BART FIVE FACTOR ANALYSIS

FLINT CREEK POWER PLANT 

GENTRY, ARKANSAS (AFIN 04-00107)

Prepared By:

TRINITY CONSULTANTS, INC.

120 East Sheridan, Suite 205

Oklahoma City, Oklahoma 73104

(405) 228-3292

TRINITY CONSULTANTS, INC.

977 Ridge Drive, Suite 380

Lenexa, Kansas 66219

(913) 894-4500

In conjunction with:

AMERICAN ELECTRIC POWER SERVICE CORPORATION

PO Box 660164

Dallas, Texas 72566

(214) 777-1113

for the

SOUTHWESTERN ELECTRIC POWER COMPANY

FLINT CREEK POWER PLANT

21797 SWEPCO Plant Road

Gentry, Arkansas 72734

Trinity Project Nos. 113701.0022 & 123701.0038

March 2013

Version 3

 
TABLE OF CONTENTS

1. EXECUTIVE SUMMARY ........................................................................................ 1-1

2. INTRODUCTION AND BACKGROUND.................................................................... 2-1

3. MODELING METHODOLOGIES AND PROCEDURES ............................................. 3-1

3.1 CALMET AND CALPUFF................................................................................... 3-1

3.2 CALPOST............................................................................................................ 3-1

4. EXISTING EMISSIONS AND VISIBILITY IMPAIRMENT ......................................... 4-1

4.1 NOX, SO2, AND PM10 BASELINE EMISSION RATES ............................................... 4-1

4.2 BASELINE VISIBILITY IMPAIRMENT....................................................................... 4-2

5. SO2 BART EVALUATION .................................................................................... 5-1

5.1 IDENTIFICATION OF AVAILABLE RETROFIT SO2 CONTROL TECHNOLOGIES .......... 5-1

5.2 ELIMINATE TECHNICALLY INFEASIBLE SO2 CONTROL TECHNOLOGIES ................ 5-1

5.2.1 DRY SORBENT INJECTION ...................................................................................5-1

5.2.2 DRY SCRUBBER...................................................................................................5-2

5.2.3 WET SCRUBBER ..................................................................................................5-2

5.3 RANK OF TECHNICALLY FEASIBLE SO2 CONTROL OPTIONS BY EFFECTIVENESS .. 5-3

5.4 EVALUATION OF IMPACTS FOR FEASIBLE SO2 CONTROLS..................................... 5-3

5.4.1 COST OF COMPLIANCE........................................................................................5-4

5.4.2 ENERGY IMPACTS AND NON-AIR QUALITY IMPACTS.........................................5-7

5.4.3 REMAINING USEFUL LIFE ...................................................................................5-7

5.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE SO2 CONTROLS ...................... 5-7

5.6 PROPOSED BART FOR SO2 ................................................................................... 5-10

5.6.1 COMPARATIVE SO2 BART DETERMINATIONS .................................................5-10

6. NOX BART EVALUATION................................................................................... 6-1

6.1 CROSS-STATE AIR POLLUTION RULE,................................................................... 6-1

CLEAN AIR INTERSTATE RULE, AND BART...................................................................... 6-1

6.2 IDENTIFICATION OF AVAILABLE RETROFIT NOX CONTROL TECHNOLOGIES......... 6-2

6.3 ELIMINATE TECHNICALLY INFEASIBLE NOX CONTROL TECHNOLOGIES ............... 6-2

6.3.1 COMBUSTION CONTROLS....................................................................................6-3

6.3.1.1 Flue Gas Recirculation (FGR).............................................................6-3

6.3.1.2 Overfire Air (OFA)..............................................................................6-3

6.3.1.3 Low NOX Burners................................................................................6-3

6.3.2 POST COM BUSTION CONTROLS..........................................................................6-4

6.3.2.1 Selective Catalytic Reduction..............................................................6-4

6.3.2.2 Selective Non-Catalytic Reduction......................................................6-4

6.4 RANK OF TECHNICALLY FEASIBLE NOX CONTROL OPTIONS BY EFFECTIVENESS.. 6-5

6.5 EVALUATION OF IMPACTS FOR FEASIBLE NOX CONTROLS ................................... 6-5

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BART Analysis – Flint Creek
6.5.1 COST OF COMPLIANCE........................................................................................6-6

6.5.2 ENERGY IMPACTS & NON-AIR IMPACTS ..........................................................6-10

6.5.3 REMAINING USEFUL LIFE .................................................................................6-10

6.6 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE NOX CONTROLS ................... 6-10

6.7 PROPOSED BART FOR NOX.................................................................................... 6-1

7. PM10 BART EVALUATION.................................................................................. 7-1

APPENDIX A.................................................................................................................................

APPENDIX B.................................................................................................................................

APPENDIX C.................................................................................................................................

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BART Analysis – Flint Creek
LIST OF TABLES

TABLE 1-1. EXISTING VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-01 (2001-2003) ...................1-1

TABLE 3-1. ANNUAL AVERAGE BACKGROUND CONCENTRATION.....................................................3-2

TABLE 3-2. FL(RH) LARGE RH ADJUSTMENT FACTORS.....................................................................3-3

TABLE 3-3. FS(RH) SMALL RH ADJUSTMENT FACTORS.....................................................................3-3

TABLE 3-4. FSS(RH) SEA SALT RH ADJUSTMENT FACTORS ...............................................................3-3

TABLE 4-1. BASELINE MAXIMUM 24-HOUR SO2, NOX, AND PM10 EMISSION RATES (AS HOURLY 

EQUIVALENTS) .......................................................................................................................4-1

TABLE 4-2. BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-01 BOILER (2001-2003).....4-2

TABLE 5-1. AVAILABLE SO2 CONTROL TECHNOLOGIES FOR SN-01 ..................................................5-1

TABLE 5-2. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE SO2 CONTROL TECHNOLOGIES5-3

TABLE 5-3. SUMMARY OF COST EFFECTIVENESS FOR SN-01 SO2 CONTROLS...................................5-5

TABLE 5-4. DOLLAR PER DECIVIEW COST EFFECTIVENESS FOR SN-01 SO2 CONTROLS OF WET 

SCRUBBING.............................................................................................................................5-6

TABLE 5-5. DOLLAR PER DECIVIEW COST EFFECTIVENESS FOR SN-01 SO2 CONTROLS OF NIDS....5-6

TABLE 5-6. SUMMARY OF EMISSION RATES MODELED TO REFLECT SO2 CONTROLS........................5-8

TABLE 5-7. SUMMARY OF MODELED IMPACTS FROM SO2 CONTROL VISIBILITY IMPACT ANALYSIS 

FOR SN-01 (2001-2003)..........................................................................................................5-9

TABLE 6-1. AVAILABLE NOX CONTROL TECHNOLOGIES FOR SN-01 ................................................6-2

TABLE 6-2. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE NOX CONTROL TECHNOLOGIES6-5

TABLE 6-3. SUMMARY OF COST EFFECTIVENESS FOR SN-01 NOX CONTROLS...................................6-8

TABLE 6-4. DOLLAR PER DECIVIEW COST EFFECTIVENESS FOR SN-01 NOX CONTROL USING

LNB/OFA...............................................................................................................................6-9

TABLE 6-5. DOLLAR PER DECIVIEW COST EFFECTIVENESS FOR SN-01 NOX CONTROL USING 

LNB/OFA PLUS SNCR ..........................................................................................................6-9

TABLE 6-6. DOLLAR PER DECIVIEW COST EFFECTIVENESS FOR SN-01 NOX CONTROL USING SCR .6-9

TABLE 6-7. SUMMARY OF EMISSION RATES MODELED TO REFLECT LNB/OFA FOR NOX CONTROL6-11

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TABLE 6-8. SUMMARY OF EMISSION RATES MODELED TO REFLECT SCR FOR NOX CONTROL.......6-11

TABLE 6-9. SUMMARY OF EMISSION RATES MODELED TO REFLECT LNB/OFA + SNCR FOR NOX

CONTROL..............................................................................................................................6-11

TABLE 6-10. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH NOX CONTROL SYSTEM ON 

SN-01 (2001-2003)...............................................................................................................6-12

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BART Analysis – Flint Creek
1. EXECUTIVE SUMMARY

This report documents the determination of the Best Available Retrofit Technology (BART) for 

Southwestern Electric Power Company’s (SWEPCO’s)1 electric generating unit at the Flint Creek 

Power Plant (SN-01). SN-01 is a dry bottom wall-fired boiler with a nominal design maximum heat 

input of 6,324 million British thermal units per hour (MMBtu/hr) that burns primarily low sulfur 

western coal. The unit has a nominal generating capacity rating of 558 MW and commenced 

commercial operation in 1978. It is currently equipped with an electrostatic precipitator and low NOX

burners.

Based on modeling performed for this analysis, cumulative emissions of nitrogen oxides (NOX),

sulfur dioxide (SO2), and particulate matter with a mean diameter smaller than ten microns (PM10)

from SN-01 are predicted to cause or contribute greater than 0.5 deciviews (∆dv) of visibility 

impairment in four Class I Areas: Caney Creek Wilderness (CACR), Upper Buffalo Wilderness 

(UPBU), Hercules Glades Wilderness (HERC), and Mingo Wilderness (MING). 

A summary of the existing visibility impairment attributable to SN-01 based on the default natural 

conditions is provided in Table 1-1. The visibility impairment summarized in Table 1-1 is based on 

modeling conducted by Trinity Consultants (Trinity) using actual emissions data based on a 

combination of stack testing and CEMS as further described in Section 4 of this report.

TABLE 1-1. EXISTING VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-01 (2001-2003)

Caney Creek

Wilderness

Upper Buffalo 

Wilderness

Hercules 

Glades

Wilderness

Mingo 

Wilderness

98th 

% 

∆dv

Days 

> 0.5 

∆dv

98th 

% 

∆dv

Days > 

0.5 

∆dv

98th 

% 

∆dv

Days 

> 0.5 

∆dv

98th 

%

∆dv

Days 

> 0.5 

∆dv

AEP Flint Creek SN-01 0.963 48 0.965 63 0.657 47 0.631 20

Trinity used the EPA’s BART guidelines in 40 CFR Part 512 and other recent EPA guidance to 

determine BART for SN-01. Trinity conducted a five-step analysis to determine BART that included 

the following:

1. Identifying all available retrofit control technologies;

2. Eliminating technically infeasible control technologies;

3. Evaluating the control effectiveness of remaining control technologies;

4. Evaluating impacts and document the results;

5. Evaluating visibility impacts.

1 Southwestern Electric Power Company (SWEPCO) is an owner and the operator of the Flint Creek Power Plant, 

and a subsidiary of American Electric Power Company, Inc. (AEP). American Electric Power Service Corporation is a 

subsidiary of AEP that provides legal, accounting, engineering, and other services to the utility operating companies in the 

AEP system, including SWEPCO. SWEPCO and the Service Corporation are referred to generically as AEP throughout this 

report.

