SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT

Final Staff Report

Proposed Amended Rule 1146.1 - Emissions of Oxides of Nitrogen from Small 

Industrial, Institutional, and Commercial Boilers, Steam Generators, and 

Process Heaters

August 2008

Deputy Executive Officer

Planning, Rule Development, and Area Sources

Elaine Chang, DrPH

Assistant Deputy Executive Officer

Planning, Rule Development, and Area Sources

Laki Tisopulos, Ph.D., P.E.

Planning and Rules Manager

Planning, Rule Development, and Area Sources 

Joe Cassmassi

Author: Rizaldy Calungcagin, Air Quality Specialist

Reviewed by: Gary Quinn, P.E. – Program Supervisor

Kurt Wiese - District Counsel
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT

GOVERNING BOARD

Chairman: WILLIAM A. BURKE, Ed.D.

Speaker of the Assembly Appointee

Vice Chairman: S. ROY WILSON, Ed.D.

Supervisor, Fourth District

Riverside County Representative

MEMBERS:

MICHAEL D. ANTONOVICH

Supervisor, Fifth District

Los Angeles County Representative

MICHAEL A. CACCIOTTI

Councilmember, City of South Pasadena

Cities Representative, Los Angeles County, Eastern Region

BILL CAMPBELL

Supervisor, Third District

County of Orange

JANE W. CARNEY

Senate Rules Committee Appointee

RONALD O. LOVERIDGE

Mayor, City of Riverside

Cities Representative, Riverside County

JOSEPH K. LYOU, Ph.D.

Governor’s Appointee

GARY OVITT

Supervisor, Fourth District

San Bernardino County Representative 

JAN PERRY

Councilmember, City of Los Angeles

City of Los Angeles

MIGUEL PULIDO

Mayor, City of Santa Ana

Cities Representative, Orange County

TONIA REYES URANGA

Councilmember, City of Long Beach

Cities Representative, Los Angeles County, Western Region

DENNIS YATES

Mayor, City of Chino

Cities Representative, San Bernardino County

EXECUTIVE OFFICER:

BARRY R. WALLERSTEIN, D.Env.
i August 2008

TABLE OF CONTENTS

TABLE OF CONTENTS ...................................................................................................i

EXECUTIVE SUMMARY .........................................................................................ES-1

CHAPTER 1: BACKGROUND

INTRODUCTION.............................................................................................................1-1

REGULATORY HISTORY .............................................................................................1-1

TYPES OF BOILERS, STEAM GENERATORS, AND PROCESS HEATERS............1-3

TECHNOLOGY ASSESSMENT.....................................................................................1-4

AFFECTED INDUSTRIES ..............................................................................................1-5

PUBLIC PROCESS ..........................................................................................................1-8

CHAPTER 2: SUMMARY OF PROPOSED AMENDED RULE 1146.1

PROPOSED AMENDED RULE 1146.1 REQUIREMENTS..........................................2-1

CHAPTER 3: IMPACT ASSESSMENT

EMISSION REDUCTIONS..............................................................................................3-1

COST EFFECTIVENESS.................................................................................................3-1

INCREMENTAL COST EFFECTIVENESS ...................................................................3-3

CALIFORNIA ENVIRONMENTAL QUALITY ACT (CEQA) ANALYSIS ................3-4

SOCIOECONOMIC ASSESSMENT...............................................................................3-5

DRAFT FINDINGS UNDER CALIFORNIA HEALTH AND SAFETY........................3-5

CODE SECTION 40727

COMPARATIVE ANALYSIS .........................................................................................3-5

TABLES AND FIGURES

TABLE ES-1 - SUMMARY OF PROPOSED NOX LIMITS AND COMPLIANCE 

DATES.................... ................................................................................................ES-1

TABLE 1 - PROPOSED NOX LIMITS AND COMPLIANCE DATES..................2-2

TABLE 2 - SUMMARY OF COST EFFECTIVENESS ANALYSIS .......................3-3

TABLE 3 - SUMMARY OF INCREMENTAL COST EFFECTIVENESS 

ANALYSIS ..............................................................................................................3-4

FIGURE 1 - INDUSTRIES AFFECTED BY RULE 1146.1............................................1-6
ii August 2008

FIGURE 2 – EQUIPMENT POPULATION BY FUEL USE ..........................................1-7

FIGURE 3 – BASELINE NOx EMISSIONS ...................................................................1-7

FIGURE 4 – NOx EMISSION REDUCTION..................................................................3-1

REFERENCES...............................................................................................................R-1

APPENDIX A - PUBLIC COMMENTS AND RESPONSES ..................................... A-1
ES-1 August 2008

EXECUTIVE SUMMARY
PAR 1146.1 Final Staff Report

ES-1 August 2008

EXECUTIVE SUMMARY

Rule 1146.1 – Emissions of Oxides of Nitrogen from Small Industrial, Institutional, and 

Commercial Boilers, Steam Generators, and Process Heaters was adopted on October 5, 1990. 

This rule applies to boilers, steam generators, and process heaters with maximum rated heat input 

capacities greater than 2 million Btu per hour and less than 5 million Btu per hour. Rule 1146.1 

establishes NOx and CO emission limits, and provides compliance options for units that meet 

low fuel usage thresholds. 

The rule does not apply to NOx RECLAIM facilities. Instead, the units in those facilities in the 

Rule 1146.1 size range are subject to NOx limits established through the RECLAIM program. 

The proposed amendment to this rule would reduce the allowable emission limits of NOx from 

units with the application of low-NOx or ultra low-NOx burners, with or without the use of flue 

gas recirculation (FGR). It is also the intent of this proposed amendment to harmonize the NOx 

compliance limits with those limits proposed for Rule 1146 – Emissions of Oxides of Nitrogen 

from Industrial, Institutional, and Commercial Boilers, Steam Generators, and Process Heaters, 

and established in Rule 1146.2 – Emissions of Oxides of Nitrogen from Large Water Heaters and 

Small Boilers and Process Heaters. The following table presents the proposed NOx emission 

limits and compliance dates.

Category Limit Submit 

Application for 

Permit to

Construct on or 

Unit Shall be in Full 

Compliance on or before 

Any Units Fired on 

Landfill Gas

25 ppm January 1, 2014 January 1, 2015

Any Units Fired on 

Digester Gas

15 ppm January 1, 2014 January 1, 2015

Atmospheric Units 12 ppm or

0.015 lbs/106

Btu

January 1, 2013 January 1, 2014

Any Units Fired on 

Natural Gas, 

Excluding Units 

Located at Schools and 

Universities 9 ppm or

January 1, 2011 January 1, 2012

Any Units Fired on 

Natural Gas Located at 

Schools and 

Universities

0.011 lbs/106

Btu

January 1, 2013 January 1, 2014

Table ES – 1

Proposed NOx Limits and Compliance Dates
PAR 1146.1 Final Staff Report

ES-2 August 2008

The proposed rule amendment also introduces:

 A weighted average formula for duel fueled co-fired units;

 Recognition of energy efficient units;

 Compliance testing frequency compatible with RECLAIM sources in the same size range;

 Monitoring NOx emissions with a portable analyzer;

 Prohibiting the derating of existing units to below 2 mmBtu/hr;

 Compliance with the 30 ppm NOx limit for low fuel usage units by January 1, 2015 or at 

time of burner replacement, whichever occurs later; and

 Extending the compliance date for health facilities complying with seismic safety 

requirements

There are approximately 1,070 boilers that may be affected by the proposed amendements. The 

proposed rule amendment is estimated to reduce approximately 0.29 tons per day of NOx

emissions by 2015, which reflects an overall 71% reduction in NOx emissions from this source 

category. The average cost effectiveness estimates for boilers and heaters affected by the 

proposed amendment range from $14,400 to $33,500 per ton. The cost differential is attributed 

to unit size, types of burners, and the unit’s operation and load. 
PAR 1146.1 Final Staff Report

ES-3 August 2008

CHAPTER 1: BACKGROUND

INTRODUCTION

REGULATORY HISTORY

TYPES OF BOILERS AND HEATERS

TECHNOLOGY ASSESSMENT

AFFECTED INDUSTRIES

PUBLIC PROCESS
PAR 1146.1 Final Staff Report

1 - 1 August 2008

INTRODUCTION

Rule 1146.1 applies to existing boilers, steam generators, and process heaters with maximum 

rated heat input capacities greater than 2 million Btu per hour and less than 5 million Btu per 

hour. The rule does not apply to units in NOx RECLAIM facilities. Instead, the units in those 

facilities in the Rule 1146.1 size range are subject to NOx limits established through the 

RECLAIM program. 

REGULATORY HISTORY

Rule 1146.1 was originally adopted in October 5, 1990 and developed pursuant to the 1989 Air 

Quality Management Plan (AQMP) of the South Coast Air Quality Management District 

(AQMD). As adopted, the rule applied to new and existing boilers, steam generators, and 

process heaters with a maximum rated heat input greater than or equal to 2 million BTU per hour 

and less than 5 million BTU per hour. The rule established a 30 ppm NOx emission limit for 

units with an annual heat input greater than 18,000 therms. For units that did not exceed an 

annual heat input of 18,000 therms the owner or operator must either install a non-resetting fuel 

use totalizing meter or provide fuel use bills from a fuel supply company based on metering of 

fuel use indicating that the 18,000 therms per year of heat input per unit was not exceeded. In 

addition these low fuel usage units must comply with the rule by either semiannual tune-ups or 

maintaining stack gas oxygen concentrations at less than 3 percent on a dry basis.

