Oklahoma Department of Environmental Quality

Air Quality Division

BART Application Analysis January 19, 2010

COMPANY: AEP- Public Service Company of Oklahoma

FACILITY: Comanche Power Station

FACILITY LOCATION: Comanche County, Oklahoma

TYPE OF OPERATION: (2) 94 MW Gas Turbine Electric Generating 

Units

REVIEWER: Phillip Fielder, Senior Engineering Manager

Lee Warden, Engineering Manager

I. PURPOSE OF APPLICATION

On July 6, 2005, the U.S. Environmental Protection Agency (EPA) published the final “Regional 

Haze Regulations and Guidelines for Best Available Retrofit Technology Determinations” (the 

“Regional Haze Rule” 70 FR 39104). The Regional Haze Rule requires certain States, including 

Oklahoma, to develop programs to assure reasonable progress toward meeting the national goal 

of preventing any future, and remedying any existing, impairment of visibility in Class I Areas. 

The Regional Haze Rule requires states to submit a plan to implement the regional haze 

requirements (the Regional Haze SIP). The Regional Haze SIP must provide for a Best 

Available Retrofit Technology (BART) analysis of any existing stationary facility that might 

cause or contribute to impairment of visibility in a Class I Area.

II. BART ELIGIBILITY DETERMINATION

BART-eligible sources include those sources that: 

(1) have the potential to emit 250 tons or more of a visibility-impairing air pollutant;

(2) were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and

(3) whose operations fall within one or more of the specifically listed source categories in 

40 CFR 51.301 (including fossil-fuel fired steam electric plants of more than 250 

mmBtu/hr heat input and fossil-fuel boilers of more than 250 mmBtu/hr heat input).

Comanche Units 1 and 2 are fossil-fuel fired steam electric plants with heat inputs greater than 

250-mmBtu/hr. The units were in existence prior to August 7, 1977, but not in operation prior to 

August 7, 1962. Based on a review of existing emissions data, the units have the potential to 

emit more than 250 tons per year of NOX, a visibility impairing pollutant. Therefore, Comanche 

Units 1 and 2 meet the definition of a BART-eligible source.
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BART is required for any BART-eligible source that emits any air pollutant which may 

reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I Area. 

DEQ has determined that an individual source will be considered to “contribute to visibility 

impairment” if emissions from the source result in a change in visibility, measured as a change in 

deciviews (Δ-dv), that is greater than or equal to 0.5 dv in a Class I area. Visibility impact 

modeling conducted by AEP-PSO determined that the maximum predicted visibility impacts 

from Comanche Units 1 and 2 exceeded the 0.5 Δ-dv threshold at the Wichita Mountains Class I 

Area. Therefore, Comanche Units 1 and 2 were determined to be BART applicable sources, 

subject to the BART determination requirements.

III. DESCRIPTION OF BART SOURCES

Baseline emissions from Comanche Units 1 and 2 were developed based on a combination of 

CEM data and operating records. In accordance with EPA guidelines in 40 CFR 51 Appendix Y 

Part III, emission estimates used in the modeling analysis to determine visibility impairment 

impacts should reflect steady-state operating conditions during periods of high capacity 

utilization. Therefore, baseline emissions (lb/hr) represent the highest 24-hour block emissions 

reported during the baseline period. Baseline emission rates (lb/mmBtu) were calculated by 

dividing the maximum hourly mass emission rates for each turbine by the turbine’s full heat 

input at that rate. In addition, the duct burners have not operated for several years, and not over 

the baseline period. Emissions for the duct burners are not included in the analysis.

