

- 16

. Table 5

- 12 provides a key to the burner type designations appearing in

### 5

- 14

Table 5

- 16

.

Table 5

- 10 Mercury Emission Modification Factors Used in EPA Base Case v.5.13

Burner

Type Particulate Control Post

- combustion

Control

- NO

x Post

- combustion

Control

- SO 2 Bituminous

EMF Subbituminous

EMF Lignite

EMF

Cyclone Cold Side ESP SCR None 0.64 0.97 1

Cyclone Cold Side ESP SCR Wet FGD 0.1 0.84 0.56

Cyclone Cold Side ESP SCR Dry FGD 0.64 0.65 1

Cyclone Cold Side ESP No SCR None 0.64 0.97 1

Cyclone Cold Side ESP No SCR Wet FGD 0.34 0.84 0.56

Cyclone Cold Side ESP No SCR Dry FGD 0.64 0.65 1

Cyclone Cold Side ESP + FF SCR None 0.2 0.75 1

Cyclone Cold Side ESP + FF SCR Wet FGD 0.1 0.3 0.56

Cyclone Cold Side ESP + FF SCR Dry FGD 0.05 0.75 1

Cyclone Cold Side ESP + FF No SCR None 0.2 0.75 1

Cyclone Cold Side ESP + FF No SCR Wet FGD 0.3 0.3 0.56

Cyclone Cold Side ESP + FF No SCR Dry FGD 0.05 0.75 1

Cyclone Cold Side ESP +

FGC SCR None 0.64 0.97 1

Cyclone Cold Side ESP +

FGC SCR Wet FGD 0.1 0.84 0.56

Cyclone Cold Side ESP +

FGC SCR Dry FGD 0.64 0.65 1

Cyclone Cold Side ESP +

FGC No SCR None 0.64 0.97 1

Cyclone Cold Side ESP +

FGC No SCR Wet FGD 0.34 0.84 0.56

Cyclone Cold Side ESP +

FGC No SCR Dry FGD 0.64 0.65 1

Cyclone Cold Side ESP +

FGC + FF SCR None 0.2 0.75 1

Cyclone Cold Side ESP +

FGC + FF SCR Wet FGD 0.1 0.3 0.56

Cyclone Cold Side ESP +

FGC + FF SCR Dry FGD 0.1 0.3 0.56

Cyclone Cold Side ESP +

FGC + FF No SCR None 0.2 0.75 1

Cyclone Cold Side ESP +

FGC + FF No SCR Wet FGD 0.1 0.3 0.56

Cyclone Cold Side ESP +

FGC + FF No SCR Dry FGD 0.1 0.3 0.56

Cyclone Fabric Filter SCR None 0.11 0.27 1

Cyclone Fabric Filter SCR Wet FGD 0.1 0.27 0.56

Cyclone Fabric Filter SCR Dry FGD 0.05 0.75 1

Cyclone Fabric Filter No SCR None 0.11 0.27 1

Cyclone Fabric Filter No SCR Wet FGD 0.1 0.27 0.56

Cyclone Fabric Filter No SCR Dry FGD 0.05 0.75 1

Cyclone Hot Side ESP SCR None 0.9 0.9 1

Cyclone Hot Side ESP SCR Wet FGD 0.1 0.8 1

Cyclone Hot Side ESP SCR Dry FGD 0.6 0.85 1

Cyclone Hot Side ESP No SCR None 0.9 0.94 1

Cyclone Hot Side ESP No SCR Wet FGD 0.58 0.8 1

Cyclone Hot Side ESP No SCR Dry FGD 0.6 0.85 1

Cyclone Hot Side ESP + FF SCR None 0.11 0.27 1

Cyclone Hot Side ESP + FF SCR Wet FGD 0.1 0.15 0.56

Cyclone Hot Side ESP + FF SCR Dry FGD 0.05 0.75 1

Cyclone Hot Side ESP + FF No SCR None 0.11 0.27 1

Cyclone Hot Side ESP + FF No SCR Wet FGD 0.03 0.27 0.56

Cyclone Hot Side ESP + FF No SCR Dry FGD 0.05 0.75 1

Cyclone Hot Side ESP + FGC SCR None 0.9 0.9 1

Cyclone Hot Side ESP + FGC SCR Wet FGD 0.1 0.8 1

Cyclone Hot Side ESP + FGC SCR Dry FGD 0.6 0.85 1

Cyclone Hot Side ESP + FGC No SCR None 0.9 0.94 1

Cyclone Hot Side ESP + FGC No SCR Wet FGD 0.58 0.8 1

Cyclone Hot Side ESP + FGC No SCR Dry FGD 0.6 0.85 1

### 5

- 15 Burner

Type Particulate Control Post

- combustion

Control

- NO

x Post

- combustion

Control

- SO 2 Bituminous

EMF Subbituminous

EMF Lignite

EMF

Cyclone No Control SCR Wet FGD 0.1 0.7 1

Cyclone No Control No SCR Wet FGD 0.1 0.7 1

FBC Cold Side ESP No SCR None 0.65 0.65 0.62

FBC Cold Side ESP No SCR Dry FGD 0.64 0.65 1

FBC Cold Side ESP + FF No SCR None 0.05 0.43 0.43

FBC Cold Side ESP + FF No SCR Dry FGD 0.05 0.75 1

FBC Fabric Filter SCR None 0.11 0.27 1

FBC Fabric Filter SCR Dry FGD 0.05 0.75 1

FBC Fabric Filter No SCR None 0.05 0.43 0.43

FBC Fabric Filter No SCR Dry FGD 0.05 0.43 0.43

FBC Hot Side ESP + FGC No SCR None 1 1 1

FBC Hot Side ESP + FGC No SCR Dry FGD 0.6 0.85 1

FBC No Control No SCR None 1 1 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 No SCR None 0.64 0.97 1

PC Cold Side ESP No SCR Wet FGD 0.34 0.84 0.56

PC Cold Side ESP No SCR Dry FGD 0.64 0.65 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 No SCR None 0.2 0.75 1

PC Cold Side ESP + FF No SCR Wet FGD 0.3 0.3 0.56

PC Cold Side ESP + FF No SCR Dry FGD 0.05 0.75 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 No SCR None 0.64 0.97 1

PC Cold Side ESP +

FGC No SCR Wet FGD 0.34 0.84 0.56

PC Cold Side ESP +

FGC No SCR Dry FGD 0.64 0.65 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 No SCR None 0.2 0.75 1

PC Cold Side ESP +

FGC + FF No SCR Wet FGD 0.3 0.3 0.56

PC Cold Side ESP +

FGC + FF No SCR 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 No SCR None 0.11 0.27 1

PC Fabric Filter No SCR Wet FGD 0.1 0.27 0.56

PC Fabric Filter No SCR Dry FGD 0.05 0.75 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 No SCR None 0.9 0.94 1

PC Hot Side ESP No SCR Wet FGD 0.58 0.8 1

PC Hot Side ESP No SCR Dry FGD 0.6 0.85 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

### 5

- 16 Burner

Type Particulate Control Post

- combustion

Control

- NO

x Post

- combustion

Control

- SO 2 Bituminous

EMF Subbituminous

EMF Lignite

EMF

PC Hot Side ESP + FF No SCR None 0.11 0.27 1

PC Hot Side ESP + FF No SCR Wet FGD 0.03 0.27 0.56

PC Hot Side ESP + FF No SCR Dry FGD 0.05 0.75 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 No SCR None 0.9 0.94 1

PC Hot Side ESP + FGC No SCR Wet FGD 0.58 0.8 1

PC Hot Side ESP + FGC No SCR Dry FGD 0.6 0.85 1

PC Hot Side ESP + FGC

+ FF SCR Dry FGD 0.05 0.75 1

PC Hot Side ESP + FGC

+ FF No SCR None 0.11 0.27 1

PC Hot Side ESP + FGC

+ FF No SCR Dry FGD 0.05 0.75 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 No SCR None 1 1 1

PC No Control No SCR Wet FGD 0.58 0.7 1

PC No Control No SCR Dry FGD 0.6 0.85 1

PC PM Scrubber SCR None 0.9 1 1

PC PM Scrubber SCR Wet FGD 0.1 0.7 1

PC PM Scrubber SCR Dry FGD 0.6 0.85 1

PC PM Scrubber No SCR None 0.9 0.91 1

PC PM Scrubber No SCR Wet FGD 0.58 0.7 1

PC PM Scrubber No SCR Dry FGD 0.6 0.85 1



### Table 5

- 11 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

- 12 Key to Burner Type Designations in Table 5

- 1 0

“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 co al particles to be captured on the cyclone barrel wall where they are burned in molten slag.

