frankfort, kentucky 40601 final - sierra club storage tank (emission unit mst) 80 c. insignificant...

Commonwealth of Kentucky Energy and Environment Cabinet

Department for Environmental Protection Division for Air Quality

200 Fair Oaks Lane, 1st Floor Frankfort, Kentucky 40601

(502) 564-3999

Final AIR QUALITY PERMIT Issued under 401 KAR 52:020

Permittee Name: Cash Creek Generating, L.L.C. Mailing Address: The Erora Group, L.L.C. 4350 Brownsboro Road, Suite 110 Louisville, KY 40207

Source Name: Cash Creek Generation Station Mailing Address: The Erora Group, L.L.C. 4350 Brownsboro Road, Suite 110 Louisville, KY 40207

Source Location: 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: Owensboro Regional Office 3032 Alvey Park Dr. W., Suite 700 Owensboro, KY 42303 (270) 687-7304 County: Henderson

Application Complete Date: November 25, 2008 Issuance Date: May 5, 2010 Revision Date: N/A Expiration Date: May 5, 2015

John S. Lyons, Director

Division for Air Quality Version 06/26/09

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

Issuance Date

Summary of Action

V-09-006 Initial APE20080003 11/25/08 TBD Construction/OperatingPermit

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 Best Available Control Technology Btu British thermal units Cabinet Kentucky Energy and Environment Cabinet CAIR Clean Air Act Interstate Rule CEMS Continuous Emissions Monitoring System CH4 methane CO carbon monoxide CO2 carbon dioxide COMS Continuous Opacity Monitoring System Division Kentucky Division for Air Quality dscf dry standard cubic feet dscm dry standard cubic meter g gram hp horsepower H2SO4 sulfuric acid H2S hydrogen sulfide HRSGs heat recovery steam generators hour hr J Joule k kilo lb pound m3 cubic meter MJ mega Joules mmBtu million British thermal units mmcal million calorie MW megawatt MWh megawatt-hour ng nanograms NOX nitrogen oxides O2 oxygen


SECTION A – PERMIT AUTHORIZATION (CONTINUED) Pa Pascal PM Particulate Matter PM2.5 Particulate Matter less than 2.5 microns in diameter PM10 Particulate Matter less than 10 microns in diameter ppm parts per million ppmv parts per million by volume RATA Relative Accuracy Test Audit scfh standard cubic feet/hour scm standard cubic meter SCR Selective Catalytic Reduction SO2 sulfur dioxide TDS Total Dissolved Solids tph tons per hour tpy tons per year VOC Volatile Organic Compounds


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS Emission Unit: HRSG1 (HRSG1) Combined Cycle Combustion Turbine Emission Unit: HRSG2 (HRSG2) 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 (NOX). 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 NOX. 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 (PM10), particulate matter less than 2.5 microns in diameter (PM2.5), sulfur dioxide (SO2), NOX, and CO emissions from a new major stationary source that commenced after September 22, 1982. 401 KAR 51:210 – CAIR NOX annual trading program. This regulation is applicable to Clean Air Interstate Rule (CAIR) NOX units that are subject to 40 CFR 96.104. This regulation establishes requirements for the control of NOX 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 NOX ozone season trading program. This regulation is applicable to the control of CAIR NOX Ozone Season units that are subject to 40 CFR 96.304. This regulation establishes requirements for the control of NOX 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 SO2 trading program. This regulation is applicable to the control of CAIR SO2 units under the CAIR SO2 Trading Program that are subject to 40 CFR 96.204. This regulation establishes requirements for the control of SO2 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


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) 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 NOX and SO2 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 NOX and SO2. 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 NOX; (2) Low NOX burners for control of NOX;

(3) A catalytic oxidizer for the control of CO; and (4) Combust only natural gas and substitute natural gas fuel for control of

PM\PM10\PM2.5.

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.


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED)

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\PM10\PM2.5, NOX, SO2, and CO in concentrations that exceed the following limits:



(1) PM\PM10\PM2.5 – 0.0111 lb/mmBtu based on a three (3) hour rolling average; (2) NOX – 0.0073 lb/mmBtu based on a twenty-four (24) hour rolling average; (3) SO2 – 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\PM10\PM2.5, NOX, SO2, and CO that exceed the following limits:

(1) PM\PM10\PM2.5 – 21.512 lb/hr based on a twenty-four (24) hour block average; (2) NOX – 14.15 lb/hr based on a thirty (30) day block average; (3) SO2 – 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 NOX 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 (O2) 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 O2

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 SO2 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 SO2/J (0.060 lb SO2/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 H2SO4.


a. Compliance with PM\PM10\PM2.5 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 NOX Emission Limitations a(2), b(2), and c shall be demonstrated by fulfilling the following requirements:



(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 SO2 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 NOX 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.



(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 NOX 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 NOX 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 SO2 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.


(3) Use the test data both to demonstrate compliance with the applicable SO2 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 SO2 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



(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.



(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 NOX 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 NOX monitor and a diluent gas O2 or CO2 monitor, to determine the hourly NOX 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 NOX CEMS shall meet the following requirements:

(1) Each NOX 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 NOX 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 NOX 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 NOX emission rate for the hour;



(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 NOX 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 NOX and diluent monitors, the data acquisition and handling system must calculate and record the hourly NOX 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 O2 concentration exceeds nineteen (19.0) percent O2 (or the hourly average CO2 concentration is less than one (1.0) percent CO2), a diluent cap value of nineteen (19.0) percent O2 or one (1.0) percent CO2 (as applicable) may be used in the emission calculations;

(3) Correction of measured NOX concentrations to fifteen (15) percent O2 is not allowed;

(4) If you have installed and certified a NOX 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 NOX 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



(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 SO2 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) 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).

(iii) 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 NOX emissions during each NOX 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 SO2 emissions

during each SO2 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



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\PM10\PM10, NOX, SO2 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 60th 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 NOX are defined as follows.



(1) An excess emissions is any unit operating period in which the four (4) hour or thirty (30) day rolling average NOX emission rate exceeds the applicable emission limit in Section 60.4320. A four (4) hour rolling average NOX emission rate is the arithmetic average of the average NOX 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 NOX emission rates immediately preceding that unit operating hour. Calculate the rolling average if a valid NOX emission rate is obtained for at least three (3) of the four (4) hours. A thirty (30) day rolling average NOX emission rate is the arithmetic average of all hourly NOX 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 NOX emissions rates for the preceding thirty (30) unit operating days if a valid NOX 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: NOX concentration, CO2 or O2 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 30th 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:



(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).


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) 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-m3 (70,000 Btu/hr-ft3).

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\PM10\PM2.5, SO2, NOX, and CO emissions from a new major stationary source that commenced after September 22, 1982. 401 KAR 51:220 – CAIR NOX ozone season trading program. This regulation is applicable to the control of CAIR NOX Ozone Season units that are subject to 40 CFR 96.304. This regulation establishes requirements for the control of NOX 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, NOX, and SO2 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 NOX and SO2 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:


auxiliary boiler is in operation, the following control technology, equipment and methods required to meet BACT demonstration:



(1) Combust only natural gas fuel for control of PM\PM10\PM2.5 and SO2; (2) Low NOX burners for control of NOX; and

(3) Maximum operation shall be 500 hours based on a twelve (12) month rolling total for control of PM\PM10\PM2.5, NOX, SO2, 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.


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\PM10\PM2.5, NOX, SO2, and CO in concentrations that exceed the following limits based on a three (3) hour rolling average:

(1) PM\PM10\PM2.5 – 0.007 lb/mmBtu; (2) NOX – 0.036 lb/mmBtu;

(3) SO2 – 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\PM10\PM2.5, NOX, SO2, and CO that exceed the following limits:

(1) PM\PM10\PM2.5 – 1.923 lb/hr based on a twenty-four (24) hour block average; (2) NOX –10.037 lb/hr based on a thirty (30) day-block average; (3) SO2 – 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 NOX and SO2 in concentrations that exceed: (1) NOX – 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) SO2 – 87 ng/J (0.20 lb/mmBtu) heat input or eight (8) percent (0.08) of the potential SO2 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.



d. Pursuant to 401 KAR 59:015, the permittee shall not discharge into the atmosphere

any gases from the auxiliary boiler that contains PM, NOX and SO2 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) NOX – 0.20 lb/mmBtu (0.36 gram (g)/million calorie (mmcal) [Section 6(1)(a)];

and (3) SO2 – 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.


a. Compliance with PM\PM10\PM2.5 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 NOX 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 SO2 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.


(1) Testing Requirements a. (2) Specific Recordkeeping Requirements d.



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.


a. Pursuant to 401 KAR 59:005, Section 2 the permittee, the permittee shall

demonstrate compliance with the PM\PM10\PM2.5, SO2 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 NOX 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 NOX 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 NOX 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.



c. Pursuant to 40 CFR 60.44b(j), compliance with the NOX 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.


a. Pursuant to 40 CFR 60.46b(c) the permittee does not have to install a NOX 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

SO2 CEMS if firing only very low sulfur gaseous fuel with a potential SO2 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 NOX emissions during each NOX 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\PM10\PM2.5, NOX, SO2 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 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 NOX performance tests required during the reporting period, the hours of operation during the reporting period, and the hours of operation since the last NOX emission test.

f. Pursuant to 40 CFR 60.49b(v), the permittee may submit electronic quarterly reports

for NOX and SO2 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



applicable emission standards and minimum data requirements of this subpart was achieved during the reporting period. Before submitting reports in the electronic format, the permittee shall coordinate with the Division to obtain their agreement to submit reports in this alternative format.

g. Pursuant to 40 CFR 60.49b(w), the reporting period for the reports is each six (6)

month period. All reports shall be submitted to the Division and shall be postmarked by the 30th day following the end of the reporting period.

7. Specific Control Equipment Operating Conditions: None.


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) Emission unit: MSH (MSH) Methanation Heater Description: The indirect heat exchanger uses nitrogen as a heat transfer medium to preheat the

methanation unit during start-up of the methanation unit. The unit is also used to "burn-in" the unit when a new catalyst is installed in the methanation unit.

Construction Date: Estimated second quarter 2010. Fuel Input: 40 mmBtu/hr (startup). 400 mmBtu/hr (burn-in). Primary Fuel: Natural gas. Control Equipment: None. APPLICABLE REGULATIONS: 401 KAR 51:017 – Prevention of significant deterioration of air quality. This regulation applicable with respect to PM\PM10\PM2.5, NOX, SO2, and CO emissions from a new major stationary source that commenced after September 22, 1982. 401 KAR 51:220 – CAIR NOX ozone season trading program. This regulation is applicable to the control of CAIR NOX Ozone Season units that are subject to 40 CFR 96.304. This regulation establishes requirements for the control of NOX 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 applicable with respect to PM, NOX and SO2 and emissions from a source with a capacity more than 250 mmBtu/hr heat input that commenced after April 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 applicable with respect to NOX, and SO2 emissions from an 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 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).


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) 1. Operating Limitations:


methanation heater is in operation, the following control technology, equipment, and methods required to meet BACT demonstration: (1) Combust only natural gas fuel for control of PM\PM10\PM2.5, NOX, SO2, and CO;

(2) Low NOX burners for control of NOX; and (3) The maximum hours of operation, based on a twelve (12) month rolling total,

for control of PM\PM10\PM2.5, NOX, SO2, and CO is restricted to the following: (i) Start-up operations –1,872 hours; (ii) Catalyst burn-in operations – 288 hours; and

(iii) The maximum annual heat input is 350,000 mmBtu (343 mmscf natural gas based on 1,020 But/scf).

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.


a. Compliance with Operating Limitations a(1) and a(2) shall be demonstrated Specific Recordkeeping Requirements b, and reporting requirements in SECTION F paragraph 9.

b. Compliance with Operating Limitations a(3)(i), a(3)(ii), and b, shall be demonstrated

by meeting the requirements of Specific Recordkeeping Requirements f and reporting requirements in SECTION F paragraph 9.

c. Compliance with Operating Limitations a(3)(iii) shall be demonstrated by meeting the

requirements of Specific Recordkeeping Requirements e.


a. Pursuant to 401 KAR 51:017, based on the BACT, the permittee shall not discharge into the atmosphere any gases from the methanation heater that contain PM\PM10\PM2.5, NOX, SO2, and CO in concentrations that exceed the following limits based on a three (3) hour rolling average:

(1) PM\PM10\PM2.5 – 0.0075 lb/mmBtu; (2) NOX (i) 0.049 lb/mmBtu (startup of methanation unit); (ii) 0.1373 lb/mmBtu (catalyst burn-in); (3) SO2 – 0.0006 lb/mmBtu; and (4) CO – 0.0824 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 methanation heater of the that contain PM\PM10\PM2.5, NOX, SO2, and CO that exceed the following limits:



(1) PM\PM10\PM2.5 based on a twenty-four (24) hour block average; (i) 0.298 lb/hr (startup).

(ii) 2.977 lb/hr (catalyst burn-in). (2) NOX based on a thirty (30) hour block average; (i) 1.96 lb/hr (startup). (ii) 54.85 lb/hr (catalyst burn-in).

(3) SO2 based on a twenty-four (24) hour block average; and (i) 0.024 lb/hr (startup).

(ii) 0.235 lb/hr (catalyst burn-in). (4) CO based on an eight (8) hour block average. (i) 3.29 lb/hr (startup). (ii) 32.908 lb/hr (catalyst burn-in).

c. Pursuant to 40 CFR 60 Subpart Db, the permittee shall not discharge into the atmosphere any gases from the methanation heater that contain NOX, and SO2 in concentrations that exceed the following limits.

(1) NOX. (i) 43 ng/J (0.1 lb/mmBtu) heat input (low heat release rate) [Section

60.44b(a)]. (ii) 43 ng/J (0.2 lb/mmBtu) heat input (high heat release rate) [Section

60.44b(a)]. Compliance demonstration shall be on twenty-four (24) hour average basis for initial performance test and three (3) hour average basis for subsequent performance test. [60.44b(j)]

(2) SO2 – 87 ng/J (0.20 lb/mmBtu) heat input or eight (8) percent (0.08) of the potential SO2 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.

d. Pursuant to 401 KAR 59:015, the permittee shall not discharge into the atmosphere

any gases from the methanation heater that contain PM (as measured by applicable methods), NOX and SO2 in concentrations that exceed the following limits based on a three (3) hour rolling average:

(1) PM – 0.10 lb/mmBtu heat input [Section 4(1)(b)]; (2) NOX – 0.20 lb/mmBtu (0.36 gram (g)/million calorie (mmcal) [Section 6(1)(a)];

and (3) SO2 – 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 per hour 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.


a. Compliance with PM\PM10\PM2.5 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 NOX 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 SO2 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.


(1) Testing Requirements a; and (2) Specific Recordkeeping Requirements d.

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.


a. Pursuant to 401 KAR 59:005, Section 2 the permittee, the permittee shall

demonstrate compliance with the PM\PM10\PM2.5, SO2 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 NOX 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 NOX 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 NOX 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.

c. Pursuant to 40 CFR 60.44b(j), compliance with the NOX 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.


a. Pursuant to 40 CFR 60.46b(c) the permittee does not have to install a NOX 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

SO2 CEMS if firing only very low sulfur gaseous fuel with a potential SO2 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 NOX emissions during each NOX control period as specified in 40 CFR 96.70 to 96.76 and 96.370 to 96.375.


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 methanation heater; 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 the process

equipment; and (3) Maintenance conducted on control devices, instrumentation, and process

equipment.

d. The permittee shall document and maintain the following records on-site showing emissions of PM\PM10\PM2.5, NOX, SO2 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 based on 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; and

(2) The hours of operation listed according to the heat input capacity the unit was operated.


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 affected facility and identification of the

fuel to be combusted in the affected facility; (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 affected facility.

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 NOX performance tests required during the reporting period, the hours of operation during the reporting period, and the hours of operation since the last NOX emission test.

f. Pursuant to 40 CFR 60.49b(v), the permittee may submit electronic quarterly reports

for NOX and SO2 in lieu of submitting the written reports required under Section 60.49b(h), (i), (j), (k), and (l). The format of each quarterly electronic report shall be coordinated with the Division. The electronic reports 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 applicable emission standards and minimum data requirements of this subpart was achieved during the reporting period. Before submitting reports in the electronic format, the permittee shall coordinate with the Division to obtain their agreement to submit reports in this alternative format.

g. Pursuant to 40 CFR 60.49b(w), the reporting period for the reports is each six (6)

month period. All reports shall be submitted to the Division and shall be postmarked by the 30th day following the end of the reporting period.



SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) Emission unit: AGR (AGR) Acid Gas Recovery Unit Vent Description:

The acid gas recovery vent is used to discharge the CO2 removed from the syngas when the CO2 is not transmitted by pipeline for use off-site.