2 The BART guidelines were published as amendments to the EPA’s RHR in 40 CFR Part 51, Section 308 on July 

6, 2005.

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Based on the five-step analysis, the following were determined to be BART:

▲ SO2 – The BART analysis concluded that the installation of a dry scrubber and baghouse 

(e.g., Novel Integrated Deacidification System [NIDS] technology) constitutes BART. The 

proposed BART emission rate for SO2 is 0.06 lb/MMBtu calculated as a 30-day rolling

average over each boiler operating day. 

▲ NOX – EPA recently issued a final rule allowing states that are subject to the Cross-State Air 

Pollution Rule (CSAPR) trading program for seasonal NOx to rely on the reductions achieved 

through that trading program to satisfy the regional haze program requirements for units 

subject to BART.3 Subsequently, CSAPR was vacated, and the Clean Air Interstate Rule 

(CAIR) remains in effect until an acceptable replacement rule is promulgated.4 If CSAPR is 

upheld and implemented in Arkansas, SWEPCO will rely on CSAPR to satisfy its regional 

haze obligations at SN-01. If CSAPR is vacated and CAIR remains in effect, EPA’s prior 

determination that the reductions provided under CAIR’s seasonal NOX trading program 

provide greater visibility improvements than BART should allow SWEPCO to rely on the 

seasonal CAIR program to satisfy its NOX obligations under BART.5 

In the alternative, SWEPCO has evaluated the cost-effectiveness and visibility improvement 

of candidate BART controls at SN-01. The visibility improvements associated with the 

addition of NOX controls at SN-01 are minimal, and the cost-effectiveness values for all 

control options exceed the values previously determined to be reasonable in EPA’s 

presumptive BART analysis. However, visibility improvements consistent with the modeled 

values used in CENRAP’s analysis for the interstate transport portion of Arkansas’s Regional 

Haze SIP obligations can be achieved with the addition of LNB/OFA, and this control option 

is proposed as BART for SN-01. If ADEQ determines that SWEPCO cannot rely on CAIR 

or CSAPR as an alternative to BART, the proposed BART emission rate for NOX at SN-01 is 

0.23 lb/MMBtu calculated as a 30-day rolling average over each boiler operating day based 

on the application of LNB/OFA controls.

▲ PM10 – A BART determination for PM10 at SN-01 was approved in EPA’s March 12, 2012 

final rule based on the existing ESP and a BART emission rate of 0.1 lb/MMBtu.6

3 “Regional Haze: Revisions to Provisions Governing Alternatives to Source-Specific Best Available Technology 

(BART) Determinations, Limited SIP Disapprovals and Federal Implementation Plans” 77 Fed. Reg. 33651 (June 7, 2012).

4 EME Homer City Generation, L.P., et al., v. United States Environmental Protection Agency, et al.,EPA. Case 

No. 11-1302 (and consolidated cases), Opinion (D.C. Cir Aug. 21, 2012).

5 “Regional Haze Regulations and Best Available Retrofit Technology (BART) Guidelines, 70 Fed. Reg. 39104, 

39143 (July 6, 2005).

6 “Approval and Promulgation of Implementation Plans; Arkansas; Regional Haze State Implementation Plan; 

Interstate Transport State Implementation Plan To Address Pollution Affecting Visibility and Regional Haze. Final Rule,” 

77 Fed. Reg. 14604 (March 12, 2012). 

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2. INTRODUCTION AND BACKGROUND

In the 1977 amendments to the Clean Air Act (CAA), Congress set a national goal to restore

national parks and wilderness areas to pristine conditions by preventing any future, and

remedying any existing, man-made visibility impairment. On July 1, 1999, the U.S. EPA published 

the final Regional Haze Rule (RHR). The objective of the RHR is to restore visibility to pristine 

conditions in 156 specific areas across the United States known as Class I areas. The CAA defines 

Class I areas as certain national parks (over 6,000 acres), wilderness areas (over 5,000 acres), national 

memorial parks (over 5,000 acres), and international parks that were in existence on 

August 7, 1977.

The RHR requires States to set goals that provide for reasonable progress towards achieving natural 

visibility conditions for each Class I area in their state. On July 6, 2005, the EPA published 

amendments to its 1999 RHR, often called the Best Available Retrofit Technology (BART) rule, 

which included guidance for making source-specific BART determinations. The BART rule defines 

BART-eligible sources as sources that meet the following criteria: 

(1) Have potential emissions of at least 250 tons per year of a visibility-impairing pollutant,

(2) Began operation between August 7, 1962 and August 7, 1977, and

(3) Are included as one of the 26 listed source categories in the guidance.

A BART-eligible source is subject to BART if the source is “reasonably anticipated to cause or 

contribute to visibility impairment in any federal mandatory Class I area.” EPA has determined that a 

source is reasonably anticipated to cause or contribute to visibility impairment if the 98th percentile 

visibility impacts from the source are greater than 0.5 delta deciviews (∆dv) when compared against a 

natural background7. Air quality modeling is the tool that is used to determine a source’s visibility 

impacts. 

Once it is determined that a source is subject to BART, a BART determination must address air 

pollution control measures for the source. The visibility regulations define BART as follows:

“...an emission limitation based on the degree of reduction achievable through the 

application of the best system of continuous emission reduction for each pollutant 

which is emitted by...[a BART-eligible source]. The emission limitation must be 

established on a case-by-case basis, taking into consideration the technology available, 

the cost of compliance, the energy and non air quality environmental impacts of 

compliance, any pollution control equipment in use or in existence at the source, the 

remaining useful life of the source, and the degree of improvement in visibility which 

may reasonably be anticipated to result from the use of such technology.

Specifically, the BART rule states that a BART determination should address the following five 

statutory factors:

1. Existing controls

2. Cost of controls

7 Note this is a change from the ADEQ protocol with the 2006 CENRAP data, as the original analysis for 

Arkansas reviewed the “High First High” impacts rather than the 98th percentile impacts

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3. Energy and non-air quality environmental impacts

4. Remaining useful life of the source

5. Degree of visibility improvement as a result of controls

Further, the BART rule indicates that the five basic steps in a BART analysis can be summarized as 

follows:

1. Identify all available retrofit control technologies;

2. Eliminate technically infeasible control technologies;

3. Evaluate the control effectiveness of remaining control technologies;

4. Evaluate impacts and document the results;

5. Evaluate visibility impacts

A BART determination should be made for each visibility affecting pollutant (VAP) by following the 

five steps listed above for each VAP.

SN-01 meets the three BART-eligibility criteria described above, and the existing visibility 

impairment attributable to SN-01 is greater than 0.5 dv in at least one Class I area. Thus, SN-01 is

subject to BART. The details of the SN-01 existing/baseline emissions and the contribution of the 

emissions to visibility impairment can be found in Section 4. The VAPs emitted by SN-01 include 

NOX, SO2, and PM10 of various forms (filterable coarse particulate matter [PMc], filterable fine 

particle matter [PMf], elemental carbon [EC], inorganic condensable particulate matter [IOR CPM] as 

sulfates [SO4], and organic condensable particulate matter [OR CPM] also referred to as secondary 

organic aerosols [SOA]). The BART determinations for SO2, NOx, and PM10 can be found in 

Sections 5, 6, and 7, respectively. 

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3. MODELING METHODOLOGIES AND PROCEDURES

This section summarizes the dispersion modeling methodologies and procedures applied in this 

BART analysis. All dispersion modeling has been conducted using the CALPUFF modeling system, 

consisting of the CALPUFF dispersion model, the CALMET meteorological data processor, and the 

CALPOST post-processing program. 

CALPUFF is a multi-layer, multi-species, non-steady-state puff dispersion model, which can simulate 

the effects of time and space varying meteorological conditions on pollutant transport, transformation, 

and removal. CALPUFF uses three-dimensional meteorological fields developed by the CALMET 

model. In addition to meteorological data, several other input files are used by the CALPUFF model 

to specify source and receptor parameters. The selection and control of CALPUFF options are 

determined by user-specific inputs contained in the control file. This file contains all of the necessary 

information to define a model run (e.g., starting date, run length, grid specifications, technical 

options, output options). CALPOST processes concentration, deposition, and visibility impacts based 

on pollutant specific concentrations predicted by CALPUFF. 

3.1 CALMET AND CALPUFF

The CALPUFF data and parameters are based on the 2005 BART modeling guidelines prepared for 

the Central States Regional Air Planning Association (CENRAP). The CALMET data and 

parameters are based on the protocol included in Appendix C. Note that the protocol included in 

Appendix C summarizes modeling methods and procedures that were followed to predict visibility 

impairment for several BART-eligible sources located in Oklahoma as part of the BART analyses for 

these sources. In addition, several sources in Texas used the CALMET data that was generated in 

accordance with the protocol in their BART analyses. 

3.2 CALPOST

The CALPOST visibility processing completed for this BART analysis is based on the October 2010 

guidance from the Federal Land Managers Air Quality Related Values Workgroup (FLAG). The 

2010 FLAG guidance, which was issued in draft form on July 8, 2008 and published as final guidance 

in December 2010, makes technical revisions to the previous guidance issued in December 2000.

