Oklahoma Department of Environmental Quality

Air Quality Division

BART Application Analysis January 19, 2010

COMPANY: AEP-Public Service Company of Oklahoma

FACILITY: Northeastern Power Plant

FACILITY LOCATION: Rogers County, Oklahoma

TYPE OF OPERATION: (1) 495 MW Natural Gas-Fired Steam Electric 

Generating Unit

(2) 490 MW Coal-Fired Steam Electric 

Generating Units

REVIEWERS: 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).

Northeast Units 2, 3 and 4 are fossil-fuel fired boilers with heat inputs greater than 250-

mmBtu/hr. All three 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, SO2, and PM10, visibility impairing pollutants. 

Therefore, Northeast Units 2, 3 and 4 meet the definition of BART-eligible sources.
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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 Northeast Units 2, 3 and 4 exceeded the 0.5 Δ-dv threshold at the Wichita Mountains, 

Caney Creek, Upper Buffalo, and Hercules Glade Class I Areas. Therefore, Northeast Units 2, 3 

and 4 were determined to be BART applicable sources, subject to the BART determination 

requirements.

III. DESCRIPTION OF BART SOURCES

Baseline emissions from Northeastern Units 2, 3 and 4 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, modeled 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 average annual mass 

emission rates for each boiler by the boiler’s average heat input over the years 2004 through 

2006.

Table 1: Northeastern Power Plant- Plant Operating Parameters for BART Evaluation

Parameter Northeastern Unit 2 Northeastern Unit 3 Northeastern Unit 4

Plant Configuration Natural Gas-Fired 

Boiler

Coal-Fired Boiler Coal-Fired Boiler

Firing 

Configuration

Tangentially-fired Tangentially-fired

Gross Output 

(nominal)

495 MW 490 MW 490 MW

Maximum Input to 

Boiler

4,754 mmBtu/hr 4,775 mmBtu/hr 4,775 mmBtu/hr

Maximum 24-hour 

Average Input

4,767 mmBtu/hr 5,812 mmBtu/hr 5,594 mmBtu/hr

Primary Fuel Natural Gas Sub-bituminous coal Sub-bituminous coal

Existing NOX

Controls

1

st Generation 

LNB/OFA

1

st Generation LNB/OFA 1st Generation LNB/OFA

Existing PM10

Controls

NA Electrostatic precipitator Electrostatic precipitator

Existing SO2

Controls

NA Low-sulfur coal Low-sulfur coal

Maximum 24-hour Emissions (CALPUFF Model)

Unit 2 Unit 3 Unit 4

lb/hr lb/mmBtu lb/hr lb/mmBtu lb/hr lb/mmBtu
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NOX 3,385 0.71 3,116 0.536 2,747 0.491

SO2 2.9 0.0006 6,106 1.05 5,930 1.06

PM10 35.4 0.007 220 0.038 330 0.059

Baseline Emissions (2004- 2006)

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

NOX 1462 0.449 1838 0.397 1827 0.404

SO2 1.66 0.0006 4235 0.914 4102 0.907

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.

In the final Regional Haze Rule U.S.EPA established presumptive BART emission limits for 

SO2 and NOX for certain electric generating units (EGUs) based on fuel type, unit size, cost 

effectiveness, and the presence or absence of pre-existing controls. The presumptive limits apply 

to EGUs at power plants with a total generating capacity in excess of 750 MW. For these 

sources, EPA established presumptive emission limits for coal-fired EGUs greater than 200 MW 

in size. The presumptive levels are intended to reflect highly cost-effective technologies as well 

as provide enough flexibility to States to consider source specific characteristics when evaluating 

BART. The BART SO2 presumptive emission limit for coal-fired EGUs greater than 200 MW in 

size without existing SO2 control is either 95% SO2 removal, or an emission rate of 0.15 

lb/mmBtu, unless a State determines that an alternative control level is justified based on a 

careful consideration of the statutory factors. For NOX, EPA established a set of BART 

presumptive emission limits for coal-fired EGUs greater than 200 MW in size based upon boiler 

size and coal type. The BART NOX presumptive emission limit applicable to Northeast Units 3 

and 4 (tangentially fired boilers firing subbituminous coal) is 0.15 lb/mmBtu.

Table 2: BART Controls and Limits

Unit NOX BART Emission Limit BART Technology

Northeastern Unit 2 0.28 lb/mmBtu (30-day average) Combustion controls including LNB/OFA

Northeastern Unit 3 0.15 lb/mmBtu (30-day average) Combustion controls including LNB/OFA

Northeastern Unit 4 0.15 lb/mmBtu (30-day average) Combustion controls including LNB/OFA 

Unit SO2 BART Emission Limit BART Technology

Northeastern Unit 3 0.65 lb/mmBtu (30-day average) Low Sulfur Coal

Northeastern Unit 4 0.65 lb/mmBtu (30-day average) Low Sulfur Coal

Unit PM10 BART Emission Limit BART Technology

Northeastern Unit 3 0.1 lb/mmBtu (3-hour average)1Existing ESP
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Northeastern Unit 4 0.1 lb/mmBtu (3-hour average)1Existing ESP

1Current emissions limits for ESPs are based on minimum NSPS requirements for front half 

catch. As part of the permitting process, PSO will be required to propose emission limits for 

front and back half reflective of the control technology and consistent with performance test 

results.

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 Northeast Units 2, 

3 and 4 are listed in Table 3.

Table 3: List of Potential Control Options

Control Technology

Combustion Controls

Burners Out of Service (NE 2 only)

Flue Gas Recirculation (FGR)

Low NOX Burners and Overfire Air (LNB/OFA)

Post Combustion Controls

Selective Noncatalytic Reduction (SNCR)

Selective Catalytic Reduction (SCR)

Reburning /Methane de-NOX (MdN)

ELIMINATE TECHICALLY INFEASIBLE OPTIONS (NOX)

Combustion Controls:

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 place a load limit on the unit. The resulting load limits would effectively result in the 

shutdown of the unit and as a result, this option is considered technically infeasible.

Flue Gas Recirculation

Flue gas recirculation (FGR) controls NOX by recycling a portion of the flue gas back into the 

primary combustion zone. The recycled air lowers NOX emissions by two mechanisms: (1) the 

recycled gas, consisting of products which are inert during combustion, lowers the combustion 

temperatures; and (2) the recycled gas will reduce the oxygen content in the primary flame zone. 

The amount of recirculation is based on flame stability. 

FGR control systems have been used as a retrofit NOX control strategy on natural gas-fired 

boilers, but have not generally been considered as a retrofit control technology on coal-fired 

units. Natural gas-fired units tend to have lower O2 concentrations in the flue gas and low 

particulate loading. In a coal-fired application, the FGR system would have to handle hot 

particulate-laden flue gas with a relatively high O2 concentration. Although FGR has been used 

on coal-fired boilers for flue gas temperature control, it would not have application on a coalfired boiler for NOX control. Because of the flue gas characteristics (e.g., particulate loading and 

O2 concentration), FGR would not operate effectively as a NOX control system on a coal-fired 
PSO Northeastern Power Plant BART Review January 19, 2010

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boiler. Therefore, FGR is not considered an applicable retrofit NOX control option for Northeast 

Units 3 and 4, and will not be considered further in the BART determination.

For Unit 2, Induced Flue Gas Recirculation (IFGR) would also place load limits on the boiler 

and call for plant equipment upgrades. As with the Burners Out of Service option, IFGR is 

considered technically infeasible. 

