SJVUAPCD 4320 - 1 10/16/08

RULE 4320 ADVANCED EMISSION REDUCTION OPTIONS FOR BOILERS, STEAM 

GENERATORS, AND PROCESS HEATERS GREATER THAN 5.0 

MMBTU/HR (Adopted October 16, 2008) 

1.0 Purpose 

 The purpose of this rule is to limit emissions of oxides of nitrogen (NOx), carbon monoxide 

(CO), oxides of sulfur (SO2

), and particulate matter 10 microns or less (PM10) from boilers, 

steam generators, and process heaters. 

2.0 Applicability 

 This rule applies to any gaseous fuel or liquid fuel fired boiler, steam generator, or process 

heater with a total rated heat input greater than 5 million Btu per hour. 

3.0 Definitions 

3.1 Air Pollution Control Officer (APCO): as defined in Rule 1020 (Definitions). 

3.2 Air Resources Board (ARB): as defined in Rule 1020 (Definitions). 

3.3 Annual Capacity Factor: the ratio of the amount of fuel burned by the unit in a 

calendar year to the amount of fuel that the unit could have burned if it had operated 

at its maximum rated capacity for 8,760 hours during the calendar year. 

3.4 Annual Heat Input: the actual, total heat input of fuels burned by a unit in a 

calendar year, as determined from the higher heating value and cumulative annual 

usage of each fuel. 

3.5 Boiler or Steam Generator: any external combustion equipment, fired with any fuel 

used to produce hot water or steam. 

3.6 British Thermal Unit (Btu): the amount of heat required to raise the temperature of 

one pound of water from 59°F to 60°F at one atmosphere. 

3.7 California Public Utility Commission (PUC) Quality Natural Gas: any gaseous fuel, 

gas-containing fuel where the sulfur content is no more than one-fourth (0.25) grain 

of hydrogen sulfide per one hundred (100) standard cubic feet and no more than five 

(5) grains of total sulfur per one hundred (100) standard cubic feet. PUC quality 

natural gas also means high methane gas of at least 80% methane by volume. 

3.8 California PUC Quality Natural Gas Curtailment: means a shortage in the supply of 

California Public Utility Commission (PUC) quality natural gas, due solely to 

supply limitations or restrictions in distribution pipelines by the utility supplying the 

gas, and not due to the cost of natural gas. 
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3.9 Dryer: any unit in which material is dried in direct contact with the products of 

combustion. 

3.10 EPA: United States Environmental Protection Agency. 

3.11 Gaseous Fuel: any fuel which is a gas at standard conditions. 

3.12 Gas Liquids Processing Facility: a facility that is engaged in the catalytic processing 

of gas liquids to produce finished products. 

3.13 Heat Input: the heat (hhv basis) released due to fuel combustion in a unit, not 

including the sensible heat of incoming combustion air and fuel. 

3.14 Higher Heating Value (hhv): the total heat liberated per mass of fuel burned 

(expressed as Btu per pound), when fuel and dry air at standard conditions undergo 

complete combustion and all resulting products are brought to their standard states 

at standard conditions. 

3.15 Liquid Fuel: any fuel which is a liquid at standard conditions. 

3.16 NOx Emissions: the sum of oxides of nitrogen expressed as NO2 in the flue gas. 

3.17 Oilfield Steam Generator: an external combustion equipment which converts water 

to dry steam or to a mixture of water vapor and steam, with an absolute pressure of 

more than 30 psia, and which is used exclusively in thermally enhanced crude oil 

production. 

3.18 Parts Per Million by Volume (ppmv): the ratio of the number of gas molecules of a 

given species, or group of species, to the number of millions of total gas molecules. 

3.19 Process Heater: any combustion equipment fired with liquid and/or gaseous fuel 

and which transfers heat from combustion gases to water or process streams. This 

definition excludes: kilns or ovens used for drying, baking, cooking, calcining, or 

vitrifying; and unfired waste heat recovery heaters used to recover sensible heat 

from the exhaust of combustion equipment. 

3.20 Qualified Technician: a stationary source employee or any personnel contracted by 

a stationary source operator who has a documented training and a demonstrated 

experience performing tune-ups on a unit to the satisfaction of the APCO. The 

documentation of tune-up training and experience shall be made available to the 

APCO upon request. 

3.21 Rated Heat Input (expressed as million Btu per hour): the heat input capacity 

specified on the nameplate of the unit. 
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3.22 Refinery Unit: a unit that is permanently installed and operated at a petroleum 

refinery or a gas liquids processing facility. 

3.23 Re-ignition: the relighting of a unit after an unscheduled and unavoidable 

interruption or shut off of the fuel flow or electrical power, for a period of less 

than 30 minutes, due to reasons outside the control of the operator. 

3.24 Seasonal Source: as defined in District Rule 2201 (New And Modified Stationary 

Source Review Rule) 

3.25 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. 