“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.

### 5

- 17

5.4.3 Mercury Control Capabilities

EPA Base Case v.5.13 offers two options f or mercury pollution control : (1) combinations of SO 2 

### , NO

x 

### , and

par t iculate cont r ols which d e liver mercury reductions as a co

- benefit and ( 2) Activated Carbon Injection

(ACI), a retrofit option speci f ically designed for mercury co n trol. These t wo options are discussed below.

Mercury C o ntrol thro u gh SO 2 

### and NO

x 

### Retrofits

In EPA Base Case v.5.13

, units that install SO 2 

### , NO

x 

### , and p a rticulate co n trols, reduce mercury emissions

a s a byproduct of these r etrofits. Sec t ion 5.4.2 d e scribed how EMFs are used in the base case t o capture

mercury e m issions d e pending on t he rank of coal burned, the generating unit’s c o mbustion c h aracteristics,

and the s p ecific confi g uration of SO 2 

### , NO

x 

### , and particulate controls (i.e., hot and cold

- side electrostatic

precipitators (ESPs), fabric f il t ers (also called “bag h ouses”) and particulate matter (PM) scrubbers).

Activated Carbon Injection (ACI)

The technology used for mercury control in EPA Base Case v.5.1 3 is Activated Carbon Injection (ACI)

downstream of the combustion proc e ss in c o al fi r ed units. Sargent & Lundy ’s updated cost and

performance assum p tions for ACI are used.

Three altern a tive ACI options are represented as capable of providing 90% mercury removal for all possible

c o nfigurations of boiler, emission contr o ls, and coal ty pes used in the U.S. electric power sector. The

three ACI options diff e r, based o n whether they are used in conjunction with an electrostatic precipitator

(ESP) or a fabric filter (also called a “ baghouse” ). The three ACI options are:

ACI with Ex i s ting ESP

ACI with Ex i s ting Bagh o use

ACI with an Additional Baghouse (also refe r red to as T o xecon)

I n the third option lis t ed above the additional baghouse is installed d o wnstream of the pre

- existing

partic u late matter device and the activated carbon is injected after t he existing controls. This configura t ion

allows t h e fly ash to be removed before it is contaminated by the mercury.

For modeling purposes, EPA currently assumes that all three co n figurations use b r ominated ACI, where a

small amount of bromine is chemically bonded to the powdered carbon which is inj e cted into the flue gas

stream. EPA recognizes that amended silicates and possibly other non

- carbon, non

- brominated

substances are in development and may become available as alternatives to brominated carbon as a

mercury sorbent.

The a pplic a ble ACI option depends on the coal ty pe burned, its SO 2 

### con t ent, the boiler and particulate

control type and, in some instanc e s

, consideration of whether an SO 2 

### scrubber (FGD) syst e m and SCR

N O

x 

### post

- combustion c o ntrol are pr e s ent.

### 5

- 18

Table 5

- 13 shows the ACI assignment scheme used in EPA B a se Case v.5.13 to achieve 90% mercury

r emoval.

### 5

- 19

Table 5

- 13 Assignment Scheme for Mercury Emissions Control Using Activated Carbon Injection

(ACI) in EPA Base Case v.5.13

Air pollution controls Bituminous Coal Subbituminous Coal Lignite Coal

Burner

Type Particulate Control Type SCR

System FGD

System ACI

Required? Toxecon

Required? Sorbent Inj

Rate

ACI

Required? Toxecon

Required? Sorbent Inj

Rate

ACI

Required? Toxecon

Required? Sorbent Inj

Rate

(lb/million

acf) (lb/million

acf) (lb/million

acf)

FBC Cold Side ESP + Fabric Filter without FGC

-- -- Yes No 2 Yes No 2 Yes No 2

FBC Cold Side ESP without FGC

-- -- Yes No 5 Yes No 5 Yes No 5

FBC Fabric Filter

-- Dry FGD No No 0 Yes No 2 Yes No 2

FBC Fabric Filter

-- -- Yes No 2 Yes No 2 Yes No 2

FBC Hot Side ESP with FGC

-- -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Cold Side ESP + Fabric Filter with FGC

-- Dry FGD Yes No 2 Yes No 2 Yes No 2

Non

- FBC Cold Side ESP + Fabric Filter with FGC

-- -- Yes No 2 Yes No 2 Yes No 2

Non

- FBC Cold Side ESP + Fabric Filter with FGC

-- Wet FGD Yes No 2 Yes No 2 Yes No 2

Non

- FBC Cold Side ESP + Fabric Filter with FGC SCR

-- Yes No 2 Yes No 2 Yes No 2

Non

- FBC Cold Side ESP + Fabric Filter with FGC SCR Dry FGD Yes No 2 Yes No 2 Yes No 2

Non

- FBC Cold Side ESP + Fabric Filter with FGC SCR Wet FGD Yes No 2 Yes No 2 Yes No 2

Non

- FBC Cold Side ESP + Fabric Filter without FGC

-- Dry FGD Yes No 2 Yes No 2 Yes No 2

Non

- FBC Cold Side ESP + Fabric Filter without FGC

-- -- Yes No 2 Yes No 2 Yes No 2

Non

- FBC Cold Side ESP + Fabric Filter without FGC

-- Wet FGD Yes No 2 Yes No 2 Yes No 2

Non

- FBC Cold Side ESP + Fabric Filter without FGC SCR

-- Yes No 2 Yes No 2 Yes No 2

Non

- FBC Cold Side ESP + Fabric Filter without FGC SCR Dry FGD Yes No 2 Yes No 2 Yes No 2

Non

- FBC Cold Side ESP + Fabric Filter without FGC SCR Wet FGD Yes No 2 Yes No 2 Yes No 2

Non

- FBC Cold Side ESP with FGC

-- Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Cold Side ESP with FGC

-- -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Cold Side ESP with FGC

-- Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Cold Side ESP with FGC SCR

-- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Cold Side ESP with FGC SCR Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Cold Side ESP with FGC SCR Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Cold Side ESP without FGC

