AIR QUALITY PERMIT Issued under 401 KAR 52:020

Commonwealth of Kentucky Energy and Environment Cabinet Department for Environmental Protection Division for Air Quality 200 Fair Oaks Lane, 1 st Floor Frankfort, Kentucky 40601 (502) 564-3999 Proposed AIR QUALITY PERMIT Issued under 401 KAR 52:020 Permittee Name: Mailing Address: Cash Creek Generating, L.L.C. The Erora Group, L.L.C. 4350 Brownsboro Road, Suite 110 Louisville, KY 40207 Source Name: Mailing Address: Source Location: Cash Creek Generation Station The Erora Group, L.L.C. 4350 Brownsboro Road, Suite 110 Louisville, KY 40207 Kentucky State Highway 1078 in Henderson County Permit: V-09-006 Agency Interest: 40285 Activity: APE20080003 Review Type: Title V / Title IV / Title I - PSD, CAIR Source ID: 21-101-00134 Regional Office: County: Owensboro Regional Office 3032 Alvey Park Dr. W., Suite 700 Owensboro, KY 42303 (270) 687-7304 Henderson Application Complete Date: November 25, 2008 Issuance Date: March 5, 2010 Revision Date: N/A Expiration Date: March 5, 2015 Version 06/26/09 John S. Lyons, Director Division for Air Quality

TABLE OF CONTENTS SECTION ISSUANCE PAGE A. PERMIT AUTHORIZATION Initial 2 B. EMISSION POINTS, EMISSIONS UNITS, APPLICABLE Initial REGULATIONS, AND OPERATING CONDITIONS Combined Cycle Combustion Turbines (Emission Units HRSG1 and HRSG2) 4 Auxiliary Boiler (Emission Unit AUXB) 16 Methanation Startup Heater (Emission Unit MSH) 23 Acid Gas Recovery Vent (Emission Unit AGR) 30 Sulfur Recovery Unit (Emission Unit TO) 35 Flare (emission Unit FLR) 42 Aspirator Vent (Emission Unit ASP) 47 Emergency Generator and Fire Pump (Emission Units EG and FP) 50 Cooling Tower (Emission Unit CT1-22) 57 Fugitive Equipment Leaks (Emission Units FE-SYN, FE-AGR, FE-SRU, 60 and FE-MET) Coal Handling (Emission Units DC-1, DC-2, DC-3, DC-4, CH-1, CH-2, CH-3, 65 CH-4, CH-5, and CH-6) Fugitive Emissions (Emission Units ST1, ST2, SLF, CPF, LFWE, and CPWE) 75 Methanol Storage Tank (Emission Unit MST) 80 C. INSIGNIFICANT ACTIVITIES Initial 83 D. SOURCE EMISSION LIMITATIONS AND TESTING Initial 84 REQUIREMENTS E. SOURCE CONTROL EQUIPMENT REQUIREMENTS Initial 87 F. MONITORING, RECORDKEEPING, AND REPORTING Initial 88 REQUIREMENTS G. GENERAL CONDITIONS Initial 91 H. ALTERNATE OPERATING SCENARIOS Initial 97 I. COMPLIANCE SCHEDULE Initial 98 J. ACID RAIN Initial 99 K. NOx BUDGET Initial 101 Permit Number Permit type Activity Number Complete Date V-09-006 Initial APE20080003 11/25/08 TBD Issuance Date Summary of Action Construction/Operating Permit

Permit Number: V-09-006 Page 2 of 101 SECTION A PERMIT AUTHORIZATION Pursuant to a duly submitted application the Kentucky Division for Air Quality (Division) hereby authorizes the operation of the equipment described herein in accordance with the terms and conditions of this permit. This permit has been issued under the provisions of Kentucky Revised Statutes Chapter 224 and regulations promulgated pursuant thereto. The Division previously issued permit V-07-17 to Cash Creek Generating Station for the construction of a coal integrated gasification combined cycle electrical generation unit. The PSD authority to construct that was granted with that permit is terminated with the issuance of the proposed permit for V-09-006. The permittee shall not construct, reconstruct, or modify any affected facilities without first submitting a complete application and receiving a permit for the planned activity from the permitting authority, except as provided in this permit or in 401 KAR 52:020, Title V Permits. Issuance of this permit does not relieve the permittee from the responsibility of obtaining any other permits, licenses, or approvals required by the Kentucky Energy and Environment Cabinet (Cabinet) or any other federal, state, or local agency. Abbreviations BACT Btu Cabinet CAIR CEMS CH 4 CO CO 2 COMS Division dscf dscm g hp H 2 SO 4 H 2 S HRSGs hour J k lb m 3 MJ mmbtu mmcal MW MWh ng NO X O 2 Best Available Control Technology British thermal units Kentucky Energy and Environment Cabinet Clean Air Act Interstate Rule Continuous Emissions Monitoring System methane carbon monoxide carbon dioxide Continuous Opacity Monitoring System Kentucky Division for Air Quality dry standard cubic feet dry standard cubic meter gram horsepower sulfuric acid hydrogen sulfide heat recovery steam generators hr Joule kilo pound cubic meter mega Joules million British thermal units million calorie megawatt megawatt-hour nanograms nitrogen oxides oxygen

Permit Number: V-09-006 Page 3 of 101 SECTION A PERMIT AUTHORIZATION (CONTINUED) Pa PM PM 2.5 PM 10 ppm ppmv RATA scfh scm SCR SO 2 TDS tph tpy VOC Pascal Particulate Matter Particulate Matter less than 2.5 microns in diameter Particulate Matter less than 10 microns in diameter parts per million parts per million by volume Relative Accuracy Test Audit standard cubic feet/hour standard cubic meter Selective Catalytic Reduction sulfur dioxide Total Dissolved Solids tons per hour tons per year Volatile Organic Compounds

