SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT

(Adopted October 5, 1990)(Amended July 10, 1992)(Amended May 13, 1994)

RULE 1146.1. EMISSIONS OF OXIDES OF NITROGEN FROM 

SMALL INDUSTRIAL, INSTITUTIONAL, AND COMMERCIAL 

BOILERS, STEAM GENERATORS, AND PROCESS HEATERS 

(a) Definitions 

1. ANNUAL HEAT INPUT means the actual amount of heat released by 

fuels burned in a unit during a calendar year, based on the fuel's higher 

heating value. 

2. BOILER OR STEAM GENERATOR means any combustion equipment 

fired with liquid and/or gaseous and/or solid fossil fuel, used to produce 

steam or to heat water, and that is not used exclusively to produce 

electricity for sale. Boiler or Steam Generator does not include any waste 

heat recovery boiler that is used to recover sensible heat from the exhaust 

of a combustion turbine or any unfired waste heat recovery boiler that is 

used to recover sensible heat from the exhaust of any combustion 

equipment. 

3. BTU means British thermal unit or units. 

4. NO

x

EMISSIONS means the sum of nitric oxide and nitrogen dioxide in 

the flue gas, collectively expressed as nitrogen dioxide. 

5. PROCESS HEATER means any combustion equipment fired with liquid 

and/or gaseous and/or solid fossil fuel and which transfers heat from 

combustion gases to water or process streams. Process Heater does not 

include any kiln or oven used for drying, curing, baking, cooking, 

calcining, or vitrifying; or any unfired waste heat recovery heater that is 

used to recover sensible heat from the exhaust of any combustion 

equipment. 

6. RATED HEAT INPUT CAPACITY means the heat input capacity 

specified on the nameplate of the combustion unit. If the combustion unit 

has been altered or modified such that its maximum heat input is different 

than the heat input capacity specified on the nameplate, the new 

maximum heat input shall be considered as the rated heat input capacity. 

7. THERM means 100,000 Btu. 

8. UNIT means any boiler, steam generator, or process heater as defined in 

paragraph (a)(2) or (a)(5). 

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(b) Applicability 

This rule applies to boilers, steam generators, and process heaters that are 

greater than 2 million Btu per hour and less than 5 million Btu per hour rated 

heat input capacity used in any industrial, institutional, or commercial 

operation. 

(c) Requirements 

1. The owner or operator of any unit subject to subdivision (b) shall operate 

such unit so that it discharges into the atmosphere no more than 30 ppm 

of NO

x

emissions or 0.037 pound NO

x

per million Btu of heat input, as 

specified in the permit to operate and no more than 400 ppm of carbon 

monoxide. For each unit, a selection must be indicated in the application 

for permit to construct and operate between the ppm NO

x

or pounds of 

NO

x

per million BTU heat input compliance option. 

2. Any unit(s) subject to subdivision (b), and with an annual heat input of 

less than or equal to 18,000 therms per calendar year, shall: 

(A) be operated in a manner that maintains stack-gas oxygen 

concentrations at less than or equal to 3 percent on a dry basis for any 15-

consecutive-minute averaging period; or 

(B) be tuned at least twice per year, (at intervals from 4 to 8 months 

apart) in accordance with the procedure described in Attachment 1 or the 

unit manufacturer's specified tuneup procedure. If a different tuneup 

procedure from that described in attachment 1 is used then a copy of this 

procedure shall be kept on site. If the unit does not operate throughout a 

continuous six-month period within a calendar year, only one tuneup is 

required for that calendar year. The owner or operator of any unit(s) who 

chooses to comply with subparagraph (c)(2)(B) shall maintain a record 

for a period of two years verifying that the tuneup has been performed. 

No tune-up is required during a calendar year 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 test firing is 

completed it shall be shutdown. Records of test firings shall be 

maintained for a period of two years, and shall be made accessible upon 

request from an authorized District representative; or

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(C) meet the emission limits specified in paragraph (c)(1). 