At the time of the original rule adoption there were about 2,700 units in the District with a gross 

heat input between 2 and 5 million Btu per hour. However, in 1993 about 58% of these units 

were no longer subject to Rule 1146.1 and instead subject to the RECLAIM program.

The first amendment occurred in July 10, 1992. The amendment was the result of a CARB 

notification to the AQMD on February 14, 1992, of certain deficiencies in Rule 1146.1. These 

amendments corrected these deficiencies and other concerns raised by the EPA, prior to the 

rule’s emission limits taking effect on July 1, 1994. The 1992 amendments specified either 

District Method 100.1 as the required test method for NOx, CO and O2, or Methods 7.1 for NOx 

and 10.1 for CO and O2. 

The method of determining emission in pounds per million Btu was not explained in the rule. 

The 1992 amendment specified that the method in the Code of Federal Regulations, Title 40, Part 

60, Appendix A, Method 19, Sections 2 and 3 must be used for this determination. EPA uses 

this method to convert the NOx concentration measured in the stack flue gas of a utility boiler to 

an emission rate in pounds per million Btu’s. For standard fuels such as fuel oil or natural gas, 

only measurements of NOx and O2 concentrations in the flue gas are required to make the 

conversion. The conversion is based on combustion stoichiometry and is applicable to boilers 

and heaters regardless of size.
PAR 1146.1 Final Staff Report

1 - 2 August 2008

Other amendments in 1992 affected alternative tune-up procedures and limiting the start-up and 

shutdown period of exemption to a maximum of 6 hours.

On May 13, 1994 Rule 1146.1 was amended to add a tune up procedure for natural-draft units. 

This addition provided guidelines for tuning natural draft-fired units that have not exceeded 

18,000 therms per year gross heat input from all fuels burned. This was deemed necessary since 

natural-draft boilers acquire combustion air by natural draft created by their stacks do not have 

combustion air fans or blowers. 

For this amendment the applicability section was changed to apply to boilers with a rated heat 

input greater than two million Btu per hour in order to conform to AQMD Rule 219.

Based on industry input, a requirement for approval by USEPA, CARB, and District of 

equivalent tune up procedures was removed to allow more flexibility of implementation. Also, 

no tune up was required for units that are not used during the whole calendar year. At the request 

of the CARB, applicability of the rule was extended to units fired on solid fuels.

In October 2000 Non-Major Source BACT approved a 12 ppm limit for units fired on natural gas 

in the 2 to 5 mmBtu/hr size range.

The AQMD’s 2007 AQMP was adopted in June of 2007. Included within the 2007 AQMP was 

Control Measure MCS-01, Facility Modernization. Control Measure MCS-01 affects a wide 

variety of permitted equipment and processes, including boilers, steam generators, and process 

heaters that are subject to Rule 1146.1. PAR 1146.1 may incorporate the facility modernization 

concept as a means of implementing this control measure. Through the facility modernization 

concept, as a boiler, steam generator, or process heater ages and reaches the end of useful life, the 

unit is either upgraded or replaced to meet NOx emissions limits that are consistent with current 

BACT. This ensures timely upgrade of existing technology to the cleanest emission levels 

available. Based on the 18 years from initial rule compliance (July 1, 1994) to the first proposed 

compliance date (i.e., January 1, 2012) there appears to an already well developed turnover of 

Rule 1146.1 burners.

The AQMP was adopted by the Governing Board in June 2007. The plan was designed to 

demonstrate attainment with national ambient air quality standards for ozone and PM2.5 and 

make progress toward attaining the state air quality standards. The 2007 AQMP contains control 

measure MCS-01 calling for additional NOx emission reductions from various non-RECLAIM 

combustion sources including boilers and heaters.

The proposed amendments address requirements for Best Available Retrofit Control Technology 

(BARCT) in accordance with California Health and Safety (H&S) Code § 40440. Reductions in 

NOx are necessary to enable the Basin to attain ozone and PM2.5 standards. 

The California Clean Air Act (CCAA) requires districts to achieve and maintain state standards 

by the earliest practicable date and, for extreme non-attainment areas, to include all feasible 

measures (H&S Code §§ 40913, 40914, and 40920.5). The term “feasible” is defined in the 14 
PAR 1146.1 Final Staff Report

1 - 3 August 2008

California Code of Regulations, § 15364, as a measure “capable of being accomplished in a 

successful manner within a reasonable period of time, taking into account economic, 

environmental, legal, social, and technological factors.” The required use of BARCT for existing 

stationary sources is one of the specified feasible measures. H&S Code §§ 40440 (a)&(b)(1) and 

40918 require AQMD to adopt rules requiring best available retrofit control technology for 

existing sources. H&S Code § 40406 specifically defines BARCT as “...best available retrofit 

technology means an emission limitation that is based on the maximum degree of reduction 

achievable taking into account environmental, energy, and economic impacts by each class or 

category of source.”

TYPES OF BOILERS, STEAM GENERATORS, AND PROCESS HEATERS

There are many of types of boilers, water heaters and process heaters subject to AQMD Rule 

1146.1. Boilers and steam generators produce hot water or steam for office buildings, 

commercial establishments, hospitals, schools and universities, hotels and industrial operations. 

Process heaters are used to heat material streams for industrial operations. Process heaters can 

heat process fluids directly or use a heat exchange fluid. For each application there may be 

several designs of boilers or heaters available. Boilers and heaters can be classified in several 

ways including the way heat is transferred, the material used in the heat exchanger, and the 

engineering and safety codes for which the unit is designed to comply. 

A unit is classified as a boiler if it is designed to meet the safety standards of the American 

Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code. While many boilers 

are used to produce steam, others provide hot water for a variety of purposes. The components 

and the entire system of a boiler must meet additional standards including those from 

Underwriters Laboratories (UL), federal and state energy efficiency standards and local building 

codes.

Boilers

Historically, boilers have been built using one of three basic designs: fire tube, water tube or cast 

iron sectional. In a fire tube boiler, the combustion gasses pass through banks of narrow tubes 

that are surrounded by a pressure vessel (tank) which contains water. The combustion gasses 

may pass through one set of tubes in one direction (one pass) or make multiple passes by 

alternating the direction through each set of tubes. Multiple passes of the hot combustion gasses 

through the pressure vessel increase efficiency and increase the temperature and pressure of the 

water or steam. This type of boiler can be built using a horizontal pressure vessel and horizontal 

tubes or a vertical pressure vessel and tubes. 

In a water tube boiler, the combustion gasses pass over and through banks of tubes containing 

water. Increasing the number and surface area of water tubes will increase the temperature and 

pressure of water in the tubes and increase the boiler efficiency. Steel water tube boilers can 

produce very high temperature water or high pressure steam.
PAR 1146.1 Final Staff Report

1 - 4 August 2008

Cast boilers pass combustion gasses over the surface of one or more water containing sections 

made of cast iron. Cast boiler sections can also be made from brass or bronze. This type of 

boiler can only be used to produce low temperature water or low pressure steam.

A newer type of boiler based on the water tube design uses a heat exchanger made of copper 

tubes with heat exchange fins. This type of boiler is typically constructed in a factory while the 

older designs may be constructed at the factory or at the location where the unit will be used.

TECHNOLOGY ASSESSMENT

In the combustion process, thermal NOx is generally the largest contributor of NOx emissions. 

High flame temperatures trigger the disassociation of nitrogen molecules from combustion air 

and a chain reaction with oxygen follows to form oxides of nitrogen. Factors that minimize the 

formation of thermal NOx include reduced flame temperature, shortened residence time, and an 

increased fuel to air ratio. 

For gaseous fuels, the formation of fuel NOx is not significant. Fuel NOx results when nitrogen 

that is bound in fuel combines with oxygen present in combustion air. Because gaseous fuels 

typically have low nitrogen levels, this mechanism does not play a significant role in NOx 

formation during natural gas combustion. Similarly, fuel NOx formation does not play a 

significant role in the combustion of diesel fuel. This fuel is the only non-gaseous fuel used in 

significant quantities within the South Coast Air Basin. California has stringent low sulfur 

standards for diesel fuel. The process used for removing sulfur also removes nitrogen, resulting 

in diesel fuel with low nitrogen levels. 

Prompt NOx forms quickly and is a reaction of free radicals that primarily occurs in a fuel rich 

flame zone within the early stages of combustion. Although prompt NOx is generated in small 

quantities, it can play a significant role when attempting to achieve single-digit NOx levels. 

To reduce NOx emissions, combustion parameters can be optimized, control techniques can be 

applied downstream of the combustion zone, or a combination of the two approaches can be 

utilized. Common types of combustion modification include: lowered flame temperature; 

reduced residence time at high combustion temperature; and reduced oxygen concentration in the 

high temperature zone. For purposes of complying with the proposed Rule 1146.1 limits the 

ensuing discussion will be limited to the application of the ultra low-NOx burner systems.

Ultra Low-NOx Burner Systems

Often, fuel and air are pre-mixed prior to combustion. This results in a lower and more uniform 

flame temperature. Some premix burners also use staged combustion with a fuel rich zone to 

start combustion and stabilize the flame and a fuel lean zone to complete combustion and reduce 

the peak flame temperature. 
PAR 1146.1 Final Staff Report

1 - 5 August 2008

Burners can also be designed to spread flames over a larger area to reduce hot spots and lower 

NOx emissions. Radiant premix burners with ceramic, sintered metal or metal fiber heads spread 

the flame and produce more radiant heat. When a burner produces more radiant heat, it results in 

less heat escaping the boiler through the exhaust gases. 

