## Oklahoma Department of Environmental Quality

Air Quality Division

BART Application Analysis January 15, 2010

COMPANY: Oklahoma Gas and Electric

FACILITY: Sooner Generating Station

FACILITY LOCATION: Red Rock, Noble County , Oklahoma

TYPE OF OPERATION: ( 2 ) 5 70 MW Steam Electric Generating Units

REVIEWER S : 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 mee ting 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 Regio nal 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).

Sooner Units 1 and 2 are fossil

- fuel fired b oiler s 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 NO X , SO 2 , and PM 10 , visibility impairing pollutant s

. Therefore, Sooner

Units 1 and 2 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 anticipate d to cause or contribute to any impairment of visibility in a Class I Area.OG&E Sooner Generating Station BART Review January 15, 2010

2 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

Sooner Units 1 and 2 exceeded the 0.5 Δ

- dv threshold at t he Wichita Mountains, Caney Creek and Upper Buffalo Class I Area s . Therefore, Sooner Units 1 and 2 were determined to be BART applicable sources, subject to the BART determination requirements.

III. DESCRIPTION OF BART SOURCES

Baseline emissions from Soon er Units 1 and 2 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 modelin g 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 base line 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 : Sooner Generating Station

- Plant Operating P arameters for BART Evaluation

Parameter Sooner Unit 1 Sooner Unit 2 Plant Configuration Pulverized Coal

- Fired Boiler Pulverized Coal

- Fired Boiler Firing Configuration Tangentially

- fired Tangentially

- fired Gross Output (nominal) 570 MW 570 MW

Maximum In put to
Boiler 5,116 mmBtu/hr 5,116 mmBtu/hr

Primary Fuel Subbituminous coal Subbituminous coal Existing NO X Controls Combustion controls Combustion controls Existing PM 10 Controls Electrostatic precipitator Electrostatic precipitator Existing SO 2 Contr ols Low

- sulfur coal Low

- sulfur coal

Maximum 24

- hour E missions

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

NO X 3

, 075 0.601 2

, 988 0.584

SO 2 4

, 393 0.86 4

, 410 0.86

PM 10 194 0.038 200 0.039 Baseline Emissions (2004

- 2006)

Pollutant lb/hr lb/mmBtu lb/hr lb/m mBtu

NO X 1,834 0.384 1,561 0.337

SO 2 2,428 0.509 2,393 0.516

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 H aze Rule). States are required to use the Appendix Y guidelines to make BART determinations for fossil

- fuel

- fired generating plantsOG&E Sooner Generating Station BART Review January 15, 2010

3 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 Result s. Step 5. Evaluate Visibility Impacts.

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

SO 2 and NO X 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 SO 2 presumptive emission limit for coal

- fired EG Us greater than 200 MW in size without existing SO 2 control is either 95% SO 2 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 NO X , 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 NO X presumptive emission limit applicable to Sooner Units 1 & 2 ( tangentially fired boilers firing subbituminous coal) is 0.15 lb/mmBtu.

Table 2 : Proposed BART Controls and Limits

Unit NO X BART Emission Limit BART Technology

Sooner Unit 1 0. 15 lb/ mmBtu (30

- day average) Combustion controls including LNB/OFA

Sooner Unit 2 0. 15 lb/ mmBtu (30

- da y average) Combustion controls including LNB/OFA

Unit SO 2 BART Emission Limit BART Technology

Sooner Unit 1 0. 65 lb/mmBtu (30

- day average) Low Sulfur Coal

0.55 lb/mmBtu (annual average)

Sooner Unit 2 0. 65 lb/mmBtu (30

- day average) Low Sulfur Coal

0.55 lb/mmBtu (annual average)

Units 1 and 2 19,736 TPY Low Sulfur Coal

Unit PM 10 BART Emission Limit BART Technology

Sooner Unit 1 0.1 lb/mmBtu (3

- hour average) Electrostatic Precipitator

Sooner Unit 2 0. 1 lb/mmBtu (3

- hour average) Electrostatic Prec ipitator

A. NO X

IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES Potentially available control options were identified based on a comprehensive review of

available information. NO X control technologies with potential application to Sooner Units 1 and

2 are listed in Table 3

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

4 Table 3 : List of Potential Control Options

Control Technology

Combustion Controls

Low NO X Burners and Overfire Air (LNB/OFA) Flue Gas Recirculation (FGR)

Post Combustion Controls Selective Noncatalytic Reduction (SNCR)

S elective Catalytic Reduction (SCR) Innovative Control Technologies Rotating Overfire Air (ROFA) ROFA + SNCR (Rotamix)

Pahlman Multi

- Pollutant Control Process

Wet NO X Scrubbing

ELIMINATE TECHICALLY INFEASIBLE OPTIONS (NO X )

Combustion Controls:

Lo w NO X burners (LNB)/ Over Fire Air (OFA)

Low NO X burners (LNB) limit NO X 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. St aging combustion reduces NO X 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. Sooner units 1 and 2 op erate 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 eng ineering judgment, it is expected that LNB/OFA on tangentially