Permit Number: V-09-006 Page 4 of 101 REGULATIONS, AND OPERATING CONDITIONS Emission Unit: HRSG1 (HRSG1) Emission Unit: HRSG2 (HRSG2) Combined Cycle Combustion Turbine Combined Cycle Combustion Turbine Description: The combustion turbines and associated heat recovery steam generators (HRSG) produce electrical power for sale. The units are not lean premix or diffusion flame, and do not use water or steam injection for control of nitrogen oxides (NO X ). The HRSGs are used to provide steam to a steam turbine for additional power output. Construction Date: Estimated second quarter 2010. Fuel Input: 1938 million British thermal units per hour (mmbtu/hr), each turbine. Primary Fuel: Natural gas defined in 40 CFR 60, Subpart KKKK. Secondary Fuel: Natural gas defined in 40 CFR 60, Subpart Da (substitute natural gas). Power Output: Approximately 169.5 megawatt (MW) at 59 degrees Fahrenheit (does not include power from steam turbine) Control Equipment: Selective catalytic reduction (SCR) for control of NO X. Catalytic oxidizer for control of formaldehyde and carbon monoxide (CO). APPLICABLE REGULATIONS: 401 KAR 51:017 Prevention of significant deterioration of air quality. This regulation is applicable with respect to particulate matter (PM), particulate matter less than 10 microns in diameter (PM 10 ), particulate matter less than 2.5 microns in diameter (PM 2.5 ), sulfur dioxide (SO 2 ), NO X, and CO emissions from a new major stationary source that commenced after September 22, 1982. 401 KAR 51:210 CAIR NO X annual trading program. This regulation is applicable to Clean Air Interstate Rule (CAIR) NO X units that are subject to 40 CFR 96.104. This regulation establishes requirements for the control of NO X emissions from large boilers and turbines used in power plants pursuant to the federal mandate published under 40 CFR 96.101 to 96.188. Refer to Section K. 401 KAR 51:220 CAIR NO X ozone season trading program. This regulation is applicable to the control of CAIR NO X Ozone Season units that are subject to 40 CFR 96.304. This regulation establishes requirements for the control of NO X emissions from large boilers and turbines used in power plants pursuant to the federal mandate published under 40 CFR 96.301 to 96.388. Refer to Section K. 401 KAR 51:230 CAIR SO 2 trading program. This regulation is applicable to the control of CAIR SO 2 units under the CAIR SO 2 Trading Program that are subject to 40 CFR 96.204. This regulation establishes requirements for the control of SO 2 emissions from large boilers and turbines used in power plants pursuant to the federal mandate published under 40 CFR 96.201 to 96.288. Refer to Section K. 401 KAR 63:020 Potentially hazardous matter or toxic substances. This regulation is applicable to an emission unit which emits or may emit potentially hazardous matter or toxic

Permit Number: V-09-006 Page 5 of 101 substances, provided such emissions are not elsewhere subject to the provisions of the administrative regulations of the Division. Refer to SECTION D for operating limitations and compliance demonstration method. 401 KAR 60:005 40 C.F.R. Part 60 standards of performance for new stationary sources incorporating by reference 40 CFR 60 Subpart KKKK Standards of Performance for Stationary Combustion Turbine. This regulation is applicable to NO X and SO 2 emissions from stationary combustion turbines with a heat input at peak load equal to or greater than 10.7 gigajoules (10 mmbtu) per hour that commenced construction, modification or reconstruction after February 18, 2005. 40 CFR 64 Compliance Assurance Monitoring. This regulation is applicable with respect to CO. 40 CFR 75 Continuous Emission Monitoring. This regulation is applicable to continuous emissions monitoring system (CEMS) for NO X and SO 2. NON-APPLICABLE REGULATIONS 40 CFR 60 Subparts GG, Da, Db, or Dc. Pursuant to 40 CFR 60.4305(b), combustion turbines are exempt from the requirements of Subpart GG and recovery steam generators and duct burners regulated under Subpart KKKK are exempt from the requirements of Subparts Da, Db, and Dc. 40 CFR 63 Subpart YYYY, National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines. This regulation applies to major sources of hazardous air pollutants. This permit contains a federally enforceable emission limit on formaldehyde so as to preclude the applicability of this regulation. 1. Operating Limitations: a. Pursuant to 401 KAR 51:017, the permittee shall install and operate whenever the combustion turbine is in operation, the following control technology, equipment and methods required to meet Best Available Control Technology (BACT) demonstration: (1) A SCR unit for control of NO X ; (2) Low NO X burners for control of NO X ; (3) A catalytic oxidizer for the control of CO; and (4) Combust only natural gas and substitute natural gas fuel for control of PM\PM 10 \PM 2.5. b. For compliance with the source-wide limits to preclude the applicability of 40 CFR 63, Subpart YYYY, the permittee shall install and operate whenever the combustion turbine is in operation, the catalytic oxidizer for the control of formaldehyde (refer to SECTION D paragraph 4). c. Pursuant to 401 KAR 51:017, the combustion turbines are restricted to the combustion of natural gas and substitute natural gas. Natural gas is any fuel that meets the definition of natural gas in 40 CFR 60.4420. Substitute natural gas is any fuel that meets the definition of natural gas in 40 CFR 60.41Da.

Permit Number: V-09-006 Page 6 of 101 d. Pursuant to 401 KAR 51:017, the permittee shall not operate either combustion turbine at a firing rate less than 60 percent of the rated capacity on an hourly basis, except during periods of startup and shutdown events. Compliance Demonstration Methods: a. Refer to reporting requirements in SECTION F paragraph 9 for compliance with Operating Limitations a through d. b. Compliance with Operating Limitations b shall be demonstrated by fulfilling the following requirements: (1) Testing Requirements f; (2) Specific Monitoring Requirements g; (3) Specific Control Equipment Operating Conditions b; and (4) See SECTION D paragraph 4. c. Compliance with Operating Limitations a(4) and b, fuel use shall be demonstrated as follows: (1) If the fuel (natural gas as defined in 40 CFR 60.4420) is a naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in geologic formations beneath the earth's surface, of which the principal constituent is methane, the permittee shall maintain records showing fuel characteristics in a current, valid purchase contract, tariff sheet or transportation contract for the fuel, specifying the fuels major constituents and heat value; or (2) If the fuel is substitute natural gas (natural gas as defined in 40 CFR 60.41Da), produced in the gasification to natural gas process, the permittee shall develop a monitoring plan approved by the Division to demonstrate the following: (i) Procedure describing sampling and test methods used to verify that the fuel is composed of at least 70 percent methane by volume or has a calorific value between 34 and 43 mega Joules(MJ)/dry standard cubic meter (dscm) (910 and 1,150 British thermal unit (Btu)/dry standard cubic feet (dscf)); (ii) Heat content of the fuel; and (iii) Sample frequency shall meet the requirements of 40 CFR 60.4370. (3) The permittee shall use the following International Organization for Standardization methods, ISO 6974-1 through 6974-1 (to determine gas composition), and/or ISO 6976 (to determine calorific values.) d. For compliance with Operating Limitations c, a metering system shall be installed and operated to accurately and separately measure natural gas and substitute natural gas being fired in the combustion turbine. (Refer to SECTION F.9 for compliance reporting). 2. Emission Limitations: a. Pursuant to 401 KAR 51:017, based on BACT, the permittee shall not discharge into the atmosphere any gases from the combustion turbines that contain PM\PM 10 \PM 2.5, NO X, SO 2, and CO in concentrations that exceed the following limits:

