## Oklahoma Department of Environmental Quality

Air Quality Division

BART Application Analysis September 2 8 , 2009

COMPANY: Oklahoma Gas and Electric

FACILITY: Seminole Generating Station

FACILITY LOCATION: Konawa, Seminole County, Oklahoma

TYPE OF OPERA TION: (3) 567 MW Steam Electric Generating Units

REVIEWER: Phillip Fielder, Senior Engineering Manager Lee Warden, Engineering Manager

I. PURPOSE OF APPLICATION

On July 6, 2005, the U.S. Environmental Protection Agency (EPA) published the final “Regio nal 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 R egional 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 sour ces 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).

Seminole Units 1, 2 and 3 are fossil

- fue l fired boiler s with heat inputs greater than 250

- mmBtu/hr. All three units were in existence prior to August 7, 1977, but not in operation prior to August 7, 1962. Based on a review of existing emissions data, all three units have the potential

to emit more than 250 tons per year of NO X , a visibility impairing pollutant. Therefore, Seminole Units 1, 2 and 3 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.OG&E Seminole Generating Station BART Evaluation September 28, 2009

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, m easured 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 Seminole Units 1, 2 and 3 exceeded the 0.5 Δ

- dv t hreshold at the Wichita Mountains Class I Area. Therefore, Seminole Units 1, 2 and 3 were determined to be BART applicable sources, subject to the BART determination requirements.

III. DESCRIPTION OF BART SOURCES

Baseline emissions from Seminole Units 1 , 2 and 3 were developed based on an evaluation of actual emissions data submitted by the facility pursuant to the federal Acid Rain Program. In accordance with EPA guidelines in 40 CFR 51 Appendix Y Part III, emission estimates used in

the modeling analy sis to determine visibility impairment impacts should reflect steady

- state operating conditions during periods of high capacity utilization. Therefore, baseline emissions (lb/hr) represent the highest 24

- hour block emissions reported during the baseline p eriod.

Baseline emission rates (lb/mmBtu) were calculated by dividing the maximum hourly mass

emission rates for each boiler by the boiler’s full load heat input.

Table 1 : Seminole Generating Station

- Plant Operating Parameters for BART Evaluation

Param eter Seminole Unit 1 Seminole Unit 2 Seminole Unit 3 Plant Configuration Natural Gas

- Fired

Boiler Natural Gas

- Fired

Boiler Natural Gas

- Fired

Boiler Firing Configuration Wall

- fired Wall

- fired Wall

- fired Gross Output (nominal) 567 MW 567 MW 567 MW

Maximu m Input to

Boiler 5,480 mm B tu /hr 5,480 mmB tu /hr 5,4 96 mmB tu /hr

Primary Fuel Natural gas Natural gas Natural gas Existing NO X Controls None None Flue gas recirculation Existing PM 10 Controls NA NA NA Existing SO 2 Controls NA NA NA

Baseline Emissions

P ollutant Baseline Actual

Emissions Baseline Actual

Emissions Baseline Actual

Emissions

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

NO X 1,859 0.339 1,940 0.354 1,204 0.219OG&E Seminole Generating Station BART Evaluation September 28, 2009

3 IV. BEST AVAILABLE RETROFIT TECHNOLOGY (BART)

Guidelines for making BART d eterminations 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.

Because the units fire natural gas , emissions of sulfur dioxide (SO 2 ) and particulate matter (PM)

a re minimal. There are no SO 2 or PM post

- combustion control technologies with a practical application to natural gas

- fired boilers. BART is good combustion practices. A full BART analysis was conducted for NO X

.

