Oklahoma Department of Environmental Quality

Air Quality Division

BART Application Analysis January 15, 2010

COMPANY: Oklahoma Gas and Electric 

FACILITY: Muskogee Generating Station

FACILITY LOCATION: Muskogee, Muskogee County, Oklahoma

TYPE OF OPERATION: (2) 572 MW 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).

Muskogee Units 4 and 5 are fossil-fuel fired boilers with heat inputs greater than 250-mmBtu/hr. 

Both 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, both units have the potential to emit more 

than 250 tons per year of NOX, SO2, and PM10, visibility impairing pollutants. Therefore, 

Muskogee Units 4 and 5 meet the definition of a BART-eligible source.

BART is required for any BART-eligible source that emits any air pollutant which may 

reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I Area. 
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DEQ has determined that an individual source will be considered to “contribute to visibility 

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

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

modeling conducted by OG&E determined that the maximum predicted visibility impacts from 

Muskogee Units 4 and 5 exceeded the 0.5 Δ-dv threshold at the Wichita Mountains, Caney Creek 

Upper Buffalo, and Hercules Glade Class I Areas. Therefore, Muskogee Units 4 and 5 were 

determined to be BART applicable sources, subject to the BART determination requirements.

III. DESCRIPTION OF BART SOURCES

Baseline emissions from Muskogee Units 4 and 5 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: Muskogee Generating Station- Plant Operating Parameters for BART Evaluation

Parameter Muskogee Unit 4 Muskogee Unit 5

Plant Configuration Pulverized Coal-Fired Boiler Pulverized Coal-Fired Boiler

Firing Configuration Tangentially-fired Tangentially-fired

Gross Output (nominal) 572 MW 572 MW

Maximum Input to 

Boiler

5,480 mmBtu/hr 5,480 mmBtu/hr

2004-2006 Average 

Heat Input to Boiler

4,594 mmBtu/hr 4,739 mmBtu/hr

Primary Fuel Subbituminous coal Subbituminous coal

Existing NOX Controls Combustion controls Combustion controls

Existing PM10 Controls Electrostatic precipitator Electrostatic precipitator

Existing SO2 Controls Low-sulfur coal Low-sulfur coal

Maximum 24-hour Emissions 

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

NOX 2,710 0.495 2,863 0.522

SO2 4,384 0.800 4,657 0.850

PM10 101 0.018 134 0.024

Baseline Emissions (2004- 2006)

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

NOX 1,342 0.292 1,545 0.326

SO2 2,329 0.507 2,436 0.514
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IV. BEST AVAILABLE RETROFIT TECHNOLOGY (BART)

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

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

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

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

described in Appendix Y includes the following steps: 

Step 1. Identify All Available Retrofit Control Technologies.

Step 2. Eliminate Technically Infeasible Options.

Step 3. Evaluate Control Effectiveness of Remaining Control Technologies.

Step 4. Evaluate Impacts and Document the Results.

Step 5. Evaluate Visibility Impacts.

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 Muskogee Units 4 

and 5 (tangentially fired boilers firing subbituminous coal) is 0.15 lb/mmBtu.

Table 2: BART Controls and Limits

Unit NOX BART Emission Limit BART Technology

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

Muskogee Unit 5 0.15 lb/mmBtu (30-day average) Combustion controls including LNB/OFA 

Unit SO2 BART Emission Limit BART Technology

Muskogee Unit 4 0.65 lb/mmBtu (30-day average) Low Sulfur Coal 0.55 lb/mmBtu (annual average)

Muskogee Unit 5 0.65 lb/mmBtu (30-day average) Low Sulfur Coal 0.55 lb/mmBtu (annual average)

Units 4 and 5 18,096 TPY Low Sulfur Coal

Unit PM10 BART Emission Limit BART Technology

Muskogee Unit 4 0.1 lb/mmBtu (3-hour average) Electrostatic Precipitator

Muskogee Unit 5 0.1 lb/mmBtu (3-hour average) Electrostatic Precipitator
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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 Muskogee Units 4 

and 5 are listed in Table 3.

Table 3: List of Potential Control Options

Control Technology

Combustion Controls

Low NOX Burners and Overfire Air (LNB/OFA)

Flue Gas Recirculation (FGR)

Post Combustion Controls

Selective Noncatalytic Reduction (SNCR)

Selective Catalytic Reduction (SCR)

Innovative Control Technologies

Rotating Overfire Air (ROFA)

ROFA + SNCR (Rotamix)

Pahlman Multi-Pollutant Control Process

Wet NOX Scrubbing

ELIMINATE TECHICALLY INFEASIBLE OPTIONS (NOX)

Combustion Controls:

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. Muskogee Units 4 and 5 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 tangentiallyfired 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.

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. 
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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 

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

Units 4 and 5, and will not be considered further in the BART determination.

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 Muskogee 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 Muskogee 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 Muskogee, has not been demonstrated in 

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

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

temperatures, could actually result in additional NOX formation. SNCR is not a technically 

feasible retrofit control for the Muskogee Boilers.
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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.

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 0.07 lb/mmBtu (30-day rolling average) on Muskogee Units 4 and 5.

Innovative NOX Control Technologies:

Rotating Opposed Fire Air and Rotomix

Rotating opposed fired air (ROFA) is a boosted over fire air system that includes a patented

rotation process which includes asymmetrically placed air nozzles. Like other OFA systems, 

ROFA stages the primary combustion zone to burn overall rich, with excess air added higher in 

the furnace to burn out products of incomplete combustion.