Permit Number: V-09-006 Page 7 of 101 (1) PM\PM 10 \PM 2.5 0.0111 lb/mmbtu based on a three (3) hour rolling average; (2) NO X 0.0073 lb/mmbtu based on a twenty-four (24) hour rolling average; (3) SO 2 0.0006 lb/mmbtu based on a three (3) hour rolling average; and (4) CO 0.0047 lb/mmbtu based on a twenty-four (24) hour rolling average. b. Pursuant to 401 KAR 51:017, to ensure the validity of the NAAQS and increment consumption modeling, the permittee shall not discharge into the atmosphere any gases from emission units HRSG1 or HRSG2 that contain PM\PM 10 \PM 2.5, NO X, SO 2, and CO that exceed the following limits: (1) PM\PM 10 \PM 2.5 21.512 lb/hr based on a twenty-four (24) hour block average; (2) NO X 14.15 lb/hr based on a thirty (30) day block average; (3) SO 2 1.163 lb/hr based on a twenty-four (24) hour block average; and (4) CO 9.11 lb/hr based on an eight (8) hour block average. c. Pursuant to 40 CFR 60.4320(a), the permittee shall not discharge into the atmosphere any gases from the combustion turbines that contain NO X in concentrations that exceed the following limits based on a three (3) hour rolling average, unless the permittee uses a CEMS, then excess emission are determined pursuant to 60.4380(b)(1): (1) Natural gas 15 ppm at 15 percent oxygen (O 2 ) or 54 nanograms (ng)/joule (J) of useful output (0.43 lb/megawatt-hour (MWh); and (2) Substitute natural gas (fuels other than natural gas) 42 ppm at 15 percent O 2 or 160 ng/j of useful output (1.3 lb/mwh). d. Pursuant to 40 CFR 60.4330(a), the permittee shall not discharge into the atmosphere any gases from the combustion turbines that contain SO 2 in concentrations that exceed the following limits: (1) 110 ng/j (0.90 lb/mwh) gross output based on a three (3) hour rolling average; or (2) Fuel combusted shall not contain total potential sulfur emissions that exceed 26 ng SO 2 /J (0.060 lb SO 2 /mmbtu) heat input. e. Pursuant to 40 CFR 60.4325, when a combustion turbine is burning both natural gas and substitute natural gas, if the total heat input is greater than or equal to fifty (50) percent natural gas the permittee shall meet the natural gas emission limits. If the total heat input is greater than fifty (50) percent substitute natural gas the permittee shall meet the substitute natural gas emission limits. f. Refer to SECTION D paragraph 5 and 6 for source-wide limits of VOC and H 2 SO 4. Compliance Demonstration Methods: a. Compliance with PM\PM 10 \PM 2.5 Emission Limitations a(1) and b(1) shall be demonstrated by fulfilling the following requirements: (1) Operating Limitations a(4) and b; and (2) Specific Recordkeeping Requirements c(2). b. Compliance with NO X Emission Limitations a(2), b(2), and c shall be demonstrated by fulfilling the following requirements:

Permit Number: V-09-006 Page 8 of 101 (1) Operating Limitations a(1) and (2); (2) Testing Requirements b and c; (3) Specific Monitoring Requirements b, c and d; (4) Specific Recordkeeping Requirements b and c; and (5) Specific Reporting Requirements a and b. c. Compliance with SO 2 Emission Limitations a(3), b(3), and d shall be demonstrated by fulfilling the following requirements: (1) Testing Requirements d; (2) Specific Monitoring Requirements e; (3) Specific Recordkeeping Requirements b and c; and (4) Specific Reporting Requirements a. d. Compliance with CO Emission Limitations a(4) and b(4) shall be demonstrated by fulfilling the following requirements: (1) Testing Requirements a and b; (2) Specific Monitoring Requirements f; and (3) Specific Recordkeeping Requirements b and c. e. Refer to reporting requirements in SECTION F paragraph 9 for compliance with Emission Limitations e. f. For compliance with Emission Limitations f see SECTION D paragraph 5 and 6. 3. Testing Requirements: a. Pursuant to 401 KAR 59:005, Section 2, the permittee shall demonstrate compliance with the VOC, and formaldehyde emission limits by conducting an initial performance test within sixty (60) days after achieving the maximum production rate at which the unit will be operated, but not later than 180 days after initial startup of such facility. The performance test for VOC shall be done on either HRSG1 or HRSG2. The performance test shall be conducted in accordance with 401 KAR 50:045 and shall be conducted a minimum of once every five (5) years (no more than sixty-two (62) calendar months following the previous performance test). b. Pursuant to 401 KAR 52:020, Section 26, the maximum and minimum temperature operation range for the combustion turbine shall be established using manufacturer information and shall be between 2,300 and 2,400 degree Fahrenheit. The performance test for CO shall be conducted at the lower operating temperature. c. Pursuant to 40 CFR 60.4405, the initial NO X performance test required under 40 CFR 60.8 may be performed in the following alternative manner. (1) Perform a minimum of nine (9) relative accuracy test audit (RATA) reference method runs, with a minimum time per run of twenty-one (21) minutes, at a single load level, within plus or minus twenty-five (25) percent of 100 percent of peak load. The ambient temperature shall be greater than zero (0) degrees Fahrenheit during the RATA runs.

