## Oklahoma Department of Environmental Quality

Air Quality Division

BART Application Analysis January 1 9 , 2010

COMPANY: A EP

- Public Service Company of Oklahoma

FACILITY: Northeastern Power Plant

FACILITY LOCATION: Rogers C ounty , Oklahoma

TYPE OF OPERATIO N: ( 1 ) 495 MW Natural Gas

- Fired Steam Electric Generating Unit (2) 490 MW Coal

- Fired 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, includ ing 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 im plement the regional haze requirements (the Regional Haze SIP). The Regional Haze SIP must provide for a Best Available Retrofit Technology (BART) analysis of any existing stationary facility that might cause or contribute to impairment of visibility in a Class I Area.

II. BART ELIGIBILITY DETERMINATION

BART

- eligible sources include those sources that: (1) have the potential to emit 250 tons or more of a visibility

- impairing air pollutant; (2) were in existence on August 7, 1977 but not in operation pri or 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 tha n 250 mmBtu/hr heat input).

Northeast Units 2, 3 and 4 are fossil

- fuel 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, the 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, Northeast Units 2, 3 and 4 meet the definition of BART

- eligible source s

.PSO Northeastern Power Plant BART Review January 1 9 , 2010

2 BART is required for any BART

- eligible source that emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I Area. DEQ has determined that an individual source will be considered to “contribute to visibili ty impairment” if emissions from the source result in a change in visibility, measured as a change in deciviews (Δ

- dv), that is greater than or equal to 0.5 dv in a Class I area. Visibility impact modeling conducted by AEP

- PSO determined that the maximum p redicted visibility impacts

from Northeast Units 2, 3 and 4 exceeded the 0.5 Δ

- dv threshold at t he Wichita Mountains, Caney Creek

, Upper Buffalo , and Hercules Glade Class I Area s . Therefore, Northeast Units 2, 3

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

III. DESCRIPTION OF BART SOURCES

Baseline emissions from Northeastern Units 2, 3 and 4 were developed based on an evaluation of actual emissions data submitted by the facility pursuant to the fede ral Acid Rain Program. In accordance with EPA guidelines in 40 CFR 51 Appendix Y Part III, emission estimates used in the modeling analysis to determine visibility impairment impacts should reflect steady

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

- hour block emissions reported during the baseline period. Baseline emission rates (lb/mmBtu) were calculated by dividing the average annual mass

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

2006.

Table 1 : Northeastern Power Plant

- Plant Operating Parameters for BART Evaluation

Parameter Northeastern Unit 2 Northeastern Unit 3 Northeastern Unit 4 Plant Configuration Natur al Gas

- Fired

Boiler Coal

- Fired Boiler C oal

- Fired Boiler

Firing Configuration Tangentially

- fired Tangentially

- fired

Gross Output (nominal) 495 MW 490 MW 490 MW

Maximum Input to

Boiler 4,754 mmBtu/hr 4

, 775 mmBtu/hr 4,775 mmBtu/hr

Maximum 24

- hour Average Input 4,767 mmBtu/hr 5,812 mmBtu/hr 5,594 mmBtu/hr

Primary Fuel Natural Gas Sub

- bituminous coal Sub

- bituminous coal Existing NO X Controls 1 st Generation

LNB/OFA 1 st Generation LNB/OFA 1 st Generation LNB/OFA

Existing PM 10 Controls NA Electrostatic preci pitator Electrostatic precipitator

Existing SO 2 Controls NA Low

- sulfur coal Low

- sulfur coal

Maximum 24

- hour Emissions (CALPUFF Model)

Unit 2 Unit 3 Unit 4

lb/hr lb/mmBtu lb/hr lb/mmBtu lb/hr lb/mmBtuPSO Northeastern Power Plant BART Review January 1 9 , 2010

3 NO X 3,385 0.71 3,116 0.536 2,747 0.491

SO 2 2.9 0 .0006 6,106 1.05 5,930 1.06

PM 10 35.4 0.007 220 0.038 330 0.059 Baseline Emissions (2004

- 2006)

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

NO X 1462 0. 4 49 1838 0.397 1827 0.404

SO 2 1.6 6 0.0006 4235 0.914 4102 0.907

IV. BEST AVAILABLE RETROFIT TEC HNOLOGY (BART)

Guidelines for making BART determinations are included in Appendix Y of 40 CFR Part 51 (Guidelines for BART Determinations under the Regional Haze Rule). States are required to use the Appendix Y guidelines to make BART determinations for f ossil

- 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. Elimina te Technically Infeasible Options. Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. Step 4. Evaluate Impacts and Document the Results. Step 5. Evaluate Visibility Impacts.

In the final Regional Haze Rule U.S.EPA established pre sumptive 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 pr ovide enough flexibility to States to consider source specific characteristics when evaluating

BART. The BART SO 2 presumptive emission limit for coal

- fired EGUs greater than 200 MW in size without existing SO 2 control is either 95% SO 2 removal, or an emis sion 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 Northeast Units 3

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

Table 2 : BART Controls and Limits

Unit NO X B ART Emission Limit BART Technology

Northeastern Unit 2 0.28 lb/mmBtu (30

- day average) Combustion controls including LNB/OFA

Northeastern Unit 3 0.15 lb/mmBtu (30

- day average) Combustion controls including LNB/OFA

Northeastern Unit 4 0. 15 lb/ mmBtu (30

- da y average) Combustion controls including LNB/OFA

Unit SO 2 BART Emission Limit BART Technology

Northeastern Unit 3 0. 65 lb/mmBtu (30

- day average) Low Sulfur Coal

Northeastern Unit 4 0. 65 lb/mmBtu (30

- day average) Low Sulfur Coal

Unit PM 10 BART Emission Limit BART Technology

Northeastern Unit 3 0. 1 lb/mmBtu (3

- hour average) 1 Existing ESPPSO Northeastern Power Plant BART Review January 1 9 , 2010

4 Northeastern Unit 4 0. 1 lb/mmBtu (3

- hour average) 1 Existing ESP

1 Current emissions limits for ESPs are based on minimum NSPS requirements for front half catch. As pa rt of the permitting process, PSO will be required to propose emission limits for

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

results.

A. 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 Northeast Units 2,

3 and 4 are listed in Table 3

. Table 3 : List of Potential Control Options

Control Technology

Combustion Controls Burners Out of Service (NE 2 only) Flue Gas Recirculation (FGR)

Low NO X Burners and Overfire Air (LNB/OFA)

Post Combustion Controls Selective Noncatalytic Reduction (SNCR) Selective Catalytic Reduction (SCR)

Re burning /Methane de

- NO X (MdN)

ELIMINATE TECHICALLY INFEASIBLE OPTIONS (NO X )

Combustion Controls: Burners Out of Service This option involves shutting off selected burners, resulting in reduced fuel usage and therefore lower emissions. This option would essentially reduce the maximum firing rate of the boiler, and place a load limit on the unit. The resulting load limits would effectively result in the shutdown of the unit and as a result, this option is considered technically infeasible.