3. The owner or operator of any unit(s) subject to paragraph (c)(2) shall 

submit and have approved by the Executive Officer, a compliance plan 

that demonstrates compliance with paragraph (c)(2). Such plan shall 

contain: 

(A) A list of permits of all units with the rated heat input capacity, 

anticipated annual heat input; and 

(B) For each unit listed, a selection of one of the three options specified 

in paragraph (c)(2) to achieve compliance with this rule; and 

(C) Non-resettable, totalizing fuel meter(s) specifications; date of 

installation; and recorded fuel usage since installation. 

4. Any owner or operator who chooses the pound per million Btu of heat 

input compliance option in paragraph (c)(1) shall install a non-resettable, 

totalizing fuel meter for each fuel used on an individual unit basis, as 

approved by the Executive Officer. 

(d) Compliance Determination 

1. Owners or operators of any units shall have the option of complying with 

either the pound per million Btu of heat input or parts per million 

emission limits specified in paragraphs (c)(1) and (c)(2)(C). 

2. All emission determinations shall be made in the as-found operating 

condition, except no compliance determination shall be established 

during unit start up, shutdown, or under breakdown conditions. Start up 

or shutdown intervals shall not last longer than is necessary to reach 

stable temperatures. In no case shall the start up or shutdown interval last 

longer than six hours or the time specified in the permit to operate, 

whichever is less. Start-ups and shutdowns shall not last longer than is 

necessary to reach stable conditions. 

3. All parts per million emission limits specified in paragraph (c)(1) are 

referenced at 3 percent volume stack-gas oxygen on a dry basis averaged 

over a period of 15 consecutive minutes. 

4. Compliance with the NO

x

and CO emission requirements of paragraph 

(c)(1) and the stack-gas oxygen concentration requirement of paragraph 

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(c)(2)(A) shall be determined according to procedures in District Source 

Test Method 100.1 - Instrumental Analyzer Procedures for Continuous 

Gaseous Emission Sampling (March 1989), or Method 7.1 - 

Determination of Nitrogen Oxide Emissions from Stationary Sources 

(March 1989) and Method 10.1 - Carbon Monoxide and Carbon Dioxide 

by Gas Chromatograph/Non-Dispersive Infrared Detector (GC/NDIR) - 

Oxygen by Gas Chromatograph-Thermal Conductivity (GC/TCD) 

(March 1989), or any other test method determined to be equivalent and 

approved before the test in writing by the Executive Officers of the 

District and the California Air Resources Board and the Regional 

Administrator of the United States Environmental Protection Agency, 

Region IX. Records of all source tests shall be maintained for a period of 

two years and shall be made available to District personnel upon request. 

Emissions determined to exceed any limits established by this rule 

through the use of any of the above-referenced test methods shall 

constitute a violation of this rule. 

5. For any owner or operator who chooses the pounds of NO

x

per million 

Btu of heat input compliance option of paragraph (c)(1), NO

x

emissions 

in pounds per million Btu of heat input shall be calculated using the 

procedures in 40 CFR Part 60, Appendix A, Method 19, Sections 2 and 3. 

(e) Compliance Schedule 

The owner or operator of units subject to this rule shall meet the following 

increments of progress: 

1. For owners or operators of units subject to paragraph (c)(1) shall: 

(A) By January 1, 1993, submit required applications for permits to 

construct and operate, and 

(B) By July 1, 1994, demonstrate compliance with paragraph (c)(1). 

2. For owners or operators of units subject to paragraph (c)(2) shall: 

(A) By January 1, 1993, submit a plan pursuant to paragraph (c)(3), and 

(B) By December 31, 1993, demonstrate compliance with paragraph (c)

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(2). 

(f) Exemption 

The provisions of paragraph (c)(1) shall not apply provided the owner or 

operator: 

1. Installs by January 1, 1992, or at the time the permit to construct for the 

unit is issued, a non-resettable, totalizing fuel meter for each fuel that 

demonstrates that the unit(s) operate with an annual heat input at or 

below 18,000 therms per calendar year; and 

2. Has available for inspection by the Executive Officer by February 1 of 

each year, records listing cumulative annual usage of each fuel for the 

preceding calendar year. Records shall be maintained and made 

accessible to the Executive Officer or authorized District representative 

for a period of two years; and 

3. Demonstrates compliance with the requirements specified in 

subparagraphs (c)(2)(A) or (c)(2)(B), and (c)(3). 

