BART DETERMINATION REPORT

AMERICAN ELECTRIC POWER  NORTHEASTERN POWER STATION UNIT 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 

BART Determination Northeastern Power Station Unit 2Report 083701.0057 

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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 ....................................................................................................3-1

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 REDUCED BURNER SERVICE ...............................................................................6-2

6.2.2 INDUCED FLUE GAS RECIRCULATION (FGR) .....................................................6-2

6.2.3 LOW NOX BURNERS (LNB) WITH OVERFIRE AIR (OFA)...................................6-2

6.3 EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES ................ 6-3 

6.4 EVALUATION OF IMPACTS FOR FEASIBLE NOX CONTROLS ................................... 6-3 

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

6.4.2 ENERGY AND NON-AIR IMPACTS ........................................................................6-4

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

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

6.6 PROPOSED BART FOR NOX.................................................................................... 6-5 

APPENDIX A – EMISSION ESTIMATES

APPENDIX B - ECONOMIC ANALYSES

APPENDIX C – CALPUFF MODELING PROTOCOL

APPENDIX D – MODELING INPUT/OUTPUT FILES
AEP Trinity Consultants 

BART Determination Northeastern Power Station Unit 2Report 083701.0057 

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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 ..............................................................................3-2

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

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

TABLE 4-3. SO2 EMISSION ESTIMATES (NATURAL GAS)...................................................................4-1

TABLE 5-1. EXISTING MAXIMUM 24-HOUR 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. EXISTING MAXIMUM 24-HOUR NOX EMISSION RATE.....................................................6-1

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

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

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

TABLE 6-5. NORTHEASTERN UNIT 2 VISIBILITY IMPACTS (98TH PERCENTILE IMPACT) .....................6-5

 
AEP Trinity Consultants 

BART Determination Northeastern Station Unit 2 083701.0057 

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1. EXECUTIVE SUMMARY

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

Northeastern (NE) Power Station, which is located at Section 4, T22N, R15E, in Rogers County, 

Oklahoma. The NE Power Station is currently operating in accordance with Oklahoma Department 

of Environmental Quality (DEQ) Title V Operating Permit, 96-288-TV, issued in June 30, 1999. The 

NE Power Station Unit 2 is considered eligible for the application of Best Available Retrofit 

Technology (BART)1

 as part of the Environmental Protection Agency (EPA) Regional Haze Rule. 

On March 30, 2007, AEP submitted to the Oklahoma DEQ, the BART determination for its BART 

eligible facilities in Oklahoma, in accordance with OAC 252:100, Subchapter 8, Permits for Part 70 

Sources, Part 11, Visibility Protection Standards, effective October 8, 2006. Among the items 

addressed in this letter was AEP’s intent to meet BART requirements for its natural gas-fired 

Northeastern Unit 2 boiler through the use of “current combustion control technology” as described in 

40 CFR, Part 51, Regional Haze Regulations and Guidelines for BART Determinations; Final rule 

(70 Fed. Reg. July 6, 2005) . 

In a letter response dated December 12, 2007, the Oklahoma DEQ requested, among other items, a 

formal five-factor BART determination for Northeastern Unit 2. Per the guidelines in 40 CFR Part 

512

, 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 for Northeastern Unit 2 as BART for PM. 

Continued use of natural gas will ensure an emission rate lower than what could be achieved 

with add-on PM controls. 

• SO2 – AEP also proposes the use of natural gas for Northeastern Unit 2 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 0.28 lb/MMBtu as BART for NOx. This will be 

achieved by installing Low NOx burners (LNB)/overfire air (OFA) system 

 

1

 40 CFR 51 Appendix Y, Guidelines for BART Determinations Under the Regional Haze Rule 2

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

Determinations 
AEP Trinity Consultants 

BART Determination Northeastern Station Unit 2 083701.0057 

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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)3

 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 

 3

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

pollutants. 
AEP Trinity Consultants 

BART Determination Northeastern Station Unit 2 083701.0057 

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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.