Flue Gas Recir culation 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 c ombustion, 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 strat egy 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 particulate loading. In a coal

- fired applica tion, 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

O 2 concentration), FGR would not operate effectively as a NO X control system on a coal

- firedPSO Northeastern Power Plant BART Review January 1 9 , 2010

5 boiler. Therefore, FGR is not considered an applicable retrofit NO X control optio n for Northeast Units 3 and 4, and will not be considered further in the BART determination.

For Unit 2, Induced Flue Gas Recirculation (IFGR) would also place load limits on the boiler and call for plant equipment upgrades. As with the Burners Out of Se rvice option, IFGR is considered technically infeasible.

L ow NO X B urners (LNB) / Over F ire A ir (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 env elope. 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 techn ologies on existing coal

- fired boilers. Northeast Units 3 and 4 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. Bas ed on information available from burner control vendors and engineering judgment, it is expected that LNB/OFA on tangentially

- fired boilers can be designed to meet the presumptive NO X BART emission rate of 0.15 lb/mmBtu on

a 30

- day rolling average and unde r all normal operating conditions while maintaining acceptable

CO and VOC emission rates

.

For the natural gas

- fired Unit 2, OFA as a single NO X control technique may reduce NO X emissions by 25

- 55 percent. When combined with LNB, reductions of up to 60% m ay result. This technology is a feasible option for all three units.

Reburning/Methane De

- NO X In reburning, also known as “off

- stoichiometric combustion” or “fuel staging,” a fraction (5 to 25 percent) of the total fuel heat input is diverted to a second combustion zone downstream of the primary zone. The fuel in the fuel

- rich secondary zone acts as a reducing agent, reducing NO, which is formed in the primary zone, to N 2 . Generally, it is more economical for a facility to use the same fuel for reburning as it does for primary combustion, although there are exceptions. In order to use coal as a reburning fuel, it must be finely ground, which requires additional pulverizing equipment.

Methane de

- NO X (MdN) utilizes the injection of natural gas together w ith recirculated flue gases (for enhanced mixing) to create an oxygen

- rich zone above the combustion grate. OFA is then injected at a higher furnace elevation to burn out the combustibles. This process is claimed to yield between 50 and 70 percent NO X redu ction and to be suitable for all solid fuel

- fired stoker boilers. However, as of 2002, MdN had only been demonstrated for a short duration in one pulp mill wood

- fired stoker boiler that also burned small amounts of waste treatment plant residuals, with NO X reductions of 40 to 50 percent reported.

MdN is not considered feasible for the coal

- fired units because (1) it is not fully demonstrated and (2) it incorporates FGR, which is technically infeasible for all three units

.PSO Northeastern Power Plant BART Review January 1 9 , 2010

6 Post Combustion Controls:

Select ive Non

- Catalytic Reduction

Selective non

- catalytic reduction (SNCR) involves the direct injection of ammonia or urea at high flue gas temperatures. The ammonia or urea reacts with NO X in the flue gas to produce N 2 and water. At temperatures below the de sired operating range, the NO X reduction reactions

diminish and NH 3 emissions increase. Above 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 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 ac hieve good mixing of reagent and flue gas, reducing overall efficiency. Performance is further influenced by residence time, reagent

- to

- NO X ratio, and fuel sulfur content.

The size of the Northeastern Units would represent several design problems making it difficult to ensure that the reagent would be injected at the optimum f l ue gas temperature, and that there would be adequate mixing and residence time. The physical size of the Northeastern boilers makes it technically infeasible to locate and install ammonia injection points capable of achieving adequate mixing within the required temperature zone. Higher reagent injection rates would be required to achieve adequate mixing. Higher ammonia injection rates would result in relatively high levels of ammo nia 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 subbitumino us ash. Subbituminous coals typically contain high levels of calcium oxide and magnesium oxide that can result in reflective ash deposits on the waterwall surfaces. Because most heat transfer in the furnace is radiant,

reflective ash can result in less hea t 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 Northeastern , has not been demonstrated in practice. Assuming that SNCR could be installed on the Northeastern Units, given the issues addressed above, control effectiveness would be marginal, and depending on boiler exit temperatures, could actually result in additional NO X f ormation.

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 N 2 and water. Anhydrous ammonia injection systems may be used, or ammonia may be g enerated 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 4

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),

unc ontrolled NO X emission rate, flue gas temperature, and catalyst activity.PSO Northeastern Power Plant BART Review January 1 9 , 2010

7 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 cataly st plugging and deactivation) it is anticipated that SCR could achieve a controlled NO X emission

rate of 0.0 54 lb/mmBtu on Northeast Unit 3 and 0.049 lb/mmBtu on Unit 4

. The addition of

SCR controls to Unit 2 could result in a controlled NO X emission rate of 0.05 lb/mmBtu.

EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (NO X )

Table 4 : Technically Feasible NO X Control Technologies

- Northeastern Power Plant

Control Technology Northeastern Unit 2 Northeastern Unit 3 Northeastern Unit 4 Approximate NO X Em ission Rate (lb/mmBtu) Approximate NO X

Emission Rate (lb/mmBtu) Approximate NO X

Emission Rate (lb/mmBtu)

LNB/OFA + SCR 0.05 0.0 54 0.0 49

LNB/OFA 0.28 0.15 0.15

SNCR

-- 0.402 0.368

Baseline 0. 4 49 0.397 0.404

E VALUATE IMPACTS AND DOCUMENT RESULTS (NO X )

AEP

- PSO evaluated the economic, environmental, and energy impacts associated with the proposed control options. In general, the cost estimating methodology followed guidance provided in the EPA Air Pollution Cost Control Manual. Capital costs were devel oped by AEP

PSO and are based on equipment costs for similar projects, and include the equipment, material, labor, and all other direct costs needed to retrofit Northeast Units 2, 3 and 4 with the control technologies. Fixed and variable O&M costs were de veloped for each control system. Fixed O&M costs include operating labor, maintenance labor, maintenance material, and administrative labor. Variable O&M costs include the cost of consumables, including reagent (e.g., ammonia ) and auxiliary power require ments. Auxiliary power requirements reflect the additional power requirements associated with operation of the new control technology, including operation of any new fans as well as the power requirements for pumps, reagent handling, and by

- product handlin g. The capital recovery factor used to estimate the annual cost

of control was based on a n 8 % interest rate and a control life of 2 0 years. Annual operating costs and annual emission reductions were calculated assuming a capacity factor of 21% for Unit 2

and a capacity factor of 85% for SO 2 control effectiveness calculations for Units 3 and 4. No capacity factors were used for NO X control effectiveness calculations.

AEP

- PSO submitted initial cost estimates in 2008 that relied upon a baseline emission ra te 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 co ntrols than would be realized given actual annual average emissions. Using a representative annual average emission rate (2004

- 2006), the cost effectiveness ($/ton removed) is much higher, but the result is representative of more reasonably achievable emi ssions reductions.PSO Northeastern Power Plant BART Review January 1 9 , 2010

8 T able 5 : Economic Cost for Units 3 and 4 ( Coal

- Fired Boiler s)

Cost Option 1:

SNCR 2 Option 2:

LNB/OFA Option 3:

LNB/OFA +SCR 1
Total Capital Investment ($) $11,500,000 $17,000,000 $ 290

, 000

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

, 537,141 Annual O&M Costs ($/Yr) $13,602,120 $680,000 $1 8

, 248 ,6 6 0 Annual Cost of Control ($) $14,773,420 $2,411,488 $ 47

, 785

, 801

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

2 Costs associated with S NCR are greater than LNB/OFA with less potential reduction in emissions, no further review will be required.