-- Dry FGD Yes No 5 Yes No 5 Yes No 5

Non

- FBC Cold Side ESP without FGC

-- -- Yes No 5 Yes No 5 Yes No 5

Non

- FBC Cold Side ESP without FGC

-- Wet FGD Yes No 5 Yes No 5 Yes No 5

Non

- FBC Cold Side ESP without FGC SCR

-- Yes No 5 Yes No 5 Yes No 5

Non

- FBC Cold Side ESP without FGC SCR Dry FGD Yes No 5 Yes No 5 Yes No 5

Non

- FBC Cold Side ESP without FGC SCR Wet FGD Yes No 5 Yes No 5 Yes No 5

Non

- FBC Fabric Filter

-- Dry FGD Yes No 2 Yes No 2 Yes No 2

Non

- FBC Fabric Filter

-- -- Yes No 2 Yes No 2 Yes No 2

Non

- FBC Fabric Filter

-- Wet FGD Yes No 2 Yes No 2 Yes No 2

Non

- FBC Fabric Filter SCR Dry FGD Yes No 2 Yes No 2 Yes No 2

Non

- FBC Fabric Filter SCR

-- Yes No 2 Yes No 2 Yes No 2

Non

- FBC Fabric Filter SCR Wet FGD Yes No 2 Yes No 2 Yes No 2

Non

- FBC Hot Side ESP + Fabric Filter with FGC

-- -- Yes No 2 Yes No 2 Yes No 2

Non

- FBC Hot Side ESP + Fabric Filter with FGC

-- Wet FGD Yes No 2 Yes No 2 Yes No 2

Non

- FBC Hot Side ESP + Fabric Filter with FGC

-- Dry FGD No No 0 Yes No 2 Y(b) No 2

Non

- FBC Hot Side ESP + Fabric Filter with FGC SCR Wet FGD Yes No 2 Yes No 2 Yes No 2

Non

- FBC Hot Side ESP + Fabric Filter with FGC SCR Dry FGD No No 0 Yes No 2 Y(b) No 2

Non

- FBC Hot Side ESP + Fabric Filter with FGC SCR

-- Yes No 2 Yes No 2 Y(b) No 2

Non

- FBC Hot Side ESP + Fabric Filter without FGC

-- Dry FGD No No 0 Yes No 2 Yes No 2

Non

- FBC Hot Side ESP + Fabric Filter without FGC

-- -- Yes No 2 Yes No 2 Yes No 2

Non

- FBC Hot Side ESP + Fabric Filter without FGC

-- Wet FGD Yes No 2 Yes No 2 Yes No 2

Non

- FBC Hot Side ESP + Fabric Filter without FGC SCR Dry FGD No No 0 Yes No 2 Yes No 2

Non

- FBC Hot Side ESP + Fabric Filter without FGC SCR

-- Yes No 2 Yes No 2 Yes No 2

Non

- FBC Hot Side ESP + Fabric Filter without FGC SCR Wet FGD Yes No 2 Yes No 2 Yes No 2

Non

- FBC Hot Side ESP with FGC

-- Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Hot Side ESP with FGC

-- -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Hot Side ESP with FGC

-- Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Hot Side ESP with FGC SCR Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Hot Side ESP with FGC SCR

-- Yes Yes 2 Yes Yes 2 Yes Yes 2

### 5

- 20 Air pollution controls Bituminous Coal Subbituminous Coal Lignite Coal

Burner

Type Particulate Control Type SCR

System FGD

System ACI

Required? Toxecon

Required? Sorbent Inj

Rate

ACI

Required? Toxecon

Required? Sorbent Inj

Rate

ACI

Required? Toxecon

Required? Sorbent Inj

Rate

(lb/million

acf) (lb/million

acf) (lb/million

acf)

Non

- FBC Hot Side ESP with FGC SCR Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Hot Side ESP without FGC

-- Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Hot Side ESP without FGC

-- -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Hot Side ESP without FGC

-- Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Hot Side ESP without FGC SCR Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Hot Side ESP without FGC SCR

-- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC Hot Side ESP without FGC SCR Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC No Control

-- Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC No Control

-- -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC No Control

-- Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC No Control SCR Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC No Control SCR

-- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC No Control SCR Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC PM Scrubber

-- Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC PM Scrubber

-- -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC PM Scrubber

-- Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC PM Scrubber SCR Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC PM Scrubber SCR

-- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non

- FBC PM Scrubber SCR Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2



### 5.4.4 Methodology for Obtaining ACI Control Costs

Sargent & Lundy’s ACI model assumes that the carbon feed rate dictates the size of t he equipment and

resul t ing cos t s. T he feed rate in turn is a f unction of t h e required removal (in t his case 9 0 %) and the type

of particulate control device. Sargent & Lundy established that a carbon feed rate of 5 po u nds of carb o n

injected f o r every 1,0 0 0,000 actual cu b ic feet per minute (acfm) of flue gas w ould provide the stipula t ed

90% mercury removal rate for units shown in Table 5

- 14 as q u alifying for ACI systems with existing ESP.

For generating u nits with fa b ric filte r s a lower injection rate of 2 pound per million acfm is required.

Alternative sets of costs were developed for each of t h e three ACI options: ACI systems for units with

existing ESPs, ACI f or units with existing fabric filte r s (baghouses), and the combined cost of ACI plus an

addition a l baghouse f or units that either have no existing particulate control or th a t require ACI plus a

baghouse in addition to t heir existing particulate control. Th e re are various reasons that a combined ACI

plus addition a l baghouse would be req u ired. These include situ a tions where the existing ESP cannot

handle the additional particulate load associate with t he ACI or where SO

3 

### i njection is currently in use to

condi ti on the flue g as for the E SP. Another cause for combined ACI and baghouse is u s e of PRB coal

whose combustion pro d uces mostly elemental mercury, not ionic merc u ry, due to this coal’s low chlorine

co n tent.

For the combined ACI and fabric fil t er option a f ull size bag h ouse with a n air

- to

- cloth (A/C) ratio of 4.0 is

assumed, as opposed to a polishing ba ghouse with a 6.0 A/C rati o 31



### .

Table 5

- 14 presents the capital, VOM, and FOM costs as well as the capacity and heat rate penalties for

the three ACI options represented in EPA Base Case v.5.13 . For each ACI option valu es are shown for

an illustrative set of generating units with a representative range of capacities and heat rates. See

Attachment 5

- 6 ( www.epa.gov/airmarkets/progsregs/epa

- ip m/BaseCasev513.html ) for details on the

Sargent & Lundy model of ACI for Hg control.

31 The “air

- to

- c l oth” (A/C) rat i o is the vol u metric fl o w, (typically expr e s sed in Actu a l Cub i c Feet per Mi n ute, ACFM) of fl u e gas

e nteri n g the bag h o u se divid e d by the a r e a s (ty p ically in s q uare feet) of fabric filter cloth in the bag h o u se. The l o w e r the A/C rat i o, e.g., A/C = 4.0 comp a r e d to A/C = 6.0, the great e r area of the cloth r e qu i red and the hig h er the cost for a given v olumetric fl o w

### 5

- 21



## 5.5 Hydrogen Chloride (HCl) Control Technologies

T he following sub

- sections describe how HCl emissio n s from coal are repres e nted in IPM for EPA Base

Case v.5.13, the emissi o n control technologi e s available f or HCl removal, and the cost and p erformance

characteris t ics of these technologi e s

.

5.5.1 Chlorine Content of Fuels

HCl emissions from the power sector result from the chlorine content of the coal that is combusted by

electric generating units. Data on chlorine content of coals had been collected as part EPA’s 1999

“Information Collection Request for Electric Utility Steam Generating Unit Mercury Emissions Information

Collection Effort” (ICR 1999) described above in section 5.4.1 This data is incorporated into the model in

order to provide the capability for EPA Base Case v.5.13 to project HCl emissions. The procedure s used

for this are presented below.

Western subbituminous coal (such as that mined in the Powder River Basin) and lignite coal contain

natural alkalinity in the form of non

- glassy calcium oxide (CaO) and other alkaline and alkaline earth

oxides. This fl y ash (classified as ‘Class C’ fly ash) has a natural pH of 9 and higher and the natural

alkalinity can effectively neutralize much of the HCl in the flue gas stream prior to the primary control

device.

Eastern bituminous coals, by contrast, tend to produ ce fly ash with lower natural alkalinity. Though

bituminous fly ash (classified as ‘Class F’ fly ash) may contain calcium, it tends to be present in a glassy

matrix and unavailable for acid

- base neutralization reactions.

