### 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 Execut ive 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 Sourc es Joe Cassmassi

Author: Rizaldy Calungcagin

– Air Quality Specialist

Reviewed by: Gary Quinn, P.E.

– Program Supervisor

Kurt Wiese

- District CounselSOUTH COAST AIR QUAL ITY MANAGEMENT DISTR ICT

GOVERNING BOARD

Chairman: WILLIAM A. BURKE, E d.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 Citie s 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 San ta 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, ST EAM GENERATORS, AND PROCESS HEATERS

............ 1

- 2

TECHNOLOGY ASSESSMEN T

................................ ................................ ..................... 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 ENVIRONME NTAL QUALITY ACT (CE QA) ANALYSIS

................ 3

- 5

SOCIOECONOMIC ASSESSMENT

................................ ................................ ............... 3

- 5

DRAFT FINDINGS UNDER CALIFORNIA HEALTH AN D SAFETY

........................ 3

- 6

CODE SECTION 40727

COMPARATIVE ANALYSIS

................................ ................................ ......................... 3

- 6

TABLES AND FIGURE S

TABLE ES

- 1

- STANDARD PROPOSED NO X LIMITS AND COMPLIA NCE

DATES ..........................................

.................................................. .ES

- 1

TABLE ES

- 2

- ENHANCED PROPOSED NO X LIMITS AND COMPLIA NCE

DATES .......................................... ..................................................ES

- 3

TABLE 1

- NUMBER OF EQUIPMENT

......................................................... ............ ................................ .......... .... 1

- 8ii

TABLE 2

- EQUIPMENT DISTRIBUTI ON BY SIZE RANGE/FUE L TYPE

............................................................ .............................. ............... ... 1

- 9

TABLE 3

- BASELINE EMISSION BY SIZE RANGE/FUEL TYPE

............. ....... 1

- 11

TABLE 4

- STANDARD PROPOSED NO X LIMITS AND COMPLIA NCE

DATES

......... ................................ ................................ ................................ ..... ......... 2

- 2

TABLE 5

- ENHANCED PROPOSED NOX LIMITS AND COMPLIANCE

DATES

... ........... . ................................ ................................ ................................ ......... 2

- 4

TABLE 6

- BREAKDOWN OF EMISSIO N REDUCTIONS BY SIZE RANGE/FUEL

TYPE .............................................

............................................. . ..... . 3

- 2

TABLE 7

- COST EFFECTIVENESS E STIMATES BY CATEGORY

............ . ..... . 3

- 4

TABLE 8

- INCREMENT AL COST EFFECTIVENES S 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 EMISSIO NS BY SIZE RANGE

................................ ............ 1

- 10

FIGURE 5

- BASELINE EMISSIONS B Y FUEL USE ...........................

...... ...1

- 10

FIGURE 6

– EMISSION REDUCTION B Y SIZE RANGE ..................... ............3

- 1

FIGURE 7

- EMISSION REDUCTIONS BY FUEL USE

................................. 3

- 2

REFERENCES

................................ ................................ ................................ ............... R

- 1

APPENDIX A

- PUBLIC COMMENTS AND R ESPONSES

................................ ..... A

- 1

### EXECUTIVE SUMMARYPAR 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 ser ving 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 prop osed 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 me e t 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 Cata lyst . 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

Pla n 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/10 6 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/10 6 Btu January 1, 2010 January 1, 2013 January 1, 2014PAR 1146 Final Staff Report

ES

- 2 August 2008 

### Table ES

- 1 (continued)

Standard Pr oposed 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 s chedule 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

F ull Compliance on

or before

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

mm B tu /hr or
greaters 5 ppm or

0.0062 lbs/10 6 Btu - January 1, 2012 January 1, 2013

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

20 to less than 75

mm B tu /hr

- 75% or more of units (by heat input) 9 ppm or

0. 011 lbs/10 6 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

mm B tu /hr, schools

and universities

- 75% or more of units (by heat input) 9 ppm or

0.011 lbs/10 6 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, 2015PAR 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/10 6 Btu January 1, 201 1 January 1, 2013 January 1, 2014

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

100% of units (by heat input) January 1, 201 1 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 f ueled 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 Califor nia 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. C ost effectiveness estimates range from $ 1 0

, 1 00 to $2 4

, 9 00 per ton for sealed units complying with the 9 ppm NOx limit (ultra low

- NOx burner) and $1 3

, 0 00 to $3 0

, 8 00 per ton for units complying with the 5 ppm NOx limit (SCR). For atmospheric boilers, the cost effectiveness of complying

with the 1 2 ppm NOx limit is estimated to range from $17,300 to $32,800.

