SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

RULE 4703 STATIONARY GAS TURBINES 

(Adopted August 18, 1994)(Amended March 16, 1995; February 15, 1996; October 16, 1997; 

April 25, 2002; August 17, 2006; September 20, 2007) 

1.0 Purpose 

The purpose of this rule is to limit oxides of nitrogen (NOx) emissions from stationary gas 

turbine systems. 

2.0 Applicability 

The provisions of this rule apply to all stationary gas turbine systems, which are subject to 

District permitting requirements, and with ratings equal to or greater than 0.3 megawatt 

(MW) or a maximum heat input rating of more than 3,000,000 Btu per hour, except as 

provided in Section 4.0. 

3.0 Definitions 

3.1 Auxiliary Burner: any fuel burning device that increases the heat content of exhaust 

gas from a gas turbine. Duct burners, fired waste heat boilers, and fired heat 

recovery steam generators are considered auxiliary burners. 

3.2 Bypass Transition Period: the duration of time that a gas turbine’s operation 

transitions between the heat recovery steam generator and bypass exhaust stacks, 

provided all of the following conditions are met: 

3.2.1 The selective catalytic reduction catalyst is not within the required 

temperature range or the required ammonia saturation level has not yet been 

achieved. 

3.2.2 The duration of a bypass transition period shall not exceed two hours. 

3.2.3 NOx emissions shall not exceed 15 ppmvd, corrected to 15% O2, averaged 

over two (2) hours. 

3.2.4 The applicable CO Compliance Limits in Section 5.0 shall not be exceeded. 

3.3 Combined Cycle unit: any stationary gas turbine which recovers heat from the gas

turbine exhaust gases to heat water, generate steam, or preheat the inlet 

combustion air to the gas turbine. 

3.4 Commercially Available: any control technology or equipment which is offered by 

at least one vendor and guaranteed by the vendor to achieve the required emission 

control performance for a regular or full-scale operation within the United States. 

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3.5 Compliance Limit: maximum allowable oxides of nitrogen (NOx) or carbon 

monoxide (CO) emission levels. 

3.6 Control System Operating Parameters: operating parameters that the APCO deems 

necessary to analyze when determining compliance, such as ammonia and exhaust 

gas flow rates and exhaust gas temperature for selective catalytic reduction; or 

humidity, water injection rate, exhaust gas flow rate and temperature for water 

injection. 

3.7 Dry Low-NOx Combustion Technology (DLN): any turbine combustor design 

which uses multiple staging, air/fuel premixing or other modifications to achieve 

lower levels of NOx emissions as compared to conventional combustors. 

3.8 Emergency Standby Unit: a stationary gas turbine system that is limited by permit 

condition to be operated only as a mechanical or electrical power source for a facility 

when the primary power source for a facility has been rendered inoperable due to 

failure beyond the reasonable control of the operator, except due to power 

interruption pursuant to an interruptible power supply agreement. Electricity 

generated by such a unit cannot be sold. 

3.9 Gas Turbine: an internal combustion engine consisting of a compressor, a 

combustor, and a power turbine, that is gas and/or liquid fueled, with or without 

power augmentation. Two or more gas turbines powering one shaft shall be treated 

as one gas turbine. 

3.10 Gas Fuel: any of the following fuels or fuels containing any of the following fuels: 

natural gas, LPG, propane, digester gas, and landfill gas. 

3.11 HHV: higher heating value of fuel. 

3.12 LHV: lower heating value of fuel. 

3.13 Liquid Fuel: any of the following fuels: kerosene, jet fuel, and distillate fuel oils. 

Sulfur content of the fuel oil shall be less than 0.05 percent, by weight. 

3.14 Major Overhaul: taking a stationary gas turbine out of service to replace or repair 

major components of the turbine. Major overhaul does not include taking a 

stationary gas turbine out of service exclusively to install emission control 

equipment. 

3.15 Measured CO Emissions Concentration: measured carbon monoxide emissions 

corrected to 15 percent oxygen on a dry basis, ppm. 

3.16 Measured NOx Emissions Concentration: measured oxides of nitrogen emissions 

corrected to 15 percent oxygen on a dry basis, ppm. 

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3.17 Non-Steady State Period: for a 3 MW to 10 MW pipeline gas turbine, any 15-minute 

period in which the fuel rate to the turbine differs from the reference fuel rate by 

more than +/- 3,000 standard cubic feet per 15-minute period. For this rule, a 15-

minute Non-Steady State Period shall be zero (0) to 15 minutes after the hour, 15 to 

30 minutes after the hour, 30 to 45 minutes after the hour, or 45 to 60 minutes after 

the hour. 

3.18 Pipeline Gas Turbine: a simple cycle stationary gas turbine used to transport gases 

or liquids in a pipeline. 

3.19 Power Augmentation: an increase in the gas turbine shaft output and/or the decrease 

in gas turbine fuel consumption by the addition of energy recovered from exhaust 

heat. 

3.20 Primary Re-ignition Period: the duration of time during which a gas turbine is 

operated at less than rated capacity in order to reset the DLN combustion system 

following a primary re-ignition, provided all of the following conditions are met: 

3.20.1 The duration of a primary re-ignition period shall not exceed one hour. 

3.20.2 NOx emissions shall not exceed 15 ppmvd, corrected at 15% O2, averaged 

over one (1) hour. 

3.20.3 CO emissions shall not exceed 25 ppmvd, corrected at 15% O2. 

3.21 Public Service Unit: a stationary gas turbine system used to generate electricity for 

sale or for use in serving the public. 

