Prepared for: Dominion Energy, Inc.



# BART Analysis for the Kincaid Power Plant

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

## Contents

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

1.0 Introduc tion ................................................................................................................... ......................... 1-1

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

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

2.2 Existing Contro l Technol ogies.................................................................................................. ....... 2-1

2.3 Baseline Em issions ............................................................................................................. ............ 2-1

3.0 Emission Contro l Altern atives.................................................................................................. ........... 3-1

3.1 SO 2 Cont rol....................................................................................................................... ............... 3-1 3.1.1 Technical Feasibility of Alternative SO 2 Contro ls ............................................................. 3-1 3.1.2 Impacts of Alternative SO 2 Contro ls.................................................................................. 3-4 3.1.3 Discussion of Candidate SO 2 Control Tec hnologies ........................................................ 3-5

3.2 NO X Emission Contro ls............................................................................................................. ....... 3-6 3.2.1 Technical Feasibility of Alternative NO x Contro ls ............................................................. 3-6 3.2.2 Discussion of Candidate NO x Control Tec hnologies ........................................................ 3-7

3.3 PM Emission Cont rol............................................................................................................ ........... 3-7

3.4 Control Sc enario s .............................................................................................................. .............. 3-8

4.0 Meteorological Data used in Vi sibility Improvemen t Modeli ng....................................................... 4-1

4.1 Elements of the Refined A nalysis ............................................................................................... .... 4-1

4.2 CALMET Pr ocessing .............................................................................................................. ......... 4-1

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

5.1 CALPUFF Modeling Domain and Recept ors.................................................................................. 5-1

5.2 Technical Options Used in the M odeling ........................................................................................ 5 -1

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

5.4 Light Extinction and Haze Impact Calcul ations .............................................................................. 5-2

6.0 CALPUFF Modeling and BART De termination R esults .................................................................... 6-1

6.1 Modeled Contro l Scenar ios...................................................................................................... ....... 6-1

6.2 Modeling Results for Baseline Em issions....................................................................................... 6 -1

6.3 Modeling Results for the Alte rnative Contro l Cases ....................................................................... 6-1

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

6.5 Conclu sions .................................................................................................................... ................. 6-6ii January 2009 BART Analysis for Kincaid Power Station 02285-076-400 7.0 Refere nces..................................................................................................................... ......................... 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 Co ntrol Emi ssions.............................. ES-2

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

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

Table 2-1 Kincaid Baseli ne Emi ssions ..................................................................................................... 2-3

Table 2-2 Kincaid Baseline Sta ck Paramete rs......................................................................................... 2-3

Table 3-1 Total Capital and Annual Costs Associated with Technically Feasible SO 2 Control Technologies Applied to Kincaid Units 1 a nd 2.............................................................................................. 3 -4

Table 3-2 Kincaid Future DSI with Tr ona Emissions (C ase 1) .............................................................. 3-10

Table 5-1 MRPO Ozone and Ammonia S easonal Concent rations ......................................................... 5-1

Table 5-2 Annual Average Natural Ba ckground Concent rations ............................................................ 5-2
Table 6-1 Regional Haze Impacts Due to Baseline and BART Control Emis sions ................................ 6-2

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

Table 6-3 Visibility Improvement and Annual Costs for Each Control Case at Mammoth Cave ........... 6-5iii January 2009 BART Analysis for Kincaid Power Station 02285-076-400 

## List of Figures

Figure ES- 1 8 th Highest Regional Haze Impacts Averaged Over 3 Years Due to Baseline and BART Control Option Em issions............................................................................................................... .....ES-2 Figure ES-2 Annual Costs vs. Visibility Im provem ents........................................................................... ...ES-4
Figure 4-1 Kincaid CALMET and CALP UFF Modeling Domain............................................................... 4-3
Figure 4-2 Location of Meteorological Stations used in CALMET Processi ng ........................................ 4-4
Figure 6-1 8 th 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: Case s 1, 1a, and 2........ 6-3
Figure 6-3 Annual Costs vs. Visibili ty Improvem ents................................................................................ 6-6ES-1 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 

## 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 Be st Available Retrofit Technology (BART) to those existing eligible sources in order to help meet the target s for visibility improvement at designated Class I areas. The IEPA has identified the two coal-fired boilers, Unit s 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 R egional Haze State Implementation Plan (SIP).

The BART rules require that sources that are subject to BART perform a site-specif ic BART analysis including a control technology review and CALPUFF modeling to a ssess the visibility impact of the emission units. Additionally, for large Electric Generating Units (E GU) affected by the rule, the source should meet presumptive control levels for nitrogen oxide (NO X ) and sulfur dioxide (SO 2 ) unless it is determined that alternative control levels are justified or equivalent in effectiveness. The presumpt ive BART limits for these units are continuous year-round operatio n of the existing SCR systems at 0.10 pound per million British thermal unit (lb/MMBtu) for NO X and 0.15 lb/MMBtu or 95 percent control for SO 2
. This report documents the case-by-case BART analysis conducted for NO x , SO 2 , and PM 10 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 So rbent Injection (DSI) with Trona capable of achieving an SO 2 emissions level of 0.20 lb/MMBtu and enhanced year-round operation of the SCR at a NO x 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 SO 2 emissions level of 0.18 lb/MMBtu (if achi evable), enhanced year-round operation of the SCR at a NO x 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 SO 2 emissions level of 0.15 lb/MMBtu and year-round operation of the SCR at a NO x emission level of 0.10 lb/MMBtu.