### CHAPTER 1: BACKGROUND

INTRODUCTION

REGULATORY HISTORY

TYPES OF BOILERS, ST EAM GENERATORS AND H EATERS

TECHNOLOGY ASSESSMEN T

AFFECTED INDUSTRIES

PUBLIC PROCESSPAR 1146 Final Staff Report

1

- 1 August 2008 

### INTRODUCTION

R ule 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 N Ox 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 generat ors, 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 Januar y 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 amendm ent 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 n atural

- draft combustion units. The rule already included a tune

- up procedure for forced

draft combustion units.

In June 2000, Rule 1146 was amended to incorporate a one

- time exemption from the NO x 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 NO x emission limit, provided that specific administrative requirement s were met. This amendment only affected one facility and had minimal emissi ons 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 wasPAR 1146 Final Staff Report

1

- 2 August 2008 increased to an annual frequency, and the use of hand

- held po rtable monitors was added as a valid test method. For units burning gaseous fuels only, NOx limits were lowered to 30 ppm (at

3% O 2 ) if the annual fuel combustion met or exceeded 90,000 therms per year. For units burning a combination of gaseous and non

- g aseous fuels, NOx limits were lowered to a weighted average emission factor between 30 and 40 ppm (at 3% O 2 ), if annual fuel combustion met or exceeded 90,000 therms per year. These units also were required to install and operate totalizing fuel

meters fo r 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 Boa rd in June 2007. The plan was designed to demonstrate attainment with national ambient air quality standards for ozone and PM 2.5 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 Saf ety (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 extr eme 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

4091 8 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, ST EAM GENERATORS, AND PROCESS HEATERS

There are many of types of boilers, water heaters and process heaters subj ect 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 i ndustrial 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 w ay 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 Me chanical 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 f rom 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 boi ler, 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 pre ssure 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 temp erature 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 s ections 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 exchang er 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 ASSESSMEN T

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 th e 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 w ith 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 inPAR 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 n itrogen, 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

qu antities, 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 co mplete 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

NO x emissions. Radiant premix burners with ceramic, sintered metal or metal fiber heads spread

the f lame 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 temperatu re 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 NO x 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 NO x burner systems for boilers and process heaters can achieve less t han 9 ppm NO x (at 3% oxygen). NOx formation results primarily from thermal NOx and fuel NOx, and to a lesser extent from prompt NOx.

Ultra l ow NOx b urners have been applied by the San Joaquin Valley Unified Air Pollution

Control District (SJVUAPCD) in th eir 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 c onjunction with Rule 4306 showed a 95% compliance rate with 9 ppm NOx limitsPAR 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 n ew 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 mm Btu /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 h as 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 Ai r 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 combu stion 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 N 2

. 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 Emiss ion Rate” (LAER)

for NOx abatement. EMx TM 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 desig ned to achieve the required emissions reduction at the maximum NOx flowrate. This system d oes 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 pr oducing 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

infor mation showed that BARCT for the majority of equipment under Rule 2009 ranges from 5PAR 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 am endment, 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.

A s 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). Depe nding 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.



### A FFECTED 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 ind ustrial 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 s ervices 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 establish ments; 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 compris es 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 

### Figure 1

Industries Affected by Rule 1146

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

as shown below :

Rating ( mmBtu /hr) Approximate Number
of Boilers

5 to < 20 869

20 to<75 184

>75 15

To tal 1,068PAR 1146 Final Staff Report

1

- 8 August 2008 

### Table 1

– Number of Equipment



## 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 p lan 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

duri ng 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, t here 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 N Ox limits through the use of low

- NOx or ultra

- low NOx

burners.PAR 1146 Final Staff Report

1

- 9 August 2008 

### F igure 3

– Unit Distribution by Fuel Use

Size Range Low

Fuel Usage

Natural

Gas Natural

Gas Natural Gas Landfill Digester Number of

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

5 t o <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 114 6 is estimated to be 1.85 tons per day. This estimate was taken from an AQMD data base for the year 2002. The N O x emission