3.22 Rating: the continuous megawatt (MW) rating or mechanical equivalent by a 

manufacturer for a gas turbine without power augmentation. 

3.23 Reduced Load Period: the time during which a gas turbine is operated at less than 

rated capacity in order to change the position of the exhaust gas diverter gate, not to 

exceed one hour. 

3.24 Reference Fuel Rate: the fuel rate, to a turbine, measured during the preceding 15-

minute period. 

3.25 SCR: selective catalytic reduction. 

3.26 Shutdown: the period of time during which a unit is taken from an operational to 

a non-operational status by allowing it to cool down from its operating 

temperature to ambient temperature as the fuel supply to the unit is completely 

turned off. 

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3.27 Simple Cycle unit: any stationary gas turbine which does not recover heat from 

the gas turbine exhaust gases to preheat the inlet combustion air to the gas

turbine, to heat water, or to generate steam. 

3.28 Standard Conditions: defined in Rule 1020 (Definitions). 

3.29 Start-up: the period of time during which a unit is brought from a shutdown 

status to its operating temperature and pressure, including the time required by the 

unit’s emission control system to reach full operation. 

3.30 Stationary Gas Turbine: a gas turbine that is attached to a foundation, or a portable 

gas turbine that is operated at a facility for more than 90 days in any 12-month 

period. 

3.31 Stationary Gas Turbine System: a stationary gas turbine, or a stationary gas turbine 

and the associated auxiliary burner. 

3.32 Steady State Period: for a 3 MW to 10 MW pipeline gas turbine, the period which 

commences after any two consecutive 15-minute periods in which the fuel rate to the 

turbine does not differ from the reference fuel rate by more than +/- 3,000 standard 

cubic feet per 15-minute period and ends when a non-steady state period begins. 

3.33 Transitional Operation Period: any of the following periods: bypass transition 

period, primary re-ignition period, reduced load period, start-up or shutdown. 

3.34 Unit: a stationary gas turbine system. 

4.0 Exemptions 

4.1 The provisions of this rule, with the exception of Section 6.1, shall not apply to 

stationary gas turbine systems operated under the following conditions: 

4.1.1 Laboratory units used in research and testing for the advancement of gas 

turbine technology, 

4.1.2 Units limited by permit condition to be operated exclusively for firefighting 

and/or flood control. 

4.2 The provisions of this rule, with the exception of Section 6.1 and the record 

keeping provisions of Section 6.2, shall not apply to emergency standby units 

limited by permit condition to operate less than 100 hours per calendar year for 

maintenance and testing purposes. 

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5.0 Requirements 

5.1 NOx Emissions 

NOx emissions concentrations measured for compliance with Section 5.0 shall be 

averaged, using consecutive 15-minute sampling periods, over a three-hour period. 

NOx emissions concentrations shall be measured in accordance with the applicable 

test method in Section 6.4 or, if continuous emission monitors are used, all 

applicable requirements of 40 CFR Part 60 as detailed in Section 6.2. Any variations 

from these measurement requirements are subject to APCO and EPA approval prior 

to implementation. 

5.1.1 Tier 1 NOx Compliance Limits 

The owner or operator of any stationary gas turbine system shall not operate 

such unit under load conditions, except as allowed by Section 5.3, which 

results in the measured emissions concentration exceeding the applicable 

emission limits below, according to the Tier 1 Compliance Schedules 

listed in Section 7.0. 

Table 5-1: Tier 1 NOx Compliance Limits 

NOx Compliance Limit, 

Stationary Gas Turbine Rating Operating ppmv at 15% O2

hours per year Gas Oil 

4 MW and greater < 877 42 65 

> 0.3 MW but < 10.0 MW ≥ 877 42 65 

10.0 MW and greater, without 

SCR 

≥ 877 15 x EFF/25 42 x EFF/25 

10.0 MW and greater, with SCR ≥ 877 9 x EFF/25 25 x EFF/25 

General Electric Frame 7 with 

Quiet Combustors 

Not applicable 18 x EFF/25 42 x EFF/25 

Solar Saturn 1100 horsepower 

gas turbine powering centrifugal 

compressor 

Not applicable 50 50 

Where EFF (efficiency) is the higher of EFF1

 or EFF2 below. An EFF that is 

less than 25 shall be assigned a value of 25. 

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EFF1 = 

3412 Btu / kW - hr

Actual Heat Rate at HHV (Btu / kW - hr)

 x 100%

EFF1

 is the demonstrated percent efficiency of the gas turbine only, as 

calculated without consideration of any downstream energy recovery from 

the actual heat rate (Btu/KW-hr); corrected to HHV and standard conditions, 

as measured at peak load for that facility. 

 

 

LHV

HHV

EFF = EFFmfr x 2

EFF2

 is EFFmfr after correction from LHV to HHV at peak load for that 

facility. EFFmfr is the manufacturer's continuous rated percent efficiency of 

the gas turbine with air pollution control equipment at LHV. 

5.1.2 Tier 2 NOx Compliance Limits 

The owner or operator of any stationary gas turbine system shall not operate 

such unit under load conditions, except as allowed by Section 5.3, which 

results in the measured emissions concentration exceeding the applicable 

emission limits below, according to the Tier 2 Compliance Schedules 

listed in Section 7.2. 