Table 2 : Proposed BART Controls and Lim its

Unit NO X BART Emission Limit BART Technology

Seminole Unit 1 0.203 lb/ mmBtu (30

- day average) Combustion controls including

LNB/OFA and FGR

Seminole Unit 2 0.212 lb/ mmBtu (30

- day average) Combustion controls including

LNB/OFA and FGR

Seminole Unit 3 0.164 lb/ mmBtu (30

- day average) Combustion controls including

LNB/OFA and FGR

A. NO X

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

available information. NO X co ntrol technologies with potential application to Seminole Units 1,

2 and 3 are listed in Table 3

. 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) Selective Catalytic Reduction (SCR) Innovative Control Technologies Rotating Overfire Air (ROFA) ROFA + SNCR (Rotamix)

Pahlman Process

Wet NO X ScrubbingOG&E Seminole Generating Station BART Evaluation September 28, 2009

4 In support of the Reg ional Haze Rule, EPA also prepared a cost

- effectiveness analysis for retrofit control technologies on oil

- and gas

- fired units. EPA’s analysis concluded that, although a

number of oil

- and gas

- fired units could make significant cost

- effective reductions i n NO X emissions using currently available combustion control technologies, for a number of units the use of combustion controls did not appear to be cost effective. As a result, EPA determined that it would be inappropriate to establish a general presumpti on regarding likely BART limits for

oil

- and natural gas fired units.

ELIMINATE TECHICALLY INFEASIBLE OPTIONS (NO X )

Combustion Controls:

Low NO X burners (LNB)/ Over Fire Air (OFA)

Low NO X burners (LNB) limit NO X formation by controlling both the stoichiom etric and temperature profiles of the combustion flame in each burner flame envelope. Over Fire Air (OFA) allows for staged combustion. Staging 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 natural gas

- fired boilers. Boilers of the size and age of the Seminole Units would be expected to achieve an average emission reduction in the range of 25% to 40% from baseline depending on the baseline emission rate and boiler operating conditions. Seminole units 1, 2, and 3 do not op erate as base load units

. The units have historically operated as “peaking units” responding to increased demand for electr icity. While technically feasible, LNB/OFA may not be as effective under all boiler operating conditions, especially during load changes and at low and high operating loads. Based on information available from burner control vendors and engineering judgm ent, it is expected that LNB/OFA on the wall

- fired boilers can be designed to achieve an average efficiency of 25% from baseline emissions under all normal operating

conditions.

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, consisting of products which are inert during combustion, lowers the combustion temperatures; and (2) the recy cled gas will reduce the oxygen content in the primary flame zone. The amount of recirculation is based on flame stability. Seminole Unit 3 is currently designed

with FGR control.

FGR may be applied in one of two techniques. Both designs are technically feasible retrofit options for gas

- boilers. Either system would be expected to achieve an additional 15% reduction above LNB/OFA or approximately 40% overall reduction from baseline.

Post Combustion Controls:

Selective Non

- Catalytic Reduction

Selective n on

- catalytic reduction (SNCR) involves the direct injection 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 reductio n reactions

diminish and NH 3 emissions increase. Above the desired temperature range, NH 3 is oxidized toOG&E Seminole Generating Station BART Evaluation September 28, 2009

5 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 per formance. 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 g as, reducing overall efficiency. Performance is further influenced by residence time, reagent

- to

- NO X ratio, and fuel sulfur content.

The size of the Seminole Units would represent several design problems making it difficult to ensure that the reagent wou ld 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 Seminole boilers makes it technically infeasible to locate and install ammonia injection points capable of achieving

a dequate mixing within the required temperature zone. Higher reagent injection rates would be required to achieve adequate mixing. This design would tend to result in relatively high levels of

ammonia slip. Further, because the Seminole boilers are typic ally used as peaking units, boiler load is continually changing. Boiler load changes affect flue gas flow rates and temperatures, which would make it particularly difficult to inject the needed quantity of reactant.

Installation of SNCR on large boiler s, such as those at Seminole, has not been demonstrated in practice. Assuming that SNCR could be installed on the Seminole Units, given the issues addressed above, control effectiveness would be marginal, and depending on boiler exit temperatures, could a ctually result in additional NO X formation. SNCR is not a technically

feasible retrofit control for the Seminole 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 gas

- fired boilers. Based on

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

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

- term average
NO X emission rates in the range of approximately 0.02 to 0.05 lb/mmBtu. Several desi gn 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 temperature, and catalyst activity.

Based on emission rates achieved in practice at existing gas

- fired units, and taking into consideration long

- term operation of an SCR control system (including catalyst plugging and deactivation) and the fact that the Seminole boilers typically operate as peaking units, it is anticipated that SCR could achieve a controlled NO X emission rate of 0.04 lb/mmBtu (30

- day rolling average) on Seminole Units 1, 2 and 3.