Construction Date: Estimated second quarter 2010. Control Equipment: Catalytic oxidizer (CO and hydrogen sulfide (H2S)). APPLICABLE REGULATIONS: 401 KAR 51:017 – Prevention of significant deterioration of air quality. This regulation is applicable with respect to SO2 and CO emissions from a new major stationary source that commenced after September 22, 1982. 401 KAR 59:105 – New process gas streams. This regulation is applicable with respect to SO2 and H2S emissions that commenced after June 6, 1979. 40 CFR 64 Compliance Assurance Monitoring. This regulation is applicable with respect to CO and H2S. 1. Operating Limitations:

Refer to compliance demonstration methods for Emission Limitations a and b.


a. Pursuant to 401 KAR 51:017, based on the BACT and to ensure the validity of the

NAAQS and increment consumption modeling, the permittee shall not discharge into the atmosphere any gases from the acid gas recovery unit vent that contain SO2 and CO in quantities that exceed the following limits based on a three (3) hour rolling average:

(1) SO2 – 43.2 lb/hr; and (2) CO – 126 lb/hr.

b. Pursuant to 401 KAR 59:105, the permittee shall not discharge into the atmosphere any gases from the acid gas recovery unit that contain SO2 and H2S in concentrations that exceed the following limits based on a three (3) hour average: (1) H2S in concentrations that exceed ten (10) gr/100 dscf (165 ppm by volume) at

zero (0) percent O2 or without reducing the concentration by 85 percent; and (2) SO2 that exceed 28.63 gr/dscf (250 ppm by volume at zero (0) percent O2).

c. For limits on source-wide emissions of VOC, refer to SECTION D paragraph 5.


a. Compliance with SO2 Emission Limitations a(1) and b(2) shall be demonstrated by fulfilling the following requirements:

(1) Testing Requirements c(2); and



(2) Specific Recordkeeping Requirements.

b. The permittee shall install and operate whenever the acid gas recovery unit vent is in operation, the catalytic oxidizer required to meet BACT demonstration for control of CO. Compliance with CO Emission Limitations a(2) shall be demonstrated by fulfilling the following requirements: (1) Testing Requirements a and b (if CEMS is not installed); or d (if a CEMS is

installed); (2) Specific Monitoring Requirements a(1) or a(2) and c; (3) Specific Recordkeeping Requirements; and (4) Specific Control Equipment Operating Conditions.

c. The permittee shall install and operate whenever the acid gas recovery unit vent is in operation, the catalytic oxidizer required for control of H2S. Compliance with H2S Emission Limitations b(1) shall be demonstrated by fulfilling the following requirements: (1) Testing Requirements c(1) and b(if CEMS is not installed); or d (if a CEMS is

installed); (2) Specific Monitoring Requirements b(1) or b(2) and c;

(3) Specific Recordkeeping Requirements (for the purpose of calculating of excess emissions for H2S, if a H2S CEMS is not installed, a control efficiency of zero (0) percent shall be assumed for all periods when the catalytic oxidizer is receiving process gases and does not meet the operating limits specified in Specific Control Equipment Operating Conditions of this section); ; and

(4) Specific Control Equipment Operating Conditions.

d. For Compliance with Emission Limitations c see SECTION D paragraph 5.

e. For the purpose of calculating of excess emissions, a control efficiency of zero (0) percent shall be assumed for all periods when the catalytic oxidizer does not meet the operating limits specified in Specific Control Equipment Operating Conditions.


a. Pursuant to 401 KAR 59:005, Section 2 the permittee, the permittee shall demonstrate compliance with the 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. If the permittee does not install a H2S CEMS, during the performance tests the

permittee shall establish the H2S destruction efficiency and operating limits for the catalytic oxidizer as follows: (1) The catalytic oxidizer shall be operated within a temperature range of 450 and

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; and

(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.

c. Pursuant to 401 KAR 59:105, Section 6, except as provided in 401 KAR 50:045,

performance tests used to demonstrate compliance with SO2 and H2S (if H2S CEMS is installed see paragraph d of this Section) shall be conducted according to the following methods, filed by reference in 401 KAR 50:015. If a H2S CEMS is not installed, the permittee shall perform subsequent H2S performance test every 2½ years (no more than thirty-two (32) calendar months following the last performance test.)

(1) Method 11 for H2S, or an alternative method approved by the Division. The sample shall be drawn from a point near the centroid of the gas line. The

minimum sampling time shall be ten (10) minutes and the minimum sample volume shall be 0.01 dscm (0.35 dscf) for each sample. The arithmetic average of two (2) samples shall constitute one (1) run. Samples shall be taken at approximately one (1) hour intervals.

(2) Method 6 for SO2 or an alternative method approved by the Division. Method 1 shall be used for velocity traverses and Method 2 for determining

velocity and volumetric flow rate. The sampling site for determining SO2 concentration by Method 6 shall be the same as for determining volumetric flow rate by Method 2. The sampling point in the duct for determining SO2 concentration by Method 6 shall be at the centroid of the cross section or at a point no closer to the walls than one (1) meter (thirty-nine (39) inches) if the cross-sectional area is five (5) square meters or more and the centroid is more than one (1) meter from the wall. The sample shall be extracted at a rate proportional to the gas velocity at the sampling point. The minimum sampling time shall be ten (10) minutes and the minimum sampling volume shall be 0.01 dscm (0.35 dscf) for each sample. The arithmetic average of two (2) samples shall constitute one (1) run. Three (3) runs will constitute a compliance test. Samples shall be taken at approximately one (1) hour intervals.

d. Pursuant to 401 KAR 52:020, Section 26, for the CO CEMS and, if the permittee

installs a H2S CEMS, the initial 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





(3) Use the test data both to demonstrate compliance with the applicable 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 emission rates for the RATA runs, expressed in units of lb/hr or lb/mmBtu does not exceed the emission limit.


a. 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 the methods in 40 CFR 60.13.

b. Pursuant to 40 CFR 64, to monitor compliance with the H2S emission limit, the

permittee shall do one of the methods below: (1) The permittee shall install a H2S CEMS that shall be calibrated, operated,

tested, and monitored in accordance with 40 CFR 60.13 or 40 CFR 75; or (2) A performance test shall be conducted every 2½ years (no more than thirty-two

(32) calendar months following the last performance test.)

c. Pursuant to 40 CFR 64.6(c), if the permittee does not install H2S CEMS, to demonstrate compliance the emission limits 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 b(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 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 b(2).

(ii) Maintain the three (3) hour average temperature difference across the catalyst bed at or above the temperature limit established according to Testing Requirements b(3).

(iii) Refer to SECTION F for additional requirements. 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 acid recovery unit; any malfunction of the air pollution control equipment; or any periods during which a continuous emission monitoring system or monitoring device is inoperative.



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;


(3) Maintenance conducted on control devices, instrumentation, and process equipment.


monthly basis and a twelve (12) month rolling total: (1) Emissions of SO2 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) Hours that the exhaust gases are vented to the atmosphere; and (3) Hours that the exhaust gases are injected into the pipeline for use off-site.

d. 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 to demonstrate continuous compliance with each operating limit.


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 during the most recent performance test according to Testing Requirements b(2); and

(2) Each occurrence where the three (3) hour average temperature difference across the catalyst bed was below the temperature limit established during the most recent performance test according to Testing Requirements b(3).


For compliance with Emission Limitations, and during operation of the acid gas recovery unit vent, the permittee shall meet the following operating limits for the catalytic oxidizer: (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 b(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 b(3).


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) Emission Unit TO (TO) Sulfur Recovery Unit Description:

The emission unit utilizes a Claus process and to recover sulfur from the following: coal-derived syngas; molten sulfur storage pit and loading rack; and the vent from wastewater treatment system.

Construction Date: Estimated second quarter 2010.

Fuel Input: 26.0 mmBtu/hr (thermal oxidizer) during normal operations and 60.0 mmBtu/hr during startup.

Primary Fuel: Natural gas. Secondary Fuel: None.

Control Equipment: Thermal oxidizer (CO, H2S, H2SO4 and VOC). Caustic scrubber (SO2 and H2SO4).

APPLICABLE REGULATONS: 401 KAR 51:017 – Prevention of significant deterioration of air quality. This regulation is applicable with respect to SO2 and CO emissions from a new major stationary source that commenced after September 22, 1982. 401 KAR 59:105 – New Process Gas Streams. This regulation is applicable with respect to H2S and SO2 emissions from facilities that commenced after June 6, 1979. It is not applicable with respect to CO emissions. 1. Operating Limitations:


sulfur recovery unit is in operation, the following control technology, equipment and methods required to meet BACT demonstration:

(1) Thermal oxidizer for control of CO; and (2) Caustic scrubber for control of SO2.

b. For compliance with the H2S Emission Limitations c(1), the permittee shall install and operate whenever the sulfur recovery unit is in operation, the thermal oxidizer for control of H2S. The following processes shall be vented to the thermal oxidizer:

(1) Degassing of the molten sulfur and sulfur storage facility for control of H2S; (2) The loading rack of the molten sulfur tanker truck and railcar unit, shall include

a vapor recovery system to return the displaced vapors for control of H2S; and (3) The waste water treatment system for control of miscellaneous VOC.

c. Pursuant to 401 KAR 51:017, sulfur recovery unit shall be operated a maximum of 104 hours during startup of the gasification process.




a. Refer to reporting requirements in SECTION F, paragraph 9 and the control equipment operating conditions in Specific Control Equipment Operating Conditions a and b for compliance with Operation Limitations a and b.

b. Compliance with Operating Limitations c shall be demonstrated by meeting the

conditions of Specific Recordkeeping Requirements d(2).


a. Pursuant to 401 KAR 51:017, based on the BACT the permittee shall not discharge into the atmosphere any gases during normal operations that contain PM\PM10\PM2.5, NOX, SO2, and CO in concentrations that exceed the following limits based on a three (3) hour rolling average:

(1) PM\PM10\PM2.5 – 0.60 lb/hr; (2) NOX – 6.80 lb/hr; (3) SO2 – 3.30 lb/hr; and

(4) CO – 7.0 lb/hr.

b. Pursuant to 401 KAR 51:017, based on the BACT the permittee shall not discharge into the atmosphere any gases during startup operations (where startup operations are defined as the first three (3) hours after coal slurry is fed to gasifiers) that contain PM\PM10\PM2.5, NOX, SO2, and CO in concentrations that exceed the following limits based on a three (3) hour rolling average:

(1) PM\PM10\PM2.5 – 2.40 lb/hr; (2) NOX – 32.0 lb/hr; (3) SO2 – 30.95 lb/hr; and

(4) CO – 45.0 lb/hr.

c. Pursuant to 401 KAR 59:105, the permittee shall not discharge into the atmosphere any gases from the sulfur recovery unit that contain SO2 and H2S in concentrations that exceed the following limits based on a three (3) hour average: (1) H2S in concentrations that exceed ten (10) gr/100 dscf (165 ppm by volume) at

zero (0) percent O2 or without reducing the concentration by 85 percent; and (2) SO2 that exceed 28.63 gr/dscf (250 ppm by volume at zero (0) percent O2).

d. Refer to SECTION D paragraph 5, 6, and 7 for source-wide emission limits of VOC, H2SO4 and H2S.



demonstrated by fulfilling the following obligations: (1) Testing Requirements a; (2) Specific Monitoring Requirements c; and (3) Specific Recordkeeping Requirements d.



b. Compliance with NOX Emission Limitations a(2) and b(2) shall be demonstrated by fulfilling the following obligations:

(1) Testing Requirements a; and (2) Specific Recordkeeping Requirements a, b, c and d.

c. Compliance with SO2 Emission Limitations a(3), b(3) and c(2) shall be demonstrated by fulfilling the following obligations:

(1) Testing Requirements d; (2) Specific Monitoring Requirements a; and (3) Specific Recordkeeping Requirements d.

d. Compliance with CO Emission Limitations a(4) and b(4) shall be demonstrated by fulfilling the following obligations:

(1) Testing Requirements a; (2) Specific Monitoring Requirements b; and (3) Specific Recordkeeping Requirements d.

e. Compliance with H2S Emission Limitations c(1) shall be demonstrated by fulfilling the following obligations:

(1) Operating Limitations b; (2) Testing Requirements b, c, and e; and (3) Specific Monitoring Requirements b.

f. For compliance with Emission Limitations d see SECTION D paragraph 5, 6, and 7.

g. For the purpose of calculating excess emissions for CO and H2S, a control efficiency of zero (0) percent shall be assumed for all periods the thermal oxidizer oxidizer is receiving process gases and does not meet the operating limits specified in Specific Control Equipment Operating Conditions a of this section);


a. Pursuant to 401 KAR 59:005, Section 2, the permittee shall demonstrate compliance with the PM\PM10\PM2.5,NOX, CO, VOC and H2SO4 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 401 KAR 59:105, Section 6, except as provided in 401 KAR 50:045, the

performance tests used to demonstrate compliance with the H2S emission standard shall be conducted according to the following methods, filed by reference in 401 KAR 50:015:

(1) The sample shall be drawn from a point near the centroid of the gas line; (2) The minimum sampling time shall be ten (10) minutes and the minimum sample

volume shall be 0.01 dscm (0.35 dscf) for each sample; (3) The arithmetic average of two (2) samples shall constitute one (1) run; and (4) Samples shall be taken at approximately one (1) hour intervals.



c. The performance tests used to demonstrate compliance with SO2 shall be conducted

according to the following methods. (1) Perform a minimum of nine (9) RATA reference method runs, with a minimum



(3) Use the test data both to demonstrate compliance with the applicable 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 emission rates for the RATA runs, expressed in units of lb/hr or lb/mmBtu does not exceed the emission limit.

d. During the performance tests the permittee shall establish the CO and H2S

destruction efficiency and operating limits for the catalytic oxidizer as follows: (1) The catalytic oxidizer shall be operated within a temperature range of 1,523

and 1,683 degrees Celsius; and (2) During the performance test, monitor and record the temperature of the

combustion chamber of the thermal oxidizer at least once every fifteen (15) minutes during each of the three (3) test runs.


a. Pursuant to 401 KAR 52:020, Section 26, the permittee shall install a SO2 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 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.

b. Pursuant to 401 KAR 52:020, Section 26, the permittee must install, calibrate,

maintain, and operate temperature measurement devices, and monitor the temperature of the thermal oxidizer combustion chamber according to the following: (1) A temperature measurement device shall be installed in the firebox of the

thermal oxidizer or immediately downstream of the firebox before any substantial heat exchange occurs;

(2) Each temperature measurement device shall be installed, calibrated, and maintained according to accepted practice and the manufacturer's specifications. The device shall have an accuracy of the greater of + five (5) percent of the temperature being measured expressed in degrees Celsius or + two and a half (2.5) degrees Celsius;

(3) Compliance shall be demonstrated by monitoring and recording the combustion temperature a minimum of once every fifteen (15) minutes and reducing the



data to three (3) hour block averages. The measurement device must be equipped with a recording device so that a permanent record is produced; and

(4) Refer to SECTION E paragraph 2 and SECTION F for additional requirements.

c. Pursuant to 401 KAR 52:020, Section 26, a minimum of once per day when the sulfur recovery unit is in operation, and during any startup, shutdown, and malfunction events, the permittee shall observe the visual emissions from thermal oxidizer stack, as follows: (1) An employee who has worked at the plant at least one (1) month and has been

trained in the appearance and characteristics of normal visible emissions for the specified processes shall perform the observation;

(2) The observation shall be taken during the part of the operation that would normally be expected to cause the greatest emissions;

(3) The results of the observation shall be noted as normal or abnormal; and (4) If abnormal emissions are observed, the permittee shall determine the opacity

of emissions using Method 9 in 40 CFR 60, Appendix A.


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 sulfur recovery unit; any malfunction of the air pollution control equipment; or any periods during which a continuous emission monitoring system or monitoring device is inoperative.

b. Pursuant to 401 KAR 52:020, Section 26, the permittee shall maintain

manufacturer's maintenance and operating instructions, corrective action program, and conduct root cause analysis as follows. (1) The permittee shall develop, implement, and maintain a written operation plan

that describes, in detail, procedures for the operation and maintenance of the gasification process, acid gas recovery unit, sulfur recovery unit, and pollution control devices, during normal operation, and during startup, shutdown and malfunction events.

(2) The operation plan shall include root cause analysis methods for determining the cause of emergency shutdown and malfunction events, and a corrective action program to correct malfunctions as soon as feasible and prevent future occurrences. The operation plan shall be submitted no later than 180 days after startup of the facility.

(3) The permittee shall conduct a root cause analysis of any emission limit exceedance or failed opacity test. In addition, a root cause analysis shall be conducted for any emergency shutdown or malfunction events in which in excess of 227 kilograms per day (kg/day) (500 lb/day) of SO2 were discharged.

(4) The first root cause analysis must be conducted no later than the first discharge that occurs twelve (12) calendar months after initial startup. For any root cause analysis performed, the permittee shall record the following:

(i) Identification of the affected facility; (ii) Date and duration of the discharge; (iii) Results of the root cause analysis; (iv) Action taken as a result of the root cause analysis; and



(v) Confirmation that established operating procedures were followed, and if procedures were not followed an explanation as to why the procedures were not followed.

c. Pursuant to 401 KAR 52:020, Section 26, the permittee shall maintain on site the

following information: (1) Verification of vendor emission rates (in lb/hr) for PM\PM10\PM2.5, NOX, SO2,

CO and H2S and control efficiencies for the thermal oxidizer and caustic scrubber during normal operation and startup events;

(2) Manufacturer's maintenance and operating instructions for the pollution control devices and process equipment;

(3) Maintenance conducted on control devices, instrumentation, and process equipment; and

(4) All performance test and monitoring results.

d. The permittee shall maintain the following records on site with totals calculated on a monthly basis and a twelve (12) month rolling total: (1) Emission of PM\PM10\PM2.5, NOX, SO2, and CO with data from monitoring

devices or by calculations using emission factors from performance tests, fuel usage, and process rates or other applicable data along with supporting calculations;

(2) Total hours of normal operation, and duration of startup, shutdown and malfunction events;

(3) Fuel usage and fuel specifications from fuel supplier; (4) The amount of sulfur recovered in the sulfur recovery unit;

(5) The average combustion chamber temperature (electronically or by strip chart during the most recent performance test, and all relevant supporting data); and

(6) All periods of malfunction, including operation during which the combustion chamber temperature of the thermal oxidizer is more than fifty (50) degrees Fahrenheit below the temperature established during the most recent performance test.


