BART DETERMINATION REPORT AMERICAN ELECTRIC POWER COMANCHE POWER STATION UNITS 1 AND 2

Transcription

1 BART DETERMINATION REPORT AMERICAN ELECTRIC POWER COMANCHE POWER STATION UNITS 1 AND 2 Prepared by: N.N. Dharmarajan Vern Choquette Principal Consultant Eugene Chen, PE Senior Consultant Jeremy Townley Consultant TRINITY CONSULTANTS 120 E. Sheridan Suite 205 Oklahoma City, OK (405) August 2008 Project

2 TABLE OF CONTENTS 1. EXECUTIVE SUMMARY BACKGROUND BART APPLICABILITY CALPUFF MODELING ANALYSES BART DETERMINATION BART APPLICABILITY ANALYSIS BART-ELIGIBLE SOURCES SOURCE EMISSIONS DATA PM EMISSIONS STACK PARAMETERS SO 2 BART DETERMINATION IDENTIFICATION OF AVAILABLE RETROFIT SO 2 CONTROL TECHNOLOGIES PM BART DETERMINATION IDENTIFICATION OF AVAILABLE RETROFIT PM CONTROL TECHNOLOGIES NO X BART DETERMINATION IDENTIFY ALL AVAILABLE RETROFIT TECHNOLOGIES ELIMINATE TECHNICALLY INFEASIBLE OPTIONS DRY LOW NOX BURNERS (DLNB) EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES EVALUATION OF IMPACTS FOR FEASIBLE NO X CONTROLS COSTS OF COMPLIANCE ENERGY AND NON-AIR IMPACTS REMAINING USEFUL LIFE EVALUATE VISIBILITY IMPACTS PROPOSED BART FOR NO X APPENDIX A EMISSION ESTIMATES APPENDIX B - ECONOMIC ANALYSES APPENDIX C CALPUFF MODELING PROTOCOL APPENDIX D MODELING INPUT/OUTPUT FILES i

3 LIST OF FIGURES TABLE 3-1. CONSTRUCTION DATE SUMMARY TABLE 3-2. PRE-BART EMISSIONS SUMMARY TABLE 3-3. PM SPECIATION PROFILE TABLE 3-4. SPECIATED PM EMISSIONS TABLE 3-5. POINT SOURCE STACK PARAMETERS TABLE 4-1. BASELINE MAXIMUM 24-HOUR AVERAGE SO 2 EMISSION RATES TABLE 4-2. AVAILABLE SO 2 CONTROL TECHNOLOGIES TABLE 4-3. SO 2 EMISSION ESTIMATES (NATURAL GAS) TABLE 5-1. BASELINE MAXIMUM 24-HOUR AVERAGE PM EMISSION RATES TABLE 5-2. AVAILABLE PM CONTROL TECHNOLOGIES TABLE 5-3. PM EMISSION ESTIMATES TABLE 6-1. BASELINE 24-HR AVERAGE NO X EMISSION RATES TABLE 6-2. AVAILABLE NO X COMBUSTION CONTROL TECHNOLOGIES TABLE 6-3. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE NO X CONTROL TECHNOLOGIES6-2 TABLE 6-4. NO X CONTROL COSTS SUMMARY TABLE 6-5. COMANCHE UNIT 1G1 AND 1G2 VISIBILITY IMPACTS (NOX) ii