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 coal-fired boilers. Northeast Units 3 and 4 operate as base load units. While technically 

feasible, LNB/OFA may not be as effective under all boiler operating conditions, especially 

during load changes and at low operating loads. Based on information available from burner 

control vendors and engineering judgment, it is expected that LNB/OFA on tangentially-fired

boilers can be designed to meet the presumptive NOX BART emission rate of 0.15 lb/mmBtu on 

a 30-day rolling average and under all normal operating conditions while maintaining acceptable 

CO and VOC emission rates.

For the natural gas-fired Unit 2, OFA as a single NOX control technique may reduce NOX

emissions by 25-55 percent. When combined with LNB, reductions of up to 60% may result. 

This technology is a feasible option for all three units.

Reburning/Methane De-NOX

In reburning, also known as “off-stoichiometric combustion” or “fuel staging,” a fraction (5 to 25 

percent) of the total fuel heat input is diverted to a second combustion zone downstream of the 

primary zone. The fuel in the fuel-rich secondary zone acts as a reducing agent, reducing NO, 

which is formed in the primary zone, to N2. Generally, it is more economical for a facility to use 

the same fuel for reburning as it does for primary combustion, although there are exceptions. In 

order to use coal as a reburning fuel, it must be finely ground, which requires additional 

pulverizing equipment. 

Methane de- NOX (MdN) utilizes the injection of natural gas together with recirculated flue 

gases (for enhanced mixing) to create an oxygen-rich zone above the combustion grate. OFA is 

then injected at a higher furnace elevation to burn out the combustibles. This process is claimed 

to yield between 50 and 70 percent NOX reduction and to be suitable for all solid fuel-fired 

stoker boilers. However, as of 2002, MdN had only been demonstrated for a short duration in 

one pulp mill wood-fired stoker boiler that also burned small amounts of waste treatment plant 

residuals, with NOX reductions of 40 to 50 percent reported.

MdN is not considered feasible for the coal-fired units because (1) it is not fully demonstrated 

and (2) it incorporates FGR, which is technically infeasible for all three units.
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Post Combustion Controls:

Selective Non-Catalytic Reduction

Selective non-catalytic reduction (SNCR) involves the direct injection of ammonia or urea at 

high flue gas temperatures. The ammonia or urea reacts with NOX in the flue gas to produce N2

and water. At temperatures below the desired operating range, the NOX reduction reactions 

diminish and NH3 emissions increase. Above the desired temperature range, NH3 is oxidized to 

NOX resulting in low NOX reduction efficiencies. Mixing of the reactant and flue gas within the 

reaction zone is also an important factor in SNCR performance. In large boilers, the physical 

distance over which the reagent must be dispersed increases, and the surface area/volume ratio of 

the convective pass decreases. Both of these factors make it difficult to achieve good mixing of 

reagent and flue gas, reducing overall efficiency. Performance is further influenced by residence 

time, reagent-to-NOX ratio, and fuel sulfur content.

The size of the Northeastern Units would represent several design problems making it difficult to 

ensure that the reagent would be injected at the optimum flue gas temperature, and that there 

would be adequate mixing and residence time. The physical size of the Northeastern boilers

makes it technically infeasible to locate and install ammonia injection points capable of 

achieving adequate mixing within the required temperature zone. Higher reagent injection rates 

would be required to achieve adequate mixing. Higher ammonia injection rates would result in 

relatively high levels of ammonia in the flue gas (ammonia slip), which could lead to plugging of 

downstream equipment.

Another design factor limiting the applicability of SNCR control systems on large subbituminous 

coal-fired boilers is related to the reflective nature of subbituminous ash. Subbituminous coals 

typically contain high levels of calcium oxide and magnesium oxide that can result in reflective 

ash deposits on the waterwall surfaces. Because most heat transfer in the furnace is radiant, 

reflective ash can result in less heat removal from the furnace and higher exit gas temperatures. 

If ammonia is injected above the appropriate temperature window, it can actually lead to 

additional NOX formation. 

Installation of SNCR on large boilers, such as those at Northeastern, has not been demonstrated 

in practice. Assuming that SNCR could be installed on the Northeastern Units, given the issues 

addressed above, control effectiveness would be marginal, and depending on boiler exit 

temperatures, could actually result in additional NOX formation. 

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 coal-fired boilers. Based on 

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

have achieved actual long-term average NOX emission rates in the range of approximately 0.04

to 0.1 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.
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Based on emission rates achieved in practice at existing subbituminous coal-fired units, and 

taking into consideration long-term operation of an SCR control system (including catalyst 

plugging and deactivation) it is anticipated that SCR could achieve a controlled NOX emission 

rate of 0.054 lb/mmBtu on Northeast Unit 3 and 0.049 lb/mmBtu on Unit 4. The addition of 

SCR controls to Unit 2 could result in a controlled NOX emission rate of 0.05 lb/mmBtu.

EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (NOX)

Table 4: Technically Feasible NOX Control Technologies- Northeastern Power Plant

Control Technology

Northeastern Unit 2 Northeastern Unit 3 Northeastern Unit 4

Approximate NOX

Emission Rate

(lb/mmBtu)

Approximate NOX

Emission Rate

(lb/mmBtu)

Approximate NOX

Emission Rate

(lb/mmBtu)

LNB/OFA + SCR 0.05 0.054 0.049

LNB/OFA 0.28 0.15 0.15

SNCR -- 0.402 0.368

Baseline 0.449 0.397 0.404

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. Capital costs were developed by AEPPSO and are based on equipment costs for similar projects, and include the equipment, material, 

labor, and all other direct costs needed to retrofit Northeast Units 2, 3 and 4 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, 

including operation of any new fans as well as the power requirements for pumps, reagent 

handling, and by-product handling. 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 21% for Unit 2

and a capacity factor of 85% for SO2 control effectiveness calculations for Units 3 and 4. No 

capacity factors were used for NOX control effectiveness calculations.

AEP-PSO submitted initial cost estimates in 2008 that relied upon a baseline emission rate 

representative of the maximum actual 24-hour emission rate, which is consistent with the 

modeling demonstration. However, the calculations overestimate the cost effectiveness by 

assuming a larger ton per year emissions reduction with the addition of controls than would be 

realized given actual annual average emissions. Using a representative annual average emission 

rate (2004-2006), the cost effectiveness ($/ton removed) is much higher, but the result is 

representative of more reasonably achievable emissions reductions. 
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Table 5: Economic Cost for Units 3 and 4 (Coal-Fired Boilers)

Cost

Option 1:

SNCR2

Option 2:

LNB/OFA

Option 3:

LNB/OFA +SCR1

Total Capital Investment ($) $11,500,000 $17,000,000 $290,000,000

Annualized Capital Cost ($/Yr) $1,171,300 $1,731,488 $29,537,141

Annual O&M Costs ($/Yr) $13,602,120 $680,000 $18,248,660

Annual Cost of Control ($) $14,773,420 $2,411,488 $47,785,801

1While not stated explicitly, costs for SCR are assumed to encompass LNB/OFA as well.

2Costs associated with SNCR are greater than LNB/OFA with less potential reduction in emissions, no further 

review will be required.

Table 6: Environmental Costs for Units 3 and 4 (Coal-Fired Boiler)

Baseline LNB/OFA LNB/OFA +SCR

NOX Emission Rate (lb/mmBtu) Unit3 0.397 0.15 0.054

NOX Emission Rate (lb/mmBtu) Unit4 0.404 0.15 0.049

Annual NOX Emission (TPY)113,971 6,274 2,154

Annual NOX Reduction (TPY) -- 7,697 11,817

Annual Cost of Control -- $2,411,488 $47,785,801

Cost per Ton of Reduction -- $313 $4,044

Incremental Cost per ton of Reduction2-- $11,013

(1) Emissions for the BART analysis are based on annual average emissions from 2004-2006 for Units 3 & 4. 

