SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT

Final Staff Report

Proposed Amended Rule 1146 - Emissions of Oxides of Nitrogen from 

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

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............1-2

TECHNOLOGY ASSESSMENT.....................................................................................1-3

AFFECTED INDUSTRIES ..............................................................................................1-6

EMISSIONS ..........................................................................................................1-9

PUBLIC PROCESS ........................................................................................................1-11

CHAPTER 2: SUMMARY OF PROPOSED AMENDED RULE 1146

PROPOSED AMENDED RULE 1146 REQUIREMENTS.............................................2-1

CHAPTER 3: IMPACT ASSESSMENT

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

COST EFFECTIVENESS.................................................................................................3-2

INCREMENTAL COST EFFECTIVENESS ...................................................................3-4

CALIFORNIA ENVIRONMENTAL QUALITY ACT (CEQA) ANALYSIS ................3-5

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

DRAFT FINDINGS UNDER CALIFORNIA HEALTH AND SAFETY........................3-6

CODE SECTION 40727

COMPARATIVE ANALYSIS .........................................................................................3-6

TABLES AND FIGURES

TABLE ES-1 - STANDARD PROPOSED NOX LIMITS AND COMPLIANCE 

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

TABLE ES-2 - ENHANCED PROPOSED NOX LIMITS AND COMPLIANCE 

DATES ............................................................................................ES-3

TABLE 1 - NUMBER OF EQUIPMENT

...................................................................................................................1-8
ii

TABLE 2 - EQUIPMENT DISTRIBUTION BY SIZE RANGE/FUEL TYPE

............................................................................................................1-9

TABLE 3 - BASELINE EMISSION BY SIZE RANGE/FUEL TYPE....................1-11

TABLE 4 - STANDARD PROPOSED NOX LIMITS AND COMPLIANCE 

DATES.............................................................................................................. .........2-2

TABLE 5 - ENHANCED PROPOSED NOX LIMITS AND COMPLIANCE 

DATES ........................................................................................................................ 2-4

TABLE 6 - BREAKDOWN OF EMISSION REDUCTIONS BY SIZE RANGE/FUEL 

TYPE .................................................................................................3-2

TABLE 7 - COST EFFECTIVENESS ESTIMATES BY CATEGORY ...................3-4

TABLE 8 - INCREMENTAL COST EFFECTIVENESS ESTIMATES ..................3-5

FIGURE 1 - INDUSTRIES AFFECTED BY RULE 1146...............................................1-6

FIGURE 2 - DISTRIBUTION BY UNIT SIZE................................................................1-8

FIGURE 3 - UNIT DISTRIBUTION BY FUEL USE.....................................................1-9

FIGURE 4 - BASELINE EMISSIONS BY SIZE RANGE ............................................1-10

FIGURE 5 - BASELINE EMISSIONS BY FUEL USE ....................................1-10

FIGURE 6 – EMISSION REDUCTION BY SIZE RANGE .................................3-1

FIGURE 7 - EMISSION REDUCTIONS BY FUEL USE ................................. 3-2

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

APPENDIX A - PUBLIC COMMENTS AND RESPONSES ..................................... A-1
EXECUTIVE SUMMARY
PAR 1146 Final Staff Report

ES -1 August 2008

EXECUTIVE SUMMARY

Rule 1146 – Emissions of Oxides of Nitrogen from Industrial, Institutional, and Commercial 

Boilers, Steam Generators, and Process Heaters was originally adopted in September of 1988. 

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

heat input capacities greater than or equal to 5 million BTU per hour. Rule 1146 establishes 

NOx and CO emission limits, and provides compliance options for units that meet low fuel usage 

thresholds. 

The rule does not apply to electric utility boilers, refinery boilers and process heaters with a rated 

heat input greater than 40 million BTU per hour, sulfur plant reaction boilers, or waste heat 

recovery boilers serving combustion turbines. These sources are subject to other rules. In 

addition, the NOx limits of Rule 1146 do not apply to NOx RECLAIM facilities. Instead, these 

facilities 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 

boilers based on rated heat input capacity. It is also the intent of this proposed amendment to 

harmonize the NOx compliance limits with those limits proposed for Rule 1146.1 – Emissions of 

Oxides of Nitrogen from Small Industrial, Institutional, and Commercial Boilers, Steam 

Generators, and process Heaters. Group I boilers, those rated at greater than or equal to 75 

mmBtu/hr, will be required to meet a lower emission limit than Group II boilers (those rated 

between 20 and 75 mmBtu/hr) and Group III boilers (those rated between 5 and 20 mmBtu/hr). 

This can be accomplished through the use of selective catalytic reduction (SCR) and other 

control technologies such as EMxTM Catalyst. The proposed emission limits for Group II and 

Group III boilers can be met through the use of ultra-low NOx burners. The following tables 

present the proposed emission limits and compliance dates:

Table ES-1

Standard Proposed NOx Limits and Compliance Dates

Rule 

Reference Category Limit Submit Compliance

Plan on or 

before 

Submit 

Application for 

Permit to

Construct on or 

before

Unit Shall be in 

Full 

Compliance on 

or before

(c)(1)(A) All Units Fired on 

Gaseous Fuels

30 ppm or

for natural gas 

fired units 0.036 

lbs/106 Btu

- - (date of 

adoption)

(c)(1)(B) Any Units Fired on 

Non-gaseous Fuels

40 ppm - - (date of 

adoption)

(c)(1)(C) Any Units Fired on 

Landfill Gas

25 ppm - - January 1, 2015

(c)(1)(D) Any Units Fired on 

Digester Gas

15 ppm - - January 1, 2015

(c)(1)(E) Atmospheric Units 12 ppm or

0.015 lbs/106 Btu

January 1, 2010 January 1, 2013 January 1, 2014
PAR 1146 Final Staff Report

ES -2 August 2008

Table ES-1 (continued)

Standard Proposed NOx Limits and Compliance Dates

In lieu of complying with the proposed NOx emission limits and schedules in Table ES-1, the 

owner or operator may opt for an extended compliance date but has to comply with more 

stringent requirements as specified in Table ES-2 shown below. In addition, an owner or 

operator who fails to submit a Compliance Plan or Application for Permit to Construct pursuant 

to the schedule specified in Table ES-1 for any of the Group II units shall be subject to the NOx 

limits and schedule specified in Table ES-2

Rule 

Reference Category Limit Submit Compliance

Plan on or 

before 

Submit 

Application for 

Permit to

Construct on 

or before

Unit Shall be in 

Full 

Compliance on 

or before

(c)(1)(F) Group I Units, 75 

mmBtu/hr or 

greaters

5 ppm or

0.0062 lbs/106 Btu

- January 1, 2012 January 1, 2013

(c)(1)(G) Group II Units

20 to less than 75 

mmBtu/hr - 75% or 

more of units (by 

heat input)