4

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: 

 4

 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 

BART Determination Northeastern Station Unit 2 083701.0057 

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[( ) ] ( )

[ ] ( )

[ ]

[ ]

[ ]

[ ]

( )

[ ] 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. 
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BART Determination Northeastern Station Unit 2 083701.0057 

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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 Northeastern 2 

unit determined that it is indeed subject to BART. The BART determinations for each of the three 

visibility affecting pollutants (SO2, NOx, and PM) can be found in Sections 3 through 5. 
AEP Trinity Consultants 

BART Determination Northeastern Power Station Unit 2 083701.0057 

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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 Northeastern 

Station is provided below. As seen from this table, the Northeastern Station has three units that were 

“in existence” within the 15-year BART window (August 7, 1962-August 7, 1977). The coal fired 

units, NE3 and 4, are addressed under separate cover. Northeastern Unit 2, the natural gas-fired unit, 

is addressed in the sections below. 

TABLE 3-1. CONSTRUCTION DATE SUMMARY

Unit 

No. 

Heat Duty 

(MMBtu/hr) 

Manufacturer Construction Date 

1 1,817 Babcock and Wilcox RB-321 Feb, 1961 

2 4,754 Babcock and Wilcox UP-60 Mar, 1970 

3 4,775 Combustion Engineering #4974 Apr, 1974 

4 4,775 Combustion Engineering #7174 Apr, 1974 

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 

NE2 3,385 35.4 2.90 0.30 

Please note that the NE2 operated entirely on natural gas from 2001-05. 

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: 
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BART Determination Northeastern Power Station Unit 2 083701.0057 

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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%).5

 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 Northeastern 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 

NE2 8.9 26.6 0 0 

3.2.2 STACK PARAMETERS

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

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) 

NE2 36.42767 95.7007 53 183 18 249 

The base elevation of each of the units is 194 meters (636 feet) above MSL based upon 

visual inspection of USGS topographic maps. 

 5

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

BART Determination Northeastern Power Station Unit 2 083701.0057 

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4. SO2 BART DETERMINATION

A summary of existing SO2 emissions as described in Section 3 is included below. 

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

Emission 

Unit 

SO2 Emission Rate 

(lb/hr) 

NE2 2.90 

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 Northeastern 

Power Station Unit 2 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. 96-

288-TV) provides an estimate of SO2 emissions from the combustion of natural gas, as summarized 

below. 

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

Emission SO2

Unit lb/hr TPY 

NE2 2.80 12.25 
AEP Trinity Consultants 

BART Determination Northeastern Power Station Unit 2 083701.0057 

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SO2 emissions from Northeastern Unit 2 are sufficiently low from natural gas usage that no add-on 

control technology could be considered economically feasible. As a result, AEP determines that 

natural gas usage is BART for Northeastern Power Station Unit 2. 
AEP Trinity Consultants 

BART Determination Northeastern Power Station Unit 2 083701.0057 

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5. PM BART DETERMINATION

A summary of existing PM emissions as described in Section 3 is included below. 

TABLE 5-1. EXISTING MAXIMUM 24-HOUR PM EMISSION RATES

Emission 

Unit 

PM Emission Rate 

(lb/hr) 

NE2 35.4 

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 Northeastern Power Station Unit 2 to natural gas only. As 

with SO2, the use of pipeline quality natural gas inherently results in low particulate emissions. The 

facility’s existing Title V operating permit (No. 96-288-TV) 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 

NE3 35.42 155.15 

These emission estimates for this unit 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 Northeastern Power Station Unit 2. 
AEP Trinity Consultants 

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6. NOXBART DETERMINATION 

The existing maximum daily NOX emission rates that were modeled for the BART applicability 

determination are summarized in Table 6-1. 

TABLE 6-1. EXISTING MAXIMUM 24-HOUR NOX EMISSION RATE

Unit ID NOX Hourly 

Emission Rate 

NOX Emission 

Rate 

 (lb/hr) (lb/MMBtu) 

NE2 3,385 0.71 

6.1 IDENTIFY ALL AVAILABLE RETROFIT TECHNOLOGIES

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

TABLE 6-2. AVAILABLE NOX COMBUSTION CONTROL TECHNOLOGIES 

NOX Control Technologies 

Burner Tuning 

Burners Out of Service (placing selected burners out of 

service) 

Induced Flue Gas Recirculation (IFGR) 

Low NOX Burners (LNB)/overfire air (OFA) 

NOX emissions controls, as listed in Table 6-2, are categorized as combustion controls. Combustion 

controls, including induced flue gas recirculation (IFGR), overfire air (OFA), and Low NOX Burners 

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

formation. Post-combustion controls, such as selective catalytic reduction (SCR) and selective noncatalytic reduction (SNCR) were not examined in this analysis. As described in Appendix Y to Part 

51, U.S. EPA states that the use of combustion control technology is highly cost-effective in 

achieving emission reductions under BART for gas-fired applications.6

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. 

