Oklahoma Department of Environmental Quality

Air Quality Division

BART Application Analysis January 19, 2010

COMPANY: AEP- Public Service Company of Oklahoma

FACILITY: Southwestern Power Station

FACILITY LOCATION: Caddo County, Oklahoma

TYPE OF OPERATION: (1) 332 MW Steam Electric Generating Unit

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).

Southwestern Unit 3 is a fossil-fuel fired boiler with heat inputs greater than 250-mmBtu/hr. The

unit was 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 unit has the potential to emit more than 250 

tons per year of NOX, a visibility impairing pollutant. Therefore, Southwestern Unit 3 meets the 

definition of a BART-eligible source.

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. 
AEP Southwestern Power Station BART Evaluation January 19, 2010

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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 Southwestern Unit 3 exceeded the 0.5 Δ-dv threshold at the Wichita Mountains Class I 

Area. Therefore, Southwestern Unit 3 was determined to be BART applicable sources, subject to 

the BART determination requirements.

III. DESCRIPTION OF BART SOURCES

Baseline emissions from Southwestern Unit 3 were developed based on an evaluation of actual 

emissions data submitted by the facility pursuant to the federal Acid Rain Program. 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 the boiler by the boiler’s heat input at that emission rate.

Table 1: Southwestern Power Station- Plant Operating Parameters for BART Evaluation

Parameter Southwestern Unit 3

Plant Configuration Natural Gas-Fired Boiler

Gross Output (nominal) 332 MW

Maximum Input to Boiler 3,290 mmBtu/hr

Primary Fuel Natural gas

Existing NOX Controls None

Existing PM10 Controls NA

Existing SO2 Controls NA

Baseline Emissions Pollutant Baseline Actual Emissions

lb/hr lb/mmBtu

NOX 3,705 1.126

PM10 24.5 0.007

SO2 1.97 0.0006

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.
AEP Southwestern Power Station BART Evaluation January 19, 2010

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Because the unit fires 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 boilers. 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

Southwestern Unit 3 0.45 lb/mmBtu (30-day average) LNB/OFA

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 Southwestern Unit 

3 are listed in Table 3.

Table 3: List of Potential Control Options

Control Technology

Combustion Controls

Burners Out of Service (BOOS)

Low NOX Burners and Overfire Air (LNB/OFA)

Induced Flue Gas Recirculation (FGR)

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.

ELIMINATE TECHICALLY INFEASIBLE OPTIONS (NOX)

Combustion Controls:

Burners Out of Service (BOOS)

This option involves shutting off selected burners, resulting in reduced fuel usage and therefore 

lower emissions. This option would essentially reduce the maximum firing rate of the boiler, and 

places a load limit on the unit. AEP-PSO estimates that NOX emissions can be reduced 20-25%. 

Implementation of this option will reduce the maximum firing rate of the unit, thereby creating 

an artificial load limit. Although this does not preclude this option from being physically 

implemented, the resulting load limits would effectively result in the shutdown of the units. As a 

result, this option is considered technically infeasible.
AEP Southwestern Power Station BART Evaluation January 19, 2010

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Induced Flue Gas Recirculation (IFGR)

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 heater 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 average NOX control efficiency range for FGR is 30 percent to 40 percent. This 

control option would also place load limits on the boiler and also call for plant component 

upgrades. As with the Burners Out Of Service, IFGR is considered technically infeasible as a 

standalone NOX control for Southwestern Power Station Unit 3.

Low NOX burners (LNB)/ Over Fire Air (OFA)

Low NOX burners (LNB) limit NOX formation by controlling both the stoichiometric and 

temperature profiles of the combustion flame in each burner flame envelope. Over Fire Air 

(OFA) allows for staged combustion. Staging combustion reduces NOX formation with a cooler 

flame in the initial stage and less oxygen in the second stage.

LNB/OFA emission control systems have been installed as retrofit control technologies on 

existing natural gas-fired boilers. Boilers of the size and age of the Southwestern Unit would be 

expected to achieve an average emission reduction in the range of 30% to 60% from baseline 

depending on the baseline emission rate and boiler operating conditions. Southwestern Unit 3

does not operate as base load units. The unit has historically operated as a “peaking unit” 

responding to increased demand for electricity. While technically feasible, LNB/OFA may not 

be as effective under all boiler operating conditions, especially during load changes and at low 

and high operating loads. 

Post Combustion Controls:

Selective Catalytic Reduction

Selective Catalytic Reduction (SCR) involves injecting ammonia into boiler 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. 

