BART DETERMINATION REPORT

AMERICAN ELECTRIC POWER  COMANCHE POWER STATION UNITS 1 AND 2 

Prepared by: 

N.N. Dharmarajan  AEP 

Vern Choquette  Principal Consultant 

Eugene Chen, PE  Senior Consultant 

Jeremy Townley  Consultant 

TRINITY CONSULTANTS

120 E. Sheridan 

Suite 205 

Oklahoma City, OK 73104 

(405) 228-3292 

August 2008 

Project 083701.0057 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

i

TABLE OF CONTENTS

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

2. BACKGROUND...................................................................................................... 2-1

2.1 BART APPLICABILITY.......................................................................................... 2-1 

2.1.1 CALPUFF MODELING ANALYSES......................................................................2-3

2.2 BART DETERMINATION ....................................................................................... 2-3 

3. BART APPLICABILITY ANALYSIS ...................................................................... 3-1

3.1 BART-ELIGIBLE SOURCES ................................................................................... 3-1 

3.2 SOURCE EMISSIONS DATA .................................................................................... 3-1 

3.2.1 PM EMISSIONS ....................................................................................................3-2

3.2.2 STACK PARAMETERS...........................................................................................3-2

4. SO2 BART DETERMINATION.............................................................................. 4-1

4.1 IDENTIFICATION OF AVAILABLE RETROFIT SO2 CONTROL TECHNOLOGIES .......... 4-1 

5. PM BART DETERMINATION .............................................................................. 5-1

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

6. NOXBART DETERMINATION.............................................................................. 6-1

6.1 IDENTIFY ALL AVAILABLE RETROFIT TECHNOLOGIES.......................................... 6-1 

6.2 ELIMINATE TECHNICALLY INFEASIBLE OPTIONS .................................................. 6-1 

6.2.1 DRY LOW NOX BURNERS (DLNB).....................................................................6-2

6.3 EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES ................ 6-2 

6.4 EVALUATION OF IMPACTS FOR FEASIBLE NOX CONTROLS ................................... 6-2 

6.4.1 COSTS OF COMPLIANCE ......................................................................................6-3

6.4.2 ENERGY AND NON-AIR IMPACTS ........................................................................6-3

6.4.3 REMAINING USEFUL LIFE ...................................................................................6-4

6.5 EVALUATE VISIBILITY IMPACTS ........................................................................... 6-4 

6.6 PROPOSED BART FOR NOX.................................................................................... 6-4 

APPENDIX A – EMISSION ESTIMATES

APPENDIX B - ECONOMIC ANALYSES

APPENDIX C – CALPUFF MODELING PROTOCOL

APPENDIX D – MODELING INPUT/OUTPUT FILES
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

ii

LIST OF FIGURES

TABLE 3-1. CONSTRUCTION DATE SUMMARY ...................................................................................3-1

TABLE 3-2. PRE-BART EMISSIONS SUMMARY ..................................................................................3-1

TABLE 3-3. PM SPECIATION PROFILE.................................................................................................3-2

TABLE 3-4. SPECIATED PM EMISSIONS ..............................................................................................3-2

TABLE 3-5. POINT SOURCE STACK PARAMETERS ..............................................................................3-3

TABLE 4-1. BASELINE MAXIMUM 24-HOUR AVERAGE SO2 EMISSION RATES ..................................4-1

TABLE 4-2. AVAILABLE SO2 CONTROL TECHNOLOGIES ....................................................................4-1

TABLE 4-3. SO2 EMISSION ESTIMATES (NATURAL GAS)....................................................................4-2

TABLE 5-1. BASELINE MAXIMUM 24-HOUR AVERAGE PM EMISSION RATES...................................5-1

TABLE 5-2. AVAILABLE PM CONTROL TECHNOLOGIES.....................................................................5-1

TABLE 5-3. PM EMISSION ESTIMATES................................................................................................5-1

TABLE 6-1. BASELINE 24-HR AVERAGE NOX EMISSION RATES.........................................................6-1

TABLE 6-2. AVAILABLE NOX COMBUSTION CONTROL TECHNOLOGIES ............................................6-1

TABLE 6-3. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE NOX CONTROL TECHNOLOGIES6-2

TABLE 6-4. NOX CONTROL COSTS SUMMARY ...................................................................................6-3

TABLE 6-5. COMANCHE UNIT 1G1 AND 1G2 VISIBILITY IMPACTS (NOX).........................................6-4

 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

1-1

1. EXECUTIVE SUMMARY

American Electric Power/Public Service Company of Oklahoma (AEP/PSO) owns and operates the 

Comanche Power Station, located near Lawton, OK. The Comanche station is an electricity 

generating station that primarily consists of two natural-gas fired combustion turbines with duct 

burners and heat recovery steam generators (HRSGs). The Comanche Station is a Title V major 

source of emissions and currently operates under Permit No. 2003-261-TVR, issued April 21, 2006. 