 6

 Federal Register, Vol 20, No. 128, 7/6/2005, p. 39172 
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BART Determination Northeastern Power Station Unit 2 083701.0057 

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6.2.1 BURNERS OUT OF SERVICE 

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 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. 

6.2.2 INDUCED FLUE GAS RECIRCULATION (IFGR) 

IFGR 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 equipment upgrades. As with the Burners Out Of Service option, IFGR is 

considered technically infeasible. 

6.2.3 LOW NOX BURNERS (LNB) WITH OVERFIRE AIR (OFA) 

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. 

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

separate air ports above the top level of burners. Staging of the combustion air creates an 

initial fuel-rich combustion zone with a lower peak flame temperature. This reduces the 

formation of thermal NOX by lowering combustion temperature and limiting the 

availability of oxygen in the combustion zone where NOX is most likely to be formed. 
AEP Trinity Consultants 

BART Determination Northeastern Power Station Unit 2 083701.0057 

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OFA as a single NOX control technique may reduce NOX emissions by 25 to 55 percent. 

When combined with LNB, reductions of up to 60 percent may result.7

 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 

(%) 

LNB w/ OFA ~30-60 

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. 

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) 

 7

 "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 

BART Determination Northeastern Power Station Unit 2 083701.0057 

6-4

...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) 

Compliance costs associated with implementing the evaluated control systems were 

developed in-house by AEP, and represent both annual operating costs and annualized capital 

costs associated with retrofit construction. 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

NE2 Low NOx Burner 

w/ Overfire Air 

573 -- 

6.4.2 ENERGY AND NON-AIR IMPACTS

Energy and non-air impacts from an LNB retrofit are minimal. Derating of output from the 

unit is not expected, or considered insignificant. 

6.4.3 REMAINING USEFUL LIFE

The remaining useful life of the Northeastern 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 
AEP Trinity Consultants 

BART Determination Northeastern Power Station Unit 2 083701.0057 

6-5

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

presented below on a unit-by-unit basis. 

TABLE 6-5. NORTHEASTERN UNIT 2 VISIBILITY IMPACTS (98TH PERCENTILE IMPACT) 

Class I Area Pre-BART LNB w/ OFA Visibility 

Improvement 

∆dv ∆dv %

Caney Creek 0.675 0.276 59% 

Hercules-Glades 0.314 0.126 60% 

Upper Buffalo 0.390 0.157 60% 

Wichita Mountains 0.421 0.162 62% 

 

6.6 PROPOSED BART FOR NOX 

AEP has determined that the NOX BART for Northeastern Unit 2 is LNB w/ OFA. As seen from the 

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

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

estimates of LNB w/ OFA, AEP proposes a BART NOx emission rate of 0.28 lb/MMBtu. 
AEP Trinity Consultants 

BART Determination Northeastern Power Station Unit 2 083701.0057 

APPENDIX A – EMISSION ESTIMATES
Unit 2

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

Case 1 Baseline Case -- 0.71 3,384.8 0.0006 2.85 0.000074 0.3 0.007 35.4 Case 2 LNB w/ OFA 60% 0.28 1,353.9

1 Sulfuric acid emissions based upon the following:

SO2 Conversion to SO3 = 10%

SO3 Conversion to H2SO4 = 100%

MW H2SO4 = 98 lb/lbmol

MW SO3 = 80 lb/lbmol

MW SO2 = 64 lb/lbmolSample Calculation:

0.0006 lb SO2 0.1 lb SO3 lb mol SO3 lb mol H2SO4 98 lb H2SO4

mmBtu 1 lb SO2 80 lb SO3 lb mol SO3 lb mol H2SO4

2 Baseline emission data for PM is not available. A conservative estimate was made using U.S. EPA emission factors, AP-42 (7/98) Table 1.4-2