Visibility impairment is quantified using the light extinction coefficient (bext), which is expressed in 

terms of the haze index expressed in deciviews (dv). The haze index (HI) is calculated as follows:





 



 = 10 (dv) 10 ln bext HI

The impact of a source is determined by comparing the HI attributable to a source relative to 

estimated natural background conditions. The change in the haze index, in deciviews, also referred to 

as “delta dv,” or ∆dv, based on the source and background light extinction is based on the following 

equation:

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BART Analysis – Flint Creek
∆ dv = 10*ln

b b

b

ext, background ext, source

ext, background

 +















The Interagency Monitoring of Protected Visual Environments (IMPROVE) workgroup adopted an 

equation for predicting light extinction as part of the 2010 FLAG guidance (often referred to as the 

new IMPROVE equation). The new IMPROVE equation is as follows:

bext =

( )[ ( ) ] ( )[ ( ) ]

( )[ ] ( )[ ]

[ ] [ ] [ ] [ ] [ ]

( )[ ] [ ] Site specific Rayleigh Scattering 2

Small Large

4 3 Small 4 3 Large

4 4 2 Small 4 4 2 Large

1.4 Sea Salt 0.33 NO

2.8 OC 6.1 OC 10 EC 1 PMF 0.6 PMC

2.4 NH NO 5.1 NH NO

2.2 NH SO 4.8 NH SO

+ +

+ + + + +

+ +

+ +

− f RH b

f RH f RH

f RH f RH

SS

S L

S L

Visibility impairment predictions for SN-01 relied upon in this BART analysis used the equation 

shown above. The use of this equation is referred to as “Method 8” in the CALPOST control file. 

The use of Method 8 requires that one of five different “modes” be selected. The modes specify the 

approach for addressing the growth of hygroscopic particles due to moisture in the atmosphere. 

“Mode 5” has been used in this BART analysis. Mode 5 addresses moisture in the atmosphere in a 

similar way as to “Method 6”, where “Method 6” is specified as the preferred approach for use with 

the old IMPROVE equation in the CENRAP BART modeling protocol.

CALPOST Method 8, Mode 5 requires the following:

• Annual average concentrations reflecting natural background for various particles and for sea 

salt

• Monthly RH factors for large and small ammonium sulfates and nitrates and for sea salts

• Rayleigh scattering parameter corrected for site-specific elevation

Tables 3-1 to Table 3-4 below show the values for the data described above that were input to 

CALPOST for use with Method 8, Mode 5. The values were obtained from the 2010 FLAG 

guidance.

TABLE 3-1. ANNUAL AVERAGE BACKGROUND CONCENTRATION 

Class I Area (NH4)2SO4 NH4NO3 OM EC Soil CM Sea Salt

Rayleigh 

(Mm-1)

Caney Creek Wilderness 0.23 0.1 1.8 0.02 0.5 3 0.03 11

Upper Buffalo Wilderness 0.23 0.1 1.8 0.02 0.5 3 0.03 11

Hercules Glades Wilderness 0.23 0.1 1.8 0.02 0.5 3 0.02 11

Mingo Wilderness 0.23 0.1 1.83 0.02 0.51 3.05 0.04 12

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TABLE 3-2. FL(RH) LARGE RH ADJUSTMENT FACTORS

Class I Area Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Caney Creek Wilderness 2.77 2.53 2.37 2.43 2.68 2.71 2.59 2.6 2.71 2.69 2.67 2.79

Upper Buffalo Wilderness 2.71 2.48 2.31 2.33 2.61 2.64 2.57 2.59 2.71 2.58 2.59 2.72

Hercules Glades Wilderness 2.7 2.48 2.3 2.3 2.57 2.59 2.56 2.6 2.69 2.54 2.57 2.72

Mingo Wilderness 2.73 2.52 2.34 2.28 2.53 2.6 2.64 2.67 2.71 2.56 2.56 2.73

TABLE 3-3. FS(RH) SMALL RH ADJUSTMENT FACTORS 

Class I Area Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Caney Creek Wilderness 3.85 3.44 3.14 3.24 3.66 3.71 3.49 3.51 3.73 3.72 3.68 3.88

Upper Buffalo Wilderness 3.73 3.33 3.03 3.07 3.54 3.57 3.43 3.5 3.71 3.51 3.52 3.74

Hercules Glades Wilderness 3.7 3.33 3.01 3.01 3.47 3.48 3.41 3.51 3.67 3.43 3.46 3.73

Mingo Wilderness 3.74 3.38 3.07 2.97 3.39 3.52 3.57 3.64 3.72 3.47 3.43 3.74

TABLE 3-4. FSS(RH) SEA SALT RH ADJUSTMENT FACTORS 

Class I Area Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Caney Creek Wilderness 3.9 3.52 3.31 3.41 3.83 3.88 3.69 3.68 3.82 3.76 3.77 3.93

Upper Buffalo Wilderness 3.85 3.47 3.23 3.27 3.72 3.78 3.69 3.7 3.84 3.64 3.67 3.86

Hercules Glades Wilderness 3.86 3.51 3.23 3.22 3.66 3.72 3.69 3.73 3.81 3.57 3.65 3.88

Mingo Wilderness 3.92 3.58 3.3 3.19 3.58 3.72 3.8 3.82 3.85 3.61 3.66 3.9

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4. EXISTING EMISSIONS AND VISIBILITY IMPAIRMENT

This section summarizes the existing (i.e. baseline) visibility impairment attributable to SN-01 based 

on air quality modeling conducted by Trinity. 

4.1 NOX, SO2, AND PM10 BASELINE EMISSION RATES

Table 4-1 summarizes the emission rates that were modeled for SO2, NOX, and PM10, including the 

speciated PM10 emissions. The SO2 and NOX emission rates are the highest actual 24-hour emission 

rates based on 2001-2003 continuous emissions monitoring system (CEMS) data. The emission rates 

for the PM10 species reflect the breakdown of the PM10 determined from the National Park Service 

(NPS) “speciation spreadsheet” for Dry Bottom Boiler Burning Pulverized Coal using only ESP8. 

Specifically, the NPS workbook shows the following baseline distribution for the PM species:

▲ Coarse PM (PMC) = 33.8 %

▲ Fine soil (modeled as PMF) = 26.1 %

▲ Fine elemental carbon (modeled as EC) = 1.0 %

▲ Organic condensable PM (modeled as SOA) = 7.8 %

▲ Inorganic condensable PM (modeled as SO4) = 31.3 %

Per EPA’s request,9 an SO4 emission rate was independently calculated using an EPRI methodology 

that considers the SO2 to SO4 conversion rate and SO4 reduction factors for various downstream 

equipment.10 This SO4 rate was used in the modeling instead of the rate resulting from the NPSbased breakdown.

TABLE 4-1. BASELINE MAXIMUM 24-HOUR SO2, NOX, AND PM10 EMISSION RATES (AS HOURLY 

EQUIVALENTS)

SO211 SO4 NOX12 PMc PMf SOA EC

Source (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr)

SN-01 4,728.4 3.1 1,945.0 65.1 50.1 15.1 1.9

8 The NPS Workbook, "PC Dry Bottom ESP Example.xls" updated 03/2006, was obtained from the NPS website: 

http://www.nature.nps.gov/air/Permits/ect/index.cfm. The following parameters were input into the workbook for speciation 

determination: total PM10 emission rate of 192.5 lb/hr, heat value of 8,500 Btu/lb, sulfur content of 0.31%, ash content of 

4.9%.

9 E-mail from Dayana Medina (EPA) to Mary Pettyjohn (ADEQ), February 8, 2013, and phone conversation with 

Michael Feldman (EPA), February 26, 2013.

10 Electric Power Research Institute (EPRI) Estimating Total Sulfuric Acid Emissions from Stationary Power 

Plants: Version 2010a. EPRI, Palo Alto, CA: 2010. 1020636.

11 Hourly rate was derived from EPA’s Clean Air Market Database (CAMD) daily rates of 113,482 lb/day. 

12 Hourly rate was derived from EPA’s Clean Air Market Database (CAMD) daily rates of 46,680 lb/day. 

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4.2 BASELINE VISIBILITY IMPAIRMENT

Trinity conducted modeling to determine the visibility impairment attributable to SN-01 in four Class 

I Areas: Caney Creek Wilderness (CACR), Upper Buffalo Wilderness (UPBU), Hercules Glades 

Wilderness (HERC), and Mingo Wilderness (MING) using the CALPUFF dispersion model. 

Table 4-2 provides a summary of the modeled visibility impairment attributable to SN-01 at CACR, 

UPBU, HERC, and MING based on the emission rates shown in Table 4-1. Note that all of the 

CALMET, CALPUFF, and CALPOST modeling files are included as part of the electronic files 

submitted with this document. 

TABLE 4-2. BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-01 BOILER (2001-2003)

Year

Maximum

(Δdv)

98th 

Percentile

(Δdv)

No. of Day 

with Δdv ≥

0.5

98th 

Percentile

% SO4

98th 

Percentile

% NO3

98th 

Percentile

% PM10

98th 

Percentile

% NO2

Caney Creek Wilderness

2001 1.318 0.609 19 62.49 34.95 1.00 1.55

2002 1.165 0.689 10 60.43 35.25 1.72 2.60

2003 1.298 0.963 19 70.90 27.64 0.62 0.85

Upper Buffalo Wilderness

2001 1.732 0.955 22 53.01 45.08 1.16 0.74

2002 2.426 0.965 18 96.29 2.75 0.96 0.00

2003 1.394 0.670 23 89.90 5.4 2.74 1.97

Hercules Glades Wilderness

2001 1.418 0.643 19 76.92 22.4 0.69 0.00

2002 1.364 0.627 15 43.49 51.71 2.08 2.72

2003 2.103 0.657 13 47.91 49.69 1.19 1.21

Mingo Wilderness

2001 1.28 0.631 11 90.97 8.59 0.42 0.01

2002 0.841 0.424 6 93.66 5.94 0.40 0.00

2003 1.488 0.393 3 38.60 59.69 1.07 0.64

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BART Analysis – Flint Creek
5. SO2 BART EVALUATION

5.1 IDENTIFICATION OF AVAILABLE RETROFIT SO2 CONTROL 

TECHNOLOGIES

Sulfur oxides, SOX, are generated during coal combustion from the oxidation of sulfur contained in 

the fuel. SOX emissions are almost entirely dependent on the sulfur content of the fuel and are 

generally not affected by boiler size or burner design. SOX emissions from conventional combustion 

systems are predominantly in the form of SO2. Since SO2 is the predominant sulfur compound emitted 

from SN-01, the BART analysis is specific to emissions of SO2.

Step 1 of the top-down control review is to identify available retrofit control options for SO2. The 

available SO2 retrofit control technologies for SN-01 are summarized in Table 5-1. The retrofit 

controls examined are limited to add-on controls that eliminate SO2 after it is formed, as SN-01 

currently uses a low sulfur fuel and would not achieve significant additional reductions through 

alternative coal supplies. 