Based upon the construction date of the sources at the Comanche station, AEP has determined that 

both units are eligible to be regulated under the Best Available Retrofit Technology (BART) 

provisions of the U.S. Environmental Protection Agency’s (EPA) Regional Haze Rule as established 

in Title 40, Code of Federal Regulations Part 51 (40 CFR 51). Both turbine/duct burner units 

comprise the BART-eligible source at the Comanche Station. 

In addition, AEP has determined that the Comanche Station contributes greater than 0.5 deciviews 

(∆dv) to visibility impairment in a federally protected Class I area when compared to a natural 

background. As a result, it does not qualify for exemption and is subject to a BART determination. 

Per the guidelines in 40 CFR Part 511

, a BART determination for SO2, NOX, and PM was performed 

using the five-step analysis 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 

Based on the five-step analysis, AEP proposes the following as BART: 

• PM – AEP proposes the use of natural gas at the Comanche Station as BART for PM. 

Natural gas use is able to ensure PM emissions lower than add-on PM controls. 

• SO2 – AEP also proposes the use of natural gas at the Comanche Station as BART for SO2. 

As with PM emissions, natural gas use is able to ensure SO2 emissions lower than add-on SO2

controls. 

• NOX – AEP proposes emission rates of 0.15 lb/MMBtu as BART for NOx. This will be 

achieved by retrofitting the turbines with Dry Low NOx burners (DLNB). 

 

 1

 40 CFR 51, Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) 

Determinations 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

2-1

2. BACKGROUND

On July 1, 1999, the U.S. Environmental Protection Agency (EPA) published the final Regional Haze 

Rule (RHR). The objective of the RHR is to improve visibility in 156 specific areas across the United 

States, known as Class I areas. The Clean Air Act 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. 

On July 6, 2005, the EPA published amendments to its 1999 RHR, often called the BART rule, which 

included guidance for making source-specific Best Available Retrofit Technology (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) Were “in existence” between August 7, 1962 and August 7, 1977, and 

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

A source that meets these criteria is considered eligible for BART and must then determine if BART 

applies. 

2.1 BART APPLICABILITY

Per the U.S. EPA’s BART Modeling Guidance, “an individual source will be considered to ‘cause 

visibility impairment’ if the emissions results in a change (delta ∆) in deciviews (dv)2

 that is greater 

than or equal to 1.0 deciview on the visibility in a Class I area...if the emissions from a source results 

in a change in visibility that is greater than or equal to 0.5 dv in a Class I area the source will be 

considered to ‘contribute to visibility impairment.’” To determine whether a BART-eligible source 

causes or contributes to visibility impairment, the U.S. EPA guidance requires the use of an air 

quality model, specifically recommending the CALPUFF modeling system, to quantify the impacts 

attributable to a single BART-eligible source. Because contribution to visibility impairment is 

sufficient cause to require a BART determination, 0.5 dv is the critical threshold for assessment of 

BART applicability. 

Regional haze is quantified using the light extinction coefficient (bext), which is expressed in terms of 

the haze index (HI) expressed in dv. The HI is calculated as shown in the following equation. 







 





 = 10

10 ln bext HI

The impact of a BART-eligible source is determined by comparing the HI attributable to a source to 

estimated natural background conditions. That is, a single-source visibility impact is measured as the 

 2

 The deciview (dv) is a metric used to represent normalized light extinction attributable to visibility-affecting 

pollutants. 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

2-2

change in light extinction versus background, and is referred to as ∆dv. The background extinction 

coefficient is affected by various chemical species and the Rayleigh scattering phenomenon and can 

be calculated as shown in the following equation. 