4 1. EXECUTIVE SUMMARY American Electric Power/Public Service Company of Oklahoma (/PSO) owns and operates the Comanche Power Station, located near Lawton, OK. The Comanche station is an electricity generating station that primarily consists of two natural-gas fired combustion turbines with duct burners and heat recovery steam generators (HRSGs). The Comanche Station is a Title V major source of emissions and currently operates under Permit No TVR, issued April 21, Based upon the construction date of the sources at the Comanche station, has determined that both units are eligible to be regulated under the Best Available Retrofit Technology (BART) provisions of the U.S. Environmental Protection Agency s (EPA) Regional Haze Rule as established in Title 40, Code of Federal Regulations Part 51 (40 CFR 51). Both turbine/duct burner units comprise the BART-eligible source at the Comanche Station. In addition, has determined that the Comanche Station contributes greater than 0.5 deciviews ( dv) to visibility impairment in a federally protected Class I area when compared to a natural background. As a result, it does not qualify for exemption and is subject to a BART determination. Per the guidelines in 40 CFR Part 51 1, a BART determination for SO 2, NO X, and PM was performed using the five-step analysis that included the following: 1. Identifying all available retrofit control technologies; 2. Eliminating technically infeasible control technologies; 3. Evaluating the control effectiveness of remaining control technologies; 4. Evaluating impacts and document the results; 5. Evaluating visibility impacts Based on the five-step analysis, proposes the following as BART: PM proposes the use of natural gas at the Comanche Station as BART for PM. Natural gas use is able to ensure PM emissions lower than add-on PM controls. SO 2 also proposes the use of natural gas at the Comanche Station as BART for SO 2. As with PM emissions, natural gas use is able to ensure SO 2 emissions lower than add-on SO 2 controls. NO X proposes emission rates of 0.15 lb/mmbtu as BART for NOx. This will be achieved by retrofitting the turbines with Dry Low NOx burners (DLNB) CFR 51, Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations 1-1

5 2. BACKGROUND On July 1, 1999, the U.S. Environmental Protection Agency (EPA) published the final Regional Haze Rule (RHR). The objective of the RHR is to improve visibility in 156 specific areas across the United States, known as Class I areas. The Clean Air Act defines Class I areas as certain national parks (over 6,000 acres), wilderness areas (over 5,000 acres), national memorial parks (over 5,000 acres), and international parks that were in existence on August 7, On July 6, 2005, the EPA published amendments to its 1999 RHR, often called the BART rule, which included guidance for making source-specific Best Available Retrofit Technology (BART) determinations. The BART rule defines BART-eligible sources as sources that meet the following criteria: (1) Have potential emissions of at least 250 tons per year of a visibility-impairing pollutant, (2) Were in existence between August 7, 1962 and August 7, 1977, and (3) Are listed as one of the 26 listed source categories in the guidance. A source that meets these criteria is considered eligible for BART and must then determine if BART applies. 2.1 BART APPLICABILITY Per the U.S. EPA s BART Modeling Guidance, an individual source will be considered to cause visibility impairment if the emissions results in a change (delta ) in deciviews (dv) 2 that is greater than or equal to 1.0 deciview on the visibility in a Class I area if the emissions from a source results in a change in visibility that is greater than or equal to 0.5 dv in a Class I area the source will be considered to contribute to visibility impairment. To determine whether a BART-eligible source causes or contributes to visibility impairment, the U.S. EPA guidance requires the use of an air quality model, specifically recommending the CALPUFF modeling system, to quantify the impacts attributable to a single BART-eligible source. Because contribution to visibility impairment is sufficient cause to require a BART determination, 0.5 dv is the critical threshold for assessment of BART applicability. Regional haze is quantified using the light extinction coefficient (b ext ), which is expressed in terms of the haze index (HI) expressed in dv. The HI is calculated as shown in the following equation. b ext HI = 10 ln 10 The impact of a BART-eligible source is determined by comparing the HI attributable to a source to estimated natural background conditions. That is, a single-source visibility impact is measured as the 2 The deciview (dv) is a metric used to represent normalized light extinction attributable to visibility-affecting pollutants. 2-1