9 ppm or

0.011 lbs/106 Btu

January 1, 2010 January 1, 2011 January 1, 2012

(c)(1)(H) Group II Units

100% of units (by 

heat input)

January 1, 2010 January 1, 2013 January 1, 2014

(c)(1)(I) Group III Units

5 to less than 20 

mmBtu/hr, schools 

and universities -

75% or more of 

units (by heat 

input)

9 ppm or

0.011 lbs/106 Btu

January 1, 2011 January 1, 2012 January 1, 2013

(c)(1)(J) Group III Units

100% of units (by 

heat input)

January 1, 2011 January 1, 2014 January 1, 2015
PAR 1146 Final Staff Report

ES -3 August 2008

Rule 

Reference Category Limit Compliance Plan

Permit to 

Construct

Full 

Compliance

(c)(2)(A) Group II Units

75% or more of units (by 

heat input) 5 ppm or 

0.0062 

lbs/106 Btu

January 1, 2011 January 1, 2013 January 1, 2014

(c)(2)(B) Group II Units

100% of units (by heat 

input)

January 1, 2011 January 1, 2015 January 1, 2016

Table ES-2

Enhanced Proposed NOx Limits and Compliance Dates

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 of NOx emissions with a portable analyzer;

 Prohibiting the de-rating 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 

burner replacement, whichever occurs later;

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

requirements pursuant to California Health & Safety Code sections 130060 and 130061.5; 

and

 Deferred compliance date for certain Group III natural gas-fired units that comply with 

BACT emission limit of 12 ppm or less.

The compliance schedule is staged over a four-year period taking into consideration size range 

and unit operation. Also taken into consideration within the compliance schedule are facilities 

with multiple units and an option for a later compliance date at a more stringent limit. There are 

approximately 1, 068 boilers that will be affected by the proposed amendments

The proposed rule amendment is estimated to reduce 1.2 tons per day of NOx by 2016, which 

reflects an overall 65% reduction in NOx emissions from this source category. Cost 

effectiveness estimates range from $10,100 to $24,900 per ton for sealed units complying with 

the 9 ppm NOx limit (ultra low-NOx burner) and $13,000 to $30,800 per ton for units complying 

with the 5 ppm NOx limit (SCR). For atmospheric boilers, the cost effectiveness of complying 

with the 12 ppm NOx limit is estimated to range from $17,300 to $32,800. 
CHAPTER 1: BACKGROUND

INTRODUCTION

REGULATORY HISTORY

TYPES OF BOILERS, STEAM GENERATORS AND HEATERS

TECHNOLOGY ASSESSMENT

AFFECTED INDUSTRIES

PUBLIC PROCESS
PAR 1146 Final Staff Report

1 - 1 August 2008

INTRODUCTION

Rule 1146 applies to existing boilers, steam generators, and process heaters with maximum rated 

heat input capacities greater than or equal to 5 million BTU per hour. The rule does not apply to 

electric utility boilers, refinery boilers and process heaters with a rated heat input greater than 40 

million BTU per hour, sulfur plant reaction boilers, or waste heat recovery boilers serving 

combustion turbines. These sources are subject to other rules. In addition, the NOx limits of 

Rule 1146 do not apply to NOx RECLAIM facilities. Instead, these facilities are subject to NOx 

limits established through the RECLAIM program. 

REGULATORY HISTORY

Rule 1146 was originally adopted in September of 1988. The rule applies to new and existing 

boilers, steam generators, and process heaters with a maximum rated heat input of 5 million 

(MM) BTU per hour and greater. The rule established a 40 ppm NOx emission limit for units 

with an annual heat input greater than 90,000 therms. For units that did not exceed an annual 

heat input of 90,000 therms, options were provided to either maintain stack gas oxygen at 3 

percent (on a dry basis), operate with a stack gas oxygen trim system, or tune the unit at least 

twice a year. In addition, for units with a rated heat input of 40 mmBtu/hr and greater, 

installation and operation of a continuous in-stack NOx monitor was required if annual heat input 

exceeded 2,000,000 therms. Since original adoption, the rule has been amended four times.

The first amendment occurred in January 1989 and established a 30 ppm NOx emission limit for 

units burning gaseous and/or non-gaseous fuels if the following applies: the unit has a maximum 

rated heat input greater than or equal to 40 million BTU per hour; and annual heat input has 

exceeded 25 percent of the maximum annual fuel consumption rated for the unit. This emission 

limit made the Rule 1146 NOx emission limit consistent with Rule 1109 – Emission of Oxides of 

Nitrogen from Boilers and Process Heaters in Petroleum Refineries. This amendment was 

deemed appropriate because the two categories of applicable equipment were considered similar 

and should therefore be subject to the same emission limit.

In May of 1994 a second amendment to Rule 1146 was made which added a tune-up procedure 

for natural-draft combustion units. The rule already included a tune-up procedure for forceddraft combustion units.

In June 2000, Rule 1146 was amended to incorporate a one-time exemption from the NOx

emission limit. This amendment was very narrow in scope. It allowed a facility that exceeded 

the 90,000 therm fuel usage threshold in 1996 to remain exempt from the NOx emission limit, 

provided that specific administrative requirements were met. This amendment only affected one 

facility and had minimal emissions impact.

The rule was amended a fourth time in November of 2000. This amendment affected emissions 

testing, NOx limits, and fuel metering requirements. The emission testing requirement was 
PAR 1146 Final Staff Report

1 - 2 August 2008

increased to an annual frequency, and the use of hand-held portable monitors was added as a 

valid test method. For units burning gaseous fuels only, NOx limits were lowered to 30 ppm (at 

3% O2) if the annual fuel combustion met or exceeded 90,000 therms per year. For units burning 

a combination of gaseous and non-gaseous fuels, NOx limits were lowered to a weighted average 

emission factor between 30 and 40 ppm (at 3% O2), if annual fuel combustion met or exceeded 

90,000 therms per year. These units also were required to install and operate totalizing fuel 

meters for each fuel line at each unit. If the permit holder agreed to a NOx limit of 30 ppm for 

units burning a combination of gaseous and non-gaseous fuels, then the totalizing fuel metering 

requirement was waived.