Most premix burners require the aid of a blower to mix the fuel with air before combustion takes 

place (primary air). Flue gas recirculation (FGR), which recycles a portion of the exhaust stream 

back into the burner, is also commonly used. Increasing the amount of primary air and/or use of 

FGR can reduce flame temperature but it also reduces the temperature of combustion gases 

through dilution and can reduce efficiency. To maintain efficiency a manufacturer may have to 

add surface area to the heat exchanger. Increasing the primary air may also destabilize the flame. 

Ultra-low NOx burners require sophisticated controls to maintain emissions levels and 

efficiency, to stabilize the flame, and to maintain a turndown ratio that is sufficient for the 

demands of the particular operation.

Ultra low-NOx burner systems for boilers and process heaters can achieve less than 9 ppm NOx

(at 3% oxygen). NOx formation results primarily from thermal NOx and fuel NOx, and to a 

lesser extent from prompt NOx.

Ultra low-NOx burners have been applied by the San Joaquin Valley Unified Air Pollution 

Control District (SJVUAPCD) in their Rule 4306. The compliance limit when applying this 

technology to equivalent boilers and heaters at the upper end of Rule 1146.1 (i.e., 5 mmBtu/hr) 

ranges from 9 to 15 ppm. Source tests conducted in conjunction with Rule 4306 showed a 95% 

compliance rate with 9 ppm NOx limits using ultra low NOx burners. The average NOx 

concentration was 7 ppm and the smallest unit tested was at 6 mmBtu/hr. In their March 17, 

2008 Proposed Amended Rule (PAR) 4307, for equivalent units in the 2 to 5 mmBtu/hr range, 

the proposed limit is 9 ppm. This would apply to new and replaced units effective upon 

installation on or after January 1, 2010.

In May 2006 AQMD Rule 1146.2 (affecting units between 75,000 Btu/hr and 2 mmBtu/hr) 

established a NOx limit of 20 ppm. SJVUAPCD is proposing to amend Rule 4306. The current 

proposal is 9 ppm for all equipment down to 5 mmBtu/hr. The proposed compliance date for 

PAR 4306 is June 1, 2011.

AFFECTED INDUSTRIES

PAR 1146.1 affects a wide variety of industries within the South Coast Air Basin. Boilers and 

heaters subject to PAR 1146.1 include those used in medical facilities, educational institutions, 

office buildings, hotels, and industrial facilities. Staff has estimated that there are about 1,072 

active permitted units in the district in the size range affected by this rule. When grouped 

according to the Standard Industrial Classification (SIC), the educational services account for 

about 24% of the units, while health services industry has approximately 10% of the units that 

are subject to the rule. Next, the food industry contributes about 8% of the units and apartments 

comprise 7% of the total. Hotels and other lodging places have about 4% share of the total Rule 
PAR 1146.1 Final Staff Report

1 - 6 August 2008

1146.1 units. The remaining 47% of the units are distributed over 52 other SIC categories. The 

distribution by SIC of boilers and heaters affected by PAR 1146.1 is shown in Figure 1 below.

Figure 1

Affected units can also be categorized by the type of fuel used and amount of fuel used annually. 

Low-fuel usage boilers and heaters are units operated at heat input of less than or equal to 18,000 

therms per calendar year. Currently, there are about 257 boilers (24% of total) that fall under the 

low-fuel usage category. All units are natural gas fired. Such boilers or heaters are currently 

exempt from the NOx and CO limits of the rule provided the units are operated at no more than 

18,000 therms per year of heat input, and under a compliance plan that specifies certain operating 

conditions, e.g. periodic tune ups or stack gas oxygen concentration of 3% or less, in lieu of 

meeting the 30 ppm NOx limit. PAR 1146.1 would require these units to meet the current NOx 

limit of 30 ppm by January 1, 2015 or during burner replacement, whichever is later, through the 

use of low-NOx burners.

Boilers and heaters that exceed 18,000 therms of annual heat input are required to meet the NOx 

and CO rule requirements. These units use either natural gas or digester gas as fuel. There are 

about 806 natural gas-fired boilers and heaters (75%) and 9 digester-fired units (1%). Natural 

and digester-gas fired units are expected to comply with the proposed NOx limit of 9 ppm and 15 

ppm, respectively, through the use of low-NOx or ultra-low NOx burners. 

Rule 1146.1 Facilities

Distributed by Number of Equipment

24%

10%

8% 4% 7%

47%

Educational Services

Health Services

Food and Kindred

Products

Apartments

Hotels and Other Lodging

Places

Remaining 52 Categories
PAR 1146.1 Final Staff Report

1 - 7 August 2008

The proposed amendment also requires units fired on landfill gas to meet 25 ppm NOx limit by 

January 1, 2015. However, there are no landfill gas-fired boilers for the size range affected by 

PAR 1146.1. Figure 2 below shows the equipment distribution by fuel use.

Number of Units = 1,072

Natural Gas Fired

75%

Low Fuel Usage

24%

Digester Gas

1%

Figure 2

The total estimated NOx emission from all units affected by PAR 1146.1 is 0.41 tons per day. 

This estimate was taken from AQMD emission database for the year 2002. Figure 3 shows the 

distribution of baseline NOx emissions for PAR 1146.1

Baseline NOx Emissions = 0.42 tpd

Natural Gas Fired

87%

Low Fuel Usage

11%

Digester Gas

2%

Figure 3
PAR 1146.1 Final Staff Report

1 - 8 August 2008

PUBLIC PROCESS

The rule development process started with the PAR 1146 effort. This has been ongoing process 

to assess low NOx technologies for boilers, steam generators, and process heaters. There have 

been five Rule 1146 Task Force meetings from January 2006 to January 2008. These meetings 

included representatives from the manufacturers, trade organizations, permit holders for units 

subject to Rule 1146, and other interested parties. At these meetings low NOx technology, 

equipment useful lives, and proposed emission limits were discussed.

In parallel with further Rule 1146 rule development efforts, staff held a Rule 1146.1 Task Force 

meeting on February 5, 2008, a Public Consultation meeting on March 19, 2008, and a Public 

Workshop on April 2, 2008. In addition, there were two joint PAR 1146.1/1146 Task Force held 

on July 10, 2008 and August 14, 2008. In assessing applicable technology, staff has held 

individual meetings and conference calls with manufacturers of boilers, steam generators, and 

process heaters.
CHAPTER 2: SUMMARY OF PROPOSED AMENDED RULE 1146.1

PROPOSED AMENDED RULE 1146.1 REQUIREMENTS
PAR 1146.1 Final Staff Report

2 - 1 August 2008

PROPOSED AMENDED RULE 1146.1 REQUIREMENTS

Existing Rule

Rule 1146.1 applies to new and existing industrial, institutional and commercial boilers, steam 

generators, and process heaters with a heat input between 2 and 5 mmBtu/hr.

The rule does not apply to units in NOx RECLAIM facilities. Instead, the units in the Rule 

1146.1 size range are subject to NOx limits established through the RECLAIM program.

Under Rule 1146.1, units burning liquid, gaseous, and/or solid fuels are required to meet a NOx 

limit of 30 ppm limit and a CO limit of 400 ppm, if annual fuel usage exceeds 18,000 therms per 

year. 

Fuel metering requirements apply to units exempt from NOx limits due to low fuel usage. Units 

that are exempt from NOx limits are also required to either maintain stack gas oxygen 

concentrations at 3% or less (on a dry basis), or tune the unit(s) at least twice per year according 

to specified tuning procedures.

All NOx limits are specified in ppm by volume at 3% oxygen. An alternative to meeting a 30 

ppm NOx limit is to meet 0.037 pounds per 106 Btu of heat input.

Proposed Rule Amendments

Applicability – Subdivision (a):

Other than placing this subdivision ahead of the “Definitions” subdivision, there are no changes 

proposed for this subdivision.

The words landfill and digester gas was added to the definitions of Boiler or Steam Generator 

and Process Heater. This should provide further clarification that these two types of fuels are 

regulated in this rule in addition to fossil fuels.

Definitions – Subdivision (b):

Definitions of thermal fluid heaters, atmospheric units, and health facilities, and schools are 

proposed to be added. The definition of health facilities are proposed to be added to take into 

consideration an extension in the compliance date for health facilities complying with seismic 

safety requirements.

Requirements – Subdivision (c):

There is a carryover of the current NOx compliance limit of 30 ppm or 0.037 lb NOx per 106 Btu. 

The optional “lbs per 106 Btu of heat input” limit is proposed to provide an incentive and credit 

for the installation of fuel efficient equipment. At the time of rule adoption this limit would 

apply to all units, except low fuel usage units (i.e., less than or equal to 18,000 therms per year). 