3.26 Solid Fuel: any fuel which is a solid at standard conditions. 

3.27 Small Producer: as defined in District Rule 1020 (Definitions) 

3.28 Standard Conditions: standard conditions as 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 Unit: any boiler, steam generator or process heater as defined in this rule. 

4.0 Exemptions 

 4.1 This rule shall not apply to: 

 4.1.1 Solid fuel fired units. 

 4.1.2 Dryers and glass melting furnaces. 

 4.1.3 Kilns and smelters where the products of combustion come into direct 

contact with the material to be heated. 

 

 4.1.4 Unfired or fired waste heat recovery boilers that are used to recover or 

augment heat from the exhaust of combustion turbines or internal 

combustion engines. 

 

4.2 The requirements of Sections 5.2 shall not apply to a unit when burning any fuel 

other than California PUC quality natural gas during California PUC quality natural 

gas curtailment provided all of the following conditions are met: 
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 4.2.1 Fuels other than California PUC quality natural gas are burned no more than 

168 cumulative hours in a calendar year plus 48 hours per calendar year for 

equipment testing, as limited by Permit to Operate.

4.2.2 NOx emission shall not exceed 150 ppmv or 0.215 lb/MMBtu. 

Demonstration of compliance with this limit shall be made by either source 

testing, continuous emission monitoring system (CEMS), an APCO 

approved Alternate Monitoring System, or an APCO approved portable 

NOx analyzer. 

 

5.0 Requirements 

 5.1 An operator of a unit(s) subject to this rule shall comply with all applicable 

requirements of the rule and one of the following, on a unit-by-unit basis: 

 

5.1.1 Operate the unit to comply with the emission limits specified in Sections 5.2 

and 5.4; or 

5.1.2 Pay an annual emissions fee to the District as specified in Section 5.3 and 

comply with the control requirements specified in Section 5.4; or 

5.1.3 Comply with the applicable Low-use Unit requirements of Section 5.5. 

 

5.2 NOx and CO Emission Limits 

 

5.2.1 On and after the indicated Compliance Deadline, units shall not be operated 

in a manner which exceeds the applicable NOx emissions limit specified in 

Table 1. On and after October 1, 2008, units shall not be operated in a 

manner to which exceeds a carbon monoxide (CO) emissions limit of 400 

ppmv. 

 

 5.2.2 No unit fired on liquid fuel shall be operated in a manner to exceed 

emissions of 40 ppmv NOx and 400 ppmv CO. 

5.2.3 All ppmv emission limits specified in this section are referenced at dry stack 

gas conditions and 3.00 percent by volume stack gas oxygen. Emission 

concentrations shall be corrected to 3.00 percent oxygen in accordance with 

Section 8.1. 
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Table 1: NOx Emission Limits

Category NOx Limit Authority to 

Construct 

Compliance 

Deadline 

a) Standard Schedule 

9 ppmv or 0.011 

lb/MMBtu; or 

July 1, 2011 

 

A. Units with a total rated heat July 1, 2012 

input > 5.0 MMBtu/hr to < 20.0 

MMBtu/hr, except for 

Categories C through G units 

b) Enhanced Schedule 

6 ppmv or 0.007 

lb/MMBtu 

January 1, 2013 January 1, 2014 

a) Standard Schedule 

7 ppmv or 0.008 

lb/MMBtu; or 

July 1, 2009 July 1, 2010 B. Units with a total rated heat 

input > 20.0 MMBtu/hr, except 

for Categories C through G units b) Enhanced Schedule 

5 ppmv or 0.0062 

lb/MMBtu 

January 1, 2013 January 1, 2014 

C. Oilfield Steam Generators 

a) Standard Schedule 

9 ppmv or 0.011 

lb/MMBtu; or 

July 1, 2011 July 1, 2012 1. Units with a total rated heat 

input > 5.0 MMBtu/hr to 

<20.0 MMBtu/hr b) Enhanced Schedule 

6 ppmv or 0.007 

lb/MMBtu 

January 1, 2013 January 1, 2014 

a) Standard Schedule 

7 ppmv or 0.008 

lb/MMBtu; or 

July 1, 2009 July 1, 2010 

b) Staged Enhanced 

Schedule 

Initial Limit 

9 ppmv or 0.011 

lb/MMBtu; and 

July 1, 2011 July 1, 2012 

2. Units with a total rated heat 

input >20.0 MMBtu/hr 

Final Limit 

5 ppmv or 0.0062 

lb/MMBtu 

January 1, 2013 January 1, 2014 

Staged Enhanced 

Schedule 

Initial Limit 

12 ppmv or 0.014 

lb/MMBtu; and 

July 1, 2010 July 1, 2011 

3. Units firing on less than 50%, 

by volume, PUC quality gas. 