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 

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. 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. 
PAR 1146 Final Staff Report

1 - 3 August 2008

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.

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

For gaseous fuels, 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 
PAR 1146 Final Staff Report

1 - 4 August 2008

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.

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. 

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. 

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 Boilers, Steam Generators, and Process 

Heaters – Phase III. The compliance limit when applying this technology to equivalent boilers 

and heaters ranges from 9 to 15 ppm, depending on equipment size and operation. Source tests 

conducted in conjunction with Rule 4306 showed a 95% compliance rate with 9 ppm NOx limits 
PAR 1146 Final Staff Report

1 - 5 August 2008

using ultra low NOx burners. The average NOx concentration was 7 ppm and the smallest unit 

tested was at 6 mmBtu/hr. 

SJVUAPCD is proposing to amend Rule 4306 and add a new Rule 4320 Advanced Emission 

Reduction Options for Boilers, Steam Generators, and Process Heaters Greater than 5.0 

mmBtu/hr. As of March 17, 2008 their proposal is 9 ppm (or 6 ppm for compliance at a later 

date) for equipment greater than 5 mmBtu/hr but less than or equal to 20 mmBtu/hr. Depending 

on the equipment size and selected NOx limit, the proposed compliance date extends from 

January 1, 2011 to January 1, 2013. In lieu of complying with the proposed limits the owner or 

operator has the option of paying into an annual emissions fee.

In addition to SJVUAPCD Rule 4306, Sacramento Metropolitan Air Quality Management 

District (SMAQMD) Rule 411 limits boilers from 9 to 15 ppm, depending on equipment size and 

operation. The Bay Area Air Quality Management District (BAAQMD) is proposing similar 

limits for units greater than 10 mmBtu/hr.

Selected Catalytic Reduction (SCR)

As indicated previously, another technique to reduce NOx emissions is to apply controls 

downstream of the combustion zone, but before NOx is released into the atmosphere. The three 

main methods of post-combustion treatment are Selective Catalytic Reduction (SCR), EMxTM 

Catalyst, and Selective Noncatalytic Reduction (SNCR). In SCR and SNCR methods, urea or 

ammonia is injected or sprayed into the exhaust stream to chemically reduce the NOx into N2. 

Both treatments operate within limited temperature ranges. Recent advancements in catalyst 

have widened the available temperature ranges for effective operation. 

EMxTM Catalyst is a multi-pollutant technology in a single system reducing emissions of NOx, 

SOx, CO, VOC, and PM. This control technology has been in operation in excess of seven years 

with the U.S. EPA declaring this technology as “the Lowest Achievable Emission Rate” (LAER) 

for NOx abatement. EMxTM is an ammonia free reduction technology available for industrial 

boilers and process heaters. Consequently there is no need for ammonia storage, transportation 

or safety issues. EMxTM is a continuous process designed to achieve the required emissions 

reduction at the maximum NOx flowrate. This system does not require a complex feedback 

control loop.

Based on the following information, SCR as applied to Rule 1146 boilers can achieve NOx 

concentrations from 5 to 6 ppm for units greater than or equal to 75 mmBtu/hr. This appears to 

be the most effective and cost-effective alternative for this subcategory of Rule 1146 units.

Consequently, the control assessment will focus on SCRs.

SCR for equipment at power producing facilities subject to Rule 2009 was considered as part of 

the year 2001 RECLAIM amendments and subsequent rule implementation. Under Rule 2009, a 

case-by-case technical and cost-effectiveness evaluation was performed for each boiler. Permit 

information showed that BARCT for the majority of equipment under Rule 2009 ranges from 5 
PAR 1146 Final Staff Report

1 - 6 August 2008

to 9 ppm. The weighted average for all utility boilers, including those higher than 9 ppm, after 

the Rule 2009 retrofits is 7 ppm.

As part of the January 2005 RECLAIM amendment, a 5 ppm NOx concentration limit for 

refinery boilers and heaters greater than 110 mmBtu/hr SCR was determined to be cost-effective 

and technologically feasible.

SJVUAPCD has a more stringent limit than AQMD rules for this subcategory of Rule 1146

refinery boilers/heaters. The SJVUAPCD Rule 4306 NOx limits emissions from units with 

greater than 20 mmBtu/hr input rating to 6 ppm. Application of SCR is an option if the 

equipment owner or operator opted to achieve compliance at later of two dates. Source data 

indicates that several owners or operators opted for the more stringent 6 ppm requirement.

According to the available source data from the SJVUAPCD showed that the NOx emissions 

from the equipment controlled with SCR were at or below 4 ppm.

As previously mentioned, SJVUAPCD is proposing to amend Rule 4306 and add a new Rule 

4320. As of March 17, 2008 their proposal for units greater than 20 mmBtu/hr would be a NOx 

compliance limit of 6 ppm (or 5 ppm for compliance at a later date). Depending on the 

equipment size and selected NOx limit, the proposed compliance date extends from January 1, 

2011 to January 1, 2015. In lieu of complying with the proposed limits the owner or operator has 

the option of paying into an annual emissions fee.

AFFECTED INDUSTRIES

PAR 1146 affects a wide variety of operations within the South Coast Air Basin. Boilers and 

process heaters subject to PAR 1146 include those units used in medical facilities, educational 

institutions, office buildings, hotels, and industrial facilities. Staff has estimated that there are 

about 1,068 active permitted units in the district in the size range affected by this rule 

amendment. 

When grouped according to the Standard Industrial Classification (SIC), the health services 

industry has approximately 19% of the units that are subject to Rule 1146, the largest single 

group. Next, educational services and the food industry each contribute about 11% of the total. 