• Case 3 . Firing 1.62%-sulfur Illinois Basin bitumi nous coal, Wet Flue Gas Desulfurization (WFGD) capable of achieving an SO 2 emissions level of 0.15 lb/MMBtu and year-round operation of the SCR at a NO x emission level of 0.10 lb/MMBtu. Kincaid Units 1 and 2 currently employ high-efficiency Elec trostatic 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, respecti vely. These emissions ar e 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 le vel of 0.015 lb/MMBtu. The DSI with Trona system has the potential for significant reductions in PM emissions 1 . 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 H 2 SO 4 removal due to Trona injection.

1 PM 10 filterable and condensable emissions were reduced by ap proximately 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.pdfES-2 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 CALPUFF modeling results for meteorological dat abase years 2002-2004 were obtained for the two PSD Class I areas within 300 km of t he Kincaid Generating Station: Mingo Wilderness Area in Missouri and Mammoth Cave National Park in Kentucky. The resu lts of the baseline emissions indicate that the 8 th highest visibility impacts at Mingo and Mammoth Cave are abo ve the 0.5 delta deciview significance threshold. Therefore, a BART determinat ion analysis was conducted.

CALPUFF modeling results for visibility impr ovements due to application of the four SO 2 control cases at the two Class I areas are tabulated in Table ES-1 and graphica lly plotted in Figure ES-1. The table indicates that substantial visibility improvements occur with the implement ation 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 98 th percentile change of at least 0.5 deltadeciview) occur at either Class I ar ea 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 ControlES-3 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 Figure ES-1 8 th 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 Area8th 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, WFGDES-4 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 Tables ES-2 and ES-3 list the projected annualized contro l cost that is a function of the capital and annual operating costs, as well as fixed c apital charges estimated by Dominion Energy. The table also presents a computation of each control case’s visibility improv ement 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 8 th highest regional haze impacts at Mingo and Ma mmoth Cave, respectively, averaged over the three years. Figure ES-2 presents a graph of visibi lity 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 SO 2 emission rate lower than 0.20 lb/MMBtu to be achieved in practice with the us e 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 Case a 8 th 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 $24,820,000 b $23,100,000

Case 1a: 0.3% S PRB Coal, enhanced DSI with Trona, Enhanced year-round SCR, FF 0.27 $32,210,000 c $29,210,000
Case 2: 0.5% S PRB Coal, year-round SCR, DS, FF 0.26 $94,700,000 d $85,060,000
Case 3: 1.62%S Illinois Coal, year-round SCR, ESP, WFGD 0.46 $125,370,000 e $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 02285-076-400 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 Case a 8 th 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 $24,820,000 b $25,720,000

Case 1a: 0.3% S PRB Coal, enhanced DSI with Trona, Enhanced year-round SCR, FF 0.23 $32,210,000 c $32,710,000
Case 2: 0.5% S PRB Coal, year-round SCR, DS, FF 0.25 $94,700,000 d $98,200,000
Case 3: 1.62%S Illinois Coal, year-round SCR, ESP, WFGD 0.40 $125,370,000 e $152,950,000ES-6 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 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

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5 8th Highest delta-dv (Average of 3-Years)Cost ($/year) Mingo

Mammoth

Baseline Case 2 Case 3

Case 1 Case 1A1-1 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 

## 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 visi bility 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 Environmen tal 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 Ki ncaid Power Plant as BART-eligible emission units.

The BART rules require that sources that are subject to BART perform a site-specif ic BART analysis including a control technology review and CALPUFF modeling to a ssess the visibility impact of the emission units. Additionally, for large Electric Generating Units (E GU) affected by the rule, the source should meet presumptive control levels for nitrogen oxide (NO X ) and sulfur dioxide (SO 2 ) unless it is determined that alternative control levels are justified or equivalent in effectiveness. The presumpt ive BART limits for these units are continuous year-round operatio n of the existing SCR systems at 0.10 pound per million British thermal unit (lb/MMBtu) for NO X and 0.15 lb/MMBtu or 95 percent control for SO 2
. The BART analysis was conducted in accordance with th e 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 technologi es 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, operat ing problems and reliability, and adverse side effects on the rest of the facility.

3. Step 3 – Evaluate the control effectiveness of th e remaining technologies based on current pollutant concentrations, flue gas properties and compos ition, control technology performance, and other factors.

4. Step 4 – Evaluate the annual and incremental co sts of each feasible option in accordance with approved EPA methods, as well as the associated en ergy and non-air quality environmental impacts.