Final Limit 

9 ppmv or 0.011 

lb/MMBtu 

January 1, 2013 January 1, 2014 
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Table 1 NOx Emission Limits (continued)

Category NOx Limit Authority to 

Construct 

Compliance 

Deadline 

D. Refinery units 

a) Standard Schedule 

9 ppmv or 0.011 

lb/MMBtu; or 

July 1, 2011 July 1, 2012 1. Units with a total rated heat 

input > 5.0 MMBtu/hr to <

20.0 MMBtu/hr b) Enhanced Schedule 

6 ppmv or 0.007 

lb/MMBtu 

January 1, 2013 January 1, 2014 

a) Standard Schedule 

6 ppmv or 0.007 

lb/MMBtu; or 

July 1, 2010 July 1, 2011 

b) Staged Enhanced 

Schedule 

Initial Limit 

9 ppmv or 0.011 

lb/MMBtu; and 

July 1, 2011 July 1, 2012 

2. Units with a total rated heat 

input >20.0 MMBtu/hr to < 

110.0 MMBtu/hr 

Final Limit 

5 ppmv or 0.0062 

lb/MMBtu 

January 1, 2013 January 1, 2014 

3. Units with a total rated heat 

input > 110.0 MMBtu/hr 

Standard Schedule 

5 ppmv or 0.0062 

lb/MMBtu 

N/A June 1, 2007 

Staged Enhanced 

Schedule 

Initial Limit 

12 ppmv or 0.014 

lb/MMBtu; and 

July 1, 2010 July 1, 2011 

4. Units firing on less than 50%, 

by volume, PUC quality gas. 

Final Limit 

9 ppmv or 0.011 

lb/MMBtu 

January 1, 2013 January 1, 2014 

E. Units, from any Category, that 

were installed prior to January 1, 

2009 and limited by a Permit to 

Operate to an annual heat input 

>1.8 billion Btu/year but < 30 

billion Btu/year. 

Standard Schedule 

9 ppmv or 0.011 

lb/MMBtu 

Twelve months 

before the next unit 

replacement but no 

later than January 

1, 2013. 

At the next unit 

replacement but 

no later than 

January 1, 2014 
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Table 1 NOx Emission Limits (continued)

Category NOx Limit Authority to 

Construct 

Compliance 

Deadline 

Staged Enhanced 

Schedule 

Initial Limit 

12 ppmv or 0.014 

lb/MMBtu; and 

July 1, 2010 July 1, 2011 F. Units at a wastewater treatment 

facility firing on less than 50%, 

by volume, PUC quality gas. 

Final Limit 

9 ppmv or 0.011 

lb/MMBtu 

January 1, 2013 January 1, 2014 

G. Units operated by a small 

producer in which the rated 

heat input of each burner is 

less than or equal to 5 

MMBtu/hr but the total rated 

heat input of all the burners in 

a unit is rated between 5 

MMBtu/hr and 20 MMBtu/hr, 

as specified in the Permit to 

Operate, and in which the 

products of combustion do not 

come in contact with the 

products of combustion of any 

other burner.

Standard Schedule 

9 ppmv or 0.011 

lb/MMBtu 

Twelve months 

before the next unit 

replacement but no 

later than January 

1, 2013. 

At the next unit 

replacement but 

no later than 

January 1, 2014 

5.2.4 When a unit is operated on combinations of gaseous fuel and liquid fuel, the 

NOx limit shall be the heat input weighted average of the applicable limits 

specified in Sections 5.1.1, as calculated by the following equation: 

G L

(NOx limitfor gaseousfuel x G) (NOx limitforliquid fuel x )L Weighted AverageLimit

+

+

=

 Where: G = annual heat input from gaseous fuel 

L = annual heat input from liquid fuel 

5.2.5 Prior to January 1, 2014, if a unit was designated to comply with a Staged 

Enhanced Schedule, an operator may redesignate the unit for compliance 

under Section 5.1.2, provided the unit meets the Initial NOx Limit; 

emission fees are paid, at time of the application for redesignation, for all 

past emissions from the unit since January 1, 2009 through the calendar 

year prior to the calculation date; and the total annual fee is paid from that 

date forward. The past emissions fee shall be calculated using the 

equations in Section 5.3 and the Fee Rate in place at the time of that 
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calculation. The future total annual fees shall be calculated and paid 

according to Section 5.3. 

 

5.3 Annual Fee Calculation 

5.3.1 On and after January 1, 2010, an operator, with units that will comply under 

Section 5.1.2, shall pay a total annual fee to the District based on the total 

NOx emissions from those units. That fee shall be calculated in the 

following manner. 

5.3.1.1 The operator shall calculate the total emissions for all units 

operating at a stationary source that will comply with Section 

5.1.2. The total NOx emissions shall be calculated in accordance 

with Section 5.3.1.3. 

5.3.1.2 The total annual emissions fee shall be calculated in accordance 

with Section 5.3.1.4. These calculations include only the units that 

have been identified to comply under Section 5.1.2.