In order to assess the extent of ex pected natural neutralization, the 2010 ICR 32 

### data was examined.

According to that data, units burning some of the subbituminous coals without operating acid gas control

technology emitted substantially lower HCl emissions than would otherwise be expected f rom the chlorine

content of those coals The data also showed that some other units burning subbituminous or lignite coals

with higher levels of Cl were achieving 50

- 85 % HCl control with only cold

- side ESP (i.e., with no flue gas

desulfurization or other a cid gas control technology). Comparing the Cl content of the subbituminous

coals modeled in IPM with the ICR results supports an assumption that combustion of those coals can

expect to experience at least 75% natural HCl neutralization from the alkaline fl y ash. Therefore, the HCl

emissions from combustion of lignite and subbituminous coals are reduced by 75% in EPA Base Case

v.5.13.

32 Collection Effort for New and Existing Coal

- and Oil

- Fired Electricty Utility Steam Generating Units (EPA ICR

No.2362.01 (OMB Control Number 2060

- 0631)

### 5

- 22 Table 5

- 14 Illustrative Activated Carbon Injection (ACI) Costs (2011$) for Representative Sizes and Heat Rates

under the Assumptions in EPA Base Case v.5.13

Control Type Heat Rate

(Btu/kWh) Capacity

Penalty (%) Heat Rate

Penalty (%) Variable O&M

cost (mills/kWh) Capacity (MW)

100 300 500 700 1000

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) Fixed

O&M

($/kW

- yr) Capital

Cost

($/kW) Fixed

O&M

($/kW

- yr)

ACI System with an

Existing ESP 9,000

- 0.10 0.10 2.19 37.89 0.32 14.90 0.13 9.65 0.08 7.25 0.06 5.35 0.04

10,000

- 0.11 0.11 2.43 38.51 0.32 15.14 0.13 9.81 0.08 7.36 0.06 5.44 0.05

Sorbent Injection

Rate of 5 lbs/million

acfm 11,000

- 0.12 0.12 2.68 39.07 0.33 15.35 0.13 9.95 0.08 7.47 0.06 5.52 0.05

ACI System with an

Existing Baghouse 9,000

- 0.04 0.04 1.57 33.03 0.28 12.98 0.11 8.41 0.07 6.32 0.05 4.66 0.04

10,000

- 0.04 0.04 1.75 33.54 0.28 13.18 0.11 8.54 0.07 6.42 0.05 4.74 0.04

Sorbent Injection

Rate of 2 lbs/million

acfm 11,000

- 0.05 0.05 1.92 34.02 0.29 13.38 0.11 8.66 0.07 6.51 0.06 4.81 0.04

ACI System with an

Additional

Baghouse 9,000

- 0.64 0.64 0.47 291.26 1.02 219.74 0.77 195.35 0.68 181.36 0.63 167.98 0.59

10,000

- 0.64 0.65 0.52 314.32 1.10 238.18 0.83 212.02 0.74 196.97 0.69 182.55 0.64

Sorbent Injection

Rate of 2 lbs/million

acfm 11,000

- 0.65 0.65 0.57 336.91 1.18 256.26 0.90 228.37 0.80 212.28 0.74 196.83 0.69

Note: The above cost estimates assume bituminous coal consumption.

### 5

- 23

5.5.2 HCl Removal Rate Assumptions for Existing and Potential Units

SO 2 

### emission controls o n existing a nd new (potential) uni t s provide the HCl reductions indic a ted in Table

5

- 15

. New supercritic a l pulverized coal units (col um n 3) that the model builds i n clude FGD (wet or dry)

which is assumed t o provide a 99% removal rate for HCl. For ex i s ting conventional pulverized coal uni t s

with pre

- exist i ng FGD (column 5), the HCl rem o val rate is assumed to be 5% higher than t he reported SO 2



### rem o v a l rate up to a max i mum o f 99% removal. In addition, for fluidized be d combusti o n units (c o l um n 4)

with no FGD and no fabric fil t er, the HCl removal rate is assumed to be the same as the SO 2 

### removal rate

up to a max i mum of 9 5 %. FBCs with fabric filt e rs are assumed to have an HCl rem o val rate of 95%.

Table 5

- 15 HCl Removal Rate Assumptions for Potential (New) and Existing Units

in EPA Base Case v.5.13

Potential (New) Existing Units with FGD

Gas Controls Supercritical

Pulverized Coal with

Wet or Dry FGD Fluidized Bed

Combustion (FBC) Conventional

Pulverized Coal (CPC)

with Wet or Dry FGD Existing Coal Steam Units with

FGD Upgrade Adjustment

HCl Removal

Rate 99% Without fabric filter:

Same as reported SO 2 removal rate up to a

maximum of

95%

−−−

With fabric filter: 95% Reported SO 2

removal rate +

5% up to a

maximum of

99% If reported SO 2 removal < 90%, unit

incurs cost to upgrade FGD, so that

SO 2 removal is 90%. Then, the

resulting HCl removal rate is 99%

−−− If reported SO 2 removal is ≥ 90% and

< 94%, then the unit incurs a cost to

upgrade FGD and the HCl removal

rate is 99%. (The SO 2 removal rate

remains as reported.)

−−− If the reported SO 2 removal rate is ≥

94%, the unit incurs no upgrade cost

and the HCl removal rate is 99%.



### In EPA Base Case v.5.13, coal steam units with existing FGD that do not achieve an SO 2 

### removal rate of

at least 90% are assumed to upgrade their FGDs in order to obtain at least 90% SO 2 

### removal and 99%

HCl removal. The cost of this “FGD Upgrade Adjustment” is assumed to be $100/kW and is considered

a sunk cost for modeling purposes.

5.5.3 HCl Retrofit Emission Control Options

The retro f it options for HCl emission control a r e discussed in detail in the following sub

- sectio n s and

summarized in

### 5

- 24

Table 5

- 16 . The scrubber upgrade adjustment was disc u ssed above in 5.5.2.

Wet and Dry F GD

In addition t o providing SO 2 

### reductions, wet sc r ubbers (Limestone Forced Oxidation, LSFO) a n d dry

scrubbers (Lime Spray Dryer, LSD) reduce HCl as well. For both LSFO and LSD the HCl removal rate is

assumed to be 99% with a floor of 0.0001 l b s/MMBtu. T his is summarized in columns 2

- 5 of

### 5

- 25

Table 5

- 16

.

### 5

- 26 Table 5

- 16 Summary of Retrofit HCl (and SO 2 

### ) Emission Control Performance

Assumptions in v.5.13

Performance

Assumptions Limestone Forced Oxid ation (LSFO) Lime Spray Dryer (LSD) Dry Sorbent Injection (DSI)

SO 2 HCl SO 2 HCl SO 2 HCl

Percent

Removal 96%

with a floor of

0.06 lbs/MMBtu 99%

with a floor of

0.0001 lbs/MMBtu 92%

with a floor of

0.08 lbs/MMBtu 99%

with a floor of

0.0001

lbs/MMBtu 70% 90%

with a floor of 0.0001

lbs/MMBtu

Capacity

Penalty Calculated based on characteristics of

the unit:

See Table 5

- 3 Calculated based on characteristics

of the unit:

See Table 5

- 3 Calculated based on

cha racteristics of the unit:

See

Excerpt from Table 5

- 22 Heat Rate

Penalty

Cost (2011$)

Applicability Units ≥ 25 MW Units ≥ 25 MW Units ≥ 25 MW

Sulfur Content

Applicability Coals ≤ 3.0 lbs of SO 2 /MMBtu Coals ≤ 2.0 lbs of

SO 2 /MMBtu

Applicable

Coal

Types BA, BB, BD, BE, BG, BH, SA, SB, SD,

SE, LD, LE, LG, LH, PK and WC BA, BB, BD, BE, SA, SB, SD, SE, LD,

and LE BA, BB, BD, SA, SB, SD,

and LD



### Dry Sorbent Injection

EPA Base Case v.5.13 includes dry sorbent injection ( D SI) a s a retrofit option for achi ev ing (in

combination with a particulate cont r ol device) b oth SO 2 

### and HCl rem o v a l. In DSI for HCl reduction, a dry

sorbent is inject e d in t o the flue g a s duct whe r e it reacts with the HCl and SO 2 

### in the flue gas to form

compounds that are t h en captured in a downstream fabric filter or electrosta t ic precipitator (ESP) and

d isposed of as waste. (A sorbent is a material that takes up another su b s tance by either adsorption on its

su r fa c e or abs o rption inter n ally or in solution. A sorbent may also chemically react with another

s u bstance.) T he sorbent a ssumed in t he cost and performance characterization di scussed in t his sec t ion

is Trona (sodium sesquicarbonate), a s o dium

- rich material with major underground deposits found in

Sweetwa t er C ounty, Wyoming. Trona is typically delivered with an average particle size of 30 μm

d iameter, but can be red u ced to about 15 μm through ons i te in

- line mil l ing to incre a se its surface area and

capture cap a bility.