SCR has been installed as NOX control technology on existing gas-fired boilers. Based on 

emissions data available from the EPA Electronic Reporting website, large gas-fired boilers 

(with heat inputs above approximately 1,000 mmBtu/hr) have achieved actual long-term average 

NOX emission rates in the range of approximately 0.02 to 0.05 lb/mmBtu. Several design and 

operating variables will influence the performance of the SCR system, including the volume, age 

and surface area of the catalyst (e.g., catalyst layers), uncontrolled NOX emission rate, flue gas 

temperature, and catalyst activity.

Based on emission rates achieved in practice at existing gas-fired units, and taking into 

consideration long-term operation of an SCR control system (including catalyst plugging and 

deactivation) and the fact that the Southwestern boiler typically operates as a peaking unit, it is 

anticipated that SCR could achieve a controlled NOX emission rate of 0.05 lb/mmBtu (30-day 

rolling average) on Southwestern Unit 3.
AEP Southwestern Power Station BART Evaluation January 19, 2010

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EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (NOX)

Table 4: Technically Feasible NOX Control Technologies- Southwestern Station

Control Technology

Southwestern Unit 3

Approximate NOX Emission Rate (lb/mmBtu)

LNB/OFA + SCR 0.05

LNB/OFA 0.45

Baseline

1

1.126

1Baseline emissions for modeling are based on the maximum 24-hour emission rate over the baseline period. 

Baseline emissions for cost effectiveness calculations were based on the annual average emission rate of 0.57 

lb/mmBtu.

EVALUATE IMPACTS AND DOCUMENT RESULTS (NOX)

AEP-PSO evaluated the economic, environmental, and energy impacts associated with the 

proposed control options. In general, the cost estimating methodology followed guidance 

provided in the EPA Air Pollution Cost Control Manual. Major equipment costs were developed 

based on costs recently developed for similar projects, and include the equipment, material, 

labor, and all other direct costs needed to retrofit Southwestern Unit 3 with the control 

technologies. Fixed and variable O&M costs were developed for each control system. Fixed 

O&M costs include operating labor, maintenance labor, maintenance material, and 

administrative labor. Variable O&M costs include the cost of consumables, including reagent 

(e.g., ammonia) and auxiliary power requirements. Auxiliary power requirements reflect the 

additional power requirements associated with operation of the new control technology. The 

capital recovery factor used to estimate the annual cost of control was based on a 8% interest rate

and a control life of 20 years. Annual operating costs and annual emission reductions were 

calculated assuming a capacity factor of 26%.

Table 5: Economic Cost 

Cost Option 1: LNB/OFA Option 2: LNB/OFA +SCR

Control Equipment Capital Cost ($) $3,000,000 $68,968,400

Capital Recover Factor ($/Yr) $305,557 $7,024,584

Annual O&M Costs ($/Yr) $120,000 $3,682,650

Annual Cost of Control ($) $425,557 $10,707,234

Table 6: Environmental Costs per Boiler

Baseline LNB/OFA LNB/OFA +SCR

NOX Emission Rate (lb/mmBtu) 0.57 0.45 0.05

Annual NOX Emission (TPY) 2,136 1,686 187

Annual NOX Reduction (TPY) -- 450 1,949

Annual Cost of Control -- $425,557 $10,707,234

Cost per Ton of Reduction -- $946 $5,494

Incremental Cost per ton of Reduction -- -- $6,859
AEP Southwestern Power Station BART Evaluation January 19, 2010

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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 Southwestern 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 Southwestern 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 Southwestern Power Station, as shown in Figure 1 below. 

Only those Class I areas most likely to be impacted by the Southwestern Power 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. 

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 Southwestern Power Station, 

AEP-PSO was required to conduct a refined BART analysis that included CALPUFF visibility 
AEP Southwestern Power Station BART Evaluation January 19, 2010

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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 Southwestern Power 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 within 44 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. 

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.
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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

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.
AEP Southwestern Power Station BART Evaluation January 19, 2010

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Figure 2: Plot of surface station locations

Figure 3: Plot of upper air station locations
AEP Southwestern Power Station BART Evaluation January 19, 2010

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Figure 4. Plot of precipitation observation stations

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 maximum 24-hour emissions averages for years 2001 to 2005. 