( ) ext background SO NO OC Soil Coarse EC Ray b = b + b + b + b + b + b + b −

4 3

1

, Mm

where: 

[ ] ( ) ( )

[ ] ( )

[ ]

[ ]

[ ]

[ ]

( )

( )

[ ] 3

1

4 3

4 2 4

Concentration in μg m

Relative Humidity Function

Rayleigh Scattering 10 Mm by default

10 EC

0.6 Coarse Mass

1Soil

4 OC

3 NH NO

3 NH SO

3

4

=

=

=

=

=

=

=

=

=

−

f RH

b

b

b

b

b

b f RH

b f RH

Ray

EC

Coarse

Soil

OC

NO

SO [( ) ]

[ ]

[ ]

[ ]

[ ]

[ ]

Rayleigh Scattering isscattering due to air molecules

EC denotes the concentration of elemental carbon

Coarse Mass denotes the concentration of coarse dusts

Soil denotes the concentration of fine soils

OC denotes the concentration of organic carbon

NH NO denotes the ammonium nitrate concentration

NH SO denotes the ammonium sulfate concentration

4 3

4 2 4

Values for the parameters listed above specific to the natural background conditions at each Class I 

area are provided on an annual-average basis in the U.S. EPA’s Guidance for Estimating Natural 

Visibility Conditions under the Regional Haze Rule.

3

Particulate species that affect visibility are emitted from anthropogenic (human-caused) sources and 

include coarse particulate matter (PMC), fine particulate matter (PMF), and elemental carbon (EC) as 

well as precursors to secondary organic aerosols (SOA) and fine particulate matter such as SO2 and 

NOX. The extinction coefficient due to emissions of visibility-affecting pollutants from a single 

BART-eligible source is calculated according to the following equation. 

( ) bext source = bSO + bNO + bSOA + bPMF + bPMC + bEC

−

4 3

1

, Mm

where: 

 3

 U.S. EPA, Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule, Table 2-1, 

Attachment A, September 2003, EPA-454/B-03-005. 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

2-3

[( ) ] ( )

[ ] ( )

[ ]

[ ]

[ ]

[ ]

( )

[ ] 3

4 3 3

4 2 4 4

Concentration in μg m

Relative Humidity Function

10 EC

0.6 PMC

1 PMF

4 SOA

3 NH NO

3 NH SO

=

=

=

=

=

=

=

=

f RH

b

b

b

b

b f RH

b f RH

EC

PMC

PMF

SOA

NO

SO [( ) ]

[ ]

[ ]

[ ]

[ ]

[ ] EC denotes the concentration of elemental carbon

PMC denotes the concentration of coarse PM

PMF denotes the concentration of fine PM

SOA denotes the concentration of secondary organic aerosols

NH NO denotes the ammonium nitrate concentration

NH SO denotes the ammonium sulfate concentration

4 3

4 2 4

2.1.1 CALPUFF MODELING ANALYSES

As stated above, the BART Guidelines recommend using the CALPUFF modeling system 

to compute the 24-hour average visibility impairment attributable to a BART-eligible 

source to assess whether the 0.5 ∆dv contribution threshold is exceeded, and if so, the 

frequency, duration, and magnitude of any exceedance events. As described further in the 

modeling protocol included in Appendix A, CALPUFF is a refined air quality modeling 

system that is capable of simulating the dispersion, chemical transformation, and longrange transport of multiple visibility-affecting pollutant emissions and is therefore preferred 

for BART applicability and determination analyses. 

2.2 BART DETERMINATION

BART-eligible sources that are found to cause or contribute to visibility impairment at a Class I area 

are required to make a BART determination. The BART Guidelines define BART as follows: 

BART means 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 costs 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. The BART analysis 

identifies the best system of continuous emission reduction taking into account: 

(1) The available retrofit control options, 

(2) Any pollution control equipment in use at the source (which affects the availability 

of options and their impacts), 

(3) The costs of compliance with control options, 

(4) The remaining useful life of the facility, 

(5) The energy and non-air quality environmental impacts of control options[, and]

(6) The visibility impacts analysis. 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

2-4

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 

As summarized in Section 3, AEP conducted a BART applicability analysis for the three units at the 

Comanche Station and determined that the units are subject to BART. The BART determinations for 

each of the three visibility affecting pollutants (SO2, NOx, and PM) can be found in Sections 4 

through 6. 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

3-1

3. BART APPLICABILITY ANALYSIS

3.1 BART-ELIGIBLE SOURCES

In order to determine what specific units constitute the “BART-eligible” source, the construction 

dates of the each of the plant’s units must be examined. A summary of all units at the Comanche 

Station is provided below. As seen from this table, both turbine/duct burner units were “in existence” 

within the 15-year BART window (August 7, 1962-August 7, 1977). 

