temporary permit - des.state.nh.us

State of New Hampshire Department of Environmental Services Air Resources Division

Temporary Permit Facility ID No: 3300700093 Permit No: FP-T-0137 County: Coos Date Issued: February 1, 2006 This certifies that:

Groveton Paper Board, Inc. has been granted a Temporary Permit for:

Combustion Turbine #2 and the Steam and Power Plant 19 Main Street, Groveton, NH

which includes devices that emit air pollutants into the ambient air as set forth in the permit application filed with the New Hampshire Department of Environmental Services, Air Resources Division (Division) on October 4, 2005, in accordance with RSA 125-C of the New Hampshire Laws. Request for permit renewal is due to the Division at least 90 days prior to expiration of this permit and must be accompanied by the appropriate permit application forms. This permit is valid upon issuance and expires August 31, 2007.

This permit is valid provided that each device is operated in accordance with all the legally enforceable conditions specified within this permit.

I. The Owner or Operator shall be subject to all applicable state and federal air pollution control regulations, including (but not limited to):

A. The New Hampshire Code of Administrative Rules Env-A 100 et seq., New Hampshire Rules Governing the Control of Air Pollution; and

B. The Code of Federal Regulations (CFR), 40 CFR Part 60, Subpart Dc, Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units and 40 CFR Part 60, Subpart GG, Standards of Performance for Stationary Gas Turbines.

II. All equipment, facilities and systems installed and used to achieve compliance with the terms and conditions of this permit shall at all times be maintained in good working order and be operated as efficiently as possible to minimize air pollutant emissions.

SEE ATTACHED SHEETS FOR ADDITIONAL PERMIT CONDITIONS

The Owner or Operator of the devices covered by this permit shall submit an application for a permit amendment to the Division at least 90 days prior to the implementation of any proposed change to the physical structure or operation of the devices covered by this permit which increases the amount of a specific air pollutant currently emitted by such devices or which results in the emission of any regulated air pollutant currently not emitted by such devices. The change shall not take place until a new permit application is submitted and acted upon by the Director pursuant to Env-600.

This permit (or a copy) should be appropriately displayed near the devices for which it is issued.

_______________________________

Director Air Resources Division

February 1, 2006 FP-T-0137 of 27 Groveton Paper Board, Inc.

Combustion Turbine #2 and the Steam and Power Plant

Abbreviations and Acronyms AAL Ambient Air Limit min Minute acf actual cubic foot MM million AGL above ground level MW megawatt Btu British thermal units NOx Oxides of Nitrogen CFR Code of Federal Regulations PM10 Particulate Matter < 10 microns CO Carbon Monoxide RACT Reasonably Available Control Technology CT Combustion Turbine RTAP Regulated Toxic Air Pollutant gal Gallon scf standard cubic foot HAP Hazardous Air Pollutant SO2 Sulfur Dioxide hr Hour TSP Total Suspended Particulate HRSG Heat Recovery Steam Generator tpy tons per consecutive 12-month period kW Kilowatt USEPA United States Environmental Protection Agency lb Pound VOC Volatile Organic Compound LNB Low NOx Burner III. Facility Description of Operations

Groveton Paper Board, Inc. (GPB) is a stand-alone semi-chemical, integrated pulp and paper mill producing up to 550 tons per day of corrugating medium at its manufacturing facility located in Groveton, NH. The GPB site is also occupied by Wausau Papers of New Hampshire Inc., which manufactures specialty papers derived from market pulp. The two facilities are not under common control and are considered separate and distinct facilities for air pollution control purposes. GPB owns and operates two boilers (Boilers #4 and #5) and two Combustion Turbines (CT) with Heat Recovery Steam Generators (HRSG). The two boilers each have a gross heat input rating of 107 mmBtu/hr and are capable of firing either natural gas or No. 6 fuel oil with a maximum sulfur content of 0.5% sulfur by weight. During calendar years 2000 and 2001, GPB installed two co-generation systems. Each co-generation system is rated at 5.5-6.0 Megawatts. The two CTs are rated at a maximum of 73.0 mmBtu/hr gross heat input rate while firing natural gas at 0 degrees F and 70.4 mmBtu/hr gross heat input rate while firing No. 2 fuel oil (both ratings at O degrees F). Each of the two HRSG is equipped with a duct burner rated at 84.5 mmBtu/hr gross heat input while firing natural gas only. Each HRSG Unit is capable of operating on fresh air makeup in place of heated combustion gases from the CT when a CT is not available for service. In these instances with a CT out of service, each duct burner is capable of firing natural gas at a gross heat input rate of 126.9 mmBtu/hr. Steam is generated to supply process and space heating needs by extracting heat from each of the combustion turbine exhaust gases into a heat recovery boiler. There will be supplementary gas-only firing in the duct leading to each heat recovery boiler from the combustion turbine. All steam and electricity generated by the new equipment will be used by GPB or sold off site. Exhaust gas is vented to the atmosphere from the heat recovery boiler via a new, dedicated stack. In the event that steam requirements are low or if there is a boiler malfunction, the combustion turbine exhaust gas may be directed to a by-pass duct connected to a stack separate from the main Turbine/HRSG main stack. This Temporary Permit is being issued for the swap out of the gas producer and power turbine modular components on CT#2. Groveton Paper Board had to perform an unscheduled outage for routine maintenance to be conducted on this unit. Solar, the equipment manufacturer, has an exchange fleet of gas producer and power turbine modular components and does an overhaul of these units at operation levels of about 30,000 hours to maintain the life expectancy of the unit. DES reviewed the total



maintenance cost of the replacement unit and determined that it was not reconstructed or modified and that there is no increase in hourly or annual emissions from the replacement unit, as evidenced in stack testing completed on October 10, 2005. Hence, CT#2 is an existing unit, that has not been modified or reconstructed, and is not subject to any applicable requirements contained in 40 CFR 63 Subpart YYYY (National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines) at this time. In the event that CT#1 or CT#2 become a reconstructed source in the future, it will become subject to 40 CFR 63 Subpart YYYY.

IV. Permitted Devices

This permit covers the devices identified in Table 1 and replaces permits previously issued for these devices:

Table 1 - Device Identification Device Manufacturer

Model No. Serial No.