- fired boilers can be designed to meet the presumptive NO X 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 NO X by recycling a portion of the flue gas back into the primary combustion zone. The recycled air lowers NO X emissions by two mechanisms: (1) the recycled gas, consi sting 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 NO X 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 O 2 concentrations in the flue gas and low

pa rticulate loading. In a coal

- fired application, the FGR system would have to handle hot particulate

- laden flue gas with a relatively high O 2 concentration. Although FGR has been used

on coal

- fired boilers for flue gas temperature control, it would not have application on a coal

fired boiler for NO X control. Because of the flue gas characteristics (e.g., particulate loading and O2 concentration), FGR would not operate effectively as a NO X control system on a coal

- firedOG&E Sooner Generating Station BART Review January 15, 2010

5 boiler. Therefore, FGR is not considere d an applicable retrofit NO X control option for Sooner Units 1 & 2, 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 inje ction of ammonia or urea at high flue gas temperatures. The ammonia or urea reacts with NO X in the flue gas to produce N 2 and water. At temperatures below the desired operating range, the NO X reduction reactions

diminish and NH 3 emissions increase. Abov e the desired temperature range, NH 3 is oxidized to

NO X resulting in low NO X 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 ove r 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 furth er influenced by residence time, reagent

- to

- NO X ratio, and fuel sulfur content.

The size of the Sooner Units would represent several design problems making it difficult to ensure that the reagent would be injected at the optimum f l ue gas temperature, and that there would be adequate mixing and residence time. The physical size of the Sooner boilers makes it technically infeasible to locate and install ammonia injection points capable of achieving adequate mixing within the required temperature zone. High er 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 r esult 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 NO X formation.

Installation of SNCR on large boilers, such as those at Sooner , has not been demonstrated in practice. Assuming that SNCR could be installed on the Sooner Units, given the issues

add ressed above, control effectiveness would be marginal, and depending on boiler exit temperatures, could actually result in additional NO X formation. SNCR is not a technically

feasible retrofit control for the Sooner Boilers.

Selective Catalytic Reduction Selective Catalytic Reduction (SCR) involves injecting ammonia into boiler flue gas in the presence of a catalyst to reduce NO X 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 NO X 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 NO X emission rates in the range of approximately 0.0 4OG&E Sooner Generating Station BART Review January 15, 2010

6 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 NO X emission rate, flue gas temp erature, 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 antici pated that SCR could achieve a controlled NO X emission rate of 0.07 lb/mmBtu (30

- day rolling average) on Sooner Units 1 & 2.

Innovative NOX Control Technologies: Rotating Opposed Fire Air and Rotomix Rotating opposed fired air (ROFA) is a boosted over fir e 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 product s 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 Sooner Units 1 & 2. As discussed for
OFA, over fire air control systems ar e a technically feasible retrofit control technology, and, based on engineering judgment, the ROFA design could also be applied on Sooner Units 1 and 2

. However, there is no technical basis to conclude that the ROFA design would provide additional

NOX redu ction 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/ NO X contact, and flue gas

t emperatures, 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 tec hnically feasible retrofit control

for the Sooner 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 sor bent) to remove NO X and SO 2 from the flue gas.

To date, bench

- and pilot

- scale testing have been conducted to evaluate the technology on utility

sized 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 b oiler. 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 SoonerOG&E Sooner Generating Station BART Review January 15, 2010

7 Units 1 and 2 . BART does not require applicants to experie nce 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 Sooner Boilers

Wet NO X Scrubbing Systems Wet scrubbing systems have been used to remove NO X 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 ozo ne is injected into the flue gas stream to oxidize NO and NO 2 to N 2 O 5 . This highly oxidized species of

NO X is very soluble and rapidly reacts with water to form nitric acid. The conversion of NO X to
nitric acid occurs as the N 2 O 5 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. Ho wever 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 NO X scrubbing systems are not technically feasible retrofit

controls for the Sooner Boilers

EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (NO X )

Table 4 : Technically Feasible NO X Control Technologies

- Sooner Station

Control Technology Sooner Unit 1 Sooner Unit 2 Approximate NO X Emission Rate (lb/mmBtu) Approximate NO X

Emission Rate (lb/mmBtu)

LNB/OFA + SCR 0.07 0.07

LNB/OFA 0.15 0.15

Baseline 0.384 0.337

EVALUATE IMPACTS AND DOCUMENT RESULTS (NO X )

OG&E evaluated the economic, environmental, and ener gy 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 a nd equipment costs recently developed for similar projects, and include the equipment, material, labor, and all other direct costs needed to retrofit

Sooner Units 1 and 2 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,

an d 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 handlin g, and by

- product handling. The capital recovery factor used to estimate the annual cost of control was based on aOG&E Sooner Generating Station BART Review January 15, 2010

8 7% interest rate and a control life of 25 years. Annual operating costs and annual emission reductions were calculated assuming a capacity factor of 9 0%.

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 effectivene ss ($/ton removed) is much higher, but the result is representative of more reasonably achievable emissions reductions.