TABLE 3-1. CONSTRUCTION DATE SUMMARY

Unit 

No. 

Heat Duty 

(MMBtu/hr) 

Manufacturer/Model Construction Date 

1G1 1,250 Westinghouse/W-501B May 1971 

1G2 1,250 Westinghouse/W-501B May 1971 

DB1 200 Westinghouse Steam Generator Burner May 1971 

DB2 200 Westinghouse Steam Generator Burner May 1971 

3.2 SOURCE EMISSIONS DATA

In developing baseline emissions, Trinity utilized a combination of operating records and continuous 

emission monitoring (CEM) data provided by AEP over a period extending from 2001-05. Modeled 

emissions are based on the highest hourly emission rate (on 24-hour calendar day average) that 

occurred from 2001 to 2005. A summary of these emissions is presented in Table 3-2 below. A more 

detailed analysis of historical emissions is included in Appendix A. 

TABLE 3-2. PRE-BART EMISSIONS SUMMARY

Unit No. NOx PM SO2 H2SO4

 lbs/hr lbs/hr lbs/hr lbs/hr 

1G1 870.00 8.25 0.75 0.11 

1G2 766.30 8.25 0.75 0.11 

Both turbines operated on natural gas during the 2001-05 period. In addition, the duct burners have 

not operated for several years, and not over the 2001-05 period. As a result, separate listing of preBART baseline emissions is not included. As discussed in the cover letter accompanying this report, 

AEP did not include the duct burners in this analysis. 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

3-2

3.2.1 PM EMISSIONS

PM emissions are not directly entered into the model but are instead speciated into 

constituent components. The PM emissions from the boilers can be speciated according to 

the Federal Land Managers’ guidance to potentially include the following: 

S Coarse particulate matter (PMC, considered PM2.5-10) 

S Fine particulate matter (PMF, considered PM<2.5) 

S Sulfates (SO4) 

S Secondary organic aerosols (SOA) 

S Elemental carbon (EC) 

Based upon FLM guidance, PM emissions from natural gas combustion consists of 

primarily coarse (25%) and fine (75%).4

 A summary of speciated PM emissions is 

presented in Table 3-3 below. 

TABLE 3-3. PM SPECIATION PROFILE

Particulate Matter Species Fraction 

PM Coarse (Soil) 25% 

Elemental Carbon (EC) 0% 

PM Fine 75% 

Secondary Organic Aerosols 

(organic carbon) 

0% 

Total 100% 

A summary of speciated PM emissions from the Comanche units is presented below. 

TABLE 3-4. SPECIATED PM EMISSIONS

Unit No. PM (coarse)4

 PM (fine)4 EC4 SOA4

 lbs/hr lbs/hr lbs/hr lbs/hr 

1G1 2.06 6.19 0 0 

1G2 2.06 6.19 0 0 

3.2.2 STACK PARAMETERS

Table 3-5 provides a summary of source exhaust parameters. 

 4

 http://www2.nature.nps.gov/air/Permits/ect/ectGasFiredCT.cfm 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

3-3

TABLE 3-5. POINT SOURCE STACK PARAMETERS

Emission 

unit 

Latitude 

(decimal 

degrees) 

Longitude

(decimal 

degrees) 

Exit 

Velocity 

(ft/s) 

Stack 

Height 

(feet) 

Stack 

Diameter 

(feet) 

Exit 

Temperature 

(Fahrenheit) 

1G1 34.5434 98.3243 147 53 10.2 355 

1G2 34.5432 98.3243 147 53 10.2 355 

The base elevation of each of the units is 338 meters (1,108 feet) above MSL based upon 

visual inspection of USGS topographic maps. 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

4-1

4. SO2 BART DETERMINATION

A summary of pre-BART SO2 emissions over the 2001-05 time period as described in Section 3 is 

included below. 

