Prepared for: 

Dominion Energy, Inc. 

BART Analysis for the Kincaid 

Power Plant 

ENSR Corporation 

January 2009 

Document No.: 02285-076-400 
Prepared for: 

Dominion Energy, Inc. 

BART Analysis for the Kincaid 

Power Plant 

__________________________________________________________ 

Prepared By: Olga Kostrova and Ian Thomson 

_________________________________ 

Reviewed By: Robert Paine 

ENSR Corporation 

January 2009 

Document No.: 02285-076-400 
i January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

Contents 

Executive Summary ...........................................................................................................................................1

1.0 Introduction ............................................................................................................................................ 1-1

2.0 Background Data ................................................................................................................................... 2-1

2.1 Overview of BART Emission Units.................................................................................................. 2-1

2.2 Existing Control Technologies......................................................................................................... 2-1

2.3 Baseline Emissions ......................................................................................................................... 2-1

3.0 Emission Control Alternatives............................................................................................................. 3-1

3.1 SO2 Control...................................................................................................................................... 3-1

3.1.1 Technical Feasibility of Alternative SO2 Controls ............................................................. 3-1

3.1.2 Impacts of Alternative SO2 Controls.................................................................................. 3-4

3.1.3 Discussion of Candidate SO2 Control Technologies ........................................................ 3-5

3.2 NOX Emission Controls.................................................................................................................... 3-6

3.2.1 Technical Feasibility of Alternative NOx Controls ............................................................. 3-6

3.2.2 Discussion of Candidate NOx Control Technologies........................................................ 3-7

3.3 PM Emission Control....................................................................................................................... 3-7

3.4 Control Scenarios ............................................................................................................................ 3-8

4.0 Meteorological Data used in Visibility Improvement Modeling....................................................... 4-1

4.1 Elements of the Refined Analysis ................................................................................................... 4-1

4.2 CALMET Processing ....................................................................................................................... 4-1

5.0 CALPUFF Modeling Procedures.......................................................................................................... 5-1

5.1 CALPUFF Modeling Domain and Receptors.................................................................................. 5-1

5.2 Technical Options Used in the Modeling ........................................................................................ 5-1

5.3 Natural Conditions and Monthly f(RH) at Class I Areas................................................................. 5-1

5.4 Light Extinction and Haze Impact Calculations .............................................................................. 5-2

6.0 CALPUFF Modeling and BART Determination Results.................................................................... 6-1

6.1 Modeled Control Scenarios............................................................................................................. 6-1

6.2 Modeling Results for Baseline Emissions....................................................................................... 6-1

6.3 Modeling Results for the Alternative Control Cases....................................................................... 6-1

6.4 Cost of BART Control Cases .......................................................................................................... 6-4

6.5 Conclusions ..................................................................................................................................... 6-6
ii January 2009 BART Analysis for Kincaid Power Station 

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7.0 References.............................................................................................................................................. 7-1

List of Appendices 

Appendix A Meteorological Stations used in CALMET Processing 

List of Tables 

Table ES- 1 Regional Haze Impacts Due to Baseline and BART Control Emissions..............................ES-2 

Table ES- 2 8th Highest Regional Haze Impacts Averaged Over 3 Years Due to Baseline and BART Control 

Option Emissions....................................................................................................................ES-3 

Table ES-3 Visibility Improvement and Annual Costs for Each Control Option at Mammoth Cave .......ES-3 

Table 2-1 Kincaid Baseline Emissions ..................................................................................................... 2-3

Table 2-2 Kincaid Baseline Stack Parameters......................................................................................... 2-3

Table 3-1 Total Capital and Annual Costs Associated with Technically Feasible SO2 Control Technologies 

Applied to Kincaid Units 1 and 2.............................................................................................. 3-4

Table 3-2 Kincaid Future DSI with Trona Emissions (Case 1).............................................................. 3-10

Table 5-1 MRPO Ozone and Ammonia Seasonal Concentrations......................................................... 5-1

Table 5-2 Annual Average Natural Background Concentrations ............................................................ 5-2

Table 6-1 Regional Haze Impacts Due to Baseline and BART Control Emissions ................................ 6-2

Table 6-2 Visibility Improvement and Annual Costs for Each Control Case at Mingo ........................... 6-4

Table 6-3 Visibility Improvement and Annual Costs for Each Control Case at Mammoth Cave ........... 6-5
iii January 2009 BART Analysis for Kincaid Power Station 

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List of Figures 

Figure ES- 1 8th Highest Regional Haze Impacts Averaged Over 3 Years Due to Baseline and BART Control 

Option Emissions....................................................................................................................ES-2 

Figure ES-2 Annual Costs vs. Visibility Improvements..............................................................................ES-4 

Figure 4-1 Kincaid CALMET and CALPUFF Modeling Domain............................................................... 4-3

Figure 4-2 Location of Meteorological Stations used in CALMET Processing ........................................ 4-4

Figure 6-1 8th Highest Regional Haze Impacts Averaged Over 3 Years Due to Baseline and BART Control 

Emissions.................................................................................................................................. 6-2

Figure 6-2 Regional Haze Impacts For Top 8 Days Averaged Over 3 Years: Cases 1, 1a, and 2........ 6-3

Figure 6-3 Annual Costs vs. Visibility Improvements................................................................................ 6-6
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Executive Summary 

Federal regulations under Title 40 of the Code of Federal Regulations (CFR) Part 51 Appendix Y provide 

guidance and regulatory authority for the application of Best Available Retrofit Technology (BART) to those 

existing eligible sources in order to help meet the targets for visibility improvement at designated Class I areas. 

The IEPA has identified the two coal-fired boilers, Units 1 and 2, at Dominion’s Kincaid Power Plant as BARTeligible emission units. This BART analysis will be reviewed and used by the Illinois Environmental Protection 

Agency (IEPA) for development of the state’s Regional Haze State Implementation Plan (SIP). 

The BART rules require that sources that are subject to BART perform a site-specific BART analysis including 

a control technology review and CALPUFF modeling to assess the visibility impact of the emission units. 

Additionally, for large Electric Generating Units (EGU) affected by the rule, the source should meet 

presumptive control levels for nitrogen oxide (NOX) and sulfur dioxide (SO2) unless it is determined that 

alternative control levels are justified or equivalent in effectiveness. The presumptive BART limits for these 

units are continuous year-round operation of the existing SCR systems at 0.10 pound per million British 

thermal unit (lb/MMBtu) for NOX and 0.15 lb/MMBtu or 95 percent control for SO2. 

This report documents the case-by-case BART analysis conducted for NOx, SO2, and PM10 emissions from 

Kincaid Units 1 and 2. The following BART control scenarios were evaluated: 

• Case 1. Firing 0.3%-sulfur PRB sub-bituminous coal, Dry Sorbent Injection (DSI) with Trona capable 

of achieving an SO2 emissions level of 0.20 lb/MMBtu and enhanced year-round operation of the SCR 

at a NOx emission level of 0.07 lb/MMBtu. 

• Case 1a. Firing 0.3%-sulfur PRB sub-bituminous coal, enhanced DSI with Trona capable of achieving 

an SO2 emissions level of 0.18 lb/MMBtu (if achievable), enhanced year-round operation of the SCR 

at a NOx emission level of 0.07 lb/MMBtu, and replacement of the existing Electrostatic Precipitators 

(ESP) with Fabric Filters (FF). 

• Case 2. Firing 0.5%-sulfur PRB sub-bituminous coal, Dry Scrubber/Fabric Filter (DS/FF) capable of 

achieving an SO2 emissions level of 0.15 lb/MMBtu and year-round operation of the SCR at a NOx

emission level of 0.10 lb/MMBtu. 

• Case 3. Firing 1.62%-sulfur Illinois Basin bituminous coal, Wet Flue Gas Desulfurization (WFGD) 

capable of achieving an SO2 emissions level of 0.15 lb/MMBtu and year-round operation of the SCR 

at a NOx emission level of 0.10 lb/MMBtu. 

Kincaid Units 1 and 2 currently employ high-efficiency Electrostatic Precipitators (ESP) to control Particulate 

Matter (PM) emissions. Based upon peak stack test measurements in 1999, the baseline PM emission rates 

for Units No. 1 and 2 are 0.011 and 0.008 lb/MMBtu, respectively. These emissions are significantly below the 

permitted PM emission limit of 0.10 lb/MMBtu. The new FF, DS/FF or WFGD systems are capable of 

achieving a vendor-guaranteed filterable PM emission level of 0.015 lb/MMBtu. The DSI with Trona system 

has the potential for significant reductions in PM emissions1

. However, for conservatism, Dominion has 

assumed that there will not be any appreciable effect on filterable PM emission levels, and they are assumed 

to remain at the baseline levels. However, we do account for an estimated 50% reduction in H2SO4 removal 

due to Trona injection. 

 

1

 PM10 filterable and condensable emissions were reduced by approximately 47% during the demonstration testing at the 

Mirant Potomac River Station. The test report can be found at: 

http://www.mirant.com/our_business/where_we_work/Unredacted_Trona_Test_Report_011706BC.pdf
ES-2 January 2009 BART Analysis for Kincaid Power Station 

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CALPUFF modeling results for meteorological database years 2002-2004 were obtained for the two PSD 

Class I areas within 300 km of the Kincaid Generating Station: Mingo Wilderness Area in Missouri and 

Mammoth Cave National Park in Kentucky. The results of the baseline emissions indicate that the 8th highest 

visibility impacts at Mingo and Mammoth Cave are above the 0.5 delta deciview significance threshold. 

Therefore, a BART determination analysis was conducted. 

CALPUFF modeling results for visibility improvements due to application of the four SO2 control cases at the 

two Class I areas are tabulated in Table ES-1 and graphically plotted in Figure ES-1. The table indicates that 

substantial visibility improvements occur with the implementation of the Case 1 or 1a (dry sorbent injection with 

Trona) and Case 2 (dry scrubber/fabric filter) controls, with lesser improvement for the Case 3 (WFGD) 

controls. In fact, no perceptible visibility impacts (defined by a 98th percentile change of at least 0.5 deltadeciview) occur at either Class I area in any modeled year with the implementation of emission controls 

associated with Cases 1/1a or 2. 