Table 1: Comanche Power Station- Operating Parameters for BART Evaluation

Parameter Comanche Unit 1 Comanche Unit 2

Plant Configuration Combustion Turbine 

with Integrated Heat 

Recovery Steam 

Genertor

Combustion Turbine 

with Integrated Heat 

Recovery Steam 

Genertor

Gross Output (nominal) 94 MW 94 MW

Maximum Input to 

Turbine

1,250 mmBtu/hr 1,250 mmBtu/hr

Primary Fuel Natural gas Natural gas

Existing NOX Controls None None

Existing PM10 Controls NA NA

Existing SO2 Controls NA NA

Baseline Emissions 

Pollutant Baseline Actual 

Emissions

Baseline Actual 

Emissions

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

NOX 870.0 0.696 766.3 0.613

SO2 0.75 -- 0.75 --

PM10 8.25 -- 8.25 --
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IV. BEST AVAILABLE RETROFIT TECHNOLOGY (BART)

Guidelines for making BART determinations are included in Appendix Y of 40 CFR Part 51 

(Guidelines for BART Determinations under the Regional Haze Rule). States are required to use 

the Appendix Y guidelines to make BART determinations for fossil-fuel-fired generating plants 

having a total generating capacity in excess of 750 MW. The BART determination process 

described in Appendix Y includes the following steps: 

Step 1. Identify All Available Retrofit Control Technologies.

Step 2. Eliminate Technically Infeasible Options.

Step 3. Evaluate Control Effectiveness of Remaining Control Technologies.

Step 4. Evaluate Impacts and Document the Results.

Step 5. Evaluate Visibility Impacts.

Because the units fire natural gas, emissions of sulfur dioxide (SO2) and particulate matter (PM)

are minimal. There are no SO2 or PM post-combustion control technologies with a practical 

application to natural gas-fired turbines. BART is good combustion practices. A full BART 

analysis was conducted for NOX. 

Table 2: Proposed BART Controls and Limits

Unit NOX BART Emission Limit BART Technology

Comanche Unit 1 0.15 lb/mmBtu (30-day average) Dry Low NOX Burners (DLNB)

Comanche Unit 2 0.15 lb/mmBtu (30-day average) Dry Low NOX Burners (DLNB)

A. NOX

IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Potentially available control options were identified based on a comprehensive review of 

available information. NOX control technologies with potential application to Comanche Units 1 

and 2 are listed in Table 3.

Table 3: List of Potential Control Options

Control Technology

Combustion Controls

Dry Low NOX Burners (DLNB)

Post Combustion Controls

Selective Catalytic Reduction (SCR)

In support of the Regional Haze Rule, EPA also prepared a cost-effectiveness analysis for retrofit 

control technologies on oil- and gas-fired units. EPA’s analysis concluded that, although a 

number of oil- and gas-fired units could make significant cost-effective reductions in NOX

emissions using currently available combustion control technologies, for a number of units the 

use of combustion controls did not appear to be cost effective. As a result, EPA determined that 

it would be inappropriate to establish a general presumption regarding likely BART limits for 

oil- and natural gas fired units.
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ELIMINATE TECHICALLY INFEASIBLE OPTIONS (NOX)

Combustion Controls:

Dry Low NOX burners (DLNB)

Low NOX burners (DLNB) limit 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 

temperature 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 

temperatures 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. A similar level 

of effectiveness is expected with retrofit installations. This technology is considered a technically 

feasible option. 

Post Combustion Controls:

Selective Catalytic Reduction

Selective Catalytic Reduction (SCR) involves injecting ammonia into turbine flue gas in the 

presence of a catalyst to reduce NOX to N2 and water. Anhydrous ammonia injection systems 

may be used, or ammonia may be generated on-site from a urea feedstock. The units at the 

Comanche Station employ combustion turbines with integrated Heat Recovery Steam Generators 

(HRSG) that are very unique in their designs. AEP-PSO contends that it is technically infeasible 

to retrofit post combustion SCR NOX control without rebuilding the generating units. Therefore 

SCR is not evaluated further.

EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (NOX)

Table 4: Technically Feasible NOX Control Technologies- Comanche Station

Control Technology

Comanche Unit 1 Comanche Unit 2

Approximate NOX

Emission Rate

(lb/mmBtu)

Approximate NOX

Emission Rate

(lb/mmBtu)

DLNB 0.15 0.15

Baseline 0.696 0.613

EVALUATE IMPACTS AND DOCUMENT RESULTS (NOX)

AEP evaluated the economic, environmental, and energy impacts associated with the proposed 

control option. In general, the cost estimating methodology followed guidance provided in the 

EPA Air Pollution Cost Control Manual. Capital costs associated with implementing the 

evaluated control system was provided to AEP-PSO by an after-market vendor. As LNB are not 

expected to incur any additional significant direct operating costs, total direct operating costs 

were assumed to be $0. Indirect operating costs are consistent with control manual guidance. 
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The capital recovery factor used to estimate the annual cost of control was based on an 8% 

interest rate and a control life of 20 years. Annual operating costs and annual emission 

reductions were calculated assuming a capacity factor of 53%.

Table 5: Economic Cost for Units 1 and 2

Cost Control Option: DLNB

Control Equipment Capital Cost ($) $34,660,000

Capital Recover Factor ($/Yr) $3,530,198

Annual O&M Costs ($/Yr) $1,386,400

Annual Cost of Control ($) $4,916,598

Table 6: Environmental Costs for Units 1 and 2

Unit Baseline DLNB

NOX Emission Rate (lb/mmBtu) Unit 1 0.48 0.15

Unit 2 0.46 0.15

Annual NOX Emission (TPY)1 Unit 1 1,393 435

Unit 2 1,385 452

Annual NOX Reduction (TPY) Unit 1 -- 958

Unit 2 -- 933

Annual Cost of Control Units 1 & 2 $4,916,598

Cost per Ton of Reduction -- $2,600

(1) Emissions for the BART analysis are based on maximum heat inputs of 1,250 mmBtu/hr. Annual emissions were 

calculated assuming a 53% capacity factor for unit 1 and a 55% capacity factor for unit 2.

B. VISIBILITY IMPROVEMENT DETERMINATION 

The fifth of five factors that must be considered for a BART determination analysis, as required 

by a 40 CFR part 51- Appendix Y, is the degree of Class I area visibility improvement that 

would result from the installation of the various options for control technology. This factor was 

evaluated for the Comanche Power Station by using an EPA-approved dispersion modeling 

system (CALPUFF) to predict the change in Class I area visibility. The Division had previously 

determined that the Comanche Power Station was subject to BART based on the results of initial 

screening modeling that was conducted using current (baseline) emissions from the facility. The 

screening modeling, as well as more refined modeling conducted by the applicant, is described in 

detail below.

Wichita Mountain Wildlife Refuge, Caney Creek, Upper Buffalo and Hercules Glade are the 

closest Class I areas to the Comanche Generating Station, as shown in Figure 1 below. 

Only those Class I areas most likely to be impacted by the Comanche Generating Station were 

modeled, as determined by source/Class I area locations, distances to each Class I area, and 

professional judgment considering meteorological and terrain factors. It can be reasonably 

assumed that areas at greater distances and in directions of less frequent plume transport will 

experience lower impacts than those predicted for the four modeled areas. 
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Figure 1: Plot of Facility location in relation to nearest Class I areas

REFINED MODELING:

Because of the results of the applicants screening modeling for the Comanche Generating 

Station, AEP-PSO was required to conduct a refined BART analysis that included CALPUFF 

visibility modeling for the facility. The modeling approach followed the requirements described 

in the Division’s BART modeling protocol, CENRAP BART Modeling Guidelines (Alpine 

Geophysics, December 2005) with refinements detailed the applicants CALMET modeling 

protocol, CALMET Data Processing Protocol (Trinity Consultants, August 2008)

CALPUFF System

Predicted visibility impacts from the Comanche Generating Station were determined with the 

EPA CALPUFF modeling system, which is the EPA-preferred modeling system for long-range 

transport. As described in the EPA Guideline on Air Quality Models (Appendix W of 40 CFR 

Part 51), long-range transport is defined as modeling with source-receptor distances greater than 

50 km. Because most modeled areas are located more than 50 km from the sources in question

and the Wichita Mountains are just under the threshold at 40 km, the CALPUFF system was 

appropriate to use.