Install Date Nameplate Rating in MMBtu/hr Permitted Fuel Type(s)1

Combustion Turbine #1 (CT #1)

Solar Taurus 60S 0207T

2000 02/27/20042

73.0 MMBtu/hr at 0 deg F on Natural gas 70.4 MMBtu/hr at 0 deg F on No. 2 fuel oil Natural gas - equivalent to 73,000 scf/hr No. 2 fuel oil – equivalent to 495.8 gal/hr

Combustion Turbine #2 (CT #2)

Solar Taurus 60S 0012T

2000 10/10/20053

73.0 MMBtu/hr at 0 deg F on Natural gas 70.4 MMBtu/hr at 0 deg F on No. 2 fuel oil Natural gas - equivalent to 73,000 scf/hr No. 2 fuel oil – equivalent to 495.8 gal/hr

Heat Recovery Steam Generator #1 (HRSG #1)

Not available 2000 84.5 MMBtu/hr with Combustion Turbine #1 in service 126.9 MMBtu/hr without Combustion Turbine #1 in service Natural gas – equivalent to 84,500 scf/hr with Combustion Turbine #1 in service Natural gas – equivalent to 126,900 scf/hr with Combustion Turbine #1 out of service

Heat Recovery Steam Generator #2 (HRSG #2)

Not available 2000 84.5 MMBtu/hr with Combustion Turbine #2 in service 126.9 MMBtu/hr without Combustion Turbine #2 in service Natural gas – equivalent to 84,500 scf/hr with Combustion Turbine #2 in service Natural gas – equivalent to 126,900 scf/hr with Combustion Turbine #2 out of service

Boiler #4 Combustion Engineering VP12W Not available

1966 LNB 1995

107.0 MMBtu/hr Natural gas – equivalent to 107,000 scf/hr No. 6 fuel oil – equivalent to 713 gal/hr

Boiler #5 Combustion Engineering VP12W Not available

1967 LNB 1995

107.0 MMBtu/hr Natural gas – equivalent to 107,000 scf/hr No. 6 fuel oil – equivalent to 713 gal/hr

1 The hourly fuel rates presented in Table 1 are set assuming a heating value of 1,000 Btu/scf for natural gas, 142,000 Btu/gal for No. 2 fuel oil, and 150,000 Btu/gal for No. 6 fuel oil. 2 Combustion Turbine #1 had a like-kind replacement of the gas producer and power turbine modular components on February 27, 2004 due to an unexpected bad bearing. The replacement unit was manufactured in 1994. 3 Combustion Turbine #2 had a like-kind replacement of the gas producer and power turbine modular components on October 10, 2005 due to an unexpected bad bearing. The replacement unit was manufactured on November 27, 1990.



V. Stack Criteria

A. The following devices at the Facility shall have exhaust stacks that discharge vertically, without obstruction, and meet the criteria in Table 2:

Table 2 - Stack Criteria Device/Stack # Minimum Height

(ft AGL) Maximum Exit Diameter (ft)

Boilers #4 & #5 (Common Stack) 135.0 6.0 CT/HRSG #1 & CT/HRSG #2 (Combined Stack)

135.0 5.58

B. Air dispersion modeling conducted by the facility for a separate turbine bypass exhaust discharging

at 65 feet elevation and 4 feet in diameter for each of the turbines indicates this activity must be limited to less than 3 hours per 24 hour period, which would be well within range of a normal startup or shutdown of the turbines. This limit only applies when both GPB Turbines are running on oil at the same time and Boilers 1, 4, and 5 are running on No. 6 fuel oil at maximum load.

C. Preauthorized changes to the state-only requirements pertaining to stack parameters (set forth in this permit), shall be permitted only when an air quality impact analysis which meets the criteria of Env-A 606 is performed either by the facility or the DES (if requested by the facility in writing) in accordance with the “DES Policy and Procedure for Air Quality Impact Modeling”. All air modeling data shall be kept on file at the facility for review by the DES upon request.

(This space left intentionally blank.)



VI. Federally Enforceable Operational and Emission Limitations

The Permittee shall be subject to the Federally enforceable operational and emission limitations identified in Tables 3a and 3b, and Federally enforceable alternative operating scenarios listed in Table 3c below:

Table 3a – Federally Enforceable Operational and Emission Limitations

Item # Applicable Requirement Applicable

Emission Unit Regulatory Cite

1. The sulfur content of No. 2 oil shall not exceed 0.40 percent sulfur by weight. Facility Wide Env-A 1604.01(a) & Temporary

Permit FP-T-0051

2. In accordance with the air dispersion modeling analysis conducted for the facility, the sulfur content of No. 6 fuel oil shall not exceed 0.5% sulfur by weight, facility wide.

Facility Wide Env-A 606.04, RSA 125-C:11, & RSA 125-C:6

3. The sulfur content of natural gas shall not exceed 5 grains of sulfur per 100 cubic feet of gas, calculated as hydrogen sulfide at standard temperature and pressure.

Facility Wide 40 CFR 524

4. Days of operation of Combustion Turbines #1 & #2, HRSG Units #1 & #2, and Boilers #4 & #5 shall be limited to 363 days per consecutive 365-day period.

CT #1 & #2, HRSG Units #1 & #2, &

Boilers #4 & #5

Temporary Permit

FP-T-0051

5. GPB shall be limited to less than 3 consecutive hours per 24-hour period when both Turbines are burning No. 2 fuel oil at the same time, while discharging through their bypass stacks. This limit applies only if Boilers 1, 4, and 5 are burning No. 6 fuel oil at maximum load during the same time period.

CT #1 & CT #2

Env-A 606.04, RSA 125-C:11, & RSA 125-C:6

6. The opacity of emissions from the Combustion Turbine/HRSG exhausts and Boilers #4 & #5 shall not exceed 20% for any consecutive 6-minute period in any 60 minute period.

CT/HRSG Units #1 & #2 & Boilers #4

& #5

Env-A 2003.02 & Temporary

Permit FP-T-0051

4 Env-A 402.03, effective on December 27, 1990, was adopted as part of the State Implementation Plan (SIP) on September 14, 1992 and is still considered federally enforceable until such time as the SIP is amended and approved by the EPA.






7. The Combustion Turbine/HRSG exhausts and Boilers #4 & #5 are allowed the following exemptions from the 20% opacity standard listed above:

a) The average opacity shall be allowed to be in excess of those standards specified in Env-A 2003.01 and Env-A 2003.02 for one period of 6 continuous minutes in any 60 minute period during startup, shutdown, malfunction, soot blowing, grate cleaning, and cleaning of fires.

b) Exceedances of the opacity standard shall not be considered violations of this part if the source demonstrates to the division that such exceedances were the result of the adherence to good boiler operating practices which, in the long term, results in the most efficient or safe operation of the boiler.

c) Examples of activities that may cause exceedances of the opacity standard that shall not be considered violations include the following: 1. Continuous soot blowing of the entire boiler tube sections over regular

time intervals as determined by the operator and in conformance with good boiler operating practice; and

2. Cold startup of a boiler over a continuous period of time resulting in efficient heat-up and stabilization of its operation and the expeditious achievement of normal operation of the unit.

d) Exceedances of the opacity standard shall not be considered violations of this part if the source demonstrates to the division that such exceedances were the result of the occurrence of an unplanned incident in which the opacity exceedance was beyond the control of the operator and in response to such an incident, the operator took appropriate steps in conformance with good boiler operating practice to eliminate the excess opacity as quickly as possible.