(g) Loss of Exemption 

If any unit subject to a compliance plan submitted pursuant to paragraph (c)(3) 

exceeds 18,000 therms of annual heat input in any calendar year after 1992, 

the owners or operators shall: 

1. Within 4 months after the end of the calendar year during which the unit 

exceeded 18,000 therms of annual heat input, submit required 

applications for permits to construct and operate; and 

2. Within 18 months after the end of the calendar year during which the unit 

exceeded 18,000 therms of annual heat input, demonstrate and maintain 

compliance with paragraph (c)(1) for the life of the unit; and 

3. Maintain compliance with requirements of paragraph (c)(2) until 

compliance with paragraph (c)(1). 

ATTACHMENT 1 

A. Equipment Tuning Procedure

1

for Forced-Draft Boilers, Steam 

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Generators, and Process Heaters 

Nothing in this Equipment Tuning Procedure shall be construed to require any 

act or omission that would result in unsafe conditions or would be in violation 

of any regulation or requirement established by Factory Mutual, Industrial 

Risk Insurers, National Fire Prevention Association, the California 

Department of Industrial Relations (Occupational Safety and Health 

Division), the Federal Occupational Safety and Health Administration, or 

other relevant regulations and requirements. 

1. Operate the unit at the firing rate most typical of normal operation. If the 

unit experiences significant load variations during normal operation, 

operate it at its average firing rate. 

2. At this firing rate, record stack gas temperature, oxygen concentration, 

and CO concentration (for gaseous fuels) or smoke-spot number

2

(for 

liquid fuels), and observe flame conditions after unit operation stabilizes 

at the firing rate selected. If the excess oxygen in the stack gas is at the 

lower end of the range of typical minimum values

3

, and if CO emissions 

are low and there is not smoke, the unit is probably operating at near 

optimum efficiency - at this particular firing rate. 

3. Increase combustion air flow to the furnace until stack gas oxygen levels 

increase by one to two percent over the level measured in Step 2. As in 

Step 2, record the stack gas temperature, CO concentration (for gaseous 

fuels) or smoke-spot number (for liquid fuels), and observe flame 

conditions for these higher oxygen levels after boiler operation stabilizes. 

 

1

This tuning procedure is based on a tune-up procedure developed by KVB, Inc. for the 

United States EPA.

2

The smoke-spot number can be determined with ASTM Test Method D-2156 or with 

the Bacharach method. ASTM Test Method D-2156 is included in a tuneup kit that can 

be purchased from the Bacharach Company.

3

Typical minimum oxygen levels for boilers at high firing rates are:

1. For natural gas: 0.5% - 3%

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2. For liquid fuels: 2% - 4% 

However, complete the remaining portion of this procedure to determine 

whether still lower oxygen levels are practical. 

1. Decrease combustion air flow until the stack gas oxygen concentration is 

at the level measured in Step 2. From this level gradually reduce the 

combustion air flow, in small increments. After each increment, record 

the stack gas temperature, oxygen concentration, CO concentration (for 

gaseous fuels) and smoke-spot number (for liquid fuels). Also observe the 

flame and record any changes in its condition. 

2. Continue to reduce combustion air flow stepwise, until one of these limits 

is reached: 

a. Unacceptable flame conditions - such as flame impingement on furnace 

walls or burner parts, excessive flame carryover, or flame instability. 

b. Stack gas CO concentrations greater than 400 ppm. 

c. Smoking at the stack. 

d. Equipment-related limitations - such as low windbox/furnace pressure 

differential, built in air-flow limits, etc. 

3. Develop an O2/CO curve (for gaseous fuels) or O2/smoke curve (for 

liquid fuels) similar to those shown in Figures 1 and 2 using the excess 

oxygen and CO or smoke-spot number data obtained at each combustion 

air flow setting. 