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 each occurrence where the three (3) hour average temperature of the combustion chamber was more than twenty-eight (28) degrees Celsius below the average combustion chamber temperature established during the most recent performance test according to Testing Requirements e(2).


a. Pursuant to 401 KAR 52:020, Section 26, the thermal oxidizer shall not be operated with a combustion chamber temperature more than twenty-eight (28) degrees Celsius lower than the average combustion chamber temperature established during the most recent performance test, based on a three (3) hour average.



b. Pursuant to 401 KAR 52:020, Section 26, the following process parameters of the caustic scrubber shall be monitored and shall be operated within the range specified in the manufacturer's operating instructions, based on a daily average:

(1) Scrubber inlet or recirculation liquid flow rate; (2) The pH range of the recirculation liquid flow rate; and

(3) O2 flow rate.


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) Emission Unit: FLR (FLARE) Flare Description: Construction Date: Estimated second quarter 2010. Fuel Input: 0.4998 mmBtu/hr natural gas for pilot flame. 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\PM10\PM2.5, SO2, NOX, and CO emissions from a new major stationary source that commenced after September 22, 1982. 401 KAR 63:015 – Flares. This regulation is applicable with respect to opacity limits for flares operated after April 9, 1972. 40 CFR 64 – Compliance Assurance Monitoring. This regulation is applicable with respect to CO. 1. Operating Limitations:

a. Pursuant to 401 KAR 51:017, the permittee shall use, whenever the flare is in standby operation (pilot operation), natural gas fuel to meet BACT demonstration.

b. Pursuant to 401 KAR 52:020 Section 26, the flare shall be operated a maximum of

156 hours during startup of the gasifiers while methanol is combusted as a fuel for preheat operations.

c. The following conditions must be met during shutdown events.

(1) The gasifier, or gasifiers, shall not be restarted for a minimum of 24 hours. (2) The process gases that are vented to the flare must be vented at a constant

rate over a minimum of an eight (8) hour period, to ensure that the vented pollutants do not exceed the rate that would have occurred from the processes during normal operations.

(3) The maximum number of shutdown events shall not exceed 52 events (the same number of startup events permitted).

Compliance Demonstration Method:

a. Compliance with Operating Limitations a shall be demonstrated by maintaining

records showing the fuel quality characteristics in a current, valid purchase contract, tariff sheet or transportation contract for the fuel and meeting the obligations of Specific Recordkeeping Requirements d and e.

b. Compliance with Operating Limitations b shall be demonstrated by meeting the

conditions of Specific Recordkeeping Requirements a.


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) 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 flare during standby operation (pilot combustion emissions) that contain PM\PM10\PM2.5, NOX, SO2, and CO in concentrations that exceed the following limits based on a three (3) hour rolling average:

(1) PM\PM10\PM2.5 – 0.0302 lb/mmBtu; (2) NOX – 0.3982 lb/mmBtu; and (3) SO2 – 0.0024 lb/mmBtu. (4) CO – 0.3345 lb/mmBtu.

b. Pursuant to 401 KAR 51:017, based on the BACT, the permittee shall not discharge into the atmosphere during startup operations (while the gasifies are preheated using methanol as a fuel), including emissions from the flare pilots, any gases that contain PM\PM10\PM2.5, NOX, SO2, and CO in concentrations that exceed the following limits based on a three (3) hour rolling average:

(1) PM\PM10\PM2.5 – 0.24 lb/hr; (2) NOX – 51.00 lb/hr; (3) SO2 – 1.00 lb/hr; and (4) CO – 351.96 lb/hr.

c. Pursuant to 401 KAR 63:015, visible emissions from the flare shall not exceed 20

percent for more than three (3) minutes in any one (1) day. d. Refer to SECTION D paragraph 5 and 6 for source-wide emission limits of VOC and

H2SO4.


a. For compliance with Emission Limitation a and b, the permittee shall meet the following: (1) The choice of adhering to either the heat content specifications pursuant to 40

CFR 60.18(c)(3)(ii) and the maximum tip velocity specifications in 40 CFR 60.18(c)(4), or adhering to the requirements in 40 CFR 60.18(c)(3)(i); and

(2) The air-assisted flare shall be designed and operated with an exit velocity less than the velocity Vmax, as determined by the method specified in 40 CFR 60.18(f)(6); and shall also meet the obligations of Specific Monitoring Requirements c and Specific Recordkeeping Requirements a, c, d and e.

b. For compliance with Emission Limitation c, the permittee must do the following:

(1) Monitor the flare to ensure that it is operated and maintained in conformance with their designs;

(2) Operate the flare with a flame present at all times when process gas may be vented to it; and

(3) Operate a flare designed for no visible emissions as determined by Method 22, except for periods not to exceed a total of five (5) minutes during any two (2) consecutive hours.



c. For compliance with Emission Limitations d, see SECTION D paragraph 5 and 6.

3. Testing Requirements: None. 4. Specific Monitoring Requirements:

a. Pursuant to 40 CFR 64.3 and 64.7, a minimum of once per week when the flare is in standby operation, and during any startup, shutdown and malfunction events, the permittee shall observe the visible emissions from flare, as follows: (1) A employee who has worked at the plant at least one (1) month and has been

trained in the appearance and characteristics of normal visible emissions for the specified processes shall perform the observation;

(2) The observation shall be taken during the part of the operation that would normally be expected to cause the greatest emissions;

(3) The results of the observation shall be noted as normal or abnormal; and (4) If visible emissions are observed, then Method 22 shall be used to determine if

the flare is in compliance with the visible emission limitations.

b. Pursuant to 40 CFR 64.3 and 64.7, the permittee shall install and maintain a thermocouple or other equivalent device to continuously monitor the presence of a pilot flame in the flare. For the purpose of this condition, continuous shall mean no less than once per minute.

c. Pursuant to 40 CFR 64.3 and 64.7, the permittee shall install, operate, and maintain

a monitoring system for each vent connected to the flare to measure and record the date and time of a flaring event and the volume of waste gas vented to the flare. In shutdown situations, the system shall be capable to control the rate at which the process gases are vented to the flare.


a. The permittee shall maintain the records of the occurrence and duration of any startup, shutdown or malfunction in the operation of any process controlled by the flare; any malfunction of the flare; or any periods during which a monitoring device is inoperative.

b. Pursuant to 401 KAR 52:020, Section 26, the permittee shall maintain

manufacturer's maintenance and operating instructions, corrective action program, and conduct root cause analysis as follows. (1) The permittee shall develop, implement, and maintain a written operation plan

that describes, in detail, procedures for the operation and maintenance of the gasification process, acid gas recovery unit, sulfur recovery unit, and pollution control devices, during normal operation, and during startup or shutdown events. The plan shall include the following features:

(i) A diagram illustrating all connections to the flare; and (ii) Methods for monitoring flow rate to the flare, including a detailed

description of the manufacturer's specifications, including but not limited



to make, model, type, range, precision, accuracy, calibration, maintenance, and quality assurance procedures for flare gas monitoring devices. See Specific Monitoring Requirements c.

(2) The operation plan shall include root cause analysis methods for determining the cause of emergency shutdown events, and a corrective action program to correct malfunctions as soon as feasible and prevent future occurrences. The operation plan shall be submitted no later than 180 days after startup of the facility.

(3) The permittee shall conduct a root cause analysis of any emission limit exceedance or failed opacity test. In addition, a root cause analysis shall be conducted for any emergency shutdown events meeting the following conditions: (i) events in which in excess of 227 kilograms per day (kg/day) (500 lb/day)

of SO2 were discharged. (ii) any process upset or malfunction that causes a discharge to the flare in

excess of 14,160 m3/day (500,000 scfd). (4) The first root cause analysis must be conducted no later than the first

discharge that occurs twelve (12) calendar months after initial startup. For any root cause analysis performed, the permittee shall record the following:

(i) Identification of the affected facility; (ii) Date and duration of the discharge; (iii) Results of the root cause analysis; (iv) Action taken as a result of the root cause analysis; and (v) Confirmation that established operating procedures were followed, and if

procedures were not followed, an explanation as to why the procedures were not followed.

c. Pursuant to 40 CFR 64.9, the permittee shall maintain the following records on site:

(1) All measurements, including monitoring devices, and all calibration checks; (2) Documents containing the design specifications for each flare, including

capacity and vendor verification of the maximum a PM\PM10\PM2.5, NOX, SO2, and CO emissions, in lb/hr, for combustion of natural gas in standby operation and flare emissions during startup events; and

(3) Manufacturer's maintenance and operating instructions for the pollution control devices and process equipment.

d. 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\PM10\PM2.5, NOX, SO2, and CO with data from monitoring

devices or by calculations using emission factors, fuel usage, process rates or other applicable data along with supporting calculations;

(2) Hours of normal operation, and startup, shutdown and malfunction; (3) Fuel usage for the pilots and fuel specifications from fuel supplier; and (4) Temperature readings of the pilot flame monitoring.

e. The permittee shall keep the following operating records for each time period that flaring occurs:

(1) Date and duration of flare event; (2) Documentation if the event was due to startup, shutdown or malfunction;



(3) Volume of waste gas vented to the flare and plant process where the waste gas originated; and

(4) Confirmation that the flare functioned properly, i.e., a flame was present and no visible emissions were observed except as allowed by 40 CFR 60.18(f)(1).


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 malfunction events and the corrective actions taken, where excursions are defined as the following:

a. Absence of pilot; and b. Presence of visible emissions as determined by Method 22 in excess of five (5)

minutes during any two (2) consecutive hours. 7. Specific Control Equipment Operating Conditions:

Refer to Operating Limitations.


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) Emission unit: ASP (ASP) Aspirator Vent Description:

The aspirator vent is an exhaust vent for the combustion gas from a 21.6 mmBtu/hr, natural gas fired, direct heat exchanger that is used to preheat the gasifiers and maintain the stand-by unit at operation temperature.

Construction Date: Estimated second quarter 2010. Fuel Input: 21.60 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\PM10\PM2.5, SO2, NOX, and CO emissions from a new major stationary source that commenced after September 22, 1982. 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. 1. Operating Limitations:

Pursuant to 401 KAR 51:017 and required to meet BACT demonstration, the permittee shall combust only natural gas fuel.

Compliance Demonstration Method: Compliance with Operating Limitations shall be demonstrated by maintaining records showing the fuel quality characteristics in a current, valid purchase contract, tariff sheet or transportation contract for the fuel and meeting the obligations of Specific Recordkeeping Requirements b.


a. Pursuant to 401 KAR 51:017, based on the BACT, the permittee shall not discharge into the atmosphere any gases from the aspirator vent that contain PM\PM10\PM2.5, NOX, SO2, and CO in concentrations that exceed the following limits:

(1) PM\PM10\PM2.5 – 0.006 lb/mmBtu; (2) NOX – 0.0667 lb/mmBtu; (3) SO2 – 0.0051 lb/mmBtu; and (4) CO – 0.0292 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 that contain PM\PM10\PM2.5, NOX, SO2, and CO that exceed the following limits:

(1) PM\PM10\PM2.5 – 0.13 lb/hr based on a twenty-four (24) hour block average; (2) NOX – 1.44 lb/hr based on a thirty (30) day block average; (3) SO2 – 0.11 lb/hr based on a twenty-four (24) hour block average; and (4) CO – 0.63 lb/hr based on an eight (8) hour block average.

c. Refer to SECTION D paragraph 5 for source-wide emission limits of VOC.


a. Compliance with PM\PM10\PM2.5 Emission Limitations a(1) and b(1) shall be demonstrated by fulfilling the requirements of Operating Limitations.

b. Compliance with NOX Emission Limitations a(2) and b(2) shall be demonstrated by

fulfilling the obligations of Testing Requirements and Specific Recordkeeping Requirements.

c. Compliance with SO2 Emission Limitations a(3) and b(3) shall be demonstrated by

fulfilling the requirements of Operating Limitations. d. Compliance with CO Emission Limitations a(4) and b(4) shall be demonstrated by

fulfilling the obligations of Testing Requirements and Specific Recordkeeping Requirements.

e. For compliance with Emission Limitations c, see SECTION D paragraph 5.


Pursuant to 401 KAR 59:005, Section 2 the permittee, the permittee shall demonstrate compliance with the NOX 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 2½ years (no more than thirty-two (32) calendar months following the previous performance test).

4. Specific Monitoring Requirements: None.


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) 5. Specific Recordkeeping Requirements:

a. Pursuant to 401 KAR 52:020, Section 26, the permittee shall maintain the following records on site:

(1) Performance test results; (2) Manufacturer's maintenance and operating instructions for the process

equipment; and (3) Maintenance conducted on instrumentation and process equipment.

b. The permittee shall maintain the following records on site with totals calculated on a monthly basis and a twelve (12) rolling total: (1) Emissions of PM\PM10\PM2.5, NOX, SO2, 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 fuel supplier; and (3) Hours of operation listed by each individual gasifier. 6. Specific Reporting Requirements:

None.



SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) Emission unit: EG (EG) Emergency Generator Description:

The emergency generator is an internal combustion, 2,826 horsepower (hp), four (4)-cycle, lean burn engine powered generator.

Construction Date: Estimated second quarter 2010. Fuel Input: 19.5 mmBtu/hr. Primary Fuel: Natural gas. Secondary Fuel: None. Control Equipment: None. Emissions Unit: FP Fire Pump Description:

The fire pump is an internal combustion, 390 horsepower, industrial engine powered fire pump.

Construction Date: Estimated second quarter 2010. Fuel Input: 2.4 mmBtu/hr. Primary Fuel: Natural gas. Secondary Fuel: None. Control Equipment: None. APPLICABLE REGULATIONS: 401 KAR 51:017 Prevention of significant deterioration of air quality. This regulation is applicable with respect to PM\PM10\PM2.5, NOX, SO2, and CO emissions from a new major stationary source that commenced after September 22, 1982. 401 KAR 60:005 – 40 C.F.R. Part 60 standards of performance for new stationary sources incorporating by reference 40 CFR 60, Subpart JJJJ Standards of Performance for Stationary Spark Ignition Internal Combustion Engines. This regulation is applicable with respect to NOX, CO, and VOC emissions from emergency engines that commenced construction after June 12, 2006 and were manufactured on or after January 1, 2009. 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. 1. Operating Limitations:

a. Pursuant to 401 KAR 51:017, the permittee shall: (1) Combust only natural gas fuel for control of PM\PM10\PM2.5, NOX, SO2, and CO;

and (2) Maximum operation shall be 36 hours for each unit, based on a twelve (12)

month rolling total for the control of PM\PM10\PM2.5, NOX, SO2, and CO.



b. Pursuant to 40 CFR 60.4243(b)(2)(i) and (ii), for the emergency generator (emission unit EG) and fire pump engine (emission unit FP), the permittee must keep a maintenance plan and records of conducted maintenance and must, to the extent practicable, maintain and operate the engine in a manner consistent with good air pollution control practice for minimizing emissions.

c. Pursuant to 40 CFR 60.4237(a), starting on July 1, 2010, if the emergency generator

(emission unit EG) was built after July 1, 2010 and does not meet the standards applicable to non-emergency engines, the permittee must install a non-resettable hour meter.

d. Pursuant to 40 CFR 60.4237(b), starting January 1, 2011, if the fire pump (emission

unit FP) was built after January 1, 2011 and does not meet the standards applicable to non-emergency engines, the permittee must install a non-resettable hour meter.


a. Compliance with Operating Limitations a shall be demonstrated by maintaining

records showing the fuel quality characteristics in a current, valid purchase contract, tariff sheet or transportation contract for the fuel and by fulfilling the obligations of Specific Recordkeeping Requirements d.

b. For compliance with Operating Limitations b, c, and d refer to SECTION F paragraph

9 for compliance reporting requirements.


a. Pursuant to 401 KAR 51:017, based on the BACT, the permittee shall not discharge into the atmosphere any gases from the emergency generator engine (emission unit EG) that contain PM\PM10\PM2.5, NOX, SO2, and CO in concentrations that exceed the following concentrations:

(1) PM\PM10\PM2.5 – 0.0194 lb/mmBtu; (2) NOX – 0.162 lb/mmBtu; (3) SO2 – 0.004 lb/mmBtu; and (4) CO – 0.7122 lb/mmBtu

b. Pursuant to 401 KAR 51:017, based on the BACT, the permittee shall not discharge

into the atmosphere any gases from the fire pump engine (emission unit FP) that contain PM\PM10\PM2.5, NOX, SO2, and CO that exceed the following concentrations:

(1) PM\PM10\PM2.5 – 0.01 lb/mmBtu; (2) NOX – 4.08 lb/mmBtu; (3) SO2 – 0.0006 lb/mmBtu; and (4) CO – 0.317 lb/mmBtu.

c. Pursuant to 40 CFR 60.4233(e), emission limits for the emergency generator engine

(emission unit EG) and fire pump engine (emission unit FP) shall not exceed the following limits:

(1) NOX – 2.0 g/(hp-hr) (160 ppmvd at 15 percent O2);



(2) CO – 4.0 g/hp-hr (540 ppmvd at 15 percent O2); and (3) VOC – 1.0 g/hp-hr (86 ppmvd at 15 percent O2).

d. Pursuant to 40 CFR 60.4234, the permittee must operate and maintain the stationary

spark ignition internal combustion engine to achieve the emission standards required by Section 60.4233 over the entire life of the engine.

e. Refer to SECTION D paragraph 6 for source-wide emission limitations of VOC.



demonstrated by combustion of natural gas.

b. Compliance with NOX Emission Limitations a(2) and b(2), and c(1) shall be demonstrated by fulfilling the following obligations:

(1) Testing Requirements a, b, c, d(1) through (4). (2) Specific Recordkeeping Requirements b, c, d (emission unit EG) and e

(emission unit FP). (3) Specific Reporting Requirements a and b.

c. Compliance with SO2 Emission Limitations a(3) and b(3) shall be demonstrated by combustion of natural gas.

d. Compliance with CO Emission Limitations a(4) and b(4), and c(2) shall be

demonstrated by fulfilling the following obligations: (1) Testing Requirements a, b, c, d(1) through (3) and d(4).

(2) Specific Recordkeeping Requirements b, c, d (emission unit EG) and e (emission unit FP).