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

1

- 10 August 2008 

### Figure 4

- Baseline Emissions by Size Range

Figure 5

– Baselin e Emissions by Fuel UsePAR 1146 Final Staff Report

1

- 11 August 2008 Size Range Low

Fuel Usage

Natural

Gas Natural

Gas Natural Gas Landfill Digester Total

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

5 to <20 0.115 0. 421 0.0 86 0.00 5 0.00 2 0. 63

20 to <75 0.005 0. 774 0.000 0.0 00 0.0 33 0. 81 75 or greater 0 0.1 93 0.000 0. 220 0.000 0 41

Total 0.120 1.388 0.0 86 0. 225 0. 0 35 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 NO x 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 meetin gs included representatives from the manufacturers, trade organizations, permit holders for units subject to Rule 1146, and other interested parties. At these meetings low NO x 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 RUL E 1146 REQUIREMENTSPAR 1146 Final Staff Report

2

- 1 August 2008 

### PROPOSED AMENDED RUL E 1 146 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 electr ic 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 inp ut 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 a llow 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 fr om 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% oxy gen. An alternative to meeting a 30 ppm NOx limit is to meet 0.036 pounds per 10 6 Btu of heat input, and an alternative to meeting a 40 ppm NOx limit is to meet 0.052 pounds per 10 6 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 : Group s I, II and III u nits, t hermal f luid h eaters , atmospheric units, and

s chools. 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 l andfill and digester gas was added to the definitions o f Boiler or Steam Generator

and Process Heater . This should provide further clarification tha t these two types of fuels a re 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 0.03 6 lb NOx per 10 6 Btu for natural gas fired units, and 40 ppm for units fired on non

gaseous fuels. The optional “lbs per 10 6 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, exce pt 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

Permi t 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/10 6 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/10 6 Btu January 1, 2010 January 1, 2013 Januar y 1, 2014

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

mmBtu /hr or
greaters 5 ppm or

0.0062 lbs/10 6

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

2

- 3 August 2008 

### Table 4 (continued) Standard Proposed NOx Limits and Compliance Dates

In li eu 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 Su bmit

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/10 6

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 pp m or

0.011 lbs/10 6 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, 2015PAR 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/ 10 6 Btu January 1, 201 1 January 1, 2013 January 1, 2014

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

100% of units (by heat input) January 1, 201 1 January 1, 2015 January 1, 2016



### Table 5 Enhanced Proposed NOx Limits and Compliance Dates

Thermal fluid units have been ide ntified 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 Liquid

Fueled Engines

. This rule requires equipment operated by the same facilities to comply with requirements by July 1, 2012. The intent was not to require compliance limits from two different rules during the same time period for the same facilities.

Rule language was also added stati ng that o n 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 pp m for

landfill a n d 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 t he biogas and natu r al gas.

In addition, t he 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 limitin g natural gas to 10% would be shutting down the unit and flaring

more bio gas

.

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

digest o r boiler unit at the 15 ppm NOx level, also when it is necessary if: th e only alternative to

limiting natural gas to 10% would be shutting down the unit and flaring more bio gas . 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 a ny digest e r bio g as

- fired engine unit burn more than 50% the approved percent natural gas

then the owner or operator would need to demonstrate compl iance 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 insta lled 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 wou ld 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 s hould 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 harmoni ze the compliance limits for the Rules 1146.1 and 1146.

The proposed rule amendment also introduces a weighted average formula for duel fueled co

fired 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

Q A + Q B

Where:

CL A = compliance limit for fuel A

CL B = compliance limit for fuel B

Q A = heat input from fuel A

Q B = heat input from fuel B

This is an optional approach in determining a compli ance 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 10 6 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 cont act 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 t he schedule specified in Table 1

, the owner or operator may opt to comply with the 9 ppm or 0.011 lbs/10 6 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 1 st

. For this situation, the next earliest emission determination would be within the last 6 hours of operation on May 18 th

. 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 31 st

. Thus, the 30

- day criterion w ould 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, an d 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 Pro gram. 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 requ irement, 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 requi rements must be conducted once every three years for units gr eater 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 requ ired 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 fr om 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 che cks, 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

cond ucting 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 Oxi des, 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 sta ff conducted a four year testing program (407 tests) emissions from Rule 1146 boilers and heaters. Using portable analyzers, the study revealed a 31% non

compliance rate. On this basis, the introduction of periodic monitoring in the rule will help

ensure a much lower non

- compliance rate.