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Table 5-2: Tier 2 NOx Compliance Limits 

NOx Compliance Limit, 

ppmvd at 15% O2 Turbine Classification Rating 

Compliance 

Option 

(see Section 7.2) Gas Fuel Liquid 

Fuel 

a) Less than 2.0 MW Solar Saturn, 

driving a centrifugal compressor Standard 50 50 

b) No greater than 10 MW, if a 

DLN System is commercially 

available for the specific unit, as 

of April 30, 2003. 

Standard 25 65 

c) No greater than 10 MW, if a 

DLN System is not 

commercially available for the 

specific unit, as of April 30, 

2003. 

Standard 35 65 

d) Greater than 10 MW, Combined Standard 5 25 

cycle. Enhanced 3 25 

Standard e) Greater than 10 MW, Simple 5 25 

cycle, and permit condition for 

greater than 877 hrs/yr operation. Enhanced 3 25 

Standard 25 42 f) Greater than 10 MW, Simple 

cycle, and permit condition for 

no greater than 877 hr/yr 

operation. Enhanced 5 25 

5.1.2.1 For units with a Standard Option and an Enhanced Option shown in 

Table 5-2, the operator shall choose which option will apply and 

shall demonstrate and maintain compliance with that NOx 

Compliance limit according to the applicable Tier 2 Compliance 

Schedule shown in Section 7.2. Units failing to demonstrate 

compliance with the applicable Standard Option limit by the 

applicable Standard Option Compliance Date, shall be required to 

meet the Enhanced Option Limit by the applicable Enhanced 

Option Compliance Date. 

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5.1.2.2 Any stationary gas turbine system equipped with a NOx emission 

control device which results in emission reductions of at least 95%, 

shall be considered to meet the Tier 2 NOx Compliance Limit. 

Percent emission reductions, if used to comply with Section 5.1.2, 

shall be calculated as follows: 

5.1.2.2.1 For units with exhaust gas NOx control devices, percent 

reduction shall be calculated using emission samples 

taken at the inlet and outlet of the control device. 

5.1.2.2.2 For units without exhaust gas NOx control devices and 

for units with an exhaust gas NOx control device in 

combination with a second emission control device or 

technique, percent reduction shall be based on source 

test results for the uncontrolled unit and the unit after 

the control device(s) or technique(s) has been 

employed. When representative source sampling prior 

to the application of an emissions control technology or 

technique is not available, the APCO may approve the 

use of manufacturer’s uncontrolled emissions 

information or source sampling from a similar, 

uncontrolled unit. 

5.1.3 Tier 3 NOx Compliance Limits 

5.1.3.1 The owner or operator of any stationary gas turbine system listed in 

Table 5-3 shall not operate such unit under load conditions, except 

as allowed by Section 5.3, which results in the measured emissions 

concentration exceeding the applicable emission limits in Table 5-

3, according to the Tier 3 Compliance Schedule listed in Section 

7.3. 

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Table 5-3: Tier 3 NOx Compliance Limits 

NOx Compliance Limit, ppmvd 

at 15% O2

Turbine Classification Rating 

Gas Fuel Liquid 

Fuel 

a) Less than 3 MW. 9 25 

b) 3 MW to 10 MW pipeline gas 

turbine. 

8 during steady 

state and 

12 during nonsteady state 

25 

c) 3 MW to 10 MW and permit 

condition for less than 877 hrs/yr 

operation and not listed above. 

9 25 

d) 3 MW to 10 MW and permit 

condition for 877 hrs/yr operation 

or greater and not listed above. 

5 25 

e) Greater than 10 MW, Simple cycle, 

and permit condition for no greater 

than 200 hrs/yr operation, except 

as provided in Section 5.1.3.3. 

25 42 

f) Greater than 10 MW, Simple cycle, 

and permit condition for greater 

than 200 hrs/yr operation but no 

greater than 877 hrs/yr operation. 

5 25 

5.1.3.2 Any stationary gas turbine system equipped with a NOx emission 

control device which results in emission reductions of at least 95%, 

shall be considered to meet the Tier 3 NOx Compliance Limit. 

Percent emission reductions, if used to comply with Section 5.1.3, 

shall be calculated as follows: 

5.1.3.2.1 For units with exhaust gas NOx control devices, percent 

reduction shall be calculated using emission samples 

taken at the inlet and outlet of the control device. 

5.1.3.2.2 For units without exhaust gas NOx control devices and 

for units with an exhaust gas NOx control device in 

combination with a second emission control device or 

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technique, percent reduction shall be based on source 

test results for the uncontrolled unit and the unit after 

the control device(s) or technique(s) has been 

employed. When representative source sampling prior 

to the application of an emissions control technology or 

technique is not available, the APCO may approve the 

use of manufacturer’s uncontrolled emissions 

information or source sampling from a similar, 

uncontrolled unit. 

5.1.3.3 Operators of turbines subject to the provisions of Table 5-3, 

subsection (e), shall also comply with the following provisions: 

5.1.3.3.1 Units may be operated in response to a California 

Independent System Operator (ISO) - declared Stage 

One, Two, or Three Emergency, or a Transmission 

Emergency, or a Turlock Irrigation District (TID) - 

declared Alert Level One, Two, or Three Energy 

Emergency, provided the unit is located in the local area 

transmission system of the emergency. The operations 

for ISO - declared or TID - declared emergencies hours 

shall not count against the unit's 200 hrs/year operating 

limit. 

5.1.3.3.2 On and after January 1, 2009, no later than April 1 each 

year, an operator, with a unit operating during an ISO - 

declared or TID - declared emergency in accordance 

with Section 5.1.3.3.1, shall pay a fee to the District. 