TABLE 5-1. AVAILABLE SO2 CONTROL TECHNOLOGIES FOR SN-01

SO2 Control Technologies

Dry Sorbent Injection

Dry Scrubber

Wet Scrubber

5.2 ELIMINATE TECHNICALLY INFEASIBLE SO2 CONTROL TECHNOLOGIES

Step 2 of the BART determination is to eliminate technically infeasible SO2 control technologies that 

were identified in Step 1. 

5.2.1 DRY SORBENT INJECTION

Dry sorbent injection involves the injection of a sorbent into the exhaust gas stream where 

SO2 reacts with and becomes entrained in the sorbent. The stream is then passed through a 

particulate control device to remove the sorbent and entrained SO2. The process was 

developed as a lower cost Flue Gas Desulfurization (FGD) option because the mixing of 

the SO2 and sorbent occurs directly in the exhaust gas stream instead of in a separate tower. 

Depending on the residence time, gas stream temperature, and limitations of the particulate 

control device, sorbent injection control efficiency can range between 40 and 60 percent.13

This control is a technically feasible option for the control of SO2 from SN-01.

13 "Assessment of Control Technology Options for BART-Eligible Sources: Steam Electric Boilers, Industrial 

Boilers, Cement Plants and Paper and Pulp Facilities" Northeast States for Coordinated Air Use Management (NESCAUM), 

March 2005.

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BART Analysis – Flint Creek

 
5.2.2 DRY SCRUBBER

In a dry scrubber, an alkaline reagent (usually lime) and water is introduced into the flue 

gas stream, where it reacts with SO2 to form calcium sulfite and calcium sulfate. The 

liquid-to-gas ratio is such that the heat from the exhaust gas causes the water to evaporate 

before leaving the scrubber outlet. This leads to the formation of a dry powder which is 

carried out with the gas and collected with a fabric filter. Existing dry scrubber control 

efficiencies range from 60 to 95 percent.14 This is a technically feasible option for the 

control of SO2 from SN-01.

There are various designs of dry scrubbing systems. In the spray dryer absorber (SDA) 

design, a fine mist of lime slurry is atomized into an absorption vessel where the SO2 is 

absorbed by the slurry droplets. The mixture of reaction products (calcium sulfite/sulfate), 

unreacted lime, and fly ash is carried out with the exhaust gas and collected with a fabric 

filter. Circulating dry scrubbing (CDS) is another type of dry scrubbing. In the CDS 

process, the flue gas is introduced into the bottom of a reactor vessel at high velocity 

through a venturi nozzle; the exhaust is mixed with water, hydrated lime, recycled flyash 

and CDS reaction products. The intensive gas-solid mixing that occurs in the reactor 

promotes the reaction of SO2 in the flue gas with the dry lime particles. As with SDA, the 

mixture of reaction products (calcium sulfite/sulfate), unreacted lime, and fly ash is carried 

out with the exhaust gas and collected with a fabric filter. A large portion of the collected 

particles is recycled to the reactor to sustain the bed and improve lime utilization.

Novel Integrated Deacidification (NID) technology is another particular type of dry 

scrubber. Hydrated lime is added to recirculated dust in the mixer of the NID system. The 

solids are sprayed with a thin layer of water in the mixer before being transported to the 

reactor. The amount of water added is only a few percent which means that the dust 

remains dry. Hydrated lime reacts with SO2 in the NID-reactor and leads to the formation 

of calcium sulfite and calcium sulfate. The flue gas entrained with dry dust material enters 

the fabric filter where the dust material is captured and clean air is released to atmosphere. 

Most of the solid material captured is reused in the system. The system has a high 

recirculation ratio of the dry dust material. Discussions with vendors have indicated that 

an outlet emission rate of 0.06 lb/MMBtu at Flint Creek will be achievable with the NID 

technology evaluated. A rate of 0.06 lb/MMBtu represents a 92% control from the 

baseline 30-day average rate of 0.75 lb/MMBtu. The controlled rate was quoted as an 

outlet rate rather than a straight percent control. 

5.2.3 WET SCRUBBER

Wet scrubbing involves scrubbing the exhaust gas stream with a slurry comprised of lime 

or limestone in suspension. The process takes place in a wet scrubbing tower located 

downstream of a PM control device such as a fabric filter or an electrostatic precipitator 

(ESP). The liquid-to-gas ratio is such that the exhaust gas is fully saturated with water and 

14 EPA Basic Concepts in Environmental Sciences, Module 6: Air Pollutants and Control Techniques 

http://www.epa.gov/eogapti1/module6/sulfur/control/control.htm

Comment [JJ1]: Do we want to add anything to 

the report here reflecting the email responses we’ve 

provided to ADEQ/EPA?

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BART Analysis – Flint Creek

 
has a similar appearance to a cooling tower exhaust. Similarly to the chemistry illustrated 

above for dry scrubbing, the SO2 in the gas stream is absorbed by water and reacts with the 

lime or limestone slurry to form calcium sulfite or calcium sulfate. Wet lime scrubbing is 

capable of achieving 80-95 percent control when used with lower sulfur coals like those 

burned at SN-01.15 This control is a technically feasible option for the control of SO2 from 

SN-01.

5.3 RANK OF TECHNICALLY FEASIBLE SO2 CONTROL OPTIONS BY 

EFFECTIVENESS

The third step in the BART analysis is to rank the technically feasible options according to their 

effectiveness in reducing the visibility affecting pollutants (VAP). Table 5-2 provides a ranking of 

the control levels for the controls listed in the previous section for SN-01.

TABLE 5-2. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE SO2 CONTROL 

TECHNOLOGIES

Control Technology

Controlled Emission 

Rate 

(lb/MMBtu)

Estimated Control 

Efficiency 

Wet Scrubbing 0.04 95%

Dry Scrubbing, e.g., NID 0.06 92%

Dry Sorbent Injection 0.30 60%

5.4 EVALUATION OF IMPACTS FOR FEASIBLE SO2 CONTROLS 

A shown in Table 5-2, wet scrubbing can achieve a 95% reduction in SO2 while dry scrubbing or NID

can achieve a 92% reduction in SO2, and these technologies are the most effective technologies at 

reducing SO2. Step four of the BART analysis procedure is the impact analysis. The BART 

determination guidelines list the four factors to be considered in the impact analysis:

▲ Cost of compliance

▲ Energy impacts

▲ Non-air quality impacts; and

▲ The remaining useful life of the source

15 Ibid.

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BART Analysis – Flint Creek

 
AEP is providing Step 4 and Step 5 evaluations specific to the NID technology as well as WFGD.

Also, AEP is providing a discussion of energy and non-air quality impacts of wet scrubbing versus 

the NID technology.

5.4.1 COST OF COMPLIANCE

Control Costs

The capital and operating costs of WFGD and NID used in the cost effectiveness 

calculations were estimated based on EPA’s Air Pollution Control Cost Manual 

supplemented with vendor and site-specific information where available. The capital costs 

were annualized over a 30-year period and then added to the annual operating costs to 

obtain the total annualized costs. The details of the capital and operating cost estimates are 

provided in Appendix A of this report. 

Annual Tons Reduced

The annual tons reduced that were used in the cost effectiveness calculations were 

determined by subtracting the estimated controlled annual emission rate from the baseline 

annual emission rate. The baseline annual emission rate is the average rate from 2001-

2003, as reported by AEP in their air emission inventories. The controlled annual emission 

rates were based on lb/MMBtu levels believed to be achievable for the control technology

multiplied by the baseline heat input in MMBtu/yr to the boiler. The baseline heat input is 

based on the 2001-2003 average daily heat input for SN-01 as determined from the EPA’s 

Clean Air Markets Database (CAMD), divided by 24 hours in a day times an estimated 

7,752 hours per year, the average number of operating hours from 2001-2003.

Cost Effectiveness

The cost effectiveness in dollars per ton of SO2 reduced was determined by dividing the 

annualized cost of control by the annual tons reduced. Table 5-3 indicates that the cost 

effectiveness of the wet scrubber at an SO2 rate of 0.04 lb/MMBtu is approximately $4,900

per ton of SO2 removed. The cost effectiveness in dollars per deciview of visibility is over 

$476 million/dv across the Class I areas, as seen in Table 5-4. 

By comparison, Table 5-3 shows the cost effectiveness of a NIDS at an SO2 rate of 0.06 

lb/MMBtu is approximately $3,800 per ton of SO2 removed. The cost effectiveness in 

dollars per deciview is approximately $368 million/dv across the Class I areas, as seen in 

Table 5-5. Table 5-3 shows that the wet scrubber is approximately $35,000/ton 

incrementally more expensive than the dry scrubber. 

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BART Analysis – Flint Creek
TABLE 5-3. SUMMARY OF COST EFFECTIVENESS FOR SN-01 SO2 CONTROLS 

Control Technology

Baseline 

Emission 

Rate

Controlled 

Emission 

Level

Annual Heat 

Input

Controlled 

Emission 

Rate

SO2 

Reduced Capital Cost

Capital 

Recovery + 

Other Indirect 

Annual Costs

Annual 

Fixed O&M

Annual 

Variable 

O&M

Total 

Annual 

Cost

Cost 

Effectiveness

Incremental 

Cost 

(tpy) (lb/MMBtu) (MMBtu/yr) (tpy) (ton/yr) ($) ($/yr) ($/yr) ($/yr) ($/yr) ($/ton) ($/ton)

NIDS 11,641.00 0.06 37,344,783 1,120.34 10,520.66 281,738,024 30,763,370 205,825 9,478,894 40,448,089 3,845 -

Wet Scrubber 11,641.00 0.04 37,344,783 746.90 10,894.10 374,427,351 40,884,248 205,825 12,502,590 53,592,663 4,919 35,198

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BART Analysis – Flint Creek
TABLE 5-4. DOLLAR PER DECIVIEW COST EFFECTIVENESS FOR SN-01 SO2 CONTROLS OF WET SCRUBBING