(2)

Incremental cost effectiveness of the SCR system is compared to costs/emissions associated with LNB/OFA 

controls.

Table 7: Economic Cost for Unit 2 (Natural Gas-Fired Boilers)

Cost

Option 1:

LNB/OFA

Option 2:

LNB/OFA +SCR1

Total Capital Investment ($) $3,450,000 $94,743,000

Annualized Capital Cost ($/Yr) $351,390 $9,649,784

Annual O&M Costs ($/Yr) $138,000 $3,789,720

Annual Cost of Control ($) $489,390 $14,366,357

1While not stated explicitly, costs for SCR are not assumed to encompass LNB/OFA based on the 

incremental cost analysis completed by the applicant.

Table 8: Environmental Costs for Unit 2 (Natural Gas-Fired Boiler)

Baseline

Option 2:

LNB/OFA

Option 3: 

LNB/OFA +SCR

NOX Emission Rate (lb/mmBtu) Unit2 0.449 0.285 0.05

Annual NOX Emission (TPY)12,861 1,246 219

Annual NOX Reduction (TPY) -- 1615 2642

Annual Cost of Control $489,390 $14,366,357

Cost per Ton of Reduction $303 $5,438

Incremental Cost per ton of Reduction2$13,512

(1) Emissions for the BART analysis are based on annual average emission from 2005- 2006 (2004 emissions are 

not reflective of annual averages. Annual costs for LNB/OFA assumed a capacity factor of 0.21. The 

applicant used a capacity factor of 0.19 in the SCR evaluation; however, the analysis reported here reflects 

the 0.21 capacity factor documented in the original submittal.

(2) Incremental cost effectiveness of the SCR system is compared to costs/emissions associated with LNB/OFA 

controls.
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B. SO2

IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES (SO2)

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

available information. SO2 control technologies with potential application to Northeast Units 3 

and 4 are listed in Table 9.

Table 9: List of Potential Control Options

Control Technology

Pre-Combustion Control

Wet Flue Gas Desulfurization

Dry Flue Gas Desulfurization-Spray Dryer Absorber

ELIMINATE TECHICALLY INFEASIBLE OPTIONS (SO2)

Pre-Combustion Control Strategy:

Fuel Switching

One potential strategy for reducing SO2 emissions is reducing the amount of sulfur contained in 

the coal. Northeast Units 3 and 4 fire subbituminous coal as their primary fuel. Subbituminous 

coal has a relatively low heating value, low sulfur content, and low uncontrolled SO2 emission 

rate. No environmental benefits accrue from burning an alternative coal; however, 

subbituminous coal with lower sulfur content is achievable and available. Fuel switching to a 

lower sulfur content coal is a viable option.

Coal Washing

Coal washing, or beneficiation, is one pre-combustion method that has been used to reduce

impurities in the coal such as ash and sulfur. In general, coal washing is accomplished by

separating and removing inorganic impurities from organic coal particles. The coal washing 

process generates a solid waste stream consisting of inorganic materials separated from the coal, 

and a wastewater stream that must be treated prior to discharge. Solids generated from 

wastewater processing and coarse material removed in the washing process must be disposed in a 

properly permitted landfill. Solid wastes from coal washing typically contain pyrites and other 

dense inorganic impurities including silica and trace metals. The solids are typically dewatered in 

a mechanical dewatering device and disposed of in a landfill.

Northeast Units 3 and 4 are designed to utilize subbituminous coals. Based on a review of

available information, no information was identified regarding the washability or effectiveness of 

washing subbituminous coals. Therefore, coal washing is not considered an available retrofit 

control option for Northeast Units 3 and 4.

Coal Processing

Pre-combustion coal processing techniques have been proposed as one strategy to reduce the 

sulfur content of coal and help reduce uncontrolled SO2 emissions. Coal processing technologies 

are being developed to remove potential contaminants from the coal prior to use. These 

processes typically employ both mechanical and thermal means to increase the quality of 
PSO Northeastern Power Plant BART Review January 19, 2010

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subbituminous coal and lignite by removing moisture, sulfur, mercury, and heavy metals. To 

date, the use of processed fuels has only been demonstrated with test burns in a coal-fired boiler. 

No coal-fired boilers have utilized processed fuels as their primary fuel source on an on-going, 

long-term basis. Although burning processed fuels, or a blend of processed fuels, has been tested 

in a coal-fired boiler, using processed fuels in Northeast Units 3 and 4 would require significant 

research, test burns, and extended trials to identify potential impacts on plant systems, including 

the boiler, material handling, and emission control systems. Therefore, processed fuels are not 

considered commercially available, and will not be analyzed further in this BART analysis.

Post-Combustion Flue Gas Desulfurization:

Wet Scrubbing Systems

Wet FGD technology is an established SO2 control technology. Wet scrubbing systems offered 

by vendors may vary in design; however, all wet scrubbing systems utilize an alkaline scrubber 

slurry to remove SO2 from the flue gas.

Wet Lime Scrubbing

The wet lime scrubbing process uses an alkaline slurry made by adding lime (CaO) to water. The 

alkaline slurry is sprayed in the absorber and reacts with SO2 in the flue gas. Insoluble CaSO3

and CaSO4 salts are formed in the chemical reaction that occurs in the scrubber and are removed 

as a solid waste by-product. The waste by-product is made up of mainly CaSO3, which is 

difficult to dewater. Solid waste by-products from wet lime scrubbing are typically managed in 

dewatering ponds and landfills.

Wet Limestone Scrubbing

Limestone scrubbers are very similar to lime scrubbers except limestone (CaCO3) is mixed with 

water to formulate the alkali scrubber slurry. SO2 in the flue gas reacts with the limestone slurry 

to form insoluble CaSO3 and CaSO4 which is removed as a solid waste by product. The use of 

limestone instead of lime requires different feed preparation equipment and a higher liquid-togas ratio. The higher liquid-to-gas ratio typically requires a larger absorbing unit. The limestone 

slurry process also requires a ball mill to crush the limestone feed.

Forced oxidation of the scrubber slurry can be used with either the lime or limestone wet FGD 

system to produce gypsum solids instead of the calcium sulfite by-product. Air blown into the 

reaction tank provides oxygen to convert most of the calcium sulfite (CaSO3) to relatively pure

gypsum (calcium sulfate). Forced oxidation of the scrubber slurry provides a more stable byproduct and reduces the potential for scaling in the FGD. The gypsum by-product from this 

process must be dewatered, but may be salable thus reducing the quantity of solid waste that 

needs to be landfilled.

Wet lime and wet limestone scrubbing systems will achieve the same SO2 control efficiencies; 

however, the higher cost of lime typically makes wet limestone scrubbing the more attractive 

option. For this reason, wet lime scrubbing will not be evaluated further in this BART 

determination.

Wet Magnesium Enhanced Lime Scrubbing
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Magnesium Enhanced Lime (MEL) scrubbers are another variation of wet FGD technology. 

Magnesium enhanced lime typically contains 3% to 7% magnesium oxide (MgO) and 90 – 95% 

calcium oxide (CaO). The presence of magnesium effectively increases the dissolved alkalinity, 

and consequently makes SO2 removal less dependent on the dissolution of the lime/limestone. 