That fee will be calculated according to the following 

formula: 

Fee = ISO or TID hrs/yr x EF x FR 

Where: 

ISO or TID = Total hours operated in response to an 

ISO - declared or TID - declared emergency, 

during the preceding calendar year. 

EF = The unit's emission factor, which is equal to 

the permitted emission rate of NOx, in lb/hr, 

divided by 2,000 lb/ton. 

FR = The fee rate, which shall be $75,000 per ton of 

NOx until December 31, 2014 and shall be 

$100,000 per ton of NOx, thereafter. 

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5.1.3.3.3 Except as provided in Section 6.5.2, in no event shall 

total operations, for any purpose, exceed 877 hours in 

any calendar year. Any operation of such units in 

excess of 877 hrs/year shall require the operator to 

comply with the emission limit of Table 5-2, subsection 

(e) – Standard Compliance Option, according to the 

compliance schedule in Section 6.5.1. 

5.1.3.3.4 Any fees received by the District, pursuant to Section 

5.1.3.3.2 shall be deposited into the District's account to 

fund air quality improvement projects. 

5.2 CO Emissions 

The owner or operator of any stationary gas turbine system shall not operate such 

unit under load conditions, except as allowed by Section 5.3, which results in the 

measured CO emissions concentration exceeding the compliance limits listed below: 

Table 5-4 : CO Compliance Limits 

Stationary Gas Turbine CO Compliance Limit, 

ppmv at 15% O2

Units not identified below 200 

General Electric Frame 7 25 

General Electric Frame 7 with Quiet Combustors 52 

Less than 2.0 MW Solar Saturn gas turbine powering 

centrifugal compressor 

250 

5.3 Transitional Operation Periods 

On and after the date a unit is required, pursuant to Section 7.0, to be in 

compliance with the emission limits requirements of Section 5.1 or Section 5.2, 

the applicable emission limits of Section 5.1 and Section 5.2 shall not apply 

during a transitional operation period, as defined in Section 3.0, provided an 

operator complies with the applicable requirements specified in Sections 5.3.1 

and 5.3.2. 

5.3.1 Except as provided in Section 5.3.3, the operator shall meet the following 

conditions: 

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5.3.1.1 The duration of each start-up or each shutdown shall not exceed 

two hours. 

5.3.1.2 For each bypass transition period, the requirements specified in 

Section 3.2 shall be met. 

5.3.1.3 For each primary re-ignition period, the requirements specified 

in Section 3.20 shall be met. 

5.3.1.4 Each reduced load period shall not exceed one hour. 

5.3.2 The emission control system shall be in operation and emissions shall be 

minimized insofar as technologically feasible during each transitional 

operation period. 

5.3.3 Notwithstanding the requirement of Section 5.3.1, an operator may submit an 

application for a Permit to Operate condition to allow more than the duration 

of time specified in Section 5.3.1 for each transitional operation period 

provided the operator meets all of the conditions specified in Section 5.3.3.1 

through Section 5.3.3.2. 

5.3.3.1 The maximum allowable duration of a transitional operation period 

will be determined by the APCO, ARB, and EPA. An operator 

seeking approval pursuant to Section 5.3.3 shall submit a written 

request and supporting information to the APCO. The District shall 

evaluate the request and if approved by the APCO, the District shall 

provide EPA and ARB with a copy of the evaluation and shall 

request EPA and ARB approval. The District evaluation and the 

APCO request shall be deemed approved unless EPA or ARB 

objects to such approval in writing within 45 days of the receipt of 

the APCO request. 

5.3.3.2 At a minimum, a justification for the increased duration shall 

include the following: 

5.3.3.2.1 A clear identification of the control technologies or 

strategies to be utilized; and 

5.3.3.2.2 A description of what physical conditions prevail 

during the period that prevent the controls from being 

effective; and 

5.3.3.2.3 A reasonably precise estimate as to when the physical 

conditions will have reached a state that allows for the 

effective control of emissions; and 

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5.3.3.2.4 A detailed list of activities to be performed during the 

period and a reasonable explanation for the length of 

time needed to complete each activity; and 

5.3.3.2.5 A description of the material process flow rates and 

system operating parameters, etc., the operator plans 

to evaluate during the process optimization; and an 

explanation of how the activities and process flow 

affect the operation of the emissions control 

equipment; and 

5.3.3.2.6 The basis for the requested additional duration. 

5.4 For existing facilities, a replacement unit installed for the sole purpose of 

complying with the requirements of this rule shall be considered to be an emission 

control technique and may be exempt from the Best Available Control 

Technology (BACT) and Offsets requirements of District Rule 2201 (New and 

Modified Stationary Source Review Rule) provided that all other requirements of 

Rule 2201 are met. 

6.0 Administrative Requirements 

6.1 Emission Control Plan 

The owner or operator of any existing stationary gas turbine system, unless exempted 

in Section 6.1.5, shall submit, to the APCO for approval, an emissions control plan of 

all actions, including a schedule of increments of progress, which will be taken to 

comply with the requirements of the applicable NOx Compliance Limit in Section 

5.0 and Compliance Schedule in Section 7.0. 