Table ES-1 Regional Haze Impacts Due to Baseline and BART Control 
ES-3 January 2009 BART Analysis for Kincaid Power Station 

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Figure ES-1 8th Highest Regional Haze Impacts Averaged Over 3 Years Due to Baseline and BART 

Control Case 

Dominion Kincaid

Regional Haze Impacts Due to Units 1&2 Baseline and BART Control Emissions

3-Year Average 8th Highest Impacts

1.37

1.22

0.30

0.25 0.27

0.23 0.25

0.46

0.40

0.26

0.0

0.5

1.0

1.5

Mingo Wilderness Mammoth Cave National Park

Class I Area

8th Highest delta-deciview

Baseline: 0.3% S PRB Coal, Seasonal

SCR, ESP

Case 1: 0.3% S PRB Coal, DSI/Trona,

Enhanced year-round SCR, ESP

Case 1a: 0.3% PRB Coal, Enhanced

DSI/Trona, Enhanced year-round SCR,

FF

Case 2: 0.5% S PRB Coal, year-round

SCR, DS, FF

Case 3: 1.62% S Illinois Coal, 

year-round SCR, ESP, WFGD
ES-4 January 2009 BART Analysis for Kincaid Power Station 

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Tables ES-2 and ES-3 list the projected annualized control cost that is a function of the capital and annual 

operating costs, as well as fixed capital charges estimated by Dominion Energy. The table also presents a 

computation of each control case’s visibility improvement effectiveness and cost relative to the baseline 

conditions, since each control case is independent of the others. The visibility results in Tables ES-2 and ES-3 

are based on the 8th highest regional haze impacts at Mingo and Mammoth Cave, respectively, averaged over 

the three years. Figure ES-2 presents a graph of visibility improvements as a function of the cost for each 

control case. It is evident from the figure that BART Case 1/1a (DSI with Trona) is clearly the most costeffective case for the visibility improvement attained (although the incremental improvement from Case 1 to 1a 

has a markedly steeper cost slope than from the baseline to Case 1, almost as steep as the slope for the Case 

2 and 3 options). Therefore, we conclude that the recommended BART control case is Case 1: the use of 

Trona injection and enhanced SCR performance operation. The ability for an SO2 emission rate lower than 

0.20 lb/MMBtu to be achieved in practice with the use of DSI with Trona will be determined from operational 

experience. 

Table ES- 2 Visibility Improvement and Annual Costs for Each Control Case at Mingo WA 

Control Casea

8th Highest at 

Mingo 

3-Yr Ave 

(delta-dv) 

Annualized Cost for 

Unit 1 & 2 

($/Year) 

Incremental Cost 

Effectiveness from 

Baseline ($/dv) 

Baseline: 0.3%S PRB Coal, Seasonal 

SCR, ESP 1.37 $0 $0 

Case 1: 0.3% S PRB Coal, DSI/Trona, 

Enhanced year-round SCR, ESP 0.30 $24,820,000b

 $23,100,000 

Case 1a: 0.3% S PRB Coal, enhanced DSI 

with Trona, Enhanced year-round SCR, FF 0.27 $32,210,000c

 $29,210,000 

Case 2: 0.5% S PRB Coal, year-round 

SCR, DS, FF 0.26 $94,700,000d

 $85,060,000 

Case 3: 1.62%S Illinois Coal, year-round 

SCR, ESP, WFGD 0.46 $125,370,000e

 $137,220,000 

a These costs are based on 2008 dollars. 

b

 When Case 1 costs are projected to 2014 dollars (based upon a 2014 installation date), the annualized cost becomes 

$30,660,000 and the incremental cost effectiveness from the baseline becomes $28,530,000. 

c

 When Case 1a costs are projected to 2014 dollars (based upon a 2014 installation date), the annualized cost 

becomes $41,320,000 and the incremental cost effectiveness from the baseline becomes $37,470,000. 

d

 When Case 2 costs are projected to 2017 dollars (based upon a 2017 installation date), the annualized cost becomes 

$156,110,000 and the incremental cost effectiveness from the baseline becomes $140,220,000. 

e

 When Case 3 costs are projected to 2017 dollars (based upon a 2017 installation date), the annualized cost becomes 

$200,430,000 and the incremental cost effectiveness from the baseline becomes $219,370,000. 
ES-5 January 2009 BART Analysis for Kincaid Power Station 

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Table ES-3 Visibility Improvement and Annual Costs for Each Control Case at Mammoth Cave 

a These costs are based on 2008 dollars. 

b

 When Case 1 costs are escalated to 2014 dollars (based upon 2014 installation date) the Annualized Cost becomes 

$30,660,000 and the Incremental Cost Effectiveness from the baseline becomes $31,770,000. 

c

 When Case 1a costs are projected to 2014 dollars (based upon a 2014 installation date), the annualized cost 

becomes $41,320,000 and the incremental cost effectiveness from the baseline becomes $41,960,000. 

d

 When Case 2 costs are escalated to 2017 dollars (based upon 2017 installation date) the Annualized Cost becomes 

$156,110,000 and the Incremental Cost Effectiveness from the baseline becomes $161,880,000 

e

 When Case 3 costs are escalated to 2017 dollars (based upon 2017 installation date) the Annualized Cost becomes 

$200,430,000 and the Incremental Cost Effectiveness from the baseline becomes $244,530,000. 

Control Casea

8th Highest at 

Mammoth 

Cave 

3-Yr Ave 

(delta-dv) 

Annualized Cost for 

Unit 1 & 2 

($/Year) 

Incremental Cost 

Effectiveness from 

Baseline ($/dv) 

Baseline: 0.3%S PRB Coal, Seasonal SCR, 

ESP 1.22 $0 $0 

Case 1: 0.3% S PRB Coal, DSI with Trona, 

Enhanced year-round SCR, ESP 0.25 $24,820,000b

 $25,720,000 

Case 1a: 0.3% S PRB Coal, enhanced DSI 

with Trona, Enhanced year-round SCR, FF 0.23 $32,210,000c $32,710,000 

Case 2: 0.5% S PRB Coal, year-round 

SCR, DS, FF 0.25 $94,700,000d

 $98,200,000 

Case 3: 1.62%S Illinois Coal, year-round 

SCR, ESP, WFGD 0.40 $125,370,000e

 $152,950,000 
ES-6 January 2009 BART Analysis for Kincaid Power Station 

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Figure ES-2 Annual Costs vs. Visibility Improvements 

$0

$20,000,000

$40,000,000

$60,000,000

$80,000,000

$100,000,000

$120,000,000

$140,000,000

1.5 1.4 1.3 1.2 1.1 1.0 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0

8th Highest delta-dv (Average of 3-Years)

Cost ($/year)

Mingo

Mammoth

Baseline

Case 2

Case 3

Case 1

Case 1A
1-1 January 2009 BART Analysis for Kincaid Power Station 

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1.0 Introduction 

Federal regulations under Title 40 of the Code of Federal Regulations (CFR) Part 51 Appendix Y provide 

guidance and regulatory authority for conducting a visibility impairment analysis for designated eligible 

sources. The program requires the application of Best Available Retrofit Technology (BART) to those existing 

eligible sources in order to help meet the targets for visibility improvement at designated Class I areas. The 

BART analysis will be reviewed and used by the Illinois Environmental Protection Agency (IEPA) for 

development of the state’s Regional Haze State Implementation Plan (SIP). The IEPA has identified the two 

coal-fired boilers, Units 1 and 2, at Dominion’s Kincaid Power Plant as BART-eligible emission units. 

The BART rules require that sources that are subject to BART perform a site-specific BART analysis including 

a control technology review and CALPUFF modeling to assess the visibility impact of the emission units. 

Additionally, for large Electric Generating Units (EGU) affected by the rule, the source should meet 

presumptive control levels for nitrogen oxide (NOX) and sulfur dioxide (SO2) unless it is determined that 

alternative control levels are justified or equivalent in effectiveness. The presumptive BART limits for these 

units are continuous year-round operation of the existing SCR systems at 0.10 pound per million British 

thermal unit (lb/MMBtu) for NOX and 0.15 lb/MMBtu or 95 percent control for SO2. 

The BART analysis was conducted in accordance with the procedures contained in the Final BART Guidelines 

published by the USEPA on July 6, 2005. Consistent with the BART Guidelines, the five steps for a case-bycase BART analysis were followed. 

1. Step 1 – Identify all available control technologies for the unit including improvements to existing 

control equipment or installation of new add-on control equipment. 

2. Step 2 – Eliminate technically infeasible options considering the commercial availability of the 

technology, space constraints, operating problems and reliability, and adverse side effects on the rest 

of the facility. 

3. Step 3 – Evaluate the control effectiveness of the remaining technologies based on current pollutant 

concentrations, flue gas properties and composition, control technology performance, and other 

factors. 

4. Step 4 – Evaluate the annual and incremental costs of each feasible option in accordance with 

approved EPA methods, as well as the associated energy and non-air quality environmental impacts. 

5. Step 5 – Determine the visibility impairment associated with baseline emissions and the visibility 

improvements provided by the control technologies considered in the engineering analysis. 

The regulation further requires a formal choice of BART based on the above data, plus the degree of 

improvement in visibility (impacts), which may be reasonably anticipated to result from the installation or 

implementation of the proposed BART. Economic analysis, remaining useful life of the plant, and impacts on 

facility operation that are a cost consequence of air pollution control equipment may be considered in the final 

BART decision-making process. 

This report documents the case-by-case BART analysis conducted for SO2, NOx and PM emissions from 

Units 1 and 2 at the Kincaid Power Station. Section 2.0 provides a description of Kincaid Units 1 and 2 and 

their baseline emissions. Section 3.0 provides a discussion of SO2, NOx and PM control technologies. The 

available meteorological data and the CALPUFF modeling procedures are described in Sections 4.0 and 5.0, 

respectively. The results of the visibility improvement modeling using CALPUFF are presented in Section 6.0, 

along with the BART recommendation. References are listed in Section 7.0.
2-1 January 2009 BART Analysis for Kincaid Power Station 

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2.0 Background Data 

2.1 Overview of BART Emission Units 

The BART-affected emission units at the Kincaid Power Plant are Units 1 and 2. Units 1 and 2 commenced 

commercial operation in 1967 and 1968, respectively. The two units began operation during the time period 

(1962-1977) targeted by the Regional Haze BART Rule. Units 1 and 2 are cyclone-fired boilers manufactured 

Babcock & Wilcox. These two units each have a rated capacity of 4,200,000 lb/hr of superheated steam at 

2,620 psig and 1,005°F. The steam is directed to dedicated turbine-generators each with a rated capacity of 

660 MW. Because the plant has a total rated capacity in excess of 750 MW, Units 1 and 2 are subject to 

presumptive BART controls in accordance with the Regional Haze BART Rule. 