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,OG&E Seminole Generating Station BART Evaluation September 28, 2009

6 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.

As discussed in 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 Seminole Units 1, 2 an d 3. However, there is no technical basis to conclude that the ROFA design would provide additional NO X 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 discusse d in the SNCR section, including the physical size of the boiler, inadequate NH3/ NO X 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 unr esolved technical difficulties. Therefore, like other SNCR control systems, the Rotamix system is not a technically feasible retrofit control

for the Seminole 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 NO X and SO 2 from the flue gas.

To date, bench

- and pilot

- scale testing have been co nducted to evaluate the technology on utility

sized boilers.9 The New & Emerging Environmental Technologies (NEET) Database identifies the development status of the Pahlman Process as full

- scale development and testing. 10 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 test ing to evaluate the technical feasibility and long

- term effectiveness of the control system on Seminole Units 1, 2 and 3. BART does not require applicants to experience extended time delays or resource penalties to allow research to be conducted on an emer ging control technique. Therefore, at this time the Pahlman Process is not a technically feasible retrofit control for the

Seminole Boilers

Wet NO X Scrubbing Systems Wet scrubbing systems have been used to remove NO X emissions from fluid catalytic crackin g 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 NO 2 to N 2 O 5 . This highly oxidiz ed 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 a nd smaller coal

- fired boilers. The NEET Database classifies wet scrubbing systems as commercially established forOG&E Seminole Generating Station BART Evaluation September 28, 2009

7 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 NO X scrubbing systems are not technically feasible retrofit

controls for the Seminole Boiler s

EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (NO X )

Table 4 : Technically Feasible NO X Control Technologies

- Seminole Station

Control Technology Seminole Unit 1 Seminole Unit 2 Seminole Unit 3 Approximate NO X Emission Rate (lb/mmBtu) Approximate NO X

Emission Rate (lb/mmBtu) Approximate NO X

Emission Rate (lb/mmBtu)

LNB/OFA + SCR 0.04 0.04 0.04

LNB/OFA + FGR 0.203 0.212 0.164

LNB/OFA 0.254 0.266 NA

Baseline 0.339 0.354 0.219

EVALUATE IMPACTS AND DOCUMENT RESULTS (NO X )

OG&E evaluated the economic , environmental, and energy impacts associated with the th r ee 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 pub licly 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 Seminole Units 1, 2 and 3 with the control technologies. Fixed and variable O& M costs were developed for each control system. Fixed O&M costs include operating labor, maintenance labor, maintenance material, and administrative labor. Variable O&M costs include the cost of consumables, including reagent (e.g., ammonia), byproduct m anagement, 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 require ments 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 2 5 years. OG&E provided a summary of historical capacity

factors whi ch typically ranged between approximately 25% to 30%. Annual operating costs and annual emission reductions were calculated assuming a capacity factor of 50%.OG&E Seminole Generating Station BART Evaluation September 28, 2009

8 T able 5 : Economic Cost Per Boiler

Cost Unit Option 1:

LNB/OFA Option 2:

LNB/OFA

w/FGR Option 3:

LNB/OFA +SCR

Control Equipment Capital

Cost ($) Unit 1 $ 9

, 432

, 200 $ 16

, 977

, 200 $ 104

, 230

, 200

Unit 2 $ 9

, 432

, 200 $ 16

, 977

, 200 $ 104

, 230

, 200

Unit 3 $ 9

, 468

, 600 $ 9

, 468

, 600 $ 104

, 834

, 200

Capital Recover Factor ($/Yr) Unit 1 $ 809

, 300 $ 1

, 456

, 700 $ 8

, 943

, 000

Uni t 2 $ 809

, 300 $ 1

, 456

, 700 $ 8

, 943

, 000

Unit 3 $ 812

, 400 $ 812

, 400 $ 8

, 994

, 800

Annual O&M Costs ($/Yr) Unit 1 $ 588

, 600 $ 1

, 190

, 900 $ 8

, 152

, 800

Unit 2 $ 588

, 600 $ 1

, 190

, 900 $ 8

, 175

, 600

Unit 3 $ 590

, 800 $ 590

, 800 $ 8

, 023

, 800

Annual Cost of Control

($) Unit 1 $ 1

, 397

, 900 $ 2

, 647

, 600 $ 17

, 095

, 800

Unit 2 $ 1

, 397

, 900 $ 2

, 647

, 600 $ 17

, 118

, 600

Unit 3 $ 1

, 403

, 200 $ 1

, 403

, 200 $ 17

, 018

, 600

Table 6 : Environmental Costs per Boiler

Baseline Option 1:

LNB/OFA Option 2:

LNB/OFA

w/FGR Option 3:

LNB/OFA

+SCR

NO X Emission

Rate (lb/mm Btu) Unit 1 0.339 0.254 0.203 0.04

Unit 2 0.354 0.266 0.212 0.04

Unit 3 0.219 0.164 0.164 0.04

Annual NO X Emission (TPY) 1 Unit 1 4,068 3,048 2,436 480

Unit 2 4,248 3,192 2,544 480

Unit 3 2,636 1,974 1,974 481

Annual NO X Reduction (TPY) Unit 1

-- 1020 1632 3588

Unit 2 1056 1704 3768

Unit 3 662 662 2155

Annual Cost of

Control 2 Unit 1 $ 1

, 397

, 900 $ 2

, 647

, 600 $ 17

, 095

, 800

Unit 2 $ 1

, 397

, 900 $ 2

, 647

, 600 $ 17

, 118

, 600

Unit 3 $ 1

, 403

, 200 $ 1

, 403

, 200 $ 17

, 018

, 600

Cost per Ton

of Reduction Unit 1 $ 1

, 370 $ 1

, 622 $ 4

, 765

Unit 2 $ 1

, 324 $ 1

, 554 $ 4

, 543

Unit 3 $ 2

, 120 $ 2

, 120 $ 7

, 897

Incremental Cost per ton of

Reduction 3 Unit 1 N/A

-- $ 2

, 042 $ 7

, 387

Unit 2 $ 1

, 929 $ 7

, 011

Unit 3

-- $ 10

, 459

(1) Emissions for the BART analysis are based on maximum hea t inputs of 5,480 mmBtu/hr (Units 1 & 2) and 5,496 mmBtu/hr (Unit 3). Annual emissions were calculated assuming 4,380 hours/year per boiler (50% capacity factor).

(2) Total annual cost for all three units are not additive because Unit 3 is currently equipp ed with FGR control and Unit 3 has a slightly higher heat input.

( 3 ) Incremental cost effectiveness of the FGR system is compared to costs/emissions associated with LNB/OFA controls. Similarly, incremental cost effectiveness of the SCR system is compared t o costs/emissions associated with

LNB/OFA+FGR controls.OG&E Seminole Generating Station BART Evaluation September 28, 2009

9 B. VISIBILITY IMPROVEMENT DETERMINATION

The fifth of five factors that must be considered for a BART determination analysis, as required by a 40 CFR part 51

- Appendix Y, is the degree of Class I ar ea visibility improvement that would result from the installation of the various options for control technology. This factor was

evaluated for the Seminole Generating Station by using an EPA

- approved dispersion modeling system (CALPUFF) to predict the cha nge in Class I area visibility . The Division had previously determined that the Seminole Generating Station was subject to BART based on the results of initial screening modeling that was conducted using current (baseline) emissions from the facility . Th e 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 the Seminole Generating Stati on, as shown in Figure 1 below.

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

Figure 1: Plot of Facili ty location in relation to nearest Class I areasOG&E Seminole Generating Station BART Evaluation September 28, 2009

10 REFINED MODELING : Because of the results of the applicants screening modeling for the Seminole Generating Station, OG&E was required to conduct a refined BART analysis that included CALPUFF visibility

mode ling 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 CALMET modeling protocol

, CALMET Data Processing Protocol (Trinity Consultants, January 2008)

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

- preferred modeling system for lon g

- 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 k m 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). T he 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 d evelops 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 ca n 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 t o 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 ta ble below.OG&E Seminole Generating Station BART Evaluation September 28, 2009

11 Table 7 : Key Programs in CALPUFF System Program Version Level

CALMET 5.53a 040716

CALPUFF 5.8 070623

CALPOST 5.51 030709

Meteorological Data Processing (CALMET) As required by the Division’s modeling protocol, the CALMET model was used to construct the

initial three

- dimensional wind field using data from the MM5 model. Surface and upper

- air data were also input to CALMET to adjust the initial wind field

.