T able 5 : Economic Cost Per Boiler

Cost Unit Option 1:

LNB/OFA Option 2:

LNB/OFA +SCR Control Equipment Capital Cost ($) Unit 1 $ 14

, 055

, 900 $ 1 92,018

, 500 Annualized Capital Cost ($/Yr) Unit 1 $1,206,100 $1 6

, 477

, 2 00 Annual O&M Costs ($/Yr) Unit 1 $877,100 $1 4,487

, 4 00 Annual Cost of Control ($) Unit 1 $2,083,200 $ 30

, 964

, 6 00

Table 6: Environmental Costs per Boiler

Baseline Option 1:

LN B/OFA Option 2 :

LNB/OFA +SCR

NO X Emission Rate (lb/mmBtu) Unit 1 0.384 0.15 0.07

Unit 2 0.337 0.15 0.07

Annual NO X Emission (TPY) 1 Unit 1 7,266 3

, 025 1

, 412

Unit 2 5,689 3

, 025 1

, 412

Annual NO X Reduction (TPY) Unit 1

-- 4

, 241 5,854

Unit 2

-- 2,664 4 ,277

Annual Cost of Control Unit 1

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

Unit 2

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

Cost per Ton of Reduction Unit 1

-- $493 $5,260

Unit 2

-- $785 $7,200
Incremental Cost per ton of

Reduction 2 Unit 1

-- -- $17,795

Unit 2

-- -- $17,795

( 1) Emissions for the BART analysis are based on average heat inputs of 4,771 and 4,634 mmBtu/hr for Units 1 & 2

. Annual emissions were calculated assuming 7,738 and 7,164 hours/year per for Units 1 and 2 respectively

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

controls.

B. SO 2

IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES (SO 2 ) Potentially available control options were identified based on a comprehensive review of

available informatio n. SO 2 control technologies with potential application to Sooner Units 1 and

2 are listed in Table 7.OG&E Sooner Generating Station BART Review January 15, 2010

9 Table 7: List of Potential Control Options

Control Technology

Pre

- Combustion Controls Fuel Switching Coal Washing Coal Processing

Post Combustio n 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 Dry er Absorber Dry Sorbent Injection Circulating Dry Scrubber

ELIMINATE TECHICALLY INFEASIBLE OPTIONS (SO 2 )

Pre

- Combustion Control Strategy: Fuel Switching One potential strategy for reducing SO 2 emissions is reducing the amount of sulfur contained in the coal. Sooner Units 1 & 2 fire subbituminous coal as their primary fuel. Subbituminous coal has a relatively low heating value, low sulfur content, and low uncontrolled SO 2 emission rate. No environmental benefits accrue from burning an alternative c oal; 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. T he 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 inor ganic impurities including silica and trace metals. The solids are typically dewatered in a mechanical dewatering device and disposed of in a landfill.

Sooner Units 1 & 2 are designed to utilize subbituminous coals. Based on a review of available

informat ion, 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 Sooner Units 1 & 2.OG&E Sooner Generating Station BART Review January 15, 2010

10 Coal Processing

Pre

- combustion coal proc essing techniques have been proposed as one strategy to reduce the sulfur content of coal and help reduce uncontrolled SO 2 emissions. Coal processing technologies are being developed to remove potential contaminants from the coal prior to use. These

proce sses 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 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 pulverized coal

- fired boil er, using processed fuels in Sooner Units 1 & 2 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 SO 2 control technology. Wet scrubbing systems offe red by vendors may vary in design; however, all wet scrubbing systems utilize an alkaline scrubber slurry to remove SO 2 from the flue gas.

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

al kaline slurry is sprayed in the absorber and reacts with SO 2 in the flue gas. Insoluble CaSO 3 and CaSO 4 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 CaSO 3 , 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 (CaCO 3 ) i s mixed with water to formulate the alkali scrubber slurry. SO 2 in the flue gas reacts with the limestone slurry

to form insoluble CaSO 3 and CaSO 4 which is removed as a solid waste by product

. The use of limestone instead of lime requires different feed p reparation equipment and a higher liquid

- to

gas 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 c an 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 (CaSO 3 ) to relatively pure gypsum (calci um sulfate ) . Forced oxidation of the scrubber slurry provides a more stable by

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

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

11 Wet lime and wet limestone scrubbing systems will achieve the same SO 2 control efficiencies; however, the higher cost of lime typically makes wet limestone scrubbing the more attractive option. For this reason, wet lime scru bbing 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 SO 2 removal less dependent on the dissolution of the lime/limestone.

MEL scrubbers have been installed on coal

- fired ut ility 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 f ire 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 wil l 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 s lurry. 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 JBR

WFGD 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 SO 2 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 con trol 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 overa ll assessment of WFGD controls.

Dual

- Alkali Wet Scrubber

Dual

- alkali scrubbing is a desulfurization process that uses a sodium

- based alkali solution to
remove SO 2 from combustion exhaust gas. The process uses both sodium

- based and calcium

based compounds . The dual

- alkali process requires lower liquid

- to

- gas ratios then scrubbing withOG&E Sooner Generating Station BART Review January 15, 2010

12 lime or limestone. The reduced liquid

- to

- gas ratios generally mean smaller reaction units,

however additional regeneration and sludge processing equipment is necessary. The s odium

based scrubbing liquor, typically consisting of a mixture of sodium hydroxide, sodium carbonate and sodium sulfite, is an efficient SO 2 control reagent. However, the high cost of the sodium

based chemicals limits the feasibility of such a unit on a l arge 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 SO 2 control similar to a limestone

- based wet FGD. H owever, 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 Precipitat or 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 cont rolled with wet FGD. WESP has not been widely used in utility applications, and has only been proposed on boilers firing high sulfur coals and equipped with SCR. Sooner Units 1 & 2 fire low