& #5

Env-A 2003.04(c)-(f) &

Temporary Permit

FP-T-0051

8. The maximum particulate matter emission rate for each of the Combustion Turbine/HRSG exhausts and Boilers #4 & #5 shall not be greater than 0.15 lb/mmBtu. In that the facility is opting out of NSR and NA applicability, it has accepted lower particulate matter emissions limits, which are presented in Tables 3a and 3b. Exceedances of these emissions limits constitute a permit violation.


& #5


Permit FP-T-0051






9. The Combustion Turbine emissions shall be limited to less than the following NOx limits, whichever is more stringent of a) or b):

a) STD = 0.0150 * (14.4/Y) + F (percent by volume at 15% oxygen, dry basis)

Where:

Y = manufacturer’s rated heat rate at peak load (kilojoules per watt hour), or actual measured heat rate based on lower heating value of fuel as measured at actual peak load for the facility. Y can not exceed 14.4 kilojoules per watt hour.

F = NOx emission allowance (percent by volume) from Table 4 below:

Table 4 – F Factors

Fuel Bound Nitrogen (percent by weight) F (NOx, percent by volume) N less than or equal to 0.015 0 0.015 < N less than or equal to 0.1 0.04(N) 0.1 < N less than or equal to 0.25 0.004 + 0.0067(N – 0.1) N > 0.25 0.005

and/or

b) 25 ppmvd, corrected to 15% oxygen or 0.092 lb/mmBtu when firing natural gas (NOx RACT Requirements from Env-A 1211.06(d)) OR 65 ppmvd corrected to 15% oxygen when firing No. 2 fuel oil (NOx RACT Requirements from Env-A 1211.06(c)(1)b.).

CT #1 & CT #2

40 CFR 60 Subpart GG

Section 60.332

10. The Combustion Turbine emissions shall be limited to less than 0.015 percent sulfur dioxide by volume at 15 percent oxygen, on a dry basis when firing natural gas.

CT #1 & CT #2

40 CFR 60 Subpart GG

Section 60.333

11. For the purposes of NOx RACT, the Combustion Turbines #1 & #2 shall meet the emissions limits contained in Env-A 1211.06(c)(1)b.2. and Env-A 1211.06(d) [65 ppmvd corrected to 15% O2 when firing No. 2 fuel oil; 25 ppmvd corrected to 15% O2 or 0.092 lb/mmBtu when firing natural gas]. The facility may use discrete emissions reduction credits generated while burning natural gas to comply with the 65 ppmdv NOx RACT limit for firing oil if necessary. GPB shall determine compliance with the NOx RACT emissions limitations by conducting NOx stack testing once every three years after the initial performance test required for each of the Combustion Turbines following the test methods contained in Env-A 802.

CT #1 & CT #2

Env-A 1211.06(c)(1)b.2.

& Env-A

1211.06(d)






12. For the purposes of NOx RACT, emissions from the HRSG Units #1 & #2 shall be less than 0.10 lb/mmBtu, based on an hourly average, or the duct burners on HRSG Units #1 & #2 must be DES certified Low NOx Burners as stated in Env-A 1211.05(c)(3)a.1. and 2. GPB shall determine compliance with the NOx RACT emissions limitations by conducting NOx stack testing once every three years after the initial performance test required for each of the HRSG Units following the test methods contained in Env-A 802. GPB may use discrete emissions reductions credits in accordance with Env-A 3100 for purposes of compliance with NOx RACT requirements for the HRSG Units #1 & #2 for when they are fresh air firing without their corresponding Combustion Turbine in operation.

HRSG Units #1 & #2

Env-A 1211.05(c)(3)a.1.

& 2.

13. For the purposes of NOx RACT, emissions from Boilers #4 & #5 shall be controlled via use of DES approved Low NOx Burners and meet the emissions limits specified in Table 2. GPB shall determine compliance with these NOx RACT emissions limitations by conducting stack testing for NOx once every three years after the initial performance test required for each of the Boilers following the test methods contained in Env-A 802.

Boilers #4 & #5

Env-A 1211.05(d)(3)a.2.




Table 3b – Emissions Limitations Device Oxides of Nitrogen

(NOx) Sulfur Dioxide

(SO2) Carbon

Monoxide (CO) Particulate

Matter (PM10) Non-Exempt

Volatile Organic Compounds (NEVOC)

Comb. Turb. #1

25 ppmvd (gas) at 15% O2 or 0.092 lb/MMBtu 65 ppmvd (oil) at 15% O2

0.0136 lb/MMBtu (gas) 0.406 lb/MMBtu (oil)




HRSG #1 0.10 lb/MMBtu (gas)

0.0136 lb/MMBtu (gas)




HRSG #1 Fresh Air Firing

0.10 lb/MMBtu 12.69 lb/hr (gas)





CT#1(oil)& HRSG#1 (gas) Combined

0.170 lb/MMBtu 26.26 lb/hr





CT#1(gas) & HRSG#1 (gas) Combined






Comb. Turb. #2

25 ppmvd (gas) at 15% O2 or 0.092 lb/MMBtu 65 ppmvd (oil) at 15% O2





HRSG #2 0.100 lb/MMBtu (gas)





HRSG #2 Fresh Air Firing






CT#2 (oil) & HRSG#2 (gas) Combined






CT#2(gas) & HRSG#2 (gas) Combined






Boiler #4 0.100 lb/MMBtu (gas) 0.390 lb/MMBtu (oil)


0.200 lb/MMBtu (gas & oil)



Boiler #5 0.100 lb/MMBtu (gas) 0.390 lb/MMBtu (oil)





Total Steam Plant Cap

218.07 tons per consecutive 12 month period







Table 3b Notes: 1. CO, PM10, and NEVOC emissions limits (in lb/MMBtu) for the duct burners in the HRSG Units are

based on vendor guarantees using higher heating values. SO2 emissions limits (in lb/MMBtu) for the duct burners in the HRSG Units are based on the State Implementation Plan (SIP) limit of 5 grains sulfur per 100 cubic feet of natural gas and 0.4% sulfur in No. 2 fuel oil. NOx emission limits (in lb/MMBtu) for the duct burners in the HRSG Units are based on the NOx RACT limit of 0.10 lb/MMBtu.

2. Emissions limits (in lb/MMBtu) are based on the higher value of the two potential Combustion Turbine

models (GE PGT-5B/1 or Solar Taurus 60S) vendor guarantees, which are based on higher heating value. SO2 emission limits (in lb/MMBtu) for the Combustion Turbines while firing gas or oil are based on the SIP limit of 5 grains of sulfur per 100 cubic feet of natural gas and 0.4% sulfur in No. 2 fuel oil. The NOx emission limits for the Turbines while firing gas are based on the NOx RACT limit of 25 ppmvd, corrected to 15% O2 or 0.092 lb/MMBtu. The facility may use discrete emissions reductions credits generated while burning natural gas to bring it in compliance with the 65 ppmvd NOx RACT limit for while firing fuel oil. CO and VOC emission limits while firing gas were Solar guarantees, while PM10 limits were selected from GE guarantees. CO, PM10, and NEVOC limits for Turbines firing fuel oil were from Solar guarantees.