6 change in light extinction versus background, and is referred to as dv. The background extinction coefficient is affected by various chemical species and the Rayleigh scattering phenomenon and can be calculated as shown in the following equation. where: 1 ( ) = bso + bno + boc + bsoil + bcoarse + bec bray b ext, background Mm b b b b b b b SO4 NO3 OC Soil EC Ray = = = = 3[ ( NH 4 ) 2SO 4 ] f ( RH ) 3[ NH 4NO3 ] f ( RH ) 4[ OC] 1Soil [ ] = 0.6[ Coarse Mass] 10[ EC] = Coarse = Rayleigh Scattering f ( RH ) = 3 [] = Concentration in µg m Relative Humidity Function 1 ( 10 Mm by default) [( NH4 ) SO ] 2 4 [ NH4NO3] [ OC] denotes [ Soil] denotes [ Coarse Mass] [ EC] denotes denotes the ammonium sulfate concentration denotes the ammonium nitrate concentration the concentration of organic carbon the concentration of fine soils denotes the concentration of coarse dusts the concentration of elemental carbon Rayleigh Scattering is scattering due to air molecules Values for the parameters listed above specific to the natural background conditions at each Class I area are provided on an annual-average basis in the U.S. EPA s Guidance for Estimating Natural Visibility Conditions under the Regional Haze Rule. 3 Particulate species that affect visibility are emitted from anthropogenic (human-caused) sources and include coarse particulate matter (PMC), fine particulate matter (PMF), and elemental carbon (EC) as well as precursors to secondary organic aerosols (SOA) and fine particulate matter such as SO 2 and NO X. The extinction coefficient due to emissions of visibility-affecting pollutants from a single BART-eligible source is calculated according to the following equation. where: ext source 1 ( ) = bso + bno + bsoa + bpmf + bpmc bec b, Mm U.S. EPA, Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule, Table 2-1, Attachment A, September 2003, EPA-454/B

7 bso = 3[ ( NH 4 ) SO 4 ] f ( RH ) 4 2 bno = 3[ NH 4 NO 3 ] f ( RH ) 3 bsoa = 4[ SOA] bpmf = 1[ PMF] bpmc = 0.6[ PMC] bec = 10[ EC] f ( RH ) = 3 [] = Concentration in µg m Relative Humidity Function [( NH 4 ) SO ] denotes 2 4 [ NH 4 NO 3 ] denotes [ SOA] denotes the concentration of [ PMF] denotes the concentration of fine PM [ PMC] denotes the concentration of coarse PM [ EC] denotes the concentration of elemental carbon the ammonium sulfate concentration the ammonium nitrate concentration secondary organic aerosols CALPUFF MODELING ANALYSES As stated above, the BART Guidelines recommend using the CALPUFF modeling system to compute the 24-hour average visibility impairment attributable to a BART-eligible source to assess whether the 0.5 dv contribution threshold is exceeded, and if so, the frequency, duration, and magnitude of any exceedance events. As described further in the modeling protocol included in Appendix A, CALPUFF is a refined air quality modeling system that is capable of simulating the dispersion, chemical transformation, and longrange transport of multiple visibility-affecting pollutant emissions and is therefore preferred for BART applicability and determination analyses. 2.2 BART DETERMINATION BART-eligible sources that are found to cause or contribute to visibility impairment at a Class I area are required to make a BART determination. The BART Guidelines define BART as follows: BART means an emission limitation based on the degree of reduction achievable through the application of the best system of continuous emission reduction for each pollutant which is emitted by [a BART-eligible source]. The emission limitation must be established, on a case-by-case basis, taking into consideration the technology available, the costs of compliance, the energy and non-air quality environmental impacts of compliance, any pollution control equipment in use or in existence at the source, the remaining useful life of the source, and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology. The BART analysis identifies the best system of continuous emission reduction taking into account: (1) The available retrofit control options, (2) Any pollution control equipment in use at the source (which affects the availability of options and their impacts), (3) The costs of compliance with control options, (4) The remaining useful life of the facility, (5) The energy and non-air quality environmental impacts of control options[, and] (6) The visibility impacts analysis. 2-3