2.2 Existing Control Technologies 

Kincaid Units 1 and 2 are both equipped with over fire air (OFA) systems and selective catalytic reduction 

(SCR) to control NOx emissions. Kincaid’s permit requires the SCR system need only be operated during the 

ozone season (May 1st through September 30th) and must achieve a NOx emission level of 0.15 lb/MMBtu 

during that period. Units 1 and 2 are also equipped with electrostatic precipitators (ESPs) to control PM 

emissions. The ESPs must achieve a filterable PM emission level of at least 0.10 lb/MMBtu according to the 

station’s permits. Units 1 and 2 currently burn low-sulfur Powder River Basin (PRB) sub-bituminous coal to 

control SO2 emissions. Based on historical emissions, the sulfur content of the PRB coal generally does not 

exceed 0.3% by weight. 

2.3 Baseline Emissions 

For the purposes of determining BART eligibility, the SO2 and NOx baseline emissions were determined using 

measurement data collected by the continuous emissions monitoring system (CEMS) during the years 2002 

through 2006. Filterable PM baseline emissions were determined using the highest results of the latest stack 

tests conducted in November 1999. 

The SO2 and NOx baseline emission rates were derived from maximum daily emissions measured by the 

CEMS) during the years 2002 through 2006. The PM emissions were derived from the results of stack tests 

conducted in November 1999. Speciation of the particulate matter emissions into filterable and condensable 

PM10 components was determined using the following approach: 

• Filterable PM was subdivided by size category consistent with the default approach cited in AP-42, 

Table 1.1-8. For cyclone furnaces equipped with ESPs, 68% of the filterable PM emissions are 

filterable PM10 and 36% of the PM emissions are fine filterable PM10 emissions (less than 2.5 microns 

in size). 

• For coal-fired boilers, elemental carbon is expected to be 3.7% of fine filterable PM10 based on the 

best estimate for electric utility coal combustion in Table 6 of “Catalog of Global Emissions Inventories 

and Emission Inventory Tools for Black Carbon”, William Battye and Kathy Boyer, EPA Contract No. 

68-D-98-046, January 2002. 

• Condensable inorganic PM10 emissions, assumed to consist of H2SO4, are based on procedures 

presented in “Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical 

Update, March 2007 (and reaffirmed in a March 2008 update). For coal-fired boilers, H2SO4

emissions are determined by the following relationship: 
2-2 January 2009 BART Analysis for Kincaid Power Station 

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E = (Q)(98.06/64.04)(F1)(F2) 

where: E is the H2SO4 emission rate (lb/hr), 

Q is the baseline SO2 emission rate (lb/hr), 

F1 is the fuel factor (0.0018 for PRB sub-bituminous coal), and 

F2 is the control factor (0.56 for an air pre-heater and 0.73 for a cold-side ESP). 

Note that, although Units 1 and 2 are equipped with SCR, the maximum daily NOx baseline emissions 

occur when the SCR system is off-line during the non-ozone season. 

• For pulverized coal-fired boilers burning coal with a sulfur content of 0.5% or less, total condensable 

organic PM10 emissions factor is 0.002 lb/MMBtu based on AP-42, Table 1.1-5. Because AP-does not 

have an emission factor for total condensable organic PM10 emissions from cyclone boilers, AP-42 

directs you to the use the pulverized coal emission factor for cyclone boilers. 

Table 2-1 provides a summary of the SO2, NOx, and PM emissions that were used in the modeling analysis for 

baseline conditions. Table 2-2 then provides the stack parameters that were used in the baseline conditions 

modeling analysis. 
2-3 

BART Analysis for Kincaid Power Station 02285-076-400

Table 2-1 Kincaid Baseline Emissions 

Table 2-2 Kincaid Baseline Stack Parameters 

Case UTM Northing (m) UTM Easting (m) Base Elevation (m) Stack Height (m) Stack Diameter (m) Flue Gas Temperature (°K) Flue Gas 

Rate (m

Baseline 4,385,605.6 284,850.0 182.87 186.69 9.03 410.93 1,673.2
3-1 January 2009 BART Analysis for Kincaid Power Station 

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3.0 Emission Control Alternatives 

The visibility impairing pollutants discussed in this section include NOX, SO2, and PM. Information on control 

of these pollutants through application of a control device, combination of devices, and/or operational change 

is provided. 

3.1 SO2 Control 

Sulfur dioxide emissions are generated in fossil fuel-fired combustion units from the oxidation of sulfur present 

in the fuel. Approximately 98% of the sulfur in coal is emitted upon combustion as gaseous sulfur oxides, SO2

and SO3. Uncontrolled emissions of SO2 are directly related to the fuel sulfur content, and not by the firing 

mechanism, boiler size, or operation. Many coal-fired boilers in the U.S. limit emissions of SO2 through the 

use of low sulfur western coals, including Powder River Basin Coal. Compared with higher sulfur eastern 

bituminous coal that may contain as much as 4% sulfur, the practice of burning western coal can reduce SO2

emissions by approximately 70% to 90%. However, control equipment can generally remove a higher 

percentage of the SO2 from higher sulfur coal than lower sulfur coal. The selection of coal type and sulfur 

content, therefore, is an important aspect of the determination of BART and needs to be considered in 

conjunction with add-on control alternatives when performing the BART analysis. 

The Unit 1 and 2 boilers currently burn low-sulfur PRB coal to limit SO2 emissions. Alternative SO2 control 

technologies available to further reduce SO2 emission from the coal-fired boilers include Dry Scrubber/Fabric 

Filter (DS/FF), Wet Flue Gas Desulfurization (WFGD) and Dry Sorbent Injection (DSI) with Trona. This 

analysis is limited to these control technologies: 

• Lime or limestone based WFGD capable of achieving 90 to 95% control; 

• Lime DS/FF capable of achieving 80 to 90% control; 

• DSI with Trona capable of achieving approximately 60% control; 

The technical feasibility, performance, and economic, energy, and environmental impacts of the alternative 

SO2 control technologies are addressed in the remainder of this section. 

3.1.1 Technical Feasibility of Alternative SO2 Controls 

The technical feasibility and performance levels of the alternative SO2 control technologies are evaluated 

below in terms of their application to Kincaid Units 1 and 2. 

 Wet Flue Gas Desulfurization 

WFGD typically uses limestone or lime to react with SO2 from coal-fired boilers. The temperature of the flue 

gas is reduced to its adiabatic saturation temperature and the SO2 is removed from the flue gas by reaction 

with the alkaline medium. SO2 is absorbed into the scrubbing slurry, which falls into the lower section of the 

vessel known as the reaction tank. Finely ground limestone and make-up water are added to the reaction 

tank to neutralize and regenerate the scrubbing slurry. 

Limestone scrubbing introduces limestone slurry into the scrubber. The sulfur dioxide is absorbed, 

neutralized, and partially oxidized to calcium sulfite and calcium sulfate. The overall reactions are shown in 

the following equations: 

CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2

CaSO3 •1/2 H2O + 3H2O + O2 → 2 CaSO4 •2 H2O 
3-2 January 2009 BART Analysis for Kincaid Power Station 

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Lime scrubbing is similar to limestone scrubbing in equipment and process flow, except that lime is a more 

reactive reagent than limestone. The reactions for lime scrubbing are as follows: 

Ca(OH)2 +SO2 → CaSO3• 1/2 H2O + 1/2 H2O 

Ca(OH)2 + SO2 + 1/2 O2 + H2O → CaSO4•2 H2O 

Whether limestone or lime is used as the reagent for SO2 removal, additional equipment is needed for 

preparing the lime/limestone slurry and collecting and concentrating the resultant sludge. Calcium sulfite 

sludge is difficult to mechanically dewater and is typically stabilized with fly ash for landfilling. Calcium sulfate 

sludge is stable and is readily mechanically dewatered. To produce calcium sulfate, an air injection blower is 

needed to supply the oxygen for the second reaction to occur (forced oxidation). 

WFGD is most effective in reducing SO2 emissions resulting from combustion of high-sulfur coals. In addition, 

the water consumption in a WFGD system is high due to water retained in the sludge and water losses to the 

atmosphere. Make-up water is added to the reaction tank and is recirculated through the gas stream. A 

WFGD will consume approximately 8 to 10% more water than a spray dryer system. In addition to higher 

water demand, a WFGD system has a number of environmental impacts including generating an additional 

solid waste stream and an additional liquid waste stream. 

WFGD has been applied on many coal-fired boilers in the United States. These installations have been 

demonstrated to consistently achieve SO2 removal efficiencies ranging from 90% to in excess of 95%. These 

high SO2 control efficiencies would provide Dominion with an opportunity to use higher sulfur Illinois 

bituminous coal and still meet the presumptive BART limit of 0.15 lb/MMBtu. Although the delivered price for 

PRB sub-bituminous coal currently is less than that for local Illinois bituminous coal, rail transportation costs 

have recently been increasing dramatically due to increases in the price of diesel fuel, so the price differential 

between PRB and local Illinois coal could narrow considerably or disappear in the future. Over the past two 

years alone, transportation costs have almost doubled and are expected to continue rising with the price of 

diesel fuel. There is also a concern about the reliability of the rail transportation from Wyoming, due to recent 

incidents of derailments and delays in PRB coal shipments. 

If Dominion were required to install WFGD for SO2 control, therefore, they would consider the use of mediumsulfur (<2.5%) sulfur Illinois coal to allay concerns about the rising costs of transporting PRB sub-bituminous 

coal to the site and to promote the use of locally mined coal to improve the Illinois economy. For the 

purposes of the visibility analysis, it is assumed that the WFGD system will be applied to Units 1 and 2 firing 

~1.62% sulfur Illinois-bituminous coal and will achieve an outlet SO2 emission level of 0.15 lb/MMBtu, 

consistent with the presumptive BART limit. 

 Dry Scrubber and Fabric Filter 

Use of a dry scrubber technology requires a dry scrubber to be located upstream of the particulate collection 

device. The flue gas passes through a spray dryer vessel, where it encounters a finely atomized alkaline lime 

slurry. The lime slurry is injected into the dry scrubber through either a rotary atomizer or fluid nozzles. 

Evaporation of the water produces a finely divided particle of mixed salt and un-reacted alkali and reduces 

flue gas temperatures. The flue gas is cooled to approximately 20 to 30°F above the adiabatic saturation 

temperature of the flue gas. A portion of the dry powder drops to the bottom of the scrubbing vessel, while 

the flue gases containing the remaining reacted salts and un-reacted lime are delivered to the particulate 

collection device. The calcium salts have a moisture content of approximately 2 to 3%, which drops to 1% 

before reaching the particulate control device. 