The following table lists the key user

- defined CALMET settings that were selected.

Table 8: CALMET Variables

Variable Description Value

PMAP Map projection LCC (Lambert Conformal Conic)

DGRIDKM Grid spacing (km) 4

NZ Number of layers 12

ZFACE Cell face heights (m) 0, 20, 40, 60, 80, 100, 150, 200, 250 , 500, 1000, 2000,

3500

RMIN2 Minimum distance for extrapolation - 1

IPROG Use gridded prognostic model

outputs 14 km (MM5 data)

RMAX1 Maximum radius of influence (surface layer, km) 20 km

RMAX2 Maximum radius of influence (layers aloft, km) 50 km

TERRAD Radius of influence for terr ain (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

.OG&E Seminole Generating Station BART Evaluation September 28, 2009

12 Figure 2: Plot of surface station locations

Figure 3: Plot of upper air station locationsOG&E Seminole Generating Station BART Evaluation September 28, 2009

13 Figure 4. Plot of precipitation observation stations

CALPUFF Modeling Setup To allow chemical transformations within CALPUFF using the recommended chemistry mechanism (MESO PUFF 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 CALPUF F 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 O ptions The first step in the refined modeling analysis was to perform visibility modeling for current (baseline) operations at the facility. Emissions of NO X for the baseline runs were established

based on CEM data and maximum 24

- hour emissions averages f or years 2001 to 2003. All particulate emissions (PM) were based on emission rate s of 0.00186 lb/mmBtu (filterable) and

were treated as PM 10 (coarse PM) and 0.00559 lb/mmBtu (condensable) and were treated as

PM 2.5 (fine PM) within CALPUFF and CALPOST. Di rect emissions of sulfate were based on

the values calculated for the Toxic Release Inventory (TRI) for the years modeled.

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

tables with data for the various control options. No attempt was made by the applicant to estimate the increase in sulfate emissions that would result from operations of SCR, and as aOG&E Seminole Generating Station BART Evaluation September 28, 2009

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

undetermined amount.

Table 9 : Baseline Source Parameters

Parameter Baseline

Natural Gas

- Fired

Unit 1 Natural Gas

- Fired

Unit 2 Natural Gas

- Fired

Unit 3 (FGR) Heat Input (mmBtu/hr ) 5

, 480 5

, 480 5

, 496 Base Elevation (m) 290 290 290 Stack Height (m) 54.27 54.27 106.71

Stack Diameter (m) 4.57 4.57 5.49 Stack Temperature (K) 392.44 392.44 411.89 Exit Velocity (m/s) 42.32 42.32 30.95 SO2 Emissions (lb/mmBtu) 0.00055 0.00042 0.00060 SO2 Emissions (TPY) 13.20 10.08 14.44

NOX Emissions 1 (lb/mmBtu) 0.339 0.354 0.219

NOX Emissions TPY 8136.81 8496.85 5271.87

PM 10 Fine Emissions 2

(lb/mmBtu) 0.00745 0.00745 0.00745

PM 10 Fine Emissions (TPY) 178.82 178.82 179.34

1 Baseline NOx emissions were based on the maximum 24

- hr average emission rate (lb/hr) reported by each unit during the baselin e period 2003

- 2005. 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 PM emissions are based on AP

- 42 emission fact ors for natural gas combustion (filterable and condensable).