- sulfur subbituminous coal. Based on the fuel characteristics, and assuming 1% SO 2 to SO 3 conversion in the boiler, potential uncontrolled H 2 SO 4 emissions from Sooner Units 1 & 2 will only be approximately 5ppm. This emission rate does not take into account inherent acid gas removal associated with alkalinity in the subb ituminous 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 Sooner Units 1 & 2, even if WFGD control was installed. WESPs have been proposed to contr ol condensable particulate emissions from boilers firing a high

- sulfur bituminous coal and equipped with SCR and wet FGD. The c ombination of coal and control equipment results in relatively high concentrations of sulfuric acid mist in the flue gas. WESP

c ontrol 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 SO 2 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 SO 2 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 eq uipment. 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 utilit y applications. SDA systems have demonstrated the ability to effectively reduce uncontrolled SO 2 emissions from pulverized coal units. The typical spray dryer absorber uses a slurry of lime and water injected

into the tower to remove SO 2 from the combustio n 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 commerciallyOG&E Sooner Generating Station BART Review January 15, 2010

13 available retrofit technology for Sooner Units 1 & 2. 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 SO 2 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 SO 2 control efficiencies for a dry sorbent injection system are generally

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

th a n 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 th is 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 scr ubbing system is the circulating dry scrubber (CDS). A CDS system uses a circulating fluidized bed of dry hydrated lime reagent to remove SO 2 . The dry by

- product produced by this system is similar to the spray dry absorber by

- product, and is routed with th e 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

utilizat ion based on inlet SO 2 loading. Furthermore, CDS systems r esult 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 tec hnology for boilers the size of Sooner Units 1 & 2, 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 sy stems are not currently commercially available as a retrofit control technology

for Sooner Units 1 & 2, and will not be evaluated further in this BART determination.

EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (SO 2 )

Table 8 : Technically Feas ible SO 2 Control Technologies

- Sooner Station

Control Technology Sooner Unit 1 Sooner Unit 2 Approximate SO 2 Emission Rate (lb/mmBtu) Approximate SO 2

Emission Rate (lb/mmBtu)

Wet FGD 0.08 0.08 Dry FGD

- Spray Dryer Absorber 0.10 0.10

Baseline 0.86 0.8 6 Annual Average Baseline 0.509 0.516OG&E Sooner Generating Station BART Review January 15, 2010

14 EVALUATE IMPACTS AND DOCUMENT RESULTS (SO 2 ) 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) vendo r 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 Sooner Units 1 and 2 with the control technologies.

While generally following the EPA methodology, these cost estimates exploited weaknesses in the estimate assumptions and resulted in highly exaggerated capita l 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 Soo ner facility. In degree of difficulty, the retrofit at the Sooner 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 co st 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. C ost 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

ma jor 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. 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 mon th intervals with the last unit being completed at Sooner

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 a nd 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 Sargen t and Lundy

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

15 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 Sooner facility.

The total capital requirement (TCR) is the sum of direct costs, indirect costs, contingency, escalation, and AFUDC. Direct costs include equipment, materi al, 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 estima ted 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 incr emental 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 incl uded 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) 201 4 Depreciable Life 20 years

Inflation Rate 2.5% /year

Effective Income Tax Rate

- Federal and State 38.12% Common Equity Fraction 0.557

Debt Fractio n 0.443 Return on Common Equity

Nominal 10.75% /year

Real 8.05% /year

Return on Debt

Nominal 6.03% /year

Real 3.44% /year Discount Rate (after

- tax cost of capital)

Nominal 7.64% /year

Real 5.43% /year Tax Depreciation 20

- year straight li ne Levelized Capital Charges (real) 10.36% /year

The revised estimates based on vendor quotes results in a TCR of $584,589,400 which is $196,222,600 less than the CUECost derived estimates provided in 2008. 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 30,281, 8 00 per boiler, which is $ 3,219

, 1 00 per boiler per year less than the 2008 estimate. C ost estimates and assumption s areOG&E Sooner Generating Station BART Review January 15, 2010

16 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 variab le 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 was te 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, $1 18

. 80 /ton, which is 5 9 % of the previously ass umed cost. Water costs were

based on 205,256 lb/hr at full load, a 90% capacity factor and $ 0

. 49 /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 dispo sal is $ 39.60 /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 an d hangers) is $3. 22 /ft 2 . 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 $ 83.83 /MWh, which is 18 6 % of the previously assumed power cost.

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

decreases in water and lime reagent costs resulting in no appreciable change in expe cted variable

O&M costs from the 2008 estimate.

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.

Operating labor was based on three shifts per day 365 days per year. The first year labor rate (salary plus benefits) is 57.33 /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 $1 1,4 56,200 per year per boiler.OG&E Sooner Generating Station BART Review January 15, 2010

17 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 calcul ated as 0. 60 % 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 insura nce 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 6 th Ed guidance of 2% of capital investment.

Due to the diff

erence in cost basis for all indirect costs, but most particularly administrative costs, the final indirect operating costs were decreased by approximately $ 12,636,500 per year per boiler from the previous assessment.

Revised O&M estimates are now consist ent 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 annu al emissions from 2004

- 2006.