6.1.1 Such plan shall contain a list that provides the following for each stationary 

gas turbine system: 

6.1.1.1 Permit or identification number, 

6.1.1.2 Name of gas turbine manufacturer, 

6.1.1.3 Gas turbine model designation, 

6.1.1.4 Rated shaft power output, (MW), 

6.1.1.5 Name of auxiliary burner manufacturer, 

6.1.1.6 Auxiliary burner model designation, 

6.1.1.7 Rated heat input of the auxiliary burner, (MMBtu/hr) 

6.1.1.8 Type of liquid fuel and/or type of gaseous fuel, 

6.1.1.9 Fuel consumption (cubic feet of gas or gallons of liquid) of 

turbine and/or auxiliary burner, 

6.1.1.10 Hours of operation in the previous one-year period, 

6.1.1.11 Heat rate (Btu/KW-hr), corrected to HHV for each type of fueling 

(liquid/gas), 

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6.1.1.12 HHV for each fuel. 

6.1.2 Such plan shall contain a list of all stationary gas turbine systems to be 

controlled, identifying the type of emission control to be applied to each unit, 

applicable emission standard from Section 5.0, and documentation showing 

current emissions of oxides of nitrogen. 

6.1.3 Such plan shall contain support documentation for any systems exempt under 

the provisions of Section 4.0. 

6.1.4 Such plan shall identify the applicable compliance schedule for each unit, as 

specified in Section 7.0. Each emission control plan for a unit subject to 

Section 7.2.2 or Section 7.3 shall include the owner/operator's overhaul 

schedule. 

6.1.5 The owner or operator of any existing stationary gas turbine system shall be 

exempt from the requirements of Section 6.1 provided all such turbines under 

his ownership or control have NOx and CO emissions limits which are 

shown on the current Permit to Operate and which do not exceed the 

applicable Compliance Limits in Section 5.0. 

6.2 Monitoring and Recordkeeping 

The owner or operator of any stationary gas turbine system subject to the 

provisions of this rule shall perform the following actions: 

6.2.1 Except for units subject to Section 6.2.3, for turbines with exhaust gas 

NOx control devices, the owner or operator shall either install, operate, 

and maintain continuous emissions monitoring equipment for NOx and 

oxygen, as identified in Rule 1080 (Stack Monitoring), or install and 

maintain APCO-approved alternate monitoring consisting of one or more 

of the following: 

6.2.1.1 periodic NOx emission concentrations, 

6.2.1.2 turbine exhaust oxygen concentration, 

6.2.1.3 air-to-fuel ratio, 

6.2.1.4 flow rate of reducing agents added to turbine exhaust, 

6.2.1.5 catalyst inlet and exhaust temperature, 

6.2.1.6 catalyst inlet and exhaust oxygen concentration, 

6.2.1.7 other operational characteristics. 

6.2.2 Except for units subject to Section 6.2.3, for turbines without exhaust-gas 

NOx control devices and without continuous emissions monitoring 

equipment, the owner or operator shall monitor operational characteristics 

recommended by the turbine manufacturer or emission control system 

supplier, and approved by the APCO. 

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6.2.3 For units 10 MW and greater that operated an average of more than 4,000 

hours per year over the last three years before August 18, 1994, the owner or 

operator shall monitor the exhaust gas NOx emissions. The NOx monitoring 

system shall meet EPA requirements as specified in 40 CFR Part 60 App. B, 

Spec. 2, 40 CFR Part 60 App. F, and 40 CFR Part 60.7 (c), 60.7 (d), and 

60.13, or other systems that are acceptable to the EPA. The owner or 

operator shall submit to the APCO information demonstrating that the 

emission monitoring system has data gathering and retrieval capability. 

6.2.4 The owner or operator shall maintain all records for a period of five years 

from the date of data entry and shall make such records available to the 

APCO upon request. 

6.2.5 The owner or operator shall submit to the APCO, before issuance of the 

Permit to Operate, information correlating the control system operating 

parameters to the associated measured NOx output. This information may be 

used by the APCO to determine compliance when there is no continuous 

emission monitoring system for NOx available or when the continuous 

emission monitoring system is not operating properly. 

6.2.6 The owner or operator shall maintain a stationary gas turbine system 

operating log that includes, on a daily basis, the actual local start-up time and 

stop time, length and reason for reduced load periods, total hours of 

operation, type and quantity of fuel used (liquid/gas). 

6.2.7 The owner or operator shall maintain a stationary gas turbine system 

operating log for units exempt under Section 4.2 that includes, on a daily 

basis, the actual local start-up time and stop time, total hours of operation, 

and cumulative hours of operation to date for the calendar year. 

6.2.8 The operator performing start-up or shutdown of a unit shall keep records of 

the duration of start-up or shutdown. 

6.2.9 On and after January 1, 2008, an operator of a unit subject to Section 5.1.3.3 

shall also keep the following records: 

6.2.9.1 A stationary gas turbine system operating log, which identifies the 

date, start time, and end time that the unit was operated pursuant to 

Section 5.1.3.3, 

6.2.9.2 A copy of the ISO or TID emergency declaration for that operation 

and 

6.2.9.3 A copy of the information used to determine the applicable Annual 

Emission Fee. 

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6.2.10 The operator of a unit subject to Section 6.5.2 shall identify in the stationary 

gas turbine system operating log the date and start time and end time that the 

unit was operated pursuant to Section 6.5.2 and keep a copy of the 

emergency declaration. 

6.2.11 The operator of a unit shall keep records of the date, time and duration of 

each bypass transition period and each primary re-ignition period. 

6.2.12 The operator of a unit subject to subsection (b) of Table 5-3 shall keep 

records of the date, time and duration of each steady state period and nonsteady state period and the quantity of fuel used during each period. 