Table 6 : Environmental Costs for Units 3 and 4 (Coal

- Fired Boiler )

Baseline LNB/OFA LNB/OFA +SCR

NO X Emission Rate (lb/mmBtu) Unit3 0.397 0.15 0 .054

NO X Emission Rate (lb/mmBtu) Unit4 0.404 0.15 0.049

Annual NO X Emission (TPY) 1 13,971 6,274 2,154

Annual NO X Reduction (TPY)

-- 7

, 697 11

, 817

Annual Cost of Control

-- $2,411,488 $47,785,801 Cost per Ton of Reduction

-- $313 $4,044

Incremental Co st per ton of Reduction 2

-- $11,013

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

- 2006 for Units 3 & 4

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

c ontrols.
Table 7 : Economic Cost for Unit 2 (Natural Gas

- Fired Boilers)

Cost Option 1:

LNB/OFA Option 2:

LNB/OFA +SCR 1
Total Capital Investment ($) $3,450,000 $ 94

, 743

, 000 Annualized Capital Cost ($/Yr) $351,390 $9,649,784 Annual O&M Costs ($/Yr) $138,000 $3,789,720 Annual Cost of Control ($) $489,390 $14,366,357

1 While not stated explicitly, costs for SCR are not assumed to encompass LNB/OFA based on the incremental cost analysis completed by the applicant.

Table 8 : Environmental Costs for Unit 2 (Natu ral Gas

- Fired Boiler)

Baseline Option 2:

LNB/OFA Option 3:

LNB/OFA +SCR

NO X Emission Rate (lb/mmBtu) Unit2 0.4 49 0.285 0.05

Annual NO X Emission (TPY) 1 2

, 861 1,246 219

Annual NO X Reduction (TPY)

-- 1615 2642

Annual Cost of Control $489,390 $14,366,357 Cost per Ton of Reduction $303 $5,438 Incremental Cost per ton of Reduction 2 $13, 512

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

- 2006 (2004 emissions are not reflective of annual averages

. Annual costs for LN B/OFA assumed a capacity factor of 0.21. The applicant used a capacity factor of 0.19 in the SCR evaluation; however, the analysis reported here reflects the 0.21 capacity factor documented in the original submittal.

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

controls.PSO Northeastern Power Plant BART Review January 1 9 , 2010

9 B. SO 2

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

available information . SO 2 control technologies with potential application to Northeast Units 3

and 4 are listed in Table 9

.

Table 9 : List of Potential Control Options

Control Technology

Pre

- Combustion Control

Wet Flue Gas Desulfurization Dry Flue Gas Desulfurization

- Spray Dryer Absorber

ELIMINATE TECHICALLY INFEASIBLE OPTIONS (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. Northeast Units 3 and 4 fire subb ituminous 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 coal; however,

subbituminous coal with l ower sulfur content is achievable and available. Fuel switching to a lower sulfur content coal is a viable option.

Coal Washing Coal washing, or beneficiation, is one pre

- combustion method that has been used to reduce impurities in the coal such as ash a nd 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 waste water 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 pyrite s and other dense inorganic impurities including silica and trace metals. The solids are typically dewatered in a mechanical dewatering device and disposed of in a landfill.

Northeast Units 3 and 4 are designed to utilize subbituminous coals. Based on a r eview of available information, no information was identified regarding the washability or effectiveness of washing subbituminous coals. Therefore, coal washing is not considered an available retrofit control option for Northeast Units 3 and 4

.

Coal Proce ssing

Pre

- combustion coal processing 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 c oal prior to use. These processes typically employ both mechanical and thermal means to increase the quality ofPSO Northeastern Power Plant BART Review January 1 9 , 2010

10 subbituminous coal and lignite by removing moisture, sulfur, mercury, and heavy metals. To date, the use of processed fuels has only been demo nstrated with test burns in a coal

- fired boiler.

No coal

- fired boilers have utilized processed fuels as their primary fuel source on an on

- going, long

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

in a coal

- fi red boiler, using processed fuels in Northeast Units 3 and 4 would require significant research, test burns, and extended trials to identify potential impacts on plant systems, including the boiler, material handling, and emission control systems. Therefor e, 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 scrubbin g systems offered 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 alkaline slurry is sprayed in the absorber and reacts with SO2 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 limes tone (CaCO 3 ) is 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 di fferent feed preparation 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 scr ubber slurry can be used with either the lime or limestone wet FGD system to produce gypsum solids instead of the calcium sulfite by

- product. Air blown into the reaction tank provides oxygen to convert most of the calcium sulfite (CaSO 3 ) to relatively pure gypsum (calcium 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

.

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 scrubbing will not be evaluated further in this BART

determination.

Wet Magnesium Enhanced Lime ScrubbingPSO Northeastern Power Plant BART Review January 1 9 , 2010

11 Magnesium Enhanced Lime (MEL) scrubbers are another variation of wet FGD technology. Magnesium enhanced lime typically contains 3% to 7% ma gnesium 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 utility boilers located in the Ohio River Valley. Systems to oxidize the MEL solids to produce a usable gypsum byproduct consisting of calcium sulfate (gypsum) and magnesium sulfate continue to be developed. Coal

- fired units equipped

with MEL F GD typically fire high

- sulfur eastern bituminous coal and use locally available reagent. There are no subbituminous

- fired units equipped with a MEL

- FGD system. Because

MEL

- FGD systems have not been used on subbituminous

- fired boilers, and because of the co st 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 contr ol systems will not be evaluated further as a commercially available retrofitted control system.

Jet Bubbling Reactor Another variation of the wet FGD control system is the jet bubbling reactor (JBR). Unlike the spray tower wet FGD systems, where the scr ubbing 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 sc rubbing 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 numbe r 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 d ata 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

- WF GD and the control efficiencies achievable with JBR

- WFGD are similar

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

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

include d in the overall assessment of WFGD controls.

Dual

- Alkali Wet Scrubber

Dual

- alkali scrubbing is a desulfurization process that uses a sodium

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

- based and calcium

b ased compounds. The dual

- alkali process requires lower liquid

- to

- gas ratios then scrubbing with

lime or limestone. The reduced liquid

- to

- gas ratios generally mean smaller reaction units,

however additional regeneration and sludge processing equipment is ne cessary. The sodium

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 large utility boiler. In addition, the process generates a less stable sludge that can create material handling and disposal problems. ItPSO Northeastern Power Plant BART Review January 1 9 , 2010

12 is projected that a dual

- alkali system could be designed to achieve SO 2 control similar to a limestone

- ba sed wet FGD. However, because of the limitations discussed above, and because

dual

- alkali systems are not currently commercially available, dual

- alkali scrubbing systems will

not be addressed further in this BART determination.