ROFA and Rotamix® systems have been demonstrated on smaller coal-fired boilers but have not 

been demonstrated in practice on boilers similar in size to Muskogee Units 4 and 5. As 

discussed for OFA, over fire air control systems are a technically feasible retrofit control 

technology, and, based on engineering judgment, the ROFA design could also be applied on 

Muskogee Units 4 and 5. However, there is no technical basis to conclude that the ROFA design 

would provide additional NOX reduction beyond that achieved with other OFA designs. 

Therefore, ROFA control systems are not evaluated as a specific control system, but are included 

in the overall evaluation of combustion controls (e.g., LNB/OFA).

ROFA + SNCR (Rotamix)

The Rotamix system is a SNCR control system (i.e., ammonia injection system) coupled with the 

ROFA rotating injection nozzle design. The technical limitations discussed in the SNCR section, 

including the physical size of the boiler, inadequate NH3/NOX contact, and flue gas 

temperatures, would apply equally to the Rotamix control system. There is no technical basis to 

conclude that the Rotamix design addresses these unresolved technical difficulties. Therefore, 

like other SNCR control systems, the Rotamix system is not a technically feasible retrofit control 

for the Muskogee Boilers.

Pahlman Multi-Pollutant Control Process

The PahlmanTM Process is a patented dry-mode multi-pollutant control system. The process uses 

a sorbent composed of oxides of manganese (the PahlmaniteTM sorbent) to remove NOX and SO2

from the flue gas.
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To date, bench- and pilot-scale testing have been conducted to evaluate the technology on utilitysized boilers. The New & Emerging Environmental Technologies (NEET) Database identifies 

the development status of the Pahlman Process as full-scale development and testing. The 

process is an emerging multi-pollutant control, and there is limited information available to 

evaluate its technically feasibility and long-term effectiveness on a large natural gas-fired boiler. 

It is likely that OG&E would be required to conduct extensive design engineering and testing to 

evaluate the technical feasibility and long-term effectiveness of the control system on Muskogee 

Units 4 and 5. BART does not require applicants to experience extended time delays or resource 

penalties to allow research to be conducted on an emerging control technique. Therefore, at this 

time the Pahlman Process is not a technically feasible retrofit control for the Muskogee Boilers

Wet NOX Scrubbing Systems

Wet scrubbing systems have been used to remove NOX emissions from fluid catalytic cracking 

units (FCCUs) at petroleum refineries. An example of a wet scrubbing system is Balco 

Technologies’ LoTOxTM system. The LoTOx system is a patented process, wherein ozone is 

injected into the flue gas stream to oxidize NO and NO2 to N2O5. This highly oxidized species of 

NOX is very soluble and rapidly reacts with water to form nitric acid. The conversion of NOX to 

nitric acid occurs as the N2O5 contacts liquid sprays in the scrubber. 

Wet scrubbing systems have been installed at chemical processing plants and smaller coal-fired

boilers. The NEET Database classifies wet scrubbing systems as commercially established for 

petroleum refining and oil/natural gas production. However the technology has not been 

demonstrated on large utility boilers and it is likely that OG&E would incur substantial 

engineering and testing to evaluate the scale-up potential and long-term effectiveness of the 

system. Therefore, at this time wet NOX scrubbing systems are not technically feasible retrofit 

controls for the Muskogee Boilers

EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (NOX)

Table 4: Technically Feasible NOX Control Technologies- Muskogee Station

Control Technology

Muskogee Unit 4 Muskogee Unit 5

Approximate NOX

Emission Rate

(lb/mmBtu)

Approximate NOX

Emission Rate

(lb/mmBtu)

LNB/OFA + SCR 0.07 0.07

LNB/OFA 0.15 0.15

Baseline 0.292 0.326

EVALUATE IMPACTS AND DOCUMENT RESULTS (NOX)

OG&E 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. Major equipment costs were developed 

based on publicly available cost data and equipment costs recently developed for similar 

projects, and include the equipment, material, labor, and all other direct costs needed to retrofit 
OG&E Muskogee Generating Station BART Review January 15, 2010

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Muskogee Units 4 and 5 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), byproduct management, water consumption, 

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 a 

7% interest rate and a control life of 25 years. Annual operating costs and annual emission 

reductions were calculated assuming a capacity factor of 90%.

OG&E 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. 

Table 5: Economic Cost Per Boiler

Cost

Option 1: 

LNB/OFA

Option 2: 

LNB/OFA +SCR

Control Equipment Capital Cost ($) $14,113,700 $193,077,000

Annualized Capital Cost ($/Yr) $1,211,100 $16,568,000

Annual O&M Costs ($/Yr) $880,700 $14,227,600

Annual Cost of Control ($) $2,091,800 $30,795,600

Table 6: Environmental Costs per Boiler

Baseline

Option 1: 

LNB/OFA

Option 2: 

LNB/OFA +SCR

NOX Emission Rate (lb/mmBtu) Unit 4 0.292 0.15 0.07

Unit 5 0.326 0.15 0.07

Annual NOX Emission (TPY)1 Unit 4 5,258 2,674 1,246

Unit 5 5,709 2,628 1,227

Annual NOX Reduction (TPY) Unit 4 -- 2,587 4,012

Unit 5 -- 3,081 4,482

Annual Cost of Control Unit 4 -- $2,091,800 $30,795,600

Unit 5 -- $2,091,800 $30,795,600

Cost per Ton of Reduction Unit 4 -- $809 $7,676

Unit 5 -- $679 $6,871

Incremental Cost per ton of 

Reduction2

Unit 4 -- -- $20,143

Unit 5 -- -- $20,488

(1) Emissions for the BART analysis are based on average heat inputs of 4,594 and 4,739 mmBtu/hr for Units 4 & 5. 