Chemicals and allied products; nonclassifiable establishments; and personal services each 

comprise approximately 4% of the units that are affected by Rule 1146. Hotels and other lodging 

places and then executive, legislative, and general government each contribute about 3%. Each 

single remaining group comprises less than 4% of the total. Remaining SIC groups include, but 

are not limited to, textile mill products; justice, public order, and safety; fabricated metal 

product; and real estate.
PAR 1146 Final Staff Report

1 - 7 August 2008

Industries Affected by Rule 1146

(Boilers Only)

Health Services 

19%

Executive, 

Legislative, & 

General Gov't 3%

Remaining SIC 

Groups* 41%

Chemical & Allied 

Products 4%

Nonclassifiable 

Establishments 

4%

Hotels & Other 

Lodging Places 

3%

Educational 

Services 11%

Personal Services 

4%

Food & Kindred 

Products 11%

*Each Remaining Group Contributes

 Less Than 3% of the Total

Figure 1

Industries Affected by Rule 1146

The distribution of units affected by PAR 1146 by size range is presented in Table 1 and Figure 2 

as shown below: 

Rating

(mmBtu/hr)

Approximate Number 

of Boilers

5 to < 20 869

20 to<75 184

>75 15

Total 1,068
PAR 1146 Final Staff Report

1 - 8 August 2008

Table 1 – Number of 

Equipment

82%

17% 1%

5 to < 20

20 to < 75

75 ≤

Figure 2 - Distribution by Unit Size

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

Low-fuel usage boilers are operated at a heat input of less than or equal to 90,000 therms per 

calendar year. Currently, there are about 133 boilers (12% of total) that fall under this category. 

A low fuel usage boiler is currently exempt from the NOx and CO limits of the rule provided the 

unit is operated 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. These boilers are required 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 that exceed 90,000 therms annual heat input are required to meet the NOx and CO rule 

requirements. These boilers use either natural, digester, or landfill gas as fuel, and do not operate 

under a compliance plan. Under this category, there are about 915 natural gas fired boilers 

(86%), 11 digester-fired boilers (1%), and nine landfill gas-fired boilers (1%). The boilers are 

expected to comply with the proposed NOx limits through the use of low-NOx or ultra-low NOx 

burners.
PAR 1146 Final Staff Report

1 - 9 August 2008

Number of Units = 1,068

Natural Gas Fired

86%

Digester Gas

1%

Low Fuel Usage

12%

Landfill

1%

Figure 3 – Unit Distribution by Fuel Use

Size Range

LowFuel 

Usage

Natural

Gas

Natural

Gas Natural Gas Landfill Digester

Number of 

Units

(mm btu/hr) (sealed) (atmospheric) Gas Gas

5 to <20 127 609 125 2 6 869

20 to <75 6 173 0 0 5 184

75 or greater 0 8 0 7 0 15

Total 133 790 125 9 11 1,068

Table 2 – Equipment Distribution by Size Range/Fuel Type

EMISSIONS

The total NOx inventory for the units affected by Rule 1146 is estimated to be 1.85 tons per day. 

This estimate was taken from an AQMD data base for the year 2002. The NOx emission 

distribution by the size range and fuel usage are as follows:
PAR 1146 Final Staff Report

1 - 10 August 2008

Rule 1146 Emission Inventory (1.85 tons/day)

by size (mmbtu/hr)

34%

43%

23%

5 to < 20

20 to < 75

75 ≤

Figure 4 - Baseline Emissions by Size Range

Baseline NOx Emissions = 1.85 tpd

by Fuel Use

Low Fuel Usage

6%

Landfill

13%

Natural Gas Fired

79%

Digester Gas

2%

Figure 5 – Baseline Emissions by Fuel Use
PAR 1146 Final Staff Report

1 - 11 August 2008

Size Range

LowFuel 

Usage

Natural

Gas

Natural 

Gas Natural Gas Landfill Digester

Total 

Emissions

(mm btu/hr) (sealed) (atmospheric) Gas Gas

5 to <20 0.115 0.421 0.086 0.005 0.002 0.63

20 to <75 0.005 0.774 0.000 0.000 0.033 0.81

75 or greater 0 0.193 0.000 0.220 0.000 041

Total 0.120 1.388 0.086 0.225 0.035 1.85

Table 3 - Baseline Emission by Size Range/Fuel Type

PUBLIC PROCESS

The rule development effort for PAR 1146 is part of an ongoing process to assess low NOx

technologies for boilers, steam generators, and process heaters. For this rule development, staff 

initially held public consultation meetings on January 18, 2006 and December 12, 2007. 

Subsequently, a series of task force meetings were held on August 16, 2007, October 31, 2007, 

November 30, 2007, January 29, 2008, July 10, 2008, and August 14, 2008. A public 

consultation/CEQA scoping meeting was held on February 22, 2008 followed by a Public 

Workshop on April 2, 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. Staff also held individual meetings and conference calls with manufacturers of 

boilers, steam generators, and process heaters.
CHAPTER 2: SUMMARY OF PROPOSED AMENDED RULE 1146

PROPOSED AMENDED RULE 1146 REQUIREMENTS
PAR 1146 Final Staff Report

2 - 1 August 2008

PROPOSED AMENDED RULE 1146 REQUIREMENTS

Existing Rule

Rule 1146 applies to new and existing industrial, institutional and commercial boilers, steam 

generators, and process heaters with a maximum rated heat input of 5 mmBtu/hr and greater.

The rule does not apply to electric utility boilers, petroleum refinery boilers and process heaters 

with a rated heat input greater than 40 million BTU per hour, sulfur plant reaction boilers, or 

waste heat recovery boilers serving combustion turbines. These sources are subject to other 

rules. In addition, the NOx limits of Rule 1146 do not apply to NOx RECLAIM facilities. 

Instead, these facilities are subject to NOx limits established through the RECLAIM program.

Under Rule 1146, units burning gaseous fuels only are required to meet a NOx limit of 30 ppm 

limit and a CO limit of 400 ppm, if annual fuel usage exceeds 90,000 therms per year. Units 

burning non-gaseous fuels only are required to meet a NOx limit of 40 ppm and a CO limit of 

400 ppm, if annual fuel usage exceeds 90,000 therms per year. 

Units burning a combination of gaseous and non-gaseous fuels are required to meet a weighted 

average emission factor between 30 and 40 ppm, if annual fuel combustion meets or exceeds 

90,000 therms. Further, units with a maximum rated heat input of 40 mmBtu/hr or more and 

which exceed an annual heat input of 200,000 therms are subject to continuous in-stack NOx 

monitoring requirements.

For units that are subject to NOx limits, annual emissions testing requirements apply. Rule 

provisions allow for the approval of hand-held portable monitoring for emissions testing. Fuel 

metering requirements apply to units burning a combination of liquid and gaseous fuels, and 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 0.036 pounds per 106 Btu of heat input, and an alternative to meeting a 

40 ppm NOx limit is to meet 0.052 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.
PAR 1146 Final Staff Report

2 - 2 August 2008

Definitions - Subdivision (b):

In order to address proposed changes to the rule, definitions are proposed to be added. These 

definitions include: Groups I, II and III units, thermal fluid heaters, atmospheric units, and 

schools. There was also added a definition of health facilities. This definition was added to take 

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

seismic safety requirements.