5. Step 5 – Determine the visibili ty impairment associated with base line 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 c onsequence of air pollution control equipm ent may be considered in the final BART decision-making process.

This report documents the case-by- case BART analysis conducted for SO 2 , NO x 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 SO 2 , NO x and PM control technologies. The available meteorological data and the CALPUFF modeli ng procedures are described in Sections 4.0 and 5.0, respectively. The results of the vi sibility improvement modeling using CA LPUFF are presented in Section 6.0, along with the BART recommendation. Re ferences are listed in Section 7.0.2-1 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 

## 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 operati on during the time period (1962-1977) targeted by the Regional Haze BART Rule. Un its 1 and 2 are cyclone-fired boilers manufactured Babcock & Wilcox. These two units each have a rate d capacity of 4,200,000 lb/hr of superheated steam at 2,620 psig and 1,005°F. The steam is directed to dedic ated 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 NO x emissions. Kincaid’s permit requires t he SCR system need only be operated during the ozone season (May 1 st through September 30 th ) and must achieve a NO x 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 l east 0.10 lb/MMBtu according to the station’s permits. Units 1 and 2 currently burn low-sulf ur Powder River Basin (PRB ) sub-bituminous coal to control SO 2 emissions. Based on historical emissions, the su lfur 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 SO 2 and NO x baseline emissions were determined using measurement data collected by the continuous emissi ons monitoring system (CEMS) during the years 2002 through 2006. Filterable PM baseline emissions were deter mined using the highest results of the latest stack tests conducted in November 1999.

The SO 2 and NO x baseline emission rates were derived from maximum daily emissions measured by the CEMS) during the years 2002 through 2006. The PM emi ssions were derived from the results of stack tests conducted in November 1999. Speciation of the parti culate matter emissions into filterable and condensable PM 10 components was determined using the following approach:

• Filterable PM was subdivided by size category cons istent 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 PM 10 and 36% of the PM emissions are fine filterable PM 10 emissions (less than 2.5 microns in size).

• For coal-fired boilers, elemental carbon is expected to be 3.7% of fine filterable PM 10 based on the best estimate for electric utility c oal combustion in Table 6 of “Catal og 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 PM 10 emissions, assumed to consist of H 2 SO 4 , are based on procedures presented in “Estimating Total Sulfuric Acid Emissi ons from Stationary Power Plants," EPRI, Technical Update, March 2007 (and reaffirmed in a Marc h 2008 update). For coal-fired boilers, H 2 SO 4 emissions are determined by the following relationship:2-2 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 E = (Q)(98.06/64.04)(F1)(F2)

where: E is the H 2 SO 4 emission rate (lb/hr), Q is the baseline SO 2 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 equ ipped with SCR, the maximum daily NO x 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 PM 10 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 PM 10 emissions from cyclone boilers, AP-42 directs you to the use the pulverized c oal emission factor for cyclone boilers. Table 2-1 provides a summary of the SO 2 , NO x , 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.2-3January 2009BART Analysis for Kincaid Power Station02285-076-400Table 2-1 Kincaid Baseline EmissionsTable 2-2 Kincaid Baseline Stack ParametersCaseUTM Northing(m)UTMEasting (m)BaseElevation (m)StackHeight (m)StackDiameter (m)Flue GasTemperature (°K)Flue Gas FlowRate (m3/s)Flue GasVelocity (m/s)Baseline 4,385,605.6 284,850.0182.87 186.69 9.03 410.93 1,673.26 26.213-1 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 

## 3.0 Emission Control Alternatives

The visibility impairing pollutants discussed in this section include NO X , SO 2 , and PM. Information on control of these pollutants through application of a control devi ce, combination of devices, and/or operational change is provided.



### 3.1 SO 2 

### Control
Sulfur dioxide emissions are generated in fossil fuel-fired combustion units from the ox idation of sulfur present in the fuel. Approximately 98% of the sulfur in coal is emitted upon combustion as gaseous sulfur oxides, SO 2 and SO 3 . Uncontrolled emissions of SO 2 are directly related to the fuel sulfur content, and not by the firing mechanism, boiler size, or operation. Many coal-f ired boilers in the U.S. limit emissions of SO 2 through the use of low sulfur western coals, including Powder Ri ver Basin Coal. Compared with higher sulfur eastern bituminous coal that may contain as much as 4% sulf ur, the practice of burning western coal can reduce SO 2 emissions by approximately 70% to 90%. Howeve r, control equipment can generally remove a higher percentage of the SO 2 from higher sulfur coal than lower sulfur c oal. The selection of coal type and sulfur content, therefore, is an import ant aspect of the determination of BART and needs to be considered in conjunction with add-on control alternat ives when performing the BART analysis.

The Unit 1 and 2 boilers currently bur n low-sulfur PRB coal to limit SO 2 emissions. Alternative SO 2 control technologies available to further reduce SO 2 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, e nergy, and environmental impacts of the alternative SO 2 control technologies are addressed in the remainder of this section.