4. From the curves prepared in Step 6, find the stack gas oxygen levels 

where the CO emissions or smoke-spot number equal the following 

values: 

Fuel Measurement Value

Gaseous CO Emissions 400 ppm

#1 and #2 oils smoke-spot number number 1

#4 oil smoke-spot number number 2

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The above conditions are referred to as the CO or smoke thresholds, or as the 

minimum excess oxygen level. 

Compare this minimum value of excess oxygen to the expected value 

provided by the combustion unit manufacturer. If the minimum level found is 

substantially higher than the value provided by the combustion unit 

manufacturer, burner adjustments can probably be made to improve fuel and 

air mixing, thereby allowing operation with less air. 

l Add 0.5 to 2.0 percent of the minimum excess oxygen level found in Step 

7 and reset burner controls to operate automatically at this higher stack 

gas oxygen level. This margin above the minimum oxygen level accounts 

for fuel variations, variations in atmospheric conditions, load changes, 

and nonrepeatability or play in automatic controls. 

l If the load of the combustion unit varies significantly during normal 

operation, repeat Steps 1-8 for firing rates that represent the upper and 

lower limits of the range of the load. Because control adjustments at one 

firing rate may affect conditions at other firing rates, it may not be 

possible to establish the optimum excess oxygen level at all firing rates. If 

this is the case, choose the burner control settings that give best 

performance over the range of firing rates. If one firing rate 

predominates, settings should optimize conditions at that rate. 

l Verify that the new settings can accommodate the sudden load changes 

that may occur in daily operation without adverse effects. Do this by 

increasing and decreasing load rapidly while observing the flame and 

stack. If any of the conditions in Step 5 result, reset the combustion 

controls to provide a slightly higher level of excess oxygen at the affected 

firing rates. Next, verify these new settings in a similar fashion. Then 

make sure that the final control settings are recorded at steady-state 

operating conditions for future reference. 

l When the above checks and adjustments have been made, record data and 

attach combustion analysis data to boiler, steam generator, or heater 

records indicating name and signature of person, title, and date the tuneup 

was performed. 

#5 oil smoke-spot number number 3

Other oils smoke-spot number number 4

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B. Equipment Tuning Procedure for Natural Draft-Fired Boilers, Steam 

Generators, and Process Heaters.

Nothing in this Equipment Tuning Procedure shall be construed to require any 

act or omission that would result in unsafe conditions or would be in violation 

of any regulation or requirement established by Factory Mutual, Industrial 

Risk Insurers, National Fire Prevention Association, the California 

Department of Industrial Relations (Occupational Safety and Health 

Division), the Federal Occupational Safety and Health Administration, or 

other relevant codes, regulations, and equipment manufacturers specifications 

and operating manuals. 

Should a different tuning procedure be used, a copy of this procedure should 

be kept with the unit records for two years and made available to the District 

personnel on request. 

1. PRELIMINARY ANALYSIS

a. CHECK THE OPERATING PRESSURE OR TEMPERATURE. 

Operate the boiler, steam generator, or heater at the lowest acceptable 

pressure or temperature that will satisfy the load demand. This will 

minimize heat and radiation losses. Determine the pressure or 

temperature that will be used as a basis for comparative combustion 

analysis before and after tuneup. 

b. CHECK OPERATING HOURS. 

Plan the workload so that the boiler, steam generator, or process heater 

operates only the minimum hours and days necessary to perform the work 

required. Fewer operating hours will reduce fuel use and emissions. For 

units requiring a tuneup to comply with the rule, a totalizing nonresettable fuel meter will be required for each fuel used and for each 

boiler, steam generator, and heater to prove fuel consumption is less than 

the heat input limit in therms per year specified in the rule. 

c. CHECK AIR SUPPLY. 

Sufficient fresh air supply is essential to ensure optimum combustion and 

the area of air supply openings must be in compliance with applicable 

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codes and regulations. Air openings must be kept wide open when the 

burner is firing and clear from restriction to flow. 

d. CHECK VENT. 

Proper venting is essential to assure efficient combustion. Insufficient 

draft or overdraft promotes hazards and inefficient burning. Check to be 

sure that vent is in good condition, sized properly and with no 

obstructions. 

e. COMBUSTION ANALYSIS. 