8 Further, the BART rule indicates that the five basic steps in a BART analysis can be summarized as follows: 1. Identify all available retrofit control technologies; 2. Eliminate technically infeasible control technologies; 3. Evaluate the control effectiveness of remaining control technologies; 4. Evaluate impacts and document the results; 5. Evaluate visibility impacts As summarized in Section 3, conducted a BART applicability analysis for the three units at the Comanche Station and determined that the units are subject to BART. The BART determinations for each of the three visibility affecting pollutants (SO 2, NOx, and PM) can be found in Sections 4 through

9 3. BART APPLICABILITY ANALYSIS 3.1 BART-ELIGIBLE SOURCES In order to determine what specific units constitute the BART-eligible source, the construction dates of the each of the plant s units must be examined. A summary of all units at the Comanche Station is provided below. As seen from this table, both turbine/duct burner units were in existence within the 15-year BART window (August 7, 1962-August 7, 1977). TABLE 3-1. CONSTRUCTION DATE SUMMARY Unit Heat Duty Manufacturer/Model Construction Date No. (MMBtu/hr) 1G1 1,250 Westinghouse/W-501B May G2 1,250 Westinghouse/W-501B May 1971 DB1 200 Westinghouse Steam Generator Burner May 1971 DB2 200 Westinghouse Steam Generator Burner May SOURCE EMISSIONS DATA In developing baseline emissions, Trinity utilized a combination of operating records and continuous emission monitoring (CEM) data provided by over a period extending from Modeled emissions are based on the highest hourly emission rate (on 24-hour calendar day average) that occurred from 2001 to A summary of these emissions is presented in Table 3-2 below. A more detailed analysis of historical emissions is included in Appendix A. TABLE 3-2. PRE-BART EMISSIONS SUMMARY Unit No. NO x PM SO 2 H 2 SO 4 lbs/hr lbs/hr lbs/hr lbs/hr 1G G Both turbines operated on natural gas during the period. In addition, the duct burners have not operated for several years, and not over the period. As a result, separate listing of pre- BART baseline emissions is not included. As discussed in the cover letter accompanying this report, did not include the duct burners in this analysis. 3-1

10 3.2.1 PM EMISSIONS PM emissions are not directly entered into the model but are instead speciated into constituent components. The PM emissions from the boilers can be speciated according to the Federal Land Managers guidance to potentially include the following: Coarse particulate matter (PM C, considered PM ) Fine particulate matter (PM F, considered PM <2.5 ) Sulfates (SO 4 ) Secondary organic aerosols (SOA) Elemental carbon (EC) Based upon FLM guidance, PM emissions from natural gas combustion consists of primarily coarse (25%) and fine (75%). 4 A summary of speciated PM emissions is presented in Table 3-3 below. TABLE 3-3. PM SPECIATION PROFILE Particulate Matter Species Fraction PM Coarse (Soil) 25% Elemental Carbon (EC) 0% PM Fine 75% Secondary Organic Aerosols 0% (organic carbon) Total 100% A summary of speciated PM emissions from the Comanche units is presented below. TABLE 3-4. SPECIATED PM EMISSIONS Unit No. PM (coarse) 4 PM (fine) 4 EC 4 SOA 4 lbs/hr lbs/hr lbs/hr lbs/hr 1G G STACK PARAMETERS Table 3-5 provides a summary of source exhaust parameters

11 Emission unit Latitude (decimal degrees) TABLE 3-5. POINT SOURCE STACK PARAMETERS Longitude (decimal degrees) Exit Velocity (ft/s) Stack Height (feet) Stack Diameter (feet) Exit Temperature (Fahrenheit) 1G G The base elevation of each of the units is 338 meters (1,108 feet) above MSL based upon visual inspection of USGS topographic maps. 3-3