In the absorbing chamber, the water in the slurry droplets is rapidly evaporated by the hot flue gases. The 

SO2 are absorbed onto the hydrated lime particles and react to form calcium salts. The reduction in flue gas 

temperature provided by the evaporating water has been shown to be a major factor influencing the removal 

of acid gases. Studies have shown that SO2 removal efficiencies are significantly higher when the dry 
3-3 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

scrubber is operated at temperatures approaching the saturation temperature of the flue gas. As a result of 

the scrubbing process, a dry, free-flowing powder is produced consisting of un-reacted lime and reacted salts 

(most prevalent being CaSO3 and CaSO4). The largest of these particles are separated by gravity from the 

gas in the absorbing chamber by gravity and fall to the bottom. The smaller particles are carried to the PM 

control device for separation from the flue gas. 

When a fabric filter is used as the particulate control device, it allows for further reaction of the lime captured 

in the filter media with the SO2 in the flue gas. This is due to the layer of porous filter cake on the surface of 

the filter that contains the reagent that all flue gas must pass through. This allows for increased efficiency of 

control of SO2 and H2SO4 as compared to wet scrubbers. This filter cake is credited with controlling pressure 

drops, dampening surges or pollutant spikes, providing a site for increased reagent utilization, and increasing 

equipment reliability. 

Dry scrubbers have been applied primarily in combination with fabric filters (FFs) on many coal-fired boilers in 

the United States. These installations have been demonstrated to consistently achieve SO2 removal 

efficiencies of 80 to 90%. For the purposes of the visibility analysis, it is assumed that the DS/FF combination 

will be applied to Units 1 and 2 firing 0.5% sulfur PRB sub-bituminous coal and will achieve an outlet SO2

emission level of 0.15 lb/MMBtu consistent with the presumptive BART limit. 

 Dry Sorbent Injection (DSI) with Trona 

A variety of manufacturers have developed DSI systems for SO2 control on coal-fired boilers. This technology 

uses very standard process equipment, including carbon steel storage silos, material handling equipment, 

blowers, and pneumatic transport piping, all of which are commodity components available from multiple 

vendors at similar cost. In order to remove SO2 compounds from hot exhaust gases, finely ground Trona, 

sodium sesquicarbonate [Na3(HCO3)], can be injected into the hot gas stream to react with the SO2 and form 

sodium sulfite (Na2SO3). The reacted salt would then be removed from the flue gas stream by the existing 

downstream particulate control devices. The main chemical reaction is as follows: 

 2(Na3(HCO3)•(CO3)•2H2O) + 3SO2 → 3Na2SO3 + 5H2O + 4CO2

A plant’s operating conditions will ultimately affect the effectiveness of DSI with Trona in removing SO2. The 

most important variables for high removal efficiency are injection temperature, SO2 concentration, fine particle 

size (~10 microns), retention time (the time the acid gases are in contact with the sorbent) and the type of 

coal utilized. 

DSI with Trona has demonstrated the following SO2 removal rates during the short term demonstration tests 

discussed below. In 2005 the Mirant Potomac River Station2

 demonstrated a maximum SO2 control of ≈80% 

while burning Central Appalachian and Columbian coals. In 2008, We Energies Presque Isle Power Plant 

demonstrated a maximum SO2 control of ≈70% while burning Powder River Basin (PRB) coal. Dominion 

estimates that for the purposes of BART implementation, DSI with Trona injection will be able to achieve an 

average SO2 control of ≈60% and an SO2 emission rate of 0.20 lb/MMBtu based upon a 30-day rolling 

average. Dominion has assumed 60% SO2 removal for PRB coal at Kincaid for several reasons, related to 

differences in the units, the limited testing scope at Presque Isle and the impact on mercury removal. Higher 

Trona injection rates during the Presque Isle tests contributed to reduced rates of mercury removal from 

Activated Carbon Injection, an issue which must be evaluated for Kincaid. Further, the Presque Isle tests 

consisted of only 8-hour injections of Trona in a 90 MW unit. Effective utilization of Trona will be more difficult 

for Kincaid's much larger 660 MW units and a 30-day rolling average presents a much greater challenge than 

an 8-hour test under optimum conditions. For example, during normal operations Kincaid operates at 

reduced loads and lower temperatures at night, which typically which reduces the reactivity of Trona. The 

 

2

 http://www.mirant.com/our_business/where_we_work/Unredacted_Trona_Test_Report_011706BC.pdf
3-4 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

Presque Isle units were tested with Trona injection upstream of a bag house while Kincaid utilizes an 

electrostatic precipitator for particulate removal. 

One advantage of the DSI with Trona injection process is that the stack temperature is not diminished 

compared to the WFGD processes that involve the use of significant amounts of water. Aside from the 

environmental benefits that result from avoiding the use of the water spray, the increased stack gas 

temperature will tend to avoid the local impacts of increased H2SO4 emissions associated with oxidation of 

SO2 to SO3 by the SCR catalyst and the subsequent formation of H2SO4 in the control equipment. 

DSI with Trona requires much lower capital investment, less physical space, and less modification to existing 

ductwork compared to a spray dryer absorber or wet scrubber. Trona is a very reactive reagent that can be 

used to achieve a range of efficiencies depending upon the amount of sorbent injected into the ductwork. 

Two cases are presented for Trona injection for SO2 control (Cases 1 and 1a), with slightly different SO2

emission rates (0.20 lb/MMBtu for Case 1 and 0.18 lb/MMBtu for Case 1a). Although the lower SO2 emission 

rate is preferred, it may not be achievable, depending upon the coal sulfur content and the effectiveness of 

the Trona removal for this specific application. 

3.1.2 Impacts of Alternative SO2 Controls 

The alternative control technologies available to control SO2 emissions from Units 1 and 2 are DSI with Trona, 

DS/FF and WFGD. This section documents the economic, non-air environmental, and energy impacts 

associated with applying alternative control technologies to Units 1 and 2. 

 Economic Impacts 

Table 3-1 presents the first-year annual capital and annual costs associated with DSI with Trona, DS/FF and 

WFGD applied to Kincaid Units 1 and 2. The capital costs for the technically feasible SO2 control 

technologies were provided by Dominion Energy. The annual fixed capital charges and annual operating 

costs were also provided by Dominion. An interest rate of 9.8% and an amortization period of 20 years were 

assumed in the calculation of the annualized costs for the BART control cases. 

Table 3-1 Total Capital and Annual Costs Associated with Technically Feasible SO2 Control 

Technologies Applied to Kincaid Units 1 and 2 

Control 

Case c Control Technology 

Total Capital 

Cost 

($)a

 Fixed Capital 

Costs 

($/yr)b

Annual O&M 

Costs 

($/yr) 

Total Annual 

Costs 

($/yr) 

1 Dry Sorbent Injection (PRB Coal) $60,000,000 $7,000,000 $17,820,000 $24,820,000 

1a Enhanced DSI/FF (PRB Coal) $163,000,000 $19,000,000 $13,210,000 $32,210,000 

2 Dry Scrubber/FF (PRB Coal) $732,580,000 $85,000,000 $9,700,000 $94,700,000 

3 WFGD (Bituminous Coal) $840,710,000 $97,000,000 $28,370,000 $125,370,000 

a

 Total capital costs for Cases 2 and 3 include $17,900,000 for removal of existing equipment; this cost for Case 1a is 

$6,000,000. In addition, total capital costs for Cases 1a and 2 include expenses associated with the fabric filter. 

b

 Fixed capital charges are based on a capital recovery factor of 0.1159, assuming an interest rate of 9.8% and an 

amortization period of 20 years. 

c

 All costs are based on 2008 dollars. 
3-5 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

 Non-Air Quality Environmental Impacts 

The preceding technology evaluation identified DSI with Trona, DS/FF and WFGD as the available SO2

control technologies providing the highest removal efficiencies relative to other technologies. Of the two 

scrubber options, the DS/FF combination is considered the preferred control technology. The disadvantages 

of WFGD compared to DS/FF system include: 

• higher water consumption or wastewater treatment requirement resulting in increased energy and 

utility operating costs; 

• liquid effluent from the wet scrubber requires pretreatment to meet regulatory requirements before 

discharge to a municipal sewer; 

• problems associated with the disposal of wet sludge resulting from the process, requiring extensive 

sludge thickening and dewatering equipment; 

• a relatively low stack gas temperature resulting in reduced buoyancy and lower plume rise, and 

hence poorer dispersion of the residual pollutants; 

• visible steam plume under most meteorological conditions, especially during periods of high relative 

humidity; and 

• corrosion, scaling and fouling of scrubber internals, requiring costly acid corrosion resistant 

construction materials for scrubber and downstream equipment. 

Furthermore, available test data demonstrate the superior effectiveness of DS/FF systems for SO2 and other 

acid gas emissions, as well as the control of secondary pollutant (i.e., trace organics and trace metals). 

As noted above, the DSI with Trona option provides significant non-air quality benefits over both scrubbing 

options: 

• no use of additional water in the FGD treatment 

• a higher stack temperature, leading to improved local air quality due to increased buoyancy and 

higher plume rise, and hence greater dispersion of the residual pollutants and 

• a lower likelihood of visible plumes, as well as fogging and icing potential. 

 Energy Impacts 

The WFGD option would consume significantly more electrical energy than the DS/FF option, while the 

DSI with Trona option would consume the least energy of any of the options. For example, the higher 

electrical energy consumption for WFGD relative to DS/FF and DSI with Trona primarily is due to the power 

required for the increased fan static pressure required to overcome the pressure drop across the 

scrubber vessel, as well as for dewatering, re-circulating pumps and material handling. WFGD applied to 

both units would consume approximately 82,000 kWh, compared to 65,000 kWh for the DS/FF compared to 

13,000 kWh for the DSI with Trona. The increased emissions of criteria pollutants required to maintain the 

net electrical output have not been incorporated into the visibility modeling. 