3. Combined Combustion Turbine/HRSG Unit emission limits (in lb/hr) were derived from multiplying the

maximum heat input rate (MMBtu/hr) by the emission factor (lb/MMBtu) for the Combustion Turbine and HRSG Unit duct burner separately and summing up the result. Combined Combustion Turbine/HRSG Unit emission limits (in lb/MMBtu) are from taking the lb/hr emissions limit and dividing by the combined maximum heat input rate of the Combustion Turbine plus the HRSG Unit duct burner. The combined NOx lb/MMBtu emissions limits for the Combustion Turbine firing oil with the HRSG Unit firing natural gas is based on using a NOx emissions limit of 65 ppm while firing oil in the Turbine and 0.100 lb/MMBtu while firing natural gas in the HRSG Unit to reflect vendor guarantees while burning oil in the Combustion Turbine and for establishing limits while conducting the performance testing of the two units in operation together.




Table 3c – Federally Enforceable Alternative Operating Scenarios Scenario Name Scenario Description Groveton1 Normal Operating Scenario (Interruptible Gas/Oil)

a) Both turbines firing No. 2 fuel oil at maximum capacity, 70.3 MMBtu/hr gross heat input each, for up to 75 days in a consecutive 365-day period and both turbines firing natural gas at maximum capacity, 65.2 MMBtu/hr gross heat input each, for up to 288 days in a consecutive 365-day period.

b) Both duct burners would be firing natural gas only, at maximum capacity, 84.5 MMBtu/hr gross heat input each, for up to 363 days in a consecutive 365-day period.

Groveton2 Normal Operating Scenario (Gas only) a) Both turbines firing natural gas only at maximum capacity, 65.2 MMBtu/hr gross heat input each, for up to 363

days in a consecutive-365 day period. b) Both duct burners would be firing natural gas only, at maximum capacity, 84.5 MMBtu/hr gross heat input

each, for up to 363 days in a consecutive 365-day period. Groveton3 Boiler Backup Scenario (Turbines and HRSG’s Unavailable)

a) Boilers #4 & #5 firing No. 6 fuel oil with a maximum sulfur content of 0.5% by weight at maximum capacity, 107 MMBtu/hr gross heat input rate each for up to 102.5 days in a consecutive 365-day period and Boilers #4 & #5 firing natural gas at maximum capacity, 107 MMBtu/hr gross heat input rate each for up to 260.5 days in a consecutive 365-day period.

Groveton4 Boiler Backup Scenario (Oil Only) a) Boilers #4 & #5 firing No. 6 fuel oil with a maximum sulfur content of 0.5% by weight at maximum capacity,

107 MMBtu/hr gross heat input rate each for up to 120 days in a consecutive 365-day period. b) Both Turbines and HRSG Units down.

Groveton5 Backup Scenario (One turbine and one HRSG Unit out of service) a) Boiler #4 or Boiler #5 firing No. 6 fuel oil with a maximum sulfur content of 0.5% by weight at maximum

capacity, 107 MMBtu/hr gross heat input rate for up to 112 days in a consecutive 365-day period and firing natural gas at maximum capacity, 107 MMBtu/hr gross heat input rate for up to 251 days in a consecutive 365-day period.

b) One turbine firing No. 2 fuel oil at maximum capacity, 70.3 MMBtu/hr gross heat input rate for up to 112 days in a consecutive 365-day period and firing natural gas at maximum capacity, 65.2 MMBtu/hr gross heat input rate for up to 251 days in a consecutive 365-day period.

c) One duct burner firing natural gas at maximum capacity, 84.5 MMBtu/hr gross heat input rate for up to 363 days in a consecutive 365-day period.

Groveton6 Maximized Fuel Use of Natural Gas Scenario a) Both turbines firing natural gas at maximum capacity, 65.2 MMBtu/hr gross heat input rate for up to 363 days

in a consecutive 365-day period b) Both duct burners would be firing natural gas only, at maximum capacity, 84.5 MMBtu/hr gross heat input

each, for up to 363 days in a consecutive 365-day period. c) Boilers #4 & #5 firing natural gas at maximum capacity, 107 MMBtu/hr each for up to 118 days in a

consecutive 365 day period. Groveton7 Maximum Natural Gas to Turbines/HRSG’s and No. 6 Fuel Oil to Boilers Scenario

a) Boilers #4 & #5 firing No. 6 fuel oil with a maximum sulfur content of 0.5% by weight at maximum capacity, 107 MMBtu/hr gross heat input rate each for up to 20 days each in a consecutive 365 day period.

b) Turbines firing natural gas at maximum capacity, 65.2 MMBtu/hr gross heat input rate each for up to 363 days in a consecutive 365-day period.

c) Both duct burners would be firing natural gas only, at maximum capacity, 84.5 MMBtu/hr gross heat input each, for up to 363 days in a consecutive 365-day period.



Table 3c – Federally Enforceable Alternative Operating Scenarios Scenario Name Scenario Description Groveton8 Additional operating scenarios are implicitly allowed, since their emissions are lower than those listed in Groveton1

through Groveton7 above, and not NSR or NA limited. These scenarios include, but are not limited to: a) One or both HRSGs operating at maximum rates, with one or both Turbines shut down. b) One or both HRSGs operating at maximum firing rates with both turbines shut down. c) Other combinations of all six combustion devices operating at varying firing rates and operating days, provided

that the annual steam and power plant emissions listed in Tables 3a and 3b are not exceeded. d) Based on performance testing of the combustion turbines and heat recovery steam generating units, the days of

operation while firing fuel oil or natural gas in the above alternate operating scenarios may be changed via a permit modification in accordance with Env-A 612, provided that the annual steam and power plant emissions listed in Tables 3a and 3b are not exceeded.