Annual emissions were calculated assuming 7,829 and 7,395 hours/year per for Units 4 and 5 respectively.

(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 Muskogee Units 4 

and 5 are listed in Table 7.

Table 7: List of Potential Control Options

Control Technology

Pre-Combustion Controls

Fuel Switching

Coal Washing

Coal Processing

Post Combustion Controls

Wet Flue Gas Desulfurization

Wet Lime FGD

Wet Limestone FGD

Wet Magnesium Enhanced Lime FGD

Jet Bubbling Reactor FGD

Dual Alkali Scrubber

Wet FGD with Wet Electrostatic Precipitator

Dry Flue Gas Desulfurization

Spray Dryer Absorber

Dry Sorbent Injection

Circulating Dry Scrubber

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. Muskogee Units 4 and 5 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; therefore, fuel

switching is not considered a feasible option for this retrofit project.

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.
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Muskogee Units 4 and 5 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 Muskogee Units 4 and 5.

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 

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 pulverized coalfired 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 pulverized coal-fired boiler, using processed fuels in Muskogee Units 4 and 5

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 by-
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product 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

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.
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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 

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. Muskogee Units 4 and 5 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 Muskogee Units 4 and 5 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 Muskogee Units 4 and 5, 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 
OG&E Muskogee Generating Station BART Review January 15, 2010

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pulverized 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 Muskogee Units 4 and 5. 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 0.10 lb/mmBtu (30-day average) on an on-going long-term basis.

Dry Sorbent Injection

Dry sorbent injection involves the injection of powdered absorbent directly into the flue gas

exhaust stream. Particulates generated in the reaction are controlled in the system’s particulate 

control device. Typical SO2 control efficiencies for a dry sorbent injection system are generally 

around 50%. OG&E stated that because the control efficiency of the dry sorbent system is lower 

than the control efficiency of either the wet FGD or SDA, the system will not be evaluated 

further. As OG&E proposed only the use of low sulfur coal as BART, it is not clear why they 

did not include this technology in the full evaluation. Lacking any data to justify why this might 

be a more cost effective option than Dry FGD with SDA, this option is set aside based solely on 

lower environmental benefit.

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 pulverized 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 OG&E would be required to conduct 

extensive design engineering to scale up the technology for boilers the size of Muskogee Units 4 

and 5, and that OG&E 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 Muskogee Units 4 and 5, and will not be evaluated further in this BART 

determination.
OG&E Muskogee Generating Station BART Review January 15, 2010

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EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (SO2)

Table 8: Technically Feasible SO2 Control Technologies- Muskogee Station

Control Technology

Muskogee Unit 4 Muskogee Unit 5

Approximate SO2

Emission Rate

(lb/mmBtu)

Approximate SO2

Emission Rate

(lb/mmBtu)

Wet FGD 0.08 0.08

Dry FGD- Spray Dryer Absorber 0.10 0.10

Modeling Baseline 0.80 0.85

Annual Average Baseline 0.507 0.514

EVALUATE IMPACTS AND DOCUMENT RESULTS (SO2)

Capital Costs 

In 2008 OG&E 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. The cost-effectiveness evaluations were "study" estimates of ±30% accuracy, 

based on: (1) engineering estimates; (2) vendor quotations provided for similar projects and 

similar equipment; (2) S&L’s internal cost database; and (4) cost estimating guidelines provided 

in U.S.EPA’s, EPA Air Pollution Control Cost Manual. Cost estimates include the equipment, 

material, labor, and all other direct costs needed to retrofit Muskogee Units 4 and 5 with the 

control technologies. 

While generally following the EPA methodology, these cost estimates exploited weaknesses in 

the estimate assumptions and resulted in highly exaggerated capital and particularly annual costs. 

In response to the ODEQ draft evaluation and EPA and FLM comments, OG&E submitted 

revised cost estimates during the public meeting held for the Oklahoma draft SIP. These revised 

estimates reflect vendor quotes for the Muskogee facility. In degree of difficulty, the retrofit at 

the Muskogee facility is described as average. The re-routing of ductwork, storm sewer systems 

and other equipment relocations were taken into consideration in the conceptual cost estimate.

The new cost estimates use the following methodology:

Plant design data were used to develop datasheets to specify the dry FGD, 

baghouse, and ID booster fan operating conditions. The datasheets were issued to 

various manufacturers to obtain budgetary quotations. Cost obtained from these 

quotations were used to derive the pricing used in the capital cost estimate. 

A general arrangement (GA) drawing was developed using the information 

received in the budgetary quotations. The GA drawing was used to estimate the 

major installation quantities for the project including ductwork, structural steel, 

foundations, relocation cable, and pipelines.

A motor list was assembled and used to develop the auxiliary power system sizing 

and quantities.