MEL scrubbers have been installed on coal-fired utility boilers located in the Ohio River Valley. 

Systems to oxidize the MEL solids to produce a usable gypsum byproduct consisting of calcium 

sulfate (gypsum) and magnesium sulfate continue to be developed. Coal-fired units equipped 

with MEL FGD typically fire high-sulfur eastern bituminous coal and use locally available 

reagent. There are no subbituminous-fired units equipped with a MEL-FGD system. Because 

MEL-FGD systems have not been used on subbituminous-fired boilers, and because of the cost 

and limited availability of magnesium enhanced reagent (either naturally occurring or blended), 

and because limestone-based wet FGD control systems can be designed to achieve the same 

control efficiencies as the magnesium enhanced systems, MEL-FGD control systems will not be 

evaluated further as a commercially available retrofitted control system.

Jet Bubbling Reactor

Another variation of the wet FGD control system is the jet bubbling reactor (JBR). Unlike the 

spray tower wet FGD systems, where the scrubbing slurry contacts the flue gas in a

countercurrent reaction tower, in the JBR-FGD flue gas is bubbled through a limestone slurry.

Spargers are used to create turbulence within the reaction tank and maximize contact between the 

flue gas bubbles and scrubbing slurry. There is currently a limited number of commercially 

operating JBR-WFGD control systems installed on coal-fired utility units in the U.S. Although 

the commercial deployment of the control system continues, there is still a very limited number 

of operating units in the U.S. Furthermore, coal-fired boilers currently considering the JBRWFGD control system are all located in the eastern U.S., and all fire eastern bituminous coals. 

The control system has not been proposed as a retrofit technology on any large subbituminous 

coal-fired boilers. However, other than scale-up issues, there do not appear to be any overriding 

technical issues that would exclude application of the control technology on a large 

subbituminous coal-fired unit. There are no data available to conclude that the JBR-WFGD 

control system will achieve a higher SO2 removal efficiency than a more traditional spray tower 

WFGD design, especially on units firing low-sulfur subbituminous coal. Furthermore, the costs 

associated with JBR-WFGD and the control efficiencies achievable with JBR-WFGD are similar 

to the costs and control efficiencies achievable with spray tower WFGD control systems. 

Therefore, the JBR-WFGD will not be evaluated as a unique retrofit technology, but will be

included in the overall assessment of WFGD controls.

Dual-Alkali Wet Scrubber

Dual-alkali scrubbing is a desulfurization process that uses a sodium-based alkali solution to 

remove SO2 from combustion exhaust gas. The process uses both sodium-based and calciumbased compounds. The dual-alkali process requires lower liquid-to-gas ratios then scrubbing with 

lime or limestone. The reduced liquid-to-gas ratios generally mean smaller reaction units, 

however additional regeneration and sludge processing equipment is necessary. The sodiumbased scrubbing liquor, typically consisting of a mixture of sodium hydroxide, sodium carbonate 

and sodium sulfite, is an efficient SO2 control reagent. However, the high cost of the sodiumbased chemicals limits the feasibility of such a unit on a large utility boiler. In addition, the 

process generates a less stable sludge that can create material handling and disposal problems. It 
PSO Northeastern Power Plant BART Review January 19, 2010

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is projected that a dual-alkali system could be designed to achieve SO2 control similar to a 

limestone-based wet FGD. However, because of the limitations discussed above, and because 

dual-alkali systems are not currently commercially available, dual-alkali scrubbing systems will 

not be addressed further in this BART determination.

Wet FGD with Wet Electrostatic Precipitator

Wet electrostatic precipitation (WESP) has been proposed on other coal-fired projects as one 

technology to reduce sulfuric acid mist emissions from coal-fired boilers. WESPs have been 

proposed for boilers firing high-sulfur eastern bituminous coals controlled with wet FGD.24

WESP has not been widely used in utility applications, and has only been proposed on boilers 

firing high sulfur coals and equipped with SCR. Northeast Units 3 and 4 fire low-sulfur

subbituminous coal. Based on the fuel characteristics, and assuming 1% SO2 to SO3 conversion 

in the boiler, potential uncontrolled H2SO4 emissions from Northeast Units 3 and 4 will only be 

approximately 5ppm. This emission rate does not take into account inherent acid gas removal 

associated with alkalinity in the subbiuminous coal fly ash. Based on engineering judgment, it is 

unlikely that a WESP control system would be needed to mitigate visible sulfuric acid mist 

emissions from Northeast Units 3 and 4, even if WFGD control was installed. WESPs have been 

proposed to control condensable particulate emissions from boilers firing a high-sulfur 

bituminous coal and equipped with SCR and wet FGD. This combination of coal and control 

equipment results in relatively high concentrations of sulfuric acid mist in the flue gas. WESP 

control systems have not been proposed on units firing subbituminous coals, and WESP would 

have no practical application on a subbituminous-fired units. Therefore, the combination of 

WFGD+WESP will not be evaluated further in this BART determination.

Dry Flue Gas Desulfurization

Another scrubbing system that has been designed to remove SO2 from coal-fired combustion 

gases is dry scrubbing. Dry scrubbing involves the introduction of dry or hydrated lime slurry 

into a reaction tower where it reacts with SO2 in the flue gas to form calcium sulfite solids 

Unlike wet FGD systems that produce a slurry byproduct that is collected separately from the fly 

ash, dry FGD systems produce a dry byproduct that must be removed with the fly ash in the 

particulate control equipment. Therefore, dry FGD systems must be located upstream of the 

particulate control device to remove the reaction products and excess reactant material.

Spray Dryer Absorber

Spray dryer absorber (SDA) systems have been used in large coal-fired utility applications. SDA 

systems have demonstrated the ability to effectively reduce uncontrolled SO2 emissions from

coal units. The typical spray dryer absorber uses a slurry of lime and water injected into the 

tower to remove SO2 from the combustion gases. The towers must be designed to provide 

adequate contact and residence time between the exhaust gas and the slurry to produce a 

relatively dry by-product. SDA control systems are a technically feasible and commercially 

available retrofit technology for Northeast Units 3 and 4. Based on the fuel characteristics and 

allowing a reasonable margin to account for normal operating conditions (e.g., load changes, 

changes in fuel characteristics, reactant purity, atomizer change outs, and minor equipment 

upsets) it is concluded that dry FGD designed as SDA could achieve a controlled SO2 emission 

rate of 0.15 lb/mmBtu (30-day average) on an on-going long-term basis.
PSO Northeastern Power Plant BART Review January 19, 2010

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Circulating Dry Scrubber

A third type of dry scrubbing system is the circulating dry scrubber (CDS). A CDS system uses a 

circulating fluidized bed of dry hydrated lime reagent to remove SO2. The dry by-product 

produced by this system is similar to the spray dry absorber by-product, and is routed with the 

flue gas to the particulate removal system. Operating experience on smaller coal boilers in the 

U.S. has shown high lime consumption rates, and significant fluctuations in lime utilization 

based on inlet SO2 loading. Furthermore, CDS systems result in high particulate loading to the 

unit’s particulate control device. Based on the limited application of CDS dry scrubbing systems 

on large boilers, it is likely that AEP-PSO would be required to conduct extensive design 

engineering to scale up the technology for boilers the size of Northeast Units 3 and 4, and that 

AEP-PSO would incur significant time and resource penalties evaluating the technical feasibility 

and long-term effectiveness of the control system. Because of these limitations, CDS dry 

scrubbing systems are not currently commercially available as a retrofit control technology for 

Northeast Units 3 and 4, and will not be evaluated further in this BART determination.

EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (SO2)

Table 10: Technically Feasible SO2 Control Technologies- Northeastern Station

Control Technology

Northeastern Unit 3 Northeastern Unit 4

Approximate SO2

Emission Rate

(lb/mmBtu)

Approximate SO2

Emission Rate

(lb/mmBtu)

Wet FGD 0.063 0.063

Dry FGD- Spray Dryer Absorber 0.153 0.153

Lower Sulfur Coal 0.55 0.55

Baseline 0.9 0.9

Annual Average Baseline 0.91 0.91

EVALUATE IMPACTS AND DOCUMENT RESULTS (SO2)

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

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

provided in the EPA Air Pollution Cost Control Manual. Sixth Edition” EPA-452/B-02-001, 

January 2002. Cost estimates include the equipment, material, labor, and all other direct costs 

needed to retrofit Northeast Units 3 and 4 with the control technologies. 

Direct O&M costs are those costs that tend to be proportional to the quantity of exhaust gas 

processed by the control system. These may include costs for catalysts, utilities (steam, 

electricity, and water), waste treatment and disposal, maintenance materials, replacement parts, 

and operating and maintenance labor. Of these direct O&M costs, costs for catalysts, utilities, 

waste treatment, and disposal are variable. Emission allowance costs associated with certain 

regulatory programs may also be represented as a variable O&M costs, but have not been 

included in this cost estimate. Indirect or “Fixed" annual costs are those whose values are totally 

independent of the exhaust flow rate and, in fact, would be incurred even if the control system 

were shut down. They include such categories as administrative charges, property taxes, and 

insurance, and include the capital recovery cost. The direct and indirect annual costs are offset 

by recovery credits, taken for materials or energy recovered by the control system, which may be 
PSO Northeastern Power Plant BART Review January 19, 2010

14

sold, recycled to the process, or reused elsewhere at the site. 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 85%.

AEP-PSO submitted initial cost estimates in 2008 that relied upon a baseline emission rate 

representative of the average annual emission (0.9 lb/mmBtu) at an annual average firing rate of 

4775 mmBtu/hr. The modeling demonstration relied on maximum 24-hr heat input numbers that 

were somewhat larger than the average. However the actual annual firing rate is much lower, 

and costs were reevaluated in order to be consistent with the methodology employed by EPA. 

Following the methodology published in the EPA advanced notice of proposed rulemaking for 

the Four Corners Power Plant and the Navajo Generating Station, cost effectiveness calculations 

were revised to reflect average annual emissions from 2004-2006.

The engineering estimates and possible vendor quotations AEP-PSO relied on to develop base 

$/kW Total Capital Investment assumptions were not provided to substantiate the capital costs 

for installation. In reviewing BART submittals to other states, AEP-PSO’s estimated costs were 

found to be somewhat higher than those reported for similar projects. However, the evaluations 

in neighboring states are known to underestimate present day costs and the analysis submitted by 

AEP-PSO is in line with the more detailed and recent analyses submitted by OG&E.

Operation and maintenance cost estimates for AEP-PSO cost calculations rely on assumptions 

provided in the AEP-PSO submittal. While the assumptions for administrative costs were 

overstated, AEP-PSO failed to incorporate labor, maintenance, and increased water costs, which 

offset the overestimated numbers. Estimates are compared to operating costs documented in the 

June 2007 report by J. Edward Cichanowicz for the Utility Air Regulatory Group, “Current 

Capital Cost and Cost-Effectiveness of Power Plant Emissions Control Technologies. The 

Cichanowicz report reproduces a Sargent and Lundy graphic, which lists a cost range in $/kW of 

15 to 38 for O&M costs. AEP-PSO estimates are approximately $33/kW. AEP-PSO’s estimates 

are again comparable to the DEQ approved more recent and detailed cost estimates for OG&E.

Table 11: Economic Cost for Unit 3 and 4 - Dry FGD- Spray Dryer Absorber

Cost DFGD/SDA

Total Capital Investment ($) $546,700,000

Total Capital Investment ($/kW) $582

Capital Recovery Cost ($/Yr) $55,682,603

Annual O&M Costs ($/Yr) $31,070,200

Total Annual Cost ($) $86,752,803

Table 12: Environmental Costs for Unit 3 and 4

Baseline Lower S Coal DFGD/SDA

SO2 Emission Rate (lb/mmBtu) 0.91 0.55 0.153

Annual SO2 Emission (TPY)131,779 19,555 5,440

Annual SO2 Reduction (TPY) -- 12,224 26,339

Total Annual Cost ($) $86,752,803

Cost per Ton of Reduction $3,294
PSO Northeastern Power Plant BART Review January 19, 2010

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Incremental Cost per Ton $6,146

(1) Baseline annual emissions were averaged based on annual emissions from 2004- 2006. Projected annual 

emissions were calculated based on the controlled SO2 emissions rate, full load heat input of 4,775 mmBtu/hr, and 

assuming an 85% capacity factor.

Table 13: Environmental Costs for Units 3 and 4- Wet FGD

Cost

AEP-PSO Cost Estimates

Units 3 and 4

Total Capital Investment ($) $703,680,000

Total Capital Investment ($/kW) $749

Capital Recovery Cost ($/Yr) $71,671,362

Annual O&M Costs ($/Yr) $35,419,400

Total Annual Cost ($) $107,090,762

Baseline SO2 Emission Rate (lb/mmBtu) 0.9

Control SO2 Emission Rate (lb/mmBtu) 0.063

Baseline Annual Emissions (TPY)1

31,779

Controlled Annual SO2 Emission (TPY)1

2,240

Annual SO2 Reduction (TPY) 29,539

Cost per Ton of Reduction ($/Ton) $3,625

Incremental Annual Cost ($/Ton) $6,356

(1) Baseline annual emissions were calculated based on annual average emissions from 2004-2006.. Projected annual 

emissions were calculated based on the controlled SO2 emissions rate, full load heat input of 4,775 mmBtu/hr, and 

assuming an 85% capacity factor.

C. PM10

IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES (PM10)

There are two generally recognized PM control devices that are used to control PM emission 

from PC boilers: ESPs and fabric filters (or baghouses). Northeast Units 3 and 4 are currently 

equipped with ESP control systems.

Table 14: Summary of Technically Feasible 

Main Boiler PM10 Control Technologies

Control Technology PM10 Emissions

(lb/mmBtu)

% Reduction

(from base case)

Fabric Filter Baghouse and ESP 0.0085/0.0079 99.9

ESP - Existing 0.025/0.040 99.7

EVALUATE IMPACTS AND DOCUMENT RESULTS (PM10)

Costs for Fabric Filter Baghouses were provided separate from the cost estimates provided by 

AEP-PSO for Dry FGD. While DEQ capital cost estimates rely on primarily fully loaded Wet 

FGD installations, the greater expense attributed to wet versus dry systems can account for the 

Fabric Filter Baghouse equipment cost without a direct line item cost. 
PSO Northeastern Power Plant BART Review January 19, 2010

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For fabric filter baghouse controls AEP-PSO estimated a total capital investment of $71,050,000 

for Units 3 and 4. The capital recovery cost was estimated to be $6,671,463 per year over 20 

years at 7% interest. The total annual cost was estimated to be $12,773592. Addition of the 

fabric filters was anticipated to result in an incremental cost of $12,565/ton over existing ESP 

controls. The applicant did not evaluate replacement of the ESP but instead the addition of 

fabric filters.