Wet FGD with Wet Electrosta tic Precipitator Wet electrostatic precipitation (WESP) has been proposed on other coal

- fired projects as one technology to reduce sulfuric acid mist emissions from coal

- fired boilers. WESPs have been proposed for boilers firing high

- sulfur eastern bitumin ous coals controlled with wet FGD.24 WESP has not been widely used in utility applications, and has only been proposed on boilers firing high sulfur coals and equipped with SCR. Northeast Units 3 and 4 fire low

- sulfur

subbituminous coal. Based on the fuel characteristics, and assuming 1% SO 2 to SO 3 conversion in the boiler, potential uncontrolled H 2 SO 4 emissions from Northeast Units 3 and 4 will only be approximately 5ppm. This emission rate does not take into account inherent acid gas removal

associated wi th alkalinity in the subbiuminous coal fly ash. Based on engineering judgment, it is unlikely that a WESP control system would be needed to mitigate visible sulfuric acid mist

emissions from Northeast Units 3 and 4 , even if WFGD control was installed. WESP s have been proposed to control condensable particulate emissions from boilers firing a high

- sulfur bituminous coal and equipped with SCR and wet FGD. This combination of coal and control equipment results in relatively high concentrations of sulfuric acid mist in the flue gas. WESP control systems have not been proposed on units firing subbituminous coals, and WESP would have no practical application on a subbituminous

- fired units. Therefore, the combination of

WFGD+WESP will not be evaluated further in th is 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 to wer 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 equipment. Therefore, dry FGD systems must be located upstream of the particulate control device to remove the reaction products and excess reactant material.

Spray Dryer Absorber Spray dryer absorber (SDA) systems have been us ed in large coal

- fired utility applications. SDA systems have demonstrated the ability to effectively reduce uncontrolled SO 2 emissions from coal units. The typical spray dryer absorber uses a slurry of lime and water injected into the

tower to remove SO 2 from the combustion gases. The towers must be designed to provide adequate contact and residence time between the exhaust gas and the slurry to produce a relatively dry by

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

available r etrofit technology for Northeast Units 3 and 4 . Based on the fuel characteristics and allowing a reasonable margin to account for normal operating conditions (e.g., load changes, changes in fuel characteristics, reactant purity, atomizer change outs, and m inor equipment upsets) it is concluded that dry FGD designed as SDA could achieve a controlled SO 2 emission

rate of 0.15 lb/mmBtu (30

- day average) on an on

- going long

- term basis.PSO Northeastern Power Plant BART Review January 1 9 , 2010

13 Circulating Dry Scrubber A third type of dry scrubbing system is the circul ating 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 the flue gas to the particula te removal system. Operating experience on smaller coal boilers in the U.S. has shown high lime consumption rates, and significant fluctuations in lime utilization

based on inlet SO 2 loading. Furthermore, CDS systems result in high particulate loading to t he unit’s particulate control device. Based on the limited application of CDS dry scrubbing systems on large boilers, it is likely that AEP

- PSO would be required to conduct extensive design engineering to scale up the technology for boilers the size of Nor theast Units 3 and 4 , and that

AEP

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

- term effectiveness of the control system. Because of these limitations, CDS dry scrubbing systems are not currently com mercially available as a retrofit control technology for

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

EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (SO 2 )

Table 10 : Technically Feasible SO 2 Control Tech nologies

- Northeastern Station

Control Technology Northeastern Unit 3 Northeastern Unit 4 Approximate SO 2 Emission Rate (lb/mmBtu) Approximate SO 2

Emission Rate (lb/mmBtu)

Wet FGD 0.0 63 0.0 63 Dry FGD

- Spray Dryer Absorber 0.1 5 3 0.1 5 3

Lower Sulfur Coa l 0.55 0.55

Baseline 0.9 0.9 Annual Average Baseline 0.91 0.91

EVALUATE IMPACTS AND DOCUMENT RESULTS (SO 2 )

AEP

- PSO evaluated the economic, environmental, and energy impacts associated with the two proposed control options. In general, the cost estimat ing methodology followed guidance provided in the EPA Air Pollution Cost Control Manual. Sixth Edition” EPA

- 452/B

- 02

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

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

Direct O&M costs are those costs that tend to be proportional to the quantity of exhaust gas processed by the control system. These may include costs for catalysts, utilities (steam, electricity, and water), waste t reatment and disposal, maintenance materials, replacement parts, and operating and maintenance labor. Of these direct O&M costs, costs for catalysts, utilities, waste treatment, and disposal are variable. Emission allowance costs associated with certain

re gulatory programs may also be represented as a variable O&M costs, but have not been included in this cost estimate. Indirect or “Fixed" annual costs are those whose values are totally independent of the exhaust flow rate and, in fact, would be incurred ev en if the control system were shut down. They include such categories as administrative charges, property taxes, and insurance, and include the capital recovery cost. The direct and indirect annual costs are offset by recovery credits, taken for materials or energy recovered by the control system, which may bePSO Northeastern Power Plant BART Review January 1 9 , 2010

14 sold, recycled to the process, or reused elsewhere at the site. The capital recovery factor used to

estimate the annual cost of control was based on a 8 % interest rate and a control life of 2 0 years

. Annual operating costs and annual emission reductions were calculated assuming a capacity

factor of 85 %.

AEP

- PSO submitted initial cost estimates in 2008 that relied upon a baseline emission rate representative of the average annual emission ( 0.9 lb/mm Btu) at a n annual average firing rate of

4775 mmBtu/hr. The modeling demonstration relied on maximum 24

- hr heat input numbers that were somewhat larger than the average

. However the actual annual firing rate is much lower,

and costs were reevaluated in o rder to be consistent with the methodology employed by EPA. Following the methodology published in the EPA advanced notice of proposed rulemaking for the Four Corners Power Plant and the Navajo Generating Station, cost effectiveness calculations

were revi sed to reflect average annual emissions from 2004

- 2006.

The engineering estimates and possible vendor quotations AEP

- PSO relied on to develop base $/kW Total Capital Investment assumptions were not provided to substantiate the capital costs

for installati on. In reviewing BART submittals to other states, AEP

- PSO ’s estimated costs were found to be somewhat higher than those reported for similar projects. However, the evaluations in neighboring states are known to underestimate present day costs and the ana lysis submitted by

AEP

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

Operation and maintenance cost estimates for AEP

- PSO cost calculations rely on assumptions provided in the AEP

- PSO submittal. While the assumptions for a dministrative costs were overstated, AEP

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

offset the overestimated numbers. E stimates are compared to operating costs documented in the June 2007 report by J. Edward Cichanowicz for the Utility Air Regulatory Group, “Current Capital Cost and Cost

- Effectiveness of Power Plant Emissions Control Technologies. The Cichanowicz report reproduces a Sargent and Lundy graphic, which lists a cost range in $/kW of

15 to 38 for O&M costs. AEP

- PSO estimates are approximately $ 33 /kW

. AEP

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

Table 11 : Economic Cost for Unit 3 and 4

- Dry FGD

- Spray Dryer Absorber

Cost DFGD/SDA Total Capit al Investment ($) $546,700,000 Total Capital Investment ($/kW) $582 Capital Recovery Cost ($/Yr) $55,682,603 Annual O&M Costs ($/Yr) $31,070,200
Total Annual Cost ($) $86,752,803

Table 12 : Environmental Costs for Unit 3 and 4

Baseline Lower S Coal D FGD/SDA

SO 2 Emission Rate (lb/mmBtu) 0.91 0.55 0.153

Annual SO 2 Emission (TPY) 1 31,779 19,555 5,440

Annual SO 2 Reduction (TPY)

-- 12,224 26,339 Total Annual Cost ($) $86,752,803 Cost per Ton of Reduction $3,294PSO Northeastern Power Plant BART Review January 1 9 , 2010

15 Incremental Cost per Ton $6,146

(1) Baseline annual emissions were averaged based on annual emissions from 2004

- 2006. Projected annual

emissions were calculated based on the controlled SO 2 emissions rate, full load heat input of 4,775 mmBtu/hr, and assuming an 85 % capacity factor.