VII. Monitoring and Testing Requirements

The Permittee is subject to the monitoring and testing requirements as contained in Table 4 below:

Table 4 – Monitoring/Testing Requirements

Item # Parameter Method of Compliance Frequency

of Method Device Regulatory Cite

1. Fuel Monitoring

For the purpose of monitoring compliance with emissions limitations and facility wide record keeping requirements of this permit, the owner or operator shall install and operate the following monitoring devices:

a) Natural gas and No. 2 fuel oil flow meters and totalizers shall be installed and continuously operated on the natural gas and No. 2 fuel oil inlet lines to each of the Combustion Turbines to measure the hourly and daily total consumption of natural gas and No. 2 fuel oil for each of the Combustion Turbines.

b) Natural gas and No. 6 fuel oil flow meters and totalizers shall be installed and continuously operated on the natural gas and No. 6 fuel oil inlet lines to each of the Boilers to measure the hourly and daily total consumption of natural gas and No. 6 fuel oil for each of the Boilers.

c) Natural gas flow meters and totalizers shall be installed and continuously operated on the natural gas inlet lines to each of the duct burners on each of the HRSG Units to measure the hourly and daily total consumption of natural gas for each of the HRSG Units.

d) GPB shall calibrate the flow meters and totalizers in accordance with the manufacturer's and/or supplier's recommendations.

e) GPB shall record the daily natural gas and No. 2 fuel oil usage for each of the Combustion Turbines in MMCF/day or gal/day, daily natural gas usage for each of the duct burners in MMCF/day, and daily natural gas and No. 6 fuel oil usage for each of the Boilers in MMCF/day and gal/day.

f) GPB shall also monitor hours of operation each day for each of these fuel burning devices.

Continuous & Daily

Total Consumption

CT #1 & #2, HRSG Units #1 &

#2, & Boilers #4

& #5

Temporary Permit

FP-T-0098






2. NOx RACT Compliance

Testing

The owner or operator shall determine compliance with NOx RACT emissions limitations and NOx emissions limitations in Tables 3a and 3b by conducting stack testing for NOx once every three years for the combustion devices listed in Table 1 following the test methods in Env-A 803.02(d) through (f) as applicable.

a) Boilers #4 & #5 shall be tested separately while combusting natural gas or No. 6 fuel oil. If the facility does not burn No. 6 fuel oil or natural gas during the three year period after the most recent NOx RACT compliance test conducted while burning No. 6 fuel oil or natural gas, the facility must conduct a NOx RACT compliance test while burning No. 6 fuel oil or natural gas within 60 days of initial firing of No. 6 fuel oil or natural gas in Boilers #4 & #5. If the Permittee uses this option, it must provide DES with a list of maintenance activities performed on the Boiler with associated costs along with the replacement cost of the Boiler to demonstrate the Boiler was not “reconstructed”.

b) GPB is required to conduct NOx RACT testing on each Combustion Turbine without its corresponding HRSG in service separately for natural gas firing and while firing No. 2 fuel oil, and furnish the results of such testing to the DES within 30 days after completion of testing. GPB is also required to conduct performance tests on each HRSG Unit firing natural gas at full load without its corresponding combustion turbine in service. In addition, GPB will conduct a performance test on the combined operation of the Combustion Turbine and corresponding HRSG unit at maximum operating capacity for both cases of operation, i.e. Turbine firing No. 2 fuel oil/HRSG firing natural gas AND Turbine/HRSG both firing natural gas.

Once every three years, the first test shall occur

no later than three years

after the date of the initial compliance

test

Boilers #4 & #5, CT #1 & #2,

and HRSG Units #1 &

#2

Env-A 803.02(d)-(f)






3. Stack Testing Procedural

Requirements

a) Compliance stack testing shall be planned and carried out at the frequency specified. A compliance stack emissions test shall conform to the general requirements of 40 CFR 60.8(a), (b), (d)-(f) and the test methods contained in 40 CFR 60 Appendix A, 40 CFR 51 Appendix M, or any other EPA-promulgated stack test method. The pre-test protocol must be submitted by the facility at least 30 days prior to the commencement of testing. The pre-test report shall contain the following information: 1. Calibration methods and sample data sheets; 2. Description of the test methods to be used; 3. Pre-test preparation procedures; 4. Sample collection and analysis methods; 5. Process data to be collected; and 6. Complete test program description.

b) At least 15 days prior to the test date, the facility and any contractor that the facility retains for performance of the test, shall participate in pre-test conference with a Division representative.

c) Emission testing shall be carried out under the observation of a Division representative. Upon commencement of any performance test, the performance test shall not be aborted unless approved by DES.

d) The Permittee shall submit stack test report to DES within 60 days of completion of the actual testing.

When testing is conducted

Facility Wide

Env-A 802.02(a) (new rule)

Env-A 802.02 (old rule)

Env-A 802.04 (new rule)

Env-A 806.01(a) (old

rule) & Temporary

Permit FP-T-0051





Requirements

The following test methods or Division approved alternatives shall be used:

a) Method 7, 7A, 7C, 7D, or 7E, 40 CFR 60, Appendix A to determine NOx concentrations in stack gases from applicable sources

b) Method 1 or 2, 40 CFR 60, Appendix A to determine the exit velocity of stack gases;

c) Method 3 or 3A, 40 CFR 60, Appendix A to determine carbon dioxide, oxygen, excess air, and molecular weight (dry basis) of stack gases;

d) Method 4, 40 CFR 60, Appendix A to determine moisture content (volume fraction of water vapor) of stack gases;

e) Method 10, 40 CFR 60, Appendix A to determine CO emissions of stack gases;

f) Method 9, 40 CFR 60, Appendix A to determine opacity of stack gases; and

g) The owner or operator may use Method 20, 40 CFR 60, Appendix A to determine NOx concentrations in stationary gas turbine exhaust gases in lieu of Method 7.


Facility Wide

Env-A 803.02(e) & (f) (new rule) & Temporary

Permit FP-T-0051







Requirements

Any compliance stack test results determined following 40 CFR 60 paragraph 60.8, which show violations of any permit requirement shall be considered violations of this permit.


Facility Wide

Temporary Permit

FP-T-0051

6. Custom Fuel Monitoring Schedule –

Pipeline Natural Gas

The owner or operator must conduct monitoring of nitrogen and sulfur content of pipeline natural gas in accordance with Section 60.334(b)(2) and 60.334(h)(3) of 40 CFR 60, Subpart GG. The owner or operator has elected for a custom schedule approved by EPA Region 1. The requirements contained in the custom schedule for natural gas nitrogen and sulfur content monitoring were updated to reflect the July 8, 2004 addition of Section 60.334(h)(3) and are listed below:

a) No monitoring of fuel nitrogen is required so long as the facility is supplied with solely pipeline-quality natural gas or LNG.

b) No monitoring of sulfur content is required for pipeline natural gas that meets the definition of natural gas in 40 CFR 60 Section 60.331(u), i.e., is less than 20 grains of sulfur per 100 cubic feet of natural gas. Pipeline natural gas supplied to GPB is below 5 grains of sulfur per 100 cubic feet.

As stated CT #1 & #2 40 CFR 60 Subpart GG

Sections 60.334(b)(2), 60.334(h)(3), & Temporary

Permit FP-T-0051

7. Monitoring Electrical

Power Generation

The owner or operator shall monitor electrical power generation from its Combustion Turbines in accordance with either Env-A 3705.01(b)(1) or (2). All power generation monitors shall be operated and maintained in accordance with the operating and maintenance procedures specified by the manufacturer.