Caney Creek 0.963 0.334 0.629 53,592,663 $ 85,202,962

Hercules-Glades 0.657 0.305 0.352 53,592,663 $ 152,251,885

Mingo 0.631 0.208 0.423 53,592,663 $ 126,696,604

Upper Buffalo 0.965 0.488 0.477 53,592,663 $ 112,353,592

Class I Area $/dv

Baseline 98th 

Percentile ∆dv

WFGD Controlled 98th 

Percentile ∆dv

Improvement in 98th 

Percentile ∆dv

Total Annual WFGD 

Cost

TABLE 5-5. DOLLAR PER DECIVIEW COST EFFECTIVENESS FOR SN-01 SO2 CONTROLS OF NIDS

Caney Creek 0.963 0.348 0.615 40,448,089 $ 65,769,251

Hercules-Glades 0.657 0.312 0.345 40,448,089 $ 117,240,838

Mingo 0.631 0.217 0.414 40,448,089 $ 97,700,699

Upper Buffalo 0.965 0.501 0.464 40,448,089 $ 87,172,606

Class I Area $/dv

Baseline 98th 

Percentile ∆dv

NID Controlled 98th Percentile 

∆dv

Total Annual NID 

Cost

Improvement in 98th 

Percentile ∆dv

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BART Analysis – Flint Creek
5.4.2 ENERGY IMPACTS AND NON-AIR QUALITY IMPACTS

Wet scrubbing is expected to achieve a slightly higher level of control of SO2 emissions 

compared to the proposed NID technology. However, the negative non-air quality 

environmental impacts are greater with wet scrubbing systems. Wet scrubbers require 

increased water use and generate large volumes of wastewater and solid waste/sludge that 

must be treated. This places additional burdens on the wastewater treatment and solid 

waste management capabilities. Moreover, if wet scrubbing produces calcium sulfite 

sludge, the sludge will be water-laden, and it must be stabilized before landfilling. Wet 

scrubbing systems have increased power requirements and increased reagent usage over 

dry scrubbers. Wet scrubber-controlled systems also have the potential for increased

particulate and sulfuric acid mist releases. Thus, from an overall environmental 

perspective, dry scrubbing (i.e., NID technology) is superior to wet scrubbing. 

5.4.3 REMAINING USEFUL LIFE

The remaining useful life of SN-01 does not impact the annualized capital costs because 

the useful life of the unit is anticipated to be at least as long as the capital cost recovery 

period, which is 30 years based on EPA cost estimates.

5.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE SO2 CONTROLS 

A final impact analysis was conducted to assess the visibility improvement achieved by comparing 

the impacts associated with the baseline emission rates to the impacts associated with the controlled 

emission rates. Section 4 of this report documents the existing visibility impairment attributable to 

SN-01. In order to assess the visibility improvement associated with the considered control options, 

the controlled SO2 emission rates were modeled using CALPUFF. 

The SO2 emission rate associated with the NID for SN-01 is detailed as follows:

P * HI = 379.44 lb/hr

Where:

P (controlled emission level) = 0.06 lb/MMBtu

HI (hourly heat input) = 6,324 MMBtu/hr

Table 5-6 summarizes the lb/hr emission rates that were modeled to reflect the addition of NIDS as a 

control at Flint Creek. The SO2 rate was developed from the controlled rate of 0.06 lb/MMBtu and 

the boiler heat input of 6,324 MMBtu/hr. The SO4 emission rate was determined assuming the 

reduction in SO4 from the baseline case is proportional to the reduction in SO2 from the baseline case 

to the controlled case (92%). The NIDS will have co-effects on some of the acid gases. The control 

of H2SO4 will result in fewer sulfates. The NOX emission rate was modeled at the baseline rate. The 

NIDS involves the use of a baghouse. The change from the current ESP to baghouse will result in 

changes in PM speciation. All other rates that changed from the baseline case were determined using 

the National Parks Services (NPS) speciation spreadsheets for dry bottom boilers burning pulverized 

coal using only fabric filter for emissions control. 

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BART Analysis – Flint Creek
Table 5-6 also summarizes the emission rates that were modeled to reflect the addition of a wet 

scrubber on SN-01, at an outlet emission rate of 0.04 lb/MMBtu. The SO2 rate was developed by 

multiplying the controlled level of 0.04 lb/MMBtu by the boiler heat input of 6,324 MMBtu/hr. The 

NOX emission rates were modeled at the baseline rates. The PM rates that changed from the baseline 

case were determined using the NPS speciation spreadsheets for dry bottom boilers burning 

pulverized coal using only fabric filter for emissions control. The SO4 rates were calculated using the 

same EPRI methodology used for the baseline case.

TABLE 5-6. SUMMARY OF EMISSION RATES MODELED TO REFLECT SO2 CONTROLS

Control Technology

SO2

(lb/hr)

SO4

(lb/hr)

NOx

(lb/hr)

PMC

(lb/hr)

PMF

(lb/hr)

SOA

(lb/hr)

EC

(lb/hr)

NIDS 379.4 0.004 1,945.0 35.2 33.9 24.4 1.3

Wet Scrubber 253.0 0.11 1,945.0 35.2 33.9 24.4 1.3

Comparisons of the existing visibility impacts and the visibility impacts based on the NIDS, including 

the maximum modeled visibility impact, 98th percentile modeled visibility impact, and the number of 

days with a modeled visibility impact greater than 0.5 Δdv, for each Class I area are provided in Table 

5-7. 

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BART Analysis – Flint Creek
TABLE 5-7. SUMMARY OF MODELED IMPACTS FROM SO2 CONTROL VISIBILITY IMPACT ANALYSIS FOR SN-01 (2001-2003)

Caney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness Mingo NWR Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Maximum Impact (Δdv) 98% Impact (Δdv)

# Days > 0.5 Δdv

Existing 

Emission Rate

1.318 0.963 48 2.426 0.965 63 2.103 0.657 47 1.488 0.631 20

NIDS 0.753 0.348 6 1.474 0.501 13 0.882 0.312 5 0.694 0.217 4

Post Control 

Improvement

0.565 0.615 42 0.952 0.464 50 1.221 0.345 42 0.794 0.414 15

Wet Scrubber 0.746 0.334 5 1.446 0.488 11 0.845 0.305 5 0.677 0.208 4

Post Control 

Improvement 

over NIDS

0.007 0.014 1 0.028 0.013 2 0.037 0.007 0 0.017 0.009 0

Note: The visibility improvement shown in the table has been calculated from baseline and controlled impacts that include more decimal places than what is 

shown in the table. Due to rounding of the baseline and controlled impacts shown in the table, the visibility improvement calculated from the baseline and 

controlled impacts shown in the table may be slightly different than the visibility improvement reflected in the table.

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BART Analysis – Flint Creek
As shown in Table 5-7, based on visibility predictions from the CALPUFF modeling system, the 

operation of a dry scrubber will result in up to a 0.647 Δdv improvement (98th percentile basis) 

(depending on the Class I area) to the existing visibility impairment attributable to SN-01. By 

comparison, wet scrubbing does not add additional visibility improvement for SN-01 over dry 

scrubbing. The reason wet scrubbing, despite the lower SO2 emission rate, does not produce greater 

visibility improvement is because it results in other visibility impairing emissions.16 

5.6 PROPOSED BART FOR SO2

SWEPCO is proposing that the SO2 BART emission rate for SN-01 be 0.06 lb/MMBtu, based on the 

installation and operation of the NID technology. AEP is proposing to meet this limit calculated as a 

30-day rolling average over each boiler operating day. Compliance will be demonstrated using data 

from the existing continuous emissions monitoring systems (CEMS).

The visibility improvement attributable to SN-01 through the use of the NIDS ranges from 48.1% to 

65.6% across the affected Class I areas (98th percentile basis). This level of improvement is 

achievable at a cost effectiveness of approximately $3,800 per ton of SO2 removed. By comparison, 

wet scrubbing is incrementally more expensive and offers less visibility improvement overall. In 

addition, the adverse environmental impacts from the use of wet scrubbing, including an increase in

particulate and sulfuric acid mist emissions as well as increased water and energy usage and 

wastewater to be treated, make dry scrubbing a more appealing option. 

5.6.1 COMPARATIVE SO2 BART DETERMINATIONS

The BART emission level proposed for SN-01 is among the most stringent BART emission levels 

approved for any coal-fired generating unit over the last two years. In Oklahoma, for similar boilers, 

EPA determined BART to be 0.06 lb/MMBtu achieved through use of dry scrubbers.17 In 

Nebraska18 at the Gerald Gentleman Station, BART for SO2 was also determined to be 0.06 

lb/MMBtu achieved through use of dry scrubbers. These similar units provide a good comparison of 

emission levels achievable through similar control technology. Levels lower than 0.06 lb/MMBtu 

have been considered, but rejected based on lack of operating experience on retrofit units, the 

incremental cost of additional reductions, and the limited incremental visibility improvement 

associated with those costs. AEP has no data to suggest that lower emission levels are sustainably 

achievable with the NID technology in a retrofit application, and has not been guaranteed any better 

performance by equipment vendors. All of these reasons support rejecting any lower emission level

for SN-01.

Other BART determinations have resulted in higher emission limitations. For example, in Alabama19

a smaller EGU was allowed an emission limitation of 0.47 lb/MMBtu through use of flue sorbent 

injection or comparable technologies. In Arizona20, SO2 BART was determined to be in the range of 

16 Wet scrubbers have less affinity for acid mist than dry scrubbers; thus, sulfate particles that form from sulfuric 

acid in the stack will be lower for dry scrubbers than wet scrubbers. AEP’s best understanding of the reason wet scrubbing 

does not produce greater visibility improvement that drying scrubbing, despite the lower SO2 rate, is that the SO4 rate 

associated with wet scrubbing is higher.

17 77 Fed. Reg. 16168 (March 22, 2011).

18 77 Fed. Reg. 40150 (July 6, 2012).

19 77 Fed. Reg. 11937 (Feb. 28, 2012).

20 77 Fed. Reg. 42834 (July 20, 2012).

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BART Analysis – Flint Creek

 
0.08 – 0.15 lb/MMBtu from existing wet scrubbers. An EGU in Colorado21 has a proposed BART 

emission rate of 0.13 lb/MMBtu through use of dry scrubbing. It is interesting to note that a lower 

emission rate of 0.09 lb/MMBtu was evaluated and determined not reasonable due to the little 

visibility improvement as compared to the higher costs between scrubbing at these two rates. 