(3) Specific Reporting Requirements a and b.

e. Compliance with VOC Emission Limitations c(3) shall be demonstrated by fulfilling the following obligations:

(1) Testing Requirements a, b, c, d(1) through (3) and d(6) and (7). (2) Specific Recordkeeping Requirements b, c, d (emission unit EG) and e

(emission unit FP). (3) Specific Reporting Requirements a and b.

f. For compliance with Emission Limitations e see SECTION D paragraph 5.


a. Pursuant to 40 CFR 60.4243(b)(2)(i), if the fire pump engine (emission unit FP) is not

certified by the manufacturer to meet applicable emission standards, the permittee, must conduct an initial performance test for NOX, CO, and VOC within one (1) year of engine startup to demonstrate compliance.

b. Pursuant to 40 CFR 60.4243(f), if the fire pump engine (emission unit FP) is not

certified by the manufacturer to meet applicable emission standards, or the certified



engine and control device are not operated and maintained according to the manufacturer's written emission-related instructions, the permittee is required to perform initial performance testing, but subsequent performance testing is not required unless the stationary engine is rebuilt or undergoes major repair or maintenance as described in 40 CFR 94.11(a).

c. Pursuant to 40 CFR 60.4243(b)(2)(ii), if the emergency generator engine (emission

unit EG) is not certified by the manufacturer to meet applicable emission standards, the permittee must conduct an initial performance tests for NOX, CO, and VOC to demonstrate compliance with the applicable emission standards. Subsequent performance tests shall be conducted every 8,760 hours or three (3) years, whichever comes first, thereafter to demonstrate compliance.

d. Pursuant to 40 CFR 60.4244(a), (b), and (c), the permittee shall conduct the

performance test using the following procedures. (1) Each performance test must be conducted within ten (10) percent of 100

percent peak (or the highest achievable) load and according to the requirements in 40 CFR 60.8 and under the specific conditions that are specified by Table 2 to Subpart JJJJ of Part 60 Requirements of Performance Test.

(2) You may not conduct performance tests during periods of startup, shutdown, or malfunction, as specified in 40 CFR 60.8(c). If the engine is non-operational, you do not need to startup the engine solely to conduct a performance test; however, you must conduct the performance test immediately upon startup of the engine.

(3) You must conduct three (3) separate test runs for each performance tests, as specified in 40 CFR 60.8(f). Each test run must be conducted within ten (10) percent of 100 percent peak (or the highest achievable) load and last at least one (1) hour.

(4) To determine compliance with the NOX mass per unit output emission limitation, convert the concentration of NOX in the engine exhaust using the following equation: [Section 60.4244(d)]

1 Equationhr - hp

T x Q x 10 x 1.912 x C ER

-3d=

Where:

ER = Emission rate of NOX in g/hp-hr. Cd = Measured NOX concentration in parts per million volume (ppmv).

1.912 × 10-3 = Conversion constant for ppm NOX to g/standard cubic meter (scm) at 20 degrees Celsius.

Q = Stack gas volumetric flow rate, in dscm/hr. T = Time of test run, in hours. HP-hr = Brake work of the engine, hp-hr.

(5) To determine compliance with the CO mass per unit output emission limitation,

convert the concentration of CO in the engine exhaust using the following equation: [Section 60.4244(e)]



2 Equationhr - hp

T x Q x 10 x 1.164 x C ER

-3d=

Where: ER = Emission rate of CO in g/hp-hr. Cd = Measured CO concentration in ppmv.

1.164 × 10-3 = Conversion constant for ppm CO to g/scm at 20 degrees Celsius.

Q = Stack gas volumetric flow rate, in dscm/hr. T = Time of test run, in hours.

HP-hr = Brake work of the engine, in hp-hr.

(6) When calculating emissions of VOC, emissions of formaldehyde should not be included. To determine compliance with the VOC mass per unit output emission limitation, convert the concentration of VOC in the engine exhaust using the following equation: [Section 60.4244(f)]

3 Equationhr - hp

T x Q x 10 x 1.833 x C ER

-3d=

Where: ER = Emission rate of VOC in g/hp-hr. Cd = VOC concentration measured as propane in ppmv.

1.833 × 10-3 = Conversion constant for ppm VOC measured as propane, to g/scm at 20 degrees Celsius.

Q = Stack gas volumetric flow rate, in dscm/hr. T = Time of test run, in hours. HP-hr = Brake work of the engine, in hp-hr.

(7) Pursuant to 40 CFR 60.4244(g), if the permittee chooses to measure VOC

emissions using either Method 18 of 40 in CFR 60, Appendix A, or Method 320 in 40 CFR 63 Appendix A, then it has the option of correcting the measured VOC emissions to account for the potential differences in measured values between these methods and Method 25A. The results from Method 18 and Method 320 can be corrected for response factor differences using Equations 4 and 5 of Section 60.4244(g). The corrected VOC concentration can then be placed on a propane basis using Equation 6 of Section 60.4244(g).


Pursuant to 40 CFR 60.4243(b)(1), a performance test is not required to demonstrate compliance with the emission limits pursuant to Section 60.4233(e), if the permittee purchases an engine certified by the manufacturer to meet applicable emissions standards, for the same model year, and the permittee demonstrates compliance by operating and maintaining the certified engine according to the manufacturer's emission-related written instructions and maintains records of conducted maintenance.


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) 4. Specific Monitoring Requirements: None. 5. Specific Recordkeeping Requirements:

a. The permittee shall maintain the records of the occurrence and duration of any

startup, shutdown, or malfunction in the operation of the fire pump or emergency generator; or any periods during which a monitoring device is inoperative.

b. 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\PM10\PM2.5, NOX, SO2 and CO with data from monitoring

devices or by calculations using emission factors from performance tests, fuel usage, and process rates or other applicable data along with supporting calculations;

(2) Fuel usage by the emergency generator (emission unit EG) and fire pump (emission unit FP) and fuel specifications from fuel supplier; and

(3) Hours that the emergency generator (emission unit EG) and fire pump (emission unit FP) were operated by the following type of operation:

(i) Emergency; (ii) Non-emergency; and (iii) Maintenance and readiness checks.

c. Pursuant to 40 CFR 60.4245(a), the permittee must keep records of the following information: (1) All notifications submitted to comply with 40 CFR 60 Subpart JJJJ and all

documentation supporting any notification; (2) Maintenance conducted on the engine;

(3) If the engine is a certified engine, documentation from the manufacturer that the engine is certified to meet the emission standards and information as required in 40 CFR parts 90, 1048, 1054, and 1060, as applicable; and

(4) If the engine is not a certified engine or is a certified engine operating in a non-certified manner and subject to Section 60.4243(a)(2), documentation that the engine meets the emission standards.

d. Pursuant to 40 CFR 60.4245(b), if the emergency generator engine (emission unit

EG) is manufactured on or after July 1, 2010 and does not meet the standards applicable to non-emergency engines, starting on July 1, 2010 the permittee must keep records of the hours of operation of the engine that is recorded through the non-resettable hour meter. The permittee must document how many hours are spent for emergency operation, including what classified the operation as emergency and how many hours are spent for non-emergency operation.3

e. Pursuant to 40 CFR 60.4245(b), if the fire pump engine (emission unit FP) is

manufactured on or after January 1, 2011 and does not meet the standards applicable to non-emergency engines, starting on January 1, 2011 the permittee must keep records of the hours of operation of the engine that is recorded through the non-resettable hour meter. The permittee must document how many hours are



spent for emergency operation, including what classified the operation as emergency and how many hours are spent for non-emergency operation.


a. Pursuant to 40 CFR 60.4245(c), if the emergency generator (emission unit EG) has not been certified by an engine manufacturer to meet the emission standards in Section 60.4231, the permittee must submit an initial notification as required in 40 CFR 60.7(a)(1). The notification must include the following applicable information listed:

(1) Name and address of the owner or operator; (2) The address of the affected source;

(3) Engine information including make, model, engine family, serial number, model year, maximum engine power, and engine displacement;

(4) Emission control equipment; and (5) Fuel used.

b. Pursuant to 40 CFR 60.4245(d), the permittee must submit a copy of each performance test as conducted in Section 60.4244 within sixty (60) days after the test has been completed.



SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) Emission Unit: CT1-22 (CT-1 CT-22) Cooling Tower Description: The cooling tower is a forced induction 22 cell cooling tower. Construction Date: Estimated second quarter 2010. Capacity: 25.8 mmgal/hr circulation rate. Control Equipment: Mist eliminator (PM\PM10\PM2.5). APPLICABLE REGULATIONS: 401 KAR 51:017 – Prevention of significant deterioration of air quality. This regulation is applicable with respect to PM\PM10\PM2.5 emissions from a new major stationary source that commenced after September 22, 1982. 401 KAR 63:010 – Fugitive emissions. This regulation is applicable with respect to particulate matter emissions. NON-APPLICABLE REGULATIONS: 40 CFR Part 63 Subpart – Q National Emission Standards for Hazardous Air Pollutants for Industrial Process Cooling Towers. This regulation is not applicable as long as the cooling towers are not operated with chromium-based water treatment chemicals. 1. Operating Limitations:


cooling tower is in use, the following control equipment and methods required to meet BACT demonstration: (1) Drift eliminators with a 0.0005 percent drift control (99.9995 percent efficiency

based on the cooling tower circulation flow rate); and (2) Total dissolved solids concentration in the circulation cooling water shall not

exceed 5,000 ppm.

b. To preclude applicability of 401 CFR 63 Subpart Q, the cooling tower shall not be operated with chromium-based water treatment chemicals, as defined in 40 CFR 63.401. [40 CFR Part 63 Subpart Q]

c. Pursuant to 401 KAR 63:010, Section 3(1), the permittee shall not cause, suffer, or

allow material to be processed, without taking reasonable precautions to prevent particulate matter from becoming airborne.

d. Pursuant to 401 KAR 63:010, Section 3(2), the permittee shall not cause or permit

the discharge of visible fugitive dust emissions beyond the lot line of the property in which the emissions originated.




a. For compliance with Operating Limitations a, refer to Specific Monitoring and Specific Recordkeeping Requirements.

b. For compliance with Operating Limitations b, c and d, refer to Operation Limitations a

and compliance reporting requirements in SECTION F paragraph 9. 2. Emission Limitations:

Pursuant to 401 KAR 51:017, based on the BACT, the permittee shall not discharge into the atmosphere any gases from the cooling towers that contain PM\PM10\PM2.5 that exceed the following concentrations: a. PM\PM10 - 1.39 lb/hr; and b. PM2.5 - 0.005 lb/hr.


Refer to Testing Requirements and Specific Recordkeeping Requirement c.


Pursuant to 401 KAR 52:020, Section 26, the permittee shall conduct an initial performance test using the Cooling Technology Institute Acceptance Test Code (ATC) #140 to verify the drift eliminator's efficiency. The permittee shall demonstrate compliance with the applicable emission standards within sixty (60) days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of such facility. The performance test shall be conducted a minimum of once every five (5) years (no more than sixty-two (62) calendar months following the previous performance test).


Pursuant to 401 KAR 52:020, Section 26, the permittee shall sample and analyze the cooling tower circulation water on a monthly basis for the total dissolved solids (TDS) concentration. Measurements of the TDS concentration in the wastewater discharge associated with the affected unit, as required by a National Pollution Discharge Elimination System Permit, may be used to satisfy this requirement if the effluent has not been diluted or otherwise treated in a manner that would significantly reduce its TDS concentration.


a. The permittee shall maintain the records of the occurrence and duration of any startup, shutdown, or malfunction in the operation of the cooling tower; any malfunction of the air pollution control equipment; or any periods during which a monitoring device is inoperative.



b. Pursuant to 401 KAR 52:020, Section 26, the permittee shall maintain the following records on site: (1) Information from the manufacturer on the design of the drift eliminators

including a verification of the 0.0005 percent drift control (based on the cooling tower circulation flow rate);

(2) All measurements, including monitoring device and performance test results; and all calibration checks;


(4) Copies of the Material Safety Data Sheets for water treatment chemicals that are added to the cooling tower circulation water.


monthly basis and a twelve (12) month rolling total: (1) Emissions of PM\PM10\PM2.5 by calculation using emission factors based on

particle distribution from Table 1 Resultant Solid Particulate Size Distribution from the abstract Calculating Realistic PM10 Emissions from Cooling Towers, average monthly cooling tower water circulation rate, monthly suspended solids test results and other applicable data.

(2) Total volume of make-up water to the cooling tower; and (3) Total cooling tower water circulated.


None.


None.


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) Fugitive Equipment Leaks (FE-SYN, FE-AGR, FE-SRU and FE-MET)

Component Gasification Plant

Acid Gas Recovery Unit

Sulfur Recovery Unit

Methanation Area

Valves 3113 1891 721 407

Connectors 6754 4278 1560 867

Compressors 0 6 1 1

Pumps 1 19 0 0 NOTE: The equipment count listed above reflects an approximate count of the equipment as of the date of issuance of this permit but is not intended to limit the permittee to the exact numbers specified. The permittee may add or remove pipeline equipment without a permit revision as long as the equipment continues to comply with the applicable requirements listed below and the changes do not have a significant impact on emissions or potential to emit. APPLICABLE REGULATIONS: 401 KAR 51:017 – Prevention of significant deterioration of air quality. This regulation is applicable with respect to CO emissions from a new major stationary source that commenced after September 22, 1982. 1. Operating Limitations:

a. Pursuant to 401 KAR 51:017, the permittee shall implement a LDAR program for VOC as an indicator of leaks and route emissions from pressure relief valves to a control device so as to meet BACT demonstration for control of CO.

b. The permittee shall also implement a LDAR program for compliance with the source-

wide VOC limit in Section D, paragraph 5 and H2S limit in Section D, paragraph 7. c. The conditions of piping, valves, connectors, pumps, and compressors in VOC

service shall not apply as follows: (1) Where the VOC has an aggregate partial pressure or vapor pressure of less

than 0.044 pounds per square inch, absolute (psia) at 68°F; or (2) Operating pressure is at least 5 kilopascals (0.725 psi) below ambient

pressure. Equipment excluded from this condition shall be identified in a list or by one of the methods described below to be made available upon request.

(i) Piping and instrumentation diagram (PID); or (ii) A written or electronic database.


a. Refer to Specific Monitoring Requirements and SECTION F paragraph 9 for

compliance with Operation Limitations a, b, and c.

b. Refer to SECTION D, paragraphs 5 and 7, for compliance demonstration methods for Operating Limitation b.




into the atmosphere any gases from the equipment leak components in emission points FE-SYN, FE-AGR, FE-SRU, and FE-MET that contain CO in quantities that exceed 1.39 tpy, based on a 12-month rolling total.

b. Refer to SECTION D, paragraphs 5 and 7 for source-wide emission limits on VOC

and H2S. Compliance Demonstration Methods:

a. Compliance with Emission Limitation a shall be achieved by fulfilling the following

conditions: (1) Specific Monitoring Requirements;

(2) Specific Recordkeeping Requirements; (3) Construction of new and reworked piping, valves, pump systems, and

compressor systems shall conform to applicable American National Standards Institute (ANSI), American Petroleum Institute (API), American Society of Mechanical Engineers (ASME), or equivalent codes. New and reworked piping connections shall be welded or flanged. Screwed connections are permissible only on piping smaller than two-inch diameter; and

(4) New and reworked underground process pipelines shall contain no buried valves such that fugitive emission monitoring is rendered impractical. New and reworked buried connectors shall be welded.

b. For compliance with Emission Limitation b shall be achieved by fulfilling the following

conditions: (1) Operating Limitation b; (2) Specific Monitoring Requirements; and (3) Specific Recordkeeping Requirements.