Continuous CT #1 & #2 Env-A 3705.01(b) &

Temporary Permit

FP-T-0098

8. Fuel Sulfur Content

Verification

The Owner or Operator shall conduct testing using the appropriate ASTM methods or retain certified delivery tickets which state the weight percent of sulfur for each delivery of fuel oil to determine compliance with the sulfur content limitation provisions in this permit for liquid fuels in order to meet the reporting requirements specified in Env-A 900.

For each delivery

Facility Wide

Env-A 809 (old rule) &

Env-A 806.05 (new rule) Federally

Enforceable




VIII. Recordkeeping Requirements

The Permittee shall be subject to the recordkeeping requirements identified in Table 5 below:

Table 5 – Applicable Recordkeeping Requirements

Item # Applicable Recordkeeping Requirement Frequency of

Recordkeeping

Applicable Emission

Unit

Regulatory Cite.

1. Retention of Records

The owner or operator shall retain records of all required monitoring data, recordkeeping and reporting requirements, and support information for a period of at least 5 years from the date of origination.

Retain for a minimum of 5

years

Facility Wide

Env-A 902.01 & 40 CFR

70.6(a)(3)(ii)(B)

2. VOC Emission Statements Recordkeeping Requirements

The Owner or Operator shall record the following information:

a) Identification of each VOC-emitting process or device; b) The operating schedule during the high ozone season (June 1

through August 31) for each VOC-emitting process or device identified in a) above, including: 1. Hours of operation per calendar month; and 2. Days of operation per calendar month.

c) The following VOC emission data: 1. Actual VOC emissions from each VOC-emitting process or

device identified in a) above, for each calendar year, in tons and a typical high ozone season day during the calendar year, in pounds per day; and

2. The emission factors and the origin of the emission factors used to calculate the VOC emissions.

Monthly and annually

Facility Wide

Env-A 901.06 (old rule) &

Env-A 904.02 (new rule) & Temporary

Permit FP-T-0051

3. General Recordkeeping Requirements for Combustion Sources

The Owner or Operator shall maintain the following records, on a monthly basis, of fuel characteristics and utilization for the fuel used in the combustion devices:

a) Hours of operation of each combustion device; b) Type (e.g., natural gas, liquefied petroleum gas, No. 2 fuel oil,

diesel fuel, and on-spec used oil) and amount of each fuel burned in each device; and

c) Sulfur content of any: 1. Gaseous fuel burned in terms of grains sulfur per 100 scf

fuel, or percent sulfur by weight, calculated as hydrogen sulfide at standard temperature and pressure; and

2. Liquid fuel burned in terms of percent sulfur by weight;

Monthly Facility Wide

Env-A 901.03(a),(c) (old rule) &

Env-A 903.03 (new rule) & Temporary

Permit FP-T-0051





Recordkeeping

Applicable Emission

Unit

Regulatory Cite.

4. General NOx Record keeping Requirements:

The owner or operator of any stationary source, area source, or device subject to this part, shall record the following information and maintain such records at the facility: a) Identification of each combustion device; b) Operating schedule during the high ozone season for

each combustion device identified in (a), above, including: 1. Hours of operation per calendar month; 2. Days of operation per calendar month; 3. Number of weeks of operation; 4. Type and amount of fuel burned for each combustion

device; 5. Heat input rate in million BTUs per hour; and 6. The following NOx emission data:

a. Actual NOx emissions from each combustion device identified in a) above for:

1) Each calendar year, in tons; and

2) A high ozone season day during that calendar year, in pounds per day; and

c) The emission factors and the origin of the emission factors used to calculate the NOx emissions.

On a continuous

basis

Facility Wide

Env-A 905.02 (new rule) & Env-A 901.08 (old rule) & Temporary

Permit FP-T-0051

5. The owner or operator shall maintain summary reports of all initial performance tests and subsequent NOx RACT compliance tests conducted on the CT #1 & #2, HRSG Units #1 & #2, and Boilers #4 & #5 in a form suitable for inspection.

On a continuous

basis

CT #1 & #2, HRSG Units #1 & #2, Boilers

#4 & #5

Env-A 906 & Temporary

Permit FP-T-0051





Recordkeeping

Applicable Emission

Unit

Regulatory Cite.

6. The owner or operator shall maintain daily records of the following information for each of the Combustion Turbines and HRSG Units:

a) The dates and times when each Combustion Turbine and HRSG Unit is run, including the total number of hours run each calendar day;

b) Hours of operation of each HRSG Unit while fresh air firing without the associated Combustion Turbine in service;

c) The running total of days of operation in a continuous 365 rolling day period;

d) The total daily, monthly, and calendar year natural gas and No. 2 fuel oil consumption in each of the Combustion Turbines and HRSG Units (MMCF/day and gal/day);

e) Retain certified fuel supplier certificates indicating No. 2 fuel oil sulfur and fuel bound nitrogen content (by weight) information. Record any instances when fuel bound nitrogen and sulfur content are above permitted limits, indicating total quantities of fuel above such limits, date of delivery of such fuels, and period of time during which fuel fired in the Combustion Turbines exceed such limits; and

f) Criteria pollutant emissions based on the most recent vendor supplied emissions factors or the most recent performance test data.

Daily, monthly, calendar year,

and consecutive 365 day period

CT #1 & #2, HRSG Units #1 &

#2


Permit FP-T-0051

7. The owner or operator shall maintain records of the following information on a calendar day basis for Boilers #4 & #5:

a) The dates and times when each Boiler is run, including the total number of hours run each calendar day;

b) The running total of days of operation in a continuous 365 rolling day period of time;

c) The total daily, monthly, and calendar year natural gas and No. 6 fuel oil consumption in each of the Boilers (MMCF/day and gal/day);

d) Retain certified delivery tickets indicating No. 6 fuel oil sulfur content by weight information for each load of fuel received; and

e) Criteria pollutant emissions based on the most recent of vendor supplied emissions factors or the most recent performance test data.

Daily, monthly, calendar year,

and consecutive 365 day period

Boilers #4 & #5


Permit FP-T-0051

8. Billing tickets from the natural gas and fuel oil supplier for each month shall be kept on file in a form suitable for inspection and shall be made available to the Division upon request. Each billing ticket shall indicate the name, address and telephone number of the natural gas or fuel oil supplier and the quantity of natural gas or fuel oil used and the sulfur content by weight delivered.

Monthly CT #1 & #2


Permit FP-T-0051





Recordkeeping

Applicable Emission

Unit

Regulatory Cite.

9. The owner or operator shall calculate and combine the NOx emissions from the CT #1 & CT #2 in accordance with Env-A 3704.01(c) for purposes of the NOx Emissions Reductions Fund Fee calculations.