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.

Requirements - Subdivision (c):

There is a carryover of the current NOx compliance limit of 30 ppm for units fired on gaseous 

fuels or 0.036 lb NOx per 106 Btu for natural gas fired units, and 40 ppm for units fired on nongaseous fuels. The optional “lbs per 106 Btu of heat input” limit is proposed to provide 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 90,000 therms per 

year). The proposed NOx compliance limits and schedule are presented in Tables 4 and 5.

Table 4

Standard Proposed NOx Limits and Compliance Dates

Rule 

Reference Category Limit Submit Compliance

Plan on or 

before 

Submit 

Application for 

Permit to

Construct on or 

before 

Unit Shall be 

in Full 

Compliance on 

or before 

(c)(1)(A) All Units Fired 

on Gaseous Fuels

30 ppm or

for natural gas 

fired units 0.036 

lbs/106 Btu

- - (date of 

adoption)

(c)(1)(B) Any Units Fired 

on Non-gaseous 

Fuels

40 ppm - - (date of 

adoption)

(c)(1)(C) Any Units Fired 

on Landfill Gas

25 ppm - - January 1, 2015

(c)(1)(D) Any Units Fired 

on Digester Gas

15 ppm - - January 1, 2015

(c)(1)(E) Atmospheric 

Units

12 ppm or

0.015 lbs/106 Btu

January 1, 2010 January 1, 2013 January 1, 2014

(c)(1)(F) Group I Units, 75 

mmBtu/hr or 

greaters

5 ppm or

0.0062 lbs/106

Btu

- January 1, 2012 January 1, 2013
PAR 1146 Final Staff Report

2 - 3 August 2008

Table 4 (continued)

Standard Proposed NOx Limits and Compliance Dates

In lieu of complying with the proposed NOx emission limits and schedules in Table 4, an owner 

or operator may opt for an extended compliance date for certain boiler category but has to 

comply with a more stringent requirement as specified in Table 5 below. In addition, an owner 

or operator who fails to submit a Compliance Plan or Application for Permit to Construct 

pursuant to the schedule specified in Table 4 for any of the Group II units shall be subject to the 

NOx limits and schedule specified in Table 5.

Rule 

Reference Category Limit Submit Compliance

Plan on or 

before 

Submit 

Application for 

Permit to

Construct on 

or before 

Unit Shall be 

in Full 

Compliance on 

or before 

(c)(1)(G) Group II Units

20 to less than 75 

mmBtu/hr - 75% 

or more of units 

(by heat input)

9 ppm or

0.011 lbs/106

Btu

January 1, 2010 January 1, 2011 January 1, 2012

(c)(1)(H) Group II Units

100% of units (by 

heat input)

January 1, 2010 January 1, 2013 January 1, 2014

(c)(1)(I) Group III Units

5 to less than 20 

mmBtu/hr, 

schools and 

universities - 75%

or more of units 

(by heat input)

9 ppm or

0.011 lbs/106 Btu

January 1, 2011 January 1, 2012 January 1, 2013

(c)(1)(J) Group III Units

100% of units (by 

heat input)

January 1, 2011 January 1, 2014 January 1, 2015
PAR 1146 Final Staff Report

2 - 4 August 2008

Rule 

Reference Category Limit Submit Compliance

Plan on or 

before 

Submit 

Application for 

Permit to

Construct on or 

before 

Unit Shall be 

in Full 

Compliance on 

or before 

(c)(2)(A) Group II Units

75% or more of units (by 

heat input) 5 ppm or 

0.0062 

lbs/106 Btu

January 1, 2011 January 1, 2013 January 1, 2014

(c)(2)(B) Group II Units

100% of units (by heat 

input)

January 1, 2011 January 1, 2015 January 1, 2016

Table 5

Enhanced 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 most 

challenging to meet and may 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 15 and 25 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. The compliance schedule took into consideration 

compliance deadlines for recently amended Rule 1110.2 - Emissions from Gaseous- and LiquidFueled 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.

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

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, 
PAR 1146 Final Staff Report

2 - 5 August 2008

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

digestor 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., either 5 or 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.

A source test was performed in 2003 on one of the 20 digester gas fired units subject to both 

Rules 1146 and 1146.1. 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.

For the nine landfill gas units, source test results on most of these units in the 1997 to 2006 time 

period resulted in NOx emissions ranging from 13 to 23 ppm (~19 ppm average). It should be 

noted that over half of the landfill gas units have a NOx permit limit ranging from 20 to 25 ppm. 

Consequently, most of these units are at or below the proposed NOx 25 ppm limit. Any 

remaining units will have until January 1, 2015 to demonstrate compliance with the proposed 25 

ppm limit.

It is important to note that PAR 1146 for the smaller size units reflects the proposed NOx limits 

specified in Rule 1146.1 (units between 2 and 5 mmBtu/hr). Staff feels that these limits would 

help harmonize the compliance limits for the Rules 1146.1 and 1146.

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:
PAR 1146 Final Staff Report

2 - 6 August 2008

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.

Criteria for the previously mentioned compliance plan have been added to the rule. These 

criteria include:

 Owner/operator contact information (company name, AQMD facility identification 

number, contact name, phone number, address, e-mail address).

 Number and size (mmBtu/hr) of natural gas fired units subject to the requirements.

 Selection of the compliance limit for each of the natural gas fired.

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 for Group II units 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. About 142 units are affected by this proposal.

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 

operating hours or 30 days. For example, let‟s say that a unit which operates 16 hours per day, 6 

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

determination would be within the last 6 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. 
PAR 1146 Final Staff Report

2 - 7 August 2008

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 

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 district 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.

For those units subject to the CEMS requirement, the relative accuracy testing requirement was 

expanded to include 40 CFR part 60 Appendix B Specification 2. This is consistent with the 

requirement specified in paragraph (c)(6).

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

once every three years for units greater than or equal to 10 mmBtu/hr rating, and once every five 

years for units 5 to less than 10 mmBtu/hr rating. This requirement would not affect units which 

are required to install CEMS. The current rule required an annual source test to demonstrate. 

This requirement was added to match the same type of requirement for similar size units in the 

RECLAIM program (ref: Rule 2012 - (d)(1)(ii), (e)(1)(ii), (j)(2) and (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 monthly or every 750 unit operating hours, whichever occurs later. If a unit is in 

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

set points, then the unit may be checked quarterly or every 2,000 unit operating hours, whichever 

occurs later, until there is a noncompliant emission check.