Permit Number: V-09-006 Page 9 of 101 (2) For each RATA run, concurrently measure the heat input to the unit using a fuel flow meter (or flow meters) and measure the electrical and thermal output from the unit. (3) Use the test data both to demonstrate compliance with the applicable NO X emission limit under Section 60.4320 and to provide the required reference method data for the RATA of the CEMS described under Section 60.4335. (4) Compliance with the applicable emission limit in Section 60.4320 is achieved if the arithmetic average of all of the NO X emission rates for the RATA runs, expressed in units of ppm or lb/mwh, does not exceed the emission limit. d. Pursuant to 401 KAR 52:020, Section 26, the SO 2 initial performance test required under 40 CFR 60.8 and 40 CFR 60.4415 may be performed in the following alternative manner. (1) Perform a minimum of nine (9) RATA reference method runs, with a minimum time per run of twenty-one (21) minutes, at a single load level, within plus or minus twenty-five (25) percent of 100 percent of peak load. The ambient temperature shall be greater than zero (0) degrees Fahrenheit during the RATA runs. (2) For each RATA run, concurrently measure the heat input to the unit using a fuel flow meter (or flow meters) and measure the electrical and thermal output from the unit. (3) Use the test data both to demonstrate compliance with the applicable SO 2 emission limit under Section 60.4330 and to provide the required reference method data for the RATA of the CEMS. (4) Compliance with the applicable emission limit in Section 60.4330 is achieved if the arithmetic average of all of the SO 2 emission rates for the RATA runs, expressed in units of ng/j or lb/mwh does not exceed the emission limit. e. Pursuant to 401 KAR 52:020, Section 26, the initial CO performance test required under 40 CFR 60.8 may be performed in the following alternative manner. (1) Perform a minimum of nine (9) RATA reference method runs, with a minimum time per run of twenty-one (21) minutes, at a single load level, within plus or minus twenty-five (25) percent of 100 percent of peak load. The ambient temperature shall be greater than zero (0) degrees Fahrenheit during the RATA runs. (2) For each RATA run, concurrently measure the heat input to the unit using a fuel flow meter (or flow meters) and measure the electrical and thermal output from the unit. (3) Use the test data both to demonstrate compliance with the applicable CO emission limit and to provide the required reference method data for the RATA of the CEMS. (4) Compliance with the applicable emission limit is achieved if the arithmetic average of all of the CO emission rates for the RATA runs, expressed in units of lb/hr or lb/mmbtu does not exceed the emission limit. f. Pursuant to 40 CFR 64.7 and 401 KAR 52:020, Section 26, during the performance test the permittee shall establish the VOC and formaldehyde destruction efficiency and operating limits for the catalytic oxidizer as follows.

Permit Number: V-09-006 Page 10 of 101 (1) The catalytic oxidizer shall be operated within a temperature range of 450 to 750 degrees Fahrenheit. (2) During the performance test, monitor and record the temperature just before the catalyst bed and the temperature difference across the catalyst bed at least once every fifteen (15) minutes during each of the three (3) test runs. (3) Use the data collected during the performance test to calculate and record the average temperature just before the catalyst bed and the average temperature difference across the catalyst bed during the performance test. These are the minimum operating limits for the catalytic oxidizer. 4. Specific Monitoring Requirements: a. Pursuant to Section 60.4340(b), the permittee must install, calibrate, maintain and operate a NO X CEMS as described in Sections 60.4335(b) and 60.4345. b. Pursuant to 40 CFR 60.4335(b), the permittee shall: (1) Install, certify, maintain, and operate a CEMS consisting of a NO X monitor and a diluent gas O 2 or CO 2 monitor, to determine the hourly NO X emission rate in ppm or lb/mmbtu; (2) For units complying with the output-based standard, install, calibrate, maintain, and operate a fuel flow meter (or flow meters) to continuously measure the heat input to the combustion turbine; (3) For units complying with the output-based standard, install, calibrate, maintain, and operate a watt meter (or meters) to continuously measure the gross electrical output of the combustion turbine in MWh; and (4) For combined heat and power units complying with the output-based standard, install, calibrate, maintain, and operate meters for useful recovered energy flow rate, temperature, and pressure, to continuously measure the total thermal energy output in Btu/hr. c. Pursuant to 40 CFR 60.4345, the NO X CEMS shall meet the following requirements: (1) Each NO X diluent CEMS shall be installed and certified according to Performance Specification 2 in 40 CFR 60, Appendix B, except the seven (7) day calibration drift is based on unit operating days, not calendar days. With state approval, Procedure 1 in 40 CFR 60, Appendix F is not required. Alternatively, a NO X diluent CEMS that is installed and certified according to 40 CFR 75 Appendix A is acceptable for use. The RATA of the CEMS shall be performed on a lb/mmbtu basis; (2) As specified in 40 CFR 60.13(e)(2), during each full unit operating hour, both the NO X monitor and the diluent monitor shall complete a minimum of one (1) cycle of operation (sampling, analyzing, and data recording) for each fifteen (15) minute quadrant of the hour, to validate the hour. For partial unit operating hours, at least one (1) valid data point shall be obtained with each monitor for each quadrant of the hour in which the unit operates. For unit operating hours in which required quality assurance and maintenance activities are performed on the CEMS, a minimum of two (2) valid data points (one in each of two (2) quadrants) are required for each monitor to validate the NO X emission rate for the hour;