The CALPUFF modeling system consists of a meteorological data pre-processor (CALMET), an 

air dispersion model (CALPUFF), and post-processor programs (POSTUTIL, CALSUM, 

CALPOST). The CALPUFF model was developed as a non-steady-state air quality modeling 

system for assessing the effects of time- and space-varying meteorological conditions on 

pollutant transport, transformation, and removal. 
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CALMET is a diagnostic wind model that develops hourly wind and temperature fields in a 

three-dimensional, gridded modeling domain. Meteorological inputs to CALMET can include 

surface and upper-air observations from multiple meteorological monitoring stations. 

Additionally, the CALMET model can utilize gridded analysis fields from various mesoscale 

models such as MM5 to better represent regional wind flows and complex terrain circulations. 

Associated two-dimensional fields such as mixing height, land use, and surface roughness are 

included in the input to the CALMET model. The CALMET model allows the user to “weight” 

various terrain influences parameters in the vertical and horizontal directions by defining the 

radius of influence for surface and upper-air stations. 

CALPUFF is a multi-layer, Lagrangian puff dispersion model. CALPUFF can be driven by the 

three-dimensional wind fields developed by the CALMET model (refined mode), or by data 

from a single surface and upper-air station in a format consistent with the meteorological files 

used to drive steady-state dispersion models. All far-field modeling assessments described here 

were completed using the CALPUFF model in a refined mode.

CALPOST is a post-processing program that can read the CALPUFF output files, and calculate 

the impacts to visibility. 

All of the refined CALPUFF modeling was conducted with the version of the CALPUFF system 

that was recognized as the EPA-approved release at the time of the application submittal. 

Version designations of the key programs are listed in the table below.

Table 7: Key Programs in CALPUFF System

Program Version Level

CALMET 5.53a 040716

CALPUFF 5.8 070623

CALPOST 5.51 030709

Meteorological Data Processing (CALMET)

As required by the Division’s modeling protocol, the CALMET model was used to construct the 

initial three-dimensional wind field using data from the MM5 model. Surface and upper-air data 

were also input to CALMET to adjust the initial wind field. 

The following table lists the key user-defined CALMET settings that were selected.

Table 8: CALMET Variables

Variable Description Value

PMAP Map projection LCC (Lambert Conformal Conic)

DGRIDKM Grid spacing (km) 4

NZ Number of layers 12

ZFACE Cell face heights (m) 0, 20, 40, 60, 80, 100, 150, 200, 

250, 500, 1000, 2000, 3500

RMIN2 Minimum distance for extrapolation -1

IPROG Use gridded prognostic model outputs 14 km (MM5 data)

RMAX1 Maximum radius of influence (surface layer, km) 20 km
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Variable Description Value

RMAX2 Maximum radius of influence (layers aloft, km) 50 km

TERRAD Radius of influence for terrain (km) 10 km

R1 Relative weighting of first guess wind field and 

observation (km)

10 km 

R2 Relative weighting aloft (km) 25 km

The locations of the upper air stations with respect to the modeling domain are shown in Figure 2.

Figure 2: Plot of surface station locations
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Figure 3: Plot of upper air station locations

Figure 4. Plot of precipitation observation stations
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CALPUFF Modeling Setup

To allow chemical transformations within CALPUFF using the recommended chemistry 

mechanism (MESOPUFF II), the model required input of background ozone and ammonia. 

CALPUFF can use either a single background value representative of an area or hourly ozone data from 

one or more ozone monitoring stations. Hourly ozone data files were used in the CALPUFF simulation. 

As provided by the Oklahoma DEQ, hourly ozone data from the Oklahoma City, Glenpool, and Lawton 

monitors over the 2001-2003 time frames were used. Background concentrations for ammonia were 

assumed to be temporally and spatially invariant and were set to 3 ppb.

Latitude and longitude coordinates for Class I area discrete receptors were taken from the 

National Park Service (NPS) Class I Receptors database and converted to the appropriate LCC 

coordinates.

CALPUFF Inputs- Baseline and Control Options

The first step in the refined modeling analysis was to perform visibility modeling for current 

(baseline) operations at the facility. Emissions of NOX for the baseline runs were established 

based on CEM data and the highest 24-hour emissions averages for years 2001 to 2005. All 

particulate emissions (PM) were based on emission rates of 0.0066 lb/mmBtu with 25% 

filterable (coarse PM) and 75% condensable treated as (fine PM) within CALPUFF and 

CALPOST. 