Table 10: Source Parameters and Emissions for BART Control Options

Scenario Control Heat Input (mmBtu/hr) NOX

Emissions (lb/mmBtu) NOX

Emissions

TPY

Control Option 1 LNB/OFA 5

, 480 0.254 6,09 7

Natural Gas

Fired

Unit 2 LNB/OFA 5

, 480 0.266 6,384

Natural Gas

Fired

Unit 3 LNB/OFA

FGR 5

, 496 0.164 3,948

Control Option 2 Natural Gas

Fired

Unit 1 LNB/OFA

FGR 5,480 0.203 4,872

Natural Gas

Fired

Unit 2 LNB/OFA

FGR 5,480 0.212 5,089

Natural Gas

Fired

Unit 3 LNB/OFA

FGR 5,496 0.164 3,948OG&E Seminole Generating Station BART Evaluation September 28, 2009

15 Scenario Control Heat Input (mmBtu/hr) NOX

Emissions (lb/mmBtu) NOX

Emissions

TPY

Control Option 3 Natural Gas

Fired

Unit 1 LNB/OFA +

SCR 5,480 0.040 960

Natural Gas

Fired

Unit 2 LNB/OFA +

SCR 5,480 0.040 960

Natural Gas

Fired

Unit 3 LNB/OFA +

SCR 5,496 0.040 963

Visibility Post

- Processi ng (CALPOST) Setup The changes in visibility were calculated using Method 6 with the CALPOST post

- processor. Method 6 requires input of monthly relative humidity factors [f(RH)] for each Class I area that is being modeled. Monthly f(RH) factors that were used for this analysis are shown in the table

below.

Table 11 : Relative Humidity Factors for CALPOST

Month Wichita

Mountains Caney Creek Upper Buffalo Hercules Glade January 2.7 3.4 3.3 3.2 February 2.6 3.1 3.0 2.9

March 2.4 2.9 2.7 2.7 April 2.4 3 .0 2.8 2.7 May 3.0 3.6 3.4 3.3

June 2.7 3.6 3.4 3.3 July 2.3 3.4 3.4 3.3 August 2.5 3.4 3.4 3.3 September 2.9 3.6 3.6 3.4

October 2.6 3.5 3.3 3.1

November 2.7 3.4 3.2 3.1

December 2.8 3.5 3.3 3.3

EPA’s default average annual aerosol concentration s 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

.OG&E Seminole Generating Station BART Evaluation September 28, 2009

16 Visibility Post

- Processing Results

Tab le 12 : CALPUFF Visibility Modeling Results for Seminole Units 1, 2 and 3

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 1.073 20 0.744 12 1.3 25 1.039 19

Caney Creek 1.173 18 0.455 7 0.443 7 0.69 11 Upper Buffalo 0.635 9 0.24 2 0.302 2 0.39 4

Hercules

Glade 0.403 5 0.294 3 0.301 3 0.33 4

Scenario 2

- Combustion Control

- LNB/OFA FGR

Wichita

Mountains 0.707 13 0.476 7 0.832 17 0.67 12

Caney Creek 0.75 4 12 0.284 1 0.284 2 0.44 5 Upper Buffalo 0.411 4 0.157 2 0.191 1 0.25 2

Hercules

Glade 0.255 2 0.186 0 0.188 2 0.21 1

Modeling for SCR controls resulted in an approximately 80% reduction in visibility impairment

from scenario two.

C. BART DETERMINAT ION

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 o f improvement in visibility (all five statutory factors) from each proposed control technology, the Division determined BART for the three units at the Seminole Generating Station.

New LNB with OFA is determined to be BART for NOX control for Units 1

- 3 ba sed, in part, on the following conclusions:

1. Installation of new LNB with OFA and FGR was cost effective, with a capital cost of $16,977,200 per unit for units 1 and 2 and $9,468,600 for unit 3 and an average cost effectiveness of $1,554

- $2,120 per ton of NO X removed for each unit over a twenty year operational life.

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

- air quality environmental mitigation for the use of chemical reagents (i.e., ammonia or urea) and there is minimal energy impa ct.OG&E Seminole Generating Station BART Evaluation September 28, 2009

17 3. After careful consideration of the five statutory factors, especially the costs of compliance and existing controls, NO X control levels on 30

- day rolling averages of 0.203 lb/mmBtu for Unit 1, 0.212 lb/mmBtu for Unit 2 and 0.164 lb/mmBtu for Unit 3 ar e justified.

4. Annual NO X emission reductions from new LNB with OFA and FGR on Units 1, 2, and 3

are 662

- 1,704 tons for a total annual reduction of 3,998 tons.