3. Testing Requirements: None 4. Specific Monitoring Requirements:

a. To the extent that good engineering practice will permit, new and reworked valves and piping connections shall be located to be reasonably accessible for leak-checking during plant operation. Non-accessible valves shall be identified in a list to be made available upon request. If an unsafe-to-monitor component is not considered safe to monitor within a calendar year, then it shall be monitored as soon as possible during safe-to-monitor times. A difficult-to-monitor component for which quarterly monitoring is specified may instead be monitored annually.

b. Gas or hydraulic testing of the new and reworked piping connections at no less than

operating pressure shall be performed prior to returning the components to service or they shall be monitored for leaks using an approved gas analyzer within 15 days of



the components being returned to service. Adjustments shall be made as necessary to obtain leak-free performance. Connectors shall be inspected by visual, audible, and/or olfactory means at least weekly by operating personnel walk-through.

c. Accessible valves shall be monitored by leak-checking for fugitive emissions at least

quarterly using an approved gas analyzer. Sealless/leakless valves (including, but not limited to, welded bonnet bellows and diaphragm valves) and relief valves venting to a control device or equipped with a rupture disc upstream, are not required to be monitored. For valves equipped with rupture discs, a pressure-sensing device shall be installed between the relief valve and rupture disc to monitor disc integrity. All leaking discs shall be replaced at the earliest opportunity but no later than the next process shutdown.

d. A check of the pressure-sensing device to verify disc integrity shall be performed

weekly and recorded in the unit log. e. The gas analyzer shall conform to requirements listed in Method 21 of 40 CFR 60,

Appendix A. The gas analyzer shall be calibrated with methane. In addition, the response factor of the instrument for a specific VOC of interest shall be determined and meet the requirements of Section 8 of Method 21. If mixtures of VOCs are being monitored, the response factor shall be calculated for the average composition of the process fluid. If a response factor less than 10 cannot be achieved using methane, then the instrument may be calibrated with one of the VOC to be measured or any other VOC so long as the instrument has a response factor of less than 10 for each VOC to be measured.

f. Replacements for leaking components shall be re-monitored within 15 days after

being placed back into VOC service. g. All pump and compressor seals shall be monitored with an approved gas analyzer at

least quarterly or be equipped with a shaft sealing system that prevents or detects emissions of VOC from the seal. Seal systems designed and operated to prevent emissions or seals equipped with automatic seal failure detection and alarm system need not be monitored. These seal systems may include (but are not limited to) dual pump seals with barrier fluid at higher pressure than process pressure, seals degassing to vent control systems kept in good working order, or seals equipped with an automatic seal failure detection and alarm system. Submerged pumps or sealless pumps (including, but not limited to, diaphragm, canned, or magnetic-driven pumps) may be used to satisfy the requirements of this condition and need not be monitored.

h. Damaged or leaking valves or connectors found to be emitting VOC in excess of 500

parts per million by volume (ppmv) or found by visual inspection to be leaking (e.g., dripping process fluids) shall be tagged and replaced or repaired. Damaged or leaking pump, compressor, and agitator seals found to be emitting VOC in excess of 2,000 ppmv or found by visual inspection to be leaking (e.g., dripping process fluids) shall be tagged and replaced or repaired. A first attempt to repair the leak must be made within 5 days. Records of the first attempt to repair shall be maintained.



i. Every reasonable effort shall be made to repair a leaking component within 15 days after the leak is found. If the repair of a component would require a unit shutdown that would create more emissions than the repair would eliminate, the repair may be delayed until the next scheduled shutdown. All leaking components which cannot be repaired until a scheduled shutdown shall be identified for such repair by tagging within 15 days of the detection of the leak. A listing of all components that qualify for delay of repair shall be maintained on a delay of repair list. The cumulative daily emissions from all components on the delay of repair list shall be estimated by multiplying the hourly mass emission rate by 24 for each component. When the cumulative daily emission rate of all components on the delay of repair list times the number of days until the next scheduled unit shutdown is equal to or exceeds the total emissions from a unit shutdown, the Division Regional Office shall be notified and may require early unit shutdown or other appropriate action based on the number and severity of tagged leaks awaiting shutdown. This notification shall be made within 15 days of making this determination.

j. In addition to the weekly physical inspection required by Item b of this section, all

connectors in gas\vapor and light liquid service shall be monitored annually with an approved gas analyzer in accordance with items c thru i of this section. Alternative monitoring frequency schedules of 40 CFR Part 63.174(b)(3)(ii) through (v), may be used in lieu of the monitoring frequency required by this permit condition

k. Each open-ended valve or line shall be equipped with an appropriately sized cap,

blind flange, plug, or a second valve to seal the line. Except during sampling, both valves shall be closed. If the removal of a component for repair or replacement results in an open-ended line or valve, it is exempt from the requirement to install a cap, blind flange, plug, or second valve for 24 hours. If the repair or replacement is not completed within 24 hours, the line or valve must have a cap, blind flange, plug, or second valve installed.


a. Records of repairs shall include date of repairs, repair results, justification for delay

of repairs, and corrective actions taken for all components. Records of instrument monitoring shall indicate dates and times, test methods, and instrument readings. Records of physical inspections shall be noted in the operator’s log or equivalent.

b. Pursuant to 401 KAR 52:020 Section 26, the permittee shall maintain records on site

of monthly and twelve month rolling total emissions of CO from equipment leak components. The permittee shall maintain records of emission factors or other applicable data along with supporting calculations used to determine emissions.

6. Specific Reporting Requirements: The results of required fugitive instrument monitoring and required records shall be made

available to the Kentucky Division for Air Quality and its designated representative upon request.


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) 7. Specific Control Equipment Operating Conditions:

None


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) Emission Unit DC-1 (DC-1) Coal Grinding and Slurry Prep Building Description:

Equipment: Two (2) 100 ton capacity surge bins, six (6) 1500 ton capacity coal silos, three (3) rod mills, and associated conveyors and equipment.

Capacity: 800 tons per hour (tph). Construction Date: Expected second quarter 2010. Control Equipment: Baghouse (PM\PM10\PM2.5). Emission Unit DC-2 (DC-2) Transfer Tower 1 Description:

Equipment: Conveyor 01-CNV-0001 (42 inch width by 5,700 feet long – 700 tph). Conveyor 01-CNV-0002 (42 inch width by 3,520feet long – 700 tph). Conveyor 01-CNV-0003 (42 inch with by 1,750 feet long – 800 tph).

Capacity: 800 tph. Construction Date: Expected second quarter 2010.

Control Equipment: Baghouse (PM\PM10\PM2.5). Emission Unit DC-3 (DC-3) Underground Feed Hoppers Description:

Equipment: Two (2) feed hoppers. Conveyor 01-CNV-0005 (42 inch by 650 feet long).

Capacity: 800 tph. Construction Date: Expected second quarter 2010. Control Equipment: Baghouse (PM\PM10\PM2.5). Emission Unit DC-4 (DC-4) Transfer Tower 2 Description:

Equipment: Two (2) crusher bins, two (2) self cleaning screens, two (2) ring granulator crushers, and associated conveyors and equipment.

Conveyor 01-CNV-0007 (42 inch by 1,000 feet long). Conveyor 01-CNV-0008 (42 inch by 1,000 feet long). Capacity: 800 tph. Construction Date: Expected second quarter 2010. Control Equipment: Baghouse (PM\PM10\PM2.5). Emission Unit CH-1 (CH-1) Barge Unloading Description: Equipment: Equilibrated crane barge unloader. Capacity: 700 tph. Construction Date: Expected second quarter 2010. Control Equipment: Fogging (PM\PM10\PM2.5).


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) Emission Unit CH-2 (CH-2) Barge Unloading Hopper Description: Equipment: Hopper. Capacity: 700 tph. Construction Date: Expected second quarter 2010. Control Equipment: Fogging (PM\PM10\PM2.5). Emission Unit CH-3 (CH-3) Vibratory Feeder Description: Equipment: Vibratory Feeder.

Conveyor 01-CNV-0011 (42 inch by 225 feet long). Capacity: 700 tph. Construction Date: Expected second quarter 2010. Control Equipment: Fogging (PM\PM10\PM2.5). Emission Unit CH-4 (CH-24) Barge Unloading Transfer Tower Description:

Equipment: Conveyor 01-CNV-0002 (42 inch by 3,250 feet long). Capacity: 700 tph. Construction Date: Expected second quarter 2010. Control Equipment: Fogging (PM\PM10\PM2.5). Emission Unit CH-5 (CH-5) Mine Conveyor Transfer Description: Equipment: Conveyor 01-CNV-0001 (42 inch by 5,700 feet long). Capacity: 700 tph. Construction Date: Expected second quarter 2010. Control Equipment: Fogging (PM\PM10\PM2.5). Emission Unit CH-6 (CH-10) Coal Pile Stacker Description: Equipment: Conveyor 01-CNV-0004 (42 inch by 600 feet long). Capacity: 800 tph. Construction Date: Expected second quarter 2010. Control Equipment: Stacker tube and Fogging (PM\PM10\PM2.5). APPLICABLE REGULATIONS: 401 KAR 51:017 – Prevention of significant deterioration of air quality. The regulation is applicable with respect to PM\PM10\PM2.5, from a new major stationary source that commenced after September 22, 1982.


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) 401 KAR 60:005 – 40 C.F.R. Part 60 standards of performance for new stationary sources. 40 CFR Part 60, Subpart Y, Standards of performance for coal preparation plants. This regulation is applicable to facilities which process more than 161 Mg (200 tons) that commenced after May 27, 2009. 401 KAR 59:010 – New Process Operations. This regulation is applicable to emissions units not covered by another PM emission standard for new stationary sources that commenced on or after July 2, 1975. 1. Operating Limitations:

Pursuant to 401 KAR 51:017, the permittee shall install and operate, whenever the coal preparation emission units are in operation, the following control devices, equipment and methods required to meet BACT demonstration:

a. The coal grinding and slurry prep building (emission unit DC-1), transfer tower 1

(emission unit DC-2), underground feed hoppers (emission unit DC-3), and transfer tower 2 (emission unit DC-4) shall use building enclosures as a control device. The building openings where fugitive emissions could escape, including but not limited to windows, doors, and conveyor entry points, shall be minimized to the extent practical.

b. Emissions from the enclosures for emission units DC-1, DC-2, DC-3, and DC-4 shall

be controlled by baghouses to ensure that emissions discharged into the atmosphere from the emission unit do not contain PM\PM10\PM2.5 in excess of following:

(1) PM\PM10 0.011 g/dscm (0.005 grain/dscf); and (2) PM2.5 0.0009 grain/dscf. c. The barge unloading (emission unit CH-1), barge unloading hopper (emission unit

CH-2), vibrator feeder (emission unit CH-3), barge unloading transfer tower (emission unit CH-4), and mine conveyor transfer (emission unit CH-5), shall be controlled by fogging.

d. The coal pile stacker (emission unit CH-6), shall be controlled by fogging, reduced

drop heights, and the use of a stacking tube.


For compliance with Operating Limitations, refer to compliance reporting requirements in SECTION F paragraph 9.



into the atmosphere any gases during coal transfer and handling operations from emission units DC-1, DC-2, DC-3 and DC-4 that contain PM\PM10\PM2.5 in concentrations that exceed the following based on a three (3) hour rolling average:

(1) PM\PM10 0.011 g/dscm (0.005 grain/dscf); and (2) PM2.5 0.0009 grain/dscf.



b. Pursuant to 40 CFR 60.254(b), on and after the date on which the performance test

is conducted or required to be completed under 40 CFR 60.8, whichever date comes first, the permittee must meet the following requirements: (1) Except as provided in paragraph (3) below, the permittee must not cause to be

discharged into the atmosphere from the affected facility any gases which exhibit 10 percent opacity or greater.

(2) The permittee must not cause to be discharged into the atmosphere from any mechanical vent the facility gases which contain particulate matter in excess of 0.023 g/dscm (0.010 gr/dscf).

(3) Equipment used in the loading, unloading, and conveying operations of open storage piles are not subject to the opacity limitations of paragraph (1) above.

c. Pursuant to 401 KAR 59:010, Section 3(2), PM emissions from emission unit DC-1,

DC-2, DC-3, and DC-4 shall not exceed the calculated allowable rate as determined by the following equation:

hrton

Wherehrton

hrlb

hrton

hrton

hrlb

hrton

hrlb

rate weightProcess P

30 than greater P for P 17.31 Emissions

30 to equal or than less but 0.5 than greater P for P 3.59 Emissions

0.5 to equal or than less P for 2.34 Emissions

0.16

0.62

=

=

=

=


a. Compliance with PM\PM10\PM2.5 Emission Limitations a shall be demonstrated by

fulfilling the following requirements: (1) Operating Limitations a and b; (2) Testing Requirements a, b and c; (3) Specific Recordkeeping Requirements a, b, and c; and (4) Specific Reporting Requirements a and b.

b. Compliance with opacity Emission Limitations b shall be demonstrated by fulfilling the following requirements:

(1) Operating Limitations a, b c, and d; (2) Testing Requirements a and d; (3) Specific Recordkeeping Requirements a and c; and (4) Specific Reporting Requirements a and b.

c. Compliance with PM Emission Limitations c is demonstrated based on the PM

emission factors provided in the application submitted by the source. If the source alters processes or process rates, or any other factor that would result in increased emissions of the previously evaluated PM10, the source shall submit the appropriate application forms pursuant to 401 KAR 52:020, Section 4.


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) 3. Testing Requirements:

a. Pursuant to 401 KAR 51:005 and 401 KAR 50:045, the permittee shall demonstrate

compliance with the PM\PM10\PM2.5 emission limits from one of the units in DC-1, DC-2, DC-3 and DC-4 and opacity limits from DC-1, DC-2, DC-3, DC-4, CH-1, CH-2, CH-3, CH-4, CH-5 and CH-6 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 the applicable methods described in paragraph h and i in this section.

b. Pursuant to CFR 60.255(b), the permittee must conduct performance tests according

to the requirements of 40 CFR 60.8 and the methods identified in 40 CFR 60.257 to demonstrate compliance with the applicable emissions standards as specified below. (1) An initial PM\PM10\PM2.5 performance test must be performed. Thereafter, a

new performance test must be conducted according the requirements below, as applicable: (i) If the results of the most recent performance test demonstrate that

emissions from the facility are greater than 50 percent of the applicable emissions standard, a new performance test must be conducted within 12 calendar months of the date that the previous performance test was required to be completed.

(ii) If the results of the most recent performance test demonstrate that emissions from the facility are 50 percent or less of the applicable emissions standard, a new performance test must be conducted within 24 calendar months of the date that the previous performance test was required to be completed.

(iii) If the facility has not operated for the 60 calendar days prior to the due date of a performance test, the permittee is not required to perform the subsequent performance test until 30 calendar days after the next operating day.

(2) An initial opacity performance test must be performed. Thereafter, a new performance test must be conducted according to the following requirements as applicable, except as provided for in 40 CFR 60.255(e) and (f). (i) If any 6-minute average opacity reading in the most recent performance

test exceeds half the applicable opacity limit, a new performance test must be conducted within 90 operating days of the date that the previous performance test was required to be completed.

(ii) If all 6-minute average opacity readings in the most recent performance test are equal to or less than half the applicable opacity limit, a new performance test must be conducted within 12 calendar months of the date that the previous performance test was required to be completed.

c. Pursuant to 40 CFR 60.255(c), since DC-1, DC-2, DC-3 and DC-4 are enclosed in a

building, if emissions from the building do not exceed any of the standards in 40 CFR 60.254 that apply to the facility, then the facility shall be deemed to be in compliance with such standards.



d. Pursuant to 40 CFR 60.255(e), since DC-1, DC-2, DC-3 and DC-4 are the same type of facility, the permittee is allowed by the Division to conduct a single PM\PM10\PM2.5 performance test on one of the four emission units to demonstrate that the group is in compliance with the applicable emissions standards provided that the permittee meets the following conditions: (1) The performance test results are ninety (90) percent or less of the emission

limit; (2) The manufacturer's recommended maintenance procedures are followed for

each control device; (3) The performance test shall be conducted a minimum of once every five (5)

years (no more than sixty-two (62) calendar months following the previous performance test).

e. Pursuant to 40 CFR 60.255(f), as an alternative to meeting the requirements 40 CFR

60.255(b)(2), the permittee may elect to comply with the requirement of paragraph (1) or (2) below. (1) Monitor visible emissions from each affected facility according to the following

requirements. (i) Conduct one daily 15-second observation each operating day for each

affected facility (during normal operation) when the coal preparation and processing plant is in operation. Each observation must be recorded as either visible emissions observed or no visible emissions observed. Each observer determining the presence of visible emissions must meet the training requirements specified in Section 2.3 of Method 22 of 40 CFR 60, Appendix A–7. If visible emissions are observed during any 15-second observation, the permittee must adjust the operation of the affected facility and demonstrate within 24 hours that no visible emissions are observed from the affected facility. If visible emissions are observed, a Method 9 of 40 CFR 60, Appendix A–4 performance test must be conducted within 45 operating days.

(ii) Conduct monthly visual observations of all process and control equipment. If any deficiencies are observed, the necessary maintenance must be performed as expeditiously as possible.

(iii) Conduct a performance test using Method 9 of 40 CFR 60, Appendix A–4 at least once every 5 calendar years for each affected facility.

(2) Prepare a written site-specific monitoring plan for a digital opacity compliance system for approval by the Division. The plan shall require observations of at least one digital image every 15 seconds for 10-minute periods (during normal operation) every operating day. An approvable monitoring plan must include a demonstration that the occurrences of visible emissions are not in excess of 5 percent of the observation period. For reference purposes in preparing the monitoring plan, see OAQPS “Determination of Visible Emission Opacity from Stationary Sources Using Computer-Based Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality and Planning Standards; Sector Policies and Programs Division; Measurement Group (D243–02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Network (TTN) under Emission Measurement Center Preliminary Methods.



The monitoring plan approved by the Administrator or delegated authority shall be implemented by the owner or operator.

f. Pursuant to 40 CFR 60.255(g), as an alternative to meeting the requirements in 40

CFR 60.255(b)(2), the permittee may install, operate, and maintain a continuous opacity monitoring system (COMS). Each COMS used to comply with provisions of 40 CFR 60, Subpart Y, must be installed, calibrated, maintained, and continuously operated according to the requirements in 40 CFR 60.255(g)(1) and (2).

g. Pursuant to 40 CFR 60.257(a), the permittee must conduct opacity performance

tests as specified below. (1) EPA Method 9 and the procedures in 40 CFR 60.11 must be used to determine

opacity, with the exceptions listed below: (i) The duration of the Method 9 of 40 CFR 60, Appendix A–4 performance

test shall be 1 hour (ten 6-minute averages). (ii) If, during the initial 30 minutes of the observation of a Method 9 of 40

CFR 60, Appendix A–4 performance test, all of the 6-minute average opacity readings are less than or equal to half the applicable opacity limit, then the observation period may be reduced from 1 hour to 30 minutes.

(2) To determine opacity for fugitive coal dust emissions sources, the additional requirements specified below must be used. (i) The minimum distance between the observer and the emission source

shall be 5.0 meters (16 feet), and the sun shall be oriented in the 140-degree sector of the back.

(ii) The observer shall select a position that minimizes interference from other fugitive coal dust emissions sources and make observations such that the line of vision is approximately perpendicular to the plume and wind direction.

(iii) The observer shall make opacity observations at the point of greatest opacity in that portion of the plume where condensed water vapor is not present. Water vapor is not considered a visible emission.

(3) A visible emissions observer may conduct visible emission observations for up to three fugitive, stack, or vent emission points within a 15-second interval if the following conditions specified below are met.

(i) No more than three emissions points may be read concurrently. (ii) All three emissions points must be within a 70 degree viewing sector or

angle in front of the observer such that the proper sun position can be maintained for all three points.