### 3.1.1 Technical Feasibility of Alternative SO 2 

### Controls
The technical feasibility and performance levels of the alternative SO 2 control technologies are evaluated below in terms of their applica tion to Kincaid Units 1 and 2.

Wet Flue Gas Desulfurization

WFGD typically uses limestone or lime to react with SO 2 from coal-fired boilers. The temperature of the flue gas is reduced to its adiabatic saturation temperature and the SO 2 is removed from the flue gas by reaction with the alkaline medium. SO 2 is absorbed into the scrubbing slurry, which falls into the lower section of the vessel known as the reaction tank. Finely gr ound 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:

CaCO 3 + SO 2 → CaSO 3 • 1/2 H 2 O + CO 2

CaSO 3 •1/2 H 2 O + 3H 2 O + O 2 → 2 CaSO 4 •2 H 2 O3-2 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 Lime scrubbing is similar to limestone scrubbing in equipment and process flow, except that lime is a more reactive reagent than limestone. The re actions for lime scrubbing are as follows:

Ca(OH) 2 +SO 2 → CaSO 3 • 1/2 H 2 O + 1/2 H 2 O

Ca(OH) 2 + SO 2 + 1/2 O 2 + H 2 O → CaSO 4 •2 H 2 O

Whether limestone or lime is used as the reagent for SO 2 removal, additional equipment is needed for preparing the lime/limestone slurry and collecting and c oncentrating 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 SO 2 emissions resulting from combustion of high-sulfur coal s. 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 en vironmental impacts incl uding generating an additional solid waste stream and an additional liquid waste stream.

WFGD has been applied on many coal-fired boilers in t he United States. These installations have been demonstrated to consistently achieve SO 2 removal efficiencies ranging from 90% to in excess of 95%. These high SO 2 control efficiencies would provide Dominion with an opportunity to use higher sulfur Illinois bituminous coal and still meet the presumptive BART li mit of 0.15 lb/MMBtu. Al though 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 consider ably 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 trans portation from Wyoming, due to recent incidents of derailments and delays in PRB coal shipments.

If Dominion were required to install WFGD for SO 2 control, therefore, they woul d 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 c oal and will achieve an outlet SO 2 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 particl e 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 evapor ated by the hot flue gases. The SO 2 are absorbed onto the hydrated lime par ticles 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 SO 2 removal efficiencies are signi ficantly higher when the dry3-3 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 scrubber is operated at temperatures approaching the satura tion 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 CaSO 3 and CaSO 4 ). The largest of these particles are separated by gravity from the gas in the absorbing chamber by gravit y 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 de vice, it allows for further reaction of the lime captured in the filter media with the SO 2 in the flue gas. This is due to the laye r of porous filter cake on the surface of the filter that contains the reagent that all flue gas mu st pass through. This allows for increased efficiency of control of SO 2 and H 2 SO 4 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 ut ilization, 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 c onsistently achieve SO 2 removal efficiencies of 80 to 90%. For the purposes of the visib ility 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 SO 2 emission level of 0.15 lb/MMBtu consist ent with the presum ptive BART limit.

Dry Sorbent Injection (DSI) with Trona

A variety of manufacturers have developed DSI systems for SO 2 control on coal-fired boilers. This technology uses very standard process equipment, including carb on steel storage silos, material handling equipment, blowers, and pneumatic transport piping, all of whic h are commodity components available from multiple vendors at similar cost. In order to remove SO 2 compounds from hot exhaust gases, finely ground Trona, sodium sesquicarbonate [Na 3 (HCO 3 )], can be injected into the hot gas stream to react with the SO 2 and form sodium sulfite (Na 2 SO 3 ). 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(Na 3 (HCO 3 )•(CO 3 )•2H 2 O) + 3SO 2 → 3Na 2 SO 3 + 5H 2 O + 4CO 2
A plant’s operating conditions will ultimately affect the effectivene ss of DSI with Trona in removing SO 2 . The most important variables for high removal efficiency are injection temperature, SO 2 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 SO 2 removal rates during the short term demonstration tests discussed below. In 2005 the Mirant Potomac River Station 2 demonstrated a maximum SO 2 control of ≈ 80% while burning Central Appalachian and Columbian coals. In 2008, We Energies Presque Isle Power Plant demonstrated a maximum SO 2 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 SO 2 control of ≈ 60% and an SO 2 emission rate of 0.20 lb/MMBtu based upon a 30-day rolling average. Dominion has assumed 60% SO 2 removal for PRB coal at Kincaid for several reasons, related to differences in the units, the limit ed testing scope at Presque Isle and t he impact on mercury removal. Higher Trona injection rates during the Presque Isle tests cont ributed to reduced rates of mercury removal from Activated Carbon Injection, an issue which must be eval uated for Kincaid. Further, the Presque Isle tests consisted of only 8-hour injections of Trona in a 90 MW unit. Effective utiliz ation 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 exampl e, during normal operations Kincaid operates at reduced loads and lower temperatures at night, which ty pically which reduces the reactivity of Trona. The

2 http://www.mirant.com/our_business/where_we_wo rk/Unredacted_Trona_Test_Report_011706BC.pdf3-4 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 proces s 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 th e use of the water spray, the increased stack gas temperature will tend to avoid the local impacts of increased H 2 SO 4 emissions associated with oxidation of SO 2 to SO 3 by the SCR catalyst and the subsequent formation of H 2 SO 4 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 scr ubber. Trona is a very reactive reagent that can be used to achieve a range of efficiencies depending upon th e amount of sorbent injected into the ductwork.