6.3 Compliance Testing 

6.3.1 The owner or operator of any stationary gas turbine systems subject to the 

provisions of Section 5.0 of this rule shall provide source test information 

annually regarding the exhaust gas NOx and CO concentrations, and, if used 

as a basis for Tier 1 emission limit calculations, the demonstrated percent 

efficiency (EFF) of the stationary gas turbine, or, for turbines complying with 

Section 5.1.2.2 or Section 5.1.3.2, the control efficiency of the emission 

control device. 

6.3.2 The owner or operator of any stationary gas turbine system operating less 

than 877 hours per year shall provide source test information biennially 

regarding the exhaust gas NOx concentrations at standard conditions and if 

used as a basis for Tier 1 emission limit calculations, the percent efficiency 

(EFF) of the stationary gas turbine. 

6.3.3 The owner or operator of any unit with an intermittently operated auxiliary 

burner shall demonstrate compliance with the auxiliary burner both on and 

off. 

6.4 Test Methods 

The following test measures shall be used unless otherwise approved by the APCO 

and EPA. 

6.4.1 Oxides of nitrogen emissions for compliance tests shall be determined by 

using EPA Method 7E or EPA Method 20. 

6.4.2 Carbon monoxide emissions for compliance tests shall be determined by 

using EPA Test Methods 10 or 10B. 

6.4.3 Oxygen content of the exhaust gas shall be determined by using EPA 

Methods 3, 3A, or 20. 

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6.4.4 HHV and LHV of distillate fuels shall be determined by using: 

6.4.4.1 ASTM D240-87, Standard Test Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb Calorimeter, or 

6.4.4.2 ASTM D2382-88, Standard Test Method for Heat of Combustion 

of Hydrocarbon Fuels by Bomb Calorimeter (High-precision 

Method). 

6.4.5 HHV and LHV of gaseous fuels shall be determined by using: 

6.4.5.1 ASTM D3588-91, Standard Practice for Calculating Heat Value, 

Compressibility Factor, and Relative Density (Specific Gravity) of 

Gaseous Fuels, or 

6.4.5.2 ASTM 1826-88, Standard Test Method for Calorific (Heating) 

Value of Gases in Natural Gas Range by Continuous Recording 

Calorimeter, or 

6.4.5.3 ASTM 1945-81, Standard Method for Analysis of Natural Gas 

by Gas Chromatography. 

6.4.6 Demonstrated percent efficiency of the stationary gas turbine shall be 

determined using the facility instrumentation for gas turbine fuel 

consumption and power output. Power output values used to determine gas 

turbine efficiency shall be either: 

6.4.6.1 the electrical power output of the gas turbine, provided the gas 

turbine generates electricity; or 

6.4.6.2 the mechanical power output of the gas turbine, provided the gas 

turbine does not generate electricity. 

6.5 Exempt and Emergency Standby Units 

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6.5.1 The owner or operator of any unit with an hour-per-year operation limit 

pursuant to Sections 4.2 or 5.0 must notify the APCO within seven days if 

the hour-per-year limit is exceeded. Except as provided in Section 6.5.2, if 

the hour per-year-limit is exceeded, the exemption shall be permanently 

withdrawn. Within 30 days after the exceedance, the owner or operator must 

submit a permit application detailing a plan to meet the appropriate 

compliance limit within 24 months. Included in this permit application, the 

owner or operator must submit an emission control plan including a schedule 

of increments of progress for the installation of the required control 

equipment. This schedule shall be subject to the review and approval of the 

APCO. 

6.5.2 A public service unit operating during a state of emergency, when such 

emergency is declared by proclamation of the Governor and when the unit is 

located in the specific geographic location identified in the proclamation, 

shall be excluded from loss of exemption due to exceeding the hour-per-year 

limit for the operation during the state of emergency. If the unit exceeds the 

hour-per-year limit based solely on operation outside of the state of 

emergency, then loss of exemption shall apply according to Section 6.5.1. 

7.0 Compliance Schedule 

7.1 Tier 1 Compliance Schedule 

All owner/operators shall be in compliance with the applicable provisions of 

Sections 5.0 and 6.0 on and after August 18, 2000. 

7.2 Tier 2 Compliance Schedule 

Owners or operators of all applicable stationary gas turbine systems shall submit 

the emission control plan required by Section 6.1 to the District by April 30, 

2003. All owner/operators shall demonstrate and maintain compliance with the 

applicable provisions of Sections 5.0 and 6.0 in accordance with the following 

Compliance Schedules: 

7.2.1 Operators complying with the Standard Option of Table 5-2 shall 

demonstrate and maintain compliance by the applicable Compliance Date: 

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Table 7-1: Tier 2 Standard Option Compliance Schedule 

Turbine Classification Rating Compliance Date 

a) Less than 2.0 MW Solar Saturn, driving a 

centrifugal compressor April 25, 2002 

b) No greater than 10 MW, if a DLN System is 

commercially available for the specific unit, as of 

April 30, 2003. 

April 30, 2004 

c) No greater than 10 MW, if a DLN System is not 

commercially available for the specific unit, as of 

April 30, 2003. 

April 30, 2003 

d) Greater than 10 MW, Combined Cycle. April 30, 2004 

e) Greater than 10 MW, Simple cycle, and permit 

condition for greater than 877 hrs/yr operation. April 30, 2005 

f) Greater than 10 MW, Simple cycle, and permit 

condition for no greater than 877 hr/yr operation. April 30, 2003 

7.2.2 Notwithstanding Table 7-1, for an operator with multiple units no greater 

than 10 MW which will comply with the 25 ppmv Standard DLN Option for 

those units, 

7.2.2.1 By April 30, 2004, demonstrate full compliance on at least 62% of 

those units which will comply with the Standard DLN Option. 