Compliance determination for CO emissions would be accomplished by either applying the 

source test requirements once every three years for units greater than or equal to 10 mmBtu/hr,

and once every five years for units 5 to less than 10 mmBtu/hr. Alternately, in lieu of 

conducting full source tests, the owner or operator has the option to conduct periodic monitoring 

and check CO emissions on or after July 1, 2009, 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 750 

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 2,000 unit operating hours, whichever occurs later, until there is a 

noncompliant emission check.
PAR 1146 Final Staff Report

2 - 8 August 2008

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

(five 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.

Starting in 2003, AQMD staff conducted a four year testing program (407 tests) emissions from 

Rule 1146 boilers and heaters. Using portable analyzers, the study revealed a 31% 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 de-rate 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 90,000 therms per year will be 

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

30 ppm or 0.036 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 
PAR 1146 Final Staff Report

2 - 9 August 2008

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

Officer on or before January 1, 2010

 

Exemptions:

The 90,000 therm exemption will no longer apply to future units. On this basis, this subdivision 

has been removed in the existing version of the 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 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 Final Staff Report

3 - 1 August 2008

EMISSION REDUCTIONS

Emissions data from operating units were taken from AQMD‟s inventory database. Control 

efficiencies were provided by vendors. Estimated capacity (usage) factors and weighted average 

boiler ratings were used to determine baseline emissions for each boiler size category. Emission 

reductions were calculated using the difference between the emission factor for the existing 

emission limit and the proposed NOx compliance limits for the various categories of boilers and 

heaters presented in Table 1. Based on this methodology, the proposed rule amendment is 

estimated to reduce approximately 1.2 tons per day of NOx emissions beginning year 2015, 

which reflects an overall 65% reduction of NOx emissions from this source category. 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. 

Based on staff analysis, the estimated emission reductions by unit size range and type of fuel 

used are presented in Figures 6 and 7. 

Estimated Emission Reductions (tons/day)

by size (mmbtu/hr)

35%

48%

17%

5 to < 20

20 to < 75

75 ≤

Figure 6 - Emission Reduction by Size Range

Total Reductions = 1.2 TPD
PAR 1146 Final Staff Report

3 - 2 August 2008

NOx Emission Reductions = 1.2 tpd

Natural Gas Fired

91%

Digester Gas

1%

Landfill

3% Low Fuel Usage

5%

Figure 7 – Emission Reduction by Fuel Use

Size Range

LowFuel 

Usage

Natural

Gas

Natural

Gas Natural Gas Landfill Digester

Total 

Emission

(mm btu/hr) (sealed) (atmospheric) Gas Gas Reductions 

5 to <20 0.057 0.29 0.051 0.001 0.001 0.4

20 to <75 0.003 0.54 0.000 0.000 0.016 0.6

75 or greater 0 0.16 0.000 0.038 0.000 0.2

Total 0.06 1.00 0.051 0.039 0.017 1.2

Table 6 - Breakdown of Emission Reductions by Size Range/Fuel Type

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 Final Staff Report

3 - 3 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 15 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. 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 above operational parameters, costs for selective catalytic reduction (SCR) 

included ammonia injection and complete regeneration of the catalyst every 5 years. Most of the 

cost data was obtained from Appendix C to SJVUAPCD Rule 4306 Staff Report. A useful life 

of twenty five years was applied in the calculation for SCRs. The 25 year useful life was applied 

to SCRs in the January 2005 amendment to RECLAIM. 

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

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

meeting the new rule requirements. Proposed Amended Rule 1146 includes provisions for 

periodic monitoring of NOx emissions that use a portable analyzer, and source testing 

requirement every three or five years depending on the unit‟s rated heat input.

In estimating the 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.

The proposed rule amendment is estimated to reduce approximately 1.2 tons per day of NOx

emissions by 2017. Based on staff analysis, the cost effectiveness values vary depending on unit 

size, type of burner, and the unit‟s operation and load. The table below shows the estimated cost 

effectiveness values for the size range affected by Proposed Amended Rule 1146.

CE = 
PAR 1146 Final Staff Report

3 - 4 August 2008

Category Control 

Technology

Operating 

Capacity

Cost Effectiveness

($/ton of NOx reduced)

75 mmBtu/hr or greater SCR

100% 11,200

75% 13,000

50% 17,500

25% 30,800

20 mmBtu/hr but less 

than 75 mmBtu/hr 

Ultra-Low NOx 

Burners

100% 9,600

75% 10,100

50% 11,000

25% 14,000

5 mmBtu/hr but less than 

20 mmBtu/hr 

Ultra-Low NOx 

Burners

100% 12,400

75% 13,800

50% 16,500

25% 24,900

Atmospheric Boilers Ultra-Low NOx 

Burners

100% 15,400

75% 17,300

50% 21,200

25% 32,800

Table 7

Cost Effectiveness Estimates by Category

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 option is to use selective catalytic reduction 

(SCR) to meet the more stringent 5 ppm NOx limit for units with rated heat input of 5 mmBtu/hr 

to 75 mmBtu/hr, and compare the cost and emission reduction to those same units using ultra 

low-NOx burners meeting the 9 ppm NOx limit.
PAR 1146 Final Staff Report

3 - 5 August 2008

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

ammonia injection, other operating and maintenance costs, and recurring catalyst replacement 

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

low-NOx burners. 

The table below shows the incremental cost effectiveness values for the size range affected by 

PAR 1146.

Category Capacity

Incremental Cost 

Effectiveness

($/ton of NOx reduced)

5 mmBtu/hr but less than 

20 mmBtu/hr 

100% 123,500

75% 145,700

50% 200,900

25% 334,500

20 mmBtu/hr but less 

than 75 mmBtu/hr 

100% 40,700

75% 48,900

50% 69,300

25% 118,700

Table 8

Incremental Cost Effectiveness Estimates

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) for proposed amended Rule 

1146. Only the topic of hazardous and hazardous materials was identified in the Draft EA as 

exceeding the AQMD‟s daily significance thresholds resulting from operational activities 

associated with the use and storage of aqueous ammonia. The Draft EA was released for a 45-

day public review and comment period from June 13, 2008 to July 29, 2008. One comment letter 

was received from the public relative to the Draft EA. 