The proposed NOx compliance limits and schedule are presented in Table 1.
PAR 1146.1 Final Staff Report

2 - 2 August 2008

Category Limit Submit 

Application for 

Permit to

Construct on or 

before 

Unit Shall be in Full 

Compliance on or before 

Any Units Fired on 

Landfill Gas

25 ppm January 1, 2014 January 1, 2015

Any Units Fired on 

Digester Gas

15 ppm January 1, 2014 January 1, 2015

Atmospheric Units 12 ppm or

0.015 lbs/106

Btu

January 1, 2013 January 1, 2014

Any Units Fired on 

Natural Gas, 

Excluding Units 

Located at Schools and 

Universities, and 

Thermal Fluid Heaters

9 ppm or

January 1, 2011 January 1, 2012

Any Units Fired on 

Natural Gas Located at 

Schools and 

Universities, 

Excluding Thermal 

Fluid Heaters

0.011 lbs/10

6

Btu

January 1, 2013 January 1, 2014

Table 1

Proposed NOx Limits and Compliance Dates

Thermal fluid units have been identified as equipment that would not be able to meet the 

proposed 9 ppm NOx limit. On this basis, these units would be required to continue meeting the 

30 ppm NOx limit. For atmospheric units, achieving the 9 ppm NOx limit would be very 

challenging and most likely result in fugitive CO emissions. Consequently, a 12 ppm NOx limit 

has been proposed for these units.

The proposed NOx limits for landfill and digester gas fired units are 25 and 15 ppm, respectively. 

These limits are based on source data of units operating in the district, allowing for a certain 

amount of buffer to assure compliance. It should be noted that there were no landfill gas units 

identified in the 2 to 5 mmBtu/hr size range. Thus, any further discussion on existing biogas 

units will be limited to digester gas fired units.

Rule language was also added stating that on or after January 1, 2015, an owner operator of any 

landfill or digester gas (biogas) unit co-fired with natural gas must not operate the unit in a 

manner that exceeds the NOx emission concentration limits for the biogas units (i.e., 25 ppm for 

landfill and 15 ppm for digester gas). Operation at the 15 or 25 ppm NOx limit would be deemed
PAR 1146.1 Final Staff Report

2 - 3 August 2008

in-compliance with Rule 1146 provided that the facility monthly average biogas usage by the 

biogas units is 90% or more, based on the higher heating value of the fuels used. Any biogas unit 

exceeding the approved percent natural gas would then be required to comply with the weighted 

average NOx limit specified in paragraph (c)(3). That is, the compliance limit would be based on 

the thermal input of the biogas and natural gas. 

In addition, the Executive Officer may approve the burning of over 25% natural gas in a biogas 

fired unit at the 15 ppm (digester gas) or 25 ppm (landfill gas) NOx level, when it is necessary, 

if: the only alternative to limiting natural gas to 10% would be shutting down the unit and flaring 

more biogas.

For new digester gas fired units, the Executive Officer may approve up to 50% natural gas in the

digester boiler unit at the 15 ppm NOx level, also when it is necessary if: the only alternative to 

limiting natural gas to 10% would be shutting down the unit and flaring more biogas. These 

newly installed units must also demonstrate compliance with the NOx limits applicable to units 

fired exclusively on natural gas (i.e., 9 ppm).

These units that have been permitted to operate at the higher than 10 % natural gas usage must 

also be based on the facility monthly average biogas usage by the biogas units and the higher 

heating value of the fuels used.

If any digestor biogas-fired engine unit burn more than 50% the approved percent natural gas 

then the owner or operator would need to demonstrate compliance with the weighted average 

NOx limit.

A source test was performed in 2003 on one of the 15 digester gas fired units. According to the 

source test results the NOx emissions ranged from about 4 ppm (low fire) to 10 ppm (high fire). 

A follow-up emission check with a portable analyzer on this unit confirmed these NOx 

emissions. More recently, AQMD staff conducted NOx emission checks with a portable 

analyzer on two other digester gas fired units. The NOx emissions from these two units were 

measured at 9 and 19 ppm. It should be noted that these digester gas units were installed to meet 

a 30 ppm NOx emission limit. In conjunction with these emission checks and source test, 

AQMD staff contacted a burner vendor who offers products specifically for digester gas units. 

The vendor confirmed that the 15 ppm NOx limit would be achievable on a consistent basis for 

digester gas fired units.

The compliance schedule for landfill and digester gas units took into consideration compliance 

deadlines for recently amended Rule 1110.2 Emissions from Gaseous- and Liquid- Fueled 

Engines. This rule requires equipment operated by the same facilities to comply with 

requirements by July 1, 2012. The intent was not to require compliance limits from two different 

rules during the same time period for the same facilities.

Staff feels that the proposed NOx limits would be in harmony with the compliance limits 

proposed for Rule 1146.
PAR 1146.1 Final Staff Report

2 - 4 August 2008

The proposed rule amendment also introduces a weighted average formula for duel fueled cofired units. The formula for calculating the weighted average compliance limit is as follows:

Weighted Limit = ______________________ Equation 2-1

 QA + QB

Where:

CLA = compliance limit for fuel A

CLB = compliance limit for fuel B

QA = heat input from fuel A

QB = heat input from fuel B

This is an optional approach in determining a compliance limit. Other units with a primary and 

standby fuel may not want to utilize this approach. Instead owners or operators of these units 

would need to demonstrate compliance with the corresponding limit for each fuel.

For natural gas fired units, the owner or operator may opt for the units to comply with an 

equivalent 0.30 lbs of CO per 106 Btu instead of the 400 ppm limit.

There is a special consideration for those units that had complied with the NOx BACT 

requirement of less than or equal to 12 ppm. Thus, for those units in lieu of complying with the 9 

ppm NOx limit according to the schedule specified in Table 1, the owner or operator may opt to 

comply with the 9 ppm or 0.011 lbs/106 Btu NOx level when the unit’s burner(s) are replaced.

Other proposed changes include clarification on the tune-up schedule for low fuel usage units 

and the use of a non-resettable totalizing fuel meter for each of the fuels in which the weighted 

average is applied.

Compliance Determination– Subdivision (d):

Language is added requiring boilers subject to this rule to conduct an emission determination at 

least 250 operating hours or at least 30 days after tuning or servicing of the unit, unless it is an 

unscheduled repair. Essentially, a unit that is scheduled for compliance determination (i.e. 

source test) must not have been subject to a tune-up or servicing within the previous 250 of 

operating hours or 30 days. For example, let’s say that a unit which operates 16 hours per day, 

six days per week was tuned-up on May 1st. For this situation, the next earliest emission 

determination would be within the last six hours of operation on May 18th. If the 30-day criterion 

was applied to the same unit then the unit would not be allowed to have an emission test until 

May 31st. Thus, the 30-day criterion would be more applicable to units that operate less 

frequently.

In this same paragraph, pre-tests for emission determinations were prohibited. 

Additional test methods, Conditional Test Method CTM-030, Determination of Nitrogen Oxides, 

Carbon Monoxide, and Oxygen Emissions from Natural Gas-Fired Engines, Boilers and Process 

(CLA x QA) + (CLB x QB)
PAR 1146.1 Final Staff Report

2 - 5 August 2008

Heaters Using Portable Analyzers and ASTM D6522-00(2005) Standard Test Method for 

Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions 

from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process 

Heaters Using Portable Analyzers, have been added to the rule. All emission determinations 

must be made by a AQMD approved contractor under the Laboratory Approval Program. These 

methods allow the owner or operator of a subject boiler to use a portable analyzer to determine 

emission compliance. Another alternative to source tests is the use of a continuous in-stack NOx 

monitor.

Compliance determination with the NOx emission sources test requirements must be conducted 

once every five years. The current rule only required a source test to demonstrate initial 

compliance. This requirement was added to match the same type of requirement for similar size 

units in the RECLAIM program (ref: Rule 2012 (e)(1)(ii) and 2012(j)(4)).

On or after July 1, 2009, under the proposed amendment the owner or operator must check NOx 

emissions with a portable NOx, CO and oxygen analyzer according to the Protocol for the

Periodic Monitoring of Nitrogen Oxides, Carbon Monoxide, and Oxygen from Units Subject to 

South Coast Air Quality Management District Rules 1146 and 1146.1. This monitoring must be 

conducted quarterly or every 2,000 unit operating hours, whichever occurs later. If a unit is in 

compliance for four consecutive emission checks, without any adjustments to the oxygen sensor 

set points, then the unit may be checked semi-annually or every 4,000 unit operating hours, 

whichever occurs later, until there is a noncompliant emission check.

Compliance determination for CO emissions would be accomplished by applying the source test 

requirements once every five years for units. Alternatively, in lieu of conducting full source 

tests, the owner or operator on or after July 1, 2009 has the option to conduct periodic monitoring 

and check CO emissions with a portable NOx, CO and oxygen analyzer according to the 

Protocol for the Periodic Monitoring of Nitrogen Oxides, Carbon Monoxide, and Oxygen from 

Units Subject to South Coast Air Quality Management District Rules 1146 and 1146.1. As with 

the NOx emissions, this monitoring must be conducted monthly or every 2,000 unit operating 

hours, whichever occurs later. If a unit is in compliance for four consecutive emission checks, 

without any adjustments to the oxygen sensor set points, then the unit may be checked quarterly 

or every 4,000 unit operating hours, whichever occurs later, until there is a noncompliant 

emission check.

Records of all monitoring data must be maintained for a rolling twelve month period of two years 

(5 years for Title V facilities) and made available to AQMD staff upon request. Any emission 

check conducted by AQMD staff that finds excess emissions would be a violation.