Perform an "as is" combustion analysis (CO, O2, etc.) with a warmed up 

unit at high and low fire, if possible. In addition to data obtained from 

combustion analysis, also record the following: 

i. Inlet fuel pressure at burner (at high & low fire) 

ii. Draft above draft hood or barometric damper 

1) Draft hood: high, medium, and low 

2) Barometric Damper: high, medium, and low 

iii. Steam pressure, water temperature, or process fluid pressure or 

temperature entering and leaving the boiler, steam generator, or 

process heater. 

iv. Unit rate if meter is available. 

With above conditions recorded, make the following checks and 

corrective actions as necessary: 

2. CHECKS & CORRECTIONS

a. CHECK BURNER CONDITION. 

Dirty burners or burner orifices will cause boiler, steam generator, or 

process heater output rate and thermal efficiency to decrease. Clean 

burners and burner orifices thoroughly. Also, ensure that fuel filters and 

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moisture traps are in place, clean, and operating properly, to prevent 

plugging of gas orifices. Confirm proper location and orientation of 

burner diffuser spuds, gas canes, etc. Look for any burned-off or missing 

burner parts, and replace as needed. 

b. CHECK FOR CLEAN BOILER, STEAM GENERATOR, OR 

PROCESS HEATER TUBES & HEAT TRANSFER SURFACES. 

External and internal build-up of sediment and scale on the heating 

surfaces creates an insulating effect that quickly reduces unit efficiency. 

Excessive fuel cost will result if the unit is not kept clean. Clean tube 

surfaces, remove scale and soot, assure proper process fluid flow and flue 

gas flow. 

c. CHECK WATER TREATMENT & BLOWDOWN PROGRAM. 

Soft water and the proper water or process fluid treatment must be 

uniformly used to minimize scale and corrosion. Timely flushing and 

periodic blowdown must be employed to eliminate sediment and scale 

build-up on a boiler, steam generator or process heater. 

d. CHECK FOR STEAM, HOT WATER OR PROCESS FLUID LEAKS

Repair all leaks immediately since even small high-pressure leaks quickly 

lead to considerable fuel, water and steam losses. Be sure there are no 

leaks through the blow-off, drains, safety valve, by-pass lines or at the 

feed pump, if used. 

3. SAFETY CHECKS

a. Test primary and secondary low water level controls. 

b. Check operating and limit pressure and temperature controls. 

c. Check pilot safety shut off operation. 

d. Check safety valve pressure and capacity to meet boiler, steam 

generator or process heater requirements. 

e. Check limit safety control and spill switch.

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4. ADJUSTMENTS

While taking combustion readings with a warmed up boiler, steam 

generator, or process heater at high fire perform checks and adjustments 

as follows: 

a. Adjust unit to fire at rate; record fuel manifold pressure. 

b. Adjust draft and/or fuel pressure to obtain acceptable, clean 

combustion at both high, medium and low fire. Carbon Monoxide (CO) 

value should always be below 400 parts per million (PPM) at 3% 02. If 

CO is high make necessary adjustments. 

Check to ensure boiler, steam generator, or process heater light offs are 

smooth and safe. A reduced fuel pressure test at both high and low fire 

should be conducted in accordance with the manufacturers instructions 

and maintenance manuals. 

c. Check and adjust operation of modulation controller. Ensure proper, 

efficient and clean combustion through range of firing rates. 

When above adjustments and corrections have been made, record all data.

5. FINAL TEST

Perform a final combustion analysis with a warmed up boiler, steam 

generator, or process heater at high, medium and low fire, whenever 

possible. In addition to data from combustion analysis, also check and 

record: 

a. Fuel pressure at burner (High, Medium, and Low). 

b. Draft above draft hood or barometric damper (High, Medium and 

Low). 

c. Steam pressure or water temperature entering and leaving boiler, steam 

generator, or process heater. 

d. Unit rate if meter is available.

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When the above checks and adjustments have been made, record data and 

attach combustion analysis data to boiler, steam generator, or process 

heater records indicating name and signature of person, title, company 

name, company address and date the tuneup was performed. 

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