7.2.2.2 By April 30, 2005 or 30 days after the completion of the next Major 

Overhaul following April 30, 2004 whichever is earliest, 

demonstrate full compliance on all remaining units which will 

comply with the Standard DLN Option. 

7.2.3 Notwithstanding Table 7-1, for an operator with multiple units greater than 

10 MW, which will comply with the Standard Option for those units, 

7.2.3.1 By April 30, 2004, demonstrate full compliance on at least 62% of 

those units which will comply with the Standard Option. 

7.2.3.2 By April 30, 2005, or 30 days after the completion of the next 

Major Overhaul following April 30, 2004, whichever is earliest, 

demonstrate full compliance on all remaining units which will 

comply with the Standard Option. 

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7.2.4 Operators complying with the Enhanced Option of Table 5-2 shall 

demonstrate and maintain compliance by the earlier of either 

7.2.4.1 April 30, 2008, or 

7.2.4.2 within 90 days following the next Major Overhaul, if that overhaul 

occurs after April 30, 2004. 

7.3 Tier 3 Compliance Schedule 

Owners or operators of all stationary gas turbine systems subject to Section 5.1.3 

(Tier 3) shall submit the emission control plan required by Section 6.1 to the 

District by January 1, 2009. All owner/operators shall demonstrate and maintain 

compliance with the applicable provisions of Section 4.0 on and after January 1, 

2009. All owner/operators shall demonstrate and maintain compliance with the 

applicable provisions of Sections 5.0 and 6.0 in accordance with the following 

Compliance Schedules: 

7.3.1 Operators with no more than two (2) units subject to Section 5.1.3 on 

September 20, 2007 shall demonstrate and maintain compliance by the 

earlier of either of the following dates (the compliance date for any 

particular unit shall be determined independently of any other unit): 

7.3.1.1 October 1, 2011, or 

7.3.1.2 Within 90 days following the next Major Overhaul on or after July 

1, 2009. 

7.3.2 Operators with more than two (2) units subject to Section 5.1.3 on 

September 20, 2007 shall demonstrate and maintain compliance in 

accordance with the following Compliance Schedule: 

7.3.2.1 Within 90 days following the next Major Overhaul, any unit that 

is overhauled on or after July 1, 2009, and 

7.3.2.2 By January 1, 2010, at least 25% of the total number of units on 

January 1, 2010 subject to Tier 3 Compliance Limits, and

7.3.2.3 By January 1, 2011, at least 62.5% of the total number of units on 

January 1, 2011 subject to Tier 3 Compliance Limits, and

7.3.2.4 By January 1, 2012, 100% of the total number of units on January 

1, 2012 subject to Tier 3 Compliance Limits. 

7.3.3 Operators of turbines subject to the provisions of Table 5-3, subsection (e), 

shall demonstrate and maintain compliance on and after January 1, 2008. 

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7.3.4 Permanent Removal of a Unit 

 In lieu of compliance with the emission limits of Section 5.1.3 (Tier 3), an 

owner of any unit may elect to permanently remove it from service. The 

owner of a unit who elects to permanently remove the unit from service shall 

comply with all of the following conditions: 

7.3.4.1 Comply with all applicable requirements of this rule, except for 

the Section 5.1.3 (Tier 3) limits, until the unit is permanently 

removed from service. 

7.3.4.2 Submit a letter to the APCO no later than July 1, 2009, stating the 

intent to permanently remove the unit from service. 

7.3.4.3 Officially surrender the Permit-to-Operate to the APCO no later 

than January 1, 2012. 

7.3.4.4 For the purposes of Section 7.3.4, emission reductions achieved by 

removal of a unit in lieu of compliance with the emission 

requirements of Section 5.1.3 (Tier 3) shall not be available for 

emission reduction credit (ERC). 

8.0 Alternative Emission Control Plan (AECP) 

8.1 General 

The owner of two or more units may comply with Section 5.1 (or Section 5.2 for 

CO) by controlling units in operation at the same stationary source, or at two 

contiguous stationary sources, to achieve an aggregated NOx (or CO) emission 

factor no higher than 90 percent of the aggregated NOx (or CO) emission factor limit 

that would result if each unit in operation were individually in compliance with the 

applicable NOx (or CO) emission limits in Section 5.1 (or Section 5.2 for CO). An 

operator that is subject to the AECP requirements below shall also comply with the 

applicable requirements of Sections 5.0, 6.0, and 7.0. 

8.2 Eligibility 

A unit subject to Section 5.1 is eligible for inclusion in an AECP. 

8.3 Exclusion 

No unit subject to Section 4.0 shall be included in an AECP. 

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8.4 AECP Definitions 

For the purposes of Section 8.0, the following definitions shall apply: 

8.4.1 Aggregated NOx (or CO) emission factor limit: the sum of the NOx (or CO) 

emissions, over seven consecutive calendar days, that would result if all units 

in the AECP were in compliance with the ppmvd limits in Section 5.1 and 

operating at their actual firing rates, divided by the sum of the heat input of 

all units in the AECP over seven consecutive calendar days. Aggregated 

emission factor limit is calculated as: 

F

FL L = i

ii

A

Σ

Σ

where: LA is the aggregated NOx emission factor limit (ppmvd) 

Li

 is the applicable NOx (or CO) emission factor limit (ppmvd) 

specified in Section 5.1 (or Section 5.2 for CO) for each category of 

unit in the AECP, 

Fi

 is the total heat input (hhv basis) of fuel (MMBtu) combusted in 

each unit during seven consecutive calendar days, and 

i identifies each unit in the AECP. 