3.1.3 Discussion of Candidate SO2 Control Technologies 

The SO2 control technologies identified for evaluation include DSI with Trona (two possible SO2 emission 

rates), DS/FF and WFGD. Of these technologies, WFGD is capable of higher SO2 control efficiencies ranging 

from 90 to 95%, providing Dominion with the flexibility of using medium-sulfur Illinois bituminous coal. The 

DS/FF, on the other hand, is capable of achieving SO2 control efficiencies ranging from 80 to 90%, limiting 

Dominion options to low-sulfur PRB sub-bituminous or eastern bituminous coals. The DSI with Trona option 

can achieve SO2 removal rates of up to 70% when firing low-sulfur PRB coals as demonstrated at the We 

Energies Presque Isle Power Plant. The WFGD system, however, has significant disadvantages compared 
3-6 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

with the other SO2 removal options. The WFGD system has substantially higher capital and annual operating 

costs than the other SO2 removal options. Compared with these other options, WFGD would result in 

significant environmental and energy impacts, including increased power requirements, increased water 

consumption, liquid effluent requiring pretreatment, wet sludge requiring dewatering, and cooler and less 

buoyant plume. 

3.2 NOX Emission Controls 

Nitrogen oxides formed during the combustion of coal are generally classified as either thermal NOx or fuelbound NOx. Thermal NOx is formed when elemental nitrogen in the combustion air is oxidized at the high 

temperatures in the primary combustion zone yielding nitrogen oxide (NO) and nitrogen dioxide (NO2). The 

rate of formation of thermal NOx is a function of residence time and free oxygen, and increases exponentially 

with peak flame temperatures. Thermal NOx from coal combustion can be effectively controlled by techniques 

that limit available oxygen or reduce peak flame temperatures in the primary combustion zone. Fuel-bound 

NOx is formed by the oxidation of chemically bound nitrogen in the fuel. The rate of formation of fuel-bound 

NOx is primarily a function of fuel bound nitrogen content, but is affected by fuel/air mixing. 

The technologies available to control NOX from coal-fired boilers include combustion controls, such as lowNOx burners (LNB), and post-combustion techniques, such as selective non-catalytic reduction (SNCR) and 

selective catalytic reduction (SCR). Because Units 1 and 2 already incorporate combustion controls, this 

analysis is limited to the following post-combustion control technologies: 

• Selective catalytic reduction capable of 80 to 90 percent control; and 

• Selective non-catalytic reduction capable of 30 to 50 percent control. 

The Unit 1 and 2 boilers currently incorporate SCR for the control of NOx emissions during the ozone season. 

As demonstrated below, this control technology is considered the most effective in reducing NOx emissions 

from coal-fired boilers. The SCR controls would need to be operated continuously to meet the presumptive 

BART requirements 

3.2.1 Technical Feasibility of Alternative NOx Controls 

The technical feasibility and performance levels of the alternative NOx control technologies are evaluated 

below in terms of their application to Kincaid Units 1 and 2. 

 Selective Catalytic Reduction 

Selective Catalytic Reduction (SCR) is a process that involves post-combustion removal of NOx from flue gas 

utilizing a catalytic reactor. In the SCR process, ammonia injected into the flue gas reacts with NOx and 

oxygen to form nitrogen and water vapor. The SCR process converts NOx to nitrogen and water by the 

following general reactions: 

4NO + 4NH3 + O2 → 4N2 + 6H2O 

 2NO2 + 4NH3 + O2 → 3N2 + 6H2O 

The reactions take place on the surface of a catalyst. The function of the catalyst is to effectively lower the 

activation energy of the NOx decomposition reaction to about 375 to 750°F, depending on the specific catalyst 

and other contaminants in the flue gas. The factors affecting SCR performance are catalyst reactor design, 

optimum operating temperature, sulfur content of the fuel, catalyst deactivation due to aging or poisoning, 

ammonia slip emissions, and design of the ammonia injection system. 

The SCR system is comprised of a number of subsystems, including the SCR reactor, ammonia injection 

system, and ammonia storage and delivery system. Typically, the SCR reactor would be located downstream 

of the economizer and upstream of the air pre-heater and the particulate control system. From the 
3-7 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

economizer outlet, the flue gas would first pass through a low-pressure ammonia/air injection grid designed to 

provide optimal mixing of ammonia with flue gas. The ammonia treated flue gas would then flow through the 

catalyst bed and exit to the air pre-heater. The SCR system for a coal boiler typically uses a fixed bed 

catalyst in a vertical down-flow, multi-stage reactor. 

Reduction catalysts are divided into two groups: base metal, primarily vanadium, platinum or titanium, (lower 

temperature), and zeolite (higher temperature). Both groups exhibit advantages and disadvantages in terms 

of operating temperature, ammonia-NOx ratio, and optimum oxygen concentration. The optimum operating 

temperature for a vanadium-titanium catalyst system is in the range of 550° to 750°F, which is significantly 

higher than for platinum catalyst systems. However, the vanadium-titanium catalyst systems begin to break 

down when operating at temperatures above this range. Operation above the maximum temperature results 

in oxidation of ammonia to ammonia sulfate and NOx, thereby actually increasing NOx emissions. 

SCR with ammonia injection technology is a demonstrated, commercially available technology. SCR has 

been used with other coal-fired boilers; therefore, SCR is technically feasible for the control of NOX emissions 

from Units 1 and 2. Performance data from Units 1 and 2 indicate that the SCR systems are capable of NOx

removal efficiencies ranging from 85 to 90%. Based on these performance data, continuous operation of the 

SCR system will ensure that Units 1 and 2 will comply with the presumptive BART limit for cyclone furnaces of 

0.10 lb/MMBtu. 

 Selective Non-Catalytic Reduction 

Selective non-catalytic reduction is a post-combustion control technology that involves ammonia or urea 

injection into the flue gases without the presence of a catalyst. SNCR, similar to SCR, involves the reaction of 

NOX with ammonia, where a portion of the NOX is converted to molecular nitrogen and water. Without the use 

of a catalyst or supplemental fuel injection, the NOX reduction reaction temperature must be tightly controlled 

between 1,600 and 2,200°F (between 1,600 and 1,800°F for optimum efficiency). Below 1,600°F ammonia 

will not fully react, resulting in un-reacted ammonia that is emitted into the atmosphere, (referred to as 

ammonia slip). If the temperature rises above 2,200°F, the ammonia added will be oxidized resulting in an 

increased level of NOX emissions. 

SNCR with ammonia injection technology is a demonstrated, commercially available technology. SNCR has 

been used with other coal-fired boilers; therefore, SNCR is indeed technically feasible for the control of NOX

emissions from Units 1 and 2. However, NOX removal efficiencies with SNCR are lower than SCR, typically 

ranging from 30 to 50% depending on the combustion process and inlet NOx concentrations. Based on such 

performance estimates, SNCR system is not capable of achieving the presumptive BART limit of 0.10 

lb/MMBtu. Because SNCR is less effective than SCR, this technology is not considered further in this 

analysis. 

3.2.2 Discussion of Candidate NOx Control Technologies 

The NOX post-combustion control technologies identified for evaluation are SCR and SNCR. Of these 

technologies, SCR has been demonstrated to be the most effective technology in minimizing NOx emissions 

from coal-fired boilers. Further, SCR is the only technology capable of achieving the presumptive BART limit 

for cyclone furnaces. Accordingly, continuous operation of the SCR systems with a rolling 30-day emission 

rate of 0.10 lb/MMBtu is recommended as BART for Kincaid Units 1 and 2. 

3.3 PM Emission Control 

Kincaid Units 1 and 2 currently employ high-efficiency Electro-Static Precipitators (ESP) to control Particulate 

Matter (PM) emissions. The baseline PM emission rates for Units No. 1 and 2 are 0.011 and 0.008 lb/MMBtu, 

respectively. These emissions are significantly below the permitted PM emission limit of 0.10 lb/MMBtu. A 

new FF, DS/FF or WFGD are capable of achieving a vendor-guaranteed filterable PM emission level of 0.015 
3-8 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

lb/MMBtu. The DSI with Trona system has been shown significant reductions in PM3. Dominion has 

conservatively assumed that there will not be any appreciable effect on PM emission levels and are assumed 

to remain at the baseline levels. Given the high performance levels of the existing ESPs, these PM control 

devices are considered BART for Unit 1 and 2 and no additional PM controls were considered in this analysis. 

3.4 Control Scenarios 

A number of different control scenarios are possible for reduction of visibility impairing pollutants from the 

Kincaid Power Plant. Based on the anticipated performance levels, the proposed NOx and particulate control 

technologies are considered BART for Units 1 and 2. Therefore, the following SO2 control scenarios are 

included in the modeling assessment: 

• Case 1. Firing 0.3%-sulfur PRB sub-bituminous coal, Dry Sorbent Injection (DSI) with Trona capable 

of achieving an SO2 emissions level of 0.20 lb/MMBtu and enhanced year-round operation of the 

SCR at a NOx emission level of 0.07 lb/MMBtu. 

• Case 1a. Firing 0.3%-sulfur PRB sub-bituminous coal, enhanced DSI with Trona capable of 

achieving an SO2 emissions level of 0.18 lb/MMBtu (if achievable), enhanced year-round operation of 

the SCR at a NOx emission level of 0.07 lb/MMBtu, and replacement of the existing Electrostatic 

Precipitators (ESP) with Fabric Filters (FF). 

• Case 2. Firing 0.5%-sulfur PRB sub-bituminous coal, Dry Scrubber/Fabric Filter (DS/FF) capable of 

achieving an SO2 emissions level of 0.15 lb/MMBtu and year-round operation of the SCR at a NOx

emission level of 0.10 lb/MMBtu. 

• Case 3. Firing 1.62%-sulfur Illinois Basin bituminous coal, Wet Flue Gas Desulfurization (WFGD) 

capable of achieving an SO2 emissions level of 0.15 lb/MMBtu and year-round operation of the SCR 

at a NOx emission level of 0.10 lb/MMBtu. 

A DS/FF or WFGD system is capable of achieving a filterable PM emission level of 0.015 lb/MMBtu. The DSI 

with Trona system has shown significant reductions in PM4

. Dominion has conservatively assumed that there 

will not be any appreciable effect on PM emission levels and are assumed to remain at the baseline. As 

noted previously, Units 1 and 2 already incorporate OFA and SCR for NOx control. The NOx controls have 

been demonstrated of being capable of achieving a NOx emission level of 0.10 lb/MMBtu. For the DSI with 

Trona options, Dominion would commit to a NOx emission rate of 0.070 lb/MMBtu. 