Permit Number: V-09-006 Page 11 of 101 (3) Each fuel flow meter shall be installed, calibrated, maintained, and operated according to the manufacturer's instructions. Alternatively, with approval by the Division, fuel flow meters that meet the installation, certification, and quality assurance requirements of part 40 CFR 75 Appendix D are acceptable for use; (4) Each watt meter, steam flow meter, and each pressure or temperature measurement device shall be installed, calibrated, maintained, and operated according to manufacturer's instructions; and (5) The permittee shall develop and keep on-site a quality assurance (QA) plan for all of the continuous monitoring equipment described above. For the CEMS and fuel flow meters, the permittee may, with approval by the Division, satisfy the requirements of this paragraph by implementing the QA program and plan described in Section 1 of 40 CFR 75 Appendix B. d. Pursuant to 40 CFR 60.4350, excess NO X emissions when using a CEMS can be determined as follows: (1) All CEMS data must be reduced to hourly averages as specified in Section 60.13(h); (2) For each unit operating hour in which a valid hourly average, as described in Section 60.4345(b), is obtained for both NO X and diluent monitors, the data acquisition and handling system must calculate and record the hourly NO X emission rate in units of ppm or lb/mmbtu, using the appropriate equation from Method 19 in 40 CFR 60, Appendix A of this part. For any hour in which the hourly average O 2 concentration exceeds nineteen (19.0) percent O 2 (or the hourly average CO 2 concentration is less than one (1.0) percent CO 2 ), a diluent cap value of nineteen (19.0) percent O 2 or one (1.0) percent CO 2 (as applicable) may be used in the emission calculations; (3) Correction of measured NO X concentrations to fifteen (15) percent O 2 is not allowed; (4) If you have installed and certified a NO X diluent CEMS to meet the requirements of 40 CFR 75 of this chapter, states can approve that only quality assured data from the CEMS shall be used to identify excess emissions under 40 CFR 60, Subpart KKKK. Periods where the missing data substitution procedures in 40 CFR 75, Subpart D are applied are to be reported as monitor downtime in the excess emissions and monitoring performance report required under Section 60.7(c); (5) All required fuel flow rate, steam flow rate, temperature, pressure, and megawatt data must be reduced to hourly averages; (6) Calculate the hourly average NO X emission rates, in units of the emission standards under Section 60.4320, using either ppm for units complying with the concentration limit or for combined-cycle and combined heat and power complying with the output-based standard, use Equation 1 Section 60.4350, except that the gross energy output is calculated as the sum of the total electrical and mechanical energy generated by the combustion turbine, the additional electrical or mechanical energy (if any) generated by the steam turbine following the heat recovery steam generator, and 100 percent of the total useful thermal energy output that is not used to generate additional electricity or mechanical output, expressed in equivalent MW, as in the Equation 2 and 3 of Section 60.4350; and

Permit Number: V-09-006 Page 12 of 101 (7) For combined cycle and combined heat and power units with heat recovery, use the calculated hourly average emission rates from paragraph (6) of this section to assess excess emissions on a thirty (30) unit operating day rolling average basis, as described in Section 60.4380(b)(1). e. Pursuant to 401 KAR 52:020, Section 26, the permittee shall install a SO 2 CEMS, the permittee and shall certify, operate, and maintain, in accordance with all the requirements of 40 CFR 75, a CEMS and a flow monitoring system with an automated data acquisition and handling system for measuring and recording concentration (in ppm), volumetric gas flow (in standard cubic feet/hour (scfh)), and mass emissions (in lb/hr) discharged to the atmosphere, except as provided in 40 CFR 75.11 and 75.16 and 40 CFR 75 Subpart E. f. Pursuant to 401 KAR 52:020, Section 26, material incorporated by reference, the permittee shall install, calibrate, maintain, and operate a CO CEMS. The permittee shall install, calibrate, operate, test, and monitor all continuous monitoring systems and monitor devices in accordance with 40 CFR 60.13. g. Pursuant to 40 CFR 64.6 (c), the permittee must meet the following continuous monitoring requirements for the catalytic oxidizer. (1) Install gas temperature monitors upstream and downstream of the catalyst bed as required by Testing Requirements f(2) and (3). (i) Locate the temperature sensor in a position that provides a representative temperature. (ii) Use a temperature sensor with a measurement sensitivity of five (5) degrees Fahrenheit or one (1) percent of the temperature value, whichever is larger. (iii) Refer to SECTION E paragraph 2 for additional requirements. (2) Collect temperature data at least once every fifteen (15) minutes and reduce the data to three (3) hour block averages. (i) Maintain the three (3) hour average temperature before the catalyst bed at or above the temperature limit established according Testing Requirements f(2). (ii) (iii) Maintain the three (3) hour average temperature difference across the catalyst bed at or above the temperature limit established according to Testing Requirements f(3). Refer to SECTION F for additional requirements. h. Pursuant to 401 KAR 51:160, 401 KAR 51:210 and 401 KAR 51:220, the permittee shall monitor the total NO X emissions during each NO X control period as specified in 40 CFR 96.70 to 96.76, 40 CFR 96.170 to 96.175 and 96.370 to 96.375. i. Pursuant to 401 KAR 51:230, the permittee shall monitor the total SO 2 emissions during each SO 2 control period as specified in 96.270 to 96.275. 5. Specific Recordkeeping Requirements: a. Pursuant to 401 KAR 59:005, Section 3(2), the permittee shall maintain the records of the occurrence and duration of any startup, shutdown, or malfunction in the

Permit Number: V-09-006 Page 13 of 101 operation of the combustion turbines; any malfunction of the air pollution control equipment; or any periods during which a continuous emission monitoring system or monitoring device is inoperative. The permittee shall maintain records of the date, time and duration of cold startup, hot startup and cumulative startup events per rolling twelve (12) month period. b. Pursuant to 401 KAR 52:020, Section 26, the permittee shall maintain the following records on site: (1) All measurements, including CEMS, monitoring devices, and performance test results; and all continuous monitoring system performance evaluations and calibration checks; (2) Manufacturer's maintenance and operating instructions for the pollution control devices and process equipment; and (3) Maintenance conducted on control devices, instrumentation, and process equipment. c. The permittee shall maintain the following records on site with totals calculated on a monthly basis and a twelve (12) month rolling total: (1) Emissions of PM\PM 10 \PM 10, NO X, SO 2 and CO with data from monitoring devices or by calculations using emission factors, data from performance tests, fuel usage, and process rates or other applicable data along with supporting calculations. (2) Fuel usage and fuel specifications from supplier; (3) Hours of operation of each combustion turbine; and (4) Records of applicable fuel sampling, including but not limited to, time of sampling event, vendor information, sulfur content analysis, percent methane analysis, and heat value analysis. d. Pursuant to 40 CFR 64.9, the following records shall be maintained for the catalytic oxidizer: (1) Records of the date, time and duration of each deviation from the operating limits; and (2) Records required demonstrating continuous compliance with each operating limit. 6. Specific Reporting Requirements: a. Pursuant to 40 CFR 60.4375, the permittee must submit the following reports: (1) Pursuant to 40 CFR 60.4375(a), reports of excess emissions and monitor downtime, in accordance with 40 CFR 60.7(c) (excess emissions shall be reported for all periods of unit operation, including start-up, shutdown, and malfunction); and (2) Pursuant to 40 CFR 60.4375(b), a written report of the results of each performance test before the close of business on the 60 th day following the completion of the performance test. b. Pursuant to 40 CFR 60.4380, for the purpose of reporting required in 40 CFR 60.7(c), excess emissions and monitor downtime for NO X are defined as follows.