Mass balances were prepared and used to size the flue gas, material handling, 

material storage, and piping systems.
OG&E Muskogee Generating Station BART Review January 15, 2010

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A schedule was developed to estimate escalation and Allowance for Funds Used 

During Construction (AFUDC) costs. It was assumed the new DFGDs would 

come on line at six month intervals with the last unit being completed at 

Muskogee near the end of 2015.

Range estimating techniques were used to identify the appropriate amount of 

contingency to obtain 95% confidence level. The contingency level was 

approximately 14%.

A design and cost basis document was prepared to document the major 

assumptions and inputs for developing the cost estimate.

Labor cost estimates were developed using the Oklahoma area wage rates, 

installation quantities, and installation rates taken from the Sargent and Lundy

database. 

The described methodology provides a conceptual capital cost estimate with accuracy in the 

range of ±20%. This methodology provides a better estimate of the capital costs associated with 

installing DFGD control systems, and a more accurate estimate of the actual costs that OG&E 

would incur to install DFGD at the Muskogee facility.

The total capital requirement (TCR) is the sum of direct costs, indirect costs, contingency, 

escalation, and AFUDC. Direct costs include equipment, material, labor, spare parts, special 

tools, consumables, and freight. Indirect costs include engineering, procurement, construction 

management, start-up, commissioning, operator training, and owner’s costs.

Escalation and AFUDC were calculated from the estimated distribution of cash flows during the 

construction period and OG&E’s before-tax weighted average cost of capital of 8.66% /year. 

The 37-day tie-in outage for each unit is assumed to be coordinated with the normal 5-week 

scheduled outage such that incremental replacement cost is negligible.

The capital recovery factor converts the TCR into equal annual costs over the depreciable life of 

the asset. These are also referred to as levelized capital charges. Property taxes and insurance 

are sometimes included with the capital charges, but are classified in the OG&E analysis as part 

of the Indirect Operating Costs to be consistent with the BART reports. The economic 

parameters used to derive the levelized capital charges are summarized in Table 9.

Table 9: Economic Parameters to Derive Levelized Capital Charges

Commercial Operation Date (Reference Year) 2015

Depreciable Life 20 years

Inflation Rate 2.5% /year

Effective Income Tax Rate- Federal and State 38.12%

Common Equity Fraction 0.557

Debt Fraction 0.443

Return on Common Equity

Nominal 10.75% /year

Real 8.05% /year

Return on Debt

Nominal 6.03% /year
OG&E Muskogee Generating Station BART Review January 15, 2010

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Real 3.44% /year

Discount Rate (after-tax cost of capital)

Nominal 7.64% /year

Real 5.43% /year

Tax Depreciation 20-year straight line

Levelized Capital Charges (real) 10.36% /year

The revised estimates based on vendor quotes results in a TCR of $634,386,800 which is 

$111,825,200 less than the CUECost derived estimates provided in 2008. However, OG&E has 

revised the capital recovery factor and reduced the number of years of expected depreciation to 

20 from 25 resulting in a levelized capital charge or capital recovery of 32,861,300 per boiler, 

which is $844,900 per boiler per year more than the 2008 estimate. Cost estimates and 

assumptions are reasonable and application of the previously relied upon capital recovery factor 

does not significantly change the cost per ton of control or the conclusion of this review.

Operating Costs

Annual operating costs for the DFGD system consist of variable operating and maintenance 

(O&M) costs, fixed O&M costs, and indirect operating costs. 

Variable O&M

Variable O&M costs are items that generally vary in proportion to the plant capacity factor. 

These consist of lime reagent costs, water costs, FGD waste disposal costs, bag and cage 

replacement costs, ash disposal costs, and auxiliary power costs.

Lime Reagent costs were based on material balances and budgetary lime quotations received for 

truck delivery, $105.53/ton, which is 52% of the previously assumed cost. Water costs were 

based on 219,839 lb/hr at full load, a 90% capacity factor and $2.57/1000 gallons. FGD Waste 

Disposal was based on material balances for the average fuel composition and a 90% capacity 

factor. First year cost of on-site disposal is $40.59/ton. Bag and cage replacement costs were 

based on exhaust gas flow through the baghouse, an air-to-cloth ratio of 3.5 for pulse jet 

baghouse, 4% contingency for bag cleaning, and 3-year bag life. The first year bag cost 

(including fabric and hangers) is $3.31/ft2. Ash disposal costs were not assumed to increase 

from the fabric filter as existing ESP is remaining in service. Auxiliary power costs were based 

on auxiliary power calculations and a 90% capacity factor. The first year auxiliary power cost is 

$85.92/MWh, which is 180% of the previously assumed power cost.

Increases in water, FGD waste disposal, bag and cage replacement, and auxiliary power costs 

offset decreases in lime reagent costs resulting in an increase in expected variable O&M costs 

from the 2008 estimate by approximately $1,000,000 per boiler per year.

Fixed O&M

Fixed O&M costs are recurring annual costs that are generally independent of the plant capacity 

factor. Theses consist of operating labor, supervisor labor, maintenance materials, and 

maintenance labor.
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Operating labor was based on three shifts per day 365 days per year. The first year labor rate 

(salary plus benefits) is 58.76/hour. Supervisory labor was based on 15% of operating labor in 

accordance with the EPA Control Cost Manual (page 2-31). Maintenance materials were based 

on 0.6% of the total plant investment. Previous cost estimates reflecting Cue Cost default 

assumptions were based on 5% of capital equipment costs and therefore contributed to the 

exaggeration of annual operating costs. Maintenance labor was again based on 110% of 

operating labor, which is consistent with the EPA Control Cost Manual (page 2-31).