T able 13 : Environmental Costs for Units 3 and 4

- Wet FGD

Cost AEP

- PSO Cost Estimates

Units 3 and 4 Total Capital Investment ($) $ 703

, 680

, 000 Total Capital Investment ($/kW) $ 749 Capital Recovery Cost ($/Yr) $ 71

, 671

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

, 419

, 400 Total Annual Cost ($) $ 107

, 090

, 762

Baseline SO 2 Emission Rate (lb/mmBtu) 0.9

Control SO 2 Emission Rate (lb/mmBtu) 0.063
Baseline Annual Emissions (TPY) 1 31

, 77 9

Controlled Annual SO 2 Emission (TPY) 1 2

, 240

Annual SO 2 Reduction (TPY) 29

, 53 9
Cost pe r Ton of Reduction ($/Ton) $3, 625 Incremental Annual Cost ($/Ton) $6,356

(1) Baseline annual emissions were calculated based on annual average emissions from 2004

- 2006. . Projected annual

emissions were calculated based on the controlled SO 2 emissions ra te, full load heat input of 4,775 mmBtu/hr, and assuming an 85% capacity factor.

C. PM 10

IDENTIFY AVAILABLE RETROFIT 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). Northeast Units 3 and 4 are currently equipped with ESP control systems.

Table 1 4 : Summary of Technically Feasible

Main Boiler PM 10 Control Technologies

Control Technology PM 10 Emissions ( lb/mmBtu) % Reduction (fr om base case)
Fabric Filter Baghouse and ESP 0.0085/0.0079 99.9

ESP

- Existing 0.0 25 /0.040 99.7

EVALUATE IMPACTS AND DOCUMENT RESULTS (PM 10 ) Costs for Fabric Filter Baghouses were provided separate from the cost estimates provided by

AEP

- PSO for Dry FG D. While DEQ capital cost estimates rely on primarily fully loaded Wet FGD installations, the greater expense attributed to wet versus dry systems can account for the Fabric Filter Baghouse equipment cost without a direct line item cost.PSO Northeastern Power Plant BART Review January 1 9 , 2010

16 For fabric fil ter baghouse controls AEP

- PSO estimated a total capital investment of $71,050,000 for Units 3 and 4. The capital recovery cost was estimated to be $6,671,463 per year over 20 years at 7% interest. The total annual cost was estimated to be $12,773592. Ad dition of the fabric filters was anticipated to result in an incremental cost of $12,565/ton over existing ESP controls. The applicant did not evaluate replacement of the ESP but instead the addition of

fabric filters.

D. VISIBILITY IMPROVEMENT DETERMI NATION

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

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

evaluated for the Northeastern Power Plant by using an EPA

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

determined that the Northeastern Power Plant was subject to BART based on the results of initial screening modeling that was conducted using current (baseline) emissions from the facility . The screening modeling, as well as more refined modeling conducted by the applicant, is described in

detail below.

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

closest Class I areas to the Northeastern Power Plant , as shown in Figure 1 below.

Only those Class I areas most likely to be impacted by the North eastern Power Plant were modeled, as determined by source/Class I area locations, distances to each Class I area, and professional judgment considering meteorological and terrain factors. It can be reasonably assumed that areas at greater distances and in directions of less frequent plume transport will experience lower impacts than those predicted for the four modeled areas.PSO Northeastern Power Plant BART Review January 1 9 , 2010

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

REFINED MODELING Because of the results of the appl icants screening modeling for the Northeastern Power Plant

, AEP

- PSO was required to conduct a refined BART analysis that included CALPUFF visibility modeling for the facility. The modeling approach followed the requirements described in the

Division’s BAR T 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 visibil ity impacts from the Northeastern Power Plant were determined with the EPA CALPUFF modeling system, which is the EPA

- preferred modeling system for long

- range transport. As described in the EPA Guideline on Air Quality Models (Appendix W of 40 CFR Part 51) , long

- range transport is defined as modeling with source

- receptor distances greater than 50 km. Because all modeled areas are located more than 50 km from the sources in question, the CALPUFF system was appropriate to use.

The CALPUFF modeling system co nsists of a meteorological data pre

- processor (CALMET), an air dispersion model (CALPUFF), and post

- processor programs (POSTUTIL, CALSUM, CALPOST). The CALPUFF model was developed as a non

- steady

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

- and space

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

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

three

- dimensional, gridded modeling domain. Meteorologica l inputs to CALMET can includePSO Northeastern Power Plant BART Review January 1 9 , 2010

18 surface and upper

- air observations from multiple meteorological monitoring stations. Additionally, the CALMET model can utilize gridded analysis fields from various mesoscale models such as MM5 to better represent regional w ind 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 pa rameters in the vertical and horizontal directions by defining the

radius of influence for surface and upper

- air stations.

CALPUFF is a multi

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

three

- dimensional wind fields developed by the CALMET model (refined mode), or by data from a single surface and upper

- air station in a format consistent with the meteorological files used to drive steady

- state dispersion models. All far

- field modeling assessments described here were completed using the CALPUFF model in a refined mode.

CALPOST is a post

- processing program that can read the CALPUFF output files, and calculate the impacts to visibility.

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

th at was recognized as the EPA

- approved release at the time of the application submittal. Version designations of the key programs are listed in the table below.

Table 1 5 : 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 CALMET model was used to construct the

initial three

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

- ai r 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 6 : CALMET Variables

Variable Description Value

PMAP Map projection LCC (Lambert Conformal Coni c)

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)

RMA X1 Maximum radius of influence 20 kmPSO Northeastern Power Plant BART Review January 1 9 , 2010

19 Variable Description Value

(surface layer, km)

RMAX2 Maximum radius of influence

(layers aloft, km) 50 km

TERRAD Radius of influence for terrain

(km) 10 km

R1 Relative weighting of first guess

wind field and observation (km) 10 km

R2 Relativ e 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 locationsPSO Northeastern Power Plant BART Review January 1 9 , 2010

20 Figure 3: Plot of upper air station locations

Figure 4. Plot of pr ecipitation observation stationsPSO Northeastern Power Plant BART Review January 1 9 , 2010

21 CALPUFF Modeling Setup To allow chemical transformations within CALPUFF using the recommended chemistry mechanism (MESOPUFF II), the model required input of background ozone and ammonia. CALPUFF can use either a single ba ckground value representative of an area or hourly ozone data from one or more ozone monitoring stations. Hourly ozone data files were used in the CALPUFF simulation. As provided by the Oklahoma DEQ, hourly ozone data from the Oklahoma City, Glenpool, and Lawton monitors over the 2001

- 2003 time frames were used. Background concentrations for ammonia were assumed to be temporally and spatially invariant and were set to 3 ppb.