TABLE 4-1. BASELINE MAXIMUM 24-HOUR AVERAGE SO2 EMISSION RATES

Emission 

Unit 

SO2 Emission 

Rate 

(lb/hr) 

1G1 0.75 

1G2 0.75 

4.1 IDENTIFICATION OF AVAILABLE RETROFIT SO2 CONTROL 

TECHNOLOGIES

The first step of a BART determination is the identification of all available retrofit SO2 control 

technologies. A list of control technologies was obtained by reviewing the U.S. EPA’s Clean Air 

Technology Center, control equipment vendor information, publicly-available air permits, 

applications, and BART analyses, and technical literature published by the U.S. EPA and Regional 

Planning Organizations (RPOs). 

TABLE 4-2. AVAILABLE SO2 CONTROL TECHNOLOGIES

SO2 Control Technologies 

Dry Sorbent Injection 

Spray Dryer Absorber (SDA) i.e., Semi-Dry Scrubber 

Wet Scrubber 

Circulating Dry Scrubber (CDS) 

All of the technologies listed in Table 4-2 involve removing the SO2 in the exhaust gas, which is 

known as flue gas desulfurization (FGD). AEP proposes to restrict fuel usage at the Comanche 

Station to natural gas only. Commercial-grade natural gas is intrinsically low in sulfur content, and 

results in low sulfur emissions. The facility’s existing Title V operating permit (No. 2003-261-TVR) 

provides an estimate of SO2 emissions from the combustion of natural gas, as summarized below. 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

4-2

TABLE 4-3. SO2 EMISSION ESTIMATES (NATURAL GAS) 

Emission SO2

Unit lb/hr TPY 

1G1 4.25 18.62 

1G2 4.25 18.62 

SO2 emissions from the two Comanche units are sufficiently low from natural gas usage that no addon control technology could be considered economically feasible. As a result, AEP determines that 

natural gas usage is SO2 BART for the Comanche units. 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

5-1

5. PM BART DETERMINATION

A summary of pre-BART PM emissions over the 2001-05 time period as described in Section 3 is 

included below. 

TABLE 5-1. BASELINE MAXIMUM 24-HOUR AVERAGE PM EMISSION RATES

Emission 

Unit 

PM Emission 

Rate 

(lb/hr) 

1G1 8.25 

1G2 8.25 

5.1 IDENTIFICATION OF AVAILABLE RETROFIT PM CONTROL 

TECHNOLOGIES

The first step of a BART determination is the identification of all available retrofit PM control 

technologies. A list of control technologies was obtained by reviewing the U.S. EPA’s Clean Air 

Technology Center, control equipment vendor information, publicly-available air permits, 

applications, and BART analyses, and technical literature published by the U.S. EPA and Regional 

Planning Organizations (RPOs). 

TABLE 5-2. AVAILABLE PM CONTROL TECHNOLOGIES

PM Control Technologies 

Electrostatic Precipitator (wet or dry) 

Baghouse (Fabric Filter) 

AEP proposes to restrict fuel usage at the Comanche Station to natural gas only. As with SO2, the use 

of commercial-grade natural inherently results in low particulate emissions. The facility’s existing 

Title V operating permit (No. 2003-261-TVR) provides an estimate of PM emissions from the 

combustion of natural gas, as summarized below. 

TABLE 5-3. PM EMISSION ESTIMATES 

Emission PM 

Unit lb/hr TPY 

1G1 8.25 36.14 

1G2 8.25 36.14 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

5-2

These emission estimates for these two Comanche units from natural gas usage are sufficiently low 

that no add-on control technology could be considered economically feasible. As a result, AEP 

determines that natural gas usage is BART for PM for the Comanche units. 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

6-1

6. NOXBART DETERMINATION 

The highest 24-hr average pre-BART NOX emissions over the 2001-05 time period are summarized in 

Table 6-1. 