Due to the difference in cost basis for maintenance materials, the final fixed O&M costs were 

decreased by approximately $10,300,000 per year per boiler.

Indirect Operating Costs

Indirect operating costs are recurring annual costs for the FGD system that are not part of the 

direct O&M. These consist of property taxes, insurance, and administration.

Property taxes were calculated as 0.85% of total capital investment, in accordance with OG&E 

property tax rates. This rate is significantly lower than the EPA default rate of 1%. Insurance 

rates were calculated as 0.0105% of total capital investment in accordance with OG&E insurance 

rates. This rate is significantly lower than the EPA default rate of 1%. Administrative costs 

were calculated as 20% of the fixed O&M costs rather the EPA Air Pollution Control Cost 

Manual 6th Ed guidance of 2% of capital investment.

Due to the difference in cost basis for all indirect costs, but most particularly administrative 

costs, the final indirect operating costs were decreased by approximately $10,980,000 per year 

per boiler from the previous assessment.

Revised O&M estimates are now consistent with the 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 lists a cost range in $/kW of 15 to 38 for O&M costs. OG&E estimates are approximately 

$29-32/kW. 

OG&E 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. 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.

Table 10: Economic Cost for Units 4 and 5 - Dry FGD- Spray Dryer Absorber

Cost Unit 4 Unit 5

Total Capital Investment ($) $317,193,600 $317,193,600

Total Capital Investment ($/kW) $555 $555

Capital Recovery Cost ($/Yr) $32,861,300 $32,861,300

Annual O&M Costs ($/Yr) $18,438,900 $18,438,900

Total Annual Cost ($) $51,300,200 $51,300,200
OG&E Muskogee Generating Station BART Review January 15, 2010

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Table 11: Environmental Costs for Units 4 and 5- Dry FGD- Spray Dryer Absorber

Unit 4 Unit 5

SO2 Baseline (TPY) 19,113 9,006

SO2 Controlled (lb/mmBtu) 0.1 0.1

Annual SO2 Controlled (TPY)22,160 2,160

Annual SO2 Reduction (TPY) 6,953 6,846

Total Annual Cost ($) $51,300,200 $51,300,200

Cost per Ton of Reduction $7,378 $7,493

(1) Baseline annual emissions are calculated as the average actual SO2 emission rate during the baseline years of 

2004-2006.

(2)Projected annual emissions were calculated based on the controlled SO2 emissions rate, full load heat input of 

5,480 mmBtu/hr, and assuming 7,884 hours/year per boiler (90% capacity factor).

OG&E did not submit revised cost estimates for Wet FGD; however, in order to be thorough,

some conclusions can be drawn from the estimates provided for Dry FGD. The total capital 

requirement for wet scrubbers was assumed to be consistent with the previous determination. 

The capital recovery factor was modified to reflect the current company position of a 20 year 

depreciation. The annual operating costs were modified to reflect the cost bases for water, labor, 

auxiliary power, taxes, insurance and administrative costs detailed in the preceding paragraphs.

Table 12: Environmental Costs for Unit 4 or 5- Wet FGD

Cost

OG&E Cost Estimates

Unit 4 Unit 5

Total Capital Investment ($) $418,567,000 $418,567,000

Capital Recovery Cost ($/Yr) $43,363,541 $43,363,541

Annual O&M Costs ($/Yr) $21,061,140 $21,061,140

Total Annual Cost ($) $64,424,681 $64,424,681

Control SO2 Emission Rate (lb/mmBtu) 0.08 0.08

Baseline Annual Emissions (TPY)1

9,113 9,006

Controlled Annual SO2 Emission (TPY)2

1,728 1,728

Annual SO2 Reduction (TPY) 7,385 7,278

Cost per Ton of Reduction ($/Ton) $8,724 $8,852

Incremental Annual Cost ($/Ton) $30,381 $30,381

(1) Baseline annual emissions were calculated based on average annual SO2 emissions for the years 2004-2006. 

(2)Projected annual emissions were calculated based on the controlled SO2 emissions rate, full load heat input of 

5,480 mmBtu/hr, and assuming 7,884 hours/year per boiler (90% capacity factor).
OG&E Muskogee Generating Station BART Review January 15, 2010

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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). Muskogee Units 4 and 5 are currently 

equipped with ESP control systems.

Table 13: Summary of Technically Feasible 

Main Boiler PM10 Control Technologies

Control Technology PM10 Emissions1

lb/mmBtu)

% Reduction

(from base case)

Fabric Filter Baghouse 0.015 99.7

ESP - Existing 0.025 99.3

Potential PM Emissions 5.65 -

1 The PM10 emission rate for the baghouse case is based on filterable PM10 emission limits

included in recently issued PSD permits for new coal-fired units. The PM10 emission rate for the

ESP case is based on the Units’ baseline PM10 emission rates. Potential PM emissions were

calculated assuming an average fuel heating value of 8,500 Btu/lb and an ash content of 6.0%,

and assuming 80% of the fuel ash will be emitted as fly ash.