If the source test or emission check finds NOx or CO emissions in excess of those allowed by the 

rule or a permit condition, the owner or operator must correct the problem and demonstrate 

compliance with another emission check, or shut down the unit by the end of an operating cycle, 

or within 72 hours from the time the owner or operator knew of excess emissions, or reasonably 

should have known, whichever is sooner.
PAR 1146.1 Final Staff Report

2 - 6 August 2008

Starting in 2003, AQMD staff conducted a four year testing program (222 tests) emissions from 

Rule 1146.1 boilers and heaters. Using portable analyzers, the study revealed a 40% noncompliance rate. On this basis, the introduction of periodic monitoring in the rule will help 

ensure a much lower non-compliance rate.

These portable analyzer tests must be conducted by a person who has completed an appropriate 

AQMD-approved training program in the operation of portable analyzers and has received a 

certification issued by the AQMD.

Owners and operators will continue to have the option to derate their equipment. However, the 

lower rated heat input capacity must not be less than 2 million Btu per hour, based on 

manufacturer’s identification or rating plate or permit condition. The 2 million Btu per hour 

lower limit would prohibit units from complying under Rule 1146.2. 

Compliance Schedule– Subdivision (e):

The proposed schedule for compliance limits is presented in subdivision (c) “Requirements” (See 

Table 1 in this report). Schedule for other rule requirements are as follows: 

 Boilers with an annual heat input less than or equal to 18,000 therms per year will be 

exempt from the proposed emission limits. However, these units would need to meet the 

30 ppm or 0.037 lbs per 106 Btu NOx emission limit by January 1, 2015 or when the unit 

has its burners replaced, whichever occurs later.

 The requirement related to the loss of exemption for low fuel usage was moved from 

subdivision (f) of the current rule to this subdivision and modified to reflect reference to 

the proposed NOx compliance limits.

 A time extension would be granted to the full compliance date with the applicable NOx 

compliance limits for any natural gas fired units for any health facility as defined in 

Section 1250 of the California Health and Safety Code that can demonstrate that the 

Office of Statewide Health Planning and Development has approved an extension of time 

to comply with seismic safety requirements pursuant to Health and Safety Code Sections 

130060 and 130061.5. The extension of time granted must be consistent with the time 

extension granted pursuant to Health and Safety Code Section 130060, but not to exceed 

January 1, 2015, and must be consistent with the time extension granted pursuant to 

Health and Safety Code Section 130061.5 but not to exceed January 1, 2020. Those 

health facilities granted a time extension must submit a compliance plan to the Executive 

Officer on or before January 1, 2010

Exemptions:

The 18,000 therms exemption will no longer apply to future units. On this basis, this subdivision 

has been removed from the existing version of the rule.

Loss of Exemption:
PAR 1146.1 Final Staff Report

2 - 7 August 2008

The loss of exemption provision in the existing version of the rule has been moved to subdivision 

(e) “Compliance Schedule” of the proposed rule.

Attachment 1:

Figures 1 and 2 have been re-introduced to Attachment. These example Oxygen/CO and 

Oxygen/Smoke characteristic curves were in the original adopted rule. Also some clarifying 

language was added to A.8 and B.1.e.ii.

Throughout PAR 1146.1 there are minor amendments to improve the clarity and enforceability of 

the rule. Compliance dates that have passed have been removed from the rule and equipment 

now subject to the same requirements has been consolidated into a single paragraph. 
CHAPTER 3: IMPACT ASSESSMENT

EMISSION REDUCTIONS

COST EFFECTIVENESS

CALIFORNIA ENVIRONMENTAL QUALITY ACT (CEQA) ANALYSIS

SOCIOECONOMIC ASSESSMENT

DRAFT FINDINGS UNDER CALIFORNIA HEALTH & SAFETY CODE 

SECTION 40727

INCREMENTAL COST-EFFECTIVENESS

COMPARATIVE ANALYSIS
PAR 1146.1 Final Staff Report

3 - 1 August 2008

EMISSION REDUCTIONS

As mentioned earlier, emission data was extracted from operating data in the AQMD inventory 

database. Control efficiency for the ultra low-NOx burners was provided by vendors. Emission 

reductions were calculated for each unit category using the difference between the emission 

factor for the existing emission limit and the proposed emission factors presented in Table 1.

Emission Reduction = Emission Inventory x (Current Limit – New Limit)/Current Limit. 

The proposed rule amendment is estimated to reduce approximately 0.29 tons per day of NOx

emissions by 2015. Natural gas-fired boilers and heaters operating at an annual heat input of 

greater than 18,000 therms account for a majority (91%) of the NOx emission reductions. The 

estimated emission reductions also take into account units that may be exempt due to low fuel 

usages and will be required to meet 30 ppm NOx limit by a certain date. Figure 4 shows the 

breakdown of NOx emissions by category.

NOx Emission Reductions = 0.29 tpd

Natural Gas Fired

91%

Digester Gas

1%

Low Fuel Usage

8%

Figure 4

COST EFFECTIVENESS

Cost-effectiveness is defined as the cost to comply with the new regulatory requirements, 

expressed in terms of dollars per ton of pollutant reduced. Determination of cost-effectiveness is 

required by section 40440(c) of the California Health and Safety Code. Costs can include 

equipment, materials, energy, or any other costs associated with meeting new regulatory 

requirements.
PAR 1146.1 Final Staff Report

3 - 2 August 2008

The approach for estimating cost-effectiveness is as follows: 

($ Meet New Limits - $ Continue w/ Existing Limits + $ Early Retirement) 

Emission Reductions from Existing to New Limits over Equipment Useful Life

This approach utilizes the Discount Cash Flow (DCF) Methodology at 4% real interest rate in 

current dollars. The assumed useful life for ultra-low NOx burners used in this cost effectiveness 

calculation is fifteen years. Fifteen years was applied in the recent amendments to Rule 1146.2 

(May 2006).

The costs to meet the proposed emission limits were estimated from information obtained 

through manufacturers and vendors of units for the size range affected by Rule 1146.1. These 

estimates incorporate capital costs (including installation) for retrofitting equipment subject to 

this rule, and costs for any additional fuel and/or electricity use that are associated with meeting 

the more stringent NOx limits. For instance, some ultra low NOx burner systems require the use 

of additional excess air and/or flue gas recirculation. This reduces fuel efficiency and also 

requires the use of additional electricity for operation of the air blower. These additional costs 

were estimated using vendor data for excess air and flue gas recirculation. 

In addition to the cost elements mentioned above, staff has also included any incremental costs 

associated with the proposed monitoring and testing requirements in determining total cost for 

meeting the new rule requirements. Proposed Amended Rule 1146.1 includes provisions for 

quarterly or semi-annual monitoring of NOx emissions using a portable analyzer, and source 

testing requirement every five years.

In estimating the total cost of continuing to meet the existing rule requirements, staff used 

equipment, operating and maintenance costs data obtained from various manufacturers and 

vendors for units that meet the current 30 ppm NOx limit. This cost is deducted from the total 

cost of meeting the new limits in determining cost effectiveness of Proposed Amended Rule 

1146.1.

The proposed rule amendment is estimated to reduce approximately 0.29 tons per day of NOx

emissions by 2015. 

Staff analysis shows that the cost effectiveness values improve for larger boiler sizes and higher 

operating capacity. The cost effectiveness estimates for units rated at 2 to 5 mmBtu/hr is 

expected to range from $14,400 to $33,500 per ton of NOx reduced, depending on the cost 

differential is attributed to unit size, types of burners, and the unit’s operation and load. The 

table below shows the cost effectiveness values for the size range affected by PA R 1146.1. It 

should be noted that this table reflects units reducing the NOx limit from 30 to 9 ppm. For 

atmospheric units reducing the NOx emissions to 12 ppm, the cost effectiveness would be 

increase by about 17 percent.

CE = 
PAR 1146.1 Final Staff Report

3 - 3 August 2008

Operating Capacity Factor Cost Effectiveness

($/ton NOx reduced)

100% $14,400

75% $16,600

50% $20,800

25% $33,500

Table 2

Summary of Cost Effectiveness Analysis

2 to 5 mmBtu/hr

INCREMENTAL COST-EFFECTIVENESS

Health and Safety Code Section 40920.6 requires an incremental cost-effectiveness analysis for 

Best Available Retrofit Control Technology (BARCT) rules or emission reduction strategies 

when there is more than one control option which would achieve the emission reduction 

objective of the proposed amendments, relative to ozone, CO, SOx, NOx, and their precursors. 

Incremental cost effectiveness is defined as the difference in control costs divided by the 

difference in emission reductions between two potential control options that can achieve the 

same emission reduction goal of a regulation.

For this incremental cost effectiveness analysis, the cost and emission reduction associated with 

the use of selective catalytic reduction (SCR) to meet the more stringent 5 ppm NOx limit for 

units affected by PAR 1146 are compared to the control cost and emission reduction of the same 

units using ultra low-NOx burners meeting the 9 ppm NOx limit.

For SCR, staff considered various cost factors such as equipment and installation, electricity, 

ammonia, other operating and maintenance costs, and recurring catalyst replacement cost in 

determining total cost. A 25-years useful life is assumed for SCR and 15 years for ultra lowNOx burners. 