TABLE 6-1. BASELINE 24-HR AVERAGE NOX EMISSION RATES

Unit ID NOX Hourly 

Emission Rate 

NOX Emission 

Rate 

 (lb/hr) (lb/MMBtu) 

1G1 870.0 0.696 

1G2 766.3 0.613 

6.1 IDENTIFY ALL AVAILABLE RETROFIT TECHNOLOGIES

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

technologies. For gas-fired applications, the Fedreal Rule at 40 CFR Part 51, Regional Haze 

Regulations and Guidelines for BART Determinations: Final Rule (70 Fed. Reg. July 6, 2005) 

indicates use of “current combustion technology” as BART. A list of “current combustion control” 

technologies, as applicable to the Gas- Tturbines, was obtained by reviewing the U.S. EPA’s Clean 

Air Technology Center, control equipment vendor information, publicly-available air permits, 

applications, and BART analyses, and technical literature published by the U.S. EPA and the RPOs. 

TABLE 6-2. AVAILABLE NOX COMBUSTION CONTROL TECHNOLOGIES 

NOX Control Technologies 

Dry Low NOx Burners (LNB) 

As listed in Table 6-2, NOX emissions controls for the Comanche Power Station gas turbines based on 

“current combustion control technology” is limited to Dry Low NOx Burners. Site specific 

considerations and marginal performance results of approaches such as water or steam injection did 

not merit their consideration as control possibilities. 

6.2 ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

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

were identified in Step 1. In the case of the Comanche Power Station Units 1 and 2, the site specific 

applicable NOx control was limited to Dry Low NOx Burners and water or steam injection were 

considered inappropriate. 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

6-2

6.2.1 DRY LOW NOX BURNERS (DLNB) 

LNB technology utilizes advanced burner design to reduce NOX formation through the 

restriction of oxygen, lowering of flame temperature, and/or reduced residence time. 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 either 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. When utilized in new turbine designs, reductions of up to 60 percent may 

result.5

 A similar level of effectiveness is expected with retrofit installations. This 

technology is considered a technically feasible option. 

. 

6.3 EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

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

effectiveness. 

TABLE 6-3. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE NOX CONTROL 

TECHNOLOGIES

Control Technology 

Estimated Control 

Efficiency 

(%) 

Dry Low NOx Burners ~30-60 

Installation of dry low NOx burners is expected to allow the turbines to attain an emission level of 

0.15 lb NOx/MMBtu.. 

6.4 EVALUATION OF IMPACTS FOR FEASIBLE NOX CONTROLS 

Step four for the BART analysis procedure is the impact analysis. The BART determination 

guidelines list 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 

Evaluation of a fifth factor, visibility impacts, is addressed separately in Section 6.5. 

 5

 "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 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

6-3

6.4.1 COSTS OF COMPLIANCE

Per the BART Guidelines, the costs of compliance analysis for each control option consists of 

comparisons of the average cost effectiveness and the incremental cost effectiveness, which 

are defined in Section IV.D.4 as follows: 

Average cost effectiveness means the total annualized costs of control divided by the 

annual emissions reduction (the difference between baseline annual emissions and 

the estimate of emissions after controls), using the following formula: 

Average cost effectiveness (dollars per ton removed) = Control option annualized 

cost ÷ (Baseline annual emissions – Annual emissions with Control option) 

...the incremental cost effectiveness calculation compares the costs of performance 

level of a control option to those of the next most stringent option, as shown in the 

following formula (with respect to cost per emissions reduction): 

Incremental Cost Effectiveness (dollars per incremental ton removed) = (Total 

annualized costs of control option) – (Total annualized costs of next control option) ÷ 

(Control option annual emissions) – (Next control option annual emissions) 

Capital costs associated with implementing the evaluated control systems were provided to 

AEP by an after-market vendor. A detailed summary of those costs is included in Appendix 

B, while estimates of annual pollutant reductions for the evaluated control technologies are 

included in Appendix A. The average cost effectiveness of this control options is 

summarized in Table 6-4. Please note that since no other options were examined, 

incremental cost effectiveness is not relevant (and not included). 

TABLE 6-4. NOX CONTROL COSTS SUMMARY

 Average Cost 

Effectiveness 

Incremental Cost 

Effectiveness 

Emission Unit Control Strategy $/ton $/ton

1G1 and 1G2 Dry low NOx 

Burners 

2,600 -- 

6.4.2 ENERGY AND NON-AIR IMPACTS

Energy and non-air impacts from DLNB retrofit are minimal. AEP expects that the retrofit 

will have a limited derating impact on the turbines, resulting in a total output decrease of 1-

2%. 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

6-4

6.4.3 REMAINING USEFUL LIFE

The remaining useful life of the Comanche units do not impact the annualized capital costs 

of potential controls because the useful lives of the units are anticipated to be at least as 

long as the capital cost recovery period, which is 20 years. 