Latitude and longitude coordinates for Class I area discrete receptors were taken from the National Park Service (NPS) Class I Receptors database and converted to the appropriate LCC

coordinates.

CALPUFF Inputs

- Baseline and Control Options The first step in the refined modeling analysis was to perform visibility modeling for current ( baseline) operations at the facility. Maximum 24

- hour heat inputs and emission rates for the

baseline emission calculations were established based on data from the years 200 2 to 200 5

.

Baseline source release parameters and emissions are shown in the ta ble below, followed by tables with data for the various control options. No attempt was made by the applicant to estimate the increase in sulfate emissions that would result from operations of SCR, and as a result the visibility improvement for those scen arios may be overestimated by some

undetermined amount.

Table 1 7 : Source Parameters

Parameter Baseline 1

Natural Gas

- Fired

Unit 2 Coal

- Fired

Unit 3 Coal

- Fired

Unit 4 Heat Input (mmBtu/hr) 4,767 5,812 5,594 Stack Height (m) 56 183 183 Stack Diameter (m ) 5.49 8.23 8.23 Stack Temperature (K) 2 394 424 415 Exit Velocity (m/s) 2 16.29 18.97 17.46

Baseline SO 2 Emissions (lb/mmBtu) 0.0006 1.05 1.06 Dry FGD SO 2 Emissions (lb/mmBtu)

-- 0.15 0.15

Wet FGD SO 2 Emissions (lb/mmBtu)

-- 0.063 0.063

Baseline NO X E missions (lb/mmBtu) 0.71 0.536 0.491

LNB/OFA NO X Emissions (lb/mmBtu) 0.28 0.15 0.15

LNB/OFA + SCR NO X Emissions (lb/mmBtu) 0.05 0.054 0.049

ESP (Baseline) PM 10 Emissions (lb/mmBtu) 0.007 0.0 25 0.0 40

FF PM 10 Emissions (lb/mmBtu)

-- 0.009 0.008

1 Baseli ne emissions data were provided by AEP

- PSO . Baseline emission rates (lb/mmBtu) were calculated by dividing the

maximum 24

- hr lb/hr emission rate by the maximum heat input to the boiler at that emission rate

.PSO Northeastern Power Plant BART Review January 1 9 , 2010

22 2 Temperature and Velocity were decreased for DFG D and WFGD evaluations. For DFGD, stack temperature was

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

decreased to 332 K and velocity decreased to 14.86 and 13.96 for Units 3 and 4 res pectively

.

Visibility Post

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

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

below.

Table 1 8 : Relative Humidity Factors for CALPOST

Month Wichita

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

March 2.4 2.9 2.7 2.7 April 2.4 3.0 2.8 2.7 May 3.0 3.6 3.4 3.3

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

October 2.6 3.5 3.3 3.1

November 2.7 3.4 3.2 3.1

December 2.8 3.5 3.3 3.3

EPA’s default average annual aerosol concentrations for the U.S. that are included in Table 2

- 1

of EPA’s Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Program were to develop natural background estimates for each Class I area

.

Visibility Post

- Processing Results

Table 1 9 : CALPUFF Visibility Modeling Results for Northeast Units 3 and 4

- NO X

Class I Area 2001 2002 2003 3

- Year Average

98 th

Percentile

Value (Δdv) 98 th

Percentile

Value (Δdv) 98 th

Percentile

Value (Δdv) 98 th Percentile Value

(Δdv)

Baseline

Wichita Mountains 0.468 0.402 0.775 0.548 Caney Creek 0.994 0.714 1.029 0.912 Upper Buffalo 0.883 0.42 0.442 0.582

Hercules Glade 0.644 0.345 0.296 0.428

Scenario 1

- Combustion Control

- LNB/OFA

Wichita Mountains 0.136 0.116 0.223 0.1 58 Caney Creek 0.301 0.213 0.293 0.269PSO Northeastern Power Plant BART Review January 1 9 , 2010

23 Upper Buffalo 0.259 0.124 0.131 0.171

Hercules Glade 0.191 0.102 0.086 0.126

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

from scenario one

.

Table 20 : CALPUFF Visib ility Modeling Results for Northeast Units 3 and 4

- SO 2

Class I Area 2001 2002 2003 3

- Year Average

98 th

Percentile Value (Δdv) 98 th

Percentile Value (Δdv) 98 th

Percentile Value (Δdv) 98 th

Percentile Value (Δdv)

Baseline

Wichita Mountains 1.123 0.819 1.836 1.260 Caney Creek 1.322 1.186 1.245 1.251 Upper Buffalo 0.993 0.683 1.227 0.968

Hercules Glade 1.071 0.626 1.1 97 0.965

Scenario 1

- Dry FGD

Wichita Mountains 0.164 0.129 0.282 0.192 Caney Creek 0.207 0.199 0.190 0.199 Upper Buffalo 0.141 0.098 0.138 0.126

Hercules Glade 0.138 0.088 0.159 0.128

Wet FGD reduced visibility impairment by a further 50 % over Dry F GD. This de creased degradation improved visibility by less 0.12 dv on the 98 th percentile days and is considered an insignificant change.

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

from direct PM e missions will be improved with the fabric filters but both technologies control visibility impairment well below 0.5dv at all Class I areas.

Table 21 : CALPUFF Visibility Modeling Results for Northeast Units 2 NO X

Class I Area 2001 2002 2003 3

- Year Averag e 98 th

Percentile

Value (Δdv) 98 th

Percentile

Value (Δdv) 98 th

Percentile

Value (Δdv) 98 th Percentile Value

(Δdv)

Baseline

Wichita Mountains 0.366 0.247 0.489 0.367 Caney Creek 0.809 0.66 0.569 0.679 Upper Buffalo 0.541 0.246 0.269 0.352

Hercules Glade 0.49 5 0.275 0.266 0.345

Scenario 1

- Combustion Control

- LNB/OFA

Wichita Mountains 0.144 0.099 0.19 0.144 Caney Creek 0.332 0.267 0.231 0.277 Upper Buffalo 0.218 0.099 0.108 0.142PSO Northeastern Power Plant BART Review January 1 9 , 2010

24 Hercules Glade 0.195 0.111 0.108 0.138

E. BART DETERMINATION

After consi dering: (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 hree units at the Northeastern Power Plant

.

NO X New LNB with OFA is determined to be BART for NO X control for Units 2, 3 and 4 based, in part, on the following conclusions:

1. Installation of new LNB with OFA was cost effective at an average cost effectiveness of $ 303

- 313

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

- air quality environmental mitigation for the use of chemical re agents (i.e., ammonia or urea) and there is minimal energy impact.

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

- day rolling averages of 0. 15

lb/mmBtu for Units 3 and 4 and 0.28 lb/mmBtu on Unit 2 are justified meet the presumptive limits prescribed by EPA

.