The alternative control technologies will not only affect SO2 and NOX emission levels from Units 1 and 2, but 

also will affect the emissions and speciation of PM10. The PM10 emissions and speciation for modeling 

purposes were determined using the following approach: 

• Filterable PM was subdivided by size category consistent with the default approach cited in AP-42, 

Table 1.1-6. For coal-fired boilers equipped with fabric filters, 92 percent of the filterable PM 

emissions are filterable PM10 and 53 percent of the PM emissions are fine filterable PM10 emissions 

(less than 2.5 microns in size). Although not as effective in controlling fine PM, WFGD was assumed 

to have the same particle size distribution for the purposes of the visibility analysis. 

• For coal-fired boilers, elemental carbon is expected to be 3.7 percent of fine PM10 based on the best 

estimate for electric utility coal combustion in Table 6 of “Catalog of Global Emissions Inventories and 

 

3

 PM10 filterable and condensable emissions were reduced by ≈47% during the demonstration testing at the Mirant 

Potomac River Station. The test report can be found at: 

http://www.mirant.com/our_business/where_we_work/Unredacted_Trona_Test_Report_011706BC.pdf

4

 PM10 filterable and condensable emissions were reduced by ≈47% during the demonstration testing at the Mirant 

Potomac River Station. The test report can be found at: 

http://www.mirant.com/our_business/where_we_work/Unredacted_Trona_Test_Report_011706BC.pdf
3-9 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

Emission Inventory Tools for Black Carbon”, William Battye and Kathy Boyer, EPA Contract No. 68-

D-98-046, January 2002. 

• Condensable inorganic PM10 emissions, assumed to consist of H2SO4, are based on “Estimating 

Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, March 2007. 

For coal-fired boilers equipped with SCR, H2SO4 emissions are determined by the following 

relationship: 

E = (Q)(98.06/64.04)(F1+S2 F3)(F2) 

where: E is the H2SO2 emission rate (lb/hr), 

Q is the baseline SO2 emission rate (lb/hr), 

F1 is the fuel factor (0.00111 for PRB sub-bituminous coal and 0.016 for mediumsulfur eastern bituminous coal), 

S2 is the SCR catalyst SO2 oxidation rate (0.003 for PRB sub-bituminous coal and 

0.005 for eastern bituminous coal) 

F3 is the technology impact factor (0.17 for PRB sub-bituminous coal and 1.00 for 

eastern bituminous coal), 

F2 is the control factor (0.56 and 0.85 for an air heater PRB coal and bituminous 

coal, respectively, 0.73 and 0.77 for an ESP for PRB coal and bituminous coal, 

respectively, 0.5 for DSI, 0.47 for wet scrubbers, and 0.01 for a DS/FF). 

• For coal-fired boilers with FGD, the total condensable organic PM10 emission factor is 0.004 

lb/MMBtu based on AP-42, Table 1.1-5. 

Tables 3-2, 3-3, 3-4, and 3-5 provide summaries of the SO2, NOx, and PM emissions that were used in the 

modeling analysis for cases 1, 1a, 2, and 3 respectively. Table 3-6 provides the stack parameters that were 

used in the modeling for these cases. 
3-10 

BART Analysis for Kincaid Power Station 02285-076-400

Table 3-2 Kincaid Future DSI with Trona Emissions (Case 1) 
3-11 

BART Analysis for Kincaid Power Station 02285-076-400

Table 3-3 Kincaid Future Enhanced DSI with Trona Emissions (Case 1a) 
3-12 

BART Analysis for Kincaid Power Station 02285-076-400

Table 3-4 Kincaid Future DS/FF Emissions (Case 2) 
3-13 

BART Analysis for Kincaid Power Station 02285-076-400

Table 3-5 Kincaid Future WFGD Emissions (Case 3) 
3-14 

BART Analysis for Kincaid Power Station 02285-076-400

Table 3-6 Kincaid Future DSI with Trona, DS/FF and WFGD Stack Parameters 

Case Description 

UTM 

Northing 

(m) 

UTM 

Easting 

(m) 

Base 

Elevation 

(m) 

Stack 

Height 

(m) 

Stack 

Diameter 

(m) 

Flue Gas 

Temperature 

(°K) 

Flu

Flo

(

1 DSI, Enhanced SCR, ESP 4,385,605.6 284,850.0 182.87 186.69 9.03 410.93 1,6

1a 

Enhanced DSI, Enhanced SCR, FF, 

4,385,605.6 284,850.0 182.87 186.69 9.03 410.93 1,6

2 SCR, Dry Scrubber, FF 4,385,605.6 284,850.0 182.87 186.69 9.03 352.59 1,43 SCR, ESP, WFGD 4,385,605.6 284,850.0 182.87 186.69 9.03 324.82 1,3
4-1 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

4.0 Meteorological Data used in Visibility Improvement Modeling 

This section discusses refinements to the Lake Michigan Air Directors Consortium (LADCO) and Midwest 

Regional Planning Organization (MRPO) meteorological database that was used for the Kincaid BART 

modeling. 

4.1 Elements of the Refined Analysis 

ENSR made several refinements to the CALMET meteorological database produced by LADCO/MRPO for 

BART CALPUFF analyses for Midwestern States. The CALMET database derived by LADCO/MRPO has a 

domain that covers approximately a 3,492 km (east-west) by 3,240 km (north-south) area with a 36-km grid 

resolution. This area covers the entire continental United States east of the Rocky Mountains, but its large 

size limits the horizontal resolution of each grid element to 36 km. This coarse grid resolution, without further 

refinement, can be deemed appropriate for a screening-level analysis, but it would not be considered 

appropriate for a more refined analysis. 

ENSR developed a refined meteorological database that included a modeling domain encompassing the two 

Class I areas (Mingo and Mammoth Cave), the Kincaid facility, and the appropriate buffers around the source 

and Class I areas for puffs recirculation. This domain covers approximately a 486 km (east-west) by 456 km 

(north-south) area, has a grid resolution of 6 km (6 times better than the LADCO/MRPO database in both eastwest and north-south directions), and contains 10 vertical levels. The refined database utilized the same MM5 

databases that were used to develop the LADCO/MRPO 36-km CALMET database. 

In addition to the use of consistent MM5 databases with the LADCO-developed meteorological data, ENSR 

utilized similar model switches/settings, when appropriate, that were used to develop the LADCO/MRPO 

CALMET database. To improve the database even further, ENSR introduced actual surface, precipitation, and 

twice-daily upper air sounding observations into the refined meteorological database. These improvements in 

the CALMET database provide more accurate plume trajectories from the Kincaid facility to the distant Class I 

areas. 

In addition, ENSR used the latest EPA-approved versions of CALMET (Version 5.8) and CALPUFF (Version 

5.8), rather than the “old” EPA-approved versions suggested in the MRPO BART common protocol (available 

at http://www.state.in.us/idem/programs/air/workgroups/regionalhaze/docs/BART_protocol.pdf). 

4.2 CALMET Processing 

ENSR used refined 6-km grid spacing for the CALMET and CALPUFF models. The modeling domain was 

based on a 100-km buffer around the source and at least a 50-km buffer around each of the two Class I areas 

to account for puffs recirculation. The modeling domain is shown in Figure 4-1. This design creates a 486 km 

(east-west) x 456 km (north-south) domain extent at a 6-km resolution. 

A Lambert Conformal Conic (LCC) coordinate system was used and is identical to the LADCO/MRPO 

coordinate system. The LCC projection for this analysis was based on the NAS-C datum and standard 

parallels of 33 and 45 degrees North, with an origin of 40 degrees North and 97 degrees West. 

ENSR used the latest EPA-approved version of CALMET (Version 5.8, Level 070623) to produce threedimensional wind fields for three years (2002-2004). Advanced meteorological data in the form of prognostic 

mesoscale meteorological data, such as the Fifth Generation Mesoscale Model (MM5), was used to provide a 

superior estimate of the initial wind fields. This application consisted of 3 years (2002-2004) of prognostic 

MM5 meteorological data supplied by the MRPO at a 36-km resolution. 
4-2 January 2009 BART Analysis for Kincaid Power Station 

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• 2002 MM5 data set at 36 km resolution provided by CENRAP; 

• 2003 MM5 data set at 36 km resolution provided by Midwest RPO; 

• 2004 MM5 data set at 36 km resolution provided by Midwest RPO. 

These databases are consistent with those used by LADCO/MRPO for their BART assessments. 

These prognostic meteorological data sets were initially combined with the 6-km grid resolution terrain and 

land use data to more accurately characterize the wind flow throughout the modeling domain. The gridded 

terrain data was derived using the U.S. Geological Survey (USGS) 90-meter grid spacing Digital Elevation 

Model (DEM) files. These files were processed in the TERREL pre-processor program. The gridded land use 

data was derived from USGS 1:250,000 Composite Theme Grid land use files. 

The Step 2 wind fields were produced using the input of all available National Weather Service (NWS) and 

CASTNET hourly surface and twice-daily upper air balloon sounding data within the modeling domain. Figure 

4-2 shows the meteorological stations that were included in the CALMET modeling and Appendix A provides 

their names and locations. 
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Figure 4-1 Kincaid CALMET and CALPUFF Modeling Domain 
4-4 January 2009 BART Analysis for Kincaid Power Station 

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Figure 4-2 Location of Meteorological Stations used in CALMET Processing 
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5.0 CALPUFF Modeling Procedures 

This section provides a summary of the modeling procedures that were used for the refined CALPUFF 

analysis conducted for the Kincaid Power Plant. 

5.1 CALPUFF Modeling Domain and Receptors 

ENSR used the latest EPA-approved version of CALPUFF (Version 5.8, Level 070623) that has been posted 

at http://www.src.com/calpuff/download/download.htm#EPA_VERSION. 

The extents of the 6-km domain are shown in Figure 4-1. The modeling domain was based on a 100-km 

buffer around the source and at least a 50-km buffer around each of the two Class I areas plus an additional 

buffer to the east and to the west to account for puff re-circulations. The modeling domain is shown in Figure 

4-1. This design allows for a 486 km (east-west) x 456 km (north-south) domain extent, at a 6-km resolution. 

5.2 Technical Options Used in the Modeling 

For CALPUFF modeling technical options, inputs, and processing steps, the Kincaid modeling procedures 

followed the MRPO common BART protocol. 

For CALPUFF modeling, ENSR used seasonal ozone and ammonia ambient background concentrations that 

are identical to the MRPO common BART modeling protocol and are listed in Table 5-1. 

Table 5-1 MRPO Ozone and Ammonia Seasonal Concentrations 

Parameter Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

O3 (ppb) 31 31 31 37 37 37 33 33 33 27 27 27 

NH3 (ppb) 0.3 0.3 0.3 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 

Due to the large distance to the nearest Class I areas, building downwash effects were not included in the 

CALPUFF modeling. 