6.5 EVALUATE VISIBILITY IMPACTS

In order to determine the change in visibility impact from the various NOx control options 

considered, calculated emissions were modeled in CALPUFF. As discussed in the modeling protocol 

included in Appendix A, visibility impacts were evaluated each of the four nearby Class I areas. 

Pre-BART baseline emissions for each unit are modeled and summarized below. Subsequent control 

scenarios incorporated calculated NOx emissions from post-control scenarios, and incorporated all 

other pollutants at baseline emissions. Per BART determination procedures, visibility impacts are 

presented below on a unit-by-unit basis. 

TABLE 6-5. COMANCHE UNIT 1G1 AND 1G2 VISIBILITY IMPACTS (NOX) 

Class I area 98th Percentile Impact 

 Pre-BART DLNB Visibility 

Improvement 

∆dv ∆dv 

Caney Creek 0.097 0.022 77% 

Hercules-Glades 0.068 0.015 78% 

Upper Buffalo 0.078 0.017 78% 

Wichita 

Mountains 

1.776 0.438 75% 

 

6.6 PROPOSED BART FOR NOX 

AEP has determined that the NOX BART for each of the Comanche units is DLNB. Based upon the 

modeled visibility improvement and calculated average cost effectiveness, this control option cannot 

be considered either technically or economically infeasible. Based upon DLNB control effectiveness 

estimates, AEP proposes a BART NOx emission rate of 0.15 lb/MMBtu. 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

APPENDIX A – EMISSION ESTIMATES
Unit 1G1

PM (f

lb/mmBtu lb/hr lb/mmBtu lb/hr lb/mmBtu lb/hr lb/mmBtu lb/hr 

Case 1 Baseline Case -- 0.696 870.0 0.0006 0.75 -- 0.11 0.0066 8.25 Case 2 DLNB 78% 0.150 187.5 0.0006 0.75 -- 0.11 0.0066 8.25 

Unit 1G2

PM (f

lb/mmBtu lb/hr lb/mmBtu lb/hr lb/mmBtu lb/hr lb/mmBtu lb/hr 

Case 1 Baseline Case -- 0.613 766.3 0.0006 0.75 -- 0.11 0.0066 8.25 Case 2 DLNB 76% 0.150 187.5 0.0006 0.75 -- 0.11 0.0066 8.25 

1 H2SO4 emissions based upon the following assumptions:

SO2 Conversion to SO3 = 10%

SO3 Conversion to H2SO4 = 100%

MW H2SO4 = 98 lb/lbmol

 MW SO2 = 64 lb/lbmol

Sample Calculation:

0.75 lb SO2 lbmol 0.1 lbmol SO3 1 lbmol H2SO4 98 lb H2SO4 = 0.11 lb SO4

hr 64 lb SO2 lbmol SO2 lbmol SO3 lbmol hr

2 Baseline emission data for PM is not available. PM Emission Factor obtained from AP-42 (4/2000), Table 3.1-2a, Stationary Gas Turbines

Please note that for natural gas usage, PM10 emissions can be considered equivalent to total PM.

PM10 = 0.0066 lb/MMBtu

3 Condensible/filterable PM speciation were based on the following profiles: 

 For Natural Gas fired combustion turbines. http://www2.nature.nps.gov/air/Permits/ect/ectGasFiredCT.cfm

Filterable 25.00%

Condensible 75.00%

4 NOx control estimate for DLNB provided to AEP by Siemens Westinghouse. See emails dated 8/8/2008 and 8/13/2008 [Controlled emission rates for NE2-SW3_Comanche.xls]

PM (total)

NOx SO2

Comanche Power Station

SO4 (from SO2)1

SO4 (from SO2)

Percent 

Reduction

Percent 

Reduction

24-hour Average Emission Estimates

PM (total)2

NOx SO2

American Electric PowerComanche Power Station

Emission Estimates (lbhr)