 5.3.1.3 Total Emissions (TE) Calculation 

 

Total TE = ∑E(unit) 

Where: ∑E(unit) = Sum of all NOx emissions from each unit, in tons 

per year. 

E(unit) = 

lb per ton

EF Unit x AFU Unit

,2 000

( ) ( )

Where: E(unit) = Annual NOx emissions for each unit, in tons/year. 

EF(Unit) = NOx Emission Limit for the Permit to Operate, in 

lb/MMBtu 

AFU(Unit) = actual amount of fuel, in MMBTU, used by each 

unit during the previous calendar year. 

5.3.1.4 Total Annual Fee Calculation 

 Total Annual Fee = (Total TE x FR) + Administrative Fee 

Where: FR (Fee Rate) = The cost of NOx reductions, in dollars per ton, 

as established pursuant to Sections 7.2 and 7.6 

of District Rule 9510, as adopted on December 

15, 2005. Under no circumstances shall the cost 

of NOx reductions exceed the cost effectiveness 
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threshold for the Carl Moyer Cost Effectiveness 

as established by the applicable state law. 

 Administrative Fee = 4% x (Total TE x FR) 

 

5.3.1.5 The operator shall pay the total annual fee to the District, no later 

than July 1 of each year, for the emissions of the previous calendar 

year. The first payment is due to the District no later than July 1, 

2010. Should July 1 fall on a day when the District is closed, the 

payment shall be made by the next District working day after July 

1. 

5.3.2 Payments shall continue annually until the unit either is permanently 

removed from use in the San Joaquin Valley Air Basin and the Permit to 

Operate is surrendered or the operator demonstrates compliance with 

applicable NOx emissions limits shown in Table 2: 

Table 2 Applicable NOx Emission Limits for Section 5.3.2

Category Date of Compliance 

Demonstration 

Applicable NOx Emissions 

Limit from Table 1 

A. Units with only a Standard 

Schedule in Table 1. 

Either prior to or after 

the Standard 

Compliance Deadline 

Standard NOx Limit 

Prior to the Enhanced 

Compliance Deadline Standard NOx Limit 

B. Units with both Standard and 

Enhanced Schedules in Table 

1. After the Enhanced 

Compliance Deadline Enhanced NOx Limit 

Prior to the Initial Limit 

Compliance Deadline Standard NOx Limit 

After the Initial Limit 

Deadline but before the 

Final Limit Deadline 

Initial NOx Limit then 

the Final NOx Limit by 

the applicable 

Compliance Deadline 

C. Units with both Standard 

and Staged Enhanced 

Schedules in Table 1. 

After the Final Limit 

Deadline Final NOx Limit 

5.3.2.1 The emissions fee for units that operate for less than the full 

calendar year before demonstrating compliance under Section 

5.3.2, shall be based on the actual fuel used during the portion of 

the calendar year prior to demonstrating that compliance or 
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removing the unit from operation within the San Joaquin Valley 

Air Basin. 

5.3.3 Operators of units for which an annual emissions fee is provided must also 

certify that the units meet federal RACT control requirements at the time the 

annual fee is provided. 

 

5.4 Particulate Matter Control Requirements 

 5.4.1 To limit particulate matter emissions, an operator shall comply with one of 

the following requirements: 

 

5.4.1.1 On and after the applicable NOx Compliance Deadline specified 

in Section 5.2 Table 1, operators shall fire units exclusively on 

PUC-quality natural gas, commercial propane, butane, or 

liquefied petroleum gas, or a combination of such gases; 

 

5.4.1.2 On and after the applicable NOx Compliance Deadline specified 

in Section 5.2 Table 1, operators shall limit fuel sulfur content to 

no more than five (5) grains of total sulfur per one hundred 

(100) standard cubic feet; or 

 5.4.1.3 On and after the applicable NOx Compliance Deadline specified 

in Section 5.2 Table 1, operators shall install and properly 

operate an emission control system that reduces SO2 emissions 

by at least 95% by weight; or limit exhaust SO2 to less than or 

equal to 9 ppmv corrected to 3.0% O2. 

5.4.1.4 Notwithstanding the compliance deadlines indicated in Sections 

5.4.1.1 through 5.4.1.3, refinery units, which require 

modification of refinery equipment to reduce sulfur emissions, 

shall be in compliance with the applicable requirement in 

Section 5.4.1 no later than July 1, 2013. 