In other determinations, such as Illinois22, the control technology was not stated in the BART 

determination but the SO2 rate determined to be BART was in the range of 0.11 – 0.23 lb/MMBtu, 

dependent upon boiler type and averaging considerations. SO2 BART in Kansas23 was achieved 

through “scrubbing” with an emission limitation of 0.10 lb/MMBtu for one boiler and through wet 

scrubbing with an emission limitation of 0.15 lb/MMBtu for another. An EGU in Montana24 similar 

to AEP’s SN-01 has a BART emission rate of 0.08 lb/MMBtu. 

The proposed SO2 BART emission rate is equivalent to the most stringent rates previously approved 

by EPA, is consistent with the design specifications for this equipment, and results in significant 

visibility improvement in the affected Class I areas. The SO2 emission rate of 0.06 lb/MMBtu should 

be adopted as BART for SN-01.

21 77 Fed. Reg. 18052 (March 26, 2012).

22 77 Fed. Reg. 3966 (Jan. 26, 2012).

23 77 Fed. Reg. 52604 (Aug. 23, 2011).

24 77 Fed. Reg. 23988 (April 20, 2012).

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BART Analysis – Flint Creek

 
6. NOX BART EVALUATION

6.1 CROSS-STATE AIR POLLUTION RULE,

CLEAN AIR INTERSTATE RULE, AND BART

On June 7, 2012 EPA published a final rule allowing states participating in the Cross-State Air 

Pollution Rule (CSAPR) trading program to use CSAPR to satisfy BART. Arkansas is one of the 

states with units subject to CSAPR that will participate in a NOX trading program during the ozone 

season. EPA commented that “NOX control in the five ozone season-only states is achieved 

predominantly by combustion controls.”25 Due to the nature of combustion controls, plants typically 

keep combustion controls in place and running year-round, even if emission limitations are seasonal. 

Although Arkansas is an ozone season-only state, combustion controls would run anytime the unit is 

in operation. However, on August 21, 2012, the D. C. Circuit Court of Appeal issued a decision 

vacating CSAPR and ordering EPA to continue to implement the Clean Air Interstate Rule (CAIR) 

until a new rule is adopted to replace it. The Court’s decision will not be effective until the time for 

filing rehearing petitions has passed, or any filed petitions for rehearing have been considered by the 

Court.26 If CSAPR is upheld and implemented in Arkansas, SWEPCO proposes rely on CSAPR to 

satisfy its regional haze obligations at SN-01. 

Prior to adopting CSAPR, EPA issued a rule confirming that CAIR provides greater reasonable 

progress toward the national visibility goal than application of BART for NOX emissions at BARTeligible sources.27 Since EPA has made the determination that CAIR reductions provide better 

progress than BART, and Arkansas has adopted the CAIR requirements into the Arkansas SIP,28

SWEPCO should be entitled to rely upon CAIR to satisfy its obligations for NOX reductions at SN01, if CSAPR is vacated in accordance with the D. C. Circuit’s opinion. 

In the alternative, SWEPCO has evaluated the cost-effectiveness and visibility improvement of 

candidate BART controls at SN-01. The visibility improvements associated with the addition of NOX

controls at SN-01 are minimal, and the cost-effectiveness values for all control options exceed the 

values previously determined to be reasonable in EPA’s presumptive BART analysis. However, 

visibility improvements consistent with the modeled values used in CENRAP’s analysis for the 

interstate transport portion of Arkansas’s Regional Haze SIP obligations can be achieved with the 

addition of newer generation LNB/OFA systems, and are proposed as BART for SN-01. If ADEQ 

determines that SWEPCO cannot rely on CAIR or CSAPR as an alternative to BART, the proposed 

BART emission rate for NOX at SN-01 is 0.23 lb/MMBtu calculated as a 30-day rolling average over 

each boiler operating day based on the application of LNB/OFA controls.

25 “Regional Haze: Revisions to Provisions Governing Alternatives to Source-Specific Best Available Retrofit 

Technology (BART) Determination, Limited SIP Disapprovals, and Federal Implementation Plans,” 77 Fed. Reg. 33651 

(June 7, 2012).

26 EME Homer City v. EPA, Case No. 11-1302 and consolidated cases, Opinion, (D.C. Cir. Aug. 21, 2012).

27 70 Fed. Reg. 39104, 39136-37, and 39143 (July 6, 2005).

28 APC&EC Reg. 19.1401 et seq.; approved at 72 Fed. Reg. 54556 (Sept. 26, 2007).

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BART Analysis – Flint Creek

 
6.2 IDENTIFICATION OF AVAILABLE RETROFIT NOX CONTROL 

TECHNOLOGIES

Nitrogen oxides, NOX, are produced during fuel combustion when nitrogen contained in both the fuel 

and the combustion air is exposed to high temperatures. The origin of the nitrogen (i.e. fuel vs. 

combustion air) has led to the use of the terms “thermal” NOX and “fuel” NOX when describing NOX

emissions. Thermal NOX emissions are produced when elemental nitrogen in the combustion air is 

exposed to a high temperature zone and oxidized. Fuel NOX emissions are created during the rapid 

oxidation of nitrogen compounds contained in the fuel. 

Nitrogen oxide (NO) is typically the predominant form of NOX from fossil fuel combustion. Nitrogen 

dioxide (NO2) makes up the remainder of the NOX. The formation of NOX compounds in utility 

boilers is sensitive to the method of firing. In a wall-fired boiler, such as SN-01, burners are mounted 

in the boiler walls, producing discrete flames in the furnace. In tangentially-fired boilers, a single 

rotating flame is created in the center of the furnace, rather than the discrete flames produced by 

burners in the wall-fired boilers. Tangentially fired boilers typically have lower uncontrolled NOX

emissions than wall-fired boilers. Therefore baseline NOX emission rates can vary significantly from

plant to plant due to method of firing and also several other factors.

Step 1 of the BART determination is the identification of all available retrofit NOX control 

technologies. The available retrofit NOX control technologies are summarized in Table 6-1 for

SN-01.

NOX emissions controls, as listed in Table 6-1, can be categorized as combustion or post-combustion 

controls. Combustion controls, including flue gas recirculation (FGR), overfire air (OFA), and Low 

NOX Burners (LNB), reduce the peak flame temperature and excess air in the furnace which 

minimizes NOX formation. Post-combustion controls, such as selective catalytic reduction (SCR) and 

selective non-catalytic reduction (SNCR) convert NOX in the flue gas to molecular nitrogen and 

water. 

TABLE 6-1. AVAILABLE NOX CONTROL TECHNOLOGIES FOR SN-01

NOX Control Technologies

Combustion Controls

Flue Gas Recirculation (FGR)

Overfire Air (OFA)

Low NOX Burners (LNB) 

Post-Combustion Controls Selective Catalytic Reduction (SCR)

Selective Non-Catalytic Reduction (SNCR)

6.3 ELIMINATE TECHNICALLY INFEASIBLE NOX CONTROL TECHNOLOGIES

Step 2 of the BART determination is to eliminate technically infeasible NOX control technologies that 

were identified in Step 1. Control ranges were developed using a combination of literature control 

ranges and efficiencies. Because many controlled emission levels from literature were higher than the 

baseline NOX rate at SN-01, vendor estimates were also used to assist in developing the expected 

emission rates from the known relationships between the control options. 

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BART Analysis – Flint Creek
6.3.1 COMBUSTION CONTROLS

6.3.1.1 FLUE GAS RECIRCULATION (FGR)

FGR uses flue gas as an inert material to reduce flame temperatures. In a 

typical flue gas recirculation system, flue gas is collected from the combustion 

chamber or stack and returned to the burner via a duct and blower. The 

addition of flue gas reduces the oxygen content of the “combustion air” (air + 

flue gas) in the burner. The lower oxygen level in the combustion zone reduces 

flame temperatures; which in turn reduces thermal NOX formation. When 

operated without additional controls, the NOX control range for coal fired 

boilers with FGR is approximately 5-25% for coal fired boilers, or 0.23-0.29 

lb/MMBtu from SN-01.29 This control is a technically feasible option for the 

control of NOX from SN-01. 

6.3.1.2 OVERFIRE AIR (OFA)

OFA diverts a portion of the total combustion air from the burners and injects it 

through separate air ports above the top level of burners. Staging of the 

combustion air creates an initial fuel-rich combustion zone with a lower peak 

flame temperature. This reduces the formation of thermal NOX by lowering 

combustion temperature and limiting the availability of oxygen in the 

combustion zone where NOX is most likely to be formed. OFA as a single NOX

control technique results in estimated NOX emissions for coal fired boilers of 

approximately 10%, or 0.28-0.29 lb/MMBtu from SN-01.30 This control is a 

technically feasible option for the control of NOX from SN-01.

6.3.1.3 LOW NOX BURNERS

LNB technology utilizes advanced burner design to reduce NOX formation 

through the restriction of oxygen, lowering of flame temperature, and/or 

reduced residence time. NOX creation rates typically peak at oxygen levels of 

five to seven percent.31 LNB is a staged combustion process that is designed to 

split fuel combustion into two zones. In the primary zone, NOX formation is 

limited by one of two methods. Under staged fuel-rich conditions, low oxygen 

levels limit flame temperatures resulting in less NOX formation. The primary 

zone is then followed by a secondary zone in which the incomplete combustion 

products formed in the primary zone act as reducing agents. Alternatively, 

under staged fuel-lean conditions, excess air will reduce flame temperature to 

reduce NOx formation. In the secondary zone, combustion products formed in 

the primary zone act to lower the local oxygen concentration, resulting in a 

decrease in NOx formation. 

29 “Controlling Nitrogen Oxides Under the Clean Air Act: A Menu of Options.” Utility Boiler section. July 

1994. 

30 Ibid.

31 http://www.energysolutionscenter.org/boilerburner/Workshop/RCTCombustion.htm.

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The estimated NOX control range for LNBs on coal boilers is 0.20-0.26 

lb/MMBtu.32 When combined with OFA, the estimated NOX control range on 

is 0.18-0.24 lb/MMBtu.33 LNB systems are technically feasible for the control 

of NOx from SN-01.