Rem o val rate assumpti o n s : The removal rate assumptions f or DSI are summarized in

### 5

- 27

Table 5

- 16 . The assumptions shown in the last two col u mns of

### 5

- 28

Table 5

- 16 were derived from assessmen t s by EPA e n gineering s t aff in consultation with Sargent &

Lundy. As indicated in this table, the assumed SO 2 

### rem o val rate for DSI + fabric filter is 70%. The ret r ofit

DSI option on an existing uni t with existing ESP is always provided in combination with a fabric filter

(Toxecon configuration) in EPA Base Case v.5.13.

Methodology for Obtaining DSI Con t rol Costs : Sargent & Lundy’s updated performance/cost model for

DSI is used in EPA Base Case v.5.13 to derive the cost o f DSI retrofits with two alternative, associa t ed

particulate control de v ices, i.e., ESP and fabric filter “baghouse”. Their analysis of DSI noted that t h e cost

drive r s of DSI are quite differ e nt from those of wet or dry FGD. Whereas p lant size a n d coal s u lfur rates

are k e y underlying determinants of FGD cost, sorbent f eed rate and fly ash waste handling are the main

drivers of the capital cost of DSI with plant size and coal s u lfur rates pl ay ing a sec o ndary role.

In EPA Base Case v.5.13 the DSI sorbent feed rate a n d variable O&M costs are based on assumptio n s

that a fabr i c filter and i n

- line trona milling are u s ed, and th a t the SO 2 

### removal rate is 70%. The

corresponding HCl removal effect is assumed to be 90%, b a sed on info rm ation from Solv a y Chemicals (H.

Davidso n

, Dry Sorbent Injection f or Multi

- pollutant Control Case Stud y

, CIBO IECT VIII, August, 2010 )

.

The cost of f ly ash waste handling, t h e other key contributor t o DSI cost, is a function of the type of

particula t e capture d e vice and the flue gas SO 2



### .

Total waste production involves the production o f both react e d and unreacted sorbent and fly ash.

Sorbent waste is a function of t he sorbent f eed rate with an adjus tm ent for ex c ess sorbent feed. Use of

sodium

- based DSI may make the fly ash unsalable, w hich would mean that any fly ash produc e d must be

landfilled a l o ng with the reacted and unreacted sorbent waste. Typical a s h contents for each fuel are us e d

to calc u la t e a total fly ash production rate. T h e fly ash production is a dded to the sorbent waste to accou n t

for the total waste stre a m for the VOM ana l ysis.

For purpos e s of modeli n g, the total VOM includes the first t wo component costs n o ted in the previous

paragraph, i.e., the costs f or sorbent us a ge and the costs associ a ted with waste production a nd dispos a l.

Table 5

- 17 presents the capital, VOM, and FOM costs a s well as the ca p acity and heat rate penalties of a

DSI retrofit for an ill u s t rative and representative set of gene r ating units w ith the capaciti e s a nd heat rat e s

indica t ed. See Attachment 5

- 5 ( www.epa.gov/airmarkets/progsregs/epa

- ipm/BaseCasev513.html ) for

details on the Sargent & Lundy DSI model.



## 5.6 Fabric Filter (Baghouse) Cost Development

Fabric filters are not endogenously modeled as a separate retrofit option. In EPA Base Case v.5.13 , an

existing or new fabric filter particulate control device is a pre

- condition for installing a DSI retrofit, and the

cost of t hese retrofits at plants without an existing fabric filter include the cost of installing a new fabric

filter. This cost was added to the DSI costs discussed in section 5.5.3.2. The costs associated with a new

fabric filter retrofit are derived from Sarge nt & Lundy’s performance/cost model. Similarly, dry scrubber

retrofit costs also include the cost of a fabric filter.

The engineering cost analysis is based on a pulse

- jet fabric filter which collects particulate matter on a

fabric bag and uses air pulses to dislodge the particulate from the bag surface and collect it in hoppers for

removal via an ash handling system to a silo. This is a mature technology that has been operating

commercially for more than 25 years. “Baghouse” and “fabric filters” are used interchangeably to refer to

such installations.

Capital Cost : The major driver of fabric filter capital cost is the “air

- to

- cloth” (A/C) ratio. The A/C ratio is

defined as the volumetric flow, (typically expressed in Actual Cubic Feet per Minute, ACFM) of flue gas

entering the baghouse divided by the areas (typically in square feet) of fabric filter cloth in the baghouse.

The lower the A/C ratio, e.g., A/C = 4.0 compared to A/C = 6.0, the greater the area of the cloth required

### 5

- 29

and the higher the cost for a given volumetric flow. An air

- to

- cloth ratio of 4.0 is used in EPA Base Case

v.5.13, and it is assumed that the existing ESP remains in place and a c tive.

Table 5

- 18 presents the capital, VOM, and FOM costs for fabric filte r s as represented in EPA Base Case

v.5.13 for an ill u st r ative set of generating u nits with a r epresentative range of capaciti e s a nd heat rat e s.

See Attachment 5

- 7 ( www.epa.gov/airmarkets/progsregs/epa

- ipm/BaseCasev513.html ) for details of the

Sargent & Lundy fabric filter PM control model.

### 5

- 30 Table 5

- 17 Illustrative Dry Sorbent Injection (DSI) Costs for Representative Sizes and Heat Rates

u nder Assumptions in EPA Base Case v.5.13

Control Type Heat Rate

(Btu/kWh ) SO 2

Rate

(lb/

MMBtu) Capacity

Penalty (%) Heat Rate

Penalty

(%) Variable O&M

(mills/kWh) Capacity (MW)

100 300 500 700 1000

Capital

Cost

($/kW) Fixed

O&M

($/kW

- yr) Capital

Cost

($/kW) Fixed

O&M

($/kW

- yr) Capital

Cost

($/kW) Fixed

O&M

($/kW

- yr) Cap ital

Cost

($/kW) Fixed

O&M

($/kW

- yr) Capital

Cost

($/kW) Fixed

O&M

($/kW

- yr)

DSI 9,000 2.0

- 0.64 0.65 8.49 138.5 3.71 63.1 1. 38 43.7 0.88 34.4 0.65 31.6 0.52

Assuming

Bituminous

Coal 10,000 2.0

- 0.71 0.72 9.44 142.8 3.75 65.0 1.40 45.1 0.89 35.1 0.66 35.1 0.55

11,000 2.0

- 0.79 0.79 10.39 146.8 3.78 66.9 1.41 46.4 0.90 38.6 0.69 38.6 0.58



### Table 5

- 18 Illustrative Particulate Controls for Costs (2011$) for Representative Sizes and Heat Rates

under the Assumptions in EPA Base Case v.5.13

Coal Type Heat Rate

(Btu/kWh) Capacity

Penalty (%) Heat Rate

Penalty (%) Variable

O&M

(mills/kWh) Capacity (MW)

100 300 500 700 1000

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) Fixed

O&M

($/kW

yr ) Capital

Cost

($/kW) Fixed

O&M

($/kW

yr)

Bituminous 9,000

- 0.60 0.60 0.05 251 0.9 204 0.7 185 0.6 174 0.6 162 0.6

10,000 0.06 274 1.0 222 0.8 202 0.7 189 0.7 177 0.6

11,000 0.07 296 1.0 240 0.8 218 0.8 204 0.7 191 0.7

### 5

- 31

5.6.1 MATS Filterable Particulate Matter (PM) Compliance

EPA Base Case v.5.13 assumes that all coal

- fired generating units with a capacity greater than 25 MW

will comply with the MATS filterable PM requirements through the operation of either el ectrostatic

precipitator (ESP) or fabric filter (FF) particulate controls. The control mechanism is not modeled

endogenously but supplied as an input when setting up the run as specified below.