D. 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 Northeastern Power Plant 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 Northeastern Power Plant 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 Northeastern Power Plant, as shown in Figure 1 below. 

Only those Class I areas most likely to be impacted by the Northeastern Power Plant 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. 
PSO Northeastern Power Plant BART Review January 19, 2010

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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 Northeastern Power Plant, 

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, January 2008)

CALPUFF System

Predicted visibility impacts from the Northeastern Power Plant 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 all modeled areas are located more than 50 km from the sources in question, 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 
PSO Northeastern Power Plant BART Review January 19, 2010

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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 15: Key Programs in CALPUFF System

Program Version Level

CALMET 5.53a 040716

CALPUFF 5.8 070623

CALPOST 5.6394 070622

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 16: 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 20 km
PSO Northeastern Power Plant BART Review January 19, 2010

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Variable Description Value

(surface layer, 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.

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
PSO Northeastern Power Plant BART Review January 19, 2010

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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. Maximum 24-hour heat inputs and emission rates for the 

baseline emission calculations were established based on data from the years 2002 to 2005. 

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

tables with data for the various control options. No attempt was made by the applicant to 

estimate the increase in sulfate emissions that would result from operations of SCR, and as a 

result the visibility improvement for those scenarios may be overestimated by some 

undetermined amount.

Table 17: Source Parameters

Parameter

Baseline1

Natural Gas-Fired

Unit 2

Coal-Fired

Unit 3

Coal-Fired

Unit 4

Heat Input (mmBtu/hr) 4,767 5,812 5,594

Stack Height (m) 56 183 183

Stack Diameter (m) 5.49 8.23 8.23

Stack Temperature (K)2394 424 415

Exit Velocity (m/s)216.29 18.97 17.46

Baseline SO2 Emissions (lb/mmBtu) 0.0006 1.05 1.06

Dry FGD SO2 Emissions (lb/mmBtu) -- 0.15 0.15

Wet FGD SO2 Emissions (lb/mmBtu) -- 0.063 0.063

Baseline NOX Emissions (lb/mmBtu) 0.71 0.536 0.491

LNB/OFA NOX Emissions (lb/mmBtu) 0.28 0.15 0.15

LNB/OFA + SCR NOX Emissions 

(lb/mmBtu)

0.05 0.054 0.049

ESP (Baseline) PM10 Emissions 

(lb/mmBtu)

0.007 0.025 0.040

FF PM10 Emissions (lb/mmBtu) -- 0.009 0.008

1Baseline 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.
PSO Northeastern Power Plant BART Review January 19, 2010

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2

Temperature and Velocity were decreased for DFGD and WFGD evaluations. For DFGD, stack temperature was 

modeled at 349 K and velocity decreased to 15.6 m/s for Unit 3 and 14.67 m/s for Unit 4. For WFGD, stack temperature 

decreased to 332K and velocity decreased to 14.86 and 13.96 for Units 3 and 4 respectively.

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 18: 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 19: CALPUFF Visibility Modeling Results for Northeast Units 3 and 4- NOX

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 0.468 0.402 0.775 0.548

Caney Creek 0.994 0.714 1.029 0.912

Upper Buffalo 0.883 0.42 0.442 0.582

Hercules Glade 0.644 0.345 0.296 0.428

Scenario 1- Combustion Control- LNB/OFA

Wichita Mountains 0.136 0.116 0.223 0.158

Caney Creek 0.301 0.213 0.293 0.269
PSO Northeastern Power Plant BART Review January 19, 2010

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Upper Buffalo 0.259 0.124 0.131 0.171

Hercules Glade 0.191 0.102 0.086 0.126

Modeling for SCR controls resulted in an approximate 66% reduction in visibility impairment 

from scenario one.

Table 20: CALPUFF Visibility Modeling Results for Northeast Units 3 and 4- SO2

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 1.123 0.819 1.836 1.260

Caney Creek 1.322 1.186 1.245 1.251

Upper Buffalo 0.993 0.683 1.227 0.968

Hercules Glade 1.071 0.626 1.197 0.965

Scenario 1- Dry FGD

Wichita Mountains 0.164 0.129 0.282 0.192

Caney Creek 0.207 0.199 0.190 0.199

Upper Buffalo 0.141 0.098 0.138 0.126

Hercules Glade 0.138 0.088 0.159 0.128

Wet FGD reduced visibility impairment by a further 50% over Dry FGD. This decreased 

degradation improved visibility by less 0.12 dv on the 98th percentile days and is considered an 

insignificant change.

Modeling for existing ESP controls with proposed fabric filters indicate the visibility impairment 

from direct PM emissions will be improved with the fabric filters but both technologies control 

visibility impairment well below 0.5dv at all Class I areas.

Table 21: CALPUFF Visibility Modeling Results for Northeast Units 2 NOX

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 0.366 0.247 0.489 0.367

Caney Creek 0.809 0.66 0.569 0.679

Upper Buffalo 0.541 0.246 0.269 0.352

Hercules Glade 0.495 0.275 0.266 0.345

Scenario 1- Combustion Control- LNB/OFA

Wichita Mountains 0.144 0.099 0.19 0.144

Caney Creek 0.332 0.267 0.231 0.277

Upper Buffalo 0.218 0.099 0.108 0.142
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Hercules Glade 0.195 0.111 0.108 0.138

E. 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 

three units at the Northeastern Power Plant.

NOX

New LNB with OFA is determined to be BART for NOX control for Units 2, 3 and 4 based, in 

part, on the following conclusions:

1. Installation of new LNB with OFA was cost effective at an average cost effectiveness of 

$303-313.

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

lb/mmBtu for Units 3 and 4 and 0.28 lb/mmBtu on Unit 2 are justified meet the 

presumptive limits prescribed by EPA. 

LNB with OFA and SCR was not determined to be BART for NOX control for Units 2, 3 and 4

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 Units 3 and 4 are on 

average $290,000,000. Based on projected emissions, SCR could reduce overall NOX

emissions from Northeast Units 3 and 4 by approximately 4,120 TPY beyond combustion 

controls; however, the incremental cost associated with this reduction is approximately 

$11,013/ton. SCR controls on Unit 2 would result in an incremental cost of $13,989.

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. The cumulative visibility improvement for SCR, as compared to LNB/OFA across 

Wichita Mountains and Caney Creek (based on the 98th percentile modeled results) was 

0.10 and 0.18 Δdv respectively.

SO2

Continued use of low sulfur coal is determined to be BART for SO2 control for Units 3 and 4 

based on the capital cost of add-on controls, the cost effectiveness both in $/ton and $/dv of addon controls, and the long term viability of coal with respect to other environmental programs, 

and national commitments.
PSO Northeastern Power Plant BART Review January 19, 2010

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Installation of DFGD is not cost effective. OG&E’s revised cost estimates are based on vendor 

quotes and go well beyond the default methodology recommended by EPA guidance. The cost 

estimates are credible, detailed, and specific for the Muskogee and Sooner facilities. Cost 

estimates for the AEP-PSO Northeastern facility continue to be lower on a capital and annualized 

basis, but are comparable to the costs documented by OG&E. The substantiated AEP-PSO

estimate for both boilers at $546,700,000 is $209,240,000 greater than the high end costs 

assumed by DEQ in the Draft SIP. 