 

5.4.2 Liquid fuel shall be used only during PUC quality natural gas curtailment 

periods, provided the requirements of Sections 4.2 and 6.1.5 are met and the 

fuel contains no more than 15 ppm sulfur, as determined by the test method 

specified in Section 6.2. 
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5.5 Low-use Unit 

 For each unit that was installed prior to January 1, 2009 and is limited to less than or 

equal to 1.8 billion Btu per calendar year heat input pursuant to a District Permit to 

Operate, the operator shall comply with the requirement of Sections 5.7 and 7.3 and 

one of the following: 

 5.5.1 Tune the unit at least twice per calendar year, (from four to eight months 

apart) by a qualified technician in accordance with the procedure described 

in Rule 4304 (Equipment Tuning Procedure for Boilers, Steam Generators, 

and Process Heaters). If the unit does not operate throughout a continuous 

six-month period within a calendar year, only one tune-up is required for 

that calendar year. No tune-up is required for any unit that is not operated 

during that calendar year; this unit may be test fired to verify availability of 

the unit for its intended use, but once the test firing is completed the unit 

shall be shutdown; or 

 

 5.5.2 Operate the unit in a manner that maintains exhaust oxygen concentrations 

at less than or equal to 3.00 percent by volume on a dry basis. 

 

5.6 Start-up and Shutdown Provision 

On and after the Compliance Deadline specified in Section 5.0, the applicable 

emission limits of Sections 5.2 Table 1 and 5.5.2 shall not apply during start-up or 

shutdown, provided an operator complies with the requirements specified below. 

5.6.1 The duration of each start-up or each shutdown shall not exceed two hours, 

except as provided in Section 5.6.3. 

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

minimized insofar as technologically feasible during start-up or shutdown. 

5.6.3 Notwithstanding the requirement of Section 5.6.1, an operator may submit 

an application for a Permit to Operate condition to allow more than two 

hours for each start-up or each shutdown provided the operator meets all of 

the conditions specified in Sections 5.6.3.1 through 5.6.3.3. 

5.6.3.1 The maximum allowable duration of start-up or shutdown will 

be determined by the APCO. The allowable duration of start-up 

shall not exceed twelve hours and the allowable duration of 

shutdown shall not exceed nine hours. 

5.6.3.2 The APCO will only approve start-up or shutdown duration 

longer than two hours when the application meets the following 

conditions: 
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 5.6.3.2.1 Clearly identifies the control technologies or 

strategies to be utilized; and 

 

 5.6.3.2.2 Describes what physical conditions prevail during 

start-up or shutdown periods that prevent the 

controls from being effective; and 

 

 5.6.3.2.3 Provides a reasonably precise estimate as to when 

the physical conditions will have reached a state 

that allows for the effective control of emissions. 

 5.6.3.3 The operator shall submit to the APCO any information deemed 

necessary by the APCO to determine the appropriate length of 

start-up or shutdown. The information shall include, but is not 

limited to the following: 

 

5.6.3.3.1 A detailed list of activities to be performed during 

start-up or shutdown and a reasonable explanation 

for the length of time needed to complete each 

activity; and 

 5.6.3.3.2 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 

 5.6.3.3.3 The basis for the requested additional duration of 

start-up or shutdown. 

 5.6.4 Permit to Operate (PTO) modifications solely to conditions to comply 

with the provisions of this rule may be exempt from Best Available 

Control Technology (BACT) and emission offset requirements if the PTO 

modifications meet the requirements of Rule 2201 (New and Modified 

Stationary Source Review Rule) Section 4.2 (BACT Exemptions) and 

Rule 2201 Section 4.6 (Emission Offset Exemptions).

5.6.5 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. 

 5.7 Monitoring Provisions 

 
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 5.7.1 The operator of any unit subject to the applicable emission limits in Sections 

5.2 shall install and maintain an operational APCO approved Continuous 

Emissions Monitoring System (CEMS) for NOx, CO, and oxygen, or 

implement an APCO-approved Alternate Monitoring System. An APCO 

approved CEMS shall comply with the requirements of 40 Code of Federal 

Regulations (CFR) Part 51, 40 CFR Parts 60.7 and 60.13 (except subsection 

h), 40 CFR Part 60 Appendix B (Performance Specifications) and 40 CFR 

Part 60 Appendix F (Quality Assurance Procedures), and applicable 

provisions of Rule 1080 (Stack Monitoring). An APCO-approved Alternate 

Monitoring System shall monitor one or more of the following: 

 5.7.1.1 Periodic NOx and CO exhaust emission concentrations, 

 5.7.1.2 Periodic exhaust oxygen concentration, 

 5.7.1.3 Flow rate of reducing agent added to exhaust, 

 5.7.1.4 Catalyst inlet and exhaust temperature,

5.7.1.5 Catalyst inlet and exhaust oxygen concentration, 

5.7.1.6 Periodic flue gas recirculation rate, or 

5.7.1.7 Other operational characteristics. 

 

5.7.2 For units subject to the requirements of Sections 5.5.1 or 5.5.2, the operator 

shall monitor, at least on a monthly basis, the operational characteristic(s) 

recommended by the manufacturer and approved by the APCO. 