Permit Number: V-09-006 Page 14 of 101 (1) An excess emissions is any unit operating period in which the four (4) hour or thirty (30) day rolling average NO X emission rate exceeds the applicable emission limit in Section 60.4320. A four (4) hour rolling average NO X emission rate is the arithmetic average of the average NO X emission rate in ppm or ng/j (lb/mwh) measured by the CEMS for a given hour and the three (3) unit operating hour average NO X emission rates immediately preceding that unit operating hour. Calculate the rolling average if a valid NO X emission rate is obtained for at least three (3) of the four (4) hours. A thirty (30) day rolling average NO X emission rate is the arithmetic average of all hourly NO X emission data in ppm or ng/j (lb/mwh) measured by the continuous emission monitoring equipment for a given day and the twenty-nine (29) unit operating days immediately preceding that unit operating day. A new thirty (30) day average is calculated each unit operating day as the average of all hourly NO X emissions rates for the preceding thirty (30) unit operating days if a valid NO X emission rate is obtained for at least seventy-five (75) percent of all operating hours. (2) A period of monitor downtime is any unit operating hour in which the data for any of the following parameters are either missing or invalid: NO X concentration, CO 2 or O 2 concentration, fuel flow rate, steam flow rate, steam temperature, steam pressure, or MW. The steam flow rate, steam temperature, and steam pressure are only required if you will use this information for compliance purposes. c. Pursuant to 40 CFR 60.4395, all reports required under 40 CFR 60.7(c) must be postmarked by the 30 th day following the end of each six (6) month period. d. Pursuant to 40 CFR 64.9, the permittee shall include in the semi-annual report required by SECTION F paragraph 6, summary information on the number, duration and cause (including unknown cause if applicable) of excursions from normal operation and the corrective actions taken, where excursions are defined as the following: (1) Each occurrence where the three (3) hour average temperature before the catalyst bed was below the temperature limit established most recent performance according to Testing Requirements f(2); and (2) Each occurrence where the three (3) hour average temperature difference across the catalyst bed was below the temperature limit established most recent performance according to Testing Requirements f(3). 7. Specific Control Equipment Operating Conditions: a. Pursuant to 40 CFR 60.4333(a), the permittee shall operate and maintain the stationary combustion turbine, air pollution control equipment, and monitoring equipment in a manner consistent with good air pollution control practices for minimizing emissions at all times including during startup, shutdown, and malfunction. b. For compliance with the BACT Operating Limitations a(3), and during operation of the combustion turbines, the permittee shall meet the following operating limits for the catalytic oxidizer:

Permit Number: V-09-006 Page 15 of 101 (1) The average temperature measured just before the catalyst bed in any three (3) hour period must not fall below the limit established according to Testing Requirements f(2); and (2) The average temperature difference across the catalyst bed in any three (3) hour period shall not fall below the temperature difference established according to Testing Requirements f(3).

Permit Number: V-09-006 Page 16 of 101 Emission unit: AUXB (AUXB) Auxiliary Boiler Description: The auxiliary boiler is used to provide process steam during startup. The unit has a high heat release rate greater than 730,000 J/sec-m 3 (70,000 Btu/hr-ft 3 ). Construction Date: Estimated second quarter 2010. Fuel Input: 278.8 mmbtu/hr. Primary Fuel: Natural gas. Control Equipment: None. APPLICABLE REGULATIONS: 401 KAR 51:017 Prevention of significant deterioration of air quality. This regulation is applicable with respect to PM\PM 10 \PM 2.5, SO 2, NO X, and CO emissions from a new major stationary source that commenced after September 22, 1982. 401 KAR 51:220 CAIR NO X ozone season trading program. This regulation is applicable to the control of CAIR NO X Ozone Season units that are subject to 40 CFR 96.304. This regulation establishes requirements for the control of NO X emissions from large boilers and turbines used in power plants pursuant to the federal mandate published under 40 CFR 96.301 to 96.388. Refer to Section K. 401 KAR 59:015 New indirect heat exchangers. This regulation is applicable with respect to PM, NO X, and SO 2 emissions from a source with a capacity of more than 250 mmbtu/hr heat input that commenced after August 17, 1971. 401 KAR 60:005 40 C.F.R. Part 60 standards of performance for new stationary sources incorporating by reference 40 CFR 60, Subpart Db Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units. This regulation is applicable with respect to NO X and SO 2 emissions from each affected facility with a heat input capacity greater than 100 mmbtu/hr that commenced after June 19, 1984. 401 KAR 63:020 Potentially hazardous matter or toxic substances. This regulation is applicable to an emission unit which emits or may emit potentially hazardous matter or toxic substances, provided such emissions are not elsewhere subject to the provisions of the administrative regulations of the Division. Refer to SECTION D for operating limitations and compliance demonstration method. NON-APPLICABLE REGULATIONS: 40 CFR 60, Subpart D Standards of Performance for Fossil-Fuel-Fired Steam Generators. Not applicable pursuant to 40 CFR Part 60.40b(j). 1. Operating Limitations: a. Pursuant to 401 KAR 51:017, the permittee shall install and operate whenever the auxiliary boiler is in operation, the following control technology, equipment and methods required to meet BACT demonstration:

Permit Number: V-09-006 Page 17 of 101 (1) Combust only natural gas fuel for control of PM\PM 10 \PM 2.5 and SO 2 ; (2) Low NO X burners for control of NO X ; and (3) Maximum operation shall be 500 hours based on a twelve (12) month rolling total for control of PM\PM 10 \PM 2.5, NO X, SO 2, and CO. b. Pursuant to 40 CFR 60.44b(j), the unit is limited to the firing of natural gas and a combined annual capacity factor of ten (10) percent. Compliance Demonstration Methods: a. Compliance with Operating Limitations a(1) and (2) shall be demonstrated by Specific Recordkeeping Requirements b, and reporting requirements in SECTION F paragraph 9. b. Compliance with Operating Limitations a(3) and b shall be demonstrated by meeting the obligations of Specific Recordkeeping Requirements f, and reporting requirements in SECTION F paragraph 9. 2. Emission Limitations: a. Pursuant to 401 KAR 51:017, based on the BACT, the permittee shall not discharge into the atmosphere any gases from the auxiliary boiler that contain PM\PM 10 \PM 2.5, NO X, SO 2, and CO in concentrations that exceed the following limits based on a three (3) hour rolling average: (1) PM\PM 10 \PM 2.5 0.007 lb/mmbtu; (2) NO X 0.036 lb/mmbtu; (3) SO 2 0.006 lb/mmbtu; and (4) CO 0.037 lb/mmbtu. b. Pursuant to 401 KAR 51:017, to ensure the validity of the NAAQS and increment consumption modeling, the permittee shall not discharge into the atmosphere any gases from the combustion turbines that contain PM\PM 10 \PM 2.5, NO X, SO 2, and CO that exceed the following limits: (1) PM\PM 10 \PM 2.5 1.923 lb/hr based on a twenty-four (24) hour block average; (2) NO X 10.037 lb/hr based on a thirty (30) day-block average; (3) SO 2 1.673 lb/hr based on a twenty-four (24) hour block average; and (4) CO 10.316 lb/hr based on an eight (8) hour block average. c. Pursuant to 40 CFR 60 Subpart Db, the permittee shall not discharge into the atmosphere any gases from the auxiliary boiler that contain NO X and SO 2 in concentrations that exceed: (1) NO X 86 ng/j (0.2 lb/mmbtu) heat input (high heat release rate). [Section 60.44b(a)] Compliance demonstration shall be on a twenty-four hour (24) average basis for initial performance test and three (3) hour average basis for subsequent performance tests [60.44b(j)]; and (2) SO 2 87 ng/j (0.20 lb/mmbtu) heat input or eight (8) percent (0.08) of the potential SO 2 emission rate (92 percent reduction) and 520 ng/j (1.2 lb/mmbtu) heat input. [Section 60.42b(k)(1)] Compliance demonstration shall be based on a three (3) hour average.

Permit Number: V-09-006 Page 18 of 101 d. Pursuant to 401 KAR 59:015, the permittee shall not discharge into the atmosphere any gases from the auxiliary boiler that contains PM, NO X and SO 2 in concentrations that exceed the following limits based on a three (3) hour average: (1) PM 0.10 lb/mmbtu heat input [Section 4(1)(b)]; (2) NO X 0.20 lb/mmbtu (0.36 gram (g)/million calorie (mmcal) [Section 6(1)(a)]; and (3) SO 2 0.8 lb/mmbtu actual heat input. [Section 5(1)(b)] e. Pursuant to 401 KAR 59:015, Section 4(2), emissions shall not exhibit greater than twenty (20) percent opacity except: (1) Indirect heat exchangers with heat input capacity of 250 mmbtu/hr or more, a maximum of twenty-seven (27) percent opacity shall be permissible for not more than one (1) six (6) minute period in any sixty consecutive minutes; and (2) For emissions from an indirect heat exchanger during building a new fire for the period required to bring the boiler up to operating conditions provided the method used is that recommended by the manufacturer and the time does not exceed the manufacturer's recommendations. f. For limits on source-wide emissions of VOC, refer to SECTION D, paragraph 5. Compliance Demonstration Methods: a. Compliance with PM\PM 10 \PM 2.5 Emission Limitations a(1), b(1) and d(1) is demonstrated by fulfilling the following requirements: (1) Operating Limitations a(1); (2) Testing Requirements a; and (3) Specific Recordkeeping Requirements d. b. Compliance with NO X Emission Limitations a(2), b(2), c(1) and d(2) shall be demonstrated by fulfilling the following requirements: (1) Testing Requirements b and c; (2) Monitoring Requirements a; (3) Specific Recordkeeping Requirements d; and (4) Specific Reporting Requirements a, b, c and e. c. Compliance with SO 2 Emission Limitations a(3), b(3) and c(2) and d(3) shall be demonstrated by fulfilling the following requirements: (1) Testing Requirements a; (2) Specific Monitoring Requirements b; (3) Specific Recordkeeping Requirements b and d; and (4) Specific Reporting Requirements a, b, c and d. d. Compliance with CO Emission Limitations a(4) and b(4) shall be demonstrated by fulfilling the following requirements: (1) Testing Requirements a. (2) Specific Recordkeeping Requirements d.