Baseline source release parameters and emissions are shown in the table below, followed by 

tables with data for the various control options. 

Table 9: Baseline Source Parameters

Parameter

Baseline

Unit 1 Unit 2

Heat Input (mmBtu/hr) 1,250 1,250

Base Elevation (m) 338 338

Stack Height (m) 16 16

Stack Diameter (m) 3.11 3.11

Stack Temperature (K) 453 455

Exit Velocity (m/s) 44.82 44.82

SO2 Emissions (TPY) 0.75 0.75

NOX Emissions1(lb/mmBtu) 0.696 0.613

NOX Emissions TPY 870 766.3

PM10 Emissions Coarse (TPY) 2.06 2.06

PM10 Emissions Fine (TPY) 6.19 6.19

1Baseline NOx emissions were based on the maximum 24-hr average emission rate (lb/hr) reported by each unit

during the baseline period 2003-2005. Baseline emissions data were provided by AEP-PSO. Baseline emission rates 

(lb/mmBtu) were calculated by dividing the maximum 24-hr lb/hr emission rate by the heat input to the turbine at 

that rate.

2

PM emissions are based on AP-42 emission factors for stationary gas turbines with filterable/condensable 

speciation based on NPS guidance. 
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Visibility Post-Processing (CALPOST) Setup

The changes in visibility were calculated using Method 6 with the CALPOST post-processor. 

Method 6 requires input of monthly relative humidity factors [f(RH)] for each Class I area that is 

being modeled. Monthly f(RH) factors that were used for this analysis are shown in the table 

below. 

Table 11: Relative Humidity Factors for CALPOST

Month

Wichita 

Mountains Caney Creek Upper Buffalo Hercules Glade

January 2.7 3.4 3.3 3.2

February 2.6 3.1 3.0 2.9

March 2.4 2.9 2.7 2.7

April 2.4 3.0 2.8 2.7

May 3.0 3.6 3.4 3.3

June 2.7 3.6 3.4 3.3

July 2.3 3.4 3.4 3.3

August 2.5 3.4 3.4 3.3

September 2.9 3.6 3.6 3.4

October 2.6 3.5 3.3 3.1

November 2.7 3.4 3.2 3.1

December 2.8 3.5 3.3 3.3

EPA’s default average annual aerosol concentrations for the U.S. that are included in Table 2-1 

of EPA’s Guidance for Estimating Natural Visibility Conditions Under the Regional Haze 

Program were to develop natural background estimates for each Class I area.

Visibility Post-Processing Results

Table 12: CALPUFF Visibility Modeling Results for Comanche Units 1 and 2

Class I Area

2001 2002 2003 3-Year Average

98th Percentile 

Value (Δdv)

98th Percentile Value 

(Δdv)

98th Percentile 

Value (Δdv)

98th Percentile 

Value (Δdv)

Baseline

Wichita Mountains 1.83 1.619 1.66 1.703

Caney Creek 0.103 0.097 0.08 0.093

Upper Buffalo 0.092 0.066 0.062 0.073

Hercules Glade 0.076 0.068 0.044 0.063

Scenario- Combustion Control- DLNB

Wichita Mountains 0.47 0.395 0.406 0.424

Caney Creek 0.024 0.022 0.018 0.021

Upper Buffalo 0.021 0.015 0.014 0.017

Hercules Glade 0.017 0.015 0.010 0.014
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C. BART DETERMINATION

After considering: (1) the costs of compliance, (2) the energy and non-air quality environmental 

impacts of compliance, (3) any pollutant equipment in use or in existence at the source, (4) the 

remaining useful life of the source, and (5) the degree of improvement in visibility (all five 

statutory factors) from each proposed control technology, the Division determined BART for the 

two units at the Comanche Generating Station.