These costs put the project well above costs reported for other BART determinations. The 

federal land managers have informally maintained a spreadsheet of BART costs and 

determinations for coal-fired facilities. This spreadsheet indicates that the highest reported cost 

for control was for the Boardman facility in Oregon at a projected cost of $247,300,000. While 

there is some uncertainty on whether this cost will ultimately be found to be cost effective, it is 

much lower than the cost of controlling a single boiler at the Muskogee facility ($273,350,000). 

Most assessments were based on costs of less than $150,000,000 and related cost effectiveness 

numbers of $3,053/ton removed for Boardman to an average of less than $2,000/ton for the other 

determinations tracked by the FLMs.

Table 20 provides a summary of the baseline SO2 emission rates included in several BART 

evaluations.

Table 22: Comparison of Baseline SO2 Emissions at Several BART Units

Station Baseline SO2 Emission Rate 

(lb/mmBtu)

Baseline SO2 Emissions 

(TPY)

Muskogee Unit 4 0.507 9,113

Muskogee Unit 5 0.514 9,006

Sooner Unit 1 0.509 9,394

Sooner Unit 2 0.516 8,570

NPPD Gerald Gentleman Unit 1 0.749 24,254

NPPD Gerald Gentleman Unit 2 0.749 25,531

White Bluff Unit 1 0.915 31,806

White Bluff Unit 2 0.854 32,510

Boardman unit 1 0.614 14,902

Northeastern Unit 3 0.900 16,000

Northeastern Unit 4 0.900 16,000

Naughton Unit 1 1.180 8,624

Naughton Unit 2 1.180 11,187

OPPD Nebraska City Unit 1 0.815 24,191

Assuming total annual costs and projected emissions are similar and thereby setting aside the 

issues related to pre-2008 cost estimates and the ability to compare them to December 2009 

estimates, cost effectiveness will be a function of the baseline emissions. This holds true for 

units firing subbituminous coals with baseline SO2 emissions rates in the range of 0.5 lb/mmBtu 

to approximately 2.0 lb/mmBtu, because removal efficiencies achievable with DFGD control 

will vary based on inlet SO2 loading. In general, DFGD control systems are capable of achieving 

higher removal efficiencies on units with higher inlet SO2 loading. DFGD control systems will 
PSO Northeastern Power Plant BART Review January 19, 2010

26

be more cost effective on units with higher baseline SO2 emissions because the control systems 

will be capable of achieving higher removal efficiencies and remove more tons of SO2 per year 

for similar costs. Conversely, DFGD will be less cost effective, on a $/ton basis, on units with 

lower SO2 baseline emissions. On the basis of baseline emissions alone, with all other factors 

being equal, the cost effectiveness of the AEP-PSO units after adopting and annual average 

emission rate of 0.55 lb/mmBtu would be about 55 to 185% higher than the other units listed, 

i.e., less cost effective. 

The average cost effectiveness at Northeastern for DFGD is $3,294 per ton of SO2 removed from 

the present baseline and $6,146 per ton from the lower sulfur coal baseline for each unit over a 

twenty year operational life. The cost of add-on controls above and beyond lower sulfur coal at 

the Northeastern facility is well above the average cost effectiveness reported for similar BART 

projects, well above costs associated with BACT determinations for SO2, and well above the cost 

of control originally contemplated in the Regional Haze Rule.

From the FLM BART tracking spreadsheet, the average cost effectiveness in $/dv was 

$5,700,000/dv. The addition of DFGD at the Northeastern Facility was anticipated to reduce 

impairment by 3.97 dv. Importantly, the cost effectiveness of that improvement is calculated to 

be $21,829,547/dv. 

A majority of the Class I areas are located in the western part of the U.S. Simply due to the 

number of Class I areas in the west, it is likely that a BART applicable unit located in the 

western U.S. will be closer to a Class I area, and that emissions from the unit will affect visibility 

at more Class I areas. For example, the Boardman Generating Station located in the north central 

region approximately 150 miles east of Portland, is located within 300 km of 14 Class I areas. 

By comparison the Northeastern station is located with 300 km of 3 Class I areas. Using the sum 

of modeled visibility improvements at all 14 Class I areas, cost effectiveness of the DFGD 

control system would be $3,690,510/dv or 5.9 times more cost effective than DFGD controls at 

the Northeastern facility. The federal land managers have indicated that costs effectiveness 

numbers of less than $10,000,000/dv should be considered cost effective. While this does not 

prohibit a determination of cost effectiveness at numbers greater than $10,000,000/dv, it does 

imply that numbers greater than that should receive greater consideration. 

An investment of this magnitude to install DFGD on an existing coal-fired power plant 

effectively guarantees the continued use of coal as the primary fuel source for energy generation 

in this facility and arguably the state for the next 20 years and beyond. Therefore, a 

determination in support of DFGD ignores the Obama Administration’s stated agenda to control 

carbon dioxide and other green house gases by restricting the alternatives left open to AEP-PSO

and hence the ratepayers of Oklahoma. Substantial uncertainty currently exists about the nature 

and costs of future federal carbon controls on power plants, including the level of stringency, 

timing, emissions allowance allocation and prices, and whether and to what degree emissions 

“offsets” are allowed. Further, new federal MACT mercury control requirements may be 

imposed on the AEP-PSO facility that would be more stringent than the scrubber can deliver. 

Fortunately, other technology options now exist that would likely achieve greater mercury 

reductions at lower cost than the scrubber. If EPA determines that MACT requires greater 

reductions than those achieved through DFGD, then ratepayers would be at risk to pay for 
PSO Northeastern Power Plant BART Review January 19, 2010

27

additional required mercury control technology.

The cost for DFGD is too high, the benefit too low and these costs, if borne, further extend the 

life expectancy of coal as the primary fuel in the AEP-PSO facility for at least 20 years and 

beyond. BART is the use of low sulfur coal (0.55 lb/mmBtu- annual average)..

Wet FGD was not determined to be BART for SO2 control for Units 3 and 4 based, in part, on 

the following conclusions:

1. The cost of compliance for installing WFGD on each unit is higher than the cost for Dry 

FGD. Based on projected emissions, WFGD could reduce overall SO2 emissions from 

Northeast Units 3 and 4 by approximately 3,200 TPY beyond dry scrubbers; however, the 

incremental cost associated with this reduction is approximately $6,356/ton without 

appreciable visibility improvement.

2. SO3 remaining in the flue gas will react with moisture in the wet FGD to generate sulfuric 

acid mist. Sulfuric acid is classified as a condensable particulate. Condensable 

particulates from the wet FGD system can be captured using additional emission controls 

(e.g., WESP). However, the effectiveness of a WESP system on a subbituminous fired 

unit has not been demonstrated and the additional cost of the WESP system significantly 

increases the cost of SO2 controls. 

3. Wet FGD systems must be located downstream of the unit’s particulate control device; 

therefore, dissolved solids from the wet FGD system will be emitted with the wet FGD 

plume. Wet FGD control systems also generate lower stack temperatures that can reduce 

plume rise and result in a visible moisture plume.

4. Wet FGD systems use more reactant (e.g., limestone) than do dry systems, therefore the 

limestone handling system and storage piles will generate more fugitive dust emissions.

5. Wet FGD systems require significantly more water than the dry systems and generate a 

wastewater stream that must be treated and discharged. Wet FGD wastewater treatment 

systems typically require calcium sulfate/sulfite desaturation, heavy metals precipitation, 

coagulation/precipitation, and sludge dewatering. Treated wastewater is typically 

discharged to surface water pursuant to an NPDES discharge permit, and solids are 

typically disposed of in a landfill. Dry FGD control systems are designed to evaporate 

water within the reaction vessel, and therefore do not generate a wastewater stream. 