6.3.2 POST COM BUSTION CONTROLS

6.3.2.1 SELECTIVE CATALYTIC REDUCTION

SCR refers to the process in which NOX is reduced by ammonia over a 

heterogeneous catalyst in the presence of oxygen. The process is termed 

selective because the ammonia preferentially reacts with NOX rather than 

oxygen, although the oxygen enhances the reaction and is a necessary 

component of the process. The overall reactions are:

4NO + 4NH3 + O2  4N2 + 6H2O

2NO2 + 4NH3 + O2  3N2 + 6H2O

The SCR process requires a reactor, a catalyst, and an ammonia storage and 

injection system. The effectiveness of an SCR system is dependent on a variety 

of factors, including the inlet NOX concentration, the exhaust temperature, the 

ammonia injection rate, and the type of catalyst. The estimated NOX control for 

SCR on coal fired boilers is 80-90%, and is consistent with vendor estimates of 

0.067 lb/MMBtu at SN-01, resulting in an 80% control efficiency.34 Control 

efficiencies of 80-90% depend on the design of the boiler as well as the starting 

baseline emissions. The vendor was able to provide an estimate of control as 

an outlet emission level of 0.067 lb/MMBtu, a low emission level. A 90% 

percent reduction would result in an outlet emission rate of 0.03 lb/MMBtu and 

has not been guaranteed by a vendor. This control is a technically feasible 

option for the control of NOX from SN-01.

6.3.2.2 SELECTIVE NON-CATALYTIC REDUCTION

In SNCR systems, a reagent is injected into the flue gas in the furnace within an 

appropriate temperature window. The NOX and reagent (ammonia or urea) 

react to form nitrogen and water. A typical SNCR system consists of reagent 

storage, multi-level reagent-injection equipment, and associated control 

instrumentation. The SNCR reagent storage and handling systems are similar 

to those for SCR systems. However, both ammonia and urea SNCR processes 

require three to four times as much reagent as SCR systems to achieve similar 

NOX reductions. The estimated NOX control range for SNCR for coal fired 

boilers is 0.18-0.27 lb/MMBtu.35 This control is a technically feasible option 

for the control of NOX from SN-01.

32 “Controlling Nitrogen Oxides Under the Clean Air Act: A Menu of Options.” Utility Boiler section. July 

1994. 

33 Ibid.

34 Ibid.

35 Ibid.

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BART Analysis – Flint Creek

 
6.4 RANK OF TECHNICALLY FEASIBLE NOX CONTROL OPTIONS BY 

EFFECTIVENESS

The third step in the BART analysis is to rank the technically feasible options according to 

effectiveness. Table 6-2 provides a ranking of the control levels for the controls listed in the 

previous section for SN-01.

TABLE 6-2. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE NOX CONTROL 

TECHNOLOGIES

Control Technology

Estimated Controlled 

Level for SN-01 

(lb/MMBtu) 36

SCR 0.067

LNB/OFA + SNCR 0.18-0.23 37

LNB/OFA 0.18-0.24

SNCR 0.18-0.27

FGR 0.23-0.29

LNB 0.20-0.26

OFA 0.28-0.29

With the exception of the control level for SCR, the control levels in Table 6-2 are presented as 

ranges. This is due to the fact that the specific level of control that is achievable for SN-01 based on 

the application of the controls listed in Table 6-2 is unknown. Based on several discussions between 

AEP Flint Creek and the Babcock and Wilcox Company, it is believed that combustion controls such 

as LNB in combination with OFA will achieve a NOX level of approximately 0.23 lb/MMBtu for SN01. EPA established presumptive SO2 and NOX controls for coal-fired EGUs in the BART rule. For 

dry-bottom wall-fired EGUs, the presumptive NOX limit is 0.23 lb/MMBtu.38 The presumptive 

BART emission rate was modeled for this source by CENRAP. Although 0.23 lb/MMBtu is the 

presumptive limit for a unit like SN-01, the presumptive limit was not automatically assumed the 

floor for combustion control on SN-01. Rather, experience with similar boilers and vendor 

discussions have led the selection of this emission level. Current NOX emissions from SN-01 are 

approximately 0.31 lb/MMBtu. Further, it is believed that SCR will achieve a NOX level of 

approximately 0.067 lb/MMBtu and LNB/OFA + SNCR will achieve a level of 0.2 lb/MMBtu or 10-

20% better control than from LNB/OFA alone. Vendor estimates for LNB/OFA + SNCR were not 

available at the time of this analysis, and obtaining vendor estimates would add significantly to the 

timing of this analysis submittal. 

6.5 EVALUATION OF IMPACTS FOR FEASIBLE NOX CONTROLS 

Step four for the BART analysis is the impact analysis. The BART determination guidelines list four 

factors to be considered in the impact analysis:

36 Ibid.

37 “Preferred and Alternative Methods for Estimating Air Emissions from Boilers.” Volume II: Chapter 2. 

January 2001.

38 Ibid.

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BART Analysis – Flint Creek

 
▲ Cost of compliance

▲ Energy impacts

▲ Non-air quality impacts; and

▲ The remaining useful life of the source

6.5.1 COST OF COMPLIANCE

The capital costs, operating costs, and cost effectiveness of LNB/OFA, LNB/OFA + SNCR 

and SCR were estimated for the cost analysis. 

Control Costs

The capital and operating costs of the controls that were used in the cost effectiveness 

calculations were estimated based on vendor estimates and published calculation methods. 

The EPA Air Pollution Control Cost Manual was followed to the extent possible and was 

supplemented with vendor and site-specific information where available. The capital 

costs were annualized over a 15-year period for LNB/OFA and over a 20-year period for 

both SCR and SNCR, and then added to the annual operating costs to obtain the total 

annualized costs. The details of the capital and operating cost estimates are provided in 

Appendix B of this report. 

Annual Tons Reduced

The annual tons reduced that were used in the cost effectiveness calculations were 

determined by subtracting the estimated controlled annual emission rate from the baseline 

annual emission rate. 

The baseline annual emission rate is the average rate as reported by AEP in the 2001-2003 

air emission inventories. The controlled annual emission rate is based on the lb/MMBtu 

level believed to be achievable from the control technology multiplied by the baseline heat 

input to the boiler in MMBtu/yr. The baseline heat input is based on the 2001-2003 

average daily heat input for SN-01 as determined from the EPA’s Clean Air Markets 

Database (CAMD), divided by 24 hours in a day times an estimated 7,752 hours per year, 

the average number of operating hours from 2001-2003.

Cost Effectiveness

The cost effectiveness in dollars per ton of NOX reduced was determined by dividing the 

annualized cost of control by the annual tons reduced. An incremental cost analyses was 

also performed to show the incremental increase in costs between SCR and an LNB/OFA 

system, as well as between LNB/OFA + SNCR and LNB/OFA. The costs effectiveness 

analysis is summarized in Table 6-3. 

In the BART guidelines, EPA calculated that for all types of boilers other than cyclone 

boilers, combustion control technology is generally more cost-effective than postcombustion controls. EPA estimates that approximately 75 percent of the BART units 

(non-cyclone) could meet the presumptive NOX limits at a cost of $100 to $1,000 per ton of 

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BART Analysis – Flint Creek
NOX removed based on the use of combustion control technology.39 For the units that 

could not meet the presumptive limits using combustion control technology, EPA estimates 

that almost all of these sources could meet the presumptive limits using advanced 

combustion controls. The EPA estimates that the costs of such controls are usually less 

than $1,500 per ton of NOX removed.40 

Table 6-3 indicates that the cost effectiveness of LNB/OFA at a NOX rate of 0.23 

lb/MMBtu is $2,579 per ton of NOX removed. Table 6-3 also indicates that the costs for 

LNB/OFA/SNCR for SN-01 is approximately $3,600/ton of NOX removed and SCR for 

SN-01 is more than $4,300 per ton of NOX removed. Additionally, the incremental cost of 

the LNB/OFA/SNCR over the LNB/OFA system is greater than $5,200 per ton of NOX

removed for SN-01. The incremental cost of SCR over the LNB/OFA system is nearly

$4,800/ton of NOX removed for SN-01. 

The cost effectiveness in dollars per deciview of visibility improvement attributable to the 

each NOX control technology was also determined. Additional details on the visibility 

improvement analysis are provided below. The cost of LNB/OFA is approximately $341

million/dv across the Class I areas, as seen in Table 6-4. The cost of LNB/OFA plus 

SNCR is approximately $588 million/dv across the Class I areas, as seen in Table 6-5. 

Table 6-6 shows that control of NOX from SCR results in a cost of approximately $895

million/dv across the Class I areas. So a review of cost effectiveness on a dollars per 

deciview basis reveals that both post-combustion control options are prohibitively 

expensive relative to the LNB/OFA control option.

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

Final Rule.” CFR Vol. 77, No. 128. Wednesday, July 6, 2005, Rules and Regulations. Pages 39134-39135.

40 Ibid.

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BART Analysis – Flint Creek

 
TABLE 6-3. SUMMARY OF COST EFFECTIVENESS FOR SN-01 NOX CONTROLS

Baseline Emission 

Rate

Controlled 

Emission 

Level

Annual Heat 

Input4

Controlled 

Emission 

Rate

NOx 

Reduced Capital Cost

Annual 

Capital Cost

Annual 

Fixed O&M

Annualized 

Variable 

O&M

Total 

Annual 

Cost

Cost 

Effectiveness

 Incremental 

Cost 

(tpy) (lb/MMBtu) (MMBtu/yr) (tpy) (ton/yr) ($) ($/yr) ($/yr) ($/yr) ($/yr) ($/ton) ($/ton)

LNB/OFA1 5,120.27 0.23 37,344,776 4294.65 825.62 16,000,000 1,756,714 240,000 132,364 2,129,078 2,579 -

LNB/OFA/SNCR2 5,120.27 0.20 37,344,776 3771.82 1348.44 23,124,235 2,429,191 240,000 2,183,048 4,852,239 3,598 5,209

SCR3 5,120.27 0.07 37,344,776 1251.05 3869.22 121,440,000 11,463,077 1,560,000 3,700,000 16,723,077 4,322 4,795

3

 SCR Cost information: Please refer to Appendix B.

1

 LNB Cost information: Please refer to Appendix B.

2

 SNCR Cost information: Please refer to Appendix B.

4

 Baseline heat input was determined from CAMD, 2001-2003, average daily heat inputs times the average number of operating hours from 2001-2003 divided by 24 hours in a day.