12 4. SO 2 BART DETERMINATION A summary of pre-bart SO 2 emissions over the time period as described in Section 3 is included below. TABLE 4-1. BASELINE MAXIMUM 24-HOUR AVERAGE SO 2 EMISSION RATES Emission Unit SO 2 Emission Rate (lb/hr) 1G G IDENTIFICATION OF AVAILABLE RETROFIT SO 2 CONTROL TECHNOLOGIES The first step of a BART determination is the identification of all available retrofit SO 2 control technologies. A list of control technologies was obtained by reviewing the U.S. EPA s Clean Air Technology Center, control equipment vendor information, publicly-available air permits, applications, and BART analyses, and technical literature published by the U.S. EPA and Regional Planning Organizations (RPOs). TABLE 4-2. AVAILABLE SO 2 CONTROL TECHNOLOGIES SO 2 Control Technologies Dry Sorbent Injection Spray Dryer Absorber (SDA) i.e., Semi-Dry Scrubber Wet Scrubber Circulating Dry Scrubber (CDS) All of the technologies listed in Table 4-2 involve removing the SO 2 in the exhaust gas, which is known as flue gas desulfurization (FGD). proposes to restrict fuel usage at the Comanche Station to natural gas only. Commercial-grade natural gas is intrinsically low in sulfur content, and results in low sulfur emissions. The facility s existing Title V operating permit (No TVR) provides an estimate of SO 2 emissions from the combustion of natural gas, as summarized below. 4-1

13 TABLE 4-3. SO 2 EMISSION ESTIMATES (NATURAL GAS) Emission SO 2 Unit lb/hr TPY 1G G SO 2 emissions from the two Comanche units are sufficiently low from natural gas usage that no addon control technology could be considered economically feasible. As a result, determines that natural gas usage is SO2 BART for the Comanche units. 4-2

14 5. PM BART DETERMINATION A summary of pre-bart PM emissions over the time period as described in Section 3 is included below. TABLE 5-1. BASELINE MAXIMUM 24-HOUR AVERAGE PM EMISSION RATES Emission Unit PM Emission Rate (lb/hr) 1G G IDENTIFICATION OF AVAILABLE RETROFIT PM CONTROL TECHNOLOGIES The first step of a BART determination is the identification of all available retrofit PM control technologies. A list of control technologies was obtained by reviewing the U.S. EPA s Clean Air Technology Center, control equipment vendor information, publicly-available air permits, applications, and BART analyses, and technical literature published by the U.S. EPA and Regional Planning Organizations (RPOs). TABLE 5-2. AVAILABLE PM CONTROL TECHNOLOGIES PM Control Technologies Electrostatic Precipitator (wet or dry) Baghouse (Fabric Filter) proposes to restrict fuel usage at the Comanche Station to natural gas only. As with SO 2, the use of commercial-grade natural inherently results in low particulate emissions. The facility s existing Title V operating permit (No TVR) provides an estimate of PM emissions from the combustion of natural gas, as summarized below. TABLE 5-3. PM EMISSION ESTIMATES Emission PM Unit lb/hr TPY 1G G

15 These emission estimates for these two Comanche units from natural gas usage are sufficiently low that no add-on control technology could be considered economically feasible. As a result, determines that natural gas usage is BART for PM for the Comanche units. 5-2