5.7.3 The operator of any unit subject to Section 5.5 shall install and maintain an 

operational non-resettable, totalizing mass or volumetric flow meter in each 

fuel line to each unit. Volumetric flow measurements shall be periodically 

compensated for temperature and pressure. A master meter, which measures 

fuel to all units in a group of similar units, may satisfy these requirements if 

approved by the APCO in writing. The cumulative annual fuel usage may 

be verified from utility service meters, purchase or tank fill records, or other 

acceptable methods, as approved by the APCO. 

5.7.4 Units operated at seasonal sources that are subject to the requirements of 

40 CFR 60, Subpart Db (Standards of Performance for IndustrialCommercial-Institutional Steam Generating Units) may implement an 

APCO approved parametric monitoring system (PMS) in lieu of a CEMS 

for compliance with federal emission limits provided all of the following 

apply: 

5.7.4.1 The boiler is fired solely on California PUC quality natural gas, 

and 

5.7.4.2 The applicable District emission limit for NOx is more 

stringent than the limit specified in 40 CFR Part 60, Subpart 

Db. 

5.7.5 The APCO shall not approve an alternative monitoring system or 

parametric monitoring system unless it is documented that continued 
SJVUAPCD 4320 - 14 10/16/08

operation within ranges of specified emissions-related performance 

indicators or operational characteristics provides a reasonable assurance of 

compliance with applicable emission limits. The operator shall source test 

over the proposed range of surrogate operating parameters to demonstrate 

compliance with the applicable emission standards.

5.7.5.1 The predictive or parametric monitoring system shall 

continuously monitor the key parameters which affect the 

emissions and demonstrate the compliance within the established 

key parameters operating envelope. 

5.7.5.2 Initial and annual real time modeling shall be performed to verify 

the key parameters operational range. 

5.7.6 Monitoring SOx Emissions 

5.7.6.1 Operators complying with Sections 5.4.1.1 or 5.4.1.2 shall 

provide an annual fuel analysis to the District unless a more 

frequent sampling and reporting period is included in the Permit 

To Operate. Sulfur analysis shall be performed in accordance 

with the test methods in Section 6.2. 

5.7.6.2 Operators complying with Section 5.4.1.3 by installing and 

operating a control device with 95% SOx reduction shall 

propose the key system operating parameters and frequency of 

the monitoring and recording. The monitoring option proposed 

shall be submitted for approval by the APCO. 

5.7.6.3 Operators complying with Section 5.4.1.3 shall perform an 

annual source test unless a more frequent sampling and 

reporting period is included in the Permit To Operate. Source 

tests shall be performed in accordance with the test methods in 

Section 6.2. 
SJVUAPCD 4320 - 15 10/16/08

5.8 Compliance Determination 

 

 5.8.1 The operator of any unit shall have the option of complying with either the 

applicable heat input, in lb/MMBtu, emission limits or the concentration, in 

ppmv, emission limits specified in Section 5.2. The emission limits selected 

to demonstrate compliance shall be specified in the source test proposal 

pursuant to Rule 1081 (Source Sampling). 

5.8.2 All emissions measurements shall be made with the unit operating either at 

conditions representative of normal operations or conditions specified in the 

Permit to Operate. Unless otherwise specified in the Permit to Operate, no 

determination of compliance shall be established within two hours after a 

continuous period in which fuel flow to the unit is shut off for 30 minutes or 

longer, or within 30 minutes after a re-ignition as defined in Section 3.0. 

 

 5.8.3 Continuous Emissions Monitoring System (CEMS) emissions 

measurements shall be averaged over a period of 15 consecutive minutes to 

demonstrate compliance with the applicable emission limits. Any 15-

consecutive-minute block average CEMS measurement exceeding the 

applicable emission limits shall constitute a violation. 

5.8.4 For emissions monitoring pursuant to Sections 5.7.1, and 6.3.1 using a 

portable NOx analyzer as part of an APCO approved Alternate Emissions 

Monitoring System, emission readings shall be averaged over a 15 

consecutive-minute period by either taking a cumulative 15-consecutiveminute sample reading or by taking at least five readings evenly spaced out 

over the 15-consecutive-minute period. 

 

5.8.5 For emissions source testing performed pursuant to Section 6.3.1 for the 

purpose of determining compliance with an applicable standard or numerical 

limitation of this rule, the arithmetic average of three 30-consecutive-minute 

test runs shall apply. If two of three runs are above an applicable limit the 

test cannot be used to demonstrate compliance with an applicable limit. 

6.0 Administrative Requirements 

 6.1 Recordkeeping 

 The records required by Sections 6.1.1 through 6.1.5 shall be maintained for five 

calendar years and shall be made available to the APCO and EPA upon request. 

Failure to maintain records or information contained in the records that demonstrate 

noncompliance with the applicable requirements of this rule shall constitute a 

violation of this rule. 