LNB with OFA and SCR was not determined to be BART for NO X control for Units 2, 3 and 4 based, in part, on the following conclusions:

1. The cost of complianc e for installing SCR on each unit is significantly higher than the cost for LNB with OFA. Additional capital costs for SCR on Units 3 and 4 are on average $ 290

, 000 ,0 0 0

. Based on projected emissions, SCR could reduce overall NO X emissions from Northeast U nits 3 and 4 by approximately 4,120 TPY beyond combustion controls; however, the incremental cost associated with this reduction is approximately $ 11

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

2. Additional non

- air qualit y environmental mitigation is required for the use of chemical

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

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

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

0. 1 0 and 0.18 Δdv respectively

.

SO 2 Continued use of low sulfur coal is determined to be BART for SO 2 control for Units 3 and 4 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 other environmental programs,

and national commitments.PSO Northeastern Power Plant BART Review January 1 9 , 2010

25 Installation of DFGD is not cost effective. OG&E’s revised cost estimates are based on vendor quotes and go well beyond the default methodology recommended by EPA guidance. The cost estimates are credible, detailed, and specific for the Muskogee and Sooner facilities. Cost

estimates for the AEP

- PSO Northeastern facility continue to be lower on a capital and annualized basis, but are comparable to the costs documented by OG&E . The substantiated AEP

- PSO estimate for both boilers at $546,700,000 is $2 09

, 240

, 0 00 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 lan d managers have informally maintained a spreadsheet of BART costs and

determinations for coal

- fired facilities. This spreadsheet indicates that the highest reported cost for control was for the Boardman facility in Oregon at a projected cost of $247,300,0 00. While there is some uncertainty on whether this cost will ultimately be found to be cost effective, it is much lower than the cost of controlling a single boiler at the Muskogee facility ($ 273,350

, 0 00).

Most assessments were based on costs of less th an $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 se veral BART

evaluations.

Table 2 2 : 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 9,006

Sooner Unit 1 0.509 9,394

S ooner 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 U nit 4 0.900 16,000 Naughton Unit 1 1.180 8,624 Naughton Unit 2 1.180 11,187 OPPD Nebraska City Unit 1 0.815 24,191

Assuming total annual costs and projected emissions are similar and thereby setting aside the issues related to pre

- 2008 cost estimates and the ability to compare them to December 2009 estimates, cost effectiveness will be a function of the baseline emissions. This holds true for units firing subbituminous coals with baseline SO 2 emissions rates in the range of 0.5 lb/mmBtu to approximate ly 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 inlet SO 2 loading. DFGD control sy stems willPSO Northeastern Power Plant BART Review January 1 9 , 2010

26 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. Conversely, DFGD will be less cost e ffective, 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 AEP

- PSO units after adopting and annual average

emission rate of 0.55 lb/mm Btu would be about 55 to 185% higher than the other units listed, i.e., less cost effective.

The average cost effectiveness at Northeastern for DFGD is $ 3,294 per ton of SO 2 removed from the present baseline and $6,146 per ton from the lower sulfur coal baseline for each unit over a twenty year operational life. The cost of add

- on controls above and beyond lower sulfur coal at
the Northeastern facility is well above the average cost effectiveness reported for similar BART projects, well above costs asso ciated 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 spreadsheet, the average cost effectiveness in $/dv was $5,700,000/dv. The addition of DFGD at the N ortheastern Facility was anticipated to reduce impairment by 3.97 dv. Importantly, the cost effectiveness of that improvement is calculated to be $2 1

, 829

, 547 /dv.

A majority of the Class I areas are located in the western part of the U.S. Simply due to the number of Class I areas in the west, it is likely that a BART applicable unit located in the western U.S. will be closer to a Class I area, and that emissions from the unit will affect visibility at more Class I areas. For example, the Boardman Gener ating Station located in the north central region approximately 150 miles east of Portland, is located within 300 km of 14 Class I areas. By comparison the Northeastern station is located with 300 km of 3 Class I areas. Using the sum

of modeled visibilit y improvements at all 14 Class I areas, cost effectiveness of the DFGD control system would be $3,690,510/dv or 5.9 times more cost effective than DFGD controls at

the Northeastern facility. The federal land managers have indicated that costs effectivenes s numbers of less than $10,000,000/dv should be considered cost effective. While this does not prohibit a determination of cost effectiveness at numbers greater than $10,000,000/dv, it does imply that numbers greater than that should receive greater consi deration.

An investment of this magnitude to install DFGD on an existing coal

- fired power plant effectively guarantees the continued use of coal as the primary fuel source for energy generation in this facility and arguably the state for the next 20 yea rs and beyond. Therefore, a determination in support of DFGD ignores the Obama Administration’s stated agenda to control carbon dioxide and other green house gases by restricting the alternatives left open to AEP

- PSO and hence the ratepayers of Oklahoma. Substantial uncertainty currently exists about the nature and costs of future federal carbon controls on power plants, including the level of stringency, timing, emissions allowance allocation and prices, and whether and to what degree emissions

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

- PSO facility that would be more stringent than the scrubber can deliver. Fortunately, other technology options now exist that would likely achieve greater merc ury reductions at lower cost than the scrubber. If EPA determines that MACT requires greater reductions than those achieved through DFGD, then ratepayers would be at risk to pay forPSO Northeastern Power Plant BART Review January 1 9 , 2010

27 additional required mercury control technology.

The cost for DFGD is too high, the benefit too low and these costs, if borne, further extend the life expectancy of coal as the primary fuel in the AEP

- PSO facility for at least 20 years and beyond. BART is the use of low sulfur coal (0.55 lb/mmBtu

- annual average).

.

Wet FGD wa s not determined to be BART for SO 2 control for Units 3 and 4 based, in part, on

t he following conclusions:

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

FGD . Based on projected emissions, WFGD could reduce overa ll SO 2 emissions from

Northeast Units 3 and 4 by approximately 3,200 TPY beyond dry scrubbers ; however, the incremental cost associated with this reduction is approximately $ 6,356 /ton without appreciable visibility improvement

. 2. SO 3 remaining in the flue ga s will react with moisture in the wet FGD to generate sulfuric acid mist. Sulfuric acid is classified as a condensable particulate. Condensable particulates from the wet FGD system can be captured using additional emission controls (e.g., WESP). However , the effectiveness of a WESP system on a subbituminous fired unit has not been demonstrated and the additional cost of the WESP system significantly

increases the cost of SO 2 controls.

3. Wet FGD systems must be located downstream of the unit’s particulate control device; therefore, dissolved solids from the wet FGD system will be emitted with the wet FGD plume. Wet FGD control systems also generate lower stack temperatures that can reduce plume rise and result in a visible moisture plume.

4. Wet FGD systems use more reactant (e.g., limestone) than do dry systems, therefore the limestone handling system and storage piles will generate more fugitive dust emissions.

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

wastewater s tream that must be treated and discharged. We t FGD wastewater treatment systems typically require calcium sulfate/sulfite desaturation, heavy metals precipitation, coagulation/precipitation, and sludge dewatering. Treated wastewater is typically discharg ed 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.

PM 10 The existing ESP control is determined to be BART for PM 10 controls for Units 3 and 4 based on

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

emissions of PM 10 from the facility.