Table 10 : Economic Cost for Unit s 1 and 2

- Dry FGD

- Spray Dryer Absorber

Cost Unit 1 Unit 2 Total Capital Investment ($) $292,294,900 $292,294,900 Total Capital Investment ($/kW) $514 $514 Capital Recovery Cost ($/Yr) $30, 281,800 $30,281,800 Annual O&M Costs ($/Yr) $16,550,500 $16,550,500
Total Annual Cost ($) $46,832,300 $46,832,300

Table 1 1 : Environmental Costs for Unit s 1 and 2

- Dry FGD

- Spray Dryer Absorber

Unit 1 Unit 2

SO 2 Baseline (TPY) 1 9,394 8,570

SO 2 Contr olled (lb/mmBtu) 0.1 0.1

Annual SO 2 Controlled (TPY) 2 2,017 2,017

Annual SO 2 Reduction (TPY) 7,377 6,553 Total Annual Cost ($) $46,832,300 $46,832,300 Cost per Ton of Reduction $6,348 $7,147

(1) Baseline annual emissions are c alculated as the average actual SO 2 emission rate during the baseline years of

2004

- 2006.OG&E Sooner Generating Station BART Review January 15, 2010

18 (2) Projected annual emissions were calculated based on the controlled SO 2 emissions rate, full load heat input of
5, 116 mmBtu/hr, and assuming 7,884 hours/year per boiler (90% capacity facto r).

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 pre vious 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 ad ministrative costs detailed in the preceding paragraphs.

Table 1 2 : Environmental Costs for Unit 2

- Wet FGD

Cost OG&E Cost Estimates

Unit 1 Unit 2 Total Capital Investment ($) $441,658,000 $441,658,000 Total Capital Investment ($/kW) $775 $775
Capita l Recovery Cost ($/Yr) $37,898,900 $37,898,900 Annual O&M Costs ($/Yr) $16,550,500 $16,550,500
Total Annual Cost ($) $54,449,400 $54,449,400

Control SO 2 Emission Rate (lb/mmBtu) 0.08 0.08
Baseline Annual Emissions (TPY) 1 9,394 8,570

Controlled Annual SO 2 Emission (TPY) 2 1,613 1,613

Annual SO 2 Reduction (TPY) 7,781 6,957 Cost per Ton of Reduction ($/Ton) $ 6,998 $ 7,827 Incremental Annual Cost ($/Ton) $18,854 $18,854

(1) Baseline annual emissions were calculated based on average annual SO 2 emissions f or the years 2004

- 2006.

(2) Projected annual emissions were calculated based on the controlled SO 2 emissions rate, full load heat input of
5, 116 mmBtu/hr, and assuming 7,884 hours/year per boiler (90% capacity factor).

C. PM 10

IDENTIFY AVAILABLE RETROFI T CONTROL TECHNOLOGIES (PM 10 ) There are two generally recognized PM control devices that are used to control PM emission from PC boilers: ESPs and fabric filters (or baghouses). Sooner Units 1 & 2 are currently equipped with ESP control systems.OG&E Sooner Generating Station BART Review January 15, 2010

19 Table 1 2 : Summary of Technically Feasible

Main Boiler PM 10 Control Technologies

Control Technology PM10 Emissions 1

( lb/mmBtu) % Reduction (from base case)
Fabric Filter Baghouse 0.015 99.7

ESP

- Existing 0.039 99.3

Potential PM Emissions 5.65

-
1 The PM 10 em ission rate for the baghouse case is based on filterable PM 10 emission limits included in recently issued PSD permits for new coal

- fired units. The PM 10 emission rate for the

ESP case is based on the Units’ baseline PM 10 emission rates. Potential PM emissi ons 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 (PM 10 ) Costs for Fabric Filter Baghouses were include d 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

furth er 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

- Appendi x 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 Sooner Generating Station by using an EPA

- approved dispersion modeling

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

determined that the Sooner Generating Station was subject to BART based on the results of initial screening modeling that was conducted using current (baseline) emis sions from the facility . The screening modeling, as well as more refined modeling conducted by the applicant,

is described in detail below.

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

closest Class I areas to t he Sooner Generating Station, as shown in Figure 1 below.

Only those Class I areas most likely to be impacted by the Sooner Generating Station were modeled, as determined by source/Class I area locations, distances to each Class I area, and professional judgment considering meteorological and terrain factors. It can be reasonably assumed that areas at greater distances and in directions of less frequent plume transport will experience lower impacts than those predicted for the four modeled areas.OG&E Sooner Generating Station BART Review January 15, 2010

20 F igure 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 Sooner Generating Station, OG&E was required to conduct a refined BART analysis that included CAL PUFF visibility modeling for the facility. The modeling approach followed the requirements described in the

Division’s BART modeling protocol, CENRAP BART Modeling Guidelines (Al pine Geophysics, December 2005) with refinements detailed the applicants CALM ET modeling protocol, CALMET Data Processing Protocol (Trinity Consultants, January 2008)

CALPUFF System Predicted visibility impacts from the Sooner Generating Station were determined with the EPA CALPUFF modeling system, which is the EPA

- preferred model ing 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 loca ted 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, CA LSUM, CALPOST). The CALPUFF model was developed as a non

- steady

- state air quality modeling system for assessing the effects of time

- and space

- varying meteorological conditions on pollutant transport, transformation, and removal.

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

three

- dimensional, gridded modeling domain. Meteorological inputs to CALMET can include surface and upper

- air observations from multiple meteorological monitoring stations.OG&E Sooner Generating Station BART Review January 15, 2010

21 Additionally, t he 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 roughnes s 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.

CALPUF F 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 meteorolo gical 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 calcula te 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 ar e listed in the table below.