EVALUATE IMPACTS AND DOCUMENT RESULTS (PM10)

Costs for Fabric Filter Baghouses were included in the cost estimates provided by OG&E for 

Dry FGD. Because of the interdependency of the control systems, a determination of baghouse 

versus existing ESP cannot be made without consideration of the eventual sulfur control. Annual 

average PM emissions are less than 500 TPY for both boilers. On a PM basis alone and 

assuming the current 20 year depreciation, no additional operating costs, and 100% emission 

reduction, a resultant cost effectiveness of $9,324 per ton would support the conclusion that 

further reductions from the addition of a $45,000,000 fabric filter are not cost effective.

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 Muskogee Generating Station by using an EPA-approved dispersion modeling 

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

determined that the Muskogee Generating Station was subject to BART based on the results of 

initial screening modeling that was conducted using current (baseline) emissions from the 

facility. The screening modeling, as well as more refined modeling conducted by the applicant, 

is described in detail below.

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

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

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

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

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

assumed that areas at greater distances and in directions of less frequent plume transport will 
OG&E Muskogee Generating Station BART Review January 15, 2010

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experience lower impacts than those predicted for the four modeled areas. 

Figure 1: Plot of Facility location in relation to nearest Class I areas

REFINED MODELING

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

Station, OG&E 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 Muskogee Generating Station were determined with the 

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

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

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

50 km. Because 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 
OG&E Muskogee Generating Station BART Review January 15, 2010

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

pollutant transport, transformation, and removal. 

CALMET is a diagnostic wind model that develops hourly wind and temperature fields in a 

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

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

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

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

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

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

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

radius of influence for surface and upper-air stations. 

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

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

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

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

were completed using the CALPUFF model in a refined mode.

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

the impacts to visibility. 

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

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

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

Table 14: 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 15: 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, 
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Variable Description Value

1000, 2000, 3500

RMIN2 Minimum distance for 

extrapolation

-1

IPROG Use gridded prognostic model 

outputs

14 km (MM5 data)

RMAX1 Maximum radius of influence 

(surface layer, km)

20 km

RMAX2 Maximum radius of influence 

(layers aloft, km)

50 km

TERRAD Radius of influence for terrain 

(km)

10 km

R1 Relative weighting of first guess 

wind field and observation (km)

10 km 

R2 Relative weighting aloft (km) 25 km

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

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

Figure 4. Plot of precipitation observation stations
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CALPUFF Modeling Setup

To allow chemical transformations within CALPUFF using the recommended chemistry 

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

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

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

CALPUFF simulation. As provided by the Oklahoma DEQ, hourly ozone data from the 

Oklahoma City, Glenpool, and Lawton monitors over the 2001-2003 time frames were used. 

Background concentrations for ammonia were assumed to be temporally and spatially invariant 

and were set to 3 ppb.

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

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

coordinates.

CALPUFF Inputs- Baseline and Control Options

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

(baseline) operations at the facility. Emissions of NOX and SO2 for the baseline runs were 

established based on CEM data and maximum 24-hour emissions averages for years 2001 to 

2003. 

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

tables with data for the various control options. 

Table 16: Source Parameters

Parameter

Baseline1

Coal-Fired

Unit 4

Coal-Fired

Unit 5

Heat Input (mmBtu/hr) 5,480 5,480

Stack Height (m) 106.71 106.71

Stack Diameter (m) 7.32 7.32

Stack Temperature (K)2430.78 430.78

Exit Velocity (m/s)225.40 25.40

Baseline SO2 Emissions (lb/mmBtu) 0.80 0.85

Dry FGD SO2 Emissions (lb/mmBtu) 0.10 0.10

Wet FGD SO2 Emissions (lb/mmBtu) 0.08 0.08

Baseline NOX Emissions (lb/mmBtu) 0.495 0.522

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

LNB/OFA + SCR NOX Emissions (lb/mmBtu) 0.07 0.07

ESP (Baseline) PM10 Emissions (lb/mmBtu) 0.0184 0.0244

FF PM10 Emissions (lb/mmBtu) 0.012 0.012

1Baseline emissions data were provided by OG&E. 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.

2

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

modeled at 359.11K and velocity decreased to 22.77 m/s. For WFGD, stack temperature decreased to 331.89K and 

velocity decreased to 21.10 m/s.
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Visibility Post-Processing (CALPOST) Setup

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

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

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

below. 

Table 17: 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 18: CALPUFF Visibility Modeling Results for Muskogee Units 4 and 5- NOX

Class I Area

2001 2002 2003 3-Year Average

98th

Percentile 

Value 

(Δdv)

No. of 

Days 

> 0.5 

Δdv

98th

Percentile 

Value 

(Δdv)

No. of 

Days 

> 0.5 

Δdv

98th

Percentile 

Value 

(Δdv)

No. of 

Days 

> 0.5 

Δdv

98th

Percentile 

Value 

(Δdv)

No. of 

Days 

> 0.5 

Δdv

Baseline

Wichita Mountains 0.511 8 0.613 9 0.744 12 0.623 10

Caney Creek 0.914 37 0.939 31 1.469 33 1.107 34

Upper Buffalo 1.021 21 0.650 11 0.702 13 0.791 15

Hercules Glade 0.574 10 0.431 5 0.407 4 0.471 6

Scenario 1- Combustion Control- LNB/OFA

Wichita Mountains 0.154 1 0.176 2 0.225 1 0.185 1

Caney Creek 0.280 1 0.283 1 0.444 4 0.336 2

Upper Buffalo 0.312 3 0.192 1 0.211 2 0.238 2

Hercules Glade 0.164 1 0.129 1 0.119 0 0.137 1
OG&E Muskogee Generating Station BART Review January 15, 2010

26

Modeling for SCR controls resulted in an approximate 50% reduction in visibility impairment 

from scenario one.