Units with existing fabric filters are assumed to be able to meet the filterable PM compliance requirement.

For units with existing ESPs the following procedure is used to determine if they already meet the

filterable PM requirement, can meet it by one of three possible ESP upgrades, or can only meet it by

install ing a FF.

First, PM emission rate data derived either from 2005 EIA Form 767 or (where available) from EPA’s

2010 Information Collection Request 33 

### are compared to the applicable filterable PM compliance

requirement. If the unit’s emission rate is equal to or less than the compliance requirement, adequate

controls are assumed already to be in place and no additional upgrade costs are imposed. For units that

do not meet the filterable PM compliance requirement, the incremental reduction needed (in lbs/mmBtu )

is calculated by subtracting the filterable PM compliance standard from the reported emission rate.

Depending on the magnitude of the incremental reduction needed, the unit is assigned one of three ESP

upgrade costs (designated ESP1, ESP2, and ESP3) or the cost of a FF installation (designated ESP4), if

the required incremental reduction cannot be achieved by an ESP upgrade. Table 5

- 19 shows the four

levels of ESP upgrades (column 1), the key technologies included in each upgrade (column 2), trigger

points for the upgrades (column 3), the capital cost of each upgrade (column 4), and the percent increase

in collection efficiency provided by the upgrade, differentiate d according to the rank (subbituminous,

bituminous, or lignite) of coal burned.

The percentage improvements in collection efficiency shown in column 5 in Table 5

- 19 are additive in the

sense that the values shown in this column are added to the pre

- upgrade collection efficiency to obtain

the after

- upgrade collection efficiency.

Table 5

- 19 Electrostatic Precipitator (ES P) Upgrades as Implemented in EPA Base Case v.5.13

--- Characteristics, Trigger Points, Associated Costs, and Performance Improvements

Upgrade

Level Key Technologies

Employed in

Upgrade Trigger Points for ESP

Upgrade

(Expressed in terms of

incremental reduction

needed (lbs/mmBtu) to

meet the filterable PM

Compliance Standard) Capital Cost Additive Percent Improvement e in

Collection Efficiency as a Result of

the Upgrade (differentiated by the

rank of coal combusted)

1 High Frequency transformer

rectifie r

(TR) sets > 0.0 to ≤ 0.005 $55/kW a 0.12 for subbituminous

0.05 for bituminous

0.01 for lignite

2 High frequency transformer

rectifier

(TR) sets + New internals

(rigid electrodes, increased

plate spacing, increased

plate height) > 0.005 to ≤ 0.01 $80/kW b 0.25 for subbituminous

0.10 for bituminous

0.02 for lignite

33 2005 EIA Form 767 is the last year where the data was reported in the format of lb/ MMBtu, which is compatible

with this analysis. Since any changes to facilities since 2005 would likely have improved (reduced) emissions, the

use of this data is conservative. More recent 2010 ICR test data is used where available. (Collection Effort fo r New

and Existing Coal

- and Oil

- Fired Electricty Utility Steam Generating Units (EPA ICR No.2362.01 (OMB Control

Number 2060

- 0631).

### 5

- 32

Upgrade

Level Key Technologies

Employed in

Upgrade Trigger Points for ESP

Upgrade

(Expressed in terms of

incremental reduction

needed (lbs/mmBtu) to

meet the filterable PM

Compliance Standard) Capital Cost Additive Percent Improvement e in

Collection Efficiency as a Result of

the Upgrade (differentiated by the

rank of coal combusted)

3 High frequency transformer

rectifier

(TR) sets + New internals

(rigid electrodes, increased

plate spacing, increased

plate height) + Additional field > 0.01 to ≤ 0.02 $100/kW c 0.50 for subbituminous

0.20 for bituminous

0.05 for lignite

4 Replacement with fabric filter

(baghouse) > 0.02 Use capital cost

equations for a

fabric filter d (Not Applicable)

a Assumes upgrading the specific collection area (SCA) to 250 square

- feet/1000 afm (actual feet per minute).

b Assumes upgrading the specific collection area (SCA) to 300 square

- feet/1000 afm (actual feet per minute).

c Assumes upgrading the existing specific collection area (SCA) by 100 square

- feet/1000 afm (actual feet per minute), a 2 0% height increase, and

additional field.

d The cost equations for fabric filters are described in Section 5.5.4

e The percentage improvement due to the ESP upgrade as shown in this column is added to the pre

- upgrade collection efficiency to obtain the after

upgrade collection removal efficiency.



### Excerpt from Table 5

- 20 contains a complete listing of coal generating units with either cold

- or hot

- side

ESPs but no fabric filters. For each generating unit in Excerpt from Table 5

- 20 shows the incremental

reductions needed to meet the PM filterable compliance requirement and the corresponding ESP upgrade

(if any) assigned to the unit to enable it to meet that requirement. A filterable PM limit of 0.279 lb/mmBtu

was used in this analysis. This value is roughly 10% below the limit in the final MATS rule, therefore

resulting in a conservative estimate of the need to upgrade existing ESPs.



## 5.7 Coal

- to

- Gas Conversions 34



### In EPA Base C ase v.5.13 exi s ting coal plants are given the option to burn natural gas in addition to coal by

investing in a co al

- to

- gas retr o fit. There a r e two components of c o st in this option: Boiler modification

costs a n d the cost of extending natural gas l a teral pipeli n e spurs from the boiler to a natural gas main

pipeline

. These two components of c o st and their associa t ed performance implicatio n s are dis c ussed in

the f o llowing sec t ions.

5.7.1 Boiler Modifications For Coal

- To

- Gas Conversions

Enabling na t ural gas firi n g in a coal b oiler typically involves i n stallation of new gas burners and

modificatio n s to the duc t ing, windbox (i.e., the c h amber surrounding a b u rner through which pressurized

air is sup p li e d for fuel c o mbustion), and possibly t o the heati n g surfaces u sed to transfer en e rgy from the

exiting hot flue gas to s t eam (referr e d to as the “ convection pass”). It may also involve modification of

environmental equipment. Engineering studies are performed to assess o perating ch a racteristics like

furnace h eat absorption and exit gas temperature; material changes affecting piping a n d components like

sup e rheaters, reheaters, economizers, and reci r c ulating fans; and operational chang e s to sootbl o w ers,

spray flows, air heaters, and emission c o ntrols.