Staff’s analysis indicates that the incremental cost effectiveness between SCR (5 ppm NOx limit) 

and ultra low-NOx burner (9 ppm NOx limit) ranges from $106,000 to $282,700 per ton of NOx 

reduced depending on the operating capacity of the unit. The table below shows the incremental 

cost effectiveness values for the size range affected by PAR 1146.1.
PAR 1146.1 Final Staff Report

3 - 4 August 2008

Capacity Factor

(%)

Incremental Cost Effectiveness

($/ton NOx reduced)

100 $106,000

75 $124,900

50 $167,300

25 $282,700

Table 3

Summary of Incremental Cost Effectiveness Analysis

2 to 5 mmBtu/hr

CALIFORNIA ENVIRONMENTAL QUALITY ACT (CEQA) ANALYSIS

Pursuant to California Environmental Quality Act (CEQA) Guidelines § 15252 and 

AQMD Rule 110, the AQMD has prepared an Environmental Assessment (EA) proposed 

amended Rule 1146.1. The Draft EA was released for a 30-day public review and 

comment period from July 2, 2008 to July 31, 2008 and no comment letters were received

from the public regarding the Draft EA. The environmental analysis in the Draft EA 

concluded that proposed amended Rule 1146.1 would not generate any significant 

adverse environmental impacts. 

Since the release of the Draft EA, minor modifications have been made to the document. 

However, none of the modifications alter any conclusions reached in the Draft EA, nor 

provide new information of substantial importance relative to the draft document. As a 

result, these minor revisions do not require recirculation of the Draft EA pursuant to 

CEQA Guidelines §15073.5. Therefore, the Draft EA is now a Final EA and is included 

as an attachment to this Governing Board package.

 
PAR 1146.1 Final Staff Report

3 - 5 August 2008

SOCIOECONOMIC ASSESSMENT

Proposed amendments to Rule 1146.1 (PAR 1146.1) would affect 618 facilities with at 

least one boiler or process heater (a total of 1,072 units) in the district. The affected 

facilities belong to a number of industries. The most affected in terms of number of units 

are in the sectors of educational services, professional, scientific, and technical services, 

and government. 

The average annual cost of PAR 1146.1 is estimated at $2.6 million between 2012 and 

2020. The majority of the cost will incur in the sectors of educational services ($0.36 

million), government ($0.26 million), health care services ($0.26 million), and 

professional, scientific and technical services ($0.23 million). 

PAR 1146.1 is projected to have 16 jobs forgone annually in the entire four-county 

economy between 2012 and 2020 (less than one-hundredth of one percent of the total 

four-county employment). 

COMPARATIVE ANALYSIS

Under Health and Safety Code Section 40727.2, the AQMD is required to perform a comparative 

written analysis when adopting, amending, or repealing a rule or regulation. The comparative 

analysis is relative to existing federal requirements, existing or proposed AQMD rules and air 

pollution control requirements and guidelines which are applicable to industrial, institutional, and 

commercial water heaters, boilers, steam generators, and process heaters.

The AQMD staff is not aware of any other AQMD, state or federal requirements regulating air 

pollution that are applicable to Rule 1146.1-type units. The amendment does make an existing 

AQMD limit or standard more stringent. However, as there are no other existing air pollution 

requirements for Rule 1146.1 type units, the proposed amendments are not in conflict with and 

do not duplicate existing AQMD, state or federal requirements. Since PAR 1146.1 applies to 

existing industrial, institutional, and commercial boilers, steam generators, and process heaters, 

Best Available Control Technology requirements under the AQMD’s New Source Review 

Program are also not applicable.
REFERENCES
PAR 1146.1 Final Staff Report

R-1 August 2008

REFERENCES

SCAQMD, 2005. Preliminary Draft Staff Report: Proposed Rule 1146.2 - Emissions of Oxides 

of Nitrogen from Large Water Heaters and Small Boilers. South Coast Air Quality Management 

District, September 2005.

SCAQMD, 2007. Addendum to the Proposed Modifications to the Draft 2007 Air Quality 

Management Plan, Appendices, South Coast Air Quality Management District, May 2007.

SCAQMD, 2008. Amended Rule 1110.2 - Emissions from Gaseous- and Liquid- Fueled 

Engines, South Coast Air Quality Management District, January 2008

Bell R. P.E., Buckingham F, Ph.D., P.E., An Overview of Technologies for Reduction of Nitrous 

Oxides Emissions, MPR Engineering Services, MPR Profile, Issue 9, Spring 2003

Webster Timothy, John Zink Company LLC, TODD Combustion Group, Burner Technology for 

Single Digit NOx Emissions in Boiler Applications, John Zink Company LLC, March 2001.

Lifshits Vladimir, Coen Company, Inc., Development of a High Performance Versatile Low NOx 

Burner, Coen Company, Inc., January 2002
APPENDIX A: PAR 1146 PUBLIC COMMENTS AND RESPONSES
PAR 1146.1 Final Staff Report

Appendix A A-1 August 2008

PAR 1146.1: PUBLIC COMMENTS AND RESPONSES

The following comments include those received on or after a Task Force meeting held on 

February 5, 2008, Public Consultation meeting held on March 19, 2008, and the Joint PAR 

1146 and 1146.1 Public Workshop meeting held on April 2, 2008. The comment period for 

the April 2008 Joint PAR 1146 and 1146.1 Public Workshop was April 11, 2008.

1. Comment: What is the basis in allowing an exemption for agricultural operations? 

Response: The exemption was a carryover from previous AQMD practices for agricultural 

operations in the Rule 1146.1 size range. However, due to changes in state law requiring any 

units operated by agricultural sources to be treated similarly to units operated by other 

stationary sources, these units are now subject to Rule 1146.1. Current data suggest that 

there are no agricultural operations subject to Rule 1146.1. On this basis, the exemption has 

been removed from PAR 1146.1.

2. Comment: The applicability in PAR 1146.1 has been widened from boiler, steam generators 

and process heaters rated at 2 mmBtu/hr to include “facilities with multiple units with a total 

rated heat input of more than 3 million Btu per hour.” The stated reason for this revision is to 

prevent boiler owner/operators from circumventing rule requirements by operating or 

installing multiple, smaller units in one facility to accomplish a single function, or by 

derating existing Rule 1146.1 boilers. Since emissions from these smaller units would be 

captured in Rule 1146.2, this addition seems unnecessary and will likely confuse operators. 

It is recommended that rule applicability simply apply to units with a rated input greater than 

2 mmBtu/hr. 

Response: It is correct that staff’s intent for adding the multiple unit approach to the 

applicability section of PAR 1146.1 is to prevent circumvention of the rule requirements. 

That is, staff wanted to add safeguards in the rule to prevent a facility owner from operating 

more than one unit in a size range outside of the Rule 1146.1 applicability with the sole 

purpose to comply with a less stringent requirement. The rule governing smaller size boilers 

and heaters is Rule 1146.2 (0.075 to 2 mmBtu/hr). 

Rule 1146.2 was recently amended in 2006 to a 20 ppm NOx compliance limit. This rule is 

different from both Rule 1146.1 in that the rule requirements are meant for compliance to be 

achieved by the equipment manufacturer rather than the end user. Thus, there is an essential 

difference in rule applicability. 

Propose amendments to Rules 1146.1 would prohibit the derating of units to less than 2 

mmBtu/hr. This proposed change should prevent circumvention from these rules.

On the basis of the proposed amendments there is no longer any need for the rule language to 

address multiple units in PAR 1146.1.

3. Comment: The proposed multiple unit concept should be modified by considering the 

distance between co-located units and whether the units serve common function. 
PAR 1146.1 Final Staff Report

Appendix A A-2 August 2008

Response: Based on the reasons provided in the Response to Comment #2, the proposed 

multiple unit requirement has been removed from PAR 1146.1.

4. Comment: We do not see the value of the proposed provision allowing capacity derating 

within a specific time frame. If owner/operators are willing to permanently limit a boiler’s 

operation, accept a permit condition to that effect, and comply with all applicable regulations 

for the derated unit, such an action should be allowed at any time. 

Response: Staff has removed the provision allowing capacity derating within a specific time 

frame. However, to prohibit rule circumvention capacity derating to below 2 mmBtu/hr 

would not be allowed.

5. Comment: Proposed amendments include new NOx limits for landfill gas and digester gasfired at 25 and 15 ppm, respectively. These represent reductions from the current limit of 30 

ppm and are apparently based on source test reports reviewed by AQMD We request that 

such NOx limits be established only after a rigorous “achieved in practice” criteria has been 

demonstrated (for instance, a technology that is operated reliably for one year, with routine 

operating data to facilitate an evaluation). We also request that such emissions information 

and identification of specific projects be provided in the PAR 1146.1 staff report. 

Response: The proposed limits for landfill and digester gases are 3 and 5 ppm, respectively, 

above the corresponding source test results. Given this fact and that the low-NOx burners 

used in these applications reflect current technology, staff feels that the proposed limits for 

landfill and digester gases are within the “achieved in practice” criteria, providing the 

operation with an adequate compliance margin. Staff has provided more details in the staff 

report on these source test results. However, to protect the confidentiality of the facility, 

project identification will not be provided.

6. Comment: We ask that AQMD staff provide cost effectiveness calculations in the staff 

report to substantiate the information presented in recent public meetings. 

Response: Cost effectiveness calculations are presented in the staff report.

7. Comment: We request that the staff report or environmental assessment include an 

evaluation of the greenhouse gas impact of PAR 1146.1. 

Response: The environmental assessment will include an evaluation of the greenhouse gas 

impact of PAR 1146.1.

8. Comment: Higher CO emission may arise from the applications of ultra low-NOx burners. 

This increase may trigger Best Available Control Technology (BACT) CO limits under new 

Proposed Rule (PR) 407.1. PR 407.1 requires all new and modified sources with increases of 

more than 1 pound per day of CO to be subject to BACT. Current minor source BACT for 

boilers is 100 ppm CO (50 ppm for fire tube boilers), which is much lower than the Rule 
PAR 1146.1 Final Staff Report

Appendix A A-3 August 2008

1146.1 CO limit of 400 ppm. This limit could unacceptably restrict the operating range of 

retrofitted units and require additional CO controls. We request that the staff report and 

environmental assessment for PAR 1146.1 address this issue. 