 6.1.1 The operator of any unit operated under the exemption of Section 4.2 shall 

monitor and record, for each unit, the cumulative annual hours of operation 

on each fuel other than natural gas during periods of natural gas curtailment 
SJVUAPCD 4320 - 16 10/16/08

and equipment testing. The NOx emission concentration, expressed in 

ppmv or lb/MMBtu, for each unit that is operated during periods of natural 

gas curtailment shall be recorded. Failure to maintain records required by 

Section 6.1.1 or information contained in the records that demonstrates 

noncompliance with the conditions for exemption under Section 4.2 will 

result in loss of exemption status. On and after the applicable compliance 

schedule specified in Section 5.2 Table 1, any unit losing an exemption 

status shall be brought into full compliance with this rule as specified in 

Section 7.2. 

 6.1.2 The operator of any unit that is subject to the requirements of Section 5.5 

shall record the amount of fuel use at least on a monthly basis for each unit. 

On and after the applicable compliance schedule specified in Section 7.0, in 

the event that such unit exceeds the applicable annual heat input limit 

specified in Section 5.5, the unit shall be brought into full compliance with 

this rule as specified in Section 5.2 Table 1. 

 

 6.1.3 The operator of any unit subject to Section 5.5.1 or Section 6.3.1 shall 

maintain records to verify that the required tune-up and the required 

monitoring of the operational characteristics of the unit have been 

performed. 

 

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

the duration of start-up or shutdown. 

6.1.5 The operator of any unit firing on liquid fuel during a PUC-quality natural 

gas curtailment period pursuant to Section 5.4.2 shall record the sulfur 

content of the fuel, amount of fuel used, and duration of the natural gas 

curtailment period. 

 

6.2 Test Methods 

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

and EPA. 

 

 6.2.1 Fuel hhv shall be certified by third party fuel supplier or determined by: 

 6.2.1.1 ASTM D 240-87 or D 2382-88 for liquid hydrocarbon fuels; 

 6.2.1.2 ASTM D 1826-88 or D 1945-81 in conjunction with ASTM D 

3588-89 for gaseous fuels. 

 6.2.2 Oxides of nitrogen (ppmv) - EPA Method 7E, or ARB Method 100. 

 6.2.3 Carbon monoxide (ppmv) - EPA Method 10, or ARB Method 100. 

 6.2.4 Stack gas oxygen - EPA Method 3 or 3A, or ARB Method 100. 

 6.2.5 NOx Emission Rate (Heat Input Basis) - EPA Method 19. 
SJVUAPCD 4320 - 17 10/16/08

 6.2.6 Stack gas velocities - EPA Method 2. 

 6.2.7 Stack gas moisture content - EPA Method 4. 

6.2.8 SOx Test Methods 

6.2.8.1 Oxides of sulfur – EPA Method 6C, EPA Method 8, or ARB 

Method 100 

6.2.8.2 The SOx emission control system efficiency shall be determined 

using the following: 

% Control Efficiency = [(CSO2, inlet – CSO2, outlet) / CSO2, inlet] X 100 

Where: 

CSO2, inlet = concentration of SOx (expressed as SO2

) at the inlet 

side of the SOx emission control system, in 

lb/dscf 

CSO2, outlet = concentration of SOx (expressed as SO2) at the 

outlet side of the SOx emission control system, in 

lb/dscf 

6.2.9 Determination of total sulfur as hydrogen sulfide (H2S) content – EPA 

Method 11 or EPA Method 15, as appropriate. 

6.2.10 Sulfur content of liquid fuel – American Society for Testing and Materials 

(ASTM) D 6920-03 or ASTM D 5453-99 

6.3 Compliance Testing 

 6.3.1 Each unit subject to the requirements in Section 5.2 shall be source tested to 

determine compliance with the applicable emission limits at least once every 

12 months, (no more than 30 days before or after the required annual source 

test date). 

6.3.1.1 Units that demonstrate compliance on two consecutive 12-month 

source tests may defer the following 12-month source test for up to 

36 months (no more than 30 days before or after the required 36-

month source test date). During the 36-month source testing 

interval, the operator shall tune the unit in accordance with the 

provisions of Section 5.5.1, and shall monitor, on a monthly basis, 

the unit’s operational characteristics recommended by the 

manufacturer to ensure compliance with the applicable emission 

limits specified in Section 5.2. 
SJVUAPCD 4320 - 18 10/16/08

6.3.1.2 Tune-ups required by Sections 5.5.1 and 6.3.1 do not need to be 

performed for units that operate and maintain an APCO approved 

CEMS or an APCO approved Alternate Monitoring System where 

the applicable emission limits are periodically monitored. 

6.3.1.3 If the result of the 36-month source test demonstrates that the unit 

does not meet the applicable emission limits specified in Section 

5.2, the source testing frequency shall revert to at least once every 

12 months. 

6.3.1.4 Failure to comply with the requirements of Section 6.3.1 or any 

source test results that exceed the applicable emission limits in 

Section 5.2 shall constitute a violation of this rule. 