Table 1 3 : Key Programs in CALPUFF System Program Version Level

CALMET 5.53a 040716

CALPUFF 5.8 070623

CALPOST 5. 6394 0 70622

Meteorological Data Processing (CALMET) As required by the Division’s modeling protocol, the CALM ET 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 1 4 : 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,

100 0, 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 kmOG&E Sooner Generating Station BART Review January 15, 2010

22 Variable Description Value

RMAX2 Maximum radius of influence

(layers aloft, km) 50 km

TERRAD Radius of influence for terrain

(km) 10 km

R1 Relative weighting of first guess

wind field and observation (km) 10 km

R2 Relative weighting aloft (km) 25 km

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

.

Figure 2: Plot of surface station locationsOG&E Sooner Generating Station BART Review January 15, 2010

23 Figure 3: Plot of upper air station locations

Figure 4. Plot of precipitation observation stationsOG&E Sooner Generating Station BART Review January 15, 2010

24 CALPUFF Modeling Setup To allow chemical transformations within CALPUFF using the recommended chem istry 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 we re 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 sp atially 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

- B aseline 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 NO X and SO 2 for the baseline runs were

established based on CEM data and maximum 24

- hour e missions 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 1 5 : Source Parameters

Parameter Baseline 1

Coal

- Fi red

Unit 1 Coal

- Fired

Unit 2 Heat Input (mmBtu/hr) 5,116 5,116 Stack Height (m) 152.44 152.44 Stack Diameter (m) 6.10 6.10 Stack Temperature (K) 2 430.78 430.78 Exit Velocity (m/s) 2 34.12 34.12

Baseline SO 2 Emissions (lb/mmBtu) 0.86 0.86 Dry FGD SO 2 Emissions (lb/mmBtu) 0.10 0.10

Wet FGD SO 2 Emissions (lb/mmBtu) 0.08 0.08

Baseline NO X Emissions (lb/mmBtu) 0.601 0.584

LNB/OFA NO X Emissions (lb/mmBtu) 0.15 0.15

LNB/OFA + SCR NO X Emissions (lb/mmBtu) 0.07 0.07
ESP (Baseline) PM 10 Emissions (lb/mmBtu ) 0.0379 0.0391

FF PM 10 Emissions (lb/mmBtu) 0.012 0.012

1 Baseline 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 Temper ature and Velocity were decreased for DFGD and WFGD evaluations. For DFGD, stack temperature was modeled at 359.11K and velocity decreased to 30.61 m/s. For WFGD, stack temperature decreased to 331.89K and velocity decreased to 28.35 m/s.OG&E Sooner Generating Station BART Review January 15, 2010

25 Visibility Po st

- 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) factor s that were used for this analysis are shown in the table

below.

Table 1 6 : 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 co ncentrations 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 1 7 : CALPUFF Visibility Modeling Results for Sooner Units 1 and 2

- NO X

Class I Area 2001 2002 2003 3

- Year Average

98 th

Percentile

Value (Δdv) No. of

Days

> 0.5

Δdv 98 th

Percentile

Value (Δdv) No. of

Days

> 0.5

Δdv 98 th

Percentile

Value (Δdv) No. o f

Days

> 0.5

Δdv 98 th

Percentile

Value (Δdv) No. of

Days

> 0.5

Δdv

Baseline

Wichita Mountains 1.244 19 0.901 16 1.199 25 1.115 20 Caney Creek 0.577 10 0.404 5 0.541 10 0.507 8 Upper Buffalo 0.573 8 0.335 4 0.337 3 0.415 5

Hercules Glade 0.440 6 0.274 5 0.388 1 0.367 4

Scenario 1

- Combustion Control

- LNB/OFA

Wichita Mountains 0.309 0 0.236 1 0.308 0 0.284 0 Caney Creek 0.147 0 0.103 0 0.14 0 0.13 0 Upper Buffalo 0.139 0 0.085 0 0.084 0 0.103 0

Hercules Glade 0.109 3 0.064 1 0.095 3 0.089 2OG&E Sooner Generating Station BART Review January 15, 2010

26 Modeli ng for SCR controls resulted in an approximate 50 % reduction in visibility impairment

from scenario one

.

Table 1 8 : CALPUFF Visibility Modeling Results for Sooner Units 1 and 2

- SO 2

Class I Area 2001 2002 2003 3

- Year Average

98 th

Percentile

Value (Δdv) No. of

Days

> 0.5

Δdv 98 th

Percentile

Value (Δdv) No. of

Days

> 0.5

Δdv 98 th

Percentile

Value (Δdv) No. of

Days

> 0.5

Δdv 98 th

Percentile

Value (Δdv) No. of

Days

> 0.5

Δdv

Baseline

Wichita Mountains 1.224 24 1.081 24 1.792 33 1.36 6 27 Caney Creek 0.709 11 0.505 10 0.584 11 0.599 11 Upper Buffalo 0.534 10 0.357 4 0.43 5 0.440 6

Hercules Glade 0.423 5 0.267 2 0.34 3 0.343 3

Scenario 1

- Dry FGD

Wichita Mountains 0.169 3 0.141 0 0.219 3 0.176 2 Caney Creek 0.08 0 0.062 0 0.063 0 0.068 0 Upper Buffalo 0.051 0 0.045 0 0.043 0 0.046 0

Hercules Glade 0.05 0 0.033 0 0.037 0 0.04 0

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

increase over modeled concentrations in scenario one. This increased degradation is a result of lower stack temperatures and velocities and higher SO 4 emission estimates. Modeling for existing ESP controls with proposed fabric filters indicate the visibility impairment from direct PM emissions will be improved with the fab ric 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

t wo units at the Sooner Generating Station.