Since the release of the Draft EA, responses to the comments have been prepared and included in 

the document. Also, 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. Further, the modifications do not 

constitute significant new information that would require recirculation of the Draft EA pursuant 

to CEQA Guidelines §15088.5. Therefore, the document is a now a Final EA and is included as 

an attachment to this Governing Board package.
PAR 1146 Final Staff Report

3 - 6 August 2008

SOCIOECONOMIC ASSESSMENT

PAR 1146 would affect 532 facilities with at least one boiler or heater (a total of 1,068 units) in 

the district. These facilities are in a wide variety of operations. The most affected sectors in 

terms of number of units are educational services, food manufacturing, health services, 

government, repair and maintenance, real estate, and hotels and other lodging places. 

The average annual cost of PAR 1146 is estimated at $9.6 million between 2012 and 2020. The 

majority of the cost will occur in the sectors of health care services ($3.2 million), educational 

services ($1.1 million), food manufacturing ($0.8 million), and government ($0.7 million). 

PAR 1146 is projected to have 71 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). 

There are four CEQA alternatives associated with the proposed amendments to Rule 1146. 

Alternative A is the No Project Alternative, which is the existing Rule 1146. Alternative B has 

less stringent NOx limits and would have later compliance dates than the proposed amendments. 

Alternative C is more stringent and has earlier compliance dates than the proposed amendments. 

Alternative D has the same requirements as Alternative C except that compliance for all affected 

units would start at a later date than Alternative C. Average annual compliance costs for the 

CEQA alternatives range from $5.4 to $35 million between 2012 and 2020. Average annual jobs 

forgone for the CEQA alternatives range from 27 jobs to 320 jobs.

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 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 type units, the proposed amendments are not in conflict with and do 

not duplicate existing AQMD, state or federal requirements. Since PAR 1146 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 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.

BAAQMD, 2007. Workshop Report: BAAQMD Regulation 9, Rule 7: Nitrogen Oxides and 

Carbon Monoxide from Industrial Institutional, and Commercial Boilers, Steam Generators, and 

Process Heaters. Bay Area Air Quality Management District, May 2007.

SMAQMD, 2005. Staff Report: Rule 411, NOx from Boilers, Process Heaters and Steam 

Generators. Sacramento Metropolitan Air Quality Management District, October 2005.

SJVUAPCD, 2003. Final Draft Staff Report, Proposed Amendments to: Rule 4305 (Boilers, 

Steam Generators, and Process Heaters - Phase 2) and Rule 4351 (Boilers, Steam Generators, 

and Process Heaters - Phase 1) and New Rule 4306 (Boilers, Steam Generators, and Process 

Heaters - Phase 3). San Joaquin Valley Unified Air Pollution Control District, September 2003.

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

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

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 Final Staff Report

Appendix A A-1 August 2008

PAR 1146: PUBLIC COMMENTS AND RESPONSES

The following comments include those received at Task Force meetings held on January 18, 

2006, August 16, 2007, October 31, 2007, and November 30, 2007 and the Public Workshop 

meeting held on December 12, 2007 as well as written comments received on or before 

December 28, 2007. 

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 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. Current data suggest that there 

are no agricultural operations subject to Rule 1146. On this basis, the exemption has been 

removed from PAR 1146.

2. Comment: The applicability in PAR 1146 has been widened from boiler, steam generators 

and process heaters rated at 5 mmBtu/hr to include “facilities with multiple units with a total 

rated heat input of more than 8 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 boilers. Since emissions from these smaller units would be 

captured in Rule 1146.1 or 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 5 mmBtu/hr. 

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

applicability section of PAR 1146 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 applicability with the sole purpose to 

comply with a less stringent requirement. The other rules governing smaller size boilers and 

heaters are Rule 1146.1 (2 to 5 mmBtu/hr) and Rule 1146.2 (0.075 to 2 mmBtu/hr). 

The proposed limit for the smaller size units in Rule 1146 is 9 ppm (0.011 lbs/mmBtu). 

However, staff is bringing forth proposed amendments to Rules 1146 and 1146.1 in the same 

time frame. The same limit of 9 ppm (0.011 lbs/mmBtu) is proposed for Rule 1146.1 units. 

This will harmonize the compliance limits in PAR 1146.1 with the applicable limits in PAR 

1146. On this basis, any circumvention to PAR 1146 should be eliminated. 

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

different from both Rules 1146.1 and 1146 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 and 1146.1 would prohibit the derating of units to less 

than 2 mmBtu/hr. This proposed change should prevent circumvention from these rules.
PAR 1146 Final Staff Report

Appendix A A-2 August 2008

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

address multiple units PAR 1146.

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. 

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

multiple unit requirement has been removed from PAR 1146.

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 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. 

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

impact of PAR 1146.
PAR 1146 Final Staff Report

Appendix A A-3 August 2008

8. Comment: Higher carbon monoxide (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 firetube boilers), which is much 

lower than the Rule 1146 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 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 would appear that CO emissions under 

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

9. Comment: PAR 1146 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.

10. Comment: PAR 1146 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.
PAR 1146 Final Staff Report

Appendix A A-4 August 2008

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.

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 SCR 

or 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 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 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 Group 3 (units less than 20 mmBtu/hr) is 

equivalent to BACT 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. 
PAR 1146 Final Staff Report

Appendix A A-5 August 2008

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 

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 5 to 6 ppm for units greater 20 mmBtu/hr and 9 to 6 

ppm for units less than or equal to 20 mmBtu/hr. Both PAR 1146 and SJVUAPCD proposal 

are 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 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, AQMD 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 has been modified 

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

occurs later.
PAR 1146 Final Staff Report

Appendix A A-6 August 2008

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

changes:

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: Though not directly impacted by this rulemaking the proposed rule changes may 

have an impact on future RECLAIM BARCT analyses. Heaters and boilers firing refinery 

fuel gas have not achieved NOx concentrations of 9 or 12 ppm with burner retrofits. The 

AQMD recognized this issue during the last RECLAIM shave adopted in January 2005, and 

used a higher concentration level for these sources. The PAR 1146 lower concentrations 

applied to sources combusting „gaseous‟ fuel may automatically be applied during the next 

RECLAIM BARCT analysis without regard to the specific gaseous fuel used.

To avoid the automatic application of these limits in future shaves and to preserve the 

opportunity for a focused technology review on sources at refineries combusting refinery fuel 

gas during the next BARCT shave, it is suggested that the AQMD consider one of the 

following rule modifications:

 Rewrite paragraph (b)(2) to eliminate the cutoff of 40 mmBtu/hr for refinery 

sources. Since they are all now regulated under RECLAIM, this should not be 

considered backsliding.

 Add a definition of „gaseous fuels‟ to this regulation which does not include 

refinery fuel gas.