Monthly CT #1 & #2


Permit FP-T-0051

10. a) The owner or operator shall maintain calendar monthly records of actual NOx emissions in accordance with the methods set forth in Env-A 620.

b) The owner or operator shall maintain calendar monthly records of power generation from the CT #1 and CT #2 in accordance with the following: 1. The measurements of power generation as output on an

instrument recorder; 2. The number of hours of operation of the NOx-emitting

generation source; 3. The number of hours of downtime of the power generation

monitoring system, if applicable, during the time period when the NOx-emitting generation source is in operation;

4. Fuel usage; and 5. The frequency and results of calibrations performed, as

applicable.

Monthly CT #1 & #2


Permit FP-T-0051

11. The owner or operator shall calculate the NOx emissions reduction fee by taking the total tons of NOx emissions calculated in accordance with Env-A 3704 and multiplying by the NOx emissions reduction fee in dollars per ton for the appropriate time period from Table 3707-1.

Annually CT #1 & CT #2


Permit FP-T-0051

12. The owner or operator shall maintain records of:

a) The occurrence and duration of any startup, shutdown, or malfunction in the operation of the CT #1 & #2 and HRSG Units #1 & #2;

b) Any malfunction of the air pollution control equipment; or c) Any periods during which a continuous monitoring system or

monitoring device is inoperative.

As stated CT #1 & #2 &

HRSG Units #1 &

#2

40 CFR 60 Subpart A

Section 60.7(b)

13. The owner or operator shall maintain a file of all measurements, including:

a) Continuous monitoring system, monitoring device (fuel flow meter), and performance testing measurements;

b) All continuous monitoring system performance evaluations; c) All continuous monitoring system or monitoring device

calibration checks; d) Adjustments and maintenance performed on these systems or

devices; and e) All other information required by this part recorded in a

permanent form suitable for inspection.

The file shall be retained for at least five years following the date of such measurements, maintenance, reports, and records.

5 year record retention

CT #1 & #2 &

HRSG Units #1 &

#2

40 CFR 60 Subpart A

Section 60.7(f)



IX. Reporting Requirements

The Permittee shall be subject to the reporting requirements identified in Table 6 below:

Table 6 – Applicable Reporting Requirements

Item # Reporting Requirements Frequency of

Reporting

Applicable Emission

Unit Regulatory Cite

1. VOC Emissions Statement Report

All sources subject to the reporting requirements of this section shall submit the following information to the director in accordance with the schedule in Env-A 901.07(h):

a) Facility information, including: 1. Source name; 2. Source identification; 3. Physical address; 4. Mailing address; and

b) Identification of each device or process operating at the source identified in a), above;

c) Operating schedule information for each device or process identified in b), above, including such information for: 1. A typical business day; and 2. A typical high ozone season day, if different from a

typical business day; d) Total quantities of actual VOC and NOX emissions for the

entire facility and for each device or process identified in b), above, including: 1. Annual VOC emissions, and 2. Typical high ozone season day VOC emissions.

Annually to DES (no later than

April 15th of the following year)

Facility Wide Env-A 908 (new rule) & Env-A

901.07 (old rule) Temporary

Permit FP-T-0051

2. NOx Reporting Requirements:

For each combustion device, the owner or operator shall submit to the director, in accordance with the schedule in Env-A 909.02(a), reports of the data required pursuant to Env-A 905.

Annually to DES (no later than

April 15th of the following year)

Facility Wide Env-A 909.03 (new rule) & Env-A 901.09 (old rule) & Temporary

Permit FP-T-0051

3. In accordance with Env-A 3704.01(b), a NOx-emitting generation source (CT #1 and CT #2) shall not be required to pay NOx emissions reduction fund fees for the first 7 pounds of NOx emitted for each megawatt-hour of electricity produced. In addition, the owner or operator may submit a written request in accordance with Env-A 3703.02 in order to claim exclusion for NOx emissions attributed to heat recovery from these devices. To date, the owner or operator has not submitted a written request.

As stated CT #1 & #2 Env-A 3704.01(b) &

Temporary Permit

FP-T-0051





Reporting

Applicable Emission


4. The owner or operator shall submit annually to the Division all information pursuant to Env-A 3706.01 (monthly actual NOx emissions and monthly power generation for CT #1 and CT #2) by April 15th of the following calendar year.

Annually, by April 15th the

following year

CT #1 & #2 Env-A 3706.02 & Temporary

Permit FP-T-0051

5. a) In accordance with Env-A 3707.01(a), in addition to the fees specified in Env-A 700, all applicable NOx-emitting generation sources shall pay to the Division each year, starting in 2006 for NOx emitted in 2005, a NOx emissions reduction fund fee as calculated pursuant to Env-A 3707.03.

b) In accordance with Env-A 3707.02, the owner or operator shall submit to the Director with each emission reduction fund fee payment a description of the method used to calculate actual emissions with each emission reduction fee payment.

c) In accordance with Env-A 3707.04, the owner or operator shall pay to the Division the NOx emissions reduction fund fee annually, in accordance with the schedule specified in Env-A 705.04 for emission-based fees.

Annually, by April 15th the

following year

CT #1 & #2 Env-A 3707.01(a),

Env-A 3707.02, Env-A 3707.04 & Temporary

Permit FP-T-0051





Reporting

Applicable Emission


6. Annual Emissions Report

a) The owner or operator shall submit an annual emissions report on or before April 15 of the following year. For calendar year 2005, the annual emissions report shall be submitted to the Division on or before April 15, 2006.

b) The annual emissions report shall include the following information: 1. The actual calendar year emissions of the stationary

source, area source or device and the methods used in calculating such emissions in accordance with Env-A 705.02, Determination of Actual Emissions for Use in Calculating Emission-based Fees.

2. For process operations, all information in accordance with Env-A 903.02, General Record keeping Requirements for Process Operations.

3. For combustion devices, all information in accordance with Env-A 903.03, General Record keeping Requirements for Combustion Devices; and

4. The actual annual emissions speciated by individual regulated air pollutants, including a breakdown of VOC emissions by compound.

Annually (no later than April

15th of the following year)

Facility Wide Env-A 907.01 & Temporary

Permit FP-T-0051

7. Emission-Based Fees Payment

Annual reporting of emission based fees shall be conducted in accordance with Section X of this Permit. The owner or operator of a stationary source, an area source, or device having actual emissions of 1,000 tons or less shall pay to the department the annual emission-based fee no later than: a) By April 15, 2006 for emissions from calendar year 2005;

and b) By April 15 each subsequent year for emissions from the

previous calendar year.