Two cases are presented for Trona injection for SO 2 control (Cases 1 and 1a), with slightly different SO 2 emission rates (0.20 lb/MMBtu for Case 1 and 0.18 lb/MMBtu for Case 1a). Although the lower SO 2 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 SO 2 

### Controls
The alternative control technologies available to control SO 2 emissions from Units 1 and 2 are DSI with Trona, DS/FF and WFGD. This section documents the ec onomic, non-air environmental, and energy impacts associated with applying alternative co ntrol 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 SO 2 control technologies were provided by Dominion Energy. The annual fixed capital charges and annual operating costs were also provided by Dominion. An interest ra te of 9.8% and an amortizati on 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 SO 2 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 DS I with Trona, DS/FF and WF GD as the available SO 2 control technologies providing the highest removal effi ciencies relative to other technologies. Of the two scrubber options, the DS/FF combinatio n is considered the preferred control technology. The disadvantages of WFGD compared to DS/FF system include:

• higher water consumption or wastewater treatm ent requirement resulti ng in increased energy and utility operating costs;

• liquid effluent from the wet scrubber requires pretr eatment to meet regulatory requirements before discharge to a municipal sewer;

• problems associated with the disposal of wet sl udge resulting from the process, requiring extensive sludge thickening and dewatering equipment;

• a relatively low stack gas temperature result ing in reduced buoyancy and lower plume rise, and hence poorer dispersion of the residual pollutants;

• visible steam plume under most meteorological condit ions, especially during perio ds of high relative humidity; and

• corrosion, scaling and fouling of scrubber internal s, 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 SO 2 and other acid gas emissions, as well as the control of sec ondary 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 WF GD 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 inco rporated into the visibility modeling.



### 3.1.3 Discussion of Candidate SO 2 

### Control Technologies

The SO 2 control technologies identified for evaluat ion include DSI with Trona (two possible SO 2 emission rates), DS/FF and WFGD. Of these tech nologies, WFGD is capable of higher SO 2 control efficiencies ranging from 90 to 95%, providing Dominion with the flexibilit y of using medium-sulfur Il linois bituminous coal. The DS/FF, on the other hand, is capable of achieving SO 2 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 SO 2 removal rates of up to 70% when firing low- sulfur PRB coals as demonstrated at the We Energies Presque Isle Power Plant. The WFGD syst em, however, has significant disadvantages compared3-6 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 with the other SO 2 removal options. The WFGD system has substantially higher capital and annual operating costs than the other SO 2 removal options. Compared with these other options, WFGD would result in significant environmental and energy impacts, incl uding increased power requirements, increased water consumption, liquid effluent requiring pretreatment , wet sludge requiring dewatering, and cooler and less buoyant plume.



### 3.2 NO X 

### Emission Controls
Nitrogen oxides formed during the combustion of coal are generally classified as either thermal NO xor fuelbound NO x . Thermal NO x is formed when elemental nitrogen in the combustion air is oxidized at the high temperatures in the primary combustion zone yi elding nitrogen oxide (NO) and nitrogen dioxide (NO 2 ). The rate of formation of thermal NO x is a function of residence time and free oxygen, and increases exponentially with peak flame temperatures. Thermal NO x from coal combustion can be effe ctively controlled by techniques that limit available oxygen or reduc e peak flame temperatures in the primary combustion zone. Fuel-bound NO x is formed by the oxidation of chemically bound nitrogen in the fuel. The rate of formation of fuel-bound NO x is primarily a function of f uel bound nitrogen content, but is affected by fuel/air mixing.

The technologies available to control NO X from coal-fired boilers include co mbustion controls, such as lowNO x burners (LNB), and post-combustion techniques, su ch as selective non-catalytic reduction (SNCR) and selective catalytic reduction (SCR). Because Units 1 a nd 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 c apable of 30 to 50 percent control.
The Unit 1 and 2 boilers currently in corporate SCR for the control of NO x emissions during the ozone season. As demonstrated below, this control technology is considered the most effective in reducing NO x 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 NO x 

### Controls
The technical feasibility and performance levels of the alternative NO x control technologies are evaluated below in terms of their applica tion to Kincaid Units 1 and 2.