6.3.2 In lieu of compliance with Section 6.3.1, compliance with the applicable 

emission limits in Section 5.2 shall be demonstrated by submittal of annual 

emissions test results to the District from a unit or units that represents a 

group of units, provided: 

 

 6.3.2.1 All units in the group are initially source tested. The emissions 

from all test runs from units within the group are less than 90% 

of the permitted value, and the emissions do not vary greater than 

25% from the average of all test runs; and 

 6.3.2.2 All units in a group are similar in terms of rated heat input, make 

and series, operational conditions, fuel used, and control method. 

No unit with a rated heat input greater than 100 MMBtu shall be 

considered as part of the group; and 

 6.3.2.3 The group is owned by a single owner and is located at a single 

stationary source; and 

 6.3.2.4 Selection of the representative unit(s) is approved by the APCO 

prior to testing; and 

 

 6.3.2.5 The number of representative units source tested shall be at least 

30% of the total number of units in the group. The

representative tests shall rotate each year so that within three 

years all units in the group have been tested at least once. 

 

6.3.2.6 All units in the group shall have received the similar 

maintenance and tune-up procedures as the representative unit(s) 

as listed in the Permit to Operate. The operator shall submit to 

the APCO the specific maintenance procedures to be performed 

on each unit that will be included in the group for representative 

testing. Such maintenance procedures shall be specified in the 
SJVUAPCD 4320 - 19 10/16/08

Permit to Operate for units that are included in the group for 

representative testing. Any maintenance work on a unit which 

has no effect on emissions standards and which is not specified 

in the maintenance procedures shall be submitted to the APCO 

for approval before such unit can be included as part of the group 

for representative testing. Any unit that necessitates any 

maintenance work which has an effect on emission standards and 

is beyond the maintenance procedures identified in the Permit to 

Operate, shall not be included as part of the group for 

representative testing. The unit shall be source tested in 

accordance with the provisions of Section 6.3.1; and 

 6.3.2.7 Should any of the representative units exceed the required 

emission limits, each of the units in the group shall demonstrate 

compliance by emissions testing. Failure to complete emissions 

testing within 90 days of the failed test shall result in the untested 

units being in violation of this rule. After compliance with the 

requirements of Section 6.3.2.7 has been demonstrated, 

subsequent source testing shall be performed pursuant to 

Sections 6.3.1 or 6.3.2. 

 6.4 Emission Control Plan (ECP) 

 6.4.1 No later than January 1, 2010, the operator of any unit shall submit to the 

APCO for approval an Emissions Control Plan according to the compliance 

schedule in Section 7.0. For each unit, the plan shall contain the following: 

 

 6.4.1.1 Permit to Operate number, 

 6.4.1.2 Fuel type and hhv, 

 6.4.1.3 Annual fuel consumption (expressed as Btu/yr), 

6.4.1.4 Current emission level, including method used to determine 

 emission level, 

6.4.1.5 NOx limit to be satisfied pursuant to Section 5.2 Table 1 or 

emission fee payment to be made pursuant to Section 5.3, and 

 6.4.1.6 Plan of actions, including a schedule of increments of progress, 

which will be taken to satisfy the requirements of Section 5.0 and 

the compliance schedule in Section 7.0. 
SJVUAPCD 4320 - 20 10/16/08

7.0 Compliance Schedule 

7.1 As shown in Section 5.2 Table 1, the column labeled: 

 7.1.1 “Authority to Construct” identifies the date by with the operator shall submit 

an Application for Authority to Construct for each unit subject to the rule. 

 

 7.1.2 “Compliance Deadline” identifies the date by which the owner shall 

demonstrate that each unit is in compliance with the applicable requirements 

of this rule. 

 7.2 Any unit that is exempted under Section 4.2 that becomes subject to the emission 

limits of this rule through the loss of exemption status shall be in full compliance 

with this rule on and after the date the exemption status is lost. 

 7.3 Any unit that becomes subject to the emission limits of this rule as a result of 

exceeding the applicable annual heat input limit specified in Section 5.5 shall be in 

compliance with the applicable emission limits in Section 5.2 Table 1 and Section 

5.4 on and after the date the annual heat input limit is exceeded. 

8.0 Calculations 

 8.1 All ppmv emission limits specified in Section 5.2 are referenced at dry stack gas 

conditions and 3.00 percent by volume stack gas oxygen. Emission concentrations 

shall be corrected to 3.00 percent oxygen as follows: 

measured

measured

corrected x [ppm NOx]

20 95. % [%O ]2

17 95. %

[ppm NOx]

−

= 

measured

measured

corrected x [ppmCO]

20 95. % [%O ]2

17 95. %

[ppmCO]

−

= 

 8.2 All pounds per million Btu NOx emission rates shall be calculated as pounds of 

nitrogen dioxide per million Btu of heat input (expressed as hhv).