PM10

The existing ESP control is determined to be BART for PM10 controls for Units 3 and 4 based on 

the determination of low sulfur coal and the high cost of fabric filters relative to the low actual 

emissions of PM10 from the facility.

Table 23: Unit-by-unit BART determinations

Control Unit 2 Unit 3 Unit 4

NOX Control LNB with OFA LNB with OFA New LNB with OFA

Emission Rate 

(lb/mmBtu)

0.28 lb/mmBtu

(30-day rolling 

average)

0.15 lb/mmBtu

(30-day rolling 

average)

0.15 lb/mmBtu

(30-day rolling 

average)

Emission Rate lb/hr 1331 lb/hr

(30-day rolling 

716 lb/hr

(30-day rolling 

716 lb/hr

(30-day rolling 
PSO Northeastern Power Plant BART Review January 19, 2010

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average) average) average)

Emission Rate TPY 5,830 TPY

(12-month rolling)

6,274 TPY

(12-month rolling)

SO2 Control -- Low Sulfur Coal Low Sulfur Coal

Emission Rate

(lb/mmBtu)

-- 0.65 lb/mmBtu

(30-day rolling 

average)

0.65 lb/mmBtu

(30-day rolling 

average)

Emission Rate lb/hr -- 3,104 lb/hr

(30-day rolling 

average)

3,104 lb/hr

(30-day rolling 

average)

Emission Rate 

(lb/mmBtu)

-- 0.55 lb/mmBtu

(12-month rolling 

average)

0.55 lb/mmBtu

(12-month rolling 

average)

Emission Rate (TPY) 23,006 TPY

PM10 Control1-- ESP ESP

Emission Rate 

(lb/mmBtu)

-- 0.1 lb/mmBtu

(3-hour rolling 

average)

0.1 lb/mmBtu

(3-hour rolling 

average)

Emission Rate lb/hr -- 478 lb/hr

(3-hour rolling 

average)

478 lb/hr

(3-hour rolling 

average)

Emission Rate TPY -- 4,183 TPY

(12-month rolling average)

1Current emissions limits for ESPs are based on minimum NSPS requirements for front half 

catch and do not reflect the true emissions. As part of the permitting process, AEP-PSO will be 

required to propose emission limits for both front and back half, which is reflective of the control 

technology and consistent with the performance tests.

F. CONTINGENT BART DETERMINATION

In the event that EPA disapproves the BART Determination referenced above in regard to the 

DEQ determination that DFGD with SDA is not cost-effective for SO2 control, the low-sulfur 

coal requirement in the BART determination for SO2 and the related ESP requirement for PM 

referenced above shall be replaced with a requirement that Northeastern Units 3 and 4 install 

DFGD with SDA for SO2 control or meet the corresponding SO2 emission limits listed below by 

December 31, 2018 or comply with the approved alternative described in section G (Greater 

Reasonable Progress Alternative).

Table 24: Unit-by-unit Contingent BART determinations

Control Unit 3 Unit 4

SO2 Control DFGD w/SDA DFGD w/SDA

Emission Rate (lb/mmBtu) 0.1 lb/mmBtu

(30-day rolling average)

0.1 lb/mmBtu

(30-day rolling average)

Emission Rate lb/hr 478 lb/hr

(30-day rolling average)

478 lb/hr

(30-day rolling average)

Emission Rate TPY 2,091 TPY 2,091 TPY
PSO Northeastern Power Plant BART Review January 19, 2010

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The “contingent” BART as defined here and in conjunction with the greater reasonable progress 

alternative recognizes the long term importance of achieving reductions in SO2 while addressing 

the need for operational flexibility in response to the eventualities of a federal carbon trading 

program and mercury MACT in the nearer term. It must be understood that DEQ has determined 

that DFGD is not cost effective. However, if EPA chooses to ignore that element of the BART 

determination, DEQ does agree that DFGD remains a technically feasible control option for SO2

reductions. 

Switching from coal to natural gas, while physically possible constitutes a significant 

modification to a facility process not contemplated by the regional haze rule. However, 

exploring some combination of both options, while allowing the uncertainty surrounding other 

federal environmental programs to settle, is a more equitable alternative for the ratepayers in 

Oklahoma than requiring an overly costly control merely to achieve limited visibility 

improvement while simultaneously solidifying the use of a higher emitting technology from now 

into the foreseeable future.

G. GREATER REASONABLE PROGRESS ALTERNATIVE DETERMINATION

In lieu of installing and operating BART for SO2 Northeastern Units 3 and 4, AEP-PSO may 

elect to implement a fuel switching alternative. The greater reasonable progress alternative 

requires AEP-PSO to achieve a combined annual SO2 emissions limit (identified in table 25) by 

installing and operating DFGD with SDA on one of the two boilers and being at or below the 

SO2 emission that would result from switching the remaining boiler to natural gas. Under this 

alternative AEP-PSO shall install the controls (i.e., DFGD with SDA or achieve equivalent 

emissions) by December 31, 2026. By adopting these emission limits, DEQ and AEP-PSO

expect the cumulative SO2 emissions from Northeastern Units 1 and 2 to be approximately 43% 

less than would be achieved through the installation and operation of DFGD with SDA at both 

units.

Table 25: SO2 Emissions with Greater Reasonable Progress

Northeastern

Parameter Unit 3 and Unit 4

BART (Low Sulfur Coal) 23,006 TPY

Contingent BART (DFGD) 4,182 TPY

GRP (DFGD/Natural Gas) 2,400 TPY

Under no circumstance will the Greater Reasonable Progress Plan result in less visibility 

improvement than would be achieved either through the DEQ determined BART or the 

“contingent” BART. By allowing the installation of SO2 controls to be delayed, current 

regulatory hurdles to long term natural gas contracts can be addressed and the best interests of 

the ratepayers and visitors to our Class I areas can be preserved for the long term 2064 goal of 

natural visibility.

V. CONSTRUCTION PERMIT

Prevention of Significant Deterioration (PSD) 
PSO Northeastern Power Plant BART Review January 19, 2010

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Northeastern Power Plant 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 Northeastern Station. The permit 

application should contain PM10 and PM2.5 emission estimates for filterable and condensable 

emissions. 

VI. OPERATING PERMIT

The Northeastern Power Plant 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. The boilers in EUG 2, 3 and 4 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

2 2 Babcock and Wilcox UP-60 4754 1970

3 3 Combustion Engineering #4974 SCRR 4775 1974

4 4 Combustion Engineering #7174 SCRR 4775 1974

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. New Low-NOX Burners,

ii. Overfire Air.

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

ESP) and establish procedures to ensure the controls are properly operated and 

maintained.
PSO Northeastern Power Plant BART Review January 19, 2010

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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 Averaging Period

2 2 0.28 lb/mmBtu 30-day rolling

EU 

ID#

Point 

ID#

NOX

Emission Limit

SO2

Emission Limit

Averaging 

Period

3 3 0.15 lb/mmBtu 0.65 lb/mmBtu 30-day rolling

4 4 0.15 lb/mmBtu 0.65 lb/mmBtu 30-day rolling

EU 

ID#

Point 

ID#

SO2

Emission Limit

SO2

Emission Limit

Averaging 

Period

3 3 0.55 lb/mmBtu 23,006 TPY annual average

4 4 0.55 lb/mmBtu annual average

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

Da.

h. Within 60 days of achieving maximum power output from each boiler, after 

modification of the boilers, 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 SO2, NOX, PM10, PM2.5, 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.