(iii) If an opacity reading for any one of the three emissions points is within 5 percent opacity from the applicable standard (excluding readings of zero opacity), then the observer must stop taking readings for the other two points and continue reading just that single point.

h. Pursuant to 40 CFR 60.257(b), the permittee must conduct all PM\PM10\PM2.5

performance tests required to demonstrate compliance with the applicable emissions standards using the applicable test methods and procedures below. (1) Method 1 or 1A of 40 CFR 60, Appendix A-4 shall be used to select sampling

port locations and the number of traverse points in each stack or duct. Sampling sites must be located at the outlet of the control device (or at the



outlet of the emissions source if no control device is present) prior to any releases to the atmosphere.

(2) Method 2, 2A, 2C, 2D, 2F, or 2G of 40 CFR 60, Appendix A-4 shall be used to determine the volumetric flow rate of the stack gas.

(3) Method 3, 3A, or 3B of 40 CFR 60, Appendix A-4 shall be used to determine the dry molecular weight of the stack gas. The permittee may use ANSI/ASME PTC 19.10-1981, "Flue and Exhaust Gas Analyses" (incorporated by reference - see 40 CFR 60.17) as an alternative to EPA Method 3B of 40 CFR 60, Appendix A-2.

(4) Method 4 of 40 CFR 60, Appendix A-4 shall be used to determine the moisture content of the stack gas.

(5) Method 5 or 5D of 40 CFR 60, Appendix A-4 or Method 17 of 40 CFR 60, Appendix A-7 shall be used to determine the PM\PM10\PM2.5 concentration as follows: (i) The sampling time and sample volume for each run shall be at least 60

minutes and 30 dscf. Sampling shall begin no less than 30 minutes after startup and shall terminate before shutdown procedures begin. A minimum of three valid test runs are needed to comprise a PM\PM10\PM2.5 performance test; and

(ii) Method 5D of 40 CFR 60, Appendix A-4 shall be used for positive pressure fabric filters and other similar applications (e.g., stub stacks and roof vents).


Refer to Testing Requirements.


a. Pursuant to 401 KAR 59:005, Section 3(2), the permittee shall maintain the records of the occurrence and duration of any malfunction of the air pollution control equipment and or any periods during which a continuous emission monitoring system or monitoring device is inoperative.


monthly basis and a twelve (12) month rolling total of PM\PM10\PM2.5 emissions using emission factors, data from performance tests, and process rates or other applicable data along with supporting calculations.

c. Pursuant to 401 KAR 52:020, Section 26 and 40 CFR 64.9, the permittee shall

maintain the following records on site: (1) All measurements, including monitoring devices and performance test results

and all calibration checks; (2) The amount and type of coal processed each calendar month;

(3) Monthly certification that the dust suppressant systems were operational when any coal was processed and that manufacturer recommendations were followed for all control systems. Any variance from the manufacturer's recommendations shall be noted;



(4) The manufacturer's recommended maintenance procedures and the date and time of any maintenance and inspection activities and the results of those activities. Any variance from manufacturer recommendation shall be noted;

(5) The date and time of periodic coal preparation and processing plant opacity observations noting those sources with emissions above the action level (visible emissions in excess of five (5) percent of the observation period) along with corrective actions taken to reduce visible emissions. Results from the actions shall be noted; and

(6) The amount of chemical stabilizer or water purchased for use in the coal preparation and processing plant.

d. Pursuant to 40 CFR 60.258, the permittee shall maintain in a logbook (written or

electronic) on-site and make it available upon request. The logbook shall record the following: (1) The manufacturer's recommended maintenance procedures and the date and

time of any maintenance and inspection activities and the results of those activities. Any variance from manufacturer recommendation, if any, shall be noted.

(2) The date and time of periodic coal preparation and processing plant visual observations, noting those sources with visible emissions along with corrective actions taken to reduce visible emissions. Results from the actions shall be noted.

(3) The amount and type of coal processed each calendar month. (4) The amount of chemical stabilizer or water purchased for use in the coal

preparation and processing plant. (5) Monthly certification that the dust suppressant systems were operational when

any coal was processed and that manufacturer's recommendations were followed for all control systems. Any variance from the manufacturer's recommendations, if any, shall be noted.

(6) Monthly certification that the fugitive coal dust emissions control plan was implemented as described. Any variance from the plan, if any, shall be noted. A copy of the applicable fugitive coal dust emissions control plan and any letters from the Division providing approval of any alternative control measures shall be maintained with the logbook. Any actions, e.g. objections, to the plan and any actions relative to the alternative control measures, e.g. approvals, shall be noted in the logbook as well.

(7) A copy of any applicable monitoring plan for a digital opacity compliance system and monthly certification that the plan was implemented as described. Any variance from plan, if any, shall be noted.


a. For the purpose of reports required under 40 CFR 60.7(c), the permittee shall report semiannually periods of excess emissions of all 6-minute average opacities that exceed the applicable standard.

b. The permittee shall submit the results of initial performance tests to the Division,

consistent with the provisions of 40 CFR 60.8. The permittee who elects to comply with the reduced performance testing provisions of sections 40 CFR 60.255(c) or (d)



shall include in the performance test report identification of each affected facility that will be subject to the reduced testing. The permittee electing to comply with 40 CFR 60.255(d) shall also include information which demonstrates that the control devices are identical.

c. After July 1, 2011, within 60 days after the date of completing each performance

evaluation conducted to demonstrate compliance with 40 CFR 60, Subpart Y, the permittee of the affected facility must submit the test data to U. S. EPA by entering the data electronically into U. S. EPA's WebFIRE data base available at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main. For performance tests that cannot be entered into WebFIRE (i.e., Method 9 of 40 CFR 60, Appendix A–4 opacity performance tests) the permittee of the affected facility must mail a summary copy to United States Environmental Protection Agency; Energy Strategies Group; 109 TW Alexander DR; mail code: D243–01; RTP, NC 27711.



SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) Emission Unit: ST1 (ST1) Plant Roadways (unpaved) Emission Unit: ST2 (ST2) Plant Roadways (paved) Emission Unit: SLF (SLF) Slag Landfill Dozer Operation Emission Unit: CPF (CH-23B) Coal Storage Pile Dozer Operation Emission Unit: LFWE (LFWE) Slag Landfill - Wind erosion Emission Unit: CPWE (CH-23A ) Coal Storage Pile - Wind erosion Description:

The vehicular fugitive emissions (emission units ST1 and ST2) are primarily due to slag disposal operations. The dozer fugitive emissions (emission units SLF and CPF) are from maintaining the coal pile storage and slag landfill areas.

Construction Date: Estimated second quarter 2010. Capacity: Not applicable. Control Equipment: None. APPLICABLE REGULATIONS: 401 KAR 51:017 – Prevention of significant deterioration of air quality. This regulation is applicable with respect to PM\PM10\PM2.5 emissions from a new major stationary source that commenced after September 22, 1982. 401 KAR 60:005 – 40 C.F.R. Part 60 standards of performance for new stationary sources. 40 CFR Part 60, Subpart Y, Standards of performance for coal preparation plants. This regulation is applicable to facilities which process more than 161 Mg (200 tons) that commenced after May 27, 2009. 401 KAR 63:010 – Fugitive emissions. This regulation is applicable to each affected facility which emits or may emit fugitive particulate emissions and is not elsewhere subject to an opacity standard within the administrative regulations of the Division. 1. Operating Limitations:

a. Pursuant to 401 KAR 51:017, the permittee shall install and use whenever coal and

slag handling operations are taking place, the following control technology, equipment, and methods required to meet BACT demonstration:

(1) Unpaved roadways - gravel, silt fences, and wet suppression; (2) Paved roadways - silt fences, and chemical and/or wet suppression;

(3) Coal storage pile and slag landfill - silt fences, compaction, chemical and/or wet suppression, and telescopic chutes and stacking tubes; and

(4) Vehicle speeds limited to twenty (20) miles per hour.

b. Pursuant to 401 KAR 63:010, Section 3(1), the permittee shall not allow material to be handled, processed, transported or stored, or a road to be used, without taking reasonable precautions to prevent PM\PM10\PM2.5 from becoming airborne. Such precautions shall include, when applicable, but not be limited to the following: (1) Application and maintenance of asphalt, application of water or suitable

chemicals on roads, material stockpiles, and other surfaces, which can create airborne dusts;



(2) Covering at all times when in motion, open bodied trucks transporting materials likely to become airborne;

(3) The use of water sprays or other measures to suppress dust emissions during handling; and

(4) Maintaining paved roadways in a clean condition and the prompt removal of earth or other material from a paved street that may have been deposited there by trucking or other earth moving equipment or erosion by water.

c. Pursuant to 401 KAR 63:010, Section 3(2), the permittee shall not cause or permit

the discharge of visible fugitive dust emissions beyond the lot line of the property on which the emissions originate.

d. Pursuant to 40 CFR 60.254(c)(6), where appropriate chemical dust suppression

agents are selected by the permittee as a control measure to minimize fugitive coal dust emissions, (1) only chemical dust suppressants with Occupational Safety and Health Administration (OSHA)-compliant material safety data sheets (MSDS) are to be allowed; (2) the MSDS must be included in the fugitive coal dust emissions control plan; and (3) the permittee must consider and document in the fugitive coal dust emissions control plan the site-specific impacts associated with the use of such chemical dust suppressants. Refer to Specific Monitoring Requirements b for other fugitive coal dust emissions control plan conditions.


a. For compliance with Operating Limitations a, refer to Specific Recordkeeping

Requirements a and b, and compliance reporting in SECTION F paragraph 9.

b. For compliance with Operating Limitations b, refer to compliance reporting in SECTION F paragraph 9.

c. For compliance with Operating Limitations c, refer to Specific Monitoring

Requirements and Specific Recordkeeping Requirements. d. For compliance with Operating Limitations d, refer to Specific Recordkeeping

Requirements.

2. Emission Limitations: None 3. Testing Requirements:

None.


a. Pursuant to 401 KAR 52:020, Section 26, the permittee shall conduct visual observations of emissions from vehicular traffic, dozer activity, coal pile storage area, and the slag landfill a minimum of once per week as follows.



(1) A employee who has worked at the plant at least one (1) month and has been trained in the appearance and characteristics of normal visible emissions for the specified processes shall perform the observation.

(2) The observation shall be taken during the part of the operation that would normally be expected to cause the greatest emissions.

(3) The results of the observation shall be noted as normal or abnormal. (4) Visual observations are not required during periods of and immediately after

rainfall event which included 0.254 mm (0.01 in) of precipitation, and when the ground is snow covered.

b. Pursuant to 40 CFR 60.254(c), the permittee must prepare and operate in

accordance with a submitted fugitive coal dust emissions control plan that is appropriate for the site conditions as specified below. (1) The fugitive coal dust emissions control plan must identify and describe the

control measures the permittee will use to minimize fugitive coal dust emissions from each open storage pile.

(2) For open coal storage piles, the fugitive coal dust emissions control plan must require that one or more of the following control measures be used to minimize to the greatest extent practicable fugitive coal dust: Locating the source inside a partial enclosure, installing and operating a water spray or fogging system, applying appropriate chemical dust suppression agents on the source, use of a wind barrier, compaction, or use of a vegetative cover. The permittee must select, for inclusion in the fugitive coal dust emissions control plan, the control measure or measures listed in this paragraph that are most appropriate for site conditions. The plan must also explain how the measure or measures selected are applicable and appropriate for site conditions. In addition, the plan must be revised as needed to reflect any changing conditions at the source.

(3) The permittee of an affected facility that is required to have a fugitive coal dust emissions control plan may petition the Division to approve, for inclusion in the plan for the affected facility, alternative control measures other than those specified in paragraph (2) of this section above as specified below. (i) The petition must include a description of the alternative control

measures, a copy of the fugitive coal dust emissions control plan for the affected facility that includes the alternative control measures, and information sufficient for EPA to evaluate the demonstrations required by paragraph (3)(ii) of this section.

(ii) The permittee must either demonstrate that the fugitive coal dust emissions control plan that includes the alternate control measures will provide equivalent overall environmental protection or demonstrate that it is either economically or technically infeasible for the affected facility to use the control measures specifically identified in paragraph (2) of this section.

(iii) While the petition is pending, the permittee must comply with the fugitive coal dust emissions control plan including the alternative control measures submitted with the petition. Operation in accordance with the plan submitted with the petition shall be deemed to constitute compliance with the requirement to operate in accordance with a fugitive coal dust emissions control plan that contains one of the control measures



specifically identified in paragraph (2) of this section while the petition is pending.

(iv) If the petition is approved by the Division, the alternative control measures will be approved for inclusion in the fugitive coal dust emissions control plan for the affected facility. In lieu of amending this subpart, a letter will be sent to the facility describing the specific control measures approved. The facility shall make any such letters and the applicable fugitive coal dust emissions control plan available to the public. If the Division determines it is appropriate, the conditions and requirements of the letter can be reviewed and changed at any point.

(4) The permittee must submit the fugitive coal dust emissions control plan to the Division described in Specific Reporting Requirements.

(5) The Division may object to the fugitive coal dust emissions control plan as specified below. (i) The Division authority may object to any fugitive coal dust emissions

control plan that it has determined does not meet the requirements of paragraphs (1) and (2) of this section.

(ii) If an objection is raised, the permittee, within 30 days from receipt of the objection, must submit a revised fugitive coal dust emissions control plan to the Division. The permittee must operate in accordance with the revised fugitive coal dust emissions control plan. The Division retains the right, under paragraph (5) of this section, to object to the revised control plan if it determines the plan does not meet the requirements of paragraphs (1) and (2) of this section.


a. The permittee shall maintain records of pollution control methods and control measures taken to reduce fugitive emissions.


monthly basis and a twelve (12) month rolling total: (1) Emissions of total particulate mater using emission factors, and other

applicable data along with supporting calculations; (2) Mileage for the trucks used to haul coal and slag;

(3) Hours of operation for the dozers operating in the coal pile storage area and the slag landfill;

(4) Records of the tonnage of the materials hauled; and (5) The base area of the coal pile and the base area of the slag landfill in acres

shall be estimated.

c. Pursuant to 401 KAR 52:020, Section 26, the permittee shall maintain records of weekly visual observations. The results of the observation and any corrective actions taken, including date and time, shall be recorded. If visual observations are not performed due to precipitation, this shall be noted in the logbook.

d. The permittee shall maintain a working rain gauge and shall record the following

information: (1) Date of rainfall event;



(2) Duration of rainfall event; and (3) Amount of precipitation.


a. Pursuant to 40 CFR 60.254(c)(4), the permittee must submit the fugitive coal dust

emissions control plan to the Division as specified in paragraphs (a)(1) and (2) of this section. (1) The plan must be submitted to the Division prior to startup of the new,

reconstructed, or modified affected facility, or 30 days after the effective date of this rule, whichever is later.

(2) The plan must be revised as needed to reflect any changing conditions at the source. Such revisions must be dated and submitted to the Division before a source can operate pursuant to these revisions. The Division may also object to such revisions as specified in paragraph (5) of this section.


None.


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) Emission unit: MST (MT) Methanol Storage Tank Description:

The methanol storage tank is fixed cone roof tank with a shell height of 36 feet and a diameter of 27 feet.

Capacity: 154,200 gallons. Construction Date: Estimated second quarter 2010. Control Equipment: Water scrubber. APPLICABLE REGULATIONS: 401 KAR 60:005 – 40 C.F.R. Part 60 standards of performance for new stationary sources incorporating by reference 40 CFR Part 60 Subpart Kb – Standards of Performance for Volatile Organic Liquid Storage Vessels (including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984. This regulation is applicable to storage tanks larger than 151 m3 (5,331.8 gallons) storing a volatile organic liquid with a maximum true vapor pressure greater than 5.2 kilo Pascal (kPa) but less than 76.6 kPa. 401 KAR 60:005 – 40 C.F.R. Part 60 standards of performance for new stationary sources incorporating by reference 40 CFR Part 60 Subpart VV – Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry for which Construction, Reconstruction, or Modification Commenced After January 5, 1981, and on or Before November 7, 2006. This regulation is applicable to test methods described in Section 60.485(b). The test methods described are only applicable to the testing of the vent and control device, and do not include any other equipment that is otherwise covered by this regulation. 1. Operating Limitations:

a. Pursuant to 40 CFR 60.112b(a)(3), the storage tank shall be equipped with a closed

vent system and a counter current flow water scrubber. The control device shall be operated at all times when the tank contains methanol liquid and/or vapor.

b. Pursuant to 40 CFR 60.112b(a)(3)(i), the closed vent system shall be designed to

collect all volatile organic compound vapors and gases discharged from the storage vessel and operated with no detectable emissions as indicated by an instrument reading of less than 500 ppm above background and visual inspections, as determined in 40 CFR 60.485(b).

c. Pursuant to 40 CFR 60.113b(c)(2), the closed vent system and control device shall

be operated in accordance with the operating plan submitted in accordance to 40 CFR 60.113b(c)(1).

Compliance Demonstration Method: For compliance, refer to SECTION F paragraph 9 for compliance reporting.



a. Pursuant to 40 CFR 60.112b(a)(3)(ii), the control device shall be designed and operated to reduce inlet VOC emissions by ninety-five (95) percent or greater.

b. Refer to SECTION D paragraph 5 for source-wide emission limits for VOC.


a. For compliance with Emission Limitations a, refer to compliance reporting in SECTION F paragraph 9.

b. For compliance with Emission Limitations b, see SECTION D paragraph 5.


a. Pursuant to 40 CFR 60.113b(c), this unit is exempt from performance testing required by 40 CFR 60.8 of the General Provisions.

b. Pursuant to 40 CFR 60.112b(a)(3)(i), the permittee shall use Method 21 to determine

the presence of leaking sources in accordance to the methods and procedures in 40 CFR 60.485(b)(1). (1) Pursuant to 40 CFR 60.482-10(f)(1), if the vapor collection system or closed

vent system is constructed of hard-piping: (i) Conduct an initial inspection according to the procedures in 40 CFR

60.485(b); and (ii) Conduct annual visual inspections for visible, audible, or olfactory

indications of leaks. (2) Pursuant to 40 CFR 60.482-10(f)(2), if the vapor collection system or closed

vent system is constructed of ductwork: (i) Conduct an initial inspection according to the procedures in 40 CFR

60.485(b); and (ii) Conduct annual inspections according to the procedures in 40 CFR

60.485(b).

c. Pursuant to 40 CFR 60.482-1(a), the permittee shall demonstrate compliance within 180 days of initial startup.