Response: Examination of San Joaquin Valley Unified Air Pollution Control District 

(SJVUAPCD) source test data have shown that units retrofitted with ultra low-NOx burners 

are well below the 400 ppm CO emission level. In addition, less than 10% of the over 150 

CO test data were below 50 ppm. On this basis, it appears that CO emissions under ultra 

low-NOx burner retrofit conditions do not pose any serious issue.

9. Comment: PAR 1146.1 allows portable analyzers for compliance determinations, if EPA 

Conditional Test Method (CTM)-030 is followed. We strongly disagree with the reliance 

upon CTM-030 because of its complexity. Instead, we again refer to PAR 1110.2, for which 

a portable analyzer protocol has been developed that is more workable than EPA CTM-030. 

Response: Staff will develop a more workable portable analyzer protocol for PAR 1146.1.

10. Comment: PAR 1146.1 provides a new formula for dual fuel boilers in which the NOx limit 

is defined as a weighted average of two fuels’ annual heat input and respective compliance 

limits. While we understand this simple approach creates flexibility for multiple-fuel units, 

we question how this emission will work in practice, particularly for boilers with a backup 

fuel but no co-firing capability. We are more comfortable with a dual compliance limit, each 

consistent with the NOx limit for the respective fuel. 

Response: Staff is proposing an optional approach that will allow co-fired units to apply the 

weighted average approach and those with standby fuel to utilize a dual compliance limit, 

each consistent with the NOx limit for the respective fuel.

11. Comment: The financial burden placed on owners and operators of stationary equipment far 

exceeds the financial burden placed on owners and operators of mobile sources. Stationary 

sources contribute less than 10% of the NOx inventory. Stationary source owners and 

operators must solely pay for the control of their equipment. Yet mobile source owners and 

operators rarely have to directly pay for emission controls on their vehicles. The costs are 

included in the vehicle price, which is subject to market place competition that keeps the 

manufacturer from fully passing on the true cost. And most recently, mobile source owners 

and operators will be receiving incentives totaling hundreds of millions of dollars to retrofit 

or replace their higher emitting vehicles. There are clearly two classes of regulated entities 

and stationary sources are being asked to do more financially than other sources.

Certainly, we understand the difficult task AQMD has in meeting national air quality 

standards without control over mobile sources. However, as AQMD pushes industry with 

even more stringent emission regulations, there is very questionable emission benefit for the 

correspondingly high costs.
PAR 1146.1 Final Staff Report

Appendix A A-4 August 2008

Response: As indicated in the 2007 AQMP, given the state of air quality and health impacts 

on the sixteen million residents in the Basin and the substantial emission reductions this 

region has to achieve by the fast approaching attainment deadlines, we have no choice but to 

seek reductions from all sources to the extent feasible. The recently revised federal 24-hour 

PM2.5 and 8-hour standard will necessitate even further reductions, above and beyond to 

those indicated in the 2007 AQMP.

12. Comment: The proposed emission limits referenced source test data conducted in 

SJVUAPCD. Lower emission limits should not be based on source test data because this 

data does not demonstrate extended, continuous operation at these levels. As the AQMD is 

aware, historically equipment may be tuned before a source test and does not reflect 

consistent and commercially verifiable performance. 

Response: Staff disagrees with the assertion that compliance limits should not be based on 

source test data. Given the fact that this data is based on existing units retrofitted with ultra 

low-NOx burners provides ample evidence that the units will demonstrate extended, 

continuous operation at these levels. The possible circumvention of recently tuned 

equipment would be mitigated with the proposed rule language that an emission 

determination must be conducted at least 250 operating hours, or 30 days subsequent to 

tuning or servicing the unit as part of the proposed monitoring requirements.

13. Comment: For some of the equipment categories in PAR 1146.1 the proposed NOx 

compliance limits are more stringent than Non-Major BACT. It is recommended that the 

AQMD set emission levels at the current BACT level. This approach will provide the 

operator some flexibility in meeting these more stringent emission levels. 

Response: Staff will set the PAR 1146.1 compliance on technically achievable and cost 

effective control options. Non-Major BACT may need to be reevaluated for a more stringent 

limit.

14. Comment: The proposed limit of 9 ppm NOx for is equivalent to BACT for units greater 

than or equal to 20 mmBtu/hr and significantly lower than BARCT in other air districts (15 

ppm in SJVUAPCD). New products meeting BACT have typically gone through years of 

development work at a factory or in the laboratory before they are commercialized. Burner 

technology is matched specifically for the boiler heat exchanger design to maximize unit 

efficiency and minimize air pollutants.

Maximizing system performance on a retrofit basis in the field is more difficult. BARCT 

should reflect emission levels that are attainable by a wider range of products to 

accommodate variations in boiler designs when applying low NOx burner technology. 

Higher emission levels are also needed to accommodate load following units where 

significant turndown is needed in an operation.

It is recommended that the AQMD set emission levels at the lowest established BARCT 

levels. Currently SJVUAPCD has the lowest emission levels in a BARCT rule for this size 
PAR 1146.1 Final Staff Report

Appendix A A-5 August 2008

equipment at 15 ppm NOx. This slightly higher emission level will provide a small cushion 

for operators to meet permit limits on a continuous basis. Boiler service companies have 

stated that achieving lower emission levels is very difficult for load following units below a 3 

to 1 turndown. Significantly higher NOx and CO emission levels may be required for load 

following units when operating at lower inputs. It is also suggested that AQMD meet with 

established burner/boiler manufacturers and service companies to determine more realistic, 

achievable emission levels for load following boilers. 

Response: AQMD staff has relied upon SJVUAPCD source test data and vendor 

information in proposing the various NOx emission limits. All of this information is based 

on realistic, achievable emission levels for a wide range of boiler applications and operations, 

including load following units. It should also be noted that the SJVUAPCD is in the process 

of revising their compliance limits to 9 ppm for units between 2 and 5 mmBtu/hr. The 

SJVUAPCD proposal is based on source test data on retrofitted units well below the 

proposed compliance limits.

15. Comment: We suggest that the proposed language in paragraph (d)(2) be rewritten as 

follows: “An emissions determination shall be conducted at least 250 operating hours, or at 

least thirty days subsequent to the tuning or servicing of the burner system of any unit”. 

Response: AQMD agrees and has made these changes to the proposed language in 

paragraph (d)(2).

16. Comment: PAR 1146.1 would require low fuel use boilers, which includes stand-by boilers, 

to meet a 30 ppm NOx level if greater than 15 years old starting in 2015. This approach is 

consistent with timelines adopted for Rule 1146.2 for boilers with a rated input less than 2 

mmBtu/hr. However, SCAQMD should consider that boilers included in Rule 1146 are far 

larger and more expensive than the smaller units under R1146.2. Because these boilers are 

exempt and many are used as stand-by only, usage factors are also low, with remaining life 

far beyond 15 years use. Manufacturers indicate that atmospheric units will have to be 

replaced to meet 30 ppm NOx. The cost to retrofit forced draft units will be slightly less than 

cost of a new unit.

In light of the high costs (for replacement or retrofit) and low usage factor, it is recommended 

a longer life of 20 years be considered for this equipment category 

Response: For low fuel usage units, AQMD staff agrees with the commentor’s suggestion 

for more time to comply with the 30 ppm limit. Consequently, PAR 1146.1 has been 

modified to allow compliance by January 1, 2015 or when the facility replaces the burners, 

whichever occurs later.

17. Comment: With regards to Attachment 1 it is recommended that staff includes the following 

changes:
PAR 1146.1 Final Staff Report

Appendix A A-6 August 2008

A8. “Add 0.5 to 2.0 percent of O2 to the minimum excess oxygen level found in Step 

7 and ....”

B.1.e.ii “Draft below above draft hood or barometric damper 

Response: Staff has changed the A8 provision in accordance to the commentor’s request but 

has changed the B.1.e.ii provision as follows: Draft at inlet to above draft hood or barometric 

damper. This language should accommodate both the draft hood and barometric damper.

18. Comment: We feel that the staff is taking a great approach in recognizing energy efficiency. 

We do hope the staff will provide a means to correctly evaluate the ultra-low-NOx burner and 

its negative impact to energy efficiency. 

Response: Staff will continue to evaluate the impact of ultra low-NOx burners on energy 

efficiency and ascertain an appropriate trade-off for advanced technologies in conserving fuel 

consumption.

19. Comment: The proposed 9 ppm NOx level must be demonstrated for six months to one 

year.

Response: One of the objectives of the proposed rule amendment is to achieve best available 

retrofit control technology (BARCT). By definition BARCT means an emission limitation 

that is based on the maximum degree of reduction achievable taking into account 

environmental, energy, and economic impacts by each class or category of source. Selection 

of BARCT does not require the six months to one year demonstration. AQMD staff has 

based the 9 ppm selection on over 250 source tests conducted in the SJVUAPCD as well as 

guaranteed levels made by various ultra low-NOx burner manufacturers.

20. Comment: Biogas (landfill and digester) should be defined by up to a volume of 25% 

natural gas. New digester gas fired units may need to be defined by more than 25% natural 

gas. Augmentation with natural gas will help avoid flaring of biogas.