16 6. NO X BART DETERMINATION The highest 24-hr average pre-bart NO X emissions over the time period are summarized in Table 6-1. TABLE 6-1. BASELINE 24-HR AVERAGE NO X EMISSION RATES Unit ID NO X Hourly Emission Rate NO X Emission Rate (lb/hr) (lb/mmbtu) 1G G IDENTIFY ALL AVAILABLE RETROFIT TECHNOLOGIES Step 1 of the BART determination is the identification of all available retrofit NO X control technologies. For gas-fired applications, the Fedreal Rule at 40 CFR Part 51, Regional Haze Regulations and Guidelines for BART Determinations: Final Rule (70 Fed. Reg. July 6, 2005) indicates use of current combustion technology as BART. A list of current combustion control technologies, as applicable to the Gas- Tturbines, was obtained by reviewing the U.S. EPA s Clean Air Technology Center, control equipment vendor information, publicly-available air permits, applications, and BART analyses, and technical literature published by the U.S. EPA and the RPOs. TABLE 6-2. AVAILABLE NO X COMBUSTION CONTROL TECHNOLOGIES NO X Control Technologies Dry Low NOx Burners (LNB) As listed in Table 6-2, NO X emissions controls for the Comanche Power Station gas turbines based on current combustion control technology is limited to Dry Low NOx Burners. Site specific considerations and marginal performance results of approaches such as water or steam injection did not merit their consideration as control possibilities. 6.2 ELIMINATE TECHNICALLY INFEASIBLE OPTIONS Step 2 of the BART determination is to eliminate technically infeasible NO X control technologies that were identified in Step 1. In the case of the Comanche Power Station Units 1 and 2, the site specific applicable NOx control was limited to Dry Low NOx Burners and water or steam injection were considered inappropriate. 6-1

17 6.2.1 DRY LOW NOX BURNERS (DLNB) LNB technology utilizes advanced burner design to reduce NO X formation through the restriction of oxygen, lowering of flame temperature, and/or reduced residence time. LNB is a staged combustion process that is designed to split fuel combustion into two zones. In the primary zone, NO X formation is limited by either one of two methods. Under staged fuel-rich conditions, low oxygen levels limit flame temperatures resulting in less NO X formation. The primary zone is then followed by a secondary zone in which the incomplete combustion products formed in the primary zone act as reducing agents. Alternatively, under staged fuel-lean conditions, excess air will reduce flame temperature to reduce NO X formation. In the secondary zone, combustion products formed in the primary zone act to lower the local oxygen concentration, resulting in a decrease in NO X formation. When utilized in new turbine designs, reductions of up to 60 percent may result. 5 A similar level of effectiveness is expected with retrofit installations. This technology is considered a technically feasible option EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES The third step in the BART analysis is to rank the technically feasible options according to effectiveness. TABLE 6-3. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE NO X CONTROL TECHNOLOGIES Control Technology Estimated Control Efficiency (%) Dry Low NOx Burners ~30-60 Installation of dry low NOx burners is expected to allow the turbines to attain an emission level of 0.15 lb NOx/MMBtu EVALUATION OF IMPACTS FOR FEASIBLE NO X CONTROLS Step four for the BART analysis procedure is the impact analysis. The BART determination guidelines list four factors to be considered in the impact analysis: Cost of compliance Energy impacts Non-air quality impacts; and The remaining useful life of the source Evaluation of a fifth factor, visibility impacts, is addressed separately in Section "Assessment of Control Technology Options for BART-Eligible Sources: Steam Electric Boilers, Industrial Boilers, Cement Plants and Paper and Pulp Facilities" Northeast States for Coordinated Air Use Management (NESCAUM), March

18 6.4.1 COSTS OF COMPLIANCE Per the BART Guidelines, the costs of compliance analysis for each control option consists of comparisons of the average cost effectiveness and the incremental cost effectiveness, which are defined in Section IV.D.4 as follows: Average cost effectiveness means the total annualized costs of control divided by the annual emissions reduction (the difference between baseline annual emissions and the estimate of emissions after controls), using the following formula: Average cost effectiveness (dollars per ton removed) = Control option annualized cost (Baseline annual emissions Annual emissions with Control option) the incremental cost effectiveness calculation compares the costs of performance level of a control option to those of the next most stringent option, as shown in the following formula (with respect to cost per emissions reduction): Incremental Cost Effectiveness (dollars per incremental ton removed) = (Total annualized costs of control option) (Total annualized costs of next control option) (Control option annual emissions) (Next control option annual emissions) Capital costs associated with implementing the evaluated control systems were provided to by an after-market vendor. A detailed summary of those costs is included in Appendix B, while estimates of annual pollutant reductions for the evaluated control technologies are included in Appendix A. The average cost effectiveness of this control options is summarized in Table 6-4. Please note that since no other options were examined, incremental cost effectiveness is not relevant (and not included). TABLE 6-4. NO X CONTROL COSTS SUMMARY Average Cost Effectiveness Incremental Cost Effectiveness Emission Unit Control Strategy $/ton $/ton 1G1 and 1G2 Dry low NOx Burners 2, ENERGY AND NON-AIR IMPACTS Energy and non-air impacts from DLNB retrofit are minimal. expects that the retrofit will have a limited derating impact on the turbines, resulting in a total output decrease of 1-2%. 6-3