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 storage tank; any malfunction of the air pollution control equipment; or any periods during which a continuous emission monitoring system or monitoring device is inoperative.

b. Monitor the parameters of the closed vent system and control device in accordance

with the operating plan submitted to the Division in accordance with 40 CFR 60.113b(c)(2).


SECTION B – EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS, AND OPERATING CONDITIONS (CONTINUED) 5. Specific Recordkeeping Requirements:

a. 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; and (2) Maintenance conducted on control devices, instrumentation, and process

equipment.

b. Pursuant to 40 CFR 60.116b(b), the permittee shall keep readily accessible records showing the dimension of the storage vessel and an analysis showing the capacity of the storage vessel.

c. Pursuant to 40 CFR 60.115b(c), the permittee shall keep the following records:

(1) A copy of the operating plan; and (2) A record of the measured values of the parameters monitored in accordance

with Section 60.113b(c)(2). 6. Specific Reporting Requirements:

Pursuant to 40 CFR 60.113b(c)(1), the permittee shall submit for approval by the Division as an attachment to the notification pursuant to 40 CFR 60.7(a)(1), an operating plan containing the information listed below: (1) Documentation demonstrating that the control device will achieve the required

control efficiency during maximum loading conditions. This documentation is to include a description of the gas stream which enters the control device, including flow and volatile organic compound content under varying liquid level conditions (dynamic and static) and manufacturer's design specifications for the control device.

(2) A description of the parameter or parameters to be monitored to ensure that the control device will be operated in conformance with its design and an explanation of the criteria used for selection of that parameter (or parameters).

7. Specific Control Equipment Operating Conditions: Refer to Operating Limitations.

Permit Number: V-09-006 Page 83 of 101 SECTION C – INSIGNIFICANT ACTIVITIES The following listed activities have been determined to be insignificant activities for this source pursuant to 401 KAR 52:020, Section 6. Although these activities are designated as insignificant the permittee must comply with the applicable regulation. Process and emission control equipment at each insignificant activity subject to an opacity standard shall be inspected monthly and a qualitative visible emissions evaluation made. Results of the inspection, evaluation, and any corrective action shall be recorded in a log.

Description Generally Applicable Regulation 1. Emission unit SST None Selexol® storage tank with activated carbon filter. (434,500 gallon capacity). 2. Emission unit DFST None Diesel fuel storage tank. (10,000 gallon capacity). 3. Emission unit: CCD None Four (4) maintenance cold cleaners.

Permit Number: V-09-006 Page 84 of 101 SECTION D – SOURCE EMISSION LIMITATIONS AND TESTING REQUIREMENTS 1. As required by Section 1b of the Cabinet Provisions and Procedures for Issuing Title V

Permits incorporated by reference in 401 KAR 52:020, Section 26; compliance with annual emissions and processing limitations contained in this permit, shall be based on emissions and processing rates for any twelve (12) consecutive months.

2. Particulate matter (PM10/PM2.5), SO2, NOx, CO, VOC, and H2SO4 mist emissions,

measured by applicable reference methods, or an equivalent or alternative method specified in 40 C.F.R. Chapter I, or by a test method specified in the state implementation plan shall not exceed the respective limitations specified herein.

3. Pursuant to 401 KAR 63:020, Section 3, the permittee shall not allow the facility to emit

potential hazardous matter or toxic substances in such quantities or duration as to be harmful to the health and welfare of humans, animals and plants. The source is in compliance with 401 KAR 63:020 based on the rates of emissions of airborne toxics provided in the application submitted by the permittee. If the permittee alters processes, process rates, material formulations, or any other factor that would result in increased emissions of these previously evaluated airborne toxics, or the emission of airborne toxics not previously evaluated by the Division, the permittee shall submit the appropriate application forms pursuant to 401 KAR 52:020, Section 4.

4. To preclude the applicability of 40 CFR 63, Subpart YYYY, source-wide emissions of

formaldehyde shall be less than nine (9) tons per twelve (12) month rolling total.


test. performane recent most theby determined factor emission controlled The [EF]

[EF]HRSG2 [EF]HRSG1Emissions deFormaldehyMonthly

=

⎥⎦

⎤⎢⎣

⎡+⎥⎦

⎤⎢⎣

⎡=monthmmscfx

mmscflb

monthmmscfx

mmscflb

For the purpose of calculating of excess emissions for formaldehyde, a control efficiency

of zero (0) percent shall be assumed for all periods when the catalytic oxidizer does not meet the operating limits specified in Specific Control Equipment Operating Conditions b in SECTION B, Emission Units HRSG1 and HRSG2.

5. To preclude the applicability of 401 KAR 51:017 significant emission increase levels for

VOC, source-wide emissions of VOC shall be less than thirty-six (36) tons per twelve (12) month rolling total.

Permit Number: V-09-006 Page 85 of 101 SECTION D – SOURCE EMISSION LIMITATIONS AND TESTING REQUIREMENTS (CONTINUED)


addendum. Method ionDemonstrat Compliance to Refer


VOCEmissions LDAR0.0005 0.2355MST

[EF] FP [EF]EG0.005 1,328FLR

0.0109FLR0.02 2.53T [EF]TO

0.3AGR 4.72ASP 5.507MSH 4.0976AUXB

[EF]HRSG2 [EF]HRSG1Emissions CMonthly VO

*

SU

=

⎥⎦⎤

⎢⎣⎡+⎥

⎦

⎤⎢⎣

⎡

+⎥⎦

⎤⎢⎣

⎡+⎥⎦

⎤⎢⎣

⎡+⎥⎥⎦

⎤

⎢⎢⎣

⎡

+⎥⎦

⎤⎢⎣

⎡+⎥⎥⎦

⎤

⎢⎢⎣

⎡+⎥⎦

⎤⎢⎣

⎡

+⎥⎦⎤

⎢⎣⎡+⎥⎦

⎤⎢⎣⎡+⎥⎦

⎤⎢⎣⎡+⎥⎦

⎤⎢⎣⎡

+⎥⎦

⎤⎢⎣

⎡+⎥⎦

⎤⎢⎣

⎡=

*

SU

monthlbx

monthhrx

hrlb

monthmmscfx

mmscflb

monthmmscfx

mmscflb

monthhrx

hrlb

monthhrx

hrlbx

monthhrx

hrlbO

monthhrx

hrlb

monthhrx

hrlb

monthmmscfx

mmscflb

monthmmscfx

mmscflb

monthmmscfx

mmscflb

monthmmscfx

mmscflb

monthmmscfx

mmscflb


H2SO4, source-wide emissions of H2SO4 shall be less than six and three-tenths (6.3) tons per twelve (12) month rolling total.



0.0003FLR0.3511 T [EF]TO

0.099017HRSG2 0.099017HRSG1Emissions SOHMonthly 42

=

⎥⎦

⎤⎢⎣

⎡+⎥⎥⎦

⎤

⎢⎢⎣

⎡+⎥⎦

⎤⎢⎣

⎡

+⎥⎦

⎤⎢⎣

⎡+⎥⎦

⎤⎢⎣

⎡=

monthhrx

hrlbx

monthhrx

hrlb01.6O

monthhrx

hrlb

monthmmscfx

mmscflb

monthmmscfx

mmscflb

SU


H2S, source-wide emissions of H2S shall be less than nine (9) tons per twelve (12) month rolling total.


addendum. Method ionDemonstrat Compliance to Refer

test performane recent most theby determined factor emission controlled The [EF]

SH Emissions LDAR0.0007 1,282T

[EF]TO [EF]AGREmissions SHMonthly

*

2

2

=

⎥⎦

⎤⎢⎣

⎡+⎥⎥⎦

⎤

⎢⎢⎣

⎡

+⎥⎦

⎤⎢⎣

⎡+⎥⎦

⎤⎢⎣

⎡=

*SU

monthlbx

monthhrx

hrlbO

monthhrx

hrlb

monthhrx

hrlb

Permit Number: V-09-006 Page 86 of 101 SECTION D – SOURCE EMISSION LIMITATIONS AND TESTING REQUIREMENTS (CONTINUED) Emission Unit Emission Unit Designation Description HRSG1 Combustion turbine 1 HRSG1 Combustion turbine 1 AUXB Auxiliary boiler MSH Methanation startup heater ASP Aspirator vent for gasifier preheat AGR Acid gas recovery vent TO Sulfur recovery unit TOSU Sulfur recovery unit (during startup) FLR Flare (pilots) FLRSU Flare (during startup while burning methanol) EG Emergency generator FP Fire pump MST Methanol storage tank ADDENDUM to Compliance Demonstration Methods for paragraphs D.5 and D.7, LDAR emissions. Fugitive Equipment Leaks Emission Factor (lb/hr-component) Stream Type Valves Connectors Compressors Pumps Heavy Liquid 0.0007 0.00007 0.0161 Light Liquid 0.0035 0.0005 0.0386 Vapor 0.0089 0.0029 0.5027 Control Efficiency (%) Stream Type Valves Connectors Compressors Pumps Heavy Liquid 97 97 0 Light Liquid 97 97 85 Vapor 97 97 85 85 Compliance Demonstration Equation: E = N x EF x W x H x (1 – CE) Where: E = Emission rate, lb/month N = Number of components EF = Stream type, component specific, emission factor (lb/hr-component) W = lb pollutant (i.e., VOC, H2S) per pound of emission H = Monthly hours of operation = 730 CE = Stream type, component specific, control efficiency (%)

Permit Number: V-09-006 Page 87 of 101 SECTION E – SOURCE CONTROL EQUIPMENT REQUIREMENTS 1. Pursuant to 401 KAR 50:055, Section 2(5), at all times, including periods of startup,

shutdown and malfunction, owners and operators shall, to the extent practicable, maintain and operate any affected facility including associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Division which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source.

2. Pursuant to 401 KAR 52:020, Section 26, for the catalytic oxidizer on the combustion

turbines (emission unit HRSG1 and HRSG2) and the acid gas recovery vent (emission unit AGR), and the thermal oxidizer on the sulfur recover unit (emission unit TO), the permittee shall conduct the following instrumentation inspections.

a. Perform an electronic calibration semi-annually (no more than twenty-eight (28)

calendar weeks after the last calibration) of the convertor/temperature readout device. Following the electronic calibration, a thermocouple validation check must be conducted in which the readout device of a second or redundant thermocouple must yield a reading within thirty (30) degrees Fahrenheit of each other.

b. Conduct an accuracy audit consisting of an electronic calibration of the

convertor/temperature readout device and validation of the thermocouple any time the thermocouple exceeds the manufacturer’s specified maximum operating temperature range or install a new lab certified thermal couple.

c. Inspect components for integrity and electrical connections for continuity, oxidation,

and galvanic corrosion on a monthly basis.

Permit Number: V-09-006 Page 88 of 101 SECTION F – MONITORING, RECORDKEEPING, AND REPORTING REQUIREMENTS 1. Pursuant to Section 1b-IV-1 of the Cabinet Provisions and Procedures for Issuing Title V

Permits incorporated by reference in 401 KAR 52:020, Section 26, when continuing compliance is demonstrated by periodic testing or instrumental monitoring, the permittee shall compile records of required monitoring information that include:

a. Date, place as defined in this permit, and time of sampling or measurements; b. Analyses performance dates; c. Company or entity that performed analyses;

d. Analytical techniques or methods used; e. Analyses results; and

f. Operating conditions during time of sampling or measurement.

2. Records of all required monitoring data and support information, including calibrations, maintenance records, and original strip chart recordings, and copies of all reports required by the Division for Air Quality, shall be retained by the permittee for a period of five (5) years and shall be made available for inspection upon request by any duly authorized representative of the Division for Air Quality [Sections 1b-IV-2 and 1a-8 of the Cabinet Provisions and Procedures for Issuing Title V Permits incorporated by reference in 401 KAR 52:020, Section 26].

3. In accordance with the requirements of 401 KAR 52:020, Section 3(1)h the permittee shall

allow authorized representatives of the Cabinet to perform the following during reasonable times: a. Enter upon the premises to inspect any facility, equipment (including air pollution

control equipment), practice, or operation; b. To access and copy any records required by the permit:

c. Sample or monitor, at reasonable times, substances or parameters to assure compliance with the permit or any applicable requirements.

Reasonable times are defined as during all hours of operation, during normal office hours; or during an emergency.

4. No person shall obstruct, hamper, or interfere with any Cabinet employee or authorized

representative while in the process of carrying out official duties. Refusal of entry or access may constitute grounds for permit revocation and assessment of civil penalties.

5. Summary reports of any monitoring required by this permit shall be submitted to the

Regional Office listed on the front of this permit at least every six (6) months during the life of this permit, unless otherwise stated in this permit. For emission units that were still under construction or which had not commenced operation at the end of the 6-month period covered by the report and are subject to monitoring requirements in this permit, the report shall indicate that no monitoring was performed during the previous six (6) months because the emission unit was not in operation [Sections 1b-V-1 of the Cabinet Provisions and Procedures for Issuing Title V Permits incorporated by reference in 401 KAR 52:020, Section 26].

6. The semi-annual reports are due by January 30th and July 30th of each year. All reports

shall be certified by a responsible official pursuant to 401 KAR 52:020, Section 23. If continuous emission and opacity monitors are required by regulation or this permit, data shall be reported in accordance with the requirements of 401 KAR 59:005, General Provisions, Section 3(3). All deviations from permit requirements shall be clearly identified in the reports.

Permit Number: V-09-006 Page 89 of 101 SECTION F – MONITORING, RECORDKEEPING, AND REPORTING REQUIREMENTS (CONTINUED) 7. In accordance with the provisions of 401 KAR 50:055, Section 1 the owner or operator

shall notify the Regional Office listed on the front of this permit concerning startups, shutdowns, or malfunctions as follows: a. When emissions during any planned shutdowns and ensuing startups will exceed the

standards, notification shall be made no later than three (3) days before the planned shutdown, or immediately following the decision to shut down, if the shutdown is due to events which could not have been foreseen three (3) days before the shutdown.

b. When emissions due to malfunctions, unplanned shutdowns and ensuing startups are or may be in excess of the standards, notification shall be made as promptly as possible by telephone (or other electronic media) and shall be submitted in writing upon request.

8. The owner or operator shall report emission related exceedances from permit

requirements including those attributed to upset conditions (other than emission exceedances covered by SECTION F.7 above) to the Regional Office listed on the front of this permit within 30 days. Deviations from permit requirements, including those previously reported under F.7 above, shall be included in the semiannual report required by F.6 [Sections 1b-V, 3 and 4 of the Cabinet Provisions and Procedures for Issuing Title V Permits incorporated by reference in 401 KAR 52:020, Section 26].

9. Pursuant to 401 KAR 52:020, Permits, Section 21, the permittee shall annually certify

compliance with the terms and conditions contained in this permit, by completing and returning a Compliance Certification Form (DEP 7007CC) (or an alternative approved by the regional office) to the Regional Office listed on the front of this permit and the U.S. EPA in accordance with the following requirements:

a. Identification of the term or condition; b. Compliance status of each term or condition of the permit; c. Whether compliance was continuous or intermittent;

d. The method used for determining the compliance status for the source, currently and over the reporting period.

e. For an emissions unit that was still under construction or which has not commenced operation at the end of the 12-month period covered by the annual compliance certification, the permittee shall indicate that the unit is under construction and that compliance with any applicable requirements will be demonstrated within the timeframes specified in the permit.

f. The certification shall be postmarked by January 30th of each year. Annual compliance certifications shall be mailed to the following addresses:

Division for Air Quality U.S. EPA Region 4 Owensboro Regional Office Air Enforcement Branch 3032 Alvey Park Drive W. Atlanta Federal Center Suite 700 61 Forsyth St. Owensboro, KY 42303 Atlanta, GA 30303-8960 Division for Air Quality Central Files 200 Fair Oaks Lane, 1st Floor Frankfort, KY 40601

Permit Number: V-09-006 Page 90 of 101 SECTION F – MONITORING, RECORDKEEPING, AND REPORTING REQUIREMENTS (CONTINUED) 10. In accordance with 401 KAR 52:020, Section 22, the permittee shall provide the Division

with all information necessary to determine its subject emissions within thirty (30) days of the date the KYEIS emission survey is mailed to the permittee.

Permit Number: V-09-006 Page 91 of 101 SECTION G – GENERAL CONDITIONS 1. General Compliance Requirements

a. The permittee shall comply with all conditions of this permit. Noncompliance shall be a violation of 401 KAR 52:020, Section 3(1)(b) and a violation of Federal Statute 42 USC 7401 through 7671q (the Clean Air Act). Noncompliance with this permit is grounds for enforcement action including but not limited to termination, revocation and reissuance, revision or denial of a permit [Section 1a-3 of the Cabinet Provisions and Procedures for Issuing Title V Permits incorporated by reference in 401 KAR 52:020, Section 26].

b. The filing of a request by the permittee for any permit revision, revocation,

reissuance, or termination, or of a notification of a planned change or anticipated noncompliance, shall not stay any permit condition [Section 1a-6 of the Cabinet Provisions and Procedures for Issuing Title V Permits incorporated by reference in 401 KAR 52:020, Section 26].

c. This permit may be revised, revoked, reopened and reissued, or terminated for

cause in accordance with 401 KAR 52:020, Section 19. The permit will be reopened for cause and revised accordingly under the following circumstances: (1) If additional applicable requirements become applicable to the source and the

remaining permit term is three (3) years or longer. In this case, the reopening shall be completed no later than eighteen (18) months after promulgation of the applicable requirement. A reopening shall not be required if compliance with the applicable requirement is not required until after the date on which the permit is due to expire, unless this permit or any of its terms and conditions have been extended pursuant to 401 KAR 52:020, Section 12;

(2) The Cabinet or the U. S. EPA determines that the permit must be revised or revoked to assure compliance with the applicable requirements;

(3) The Cabinet or the U. S. EPA determines that the permit contains a material mistake or that inaccurate statements were made in establishing the emissions standards or other terms or conditions of the permit;

(4) New requirements become applicable to a source subject to the Acid Rain Program.