Permit Number: V-09-006 Page 19 of 101 e. Compliance with opacity Emission Limitations e shall be demonstrated by fulfilling the requirements of Operating Limitations a(1). f. For compliance with Emission Limitations f see SECTION D paragraph 5. 3. Testing Requirements: a. Pursuant to 401 KAR 59:005, Section 2 the permittee, the permittee shall demonstrate compliance with the PM\PM 10 \PM 2.5, SO 2 and CO emission limits by conducting an initial performance test within sixty (60) days after achieving the maximum production rate at which the unit will be operated, but not later than 180 days after initial startup of such facility. The performance test shall be conducted in accordance with 401 KAR 50:045 and shall be conducted a minimum of once every five (5) years (no more than sixty-two (62) calendar months following the previous performance test). b. Pursuant to 40 CFR 60.46b(c), the permittee must demonstrate continuous compliance with NO X emission standards through the following performance testing: (1) Pursuant to 40 CFR 60.46b(g), the permittee shall demonstrate the maximum heat input capacity of the steam generating unit by operating the facility at maximum capacity for twenty-four (24) hours. The permittee shall determine the maximum heat input capacity by using the heat loss method or the heat input method described in Sections 5 and 7.3 of the ASME Power Test Codes 4.1 (incorporated by reference, see 40 CFR 60.17). The demonstration of maximum heat input capacity shall be made during the initial performance test for a boiler that meets the criteria of 60.44b(j). Subsequent demonstrations may be required by the Division at any other time. If this demonstration indicates that the maximum heat input capacity of the boiler is less than that stated by the manufacturer of the boiler, the maximum heat input capacity determined during this demonstration shall be used to determine the capacity utilization rate for the boiler. Otherwise, the maximum heat input capacity provided by the manufacturer is used; and (2) Pursuant to 40 CFR 60.46b(h), the permittee shall complete the following performance tests: (i) Conduct an initial performance test as required under 40 CFR 60 Subpart A, Section 60.8 over a minimum of twenty-four (24) consecutive steam generating unit operating hours at maximum heat input capacity to demonstrate compliance with the NO X emission standards under Section 60.44b using Method 7, 7A, 7E in 40 CFR 60, Appendix A, or other reference methods approved by the Division and EPA; and (ii) Conduct subsequent performance tests once per calendar year or every 400 hours of operation (whichever comes first) to demonstrate compliance with the NO X emission standards under Section 60.44b over a minimum of three (3) consecutive steam generating unit operating hours at maximum heat input capacity using Method 7, 7A, 7E in 40 CFR 60, Appendix A, or other reference methods approved by the Division and EPA.

Permit Number: V-09-006 Page 20 of 101 c. Pursuant to 40 CFR 60.44b(j), compliance with the NO X emission limits are determined on a twenty-four (24) hour average basis for the initial performance test and three (3) hour average basis for subsequent performance tests for any facility that meets the following requirements: (1) Combust only natural gas; (2) Have a combined annual capacity factor of ten (10) percent or less for natural gas; and (3) Are subject to a federally enforceable requirement limiting operation of the affected facility to the firing of natural gas and limiting operation of the affected facility to a combined annual capacity factor of ten (10) percent or less for natural gas. 4. Specific Monitoring Requirements: a. Pursuant to 40 CFR 60.46b(c) the permittee does not have to install a NO X CEMS if the requirements in 60.46b(g) and (h) are meet. Refer to Testing Requirements b(1) and (2). b. Pursuant to 40 CFR 60.47b(f), the permittee does not have to install or operate a SO 2 CEMS if firing only very low sulfur gaseous fuel with a potential SO 2 emission rate of 140 ng/j (0.32 lb/mmbtu) heat input or less [60.42b(k)(2)], and fuel records are maintained pursuant to Section 60.49b(r)(1). Refer to Specific Recordkeeping Requirements b. c. Pursuant to 401 KAR 51:160 and 401 KAR 51:220, the permittee shall monitor the total NO X emissions during each NO X control period as specified in 40 CFR 96.70 to 96.76 and 96.370 to 96.375. 5. Specific Recordkeeping Requirements: a. Pursuant to 401 KAR 59:005, Section 3(2), the permittee shall maintain the records of the occurrence and duration of any startup, shutdown, or malfunction in the operation of the auxiliary boiler; or any periods during which a monitoring device is inoperative. b. The permittee must maintain fuel records pursuant to Section 60.49b(r)(1). c. Pursuant to 401 KAR 52:020, Section 26, the permittee shall maintain the following records on site: (1) All measurements, including monitoring devices and performance test results; and all calibration checks; (2) Manufacturer's maintenance and operating instructions for process equipment; and (3) Maintenance conducted on control devices, instrumentation, and process equipment. d. The permittee shall document and maintain the records showing emissions of PM\PM 10 \PM 2.5, NO X, SO 2 and CO with data from monitoring devices or by calculations using emission factors, data from performance tests, fuel usage, and

Permit Number: V-09-006 Page 21 of 101 process rates or other applicable data along with supporting calculations based on a monthly basis and a twelve (12) month rolling total. e. Pursuant to 40 CFR 60.49b(d), the permittee must record and maintain records of the amount of fuel combusted during each calendar month. f. Pursuant to 40 CFR 60.49b(p), the permittee shall maintain records of the following information each operating day: (1) Calendar date; (2) The number of hours of operation; and (3) A record of the hourly steam load. 6. Specific Reporting Requirements: a. Pursuant to 40 CFR 60.49b(a), the permittee shall submit notification of the date of initial startup, as provided by 40 CFR 60.7. This notification shall include: (1) The design heat input capacity of the boiler and identification of the fuel to be combusted; (2) If applicable, a copy of any federally enforceable requirement that limits the annual capacity factor for fuels under Sections 60.44b(i), (j), 60.45b(d), (g), 60.46b(h), or 60.48b(i); and (3) The annual capacity factor at which the permittee anticipates operating the facility. b. Pursuant to 40 CFR 60.49b(b), the permittee shall submit to the Division the performance test data from the initial performance test and shall submit to the Division the maximum heat input capacity data from the demonstration of the maximum heat input capacity of the boiler. c. Pursuant to 40 CFR 60.49b(h), the permittee shall submit excess emission reports that occurred during the reporting period. d. Pursuant to 40 CFR 60.49b(r)(1), the permittee shall submit a report to the Division certifying that only natural gas that is known to contain insignificant amounts of sulfur were combusted in the affected facility during the reporting period. e. Pursuant to 40 CFR 60.49b(q), the permittee shall submit to the Division a report containing: (1) The annual capacity factor over the previous twelve (12) months; and (2) Results of any NO X performance tests required during the reporting period, the hours of operation during the reporting period, and the hours of operation since the last NO X emission test. f. Pursuant to 40 CFR 60.49b(v), the permittee may submit electronic quarterly reports for NO X and SO 2 in lieu of submitting the written reports required under Section 60.49b(h), (i), (j), (k), and (l). The format of each quarterly electronic reports shall be coordinated with the Division. The electronic report shall be submitted no later than thirty (30) days after the end of the calendar quarter and shall be accompanied by a certification statement from the permittee, indicating whether compliance with the