19 6.4.3 REMAINING USEFUL LIFE The remaining useful life of the Comanche units do not impact the annualized capital costs of potential controls because the useful lives of the units are anticipated to be at least as long as the capital cost recovery period, which is 20 years. 6.5 EVALUATE VISIBILITY IMPACTS In order to determine the change in visibility impact from the various NOx control options considered, calculated emissions were modeled in CALPUFF. As discussed in the modeling protocol included in Appendix A, visibility impacts were evaluated each of the four nearby Class I areas. Pre-BART baseline emissions for each unit are modeled and summarized below. Subsequent control scenarios incorporated calculated NOx emissions from post-control scenarios, and incorporated all other pollutants at baseline emissions. Per BART determination procedures, visibility impacts are presented below on a unit-by-unit basis. TABLE 6-5. COMANCHE UNIT 1G1 AND 1G2 VISIBILITY IMPACTS (NOX) Class I area 98 th Percentile Impact Pre-BART DLNB Visibility Improvement dv dv Caney Creek % Hercules-Glades % Upper Buffalo % Wichita Mountains % 6.6 PROPOSED BART FOR NO X has determined that the NO X BART for each of the Comanche units is DLNB. Based upon the modeled visibility improvement and calculated average cost effectiveness, this control option cannot be considered either technically or economically infeasible. Based upon DLNB control effectiveness estimates, proposes a BART NOx emission rate of 0.15 lb/mmbtu. 6-4

20 APPENDIX A EMISSION ESTIMATES

21 Comanche Power Station 24-hour Average Emission Estimates PM 10 Speciation Unit 1G1 Percent NOx SO 2 SO 4 (from SO 2 ) 1 PM (total) 2 PM (filterable) 3 PM (condensible) 3 Reduction lb/mmbtu lb/hr lb/mmbtu lb/hr lb/mmbtu lb/hr lb/mmbtu lb/hr lb/hr lb/hr Case 1 Baseline Case Case 2 DLNB 78% Unit 1G2 PM 10 Speciation Percent NOx SO 2 SO 4 (from SO 2 ) PM (total) PM (filterable) 3 PM (condensible) 3 Reduction lb/mmbtu lb/hr lb/mmbtu lb/hr lb/mmbtu lb/hr lb/mmbtu lb/hr lb/hr lb/hr Case 1 Baseline Case Case 2 DLNB 76% H 2 SO 4 emissions based upon the following assumptions: SO 2 Conversion to SO 3 = 10% SO 3 Conversion to H 2 SO 4 = 100% MW H 2 SO 4 = 98 lb/lbmol MW SO 2 = 64 lb/lbmol Sample Calculation: 0.75 lb SO2 lbmol 0.1 lbmol SO3 1 lbmol H2SO4 98 lb H2SO4 = 0.11 lb SO4 hr 64 lb SO2 lbmol SO2 lbmol SO3 lbmol hr 2 Baseline emission data for PM is not available. PM Emission Factor obtained from AP-42 (4/2000), Table 3.1-2a, Stationary Gas Turbines Please note that for natural gas usage, PM10 emissions can be considered equivalent to total PM. PM 10 = lb/mmbtu 3 Condensible/filterable PM speciation were based on the following profiles: For Natural Gas fired combustion turbines. Filterable 25.00% Condensible 75.00% 4 NOx control estimate for DLNB provided to by Siemens Westinghouse. See s dated 8/8/2008 and 8/13/2008 [Controlled emission rates for NE2-SW3_Comanche.xls] American Electric Power Comanche Power Station Emission Estimates (lbhr) Printed on 8/27/2008 Page 1 of