Selective Catalytic Reduction

Selective Catalytic Reduction (SCR) is a proce ss that involves post-combustion removal of NO x from flue gas utilizing a catalytic reactor. In the SCR process, ammonia injected into the flue gas reacts with NO x and oxygen to form nitrogen and water vapor. The SCR process converts NOx to nitrogen and water by the following general reactions:

4NO + 4NH 3 + O 2 → 4N 2 + 6H 2 O

2NO 2 + 4NH 3 + O 2 → 3N 2 + 6H 2 O

The reactions take place on the surface of a catalyst. T he function of the catalyst is to effectively lower the activation energy of the NO x decomposition reaction to about 375 to 750°F, depending on the specific catalyst and other contaminants in the flue gas. The factors af fecting 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 subsys tems, including the SCR r eactor, ammonia injection system, and ammonia storage and delivery system. Ty pically, the SCR reactor would be located downstream of the economizer and upstream of the air pre-heater and the particulate control system. From the3-7 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 S CR 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 tem perature). 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 cata lyst 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 ran ge. Operation above the maximum temperature results in oxidation of ammonia to ammonia sulfate and NO x , thereby actually increasing NO x emissions.

SCR with ammonia injection technology is a demonstr ated, commercially available technology. SCR has been used with other coal-fired boilers; therefore, S CR is technically feasible for the control of NO X emissions from Units 1 and 2. Performance data from Units 1 and 2 indicate that the SCR systems are capable of NO x removal efficiencies ranging from 85 to 90%. Based on these performanc e 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-combusti on control technology that involves ammonia or urea injection into the flue gases without the presence of a cata lyst. SNCR, similar to SCR, involves the reaction of NO X with ammonia, where a portion of the NO X is converted to molecular nitrogen and water. Without the use of a catalyst or supplemental fuel injection, the NO X reduction reaction temperatur e must be tightly controlled between 1,600 and 2,200°F (between 1,600 and 1,800°F fo r optimum efficiency). Below 1,600°F ammonia will not fully react, resulting in un-reacted ammonia th at 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 NO X emissions.

SNCR with ammonia injection technology is a demonstrat ed, commercially available technology. SNCR has been used with other coal-fired boilers; therefore, SNCR is indeed technica lly feasible for the control of NO X emissions from Units 1 and 2. However, NO X removal efficiencies with SNCR are lower than SCR, typically ranging from 30 to 50% depending on the combustion process and inlet NO x 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 NO x 

### Control Technologies

The NO X 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 NO x emissions from coal-fired boilers. Further, SCR is the only tech nology capable of achieving the presumptive BART limit for cyclone furnaces. Accordingly, continuous operatio n of the SCR systems with a rolling 30-day emission rate of 0.10 lb/MMBtu is recomm ended as BART for Kincaid Units 1 and 2.



### 3.3 PM Emission Control
Kincaid Units 1 and 2 currently employ high-efficiency Elec tro-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 si gnificantly below the per mitted 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 0.0153-8 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 lb/MMBtu. The DSI with Trona system ha s been shown significant reductions in PM 3 . Dominion has conservatively assumed that there wi ll 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 additiona l PM controls were consi dered 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 ant icipated performance levels, the proposed NO x and particulate control technologies are considered BART for Units 1 and 2. Therefore, the following SO 2 control scenarios are included in the modeling assessment:

• Case 1 . Firing 0.3%-sulfur PRB sub- bituminous coal, Dry So rbent Injection (DSI) with Trona capable of achieving an SO 2 emissions level of 0.20 lb/MMBtu and enhanced year-round operation of the SCR at a NO x 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 SO 2 emissions level of 0.18 lb/MMBtu (i f achievable), enhanced year-round operation of the SCR at a NO x emission level of 0.07 lb/MMBtu, and r eplacement of the exis ting 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 SO 2 emissions level of 0.15 lb/MMBtu and year-round operation of the SCR at a NO x emission level of 0.10 lb/MMBtu.

• Case 3 . Firing 1.62%-sulfur Illinois Basin bitumi nous coal, Wet Flue Gas Desulfurization (WFGD) capable of achieving an SO 2 emissions level of 0.15 lb/MMBtu and year-round operation of the SCR at a NO x emission level of 0.10 lb/MMBtu. A DS/FF or WFGD system is capable of achieving a fi lterable PM emission level of 0.015 lb/MMBtu. The DSI with Trona system has shown significant reductions in PM 4 . Dominion has conservati vely 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 NO x control. The NO x controls have been demonstrated of being capable of achieving a NO x emission level of 0.10 lb/MMBtu. For the DSI with Trona options, Dominion would commit to a NO x emission rate of 0.070 lb/MMBtu.

The alternative control technologi es will not only affect SO 2 and NO X emission levels from Units 1 and 2, but also will affect the emissions and speciation of PM 10 . The PM 10 emissions and speciation for modeling purposes were determined using the following approach:

• Filterable PM was subdivided by size category cons istent 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 PM 10 and 53 percent of the PM emissions are fine filterable PM 10 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 th e visibility analysis.

• For coal-fired boilers, elemental carbon is expected to be 3.7 percent of fine PM 10 based on the best estimate for electric utility coal combustion in Table 6 of “Catal og of Global Emissions Inventories and

3 PM 10 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 PM 10 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.pdf3-9 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 Emission Inventory Tools for Black Carbon”, Wil liam Battye and Kathy Boyer, EPA Contract No. 68- D-98-046, January 2002.