As specified Facility Wide

Env-A 705.045 (new rule) & Env-A 704.03

(old rule)

5 Adopted June 26, 2004.





Reporting

Applicable Emission


8. GPB shall submit a semi-annual excess emissions report to the EPA and DES, which identifies periods of excess emissions. Excess emissions of nitrogen oxides shall be any period during which the fuel-bound nitrogen of the fuel is greater than the maximum nitrogen content allowed by the fuel-bound nitrogen allowance used during the performance test. Excess emissions of sulfur dioxide shall be any daily period during which the sulfur content of the fuel being fired in the gas turbine exceeds 0.8 percent. Each report shall include the average fuel consumption, ambient conditions, gas turbine load, sulfur content, and nitrogen content of the fuel being fired during the period of excess emissions.

As specified CT #1 & #2 40 CFR 60 Subpart A

Section 60.7(c)

9. Discrete Emissions Reductions Trading Program – Notice of Intent to Use DERs: The owner or operator shall submit to DES a Notice of Intent to Use DERs at least 30 days before the intended use period begins, and at least annually if the use period is greater than one year. The Notice of Intent to Use DERs shall include the following information6:

a) The name and location of the user; b) The name and identification number of the emissions unit,

the permit number (if applicable), and the applicable pollutant (NOx);

c) The applicable requirements and state requirements that the DERs will be used to comply with (i.e., 65 ppmvd NOx limit while firing No. 2 fuel oil in the CTs, 0.10 lb NOx/mmBtu for the HRSG units, or NOx emissions limits for Boilers #4 or #5 contained in Tables 3a and 3b) and the intended use period;

d) A copy of the Notice and Certification of Generation submitted by the generator source to the State; and

e) The protocols that will be used to document the amount of DERs needed to demonstrate compliance.

30 days before intended use and

annually

CT #1 & #2, HRSG Units #1 & #2, and Boilers #4 &

#5


Permit FP-T-0051

10. Discrete Emissions Reductions Trading Program – Notice and Certification of Use: The owner or operator must submit to the Division a Notice and Certification of Use that contains the information described in Env-A 3104.09(d) within 90 days after the end of the use period or one year after the beginning of the use period, whichever is sooner. The Notice and Certification of Use must also include a truth, accuracy, and completeness certification signed by the responsible official.

Within 90 days after the end of

the use period or one year after the beginning of the

use period, whichever is

sooner

CT #1 & #2, HRSG Units #1 & #2, and Boilers #4 &

#5


Permit FP-T-0051

6 GPB has elected to include the use of DERs as a means of compliance with the NOx RACT emission limit of 65 ppmvd at 15% oxygen for the CT while firing No. 2 fuel oil and wishes to generate DERs for internal use from combusting natural gas in the CT.





Reporting

Applicable Emission


11. Discrete Emissions Reductions Trading Program – Notice and Certification of Generation: The owner or operator of a generator source shall provide a Notice and Certification of Generation to the Division prior to the first day of the use period and in no case later than one year after the first day of the generation period (and at least annually thereafter if longer than one year). The Notice and Certification of Generation shall include the information in Env-A 3103.08(d) and must also include a truth, accuracy, and completeness certification signed by the responsible official.

Annually CT #1 & #2, HRSG Units #1 & #2, and Boilers #4 &

#5


Permit FP-T-0051

12. GPB shall follow recordkeeping and public availability requirements, as applicable, in Env-A 3106.

As specified CT #1 & #2, HRSG Units #1 & #2, and Boilers #4 &

#5


Permit FP-T-0051

13. Permit Deviations

The owner or operator shall report to the DES all instances of deviations from Permit requirements, by telephone, fax, or email to [email protected], within 24 hours of discovery of such deviation. This report shall include the deviation itself, including those attributable to upset conditions as defined in the Permit, the probable cause of such deviations, and any corrective actions or preventative measures taken. Said Permit deviation shall also be submitted in writing to the DES in the semi-annual summary report of monitoring and testing requirements due July 31st and January 31st of each calendar year. Deviations are instances where any Permit condition is violated and has not already been reported as an emergency pursuant to Section XXVII. of the Title V Operating Permit TV-OP-040 issued on January 17, 2002.

Within 24 hours of discovery

Facility Wide 40 CFR 70.6(a)(3)(iii)(B)

X. Emission-Based Fee Requirements:

A. Env-A 705.01, Emission-based Fees: The Owner or Operator shall pay to the Division each year an emission-based fee for emissions from the devices listed in its Title V Operating Permit TV-OP-040.

B. Env-A 705.02, Determination of Actual Emissions for use in Calculating of Emission-based Fees: The Owner or Operator shall determine the total actual annual emissions from the devices for each calendar year in accordance with the methods specified in Env-A 616, Determination of Actual Emissions. If the emissions are determined to be less than one ton, the emission-based fee shall be calculated using an emission-based multiplier of one ton.

C. Env-A 705.03, Calculation of Emission-based Fees: The Owner or Operator shall calculate the annual emission-based fee for each calendar year in accordance with the procedures specified in



Env-A 705.03 and the following equation:

DPT*EFEE = Where: FEE = The annual emission-based fee for each calendar year as specified in Env-A 705. E = Total actual emissions as determined pursuant to Condition X.B. DPT = The dollar per ton fee calculated by the Division as specified in Env-A 705.03(e).

D. Env-A 3704.01, Calculation of NOx Emissions for One or More NOx-Emitting Generation Sources Located at a Single Stationary Source: The Owner or Operator shall calculate average monthly emissions from the CT #1 and CT #2 using the following equation:

( ) ( )2000

*7 2#1#2#1#

CTCTCTCTtotal

BBAAE

+−+=

Where: Etotal = The total NOx emissions in tons per month; A = The actual NOx emissions in tons per month for each unit; and B = The actual power generation for each unit in megawatt-hours of electricity produced per

month.

E. Env-A 3707.03, Calculation of NOx Emissions Reduction Fund Fees: The NOx emissions reduction fund fee shall be equal to the total tons of NOx emissions calculated in accordance with Condition X.D multiplied by the NOx emissions reduction fund fee in dollars per ton as listed in Table 7:

Table 7 - NOx Emissions Reduction Fund Fee

Time Period NOx Emissions Reduction Fund Fee (Dollars Per Ton)

January 1 to April 30 500 May 1 to September 30 1000

October 1 to December 31 500

F. Env-A 705.04, Payment of Emission-based Fee: The Owner or Operator shall submit, to the Division, payment of the emission-based fee by April 15th for emissions during the previous calendar year. For example, the emission-based fee for calendar year 2005 shall be submitted on or before April 15, 2006.

G. Env-A 3707.04, Payment of NOx Emissions Reduction Fund Fee: The Owner or Operator shall submit, to the Division, payment of the NOx emissions reduction fund fee by April 15th for emissions during the previous calendar year. For example, the NOx emissions reduction fund fee for calendar year 2005 shall be submitted on or before April 15, 2006.

temporary permit - des.state.nh.us

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