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BART Analysis – Flint Creek
TABLE 6-4. DOLLAR PER DECIVIEW COST EFFECTIVENESS FOR SN-01 NOX CONTROL USING LNB/OFA

Caney Creek 0.963 0.849 0.114 2,129,078 $ 18,676,121

Hercules-Glades 0.657 0.633 0.024 2,129,078 $ 88,711,577

Mingo 0.631 0.617 0.014 2,129,078 $ 152,076,989

Upper Buffalo 0.965 0.939 0.026 2,129,078 $ 81,887,609

$/dv

Baseline 98th 

Percentile ∆dv

Improvement in 98th 

Percentile ∆dv

Total Annual 

Class I Area LNB/OFA Cost

LNB/OFA Controlled 98th 

Percentile ∆dv

TABLE 6-5. DOLLAR PER DECIVIEW COST EFFECTIVENESS FOR SN-01 NOX CONTROL USING LNB/OFA PLUS SNCR

Caney Creek 0.963 0.849 0.114 4,852,239 $ 42,563,504

Hercules-Glades 0.657 0.623 0.034 4,852,239 $ 142,712,926

Mingo 0.631 0.612 0.019 4,852,239 $ 255,381,025

Upper Buffalo 0.965 0.932 0.033 4,852,239 $ 147,037,560

$/dv

Baseline 98th 

Percentile ∆dv

Improvement in 98th 

Percentile ∆dv

Total Annual 

LNB/OFA + SNCR 

Class I Area Cost

LNB/OFA/SNCR 98th 

Percentile ∆dv

TABLE 6-6. DOLLAR PER DECIVIEW COST EFFECTIVENESS FOR SN-01 NOX CONTROL USING SCR

Caney Creek 0.963 0.718 0.245 16,723,077 $ 68,257,457

Hercules-Glades 0.657 0.573 0.084 16,723,077 $ 199,084,249

Mingo 0.631 0.588 0.043 16,723,077 $ 388,908,765

Upper Buffalo 0.965 0.895 0.07 16,723,077 $ 238,901,099

$/dv

Baseline 98th 

Percentile ∆dv

Improvement in 98th 

Percentile ∆dv

Total Annual SCR 

Class I Area Cost

SCR Controlled 98th Percentile 

∆dv

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BART Analysis – Flint Creek
6.5.2 ENERGY IMPACTS & NON-AIR IMPACTS

SCR systems require electricity to operate the ancillary equipment. The need for electricity 

to help power some of the ancillary equipment creates a demand for energy that currently 

does not exist. 

SCR and SNCR can potentially cause significant environmental impacts related to the 

storage of ammonia. The storage of aqueous ammonia above 10,000 lbs is regulated by a 

risk management program (RMP), since the accidental release of ammonia has the 

potential to cause serious injury and death to persons in the vicinity of the release. SCR 

and SNCR will likely also cause the release of unreacted ammonia to the atmosphere. 

This is referred to as ammonia slip. Ammonia slip from SCR and SNCR systems occurs 

either from ammonia injection at temperatures too low for effective reaction with NOx, 

leading to an excess of unreacted ammonia, or from over-injection of reagent leading to 

uneven distribution; which also leads to an excess of unreacted ammonia. Ammonia 

released from SCR and SNCR systems will react with sulfates and nitrates in the 

atmosphere to form ammonium sulfate and ammonium nitrate. Together, ammonium 

sulfate and ammonium nitrate are the predominant sources of regional haze. 

6.5.3 REMAINING USEFUL LIFE

The remaining useful life of SN-01 does not impact the annualized capital costs of 

potential controls because the useful life of the boiler is anticipated to be at least as long as 

the capital cost recovery period, which is 15 years for LNB/OFA and 20 years for SNCR 

and SCR.

6.6 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE NOX CONTROLS 

A final impact analysis was conducted to assess the visibility improvement for existing emission rates 

when compared to the emission rates associated with LNB/OFA, LNB/OFA/SNCR and SCR systems. 

Section 4 of this report documented the existing visibility impairment attributable to SN-01. In order 

to assess the visibility improvement associated with LNB/OFA, SCR and SNCR systems, the NOX

emission rates associated with both LNB and SCR systems were modeled using CALPUFF. The 

controlled emission level associated with SCR systems is 0.067 lb/MMBtu for SN-01. The controlled 

emission level associated with the LNB/OFA system is 0.23 lb/MMBtu, and for LNB/OFA/SNCR is 

0.21 lb/MMBtu. These levels were multiplied by the maximum heat input to derive hourly the hourly 

emission rates used in the modeling. 

Tables 6-7 through 6-9 summarize the NOX emission rates that were modeled to reflect the LNB/OFA 

SCR and LNB/OFA/SNCR systems, respectively. The emission rates for the other pollutants shown 

in Tables 6-7 through 6-9 are the same as in the baseline modeling. 

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TABLE 6-7. SUMMARY OF EMISSION RATES MODELED TO REFLECT LNB/OFA FOR NOX

CONTROL

SO2

(lb/hr)

SO4

(lb/hr)

NOX

(lb/hr)

PMC

(lb/hr)

PMF

(lb/hr)

SOA

(lb/hr)

EC

(lb/hr)

4,728.4 3.1 1,454.5 65.1 50.1 15.1 1.9

TABLE 6-8. SUMMARY OF EMISSION RATES MODELED TO REFLECT SCR FOR NOX CONTROL

SO2

(lb/hr)

SO4

(lb/hr)

NOX

(lb/hr)

PMC

(lb/hr)

PMF

(lb/hr)

SOA

(lb/hr)

EC

(lb/hr)

4,728.4 3.1 423.7 65.1 50.1 15.1 1.9

TABLE 6-9. SUMMARY OF EMISSION RATES MODELED TO REFLECT LNB/OFA + SNCR FOR NOX

CONTROL

SO2

(lb/hr)

SO4

(lb/hr)

NOX

(lb/hr)

PMC

(lb/hr)

PMF

(lb/hr)

SOA

(lb/hr)

EC

(lb/hr)

4,728.4 3.1 1,277.74 65.1 50.1 15.1 1.9

Table 6-10 provides a comparison of the existing visibility impairment and the visibility impairment 

associated with the addition of NOX controls on SN-01 in all affected Class I areas, including the 

maximum modeled visibility impact, 98th percentile modeled visibility impact, and the number of 

days with a modeled visibility impact greater than 0.5 Δdv. 

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TABLE 6-10. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH NOX CONTROL SYSTEM ON SN-01 (2001-2003)

Caney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness Mingo NWR Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Maximum Impact (Δdv) 98% Impact (Δdv)

# Days > 0.5 Δdv

Existing Emission 

Rate

1.318 0.963 48 2.426 0.965 63 2.103 0.657 47 1.488 0.631 20

LNB/OFA 1.232 0.849 39 2.130 0.939 56 1.938 0.633 43 1.361 0.617 17

Post Control 

Improvement

0.086 0.114 9 0.296 0.026 7 0.165 0.024 4 0.127 0.014 3

SCR 0.986 0.718 22 1.569 0.895 41 1.589 0.573 33 1.099 0.588 14

Improvement 

over LNB/OFA

0.246 0.131 17 0.561 0.044 15 0.349 0.060 10 0.262 0.029 3

LNB/OFA+ SNCR 1.201 0.849 36 2.022 0.932 54 1.878 0.623 42 1.316 0.612 17

Improvement 

over LNB/OFA

0.031 0.000 3 0.108 0.007 2 0.06 0.010 1 0.045 0.005 0

Note: The visibility improvement shown in the table has been calculated from baseline and controlled impacts that include more decimal places than what is shown in the 

table. Due to rounding of the baseline and controlled impacts shown in the table, the visibility improvement calculated from the baseline and controlled impacts shown in the 

table may be slightly different than the visibility improvement reflected in the table.

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The operation of an LNB/OFA system results in an estimated 0.01 to 0.11 Δdv improvement (2 to 12

percent) (98th percentile basis) of visibility impairment attributable to SN-01 at the modeled Class I 

areas. Further, the operation of SCR systems results in an estimated 0.02 to 0.13 Δdv incremental 

improvement over LNB/OFA alone, while LNB/OFA + SNCR results in an estimated 0 to 0.01 Δdv 

incremental improvement over LNB/OFA alone. 

6.7 PROPOSED BART FOR NOX 

If CSAPR is upheld and implemented in Arkansas, SWEPCO will rely on CSAPR to satisfy its 

regional haze obligations at SN-01. If CSAPR is vacated, SWEPCO should be entitled to rely on 

EPA’s prior determination that CAIR provides greater reductions than BART, and satisfy its 

obligations by continuing to comply with CAIR.

If a full evaluation of BART is required, the cost-effectiveness of the control options and the limited 

incremental improvement in visibility in the affected Class I areas do not justify the installation of 

SCR or SNCR. SWEPCO proposes a BART emission rate of 0.23 lb/MMBtu calculated as a 30-day

rolling average for each boiler operating day, achievable through use of LNB/OFA. The visibility 

improvement attributable to SN-01 through the use of LNB/OFA ranges from 2.2% to 11.8% across 

the affected Class I areas. This level of improvement is achievable at a cost effectiveness of 

approximately $2,600 per ton of NOX removed. Although LNB/OFA plus SNCR adds a slight 

visibility improvement over LNB/OFA alone, the small improvement does not justify the incremental 

cost of over $5,200 per ton of NOX removed. The incremental cost for SCR at SN-01 is nearly 

$4,800 per ton of NOX removed, and is an excessive cost to be considered BART. In addition, the 

adverse environmental impacts from the use of SCR, including an increased demand for electricity 

and the potential for ammonia slip, which could create haze, outweigh the limited, imperceptible 

improvements in visibility associated with its use at SN-01.

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7. PM10 BART EVALUATION

EPA’s Approval and Promulgation of Implementation Plans published March 12, 2012, determined 

that the currently installed ESP is BART for PM10 for SN-01. As such, no further PM10 analysis has 

been conducted. 

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APPENDIX A

SO2CONTROL COST CALCULATIONS

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APPENDIX B

NOX CONTROL COST CALCULATIONS

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APPENDIX C

CALMET PROTOCOL

The meteorological data used in the analyses presented in this report was originally developed in 

2007 and was first used in a BART determination for Oklahoma Gas & Electric. Because the 

development of a set of CALMET/CALPUFF meteorological data is so intensive, this same dataset 

has been used numerous times since 2007 for various other BART projects in EPA Region 6. The 

protocol that accompanied the original development has followed the dataset in each case and is 

doing so here again.

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