• Condensable inorganic PM 10 emissions, assumed to consist of H 2 SO 4 , are based on “Estimating Total Sulfuric Acid Emissions from Stationary Po wer Plants," EPRI, Technical Update, March 2007. For coal-fired boilers equipped with SCR, H 2 SO 4 emissions are determined by the following relationship: E = (Q)(98.06/64.04)(F1+S2 F3)(F2)

where: E is the H 2 SO 2 emission rate (lb/hr), Q is the baseline SO 2 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 SO 2 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 PM 10 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 SO 2 , NO x , 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.3-10January 2009BART Analysis for Kincaid Power Station02285-076-400Table 3-2 Kincaid Future DSI with Trona Emissions (Case 1)3-11January 2009BART Analysis for Kincaid Power Station02285-076-400Table 3-3 Kincaid Future Enhanced DSI with Trona Emissions (Case 1a)3-12January 2009BART Analysis for Kincaid Power Station02285-076-400Table 3-4 Kincaid Future DS/FF Emissions (Case 2)3-13January 2009BART Analysis for Kincaid Power Station02285-076-400Table 3-5 Kincaid Future WFGD Emissions (Case 3)3-14January 2009BART Analysis for Kincaid Power Station02285-076-400Table 3-6 Kincaid Future DSI with Trona, DS/FF and WFGD Stack ParametersCase DescriptionUTMNorthing(m)UTMEasting(m)BaseElevation(m)StackHeight(m)StackDiameter(m)Flue GasTemperature(°K)Flue GasFlow Rate(m3/s)Flue GasVelocity(m/s)1DSI, EnhancedSCR, ESP4,385,605.6 284,850.0 182.87 186.69 9.03 410.93 1,673.26 26.211aEnhanced DSI,Enhanced SCR,FF,4,385,605.6 284,850.0 182.87 186.69 9.03 410.93 1,673.26 26.212SCR, Dry Scrubber,FF4,385,605.6 284,850.0 182.87 186.699.03 352.59 1,463.18 22.863 SCR, ESP, WFGD 4,385,605.6 284,850.0 182.87 186.699.03 324.82 1,373.33 21.464-1 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 

## 4.0 Meteorological Data used in Visibility Im provement Modeling

This section discusses refinements to the Lake Michig an Air Directors Consortium (LADCO) and Midwest Regional Planning Organization (MRPO) meteorologica l database that was used for the Kincaid BART modeling.


### 4.1 Elements of the Refined Analysis

ENSR made several refinements to the CALMET me teorological database produced by LADCO/MRPO for BART CALPUFF analyses for Midwestern States. Th e 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 w ould not be considered appropriate for a more refined analysis.

ENSR developed a refined meteorological database t hat included a modeling domain encompassing the two Class I areas (Mingo and Mammoth Cave), the Kincaid fa cility, and the appropriate buffers around the source and Class I areas for puffs recirculation. This domai n 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 th e 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/s ettings, when appropriate, that were used to develop the LADCO/MRPO CALMET database. To improve the dat abase even further, ENSR introduced act ual surface, precipitation, and twice-daily upper air sounding observations into the re fined meteorological database. These improvements in the CALMET database provide more accurate plume trajectori es 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 sugg ested 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 CALM ET 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) dom ain 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 th is analysis was based on the NAS-C datum and standard parallels of 33 and 45 degrees North, with an or igin of 40 degrees North and 97 degrees West.

ENSR used the latest EPA-approved version of CALM ET (Version 5.8, Level 070623) to produce threedimensional wind fields for three years (2002-2004). Adv anced meteorological data in the form of prognostic mesoscale meteorological data, such as the Fifth Gene ration 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 02285-076-400 • 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 us ed by LADCO/MRPO for their BART assessments.

These prognostic meteorological data sets were initiall y combined with the 6-km grid resolution terrain and land use data to more accurately characterize the wi nd flow throughout the modeling domain. The gridded terrain data was derived using the U.S. Geological Surv ey (USGS) 90-meter grid spacing Digital Elevation Model (DEM) files. These files were processed in t he TERREL pre-processor program. The gridded land use data was derived from USGS 1:250,000 Com posite 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 ball oon 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.4-3 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 Figure 4-1 Kincaid CALMET and CALPUFF Modeling Domain4-4 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 Figure 4-2 Location of Meteorological Stations used in CALMET Processing5-1 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 

## 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 CALP UFF (Version 5.8, Level 070623) that has been posted at http://www.src.com/calpuff/dow nload/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 ar ound 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

O 3 (ppb) 31 31 31 37 37 37 33 33 33 27 27 27

NH 3 (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 Mont hly f(RH) at Class I Areas

Two Class I areas were modeled for the Kincaid faci lity. 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 m odeling 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 databa se 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 t hat 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 annual5-2 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 average background with the 98 th 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 visi bility impacts based on the source’s impacts at the 98 th percentile day modeled results. This procedure is c onsistent 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 no ted below with site-specif ic considerations, and corresponding to the annual average natural background concentrations (EPA 2003, Appendix B).