34 As disc u ssed here coa l

- to

- gas conv e rs i on ref e rs to the modificatio n o f a n exis t in g boil e r t o allo w i t t o fire natura l g a s

. I t doe s no t refe r t o th e addi t io n o f a ga s t urbi n e to an e x isting boil e r cycle, the re p l ace m ent of a coal boi l er with a n e w

natural g a s combin e d cyc l e plant, or to the g a sificati o n of coal for u se in a natural g as comb u stion turbine

### 5

- 33

Excerpt from Table 5

- 20 ESP Upgrade Provided to Existing Units without Fabric Filters so that

They Meet Their Filterable PM Compliance Requirement

This is a small excerp t of the data in Excerpt from Table 5

- 20 . The complete data set in spreadsheet

format can be downloaded via the link found at www.epa.gov/airmarkets/pro gsregs/epa

ipm/BaseCasev513.html )

Plant Name Unit ID State

Name Unique ID Capacity

(MW) Level of

ESP

Upgrade

Required

to Meet

Filterable

PM

Requirement

A B Brown 2 Indiana 6137_B_2 245

---

AES Beaver Valley Partners Beaver Valley 2 Pennsylvania 10676_B_2 43 ESP

- 4

AES Beaver Valley Partners Beaver Valley 3 Pennsylvania 10676_B_3 43 ESP

- 4

AES Beaver Valley Partners Beaver Valley 4 Pennsylvania 10676_B_4 43 ESP

- 1

AES Cayuga 1 New York 2535_B_1 150

---

AES Cayuga 2 New York 2535_B_2 151

---

AES Deepwater AAB001 Texas 10670_B_AAB001 139

---

AES Somerset LLC 1 New York 6082_B_1 681

---

Allen Steam Plant 1 Tennessee 3393_B_1 245

---

Allen Steam Plant 2 Tennessee 3393_B_2 245

---

Allen Steam Plant 3 Tennessee 3393_B_3 245

---

Alma B4 Wisconsin 4140_B_B4 51

---

Alma B5 Wisconsin 4140_B_B5 77 ESP

- 4

Ames Electric Services Power Plant 7 Iowa 1122_B_7 33

---

Ames Electric Services Power Plant 8 Iowa 1122_B_8 70

---

Apache Station 2 Arizona 160_B_2 175

---

Apache Station 3 Arizona 160_B_3 175

---

Asbury 1 Missouri 2076_B_1 213 ESP

- 4

Asheville 1 North Carolina 2706_B_1 191

---

Asheville 2 North Carolina 2706_B_2 185

---



### The followi n g table summarizes the cost and pe r formance assumptions f or coal

- to

- gas boiler modificatio n s

as incorp o rated in EPA Base Case v.5.13

. T h e values in t he table were developed by EPA’s en g ineering

sta f f based on t echnical papers 35 

### and discussions wi t h industry engineers f a miliar with such projec t s

. They

were designed to be applica b le across t h e existing coal fleet.

Table 5

- 21 Cost and Performance Assumptions for Coal

- to

- Gas Retrofits

Factor Description Notes

Applicabilit y : Existing pulverized coal (PC) fired and

cyclone boiler units of a size gr e ater

than 25 MW: Not applica b le for fluidized bed

combustion (FBC) and stoker boilers.

Capacity Penalty: None The furnace of a boiler d esigned to burn coal is

oversized f o r natural gas, and c o al boilers

include equipment, such as coal mills, that are

not needed for gas. As a result, burning gas

should have no impact on net power output.

35 For an exa m ple s e e Babcock and Wil c ox’ s Whit e P a pe r MS

- 1 4 “Natura l G a s Conversio n s o f Exiting Coa l

- Fired

B oilers” 2 010 ( www.babcock.c o m/library/tech

- utility.html#1 4 ).

### 5

- 34 Factor Description Notes

Heat Rate

Penalt y : + 5% When gas is combusted instead of coal, the

st a ck temperature is lower and the moisture

loss to stack is higher. This reduces

efficiency, which is reflected in an increase in

the heat ra t e.

Incremental Capital

Cost: PC units: $/kW

= 267 *(75/M W )^0.35

Cyclone units: $/kW

=

374 *(75/M W )^0.35 The cost fu n ction covers new gas burners and

piping, win d box modificatio n s, air heater

upgrades, gas recirc u l ating fans, a nd control

s y stem m odificatio n s.

Ex a m ple for 50 MW PC unit:

$/kW

= 267 *(75/50)^0.35

= 308

Incremental

Fixed O&M: - 33% of the FOM cost of the existing

coal unit Due to reduced needs f or operators,

maintenance materials, and maintenance staff

when natural gas combusted, FOM costs

decrease by 33%.

Incremental

Variable O&M: - 25% of the VOM cost of the existing

coal unit Due to reduced waste disposal and

miscellane o us other costs, VOM costs

d e cr e ase by 25%.

Fuel Cost: Natural gas To obtain n a tural gas the unit incu r s the cost of

ex tending lateral pipeline spurs from the boiler

location to the natural gas transmission

pipeline

. See section 5.7.2.

NO

x emiss i on rate: 50% of existing coal u n it NO

x emission ra t e, with a fl o or of

0.05 lbs/MMBtu The 0.05 lbs/MMBtu floor is the same as the

NO

x rate floor for new retrofit SCR on units

bu r ning subbituminous coal

SO 2 emiss i ons: Zero



### 5.7.2 Natural Gas Pipeline Requirements For Coal

- To

- Gas Conversions

For every i n dividual coal boiler in the U.S., EPA t asked ICF to determine the miles and associa t ed cost of

extending pipeli n e laterals fr o m each boiler to the interstate n a tural gas pi p eline system.

To develop these cos t s t he following principl e s were applied:

For each boiler, gas vol u me was estimated based on size a n d heat rate.

Direct dista n ce to the cl o sest pip e line was calcul a ted. (The a nalysis only considered mainlines with

diameters that were 16 inches or greater. The lateral dis t ance represented the shortest distance

– “ as

the crow flies”

– bet w een the boiler and the mainline.)

Gas volume (per day) of the initi a l la t eral was not allowed to exceed more than 10 percent of t h e

estimated capacity of t he mainline.

The mainline capaci t ies were estimated from the pipe’s dia m eter using t h e Weymou t h equatio n 36



### .

If the gas r e quirement exceeded 10 percent of t h e estimated capacity of t he mainline, the cost of a

second lat e ral to conn e ct to the next closest mainline was c a lculated.

This proce d ure was repeated until t he entire c a pacity required for the b oiler was reached.

Diameters of each later a l were then calculated u sing the W e ymouth eq u ation based on their requir e d

capaci t ies.

36 Th e W e ymou t h equatio n i n classica l flui d dy na mi cs i s us e d i n calculatin g compressibl e g a s flo w as a f u n ct io n of

pipelin e diam e t e r an d fricti o n factors

. I t i s use d fo r pipe sizing.

### 5

- 35

The cost of all the later a ls was calc u lated based on the pipeline diameter and mileage required. T hus,

the fin a l pipeline c o st for each b oiler was b a sed on the t otal miles of laterals req u ired.

Figure 5

- 1 shows the calculations p e rformed.

Figure 5

- 1 Calculations Performed in Costing Lateral Pipeline Requirement

There are several points to not e a b out the above app r oach. First, for relatively large boile r s or in cases

whe r e the clos e s t mainline h as a relativ e ly small diameter, mult i ple laterals are required to connect t he

boiler to t he interstate gas transmission grid. This assur e s that each individual boiler will n o t become a

relatively large portion of a pipelines’ t ransmission capacity. It also reflects real

- w orld practices where

larger gas

- f i r ed power plants typically have multiple laterals connecting t hem to different mainlines. This

inc r eases the r e liability of their gas sup p ly and provides m u ltiple opti o ns for gas purchase all o wi n g them to

capture favorable prices from multiple so u rces of gas supply at di f ferent points in time.