NO X New LNB with OFA is determined to be BART for NO X control for Units 1 and 2 based, in part, on the following conclusions:

1. Installation of new LNB with OFA was cost effective, with a capital cost of $1 4,055

, 9 00 per unit for units 1 and 2 and an average cost effectiveness of $ 493

- 785 per ton of NO X removed for each unit over a twenty

- five year operational life.

2. Combustion control using the LNB/OFA does not require non

- air quality environmental mitigation for t he 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 ofOG&E Sooner Generating Station BART Review January 15, 2010

27 compliance and existing controls, NO X control levels on 30

- day rolling averages of 0. 15

lb/mmBtu for Unit 1 and 2 are justified meet the presumptive limits prescribed by EPA

. 4. Annual NO X emission reductions from new LNB with OFA on Units 1 and 2 are 2

, 66 4

- 4

, 241 tons for a total annual reduction of 6,90 5 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 NO X control for Units 1 and 2 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 1 and 2 are on average $ 192

, 018

, 5 00 per unit. Based on projected emissions, SCR could reduce overall

NO X emissions from Sooner Units 1 and 2 by approx imately 3

, 226 TPY beyond combustion controls; however, the incremental cost associated with this reduction is approximately $ 17

, 795 /ton.

2. Additional non

- air quality environmental mitigation is required for the use of chemical

reagents.
3. Operation of LNB wi th 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 98 th percentile modeled results) was 0. 15 Δdv for both

units.

SO 2 C ontinued use of low sulfur coal is determined to be BART for SO 2 control for Units 1 and 2

based on the capital cost of add

- on controls, the cost effectiveness both in $/ton and $/dv of add

on controls, and the long term viability of coal with respect to o ther 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 cr edible, detailed, and specific for the Sooner facility. The final estimate for both boilers at $584,589,800 is $175,329,800 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 Or egon at a projected cost of $247,300,000 . While there is some uncertainty on whether this cost will ultimately be found to be cost effective, it is lower than the cost of controlling a single boiler at the Sooner facility ($ 292,294,700 ). 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 SO 2 emission rates included in several BART

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

28 Table 20 : Comparison of Baseline SO 2 Emissions at Several BART Units

Station Baseline SO 2 Emission Rate (lb/mmBtu) Baseline SO 2 Emissions (TPY) Muskogee Unit 4 0.507 9,113 Muskogee Unit 5 0.514 9,00 6

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 rela ted 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 SO 2 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 SO 2 loading. In general, DFGD control systems are capable of achieving higher removal efficiencies on units with higher inle t SO 2 loading. DFGD control systems will be more cost effective on units with higher baseline SO 2 emissions because the control systems will be capable of achieving higher removal efficiencies and remove more tons of SO 2 per year for similar costs. Conve rsely, DFGD will be less cost effective, on a $/ton basis, on units with

lower SO 2 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 Sooner for DFGD is $ 6,348

- $7,147 per ton of SO 2 removed for each unit over a twenty year operational life . The cost of this control at the Sooner facility is

well above the average cost effectiveness reported for similar BART projects, well above costs

associated with BACT determinations for SO 2 , and well above the cost of control originally contemplated in the Regional Haze Rule.

From the FLM BART tracking spread sheet, the average cost effectiveness in $/dv was $5,700,000/dv. The addition of DFGD at the Sooner Facility was anticipated to reduce impairment by 2.44 dv. Importantly, the cost effectiveness of that improvement is now calculated to be $38,387,000/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 visibilityOG&E Sooner Generating Station BART Review January 15, 2010

29 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 Sooner station is located with in 300 km of 1 Class I area. 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 10.4 times more cost effective than DFGD controls at the Sooner 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 $10,00 0,000/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 sourc e 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 restr icting 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 all owance 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

Sooner facility that would be more stringent than the scrubber can deliver. Fortuna tely, 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 pa y for additional required mercury control technology.

The cost for DFGD is too high, the benefit to o low and these costs, if borne, further extend the life expectancy of coal as the primary fuel in the Sooner facility for at least 20 years and beyond.

BA RT is the continued use of low sulfur coal.

Wet FGD was not determined to be BART for SO 2 control for Units 1 and 2 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. B ased on projected emissions, WFGD could reduce overall SO 2 emissions from

Sooner Units 1 and 2 by approximately 8 08 TPY beyond dry scrubbers; however, the incremental cost associated with this reduction is approximately $ 18

, 854 /ton.

2. SO 3 remaining in the fl ue 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). Ho wever, 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 SO 2 controls.

3. Wet FGD systems must be located downstream of the unit’s partic ulate 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.OG&E Sooner Generating Station BART Review January 15, 2010

30 4. Wet FGD sys tems 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

wastewa ter 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

disc harged 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. Beca use of a slower exit velocity, lower stack temperature and higher SO 4 emissions associated with Wet FGD, visibility impairment was found to higher under this control strategy than the Dry

FGD

.

PM 10 The existing ESP control is determined to be BART for PM 10 controls for Units 1 and 2 based on

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

emissions of PM 10 from the facility.