Table 23 : U nit

- by

- unit BA RT determinations

Control Unit 2 Unit 3 Unit 4

NO X Control LNB with OFA LNB with OFA New LNB with OFA

Emission Rate (lb/mmBtu) 0.28 lb/mmBtu (30

- day rolling average) 0.15 lb/mmBtu

(30

- day rolling average) 0.15 lb/mmBtu

(30

- day rolling average)

Emission Rate lb/hr 1331 lb/hr (30

- day rolling 716 lb/hr

(30

- day rolling 716 lb/hr (30

- day rollingPSO Northeastern Power Plant BART Review January 1 9 , 2010

28 average) average) average)

Emission Rate TPY 5,830 TPY (12

- month rolling) 6,274 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

-- 3,104 lb/hr (30

- day rolling average) 3,104 lb/hr

(30

- day rolling average)

Emission Rate (lb/mmBtu) -- 0.55 lb/mmBtu (12

- month rolling

aver age) 0.55 lb/mmBtu

(12

- month rolling average) Emission Rate (TPY) 23,006 TPY

PM 10 Control 1

-- ESP ESP

Emission Rate (lb/mmBtu) -- 0.1 lb/mmBtu (3

- hour rolling average) 0.1 lb/mmBtu

(3

- hour rolling average)

Emission Rate lb/hr

-- 478 lb/hr (3

- hour rol ling average) 478 lb/hr

(3

- hour rolling average)

Emission Rate TPY

-- 4,183 TPY (12

- month rolling average)

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

catch and do not reflect the true emission s . As part of t he permitting process, AEP

- PSO will be required to propose emission limits for both front and back half, which is reflective of the control technology and consistent with the performance tests

.

F

. CONTINGENT BART DETERMINATION In the event that EPA disap proves 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 Northeastern Units 3 and 4 install

DFGD with SDA for SO 2 control or meet the corresponding SO 2 emission limits listed below by December 31, 2018 or comply with the approved alternative described in section G (Greater Reasonable Progress Alternative).

Table 2 4 : Unit

- by

- unit Contingent BART determinations

Control Unit 3 Unit 4

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 Rate lb/hr 478 lb/hr (30

- day rolling average) 478 lb/hr (30

- day rolling average)

Emission Rate TPY 2,091 TPY 2,091 TPYPSO Northeastern Power Plant BART Review January 1 9 , 2010

29 The “contingent” BART as defined here and in conjunction with the greater reasonable progress alternative recognizes the l ong term importance of achieving reductions 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 determine d that DFGD is not cost effective. However, if EPA chooses to ignore that element of the BART determination, DEQ does agree that DFGD remains a technically feasible control option for 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 sett le, is a more equitable alternative for the ratepayers in Oklahoma than requiring an overly costly control merely to achieve limited visibility improvement while simultaneously solidifying the use of a higher emitting technology from now

into the foreseeab le future.

G

. GREATER REASONABLE PROGRESS ALTERNATIVE DETERMINATION In lieu of installing and operating BART for SO 2 Northeastern Units 3 and 4, AEP

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

req uires AEP

- PSO to achieve a combined annual SO 2 emissions limit (identified in table 25) by installing and operating DFGD with SDA on one of the two boilers and being at or below the

SO 2 emission that would result from switching the remaining boiler to natu ral gas. Under this

alternative AEP

- PSO shall install the controls (i.e., DFGD with SDA or achieve equivalent emissions) by December 31, 2026. By adopting these emission limits, DEQ and AEP

- PSO expect the cumulative SO 2 emissions from Northeastern Units 1 and 2 t o be approximately 43 % less than would be achieved through the installation and operation of DFGD with SDA at both

units

.

Table 25: SO 2 Emissions with Greater Reasonable Progress

Northeastern

Parameter Unit 3 and Unit 4 BART (Low Sulfur Coal) 23,006 TPY Contingent BART (DFGD) 4,182 TPY GRP (DFGD/Natural Gas) 2,400 TPY

Under no circumstance will the Greater Reasonable Progress Plan result in less visibility improvement than would be achieved either through the DEQ determined BART or the

“co ntingent” 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 visitors to our Class I areas can be preserved for the long term 2064 goal of natural visibility.

V. CONSTRUCTION PERMIT

Prevention of Significant Deterioration (PSD)PSO Northeastern Power Plant BART Review January 1 9 , 2010

30 Northeastern Power Plant is a major source under OAC 252:100

- 8 Permits for Part 70 Sources.

AEP

- PSO should comply with the permitting requi rements of Subchapter 8 as they apply to the

installation of controls determined to meet BART.

The installation of controls determined to meet BART will not change NSPS or NESHAP/MACT applicability for the gas

- fired units at the Northeastern Station. The permit application should contain PM 10 and PM 2.5 emission estimates for filterable and condensable

emissions.

VI. OPERATING PERMIT

The Northeastern Power Plant is a major source under OAC 252:100

- 8 and has submitted an application to modify their exist ing 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, 3 and 4 are subject to the Best Available Retrofit Technology (BART) requi rements 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 su bject to the requirements of this Specific Condition, the Protection of Visibility and Regional Haze Requirements of 40 CFR Part 51, and all applicable SIP requirements:

EU ID# Point

ID# EU Name Heat Capacity (MMBTUH) Construction

Date

2 2 Babcock and Wi lcox UP

- 60 4754 1970

3 3 Combustion Engineering #4974 SCRR 4775 1974

4 4 Combustion Engineering #7174 SCRR 4775 1974

b. Each existing affected facility shall install and operate the SIP approved BART as expeditiously as practicable but in no later than fi ve years after approval of the SIP incorporating the BART requirements.

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

modification of the boilers. If the modifications will result in a significant emission increase and a signific ant 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 analysi s, to reduce

emissions of NO X to below the emission limits below:

i. New Low

- NO X Burners,

ii. Overfire Air

.

e. The permittee shall maintain the controls (Low

- NO X burners, overfire air and

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

maintained.PSO Northeastern Power Plant BART Review January 1 9 , 2010

31 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 o f 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 Averaging Period

2 2 0.28 lb/mmBtu 30

- day rolling

EU

ID# Point

ID# NO X Emission Limit SO 2

Emission Limit Averaging

Period

3 3 0.15 lb/mmBtu 0. 65 lb/mmBtu 30

- day rolling

4 4 0.15 lb/mmBtu 0. 6 5 lb/mmBtu 30

- day rolling

EU

ID# Point

ID# SO 2 Emission Limit SO 2

Emission Limit Averaging

Period

3 3 0. 55 lb/mmBtu 23,006 TPY annual average

4 4 0. 55 lb/mmBtu annual average

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

Da.

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

- up, the permittee shall conduct pe rformance testing as follows and furnish a written report to Air Quality. Such report shall document compliance with BART

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

- 8

- 6(a)]

i. The permittee shall conduct SO 2 , NO X , PM 10 , PM 2 .5 , CO, and VOC testing on the boilers at 60% and 100% of the maximum capacity. NOX and CO testing shall also be conducted at least one additional intermediate point in the operating range.

ii. Performance testing shall be conducted while the units a re operating within 10% of the desired testing rates. A testing protocol describing how the testing will be performed shall be provided to the AQD for review and approval at least 30 days prior to the start of such testing. The permittee shall also provi de notice of the actual test date to AQD.