LNB with OFA and SCR was not determined to be BART for NO X control for Units 1

- 3 based, in part , on the following conclusions:

1. The cost of compliance for installing SCR on each unit is significantly higher than the cost for LNB with OFA and FGR. Additional capital costs for SCR on Units 1

- 3 are on average $89,957,200 per unit. Based on projected actual emissions, SCR could reduce

overall NO X emissions from Seminole Units 1, 2 and 3 by approximately 5,513 tpy (compared to combustion controls and flue gas recirculation); however, the incremental cost associated with this reduction is approximately $ 44,534,600 per year, or $8,078/ton.

2. Additional non

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

reagents.

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

4. SCR control may not be as effective on boilers that operate as peaking units, as NO X reduction in an SCR is a function of flue gas temperature.

5. The cumulative visibility improvement for SCR, as compared to LNB/OFA and FGR across Wichita Mountains and Caney Creek (based on the 98 th percenti le modeled results) was 0.56

- 0.60
Δdv for all three units.

The Division considers the installation and operation of the BART determined NO X controls, new LNB with OFA and FGR, to meet the statutory requirements of BART.

Unit

- by

- unit NO X BART determinatio ns:

Seminole Generating Station Unit 1: New LNB with OFA and FGR and meeting NO X emission limit of 0.203 lb/mmBtu (30

- day rolling average), 1,112 lb/hr (30

- day rolling average), and 4,872 tpy (12

- month rolling) as BART for NO X

.

Seminole Generating Stati on Unit 2: New LNB with OFA and FGR and meeting NO X emission limit of 0.212 lb/mmBtu (30

- day rolling average), 1,162 lb/hr (30

- day rolling average), and 5,089 tpy (12

- month rolling) as BART for NO X

.

Seminole Generating Station Unit 3: New LNB with OFA and FGR and meeting NO X emission limit of 0.164 lb/mmBtu (30

- day rollingOG&E Seminole Generating Station BART Evaluation September 28, 2009

18 average), 901 lb/hr (30

- day rolling average), and 3,948 tpy (12

- month rolling) as BART for NO X

.

V. CONSTRUCTION PERMIT

Prevention of Significant Deterioration (PSD)

Seminole Generati ng 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 Seminole Station.

VI. OPERATING PERMIT

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

- 8 and has submitted an appli cation 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 subject to the Best Available Retrofit Tech nology (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 fa cilities and are subject to the requirements of this Specific Condition, the Protection of Visibility and Regional Haze Requirements of 40 CFR Part 51, and all applicable SIP requirements:

EU ID# Point

ID# EU Name Heat Capacity (MMBTUH) Construction

Date

2

- B 01 Unit 1 Boiler 5,480 1968

2

- B 02 Unit 2 Boiler 5,480 1968

2

- B 03 Unit 3 Boiler 5,496 5/28/70

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 ap proval 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

emis sions of NOX to below the emission limits below:

i. Low

- NOX Burners,

ii. Overfire Air, andOG&E Seminole Generating Station BART Evaluation September 28, 2009

19 iii. Flue Gas Recirculation.

e. The permittee shall maintain the combustion controls (Low

- NOX burners, overfire air, and flue gas recirculation) 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. T he emission limits established in the construction permit shall not exceed the following emission limits:

EU ID# Point ID# NOX Emission Limit Averaging Period

2

- B 01 0.203 lb/MMBTU 30

- day rolling

2

- B 02 0.212 lb/MMBTU 30

- day rolling

2

- B 03 0.164 lb/MMB TU 30

- day rolling

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

Da.

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

i. Within 60 days of achieving maximum power output from each boiler, after modification of the boilers, not to exceed 180 days from initial start

- up, the permittee shall conduct performance testing as follows and furnish a written report to Air Quality. Suc h report shall document compliance with BART

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

- 8

- 6(a)]

i. The permittee shall conduct NOX, CO, and VOC testing on the boilers at 60% and 100% of the maximum capacity. NOX and CO test ing 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 tes ting 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.

iii. The following USEPA methods shall be used for testing of emissions, unless otherwise approved by Air Quality:

Method 1: Sample and Velocity Traverses for Stationary Sources.

Method 2: Determination of Stack Gas Velocity and Volumetric Flow

Rate.

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

Molecular Weight.