Second, expansion of mainlines was not includ e d in the boiler specific pipeline cost, because the

integrat e d gas model within IPM already inc l udes corrid o r expansion capabili t ies. However, if in future IP M

runs, multiple conv e rted boilers are concent r ated on a single pipeli n e along a corridor that includes

multiple pip e lines, a furth e r assessm e nt may be r e quired to make sure that the mainline expansion is n ot

b eing unders t ated due to modeled efficienci e s that may not actually be available in t he field.

Figures 5

- 2 through 5

- 7 summarize the results of the pipeline costing pr o cedure described above. They

provide histograms of the number of laterals r e quired per b oiler (

### 5

- 36

Figure 5

- 2 ), miles of pipeline r equired per boiler ( Figure 5

- 3 ), diameters of the laterals in i n ches (

### 5

- 37

Figure 5

- 4 ), total inch

- mi les o f laterals re q uired per bo i ler ( Figure 5

- 5 ), total cost to each bo i ler in millio n $

( Figure 5

- 6 ), and c o st (in $) per kW of boiler capacity ( Figu re 5

- 7 ). Excerpt from Table 5

- 22 sh ow s the

pipeline costing r esults for e a ch qualifying existing co a l fired unit r e presented in EPA Base Case v.5.13.

### 5

- 38 Figure 5

- 2 Number of Laterals Required per Boiler

Figure 5

- 3 Miles of Pipeline Required per Boiler

### 5

- 39 Figure 5

- 4 Diameter of Laterals

Figure 5

- 5 Total Inch

- Miles of Laterals Required per Boiler

### 5

- 40 Figure 5

- 6 Total Cost to Each Boiler

Figure 5

- 7 Cost per kW of Boiler Capacity

### 5

- 41 Excerpt from Table 5

- 22 Cost of Building Pipelines to Coal Plants

This is a small excerpt of the data in Table

- 22. The complete data set in spreadsheet format can be

downloaded via the link found at http://www.epa.gov/airmarkets/progsregs/epa

- ipm/BaseCasev513.html

.

Unique ID Plant Name Sta te Name Coal Boiler

Capacity

(MW) Number

of

Laterals

Required Miles of

New Pipeline

Required to

Hook Up Unit

(miles) Cost of New

Pipeline

(2011$) Cost of New

Pipeline

per KW

of Coal

Capacity

(2011$/kW)

3_B_1 Barry Alabama 138 2 8.5 2324786 16.85

3_B_2 Barry Alabama 137 2 8.5 2136794 15.60

3_B_3 Barry Alabama 249 2 8.5 7209727 28.95

3_B_4 Barry Alabama 362 2 8.5 8979092 24.80

3_B_5 Barry Alabama 726 2 8.5 12412831 17.10

7_G_1 Gadsden Alabama 64 1 28.7 22383509 349.74

7_G_2 Gadsden Alabama 66 1 28.7 22617875 342.70

8_B_10 Gorgas Alabama 703 2 68.4 87979597 125.15

8_B_6 Gorgas Alabama 103 1 7.6 6250679 60.69

8_B_7 Gorgas Alabama 104 1 7.6 6269532 60.28

8_B_8 Gorgas Alabama 161 1 7.6 7407093 46.01

8_B_9 Gorgas Alabama 170 1 7.6 7533473 44.31

10_B_1 Greene County Alabama 254 1 6.9 7898586 31.10

10_B_2 Greene County Alabama 243 1 6.9 7776757 32.00

26_B_1 E C Gaston Alabama 254 1 23.0 26126943 102.86

26_B_2 E C Gaston Alabama 256 1 23.0 26294370 102.71

26_B_3 E C Gaston Alabama 254 1 23.0 26143766 102.93

26_B_4 E C Gaston Alabama 256 1 23.0 26143766 102.12

26_B_5 E C Gaston Alabama 842 3 162.4 201898208 239.78

47_B_1 Colbert Alabama 178 1 0.7 725276 4.07

47_B_2 Colbert Alabama 178 1 0.7 722785 4.06

47_B_3 Colbert Alabama 178 1 0.7 722785 4.06

47_B_4 Colbert Alabama 178 1 0.7 723409 4.06

47_B_5 Colbert Alabama 472 2 4.6 5183155 10.98

50_B_7 Widows Creek Alabama 473 3 253.0 231385577 489.19

50_B_8 Widows Creek Alabama 465 3 253.0 227553333 489.36

51_B_1 Dolet Hills Louisiana 638 4 28.3 28812871 45.16

56_B_1 Charles R Lowman Alabama 80 1 17.3 13132673 164.16

56_B_2 Charles R Lowman Alabama 235 2 43.8 38349442 163.19

56_B_3 Charles R Lowman Alabama 235 2 43.8 38128365 162.25

59_B_1 Platte Nebraska 100 1 25.8 21561000 215.61

60_B_1 Whelan Energy Center Nebraska 77 1 8.1 6169545 80.12

60_B_2 Whelan Energy Center Nebraska 220 1 8.1 9036600 41.08

87_B_1 Escalante New Mexico 247 2 11.4 7831404 31.71

108_B_SGU1 Holcomb Kansas 362 5 77.1 43429164 119.97

113_B_1 Cholla Arizona 116 1 27.5 23648324 203.86

113_B_2 Cholla Arizona 260 1 27.5 32391059 124.58

113_B_3 Cholla Arizona 271 1 27.5 32691880 120.63

### 5

- 42



## 5.8 Natural Gas Co

- firing

Existing coal plants with existing natural gas pipelines have an option of co

- firing with natural gas. Gas

co

- firing at these units is limited to 10% of the unit’s power output.

The option of co

- firing with gas at an existing coal boiler is only offered if one of the following two criteria

based on 2012 EIA 860

, 2012 EIA Form 923 and NEEDS v.5.13 is met: (1) the unit reported the use of

gas as a startup fuel, or (2) an existing gas

- fired unit (e.g., NGCC) is located at the same facility (with the

same ORIS) as the coal

- fired unit. EPA assumes that in either of these cases, sufficient pipeline capacity

exists to supply up to 10% of total power output of the coal steam boiler located at these sites. These

units are detailed below in Excerpt from Table 5

- 23

.

Similar to the coal

- to

- gas retrofit option, there is a 5% increase in heat rate for the share of generation

fueled by natural gas (accounting for the increased flue gas moisture and stack heat loss). On a $/kWh

basis, any change in capital or operating costs of co

- firing with natural gas at low levels is very small.

Hence, EPA do not include additional capital or operating costs for this option.

Excerpt from Table 5

- 23 List of Coal S team U nits with Natural Gas Co

- firing option

This is a small excerpt of the data in Excerpt from Table 5

- 23

. The complete data set in spreadsheet

format can be downloaded via the link found at http://www.epa.gov/airmarkets/progsregs/epa

ipm/BaseCasev513.html

UniqueID Plant Name ORIS Code State N ame Capacity ( MW )

10684_G_TG5 Argus Cogen Plant 10684 California 7

1077_G_3 Sutherland 1077 Iowa 78

1554_G_2 Herbert A Wagner 1554 Maryland 135

2943_G_3 Shelby Municipal Light Plant 2943 Ohio 5

511_G_1 Trinidad 511 Colorado 3.8

54407_G_1 Waupun Correctional Central Heating Plt 54407 Wisconsin 0.2

54407_G_2 Waupun Correctional Central Heating Plt 54407 Wisconsin 0.5

56564_G_1 John W Turk Jr Power Plant 56564 Arkansas 609

56785_G_WG01 Virginia Tech Power Plant 56785 Virginia 2.5

7_G_1 Gadsden 7 Alabama 64

7_G_2 Gadsden 7 Alabama 66

728_G_4 Yates 728 Georgia 133

728_G_5 Yates 728 Georgia 135

10_B_1 Greene County 10 Alabama 254

10_B_2 Greene County 10 Alabama 243