Table 19: CALPUFF Visibility Modeling Results for Muskogee Units 4 and 5- SO2

Class I Area

2001 2002 2003 3-Year Average

98th

Percentile 

Value 

(Δdv)

No. of 

Days 

> 0.5 

Δdv

98th

Percentile 

Value 

(Δdv)

No. of 

Days 

> 0.5 

Δdv

98th

Percentile 

Value 

(Δdv)

No. of 

Days 

> 0.5 

Δdv

98th

Percentile 

Value 

(Δdv)

No. of 

Days 

> 0.5 

Δdv

Baseline

Wichita Mountains 0.939 24 1.208 18 1.218 28 1.122 23

Caney Creek 1.081 34 1.287 40 1.724 50 1.364 41

Upper Buffalo 1.342 27 0.974 22 1.286 34 1.200 28

Hercules Glade 1.145 17 0.898 21 0.845 17 0.963 18

Scenario 1- Dry FGD

Wichita Mountains 0.117 0 0.148 0 0.165 1 0.143 0

Caney Creek 0.140 0 0.171 0 0.234 2 0.182 1

Upper Buffalo 0.160 0 0.114 1 0.167 0 0.147 0

Hercules Glade 0.119 0 0.122 0 0.101 0 0.114 0

While mass emissions are decreased marginally with Wet FGD controls modeled impacts 

increase over modeled concentrations in scenario one for all Class I areas but the Wichita 

Mountains. Wet FGD reduced visibility impairment by a further 1% over Dry FGD. This 

generally increased degradation is a result of lower stack temperatures and velocities and higher 

SO4 emission estimates.

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.

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 

two units at the Muskogee Generating Station.

NOX

New LNB with OFA is determined to be BART for NOX control for Units 4 and 5 based, in part, 

on the following conclusions:

1. Installation of new LNB with OFA was cost effective, with a capital cost of $14,113,700 

per unit for units 4 and 5 and an average cost effectiveness of $260-$281 per ton of NOX

removed for each unit over a twenty-five year operational life.
OG&E Muskogee Generating Station BART Review January 15, 2010

27

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 Unit 4 and 5 are justified meet the presumptive limits prescribed by EPA. 

4. Annual NOX emission reductions from new LNB with OFA on Units 4 and 5 are 2,018-

2,469 tons for a total annual reduction of 4,487 tons based on actual emissions from 

2004-2006 and projected emissions at maximum heat input and 90% capacity.

LNB with OFA and SCR was not determined to be BART for NOX control for Units 4and 5

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 4 and 5 are on 

average $193,077,000 per unit. Based on projected emissions, SCR could reduce overall 

NOX emissions from Muskogee Units 4 and 5 by approximately 3,456 TPY beyond 

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

approximately $16,611/ton.

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

reagents. 

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

4. 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 4 and 5

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.

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 facility. The final estimate for 

both boilers at $634,387,200 is $223,691,200 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 ($317,193,600).

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.
OG&E Muskogee Generating Station BART Review January 15, 2010

28

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

evaluations.

Table 20: 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 

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 OG&E units would be about 55 to 185% higher than 

the other units listed, i.e., less cost effective. 

The average cost effectiveness at Muskogee for DFGD is $7,378-$7,493 per ton of SO2 removed 

for each unit over a twenty year operational life. The cost of this control at the Muskogee 

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 Muskogee Facility was anticipated to reduce 

impairment by 4.217 dv. Importantly, the cost effectiveness of that improvement is now 

calculated to be $24,330,000/dv. 
OG&E Muskogee Generating Station BART Review January 15, 2010

29

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 Muskogee station is located within 300 km of 4 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 6.5 times more cost effective than DFGD controls at 

the Muskogee 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 OG&E 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 

Muskogee 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 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 Muskogee facility for at least 20 years and 

beyond. BART is the continued use of low sulfur coal.

Wet FGD was not determined to be BART for SO2 control for Units 4 and 5 based, in part, on 

the following conclusions:

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

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

Muskogee Units 4 and 5 by approximately 864 TPY beyond dry scrubbers; however, the 

incremental cost associated with this reduction is approximately $30,381/ton.

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; 
OG&E Muskogee Generating Station BART Review January 15, 2010

30

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. We 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. 

6. Because of a slower exit velocity, lower stack temperature and higher SO4 emissions associated 

with Wet FGD, visibility impairment was found to higher under this control strategy than the Dry 

FGD for three of four Class I areas. 