Table 2 1 : Unit

- by

- unit BART determinations

Control Unit 1 Unit 2

NO X 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 767 lb/hr (30

- day rolling average), 767 lb/hr (30

- day rolling average),

Emission Rate TPY 3,361 TPY (12

- month rolling) 3,361 TPY (12

- month rolling)

SO 2 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, 325 lb/hr (30

- day rolling averag e) 3, 325 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 19,736 TPY

PM 10 Control Existing ESP Existing ESP
Emission Rate (lb/mmBtu) 0. 1 lb/mmBtu 0. 1 lb/m mBtu

Emission Rate lb/hr 512 lb/hr 512 lb/hr

Emission Rate TPY 2,241 TPY (12

- month rolling average) 2,241 TPY (12

- month rolling average)OG&E Sooner 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 SO 2 control, the low

- sulfur coal requirement in the BART determination for SO 2 and the related ESP requirement for PM referenced above shall be replaced with a requirement that So oner Units 1 and 2 install DFGD

with SDA for SO 2 control and fabric filters for PM control or meet the corresponding SO 2 and

PM 10 emission limits listed below by December 31 , 2018 or comply with the approved alternative described in section G (Greater Reas onable Progress Alternative).

Table 2 2 : Unit

- by

- unit Contingent BART determinations

Control Unit 1 Unit 2

SO 2 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 R ate lb/hr 5 12 lb/hr (30

- day rolling average) 5 12 lb/hr (30

- day rolling average)

Emission Rate TPY 2, 241 TPY 2, 241 TPY

PM 10 Control Fabric Filter Fabric Filter
Emission Rate (lb/mmBtu) 0.0 15 lb/mmBtu 0.0 15 lb/mmBtu

Emission Rate lb/hr 77 lb/hr 77 lb/ hr

Emission Rate TPY 3 3 6 TPY (12

- month rolling average) 3 36 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 reduct ions in SO 2 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. How ever, if EPA chooses to ignore that element of the BART determination, DEQ does agree that DFGD remains an achievable control option for SO 2 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 rate payers 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 SO 2 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 a nnual SO 2 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 SO 2 emission that would result from switching theOG&E Sooner Generating Station BART Review January 15, 2010

32 remaining two boiler to natural gas. Under this alternativ e 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 SO 2 emissions from Sooner Units 1 and 2 and Muskogee Units 4 and 5 to be ap proximately 57% less than would be achieved through the installation and operation of DFGD with SDA at all four units (assuming 90% capacity).

Table 23: SO 2 Emissions with Greater Reasonable Progress Muskogee Sooner

Parameter Unit 4 and Unit 5 Unit 1 an d 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 achie ved either through the DEQ determined BART or the “contingent” BART. By allowing the installation of SO 2 controls to be delayed, current regulatory hurdles to long term natural gas contracts can be addressed and the best interests of the ratepayers and vi sitors 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)

Sooner Generating Station is a major source under OAC 252:100

- 8 Permits for Part 70 Sou rces. 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 Sooner Station. The permit application should contain PM 10 and PM 2.5 emission estimates for filterable and condensable

emissions.

VI. OPERATING PERMIT

The Sooner Generating Station is a major source under OAC 252:100

- 8 and has submitted an application to modify their existing Ti tle 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 are sub ject 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 Sooner Generating Station BART Review January 15, 2010

33 EU ID# Point

ID# EU Name H eat Capacity (MMBTUH) Construction

Date

2

- B 01 Unit 1 Boiler 5,116 19 74

2

- B 02 Unit 2 Boiler 5, 116 19 74

b. Each existing affected facility shall install and operate the SIP approved BART as expeditiously as practicable but in no later than five years afte r 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 emiss ion 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 NO X to below the emission limits below:

i. Low

- NO X Burners,

ii. Overfire Air

.

e. The permittee shall maintain the controls (Low

- NOX burners, overfire air ) and establish procedures to ensure the controls are properly operated and maintained.

f. Within 60 days of achieving maximum power output from each affected facility, after modification or installation of BART, not to exceed 180 days from initial

start

- up of the affected facility the permittee shall comply with the emission limits established in the construction permit. The emission limits established in the construction permit shall be consistent with manufacturer’s data and an agreed upon safety factor. The emission limits established in the construction permit

shall not exceed the following emission limits:

EU

ID# Point

ID# NO X Emission Limit SO 2

Emission Limit Averaging

Period

2

- B 01 0.15 lb/mmBtu 0. 65 lb/mmBtu 30

- day rolling

2

- B 02 0.15 lb/mmBtu 0. 65 lb/mmBtu 30

- day rolling

EU ID# Point ID# PM 10 2

- B 01 0. 1 lb/mmBtu

2

- B 02 0. 1 lb/mmBtu

EU

ID# Point

ID# SO 2 Emission Limit SO 2

Emission Limit Averaging

Period

2

- B 01 19,736 0. 55 lb/mmBtu Annual ro lling

2

- 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, theOG&E Sooner Generating Station BART Review January 15, 2010

34 permittee shall conduct performance testing as follows and furnish a written report to Air Quality. Su ch report shall document compliance with BART

emission limits for the affected facilities. [OAC 252:100

- 8

- 6(a)]

i. The permittee shall conduct SO 2 , NO X , PM 10 , PM 2.5 , CO, and VOC testing on the boilers at 60% and 100% of the maximum capacit y. 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 des cribing 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.