To determine the input to CALPOST, it is first necessa ry 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 scatte ring. This remaining extinction is due to naturally occurring particles, and is held constant for the entire year’s simulation. Theref ore, 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 μ g/m 3 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 μ g/m 3 )* 21.58 21.02

* Extinction values include Rayleigh scattering.



### 5.4 Light Extinction and Ha ze Impact Calculations
The CALPOST postprocessor was used for part of the calc ulation 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, whic h 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:

b ext = 3 f(RH) [(NH 4 )2SO 4 ] + 3 f(RH) [NH 4 NO 3 ] + 4[OC] + 1[Soil] + 0.6[Coarse Mass] + 10[EC] + b Ray
The concentrations, in square brackets, are in μ g/m 3 and b ext is in units of Mm -1 . The Rayleigh scattering term (b Ray ) 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 02285-076-400 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 extinc tion 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 cont ribution to the total source-caused extinction from ammonium sulfate and nitrate is then added to the other, non-hygroscopic com ponents of the particulate concentration (from coarse and fine soil, secondary organic aerosols, and from elemental carbon) to yi eld the total hourly source-caused extinction.6-1 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 

## 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 pr esents 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 emis sions associated with the alternat ive control scenarios for Units 1 and 2.


### 6.2 Modeling Results fo r 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 y ears 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 8 th highest delta-deciview. Figure 6-1 indicates that the higher visibility impacts occur at Mi ngo Wilderness and they are due to that park’s proximity to Kincaid.

The results of the baseline emissions indicate that the 8 th 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 y ears 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 improvem ents occur with either Case 1/1a (DSI with Trona) and Case 2 (DS/FF) controls and that no percept ible visibility impacts (defined by a 98 th percentile change of at least 0.5 delta-deciview) occur at an y 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 improvem ent 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 H 2 SO 4 emissions associated with WFGD. Addition of WFGD would reduc e visibility impacts by about 0.96 de lta-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 visibi lity improvements available from BART cases 1 and 2 are essentially equivalent.6-2 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 Table 6-1 Regional Haze Impacts Due to Baseline and BART Control Emissions

Figure 6-1 8 th 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 Area8th 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, WFGD6-3 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 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 AreaAverage Delta-Deciview of 8 Highest Days Case 1: 0.3% S PR B 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, FF6-4 January 2009 BART Analysis for Kincaid Power Station 02285-076-400



### 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 Domini on Energy. The table also presents a computation of each control case’s visibility improve ment 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 8 th highest regional haze impacts at Mingo and Mammoth Ca ve, 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 th e most cost-effective option for the visibility improvement attained. As Figure 6-3 indica tes, the incremental cost effectiveness of proceeding to Case 1a from Case 1 is steep (very li ttle 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 Case a 8 th 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 $24,820,000 b $23,100,000

Case 1a: 0.3% S PRB Coal, enhanced DSI with Trona, Enhanced year-round SCR, FF 0.27 $32,210,000 c $29,210,000
Case 2: 0.5% S PRB Coal, year-round SCR, DS, FF 0.26 $94,700,000 d $85,060,000
Case 3: 1.62%S Illinois Coal, year-round SCR, ESP, WFGD 0.46 $125,370,000 e $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 02285-076-400 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 Case a 8 th 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 $24,820,000 b $25,720,000

Case 1a: 0.3% S PRB Coal, enhanced DSI with Trona, Enhanced year-round SCR, FF 0.23 $32,210,000 c $32,710,000
Case 2: 0.5% S PRB Coal, year-round SCR, DS, FF 0.25 $94,700,000 d $98,200,000
Case 3: 1.62%S Illinois Coal, year-round SCR, ESP, WFGD 0.40 $125,370,000 e $152,950,0006-6 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 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

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5 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 mo deled 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 th e recommended BART control case is Case 1, with the use of DSI with Trona and enhanced SCR performance operat ion. 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 SO 2 emission rate lower than 0.20 lb/MMBtu to be achieved in practice with the use of DSI with Trona will be determin ed from operational experience.7-1 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 

## 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 (E PA), 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 (E PA), 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 Ava ilable Retrofit Technology (BART) Determinations; Final Rule (FR Vol. 70, No. 128 published July 6, 2005)

Regional Haze Regulations; Revisions to Provisions Gove rning 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 BA RT Modeling Protocol November 17, 2005, Lake Michigan Air Directors Consortium, Des Plaines, ILJanuary 2009 BART Analysis for Kincaid Power Station 02285-076-400 

## Appendix A

Meteorological Stations used in CALMET ProcessingJanuary 2009 BART Analysis for Kincaid Power Station 02285-076-400 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/MURPH YSB 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 MUNICI PAL 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 -86.68January 2009 BART Analysis for Kincaid Power Station 02285-076-400 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