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

PM10 = 7.6 lb/MMSCF

0.0075 lb/MMBtu

Natural gas heating value = 1020 BTU/scf

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%

Condensible 75%

Percent 

Reduction

NOx

BART Emissions Modeling Inputs

Northeastern Power Station

=

0.000074 lbs H2SO4

mmBtu

PM (total)2 SO2 H2SO4 (as SO4 from SO2)1

American Electric PowerNortheastern Power Station

Emission Estimates (lbhr)

Printed on 8/27/2008

Page 1 of 2
Unit ID

Unit 2

Unit 2

NOx

Reduction (%) (lb/MMBtu)1 tpy

Case 1 Baseline Case -- 0.48 9,995Case 2 LNB w/ OFA 41% 0.28 5,930

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

Northeastern Power Plant

Annual Emission Estimates

(MMBtu/hr)

4754

Annual Ave Firing Rate

American Electric PowerNortheastern Power Station

Emission Estimates (Annual)

Printed on 8/27/2008

Page 2 of 2
Northeastern Station

CALPUFF Visibility Results

Peak Impact 98th Percentile

Pollutant Class I Area

Control Technology (∆dv)

% Reduction 

from Baseline (∆dv)

% Reduction 

from Baseline

NOx Caney Creek Baseline 1.810 -- 0.675 --

LNB w/ OFA 0.751 59% 0.276 59%

Herc-Glades Baseline 1.164 -- 0.314 --

LNB w/ OFA 0.482 59% 0.126 60%

Upper Buffalo Baseline 1.456 -- 0.390 --

LNB w/ OFA 0.601 59% 0.157 60%

Wichita Mts Baseline 1.698 -- 0.421 --

LNB w/ OFA 0.703 59% 0.162 62%

PM10 Caney Creek Baseline 0.002 -- 0.001 --

Herc-Glades Baseline 0.001 -- -- --Upper Buffalo Baseline 0.002 -- 0.001 --Wichita Mts Baseline 0.002 -- 0.001 --

SO2 Caney Creek Baseline 0.001 -- -- --

Herc-Glades Baseline -- -- -- --Upper Buffalo Baseline 0.001 -- -- --Wichita Mts Baseline 0.001 -- -- --
AEP Trinity Consultants 

BART Determination Northeastern Power Station Unit 2 083701.0057 

APPENDIX B - ECONOMIC ANALYSES
Printed: 8/27/2008

Economic Analysis for Low NOx Burners w/ Overfire Air

Capital Cost Summary Capital Cost

TOTAL CAPITAL INVESTMENT a TCI = $3,450,000

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 $69,000

Insurance (1% of TCI) b $34,500

Property Taxes (1% of TCI) b $34,500

Capital Recovery (CRF x TCI)

20 years @ 8.00% interest CRF = 0.1019 $351,390

TOTAL INDIRECT COSTS (IC) IC = $489,390

TOTAL ANNUALIZED COST (TAC = DC + IC) TAC= $489,390

Cost Effectiveness Summary

Annual Control Cost: $489,390

NOx to be Removed (tpy): c 854

CONTROL COST EFFECTIVENESS ($/ton): $573

a Cost of purchasing and installing Low-NOx burners provided by AEP via email (8/21/2008). 

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

c LNB w/OFA NOx Removal Rate = 41%

Annual Capacity Factor = 0.21 Provided by AEP via email, 8/20/2008

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

Annual Average Firing Rate = 4754 MMBtu/hr, as listed in Permit No. 96-288-TV.

Sample Calculation:

0.48 lb 4754 MMBtu 8760 hrs ton 0.21 capacity factor 0.41 NOx Removal Rate = 854 tons NOx

MMBtu hr yr 2000 lb year

American Electric Power

Northeastern Power Station Cost Analysis (LNB wOFA)

Trinity Consultants

083701.0057
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BART Determination Northeastern Power Station Unit 2 083701.0057 

APPENDIX C – CALPUFF MODELING PROTOCOL
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BART Determination Northeastern Power Station Unit 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 LNB w/ OFA Run 2 --