 Modify the compliance limit table by replacing the term gaseous fuels with natural 

gas where appropriate. 

Response: All of the above suggestions are based on the assumption that staff will not 

consider such critical variables as fuel burned in assessing the appropriate control option and 

limit. As related in PAR 1146 staff report as well as the January 2005 RECLAIM staff report 
PAR 1146 Final Staff Report

Appendix A A-7 August 2008

this variable is considered in such analysis. As such, AQMD staff will decline in 

incorporating the above recommendation.

20. Comment: We suggest you provide an incremental cost effectiveness and emission benefit 

analysis for the requirement to go from 9 ppm to 5 ppm. Since the lower limit requires the 

addition of SCR versus what can be achieved with a burner change only. In addition, it is 

important for the public and the decision makers to understand the cost-benefit differential. 

Response: Staff has conducted both a standard and incremental cost effectiveness analysis 

as part of the staff report. However, the incremental cost effectiveness analysis compares the 

proposed control to a more stringent option. Thus, staff declines to make an incremental cost

effectiveness analysis as proposed by the commentator. In addition, a cost-benefit analysis is 

typically not included as part of the staff report. However, we should point out that the 2007 

AQMP did include a cost/benefit analysis, which concluded that benefits far outweighed the 

costs of controls.

21. Comment: It is recommended that the AQMD provide a robust analysis of the impact of 

SCR deployment in the staff report and/or the CEQA document. Since the limits proposed 

by the AQMD for sources with upgraded burners nearly achieve those levels that necessitate 

SCR, it is important that stakeholders understand all the impacts of adding more SCR 

systems in the basin – to smaller and smaller sources. Considerations in this analysis should 

include, but not be limited to, the following:

 Benefit-cost analysis

 Additional risks of ammonia handling during storage/transmission –

proliferation to multiple facilities that may or may not handle ammonia 

currently

 Analysis of the PM2.5 impacts of the 4 -7 ppm NOx differential achieved by 

SCRs vs. the burners (5 ppm vs. 9/12 ppm) to the 5 ppm NH3 slip expected. 

Again, this needs to be done on an incremental basis from what can be 

achieved by the burners

 Particulate and GHG impacts from the additional truck transportation of the 

ammonia. Again, does the 4-7 ppm NOx benefit to PM2.5 attainment 

outweigh the NH3 slip and diesel particulate contribution? 

Response: Except for the benefit-cost analysis, the abovementioned analysis would be 

addressed in the staff report or environmental assessment document. Staff will continue to 

rely upon cost effectiveness analysis (standard and incremental) to provide stakeholders with 

a means to understand the financial impacts associated with rule changes that result in 

lowering the emissions.
PAR 1146 Final Staff Report

Appendix A A-8 August 2008

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

Workshop meeting held on April 2, 2008 as well as written comments received on or after 

the January 29, 2008 and July 10, 2008 Task Force meetings and the February 22, 2008 

Public Consultation/CEQA Scoping meeting.

22. Comment: The proposed 9 ppm NOx level must be demonstrated for 6 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 6 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.

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

natural gas. New digester gas fired units 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 gas 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.

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., either 5 or 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.
PAR 1146 Final Staff Report

Appendix A A-9 August 2008

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.

24. 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 3 years for units greater than or equal to 10 mmBtu/hr and every five years for units 

greater than or equal to 5 mmBtu/hr. The option to monitor with a portable analyzer would 

be conducted monthly or every 750 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 2,000 unit operating hours, 

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

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.

26. Comment: The establishment of a 9 or 12 ppm level in the 5 to 8 mmBtu/hr size category 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.

27. 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.
PAR 1146 Final Staff Report

Appendix A A-10 August 2008

28. Comment: In Table 1146-1 and 1146-2, 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.

29. Comment: Please change paragraph(c)(10) to read the following: The owner or operator of 

Group II or Group III units shall submit for the approval of the Executive Officer a 

compliance plan in accordance with the requirements of Rule 221 – Plans and Rule 306 –

Plan Fees by the applicable date specified in Tables 1146-1 and 1146-2. The compliance 

plan shall include the following information:”

Response: Staff has incorporated these recommended changes.

30. 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.

31. 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.

32. Comment: Is a low use boiler as specified in paragraph (c)(6) subject to paragraph (d)(8)?

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)(8). 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)(8). 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.

33. Comment: Paragraph (d)(8) 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?
PAR 1146 Final Staff Report

Appendix A A-11 August 2008

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.

34. Comment: Paragraph (d)(8) – 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.

35. 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. These types of units 

are typically no larger than 10 mmBtu/hr in size.

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 less than 10 mmBtu/hr in size.

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

1146(b)(4) and the definition for PROCESS HEATER under PAR 1146(b)(12) 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.

37. Comment: Rule 1146(c)(6) states that the continuous in-stack monitor shall be in 

compliance with 40 CFR part 60 Appendix B Specification 2 (see paragraph (c)(6). To be 

consistent with this paragraph, subparagraph (d)(7)(B) should include the same CFR 

reference.

Response: Staff agrees with the commentator and has added the 40 CFR part 60 Appendix B 

Specification 2 to paragraph (c)(7)(B).

38. Comment: Please clarify if units equal to or greater than 40mmBtu/hr must conduct 

full source tests for NOx per PAR 1146 (d)(6)(A) or (B) since the language specifies only 

smaller units. Also, please consider clarifying whether units equal to or greater than 

40mmBtu/hr with more than 200x109 Btu annual usage, which must have continuous in-stack 

NOx monitoring (CEMS), must also have monthly portable analyzer checks for NOx 

per PAR 1146 (d)(8). Finally, we understand that units equal to or greater than 40

mmBtu/hr shall opt to test for CO periodically by either (d)(6) or (d)(8),but if (d)(6) is 

selected, please clarify what frequency shall be followed (i.e. every three years or every five

years).
PAR 1146 Final Staff Report

Appendix A A-12 August 2008

Response: Rule 1146 has been changed to clarify all of the questions raised by the 

commentator. For NOx compliance determination, all units greater than or equal to 10 

mmBtu/hr are required to conduct source tests every 3 years and monitor emissions with 

portable analyzers every month. The exception to this requirement would be those units 

required to install a NOx CEMS.

For CO compliance determination, all units greater than or equal to 10 mmBtu/hr are required 

to conduct source tests every three years or monitor emissions with portable analyzers every 

month. 

39. 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 

requiring these individual to undergo this training.