Printed on 8/27/2008

Page 1 of 2
Unit 1G1

NOx

% reduction lb/mmBtu1 tpy

Case 1 Baseline Case -- 0.480 2,628Case 2 DLNB 69% 0.150 821

Unit 1G2

NOx

% reduction lb/mmBtu1 tpy

Case 1 Baseline Case -- 0.460 2,519Case 2 DLNB 67% 0.150 821

1 Baseline emission factor based upon annual average. Provided by AEP via email, 8/20/2008

1G11G2

12501250

Comanche Power Station

Annual Emission Estimates

Unit ID

Maximum Heat Duty

(MMBtu/hr)

American Electric PowerComanche Power Station

Emission estimates (Annual)

Printed on 8/27/2008

Page 2 of 2
Comanche Station

CALPUFF Visibility Results

Peak Impact 98th Percentile

Pollutant Class I Area

Control Technology (∆dv)

% Reduction 

from previous

% Reduction 

from Baseline (∆dv)

% Reduction 

from previous

NOx Caney Creek Baseline 0.720 -- -- 0.097 -- 

DLNB 0.167 77% 77% 0.022 77% 

Herc-Glades Baseline 0.224 -- -- 0.068 -- 

DLNB 0.051 77% 77% 0.015 78% 

Upper Buffalo Baseline 0.275 -- -- 0.078 -- 

DLNB 0.062 77% 77% 0.017 78% 

Wichita Mts Baseline 5.585 -- -- 1.776 -- 

DLNB 1.608 71% 71% 0.438 75% 

PM10 Caney Creek Baseline 0.001 -- -- -- -- 

Herc-Glades Baseline -- -- -- -- -- Upper Buffalo Baseline 0.001 -- -- -- -- Wichita Mts Baseline 0.054 -- -- 0.023 -- 

SO2 Caney Creek Baseline 0.001 -- -- -- -- 

Herc-Glades Baseline -- -- -- -- -- Upper Buffalo Baseline -- -- -- -- -- Wichita Mts Baseline 0.010 -- -- 0.004 -- 
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

APPENDIX B - ECONOMIC ANALYSES
Printed: 8/29/2008

Economic Analysis for Dry Low NOx Burners

Capital Cost Summary Capital Cost

TOTAL CAPITAL INVESTMENT a TCI = $34,660,000

Annual Cost Summary Annual Cost

DIRECT OPERATING COSTS

Low-NOx burners are not expected to incur any additional significant direct operating costs

TOTAL DIRECT COSTS (DC) DC = $0

INDIRECT OPERATING COSTS

Administrative Charges (2% of TCI) b $693,200

Insurance (1% of TCI) b $346,600

Property Taxes (1% of TCI) b $346,600

Capital Recovery (CRF x TCI)

20 years @ 8.00% interest CRF = 0.1019 $3,530,198

TOTAL INDIRECT COSTS (IC) IC = $4,916,598

TOTAL ANNUALIZED COST (TAC = DC + IC) TAC= $4,916,598

Cost Effectiveness Summary

Annual Control Cost: $4,916,598

NOx to be Removed (tpy): c 1,891

CONTROL COST EFFECTIVENESS ($/ton): $2,600

a Cost data provided by AEP (8/19/2008). Cost listed above is the total for both Comanche turbines

b Direct and indirect cost factors taken from OAQPS Control Cost Manual, Sixth Edition, January 2002.

c NOx total includes reductions from both turbines: 

Unit 1G1 Unit 1G2

DLNB NOx Removal Rate = 69% 67%

Annual Capacity Factor = 0.53 0.55 Provided by AEP via email, 8/20/2008

Baseline (pre-BART) emission factor = 0.48 0.46 Based upon an annual average

Maximum Firing Rate = 1250 1250 MMBtu/hr, as listed in Permit No. 96-288-TV.

Sample Calculation (Unit 1G1):

0.48 lb 1250 MMBtu 8760 hrs ton 0.53 capacity factor 0.69 NOx Removal Rate = 957.58 tons NOx

MMBtu hr yr 2000 lb year

American Electric Power

Comanche Power Station Cost Analysis (DLNB)

Trinity Consultants

083701.0057
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

APPENDIX C – CALPUFF MODELING PROTOCOL
AEP Trinity Consultants 

Comanche Power Station Units 1 and 2 083701.0057 

APPENDIX D – MODELING INPUT/OUTPUT FILES

Control Scenario Description Model Run Number 

 NOx SO2

Case 1 Baseline Case Run 1 Run 1 

Case 2 DLNB Run 2 --