Response: .Subsequent to receiving this comment, AQMD staff had further discussions with 

the commentator on this issue. In addition, staff reviewed available source tests in which 

landfill was co-fired with natural gas and discussed this issue with a burner manufacturer for 

landfill and digester gas units. Based on this investigation, staff concluded that biogas when 

co-fired with natural gas may have problems complying with proposed NOx limit. On this 

basis, the rule has been changed to allow up to 10% natural and still be considered a landfill 

or biogas unit. However, any unit exceeding the 10% natural gas will be required to comply 

with the weighted average specified in paragraph (c)(3).

In addition, the Executive Officer may approve the burning of over 25% natural gas in a 

biogas fired unit at the 15 ppm (digester gas) or 25 ppm (landfill gas) NOx level, when it is 

necessary, if: the only alternative to limiting natural gas to 10% would be shutting down the 

unit and flaring more biogas.
PAR 1146.1 Final Staff Report

Appendix A A-7 August 2008

For new digester gas fired units, the Executive Officer may approve up to 50% natural gas in 

thedigestor boiler unit at the 15 ppm NOx level, also when it is necessary if: the only 

alternative to limiting natural gas to 10% would be shutting down the unit and flaring more 

biogas. These newly installed units must also demonstrate compliance with the NOx limits 

applicable to units fired exclusively on natural gas (i.e., 9 ppm).

These units that have been permitted to operate at the higher than 10% natural gas usage must 

also be based on the facility monthly average biogas usage by the biogas units and the higher 

heating value of the fuels used.

If any digester biogas-fired engine unit burn more than 50%the approved percent natural gas 

then the owner or operator would need to demonstrate compliance with the weighted average 

NOx limit.

21. Comment: CO emissions monitored with portable analyzers should be conducted on a semiannual basis consistent with the frequency of tune-ups required by RECLAIM.

Response: For CO emissions the proposal has been changed to give the owner or operator 

the option to source test or monitor with a portable analyzer. The testing would be conducted 

every five years. The option to monitor with a portable analyzer would be conducted 

quarterly or every 2,000 unit operating hours, whichever occurs later. If a unit is in 

compliance for four consecutive emission checks, without any adjustments to the oxygen 

sensor set points, then the unit may be checked semi-annually or every 4,000 unit operating 

hours, whichever occurs later, until there is a noncompliant emission check.

22. Comment: It would be too costly to retrofit low fuel use units with a 30 ppm burner.

Response: These units would be required to replace their existing burners starting January 1, 

2015 or when they replace their burners, whichever occurs later. The 30 ppm burner has 

been the standard for many years in achieving the minimal amount of NOx emissions from 

these units. In addition, the cost of the burners is relatively low, they are commercially 

available for all types of applications, and the proposed amendment calls for a long lead time 

for burner replacement. On this basis, AQMD staff does not feel that burner replacement 

would result in an undue financial burden for low fuel use units.

23. Comment: The establishment of a 9 or 12 ppm level is beyond what many boilers can do, 

not practical for retrofit, and extremely costly for our type of boiler user in the AQMD.

Response: Source test data in the SJVUAPCD indicate that the 9 ppm level is achievable for 

units in this size range. This was confirmed with various ultra low-NOx burner 

manufacturers. Staff does recognize and has included the costs associated with retrofitting 

units with the 9 ppm burner.
PAR 1146.1 Final Staff Report

Appendix A A-8 August 2008

24. Comment: The current language is not clear on how the equation for the weighted average 

option should be applied for co-fired units. For example, there is no mention of the 

averaging period and there is no effective date for the formula. We suggest a monthly 

weighted limit based on monthly average fuel flows.

Response: There may be a misunderstanding on the application of this formula. The 

formula would be used during the compliance determination testing. Thus, for dual fuels one 

could correlate the concentration in the stack to the relative contribution from each fuel.

25. Comment: In Table 1146.1-1, please change “Compliance Plan” to “Submit Compliance 

Plan on or Before”, update the “Permits to Construct” to “Submit Application for Permit to 

Construct on or before” and update “Full Compliance” to “Unit in Full Compliance by”.

Response: Staff has incorporated these recommended changes.

26. Comment: The 9 ppm NOx level should not apply to thermal fluid heaters. The combustion 

temperature and other operating parameters would not make it possible for these units to 

comply with the proposed standard.

Response: AQMD staff has examined the ability of these relatively few units to comply with 

the 9 ppm NOx level. Based on our review, we agree with the commentator and have 

allowed these thermal fluid heaters to remain at the 30 ppm NOx level.

27. Comment: It is uncertain when the portable analyzer monitoring should commence.

Response: To allow time for the industry to apply the newly developed protocol, the start 

date for the portable analyzers will be July 1, 2009.

28. Comment: Is a low use boiler as specified in paragraph (c)(5) subject to paragraph (d)(7)?

If so, then I don’t believe a facility should have to perform the semi-annual tune-ups if they 

perform the emission checks as specified in paragraph (d)(7). The rigorous emission checks 

should be enough to ensure the unit is in compliance with the emission limits.

Response: Low fuel use boilers would be subject to the monitoring requirements specified 

in paragraph (d)(7). However, the proposal has been changed to require the monitoring to be 

conducted along with the semi-annual or annual tune-up. In addition, the monitoring with the

portable analyzer would not occur until after January 1, 2015 or during burner replacement, 

whichever occurs later.

29. Comment: Paragraph (d)(7) requires that records be maintained for two years. Typically 

Title V facilities need to maintain records for five years. Can you please clarify this issue.

Response: The proposed rule language has been modified to clarify that records should be 

maintained for at least two years and for five years if the units are to be operated in a Title V 

facility.
PAR 1146.1 Final Staff Report

Appendix A A-9 August 2008

30. Comment: According to paragraph (d)(7), is a facility required to install an hour meter?

Response: Only units applying the pound per million Btu option or weighted average 

emission limit would be required to install an hour meter.

31. Comment: The proposed limit specified in Table 1146.1-1 for natural gas fired units should 

be changed, in certain situations, to an alternative limit. For example, a boiler rated at 2.5 

mmBtu/hr with a NOx limit of 12 ppm will not exceed 1 lb/day operating at 24 hours per 

day. Even a unit with a NOx limit of 30 ppm that is limited to a fuel usage that is equivalent 

to 10 hours per day will not exceed 1 lb/day. The 1 lb/day value is the threshold that triggers 

Best Available Control Technology (BACT). I don’t believe that these units should have to 

be replaced to achieve the 9 ppm limit. If the AQMD feels that it’s still necessary then I 

think that these units should be provided more time to replace the equipment.

Response: AQMD staff appreciates the time and effort the commenter has spent in deriving 

this approach to establish NOx emission limits. However, in order to ascertain compliance 

with this method the owner or operator would need to measure NOx emissions in intervals 

less than a one-day period. Only continuous emissions monitoring systems (CEMS) would 

be capable of providing these emission measurements. For the 2 to 5 mmBtu/hr size range 

the application of such measurement devices would be costly. On this basis, AQMD staff 

declines in pursuing this approach to establish NOx emission limits.

32. Comment: According to paragraph (d)(4), the AQMD will require an initial source test for 

each unit. Some permitting engineers issue permits with no testing requirement or if a 

facility submits multiple identical units the permitting engineer may only ask to have one unit 

tested. Will the amended rule require all previously permitted units that were not tested to be 

tested? After adoption, if the AQMD engineer does not specify a testing condition does the 

facility still need to test the unit? Are these initial tests required to be submitted to the 

AQMD?

Response: According to PAR 1146.1 all existing units will be subject to source testing every 

5 years. All source tests, including initial source tests, will be required to be stored onsite. 

For existing sources the first source test would need to be conducted within 5 years of rule 

adoption. However, independent of PAR 1146.1, the AQMD engineer may require a copy of 

the source test.

33. Comment: Atmospheric units with non-sealed combustion would not be able to achieve the 

proposed 9 ppm NOx limit. At these lower NOx levels there are real safety concerns in that 

fugitive CO emissions would emanate from the burner during operation.

Response: AQMD staff is also very concerned with the safe operation of equipment. 

Therefore staff has proposed a 12 ppm limit for natural gas fired atmospheric units with nonsealed combustion.
PAR 1146.1 Final Staff Report

Appendix A A-10 August 2008

The following comments include those received on or after the Joint PAR 1146 and 1146.1

Task Force meetings held on July 10, 2008 and August 14, 2008.

34. Comment: The Current definition for BOILER or STEAM GENERATOR under PAR 

1146.1 (b)(3) and the definition for PROCESS HEATER under PAR 1146.1 (b)(7) refer to

"...combustion equipment fired with liquid and/or gaseous and/or solid fossil fuel..." 

which may be read to exclude biogas or non-fossil fuel units. In order to clarify rule 

applicability to biogas, please consider revising to remove the word "fossil" in both 

definitions, or altering the text to "...combustion equipment fired with liquid and/or gaseous 

and/or solid fossil fuel, digester gas or landfill gas... ".

Response: AQMD staff has added the words “landfill and digester gas” in both definitions.

35. Comment: Is there going to be a training program for those individuals using portable 

analyzers to establish NOx or CO compliance at their facility?

Response: Yes, there will be a training program for individuals using portable analyzers to 

establish NOx or CO compliance at their facility. Language has been added to PAR 1146.1

requiring these individual to undergo this training.