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

tables with data for the various control options. 
AEP Southwestern Power Station BART Evaluation January 19, 2010

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Table 9: Baseline Source Parameters

Parameter

Southwestern Unit 3

Natural Gas-Fired

Heat Input (mmBtu/hr) 3,290

Base Elevation (m) 371

Stack Height (m) 43

Stack Diameter (m) 4.27

Stack Temperature (K) 408

Exit Velocity (m/s) 16.26

SO2 Emissions (lb/mmBtu) 0.0006

SO2 Emissions (TPY) 8.63

NOX Emissions1(lb/mmBtu) 1.26

NOX Emissions TPY 16227.9

PM10 Fine Emissions2(lb/mmBtu) 0.00175

PM10 Fine Emissions (TPY) 6.13

PM10 Coarse Emissions (lb/mmBtu) 0.00525

PM10 Coarse Emissions (TPY) 18.39

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

boiler at that emission rate.

2

PM emissions are based on AP-42 emission factors for natural gas combustion and NPS speciation factors for 

(filterable and condensable).

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
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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 Southwestern Unit 3

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 3.86 2.85 3.74 3.48

Scenario 2- Combustion Control- LNB/OFA 

Wichita Mountains 1.73 1.24 1.70 1.56

Modeling for SCR controls resulted in an approximately 88% reduction in visibility impairment 

from scenario two.

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 

unit at the Southwestern Power Station.

New LNB with OFA is determined to be BART for NOX control for Unit 3 based, in part, on the 

following conclusions:

1. Installation of new LNB with OFA was cost effective, with a capital cost of $3,000,000 

and an average cost effectiveness of $947 per ton of NOX removed over a twenty year 

operational life.

2. Combustion control using the LNB/OFA 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 NOX control levels on 30-day rolling averages of 0.45 lb/mmBtu for Unit 3

are justified. 

4. Annual actual NOX emission reductions from new LNB with OFA on Unit 3 are 450

tons.
AEP Southwestern Power Station BART Evaluation January 19, 2010

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LNB with OFA and SCR was not determined to be BART for NOX control for Unit 3 based, in 

part, on the following conclusions:

1. The cost of compliance for installing SCR on each unit is significantly higher than the 

cost for LNB with OFA. Additional capital costs for SCR on Unit 3 are $65,968,400. 

Based on projected actual emissions, SCR could reduce overall NOX emissions from 

Southwestern Unit 3 by approximately 1,441 tpy (compared to combustion controls); 

however, the incremental cost associated with this reduction is approximately 

$10,281,677 per year, or $6,859/ton.

2. Additional non-air quality environmental mitigation is required for the use of chemical 

reagents. 

3. Operation of LNB with OFA and SCR is parasitic and requires power from each unit.

4. SCR control may not be as effective on boilers that operate as peaking units, as NOX reduction in 

an SCR is a function of flue gas temperature.

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

new LNB with OFA, to meet the statutory requirements of BART.

V. CONSTRUCTION PERMIT

Prevention of Significant Deterioration (PSD) 

Southwestern 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 Southwestern Station.

VI. OPERATING PERMIT

The Southwestern Power 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:

1. Unit 3 in EUG 1 is 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:
AEP Southwestern Power Station BART Evaluation January 19, 2010

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EU ID#

Point 

ID# EU Name

Heat Capacity

(MMBTUH)

Construction

Date

3 3 Babcock/Wilcox, RB-426 3,290 May 1967

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 boilers. 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 the following current combustion 

control technology, as determined in the submitted BART analysis, to reduce 

emissions of NOX to below the emission limits below:

i. Low-NOX Burners,

ii. Overfire Air, and

e. The permittee shall maintain the combustion controls (Low-NOX burners, overfire 

air) 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

3 03 0.45 lb/MMBTU 30-day rolling

g. Boiler operating day shall have the same meaning as in 40 CFR Part 60, Subpart Da.

h. After installation of the BART, the affected facilities shall only be fired with natural 

gas.

i. Within 60 days of achieving maximum power output from the boiler, after 

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

shall conduct performance testing as follows 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)]

i. The permittee shall conduct NOX, CO, and VOC testing on the boilers at 60% 

and 100% of the maximum capacity. NOX and CO testing shall also be 

conducted at least one additional intermediate point in the operating range.

ii. Performance testing shall be conducted while the units are operating within 

10% of the desired testing rates. 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. The permittee shall also provide notice 

of the actual test date to AQD.
AEP Southwestern Power Station BART Evaluation January 19, 2010

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iii. The following USEPA methods shall be used for testing of emissions, unless 

otherwise approved by Air Quality:

Method 1: Sample and Velocity Traverses for Stationary Sources.

Method 2: Determination of Stack Gas Velocity and Volumetric Flow 

Rate.

Method 3: Gas Analysis for Carbon Dioxide, Excess Air, and Dry 

Molecular Weight.