5.3 Natural Conditions and Monthly f(RH) at Class I Areas 

Two Class I areas were modeled for the Kincaid facility. For these Class I areas, natural background 

conditions were established in order to determine a change in natural conditions related to a source’s 

emissions. 

For BART analyses, EPA has allowed states to accept either the annual average or 20% best day’s natural 

background for BART exemption and determination modeling analyses. Regional Planning Organizations 

(RPOs) have provided guidance to states within their RPOs on what values to accept, which typically has 

varied based on the degree of the meteorological database refinement. For example, the VISTAS RPO has 

generally adopted the annual average background because it has provided member states with refined 

meteorological data sets. Since MRPO used the 36-km database with no observations, as a measure of 

conservatism, MRPO/LADCO recommended to states that the 20% best day’s background be incorporated 

into the analysis as opposed to the annual average. This measure of conservatism was taken due to concerns 

by EPA Region 5 and FLMs on the accuracy of the 36-km meteorological data in “NO-OBS” mode. However, 

Wisconsin and Indiana, both MRPO states, have stated that they would allow sources to use the annual 
5-2 January 2009 BART Analysis for Kincaid Power Station 

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average background with the 98th percentile day as opposed to the 20% best days if a site-specific 

meteorological database is developed. 

ENSR refined the meteorological database with a finer grid resolution (6-km) and by introducing surface 

observations. Having a refined meteorological database has provided ENSR with additional justification for 

using the annual average background, while evaluating visibility impacts based on the source’s impacts at the 

98th percentile day modeled results. This procedure is consistent with other eastern states and other states 

within the MRPO. 

For the modeling described in this document, ENSR used the annual average natural background 

concentrations shown in Table 5-2, modified as noted below with site-specific considerations, and 

corresponding to the annual average natural background concentrations (EPA 2003, Appendix B). 

To determine the input to CALPOST, it is first necessary to convert the deciviews to extinction using the 

equation: 

Extinction (Mm-1) = 10 exp(deciviews/10). 

For example, for Mingo, 7.43 deciviews is equivalent to an extinction of 21.02 inverse megameters (Mm-1); this 

extinction includes the default 10 Mm-1 for Rayleigh scattering. This remaining extinction is due to naturally 

occurring particles, and is held constant for the entire year’s simulation. Therefore, the data provided to 

CALPOST for Mingo would be the total natural background extinction minus 10 (expressed in Mm-1), or 11.02. 

This is most easily input as a fine soil concentration of 11.02 μg/m3

 in CALPOST, since the extinction 

efficiency of soil (PM-fine) is 1.0 and there is no f(RH) component. The concentration entries for all other 

particle constituents would be set to zero, and the fine soil concentration would be kept the same for each 

month of the year. The monthly values for f(RH) that CALPOST needs were taken from "Guidance for 

Tracking Progress Under the Regional Haze Rule" (EPA, 2003) Appendix A, Table A-3. 

Table 5-2 Annual Average Natural Background Concentrations 

Component Represented Mammoth Cave Mingo 

Soil (PM fine) (deciview) 7.69 7.43 

Soil (PM fine) (Mm-1 or μg/m3)* 21.58 21.02 

* Extinction values include Rayleigh scattering. 

5.4 Light Extinction and Haze Impact Calculations 

The CALPOST postprocessor was used for part of the calculation of the impact from the modeled source’s 

primary and secondary particulate matter concentrations on light extinction. The formula that is used in 

CALPOST is the existing IMPROVE/EPA formula, which is applied to determine a change in light extinction 

due to increases in the particulate matter component concentrations. Using the notation of CALPOST, the 

formula is the following: 

bext = 3 f(RH) [(NH4)2SO4] + 3 f(RH) [NH4NO3] + 4[OC] + 1[Soil] + 0.6[Coarse Mass] + 10[EC] + bRay

The concentrations, in square brackets, are in μg/m3

 and bext is in units of Mm-1. The Rayleigh scattering term 

(bRay) has a default value of 10 Mm-1, as recommended in EPA guidance for tracking reasonable progress 

(EPA, 2003a). 
5-3 January 2009 BART Analysis for Kincaid Power Station 

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The assessment of visibility impacts at the Class I areas applied CALPOST Method 6 (as standard with all 

BART applications). Each hour’s source-caused extinction is calculated by first using the hygroscopic 

components of the source-caused concentrations, due to ammonium sulfate and nitrate, and monthly Class I 

area-specific f(RH) values. The contribution to the total source-caused extinction from ammonium sulfate and 

nitrate is then added to the other, non-hygroscopic components of the particulate concentration (from coarse 

and fine soil, secondary organic aerosols, and from elemental carbon) to yield the total hourly source-caused 

extinction. 
6-1 January 2009 BART Analysis for Kincaid Power Station 

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6.0 CALPUFF Modeling and BART Determination Results 

This section provides a summary of the modeled visibility improvement as a result of installing BART controls 

on Kincaid Units 1 and 2. It also presents the recommended BART determination. 

6.1 Modeled Control Scenarios 

The baseline emissions were modeled along with the four alternative control emission scenarios. Tables 3-2 

through 3-5 present contain the emissions associated with the alternative control scenarios for Units 1 and 

2.

6.2 Modeling Results for Baseline Emissions 

CALPUFF modeling results of the baseline emissions at the two Class I areas are presented in Table 6-1 and 

graphically plotted in Figure 6-1. Modeling was conducted for all three years of CALMET meteorological data 

(2002-2004). For each Class I area and year, Table 6-1 lists the number of days above 0.5 and 1.0 deltadeciview due to plant emissions as well as the maximum and the 8th highest delta-deciview. Figure 6-1 

indicates that the higher visibility impacts occur at Mingo Wilderness and they are due to that park’s proximity 

to Kincaid. 

The results of the baseline emissions indicate that the 8th highest visibility impacts at Mingo and Mammoth 

Cave are above the 0.5 delta deciview threshold. 

6.3 Modeling Results for the Alternative Control Cases 

CALPUFF modeling results of the four control cases at the two Class I areas are presented in Table 6-1 and 

graphically plotted in Figure 6-1. Modeling was conducted for all three years of CALMET meteorological data 

(2002-2004). For each Class I area and year, Table 6-1 lists the number of days above 0.5 and 1.0 deltadeciview due to plant BART emission controls. 

Figure 6-1 indicates that substantial visibility improvements occur with either Case 1/1a (DSI with Trona) and 

Case 2 (DS/FF) controls and that no perceptible visibility impacts (defined by a 98th percentile change of at 

least 0.5 delta-deciview) occur at any Class I area with these controls. 

The results show that the averaged regional haze impacts with dry scrubber/fabric filter controls are reduced 

by about 1.10 delta-dv at Mingo and by 0.96 delta-dv at Mammoth Cave (relative to the baseline case). 

Nearly the same visibility improvement occurs with the use of the BART Case 3 controls, and the modeling 

results provided here have not accounted for the larger energy requirements of these controls. Installation of 

WFGD results in less improvement at the Class I areas due to the higher H2SO4 emissions associated with 

WFGD. Addition of WFGD would reduce visibility impacts by about 0.96 delta-dv at Mingo and by 0.81 deltadv at Mammoth Cave from the baseline case. 

Figure 6-2 shows a comparison between the visibility improvement over the top 8 days on average for BART 

control cases 1 and 2. This is a more robust comparison because it uses a more stable statistical sample of 

peak impact days. The results indicate that the visibility improvements available from BART cases 1 and 2 are 

essentially equivalent. 
6-2 January 2009 BART Analysis for Kincaid Power Station 

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Table 6-1 Regional Haze Impacts Due to Baseline and BART Control Emissions 

Figure 6-1 8th Highest Regional Haze Impacts Averaged Over 3 Years Due to Baseline and BART 

Control Emissions 

Dominion Kincaid

Regional Haze Impacts Due to Units 1&2 Baseline and BART Control Emissions

3-Year Average 8th Highest Impacts

1.37

1.22

0.30

0.25 0.27

0.23 0.25

0.46

0.40

0.26

0.0

0.5

1.0

1.5

Mingo Wilderness Mammoth Cave National Park

Class I Area

8th Highest delta-deciview

Baseline: 0.3% S PRB Coal, Seasonal

SCR, ESP

Case 1: 0.3% S PRB Coal, DSI/Trona,

Enhanced year-round SCR, ESP

Case 1a: 0.3% PRB Coal, Enhanced

DSI/Trona, Enhanced year-round SCR,

FF

Case 2: 0.5% S PRB Coal, year-round

SCR, DS, FF

Case 3: 1.62% S Illinois Coal, 

year-round SCR, ESP, WFGD
6-3 January 2009 BART Analysis for Kincaid Power Station 

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Figure 6-2 Regional Haze Impacts For Top 8 Days Averaged Over 3 Years: Cases 1, 1a, and 2 

3-Year Average of 8 Highest Days

0.355 0.350 0.357

0.385

0.326

0.371

0.000

0.050

0.100

0.150

0.200

0.250

0.300

0.350

0.400

Mingo Wilderness Mammoth Cave National Park

Class I Area

Average Delta-Deciview of 8 Highest Days

Case 1: 0.3% S PRB Coal, DSI/Trona,

Enhanced year-round SCR, ESP

Case 1a: 0.3% PRB Coal, Enhanced

DSI/Trona, Enhanced year-round SCR, FF

Case 2: 0.5% S PRB Coal, year-round SCR,

DS, FF
6-4 January 2009 BART Analysis for Kincaid Power Station 

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6.4 Cost of BART Control Cases 

Table 6-2 summarizes the annualized control cost that is a function of the capital and annual operating costs, 

as well as fixed capital charges estimated by Dominion Energy. The table also presents a computation of 

each control case’s visibility improvement effectiveness and cost relative to the baseline conditions, since each 

control case is independent of the others. The visibility results in Table 6-2 and Table 6-3 are based on the 8th

highest regional haze impacts at Mingo and Mammoth Cave, respectively, averaged over the three years. 

Figure 6-3 presents a graph of visibility improvements as a function of the cost for each control case. It is 

clear from the figure that BART Case 1 (DSI with Trona) is clearly the most cost-effective option for the 

visibility improvement attained. As Figure 6-3 indicates, the incremental cost effectiveness of proceeding to 

Case 1a from Case 1 is steep (very little visibility improvement for the additional cost), so this step is not 

recommended. 