New DLNB is determined to be BART for NOX control for Units 1 and 2 based, in part, on the 

following conclusions:

1. Installation of new DLNB was cost effective, with a capital cost of $34,660,000 for units 

1 and 2 and an average cost effectiveness of $2,600 per ton of NOX removed for each unit 

over a twenty year operational life.

2. Combustion control using the LNB does not require non-air quality environmental 

mitigation for the use of chemical reagents (i.e., ammonia or urea) and there is minimal 

energy impact.

3. After careful consideration of the five statutory factors, especially the costs of 

compliance and existing controls, NOX control levels on 30-day rolling averages of 0.15

lb/mmBtu for Unit 1 and 2 are justified. 

4. Annual NOX emission reductions from new LNB on Units 1, and 2 are a total of 1,891

tons.

The Division considers the installation and operation of the BART determined NOX controls, 

new DLNB, to meet the statutory requirements of BART.

V. CONSTRUCTION PERMIT

Prevention of Significant Deterioration (PSD) 

Comanche Power Station is a major source under OAC 252:100-8 Permits for Part 70 Sources. 

AEP-PSO should comply with the permitting requirements of Subchapter 8 as they apply to the 

installation of controls determined to meet BART.

The installation of controls determined to meet BART will not change NSPS or 

NESHAP/MACT applicability for the gas-fired units at the Comanche Station.

With installation of the BART controls, the duct burners will no longer be authorized to operate.

VI. OPERATING PERMIT

The Comanche Generating Station is a major source under OAC 252:100-8 and has submitted an 

application to modify their existing Title V permit to incorporate the requirement to install 

controls determined to meet BART. The Permit will contain the following specific conditions:
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1. The turbines in EUG 1 and 2 are subject to the Best Available Retrofit Technology (BART) 

requirements of 40 CFR Part 51, Subpart P, and shall comply with all applicable requirements 

including but not limited to the following: [40 CFR §§ 51.300-309 & Part 51, Appendix Y]

a. Affected facilities. The following sources are affected facilities and are subject to 

the requirements of this Specific Condition, the Protection of Visibility and 

Regional Haze Requirements of 40 CFR Part 51, and all applicable SIP 

requirements:

EU ID#

Point 

ID# EU Name

Heat Capacity

(MMBTUH)

Construction

Date

1G1 1G1 Westinghouse /W-501B 1250 1971

1G2 1G2 Westinghouse /W-501B 1250 1971

b. Each existing affected facility shall install and operate the SIP approved BART as 

expeditiously as practicable but in no later than five years after approval of the SIP 

incorporating the BART requirements.

c. The permittee shall apply for and obtain a construction permit prior to modification of the 

turbines. If the modifications will result in a significant emission increase and a 

significant net emission increase of a regulated NSR pollutant, the applicant shall apply 

for a PSD construction permit.

d. The affected facilities shall be equipped with Dry Low-NOX Burners, as determined in 

the submitted BART analysis, to reduce emissions of NOX to below the emission limits 

below:

e. The permittee shall maintain the combustion controls (Low-NOX burners) and establish 

procedures to ensure the controls are properly operated and maintained.

f. Within 60 days of achieving maximum power output from each affected facility, after 

modification or installation of BART, not to exceed 180 days from initial start-up of the 

affected facility the permittee shall comply with the emission limits established in the 

construction permit. The emission limits established in the construction permit shall be 

consistent with manufacturer’s data and an agreed upon safety factor. The emission 

limits established in the construction permit shall not exceed the following emission 

limits:

EU ID# Point ID# NOX Emission Limit Averaging Period

1G1 1G1 0.15 lb/MMBTU 30-day rolling

1G2 1G2 0.15 lb/MMBTU 30-day rolling

g. Within 60 days of achieving maximum power output from each turbine, after 

modification of the turbines, not to exceed 180 days from initial start-up, the permittee 

shall conduct performance testing and furnish a written report to Air Quality. Such report 

shall document compliance with BART emission limits for the affected facilities. 

[OAC 252:100-8-6(a)]
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1. A testing protocol describing how the testing will be performed shall be provided 

to the AQD for review and approval at least 30 days prior to the start of such 

testing.

2. The permittee shall also provide notice of the actual test date to AQD.