8.4.2 Aggregated NOx (or CO) emission factor: the sum of the actual NOx (or 

CO) emissions during seven consecutive calendar days from all units in the 

AECP, divided by the sum of the heat input of all units in the AECP during 

seven consecutive calendar days. The aggregated emission factor is 

calculated as: 

F

FE E = i

ii

A

Σ

Σ

where: EA is the aggregated NOx (or CO) emission factor (ppmvd), 

Ei

 is the NOx (or CO) emission factor (ppmvd) for each unit in the 

AECP, established and verified by source testing or continuous 

emission monitors, 

Fi

 is the total heat input (hhv basis) of fuel (MMBtu) combusted in 

each unit during seven consecutive calendar days, and 

i identifies each unit in the AECP. 

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8.5 AECP Requirements 

8.5.1 The aggregated NOx (or CO) emission factor (EA) shall not exceed 90 

percent of the aggregated emission limit (LA). The owner of any unit in an 

AECP shall notify the APCO within 24 hours of any violation of this section. 

 EA <= 0.90 x LA 

8.5.2 Only units in the AECP which were operated during seven consecutive 

calendar days shall be included in the calculations of the aggregated NOx (or 

CO) emission factor (LA) and the aggregated NOx (or CO) emission limit 

(EA). 

8.5.3 During each seven consecutive calendar days of operation that the AECP is 

used, the operator shall calculate and record the aggregated NOx (or CO) 

emission factor (LA) and the aggregate NOx (or CO) emission limit (EA). 

8.5.4 The operator shall submit a NOx (or CO) emission factor for each unit that is 

included in the AECP. The established NOx (or CO) emission factor of the 

unit shall be no less than the emission factor of the unit from the most recent 

source test conducted pursuant to Section 6.3 and approved by the APCO. 

The operator shall not operate any AECP unit in such a manner that the NOx 

(or CO) emissions exceed the established NOx (or CO) emission factor of 

the unit. 

8.5.5 The operator shall submit the AECP, for approval by the APCO, by January 

1, 2009 or at least 18 months before compliance with the applicable emission 

limits in Section 5.1 is required pursuant to Section 7.3, whichever is later. 

The AECP shall be submitted with an application for an Authority to 

Construct pursuant to complying with Section 7.3 as applicable. The 

operator shall obtain a written approval of the AECP from the APCO prior to 

implementation. 

8.5.6 It is a violation of each and every day within the averaging period if a source 

does not meet the requirements of Section 8.5.1 of the AECP (have sufficient 

emission reductions, etc.) for that averaging period. 

8.6 AECP Administrative Requirements 

8.6.1 The AECP shall: 

8.6.1.1 Contain all data, records, and other information necessary to 

determine eligibility of the units for alternative emission control, 

including but not limited to: 

8.6.1.1.1 A list of units subject to alternative emission control, 

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8.6.1.1.2 Daily average and maximum hours of utilization for 

each unit, 

8.6.1.1.3 Rated heat input of each unit, and 

8.6.1.1.4 Fuel type for each unit. 

8.6.1.2 Present the methodology for recordkeeping and reporting required 

by Sections 8.6.3 and 8.6.4. 

8.6.1.3 Demonstrate that the aggregated emission factor will meet the 

requirements of Section 8.5. 

8.6.1.4 Demonstrate that the schedule for achieving AECP NOx (or CO) 

emission levels is at least as expeditious as the schedule if 

applicable units were to comply individually with the applicable 

emission levels in Section 5.1 (or Section 5.2 for CO) and the 

increments of progress in Section 7.0. 

8.6.2 Revision of AECP 

Owners shall demonstrate APCO approval of the AECP prior to applying for 

a modification to said AECP. 

8.6.3 AECP Recordkeeping 

In addition to the records kept pursuant to Section 6.2, the operator shall 

maintain records, on a daily basis, of the parameters needed to demonstrate 

compliance with the applicable NOx (or CO) emission limits when operating 

under the AECP. The records shall be retained for at least five years and 

shall be made available to the APCO upon request. For each unit included in 

the AECP the owner shall maintain, for each day, the records that include, 

but are not limited to, the following: 

8.6.3.1 The fuel type and amount used for each unit (Fi

), 

8.6.3.2 The actual emission factor for each unit (Ei

), 

8.6.3.3 The total emissions for all units (ΣEi

Fi), 

8.6.3.4 The aggregated emission factor (EA), 

8.6.3.5 The aggregated emission factor limit (LA), and 

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8.6.3.6 Any other parameters needed to demonstrate daily compliance with 

the applicable NOx (or CO) emissions when operating the units 

under the AECP. 

8.6.4 Reporting and Annual Updates 

Notifications of any violation pursuant to Section 8.5 shall include: 

8.6.4.1 The name and location of the facility, 

8.6.4.2 A list of applicable units, 

8.6.4.3 The cause and expected duration of exceedance, 

8.6.4.4 The amount of excess emissions, and 

8.6.4.5 The proposed corrective actions and schedule. 

8.7 Compliance Schedule 

The AECP schedule for achieving reduced NOx (or CO) emission levels shall be at 

least as expeditious as the schedule if applicable units were to comply individually 

with the emissions limits specified in Sections 5.1 and 5.2 and the applicable 

compliance schedule required by Section 7.0. 

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