PM10

The existing ESP control is determined to be BART for PM10 controls for Units 4 and 5 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 21: Unit-by-unit BART determinations

Control Unit 4 Unit 5

NOX Control New LNB with OFA New LNB with OFA

Emission Rate (lb/mmBtu) 0.15 lb/mmBtu

(30-day rolling average)

0.15 lb/mmBtu

(30-day rolling average)

Emission Rate lb/hr 822 lb/hr

(30-day rolling average),

822 lb/hr

(30-day rolling average),

Emission Rate TPY 3,600 TPY

(12-month rolling)

3,600 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 3,562 lb/hr

(30-day rolling average)

3,562 lb/hr

(30-day rolling average)

Annual Emission Rate

(lb/mmBtu)

0.55 lb/mmBtu 

(annual average)

0.55 lb/mmBtu 

(annual average)

Emission Rate TPY 18,096 TPY

PM10 Control Existing ESP Existing ESP

Emission Rate (lb/mmBtu) 0.1 lb/mmBtu 0.1 lb/mmBtu

Emission Rate lb/hr 548 lb/hr 548 lb/hr

Emission Rate TPY 2,400 TPY

(12-month rolling average)

2,400 TPY

(12-month rolling average)
OG&E Muskogee Generating Station BART Review January 15, 2010

31

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 Muskogee Units 4 and 5 install 

DFGD with SDA for SO2 control and fabric filters for PM control or meet the corresponding SO2

and PM10 emission limits listed below by December 31, 2018 or comply with the approved 

alternative described in section G (Greater Reasonable Progress Alternative).

Table 22: Unit-by-unit Contingent BART determinations

Control Unit 4 Unit 5

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 548 lb/hr

(30-day rolling average)

548 lb/hr

(30-day rolling average)

Emission Rate TPY 2,400 TPY 2,400 TPY

PM10 Control Fabric Filter Fabric Filter

Emission Rate (lb/mmBtu) 0.015 lb/mmBtu 0.015 lb/mmBtu

Emission Rate lb/hr 82 lb/hr 82 lb/hr

Emission Rate TPY 360 TPY

(12-month rolling average)

360 TPY

(12-month rolling average)

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 reductions while 

simultaneously solidifying the use of a dirty technology from now into the foreseeable future.

G. GREATER REASONABLE PROGRESS ALTERNATIVE DETERMINATION

In lieu of installing and operating BART for SO2 and PM control at Sooner Units 1 and 2 and 

Muskogee Units 4 and 5, OG&E may elect to implement a fuel switching alternative. The 

greater reasonable progress alternative requires OG&E to achieve a combined annual SO2

emissions limit (identified in table 23 ) by installing and operating DFGD with SDA on two of 

the four boilers and being at or below the SO2 emission that would result from switching the 
OG&E Muskogee Generating Station BART Review January 15, 2010

32

remaining two boiler to natural gas. Under this alternative OG&E shall install the controls (i.e., 

DFGD with SDA or achieve equivalent emissions) by December 31, 2026. By adopting these 

emission limits, DEQ and OG&E expect the cumulative SO2 emissions from Sooner Units 1 and 

2 and Muskogee Units 4 and 5 to be approximately 57% less than would be achieved through the 

installation and operation of DFGD with SDA at all four units (assuming 90% capacity).

Table 23: SO2 Emissions with Greater Reasonable Progress

Muskogee Sooner

Parameter Unit 4 and Unit 5 Unit 1 and Unit 2

BART (Low Sulfur Coal) 18,096 TPY 19,736 TPY

Contingent BART (DFGD) 4,800 TPY 4,482 TPY

GRP (DFGD/Natural Gas) 3,600 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) 

Muskogee Generating Station is a major source under OAC 252:100-8 Permits for Part 70 

Sources. Oklahoma Gas and Electric 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 Muskogee Station. The permit 

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

emissions. 

VI. OPERATING PERMIT

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

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

controls determined to meet BART. The Permit will contain the following specific conditions:

1. The boilers in EUG 3 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:
OG&E Muskogee Generating Station BART Review January 15, 2010

33

EU ID#

Point 

ID# EU Name

Heat Capacity

(MMBTUH)

Construction

Date

3-B 01 Unit 4 Boiler 5,480 1972

3-B 02 Unit 5 Boiler 5,480 1972

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

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

SIP incorporating the BART requirements.

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

modification of the boilers. If the modifications will result in a significant 

emission increase and a significant net emission increase of a regulated NSR 

pollutant, the applicant shall apply for a PSD construction permit.

d. The affected facilities shall be equipped with the following current combustion 

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

emissions of NOX to below the emission limits below:

i. Low-NOX Burners,

ii. Overfire Air.

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

and establish procedures to ensure the controls are properly operated and 

maintained.

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

after modification or installation of BART, not to exceed 180 days from initial 

start-up of the affected facility the permittee shall comply with the emission limits 

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

construction permit shall be consistent with manufacturer’s data and an agreed 

upon safety factor. The emission limits established in the construction permit 

shall not exceed the following emission limits:

EU 

ID#

Point 

ID#

NOX

Emission Limit

SO2

Emission Limit

Averaging 

Period

3-B 01 0.15 lb/mmBtu 0.65 lb/mmBtu 30-day rolling

3-B 02 0.15 lb/mmBtu 0.65 lb/mmBtu 30-day rolling

EU ID# Point ID# PM10

3-B 01 0.1 lb/mmBtu

3-B 02 0.1 lb/mmBtu

EU 

ID#

Point 

ID#

SO2

Emission Limit

SO2

Emission Limit

Averaging 

Period

3-B 01 18,096 TPY 0.55 lb/mmBtu Annual rolling

3-B 02 0.55 lb/mmBtu Annual rolling

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 
OG&E Muskogee Generating Station BART Review January 15, 2010

34

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.