Proceedings to reopen and reissue a permit shall follow the same procedures as apply to initial permit issuance and shall affect only those parts of the permit for which cause to reopen exists. Reopenings shall be made as expeditiously as practicable. Reopenings shall not be initiated before a notice of intent to reopen is provided to the source by the Division, at least thirty (30) days in advance of the date the permit is to be reopened, except that the Division may provide a shorter time period in the case of an emergency.

d. The permittee shall furnish information upon request of the Cabinet to determine if

cause exists for modifying, revoking and reissuing, or terminating the permit; or to determine compliance with the conditions of this permit [Sections 1a- 7 and 8 of the Cabinet Provisions and Procedures for Issuing Title V Permits incorporated by reference in 401 KAR 52:020, Section 26].

e. Emission units described in this permit shall demonstrate compliance with applicable

requirements if requested by the Division [401 KAR 52:020, Section 3(1)(c)].

Permit Number: V-09-006 Page 92 of 101 SECTION G- GENERAL CONDITIONS (CONTINUED)

f. The permittee, upon becoming aware that any relevant facts were omitted or incorrect information was submitted in the permit application, shall promptly submit such supplementary facts or corrected information to the permitting authority [401 KAR 52:020, Section 7(1)].

g. Any condition or portion of this permit which becomes suspended or is ruled invalid

as a result of any legal or other action shall not invalidate any other portion or condition of this permit [Section 1a-14 of the Cabinet Provisions and Procedures for Issuing Title V Permits incorporated by reference in 401 KAR 52:020, Section 26].

h. The permittee shall not use as a defense in an enforcement action the contention

that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance [Section 1a-4 of the Cabinet Provisions and Procedures for Issuing Title V Permits incorporated by reference in 401 KAR 52:020, Section 26].

i. Except for requirements identified in this permit as state-origin requirements, all

terms and conditions shall be enforceable by the United States Environmental Protection Agency and citizens. [Section 1a-15-b of the Cabinet Provisions and Procedures for Issuing Title V Permits incorporated by reference in 401 KAR 52:020, Section 26]

j. This permit shall be subject to suspension if the permittee fails to pay all emissions

fees within 90 days after the date of notice as specified in 401 KAR 50:038, Section 3(6) [Section 1a-10 of the Cabinet Provisions and Procedures for Issuing Title V Permits incorporated by reference in 401 KAR 52:020, Section 26].

k. Nothing in this permit shall alter or affect the liability of the permittee for any violation

of applicable requirements prior to or at the time of permit issuance [401 KAR 52:020, Section 11(3) 2.].

l. This permit does not convey property rights or exclusive privileges [Section 1a-9 of

the Cabinet Provisions and Procedures for Issuing Title V Permits incorporated by reference in 401 KAR 52:020, Section 26].

m. Issuance of this permit does not relieve the permittee from the responsibility of

obtaining any other permits, licenses, or approvals required by the Cabinet or any other federal, state, or local agency.

n. Nothing in this permit shall alter or affect the authority of U.S. EPA to obtain

information pursuant to Federal Statute 42 USC 7414, Inspections, monitoring, and entry [401 KAR 52:020, Section 11(3) 4.].

o. Nothing in this permit shall alter or affect the authority of U.S. EPA to impose

emergency orders pursuant to Federal Statute 42 USC 7603, Emergency orders [401 KAR 52:020, Section 11(3) 1.].

p. This permit consolidates the authority of any previously issued PSD, NSR, or

Synthetic Minor source preconstruction permit terms and conditions for various emission units and incorporates all requirements of those existing permits into one (1) single permit for this source.


q. Pursuant to 401 KAR 52:020, Section 11, a permit shield shall not protect the owner or operator from enforcement actions for violating an applicable requirement prior to or at the time of permit issuance. Compliance with the conditions of this permit shall be considered compliance with: (1) Applicable requirements that are included and specifically identified in the

permit and (2) Non-applicable requirements expressly identified in this permit.

2. Permit Expiration and Reapplication Requirements

a. This permit shall remain in effect for a fixed term of five (5) years following the

original date of issue. Permit expiration shall terminate the source's right to operate unless a timely and complete renewal application has been submitted to the Division at least six months prior to the expiration date of the permit. Upon a timely and complete submittal, the authorization to operate within the terms and conditions of this permit, including any permit shield, shall remain in effect beyond the expiration date, until the renewal permit is issued or denied by the Division [401 KAR 52:020, Section 12].

b. The authority to operate granted shall cease to apply if the source fails to submit

additional information requested by the Division after the completeness determination has been made on any application, by whatever deadline the Division sets [401 KAR 52:020, Section 8(2)].

3. Permit Revisions

a. A minor permit revision procedure may be used for permit revisions involving the use of economic incentive, marketable permit, emission trading, and other similar approaches, to the extent that these minor permit revision procedures are explicitly provided for in the SIP or in applicable requirements and meet the relevant requirements of 401 KAR 52:020, Section 14(2).

b. This permit is not transferable by the permittee. Future owners and operators shall

obtain a new permit from the Division for Air Quality. The new permit may be processed as an administrative amendment if no other change in this permit is necessary, and provided that a written agreement containing a specific date for transfer of permit responsibility coverage and liability between the current and new permittee has been submitted to the permitting authority within ten (10) days following the transfer.

4. Construction, Start-Up, and Initial Compliance Demonstration Requirements

Pursuant to a duly submitted application the Kentucky Division for Air Quality hereby authorizes the construction of the equipment described herein, emission points HRSG1, HRSG2, AUXB, MSH, AGR, TO, FLR, ASP, EG, FP, CT1-22, DC-1, DC-2, DC-3, DC-4, CH-1, CH-2, CH-3, CH-4, CH-5, CH-6, ST1, ST2, SLF, CPF, LFWE, CPWE and MST in accordance with the terms and conditions of this permit.

a. Construction of any process and/or air pollution control equipment authorized by this

permit shall be conducted and completed only in compliance with the conditions of this permit.


b. Within thirty (30) days following commencement of construction and within fifteen (15) days following start-up and attainment of the maximum production rate specified in the permit application, or within fifteen (15) days following the issuance date of this permit, whichever is later, the permittee shall furnish to the Regional Office listed on the front of this permit in writing, with a copy to the Division's Frankfort Central Office, notification of the following:

(1) The date when construction commenced. (2) The date of start-up of the affected facilities listed in this permit.

(3) The date when the maximum production rate specified in the permit application was achieved.

c. Pursuant to 401 KAR 52:020, Section 3(2), unless construction is commenced within

eighteen (18) months after the permit is issued, or begins but is discontinued for a period of eighteen (18) months or is not completed within a reasonable timeframe then the construction and operating authority granted by this permit for those affected facilities for which construction was not completed shall immediately become invalid. Upon written request, the Cabinet may extend these time periods if the source shows good cause.

d. For those affected facilities for which construction is authorized by this permit, a

source shall be allowed to construct with the proposed permit. Operational or final permit approval is not granted by this permit until compliance with the applicable standards specified herein has been demonstrated pursuant to 401 KAR 50:055. If compliance is not demonstrated within the prescribed timeframe provided in 401 KAR 50:055, the source shall operate thereafter only for the purpose of demonstrating compliance, unless otherwise authorized by Section I of this permit or order of the Cabinet.

e. This permit shall allow time for the initial start-up, operation, and compliance

demonstration of the affected facilities listed herein. However, within sixty (60) days after achieving the maximum production rate at which the affected facilities will be operated but not later than 180 days after initial start-up of such facilities, the permittee shall conduct a performance demonstration on the affected facilities in accordance with 401 KAR 50:055, General compliance requirements. Testing must also be conducted in accordance with General Provisions G.5 of this permit.

f. Terms and conditions in this permit established pursuant to the construction authority

of 401 KAR 51:017 or 401 KAR 51:052 shall not expire.

5. Testing Requirements

a. Pursuant to 401 KAR 50:045, Section 2, a source required to conduct a performance test shall submit a completed Compliance Test Protocol form, DEP form 6028, or a test protocol a source has developed for submission to other regulatory agencies, in a format approved by the cabinet, to the Division's Frankfort Central Office a minimum of sixty (60) days prior to the scheduled test date. Pursuant to 401 KAR 50:045, Section 7, the Division shall be notified of the actual test date at least thirty (30) days prior to the test.

b. Pursuant to 401 KAR 50:045, Section 5, in order to demonstrate that a source is

capable of complying with a standard at all times, any required performance test shall be conducted under normal conditions that are representative of the source’s


operations and create the highest rate of emissions. If [When] the maximum production rate represents a source’s highest emissions rate and a performance test is conducted at less than the maximum production rate, a source shall be limited to a production rate of no greater than 110 percent of the average production rate during the performance tests. If and when the facility is capable of operation at the rate specified in the application, the source may retest to demonstrate compliance at the new production rate. The Division for Air Quality may waive these requirements on a case-by-case basis if the source demonstrates to the Division's satisfaction that the source is in compliance with all applicable requirements.

c. Results of performance test(s) required by the permit shall be submitted to the

Division by the source or its representative within forty-five days or sooner if required by an applicable standard, after the completion of the fieldwork.

6. Acid Rain Program Requirements

a. If an applicable requirement of Federal Statute 42 USC 7401 through 7671q (the Clean Air Act) is more stringent than an applicable requirement promulgated pursuant to Federal Statute 42 USC 7651 through 7651o (Title IV of the Act), both provisions shall apply, and both shall be state and federally enforceable.

b. The permittee shall comply with all applicable requirements and conditions of the

Acid Rain Permit and the Phase II permit application (including the Phase II NOx compliance plan and averaging plan, if applicable) incorporated into the Title V permit issued for this source. The source shall also comply with all requirements of any revised or future acid rain permits issued to this source.

7. Emergency Provisions

a. Pursuant to 401 KAR 52:020, Section 24(1), an emergency shall constitute an affirmative defense to an action brought for the noncompliance with the technology-based emission limitations if the permittee demonstrates through properly signed contemporaneous operating logs or relevant evidence that: (1) An emergency occurred and the permittee can identify the cause of the

emergency; (2) The permitted facility was at the time being properly operated;

(3) During an emergency, the permittee took all reasonable steps to minimize levels of emissions that exceeded the emissions standards or other requirements in the permit; and

(4) Pursuant to 401 KAR 52:020, 401 KAR 50:055, and KRS 224.01-400, the permittee notified the Division as promptly as possible and submitted written notice of the emergency to the Division when emission limitations were exceeded due to an emergency. The notice shall include a description of the emergency, steps taken to mitigate emissions, and corrective actions taken.

(5) This requirement does not relieve the source of other local, state or federal notification requirements.

b. Emergency conditions listed in General Condition G.7.a above are in addition to any

emergency or upset provisions contained in an applicable requirement [401 KAR 52:020, Section 24(3)].


c. In an enforcement proceeding, the permittee seeking to establish the occurrence of an emergency shall have the burden of proof [401 KAR 52:020, Section 24(2)].

8. Ozone Depleting Substances

a. The permittee shall comply with the standards for recycling and emissions reduction pursuant to 40 CFR 82, Subpart F, except as provided for Motor Vehicle Air Conditioners (MVACs) in Subpart B: (1) Persons opening appliances for maintenance, service, repair, or disposal shall

comply with the required practices contained in 40 CFR 82.156. (2) Equipment used during the maintenance, service, repair, or disposal of

appliances shall comply with the standards for recycling and recovery equipment contained in 40 CFR 82.158.

(3) Persons performing maintenance, service, repair, or disposal of appliances shall be certified by an approved technician certification program pursuant to 40 CFR 82.161.

(4) Persons disposing of small appliances, MVACs, and MVAC-like appliances (as defined at 40 CFR 82.152) shall comply with the recordkeeping requirements pursuant to 40 CFR 82.166

(5) Persons owning commercial or industrial process refrigeration equipment shall comply with the leak repair requirements pursuant to 40 CFR 82.156.

(6) Owners/operators of appliances normally containing 50 or more pounds of refrigerant shall keep records of refrigerant purchased and added to such appliances pursuant to 40 CFR 82.166.

b. If the permittee performs service on motor (fleet) vehicle air conditioners containing

ozone-depleting substances, the source shall comply with all applicable requirements as specified in 40 CFR 82, Subpart B, Servicing of Motor Vehicle Air Conditioners.

9. Risk Management Provisions

a. The permittee shall comply with all applicable requirements of 401 KAR Chapter 68, Chemical Accident Prevention, which incorporates by reference 40 CFR Part 68, Risk Management Plan provisions. If required, the permittee shall comply with the Risk Management Program and submit a Risk Management Plan to:

RMP Reporting Center

P.O. Box 1515 Lanham-Seabrook, MD 20703-1515.

b. If requested, submit additional relevant information to the Division or the U.S. EPA.

Permit Number: V-09-006 Page 97 of 101 SECTION H-ALTERNATE OPERATING SENERIOS Not Applicable

Permit Number: V-09-006 Page 98 of 101 SECTION I-COMPLIANCE SCHEDULE Not Applicable

Permit Number: V-09-006 Page 99 of 101 SECTION J- ACID RAIN TITLE IV PHASE II ACID RAIN

ACID RAIN PERMIT CONTENTS

1) Statement of Basis

2) SO2 allowances allocated under this permit and NOx requirements for each affected

unit.

3) Comments, notes and justifications regarding permit decisions and changes made to the permit application forms during the review process, and any additional requirements or conditions.

4) The permit application submitted for this source. The owners and operators of the

source must comply with the standard requirements and special provisions set forth in the Phase II Application and the Phase II NOx Compliance Plan.

5) Summary of Actions

1) Statement of Basis:

Statutory and Regulatory Authorities: For emission units HRSG1 and HRSG2, the Energy and Environment Cabinet, Division of Air Quality issues this permit pursuant to 401 KAR 52:020, Title V permits, 401 KAR 52:060, Acid rain permits, and 40 CFR 76 and in accordance to KRS 224.10-100 and Titles IV and V of the Clean Air Act.

PERMIT (Conditions)

Plant Name: Cash Creek Generating Station Affected Unit: HRSG1, HRSG2

Permit Number: V-09-006 Page 100 of 101 SECTION J- ACID RAIN (CONTINUED)

PERMIT (Conditions) 2. SO2 Allowance Allocations and NOx Requirements for the affected unit:

SO2 Allowances Year

2006 2007 2008 2009 2010

Tables 2, 3 or 4 of 40 CFR Part 73

0* 0* 0* 0* 0*

NOx Requirements NOx Limits N/A**

* For newly constructed units, there are no SO2 allowances per USEPA Acid Rain Program

** These units currently do not have applicable NOx limits set by 40 CFR, part 76.

Limits will be set by 40 CFR 76 upon construction. 3. Comments, Notes, and Justifications:

(1) The two (2) combined cycle combustion turbines with HRSG, units HRSG1 and HRSG2 will be constructed after the SO2 allocation date; therefore these units will have no SO2 allowances allocated by U.S. EPA and must obtain allowances.

(2) The two (2) combined cycle combustion turbines, emission units HRSG1 and

HRSG2, do not have applicable NOx limits set by 40 CFR 76. 4. Permit Application:

The Phase II Permit Application is a part of this permit and the source must comply with the standard requirements and special provisions set forth in the Phase II Application.

5. Summary of Actions:

Previous Action: (1) Draft Title V, Permit V-07-017 with Acid Rain Permit was advertised for public

comments.

(2) Final Title V, Permit V-07-017 with Acid Rain Permit issued January 18, 2008.

Present Action: (1) Final Title V, Permit V-09-006 with Acid Rain Permit, issued May 5, 2010.

Permit Number: V-09-006 Page 101 of 101 SECTION K- NOX BUDGET 1. Statement of Basis

Statutory and Regulatory Authorities: In accordance with KRS 224.10-100, the Kentucky Energy and Environment Cabinet issues this permit pursuant to 401 KAR 52:020 Title V permits, 401 KAR 51:210, CAIR NOx Annual Trading Program and 401 KAR 51:220, CAIR NOx Ozone Trading Program, and 401 KAR 51:230, CAIR SO2 Trading Program.

2. CAIR Application

The CAIR application for two (2) electrical generating units was submitted to the Division and received on February 11, 2009. Requirements contained in that application are hereby incorporated into and made part of this CAIR Permit. Pursuant to 401 KAR 52:020, Section 3, the source shall operate in compliance with those requirements.

3. Comments, notes, justifications regarding permit decisions and changes made to

the permit application forms during the review process, and any additional requirements or conditions.

The Affected units are two (2) Integrated Combined Cycle Combustion Turbines with HRSG, emission units HRSG1 and HRSG2 used for electrical power production. Each unit has a nameplate capacity to generate greater than 25 MW of electricity, which is offered for sale. The units use natural gas as fuel source, and are authorized as base load electric generating units.

4. Summary of Actions

The CAIR Permit is being issued as part of the Title V permit for this source. Public,

affected states, and U.S. EPA review will follow procedures specified in 401 KAR 52:100.