22 Comanche Power Station Annual Emission Estimates Unit ID 1G1 1G2 Maximum Heat Duty (MMBtu/hr) Unit 1G1 NOx % reduction lb/mmbtu 1 tpy Case 1 Baseline Case ,628 Case 2 DLNB 69% Unit 1G2 NOx % reduction lb/mmbtu 1 tpy Case 1 Baseline Case ,519 Case 2 DLNB 67% Baseline emission factor based upon annual average. Provided by via , 8/20/2008 American Electric Power Comanche Power Station Emission estimates (Annual) Printed on 8/27/2008 Page 2 of

23 Comanche Station CALPUFF Visibility Results Peak Impact 98th Percentile Pollutant Class I Area Control Technology ( dv) % Reduction from previous % Reduction from Baseline ( dv) % Reduction from previous % Reduction from Baseline NOx Caney Creek Baseline DLNB % 77% % 77% Herc-Glades Baseline DLNB % 77% % 78% Upper Buffalo Baseline DLNB % 77% % 78% Wichita Mts Baseline DLNB % 71% % 75% PM 10 Caney Creek Baseline Herc-Glades Baseline Upper Buffalo Baseline Wichita Mts Baseline SO 2 Caney Creek Baseline Herc-Glades Baseline Upper Buffalo Baseline Wichita Mts Baseline

24 APPENDIX B - ECONOMIC ANALYSES

25 Printed: 8/29/2008 Economic Analysis for Dry Low NOx Burners Capital Cost Summary Capital Cost TOTAL CAPITAL INVESTMENT a TCI = $34,660,000 Annual Cost Summary Annual Cost DIRECT OPERATING COSTS Low-NOx burners are not expected to incur any additional significant direct operating costs TOTAL DIRECT COSTS (DC) DC = $0 INDIRECT OPERATING COSTS Administrative Charges (2% of TCI) b $693,200 Insurance (1% of TCI) b $346,600 Property Taxes (1% of TCI) b $346,600 Capital Recovery (CRF x TCI) % interest CRF = $3,530,198 TOTAL INDIRECT COSTS (IC) IC = $4,916,598 TOTAL ANNUALIZED COST (TAC = DC + IC) TAC= $4,916,598 Cost Effectiveness Summary Annual Control Cost: $4,916,598 NOx to be Removed (tpy): c 1,891 CONTROL COST EFFECTIVENESS ($/ton): $2,600 a Cost data provided by (8/19/2008). Cost listed above is the total for both Comanche turbines b Direct and indirect cost factors taken from OAQPS Control Cost Manual, Sixth Edition, January c NOx total includes reductions from both turbines: Unit 1G1 Unit 1G2 DLNB NOx Removal Rate = 69% 67% Annual Capacity Factor = Provided by via , 8/20/2008 Baseline (pre-bart) emission factor = Based upon an annual average Maximum Firing Rate = MMBtu/hr, as listed in Permit No TV. Sample Calculation (Unit 1G1): 0.48 lb 1250 MMBtu 8760 hrs ton 0.53 capacity factor 0.69 NOx Removal Rate = tons NOx MMBtu hr yr 2000 lb year American Electric Power Comanche Power Station Cost Analysis (DLNB)

26 APPENDIX C CALPUFF MODELING PROTOCOL

27 APPENDIX D MODELING INPUT/OUTPUT FILES Control Scenario Description Model Run Number NOx SO 2 Case 1 Baseline Case Run 1 Run 1 Case 2 DLNB Run 2 --