Table 6-2 Visibility Improvement and Annual Costs for Each Control Case at Mingo 

Control Casea

8th Highest at 

Mingo 

3-Yr Ave 

(delta-dv) 

Annualized Cost for 

Unit 1 & 2 

($/Year) 

Incremental Cost 

Effectiveness from 

Baseline ($/dv) 

Baseline: 0.3%S PRB Coal, Seasonal 

SCR, ESP 1.37 $0 $0 

Case 1: 0.3% S PRB Coal, DSI/Trona, 

Enhanced year-round SCR, ESP 0.30 $24,820,000b

 $23,100,000 

Case 1a: 0.3% S PRB Coal, enhanced DSI 

with Trona, Enhanced year-round SCR, FF 0.27 $32,210,000c

 $29,210,000 

Case 2: 0.5% S PRB Coal, year-round 

SCR, DS, FF 0.26 $94,700,000d

 $85,060,000 

Case 3: 1.62%S Illinois Coal, year-round 

SCR, ESP, WFGD 0.46 $125,370,000e

 $137,220,000 

a These costs are based on 2008 dollars. 

b

 When Case 1 costs are projected to 2014 dollars (based upon a 2014 installation date), the annualized 

cost becomes $30,660,000 and the incremental cost effectiveness from the baseline becomes $28,530,000. 

c

 When Case 1a costs are projected to 2014 dollars (based upon a 2014 installation date), the annualized 

cost becomes $41,320,000 and the incremental cost effectiveness from the baseline becomes $37,470,000. 

d

 When Case 2 costs are projected to 2017 dollars (based upon a 2017 installation date), the annualized 

cost becomes $156,110,000 and the incremental cost effectiveness from the baseline becomes $140,220,000. 

e When Case 3 costs are projected to 2017 dollars (based upon a 2017 installation date), the annualized 

cost becomes $200,430,000 and the incremental cost effectiveness from the baseline becomes $219,370,000.
6-5 January 2009 BART Analysis for Kincaid Power Station 

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Table 6-3 Visibility Improvement and Annual Costs for Each Control Case at Mammoth Cave 

a These costs are based on 2008 dollars. 

b

 When Case 1 costs are escalated to 2014 dollars (based upon 2014 installation date) the Annualized Cost becomes 

$30,660,000 and the Incremental Cost Effectiveness from the baseline becomes $31,770,000. 

c

 When Case 1a costs are projected to 2014 dollars (based upon a 2014 installation date), the annualized cost 

becomes $41,320,000 and the incremental cost effectiveness from the baseline becomes $41,960,000. 

d

 When Case 2 costs are escalated to 2017 dollars (based upon 2017 installation date) the Annualized Cost becomes 

$156,110,000 and the Incremental Cost Effectiveness from the baseline becomes $161,880,000 

e

 When Case 3 costs are escalated to 2017 dollars (based upon 2017 installation date) the Annualized Cost becomes 

$200,430,000 and the Incremental Cost Effectiveness from the baseline becomes $244,530,000. 

Control Casea

8th Highest at 

Mammoth 

Cave 

3-Yr Ave 

(delta-dv) 

Annualized Cost for 

Unit 1 & 2 

($/Year) 

Incremental Cost 

Effectiveness from 

Baseline ($/dv) 

Baseline: 0.3%S PRB Coal, Seasonal SCR, 

ESP 1.22 $0 $0 

Case 1: 0.3% S PRB Coal, DSI with Trona, 

Enhanced year-round SCR, ESP 0.25 $24,820,000b

 $25,720,000 

Case 1a: 0.3% S PRB Coal, enhanced DSI 

with Trona, Enhanced year-round SCR, FF 0.23 $32,210,000c $32,710,000 

Case 2: 0.5% S PRB Coal, year-round 

SCR, DS, FF 0.25 $94,700,000d

 $98,200,000 

Case 3: 1.62%S Illinois Coal, year-round 

SCR, ESP, WFGD 0.40 $125,370,000e

 $152,950,000 
6-6 January 2009 BART Analysis for Kincaid Power Station 

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Figure 6-3 Annual Costs vs. Visibility Improvements 

$0

$20,000,000

$40,000,000

$60,000,000

$80,000,000

$100,000,000

$120,000,000

$140,000,000

1.5 1.4 1.3 1.2 1.1 1.0 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0

8th Highest delta-dv (Average of 3-Years)

Cost ($/year)

Mingo

Mammoth

Baseline

Case 2

Case 3

Case 1

Case 1A

6.5 Conclusions 

CALPUFF modeling of the baseline emissions and four BART control emission scenarios has been 

conducted. BART control cases included continuous operation of SCR and the installation of DSI with 

Trona, DS/FF and WFGD. Each control case was modeled to assess visibility improvements at the two 

Class I areas within 300 km of the plant. 

The CALPUFF modeling results indicate that the use of DSI with Trona with increased SCR performance 

results in a visibility improvement that is about equivalent to or better than the dry or wet scrubber options, at a 

much reduced cost. Therefore, we conclude that the recommended BART control case is Case 1, with the 

use of DSI with Trona and enhanced SCR performance operation. The difference in effectiveness for regional 

haze reduction between BART Control Cases 1 and 1a is very small and the associated cost is relatively high. 

The ability for an SO2 emission rate lower than 0.20 lb/MMBtu to be achieved in practice with the use of DSI 

with Trona will be determined from operational experience.
7-1 January 2009 BART Analysis for Kincaid Power Station 

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7.0 References 

Environmental Protection Agency (EPA), AP 42, Fifth Edition, Compilation of Air Pollutant Emission Factors, 

Volume 1: Stationary Point and Area Sources, January, 1995 

Environmental Protection Agency (EPA), Guidance for Tracking Progress Under the Regional Haze Rule, 

EPA-454/B-03-003, Appendix A, Table A-3, September, 2003a 

Environmental Protection Agency (EPA), Guidance for Estimating Natural Visibility Conditions Under the 

Regional Haze Program, EPA 454/B-03-005, September 2003b 

Environmental Protection Agency (EPA), Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 

Summary Report and Recommendations for Modeling Long Range Transport Impacts, EPA-454/R-98-019, 

December, 1998 

EPRI. Estimating Total Sulfuric Acid Emissions from Stationary Power Plants, EPRI, Palo Alto, CA: 2008. 

1016384. 

Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations; 

Final Rule (FR Vol. 70, No. 128 published July 6, 2005) 

Regional Haze Regulations; Revisions to Provisions Governing Alternative to Source-Specific Best Available 

Retrofit Technology (BART) Determinations; Final Rule (FR Vol. 71, NO. 198 published October 13, 2006) 

Single Source Modeling to Support Regional Haze BART Modeling Protocol November 17, 2005, Lake 

Michigan Air Directors Consortium, Des Plaines, IL 
 January 2009

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Appendix A 

Meteorological Stations used in CALMET Processing 
 January 2009

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Table A-1 NWS Surface Stations used in CALMET Processing 

ID Station Name State Latitude Longitude 

724395 ALTON/ST LOUIS RGNL IL 38.90 -90.05 

724338 BELLEVILLE SCOTT AF IL 38.55 -89.85 

724397 BLOOMINGTON/NORMAL IL 40.48 -88.91 

725314 CAHOKIA/ST. LOUIS IL 38.56 -90.15 

724336 CARBONDALE/MURPHYSB IL 37.78 -89.25 

725315 CHAMPAIGN/URBANA IL 40.03 -88.28 

725316 DECATUR AIRPORT IL 39.83 -88.86 

725342 LAWRENCEVILLE\VIN. IL 38.76 -87.60 

724339 MARION REGIONAL IL 37.75 -89.01 

725317 MATTOON/CHARLESTON IL 39.48 -88.28 

724335 MOUNT VERNON (AWOS) IL 38.31 -88.86 

725320 PEORIA GREATER PEOR IL 40.66 -89.68 

724330 SALEM-LECKRONE IL 38.65 -88.96 

724390 SPRINGFIELD CAPITAL IL 39.85 -89.68 

724385 ANDERSON MUNICIPAL IN 40.11 -85.61 

724375 BLOOMINGTON/MONROE IN 39.15 -86.61 

724363 COLUMBUS BAKALAR IN 39.26 -85.90 

724384 EAGLE CREEK IN 39.83 -86.30 

724320 EVANSVILLE REGIONAL IN 38.05 -87.53 

724365 HUNTINGBURG IN 38.25 -86.95 

724380 INDIANAPOLIS INTL A IN 39.71 -86.26 

724386 LAFAYETTE PURDUE UN IN 40.41 -86.93 

725336 MUNCIE/JOHNSON FLD IN 40.25 -85.40 

724356 SHELBYVILLE MUNI IN 39.58 -85.80 

724373 TERRE HAUTE HULMAN IN 39.45 -87.30 

746716 BOWLING GREEN WARRE KY 36.98 -86.43 

746710 FORT CAMPBELL (AAF) KY 36.66 -87.50 

724240 FORT KNOX GODMAN AA KY 37.90 -85.96 

724238 HENDERSON CITY KY 37.81 -87.68 

724235 LOUISVILLE BOWMAN F KY 38.23 -85.66 

724230 LOUISVILLE STANDIFO KY 38.18 -85.73 

724237 OWENSBORO/DAVIESS KY 37.73 -87.16 

724350 PADUCAH BARKLEY REG KY 37.05 -88.76 

723489 CAPE GIRARDEAU MUNI MO 37.23 -89.56 

724454 FARMINGTON MO 37.76 -90.40 

723300 POPLAR BLUFF(AMOS) MO 36.76 -90.46 

724347 ST CHARLES COUNTY A MO 38.91 -90.41 

724340 ST LOUIS LAMBERT IN MO 38.75 -90.36 

724345 ST LOUIS SPIRIT OF MO 38.65 -90.65 

723270 NASHVILLE INTERNATI TN 36.11 -86.68 
 January 2009

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Table A-2 CASTNET Surface Stations used in CALMET Processing 

ID Station Name State Latitude Longitude 

ALH157 Alhambra IL 38.87 -89.62 

CDZ171 Cadiz KY 36.78 -87.85 

MAC426 Mammoth Cave NP KY 37.28 -86.26 

MCK131 Mackville KY 37.70 -85.05 

Table A-3 Upper Air Stations used in CALMET Processing 

WBAN ID Station Name State Latitude Longitude 

4833 Lincoln-Logan IL 40.15 -89.33 

13897 Nashville TN 36.25 -86.57