The se 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, t he 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 cond ition . 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 th is 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 0.03 6 lbs per 10 6 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 subdiv ision 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

Sec tion 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

13 0060 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

Heal th and Safety Code Section 130061.5 but not to exceed January 1, 2020. ThosePAR 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 th e 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 ENVIRONME NTAL QUALITY ACT (CE QA) ANALYSIS

SOCIOECONOMIC AS SESSMENT

DRAFT FINDINGS UNDER CALIFORNIA HEALTH & SAFETY CODE

SECTION 40727

INCREMENTAL COST

- EFFECTIVENESS

COMPARATIVE ANALYSISPAR 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 NO x 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 pp m 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 Figure s 6 and 7.



### Figure 6

- Emission Reduction by Size Range

Total Reductions = 1.2 TPDPAR 1146 Final Staff Report

3

- 2 August 2008 

### Figure 7

– Emission Reduction by Fuel Use

Size Range Low

Fuel 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. 5 4 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 1.0 0 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 requireme nts, 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 w ith 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 appli ed 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 incorporat e 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 syst ems 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 exce ss 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 N Ox emissions that us e 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 a nd 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 NO x 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 tabl e 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 req uires 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 a mendments, relative to ozone, CO, SOx, NO x , 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 m mBtu /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 oper ating 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 ENVIRONME NTAL QUALITY ACT (CE QA) 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 a ctivities 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.

Sin ce 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 pro vide 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 ASSESS MENT

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

the d istri ct. 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 p laces.

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 mill ion), 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 alte rnatives 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 comparat ive 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, institutio nal, 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.

### REFERENCESPAR 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

Gen erators. 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 Genera tors,
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 Dra ft 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 P erformance Versatile Low NOx
Burner, Coen Company, Inc., January 2002

### APPENDIX A: PAR 114 6 PUBLIC COMMENTS AN D RESPONSESPAR 1146 Final Staff Report

Appendix A A

- 1 August 2008 

### PAR 1146: PUBLIC COM MENTS 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 ag ricultural 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.” T he 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. Sin ce 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 mmB tu/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 fac ility 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,

th ere 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 spe cific 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 NO x limits for landfill gas and digester gas

fired 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 NO x limits be established only after a r igorous “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

us ed 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 d etails 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 greenhou se 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

- NO x burners. This increa se 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 boi lers 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 re port and environmental assessment for PAR 1146 address this issue.

Response: E xamination 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 anal yzer 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 def ined 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 boiler s 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 appl y 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 t he 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 a nd 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, t here 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 reduction s 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 reduc tions, 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 ext ended, 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 compl iance 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 le vels. 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. T his 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 reeval uated 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 hav e 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.

M aximizing 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 Hi gher 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 e mission 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 em ission 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

establishe d 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 em ission 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 s ystem 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 NO x level if greater than 15 year s 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 p pm NO x . 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 cat egory

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 abov e 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 acc ommodate 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 imp act 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 is sue 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 a nalysis 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 b e 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 abo ve 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 reportPAR 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 cond ucted 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 upgrad ed 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 differe ntial 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 env ironmental 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 emiss ions.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 meeting s and the Feb ruary 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 te chnology (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 no t 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 (land fill 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 ha d further discussions

with the commentator on this issue. In addition, staff review ed available source tests in

which landfil l was co

- fired with natural gas and discuss ed this issue with a burner

manufacturer for landfill and digester gas units . Based on th is 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, t he 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 1 0% would be shutting down the

unit and flaring more bio gas

.

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

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

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

bio gas . 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 a ny digest e r bio gas

- fired engine uni t burn more than 50% the approved percent natural gas

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

NOx limit.

24. Comment: CO emissions monitored with portable analyzers should be conducted on a semi

annual 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 y ears 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 occu rs 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 noncom pliant 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, whichev er 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 applicatio ns, 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 langua ge 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 o n 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 t o 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 informa tion:”

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 w ith 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. C omment: 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 r igorous 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 t o 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: Para graph (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 sho uld 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 opti on 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 non

sealed 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 HE ATER 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 rev ising 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 “landf ill 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 , subparagrap h ( 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 40 mm Btu/hr mus t conduct

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

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

40 mm Btu/hr with more than 200x10 9 Btu annual usage, which must hav e continuous in

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

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

mm Btu/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 determ i nation , all units greater than or equal to 10

mm B tu/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

.

F or CO compliance determination, all units greater than or equal to 10 mm B tu/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 add ed to PAR 1146 requiring these individual to undergo this training.