### SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT

Final Staff Report Proposed Amended Rule 1146.1

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

Process Heaters

August 2008

Deput y Executive Officer Planning, Rule Development, and Area Sources Elaine Chang, DrPH

Assistant Deputy Executive Officer Planning, Rule Development, and Area Sources Laki Tisopulos, Ph.D., P.E.

Planning and Rules Manager Planning, Rule Development, and Ar ea Sources

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, Ed.D. Speaker of the Assembly Appointee

Vice Chairman: S. ROY WILSON, Ed.D. Supervisor, Fourth District Riverside County Representative

MEMBERS:

MICHAEL D. ANTONOVICH Supervisor, Fifth District Los Angeles County Representative

MICHAEL A. CACCIO TTI 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 Riversi de Cities Representative, Riverside County

JOSEPH K. LYOU, Ph.D. Governor’s Appointee

GARY OVITT Supervisor, Fourth District San Bernardino County Representative

JAN PERRY Councilmember 

### , City of Los Angeles City of Los Angeles

MIGUEL PULIDO Mayor, Cit y of Santa Ana Cities Representative, Orange County

TONIA REYES URANGA Councilmember, City of Long Beach Cities Representative, Los Angeles County, Western Region

DENNIS YATES Mayor, City of Chino Cities Representative, San Bernardino County

EXECUTIVE O FFICER:

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

### TABLE OF CONTENTS

TABLE OF CONTENTS

................................ ................................ ................................ ... i

EXECUTIVE SUMMARY

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

- 1

CHAPTER 1: BACKGROUND

INTRODUCTION

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

- 1

REGULATORY HISTORY

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

- 1

TYPES OF BOILERS, ST EAM GENERATORS, AND PROCESS HEATERS

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

- 3

TECHNOLOGY ASSESSMEN T

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

- 4

AFFECTED INDUSTRIES

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

- 5

PUBLIC PROCESS

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

- 8

CHAPTER 2: SUMMARY OF PROPOSED AMENDED RULE 1146.1

PROPOSED AMENDED RULE 1146.1 REQUIREMENTS

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

- 1

CHAPTER 3: IMPACT ASSESSMENT

EMISSION REDUCTIONS

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

- 1

COST EFFECTIVENES S

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

- 1

INCREMENTAL COST EFFECTIVENESS

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

- 3

CALIFORNIA ENVIRONME NTAL QUALITY ACT (CE QA) ANALYSIS

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

- 4

SOCIOECONOMIC ASSESSMENT

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

- 5

DRAFT FINDINGS UNDER CALIFORNIA HEALTH AN D SAFETY

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

- 5

CODE SECTION 40727

COMPARATIVE ANALYSIS

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

- 5

TABLES AND FIGURES

TABLE ES

- 1

- SUMMARY OF PROPOSED NOX LIMITS AND COMPL IANCE

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

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

- 1

TABLE 1

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

- 2

TABLE 2

- SUMMARY OF COST EFFECTIVENES S ANALYSIS

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

- 3

TABLE 3

- SUMMARY OF INCREMENT AL COST EFFECTIVENES S

ANALYSIS ...........................

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

- 4

FIGURE 1

- INDUSTRIES AFFECTED BY RULE 1146.1

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

- 6ii August 2008

FIGURE 2

– EQUIPMENT POPULATION BY FUEL USE

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

- 7

FIGURE 3

– BASELINE NO x EMISSIONS

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

- 7

FIGURE 4

– NO x EMISSION REDUCTION

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

- 1

REFERENCES

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

- 1

APPENDIX A

- PUBLIC COMMENTS AND RESPONSES

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

- 1ES

- 1 August 2008



### EXECUTIVE SUMMARYPAR 1146.1 Final Staff Report

ES

- 1 A ugust 2008 

### EXECUTIVE SUMMARY

Rule 1146.1

– Emissions of Oxides of Nitrogen from Small Industr ial, Institutional, and Commercial Boilers, Steam Generators, and Process Heaters was adopted on October 5, 1990.

This rule applies to boilers, steam generators, and process heaters with maximum rated heat input capacities greater than 2 million Btu p er hour and less than 5 million Btu per hour. Rule 1146.1 establishes NOx and CO emission limits, and provides compliance options for units that meet low fuel usage thresholds.

The rule does not apply to NOx RECLAIM facilities. Instead, the units in those facilities in the Rule 1146.1 size range are subject to NOx limits established through the RECLAIM program.

The proposed amendment to this rule would reduce the allowable emission limits of NOx from units with the application of low

- NOx or ult ra low

- NOx burners, with or without the use of flue gas recirculation (FGR). It is also the intent of this proposed amendment to harmonize the NOx compliance limits with those limits proposed for Rule 1146

– Emissions of Oxides of Nitrogen

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

and established in Rule 1146.2

– Emissions of Oxides of Nitrogen from Large Water Heaters and Small Boilers and Process Heaters. The following table presents the proposed NOx emission limits and compliance dates.

Category Limit Submit Application for

Permit to

Construct on or Unit Shall be in Full

Compliance on or before

Any Units Fired on

Landfill Gas 25 ppm January 1, 2014 January 1, 2015

Any Units Fired on Digester Gas 15 ppm January 1, 2014 January 1, 2015

Atmospheric Units 12 ppm or

0.015 lbs/10 6

Btu January 1, 2013 January 1, 2014

Any Units Fired on Natural Gas, Excluding Units

Located at Schools and

Universities 9 ppm or January 1, 2011 January 1, 2012

Any Uni ts Fired on

Natural Gas Located at

Schools and

Universities 0.011 lbs/10 6

Btu January 1, 2013 January 1, 2014



### Table ES

– 1 Proposed NOx Limits and Compliance DatesPAR 1146.1 Final Staff Report

ES

- 2 August 2008 The proposed rule amendment also introduces:



###  A weighted average formula for duel fueled c o

- fired units;



###  Recognition of energy efficient units;



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



###  Monitoring NOx emissions with a portable analyzer;



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



###  Compliance with the 30 ppm NOx limit for low fuel usage units by January 1, 2015 or at time of burner replacement, whichever occurs later; and



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

There are app roximately 1, 070 boilers that may be affected by the proposed amendements. The proposed rule amendment is estimated to reduce approximately 0.29 tons per day of NOx emissions by 2015 , which reflects an overall 71% reduction in NOx emissions from this sour ce category . The average cost effectiveness estimates for boilers and heaters affected by the proposed amendment range from $14, 4 00 to $3 3

, 5 00 per ton. The cost differential is attributed to unit size, types of burners, and the unit’s operation and load.PAR 1146.1 Final Staff Report

ES

- 3 August 2008 

### CHAPTER 1: BACKGROUND

INTRODUCTION

REGULATORY HISTORY

TYPES OF BOILERS AND HEATERS

TECHNOLOGY ASSESSMEN T

AFFECTED INDUSTRIES

PUBLIC PROCESSPAR 1146.1 Final Staff Report

1

- 1 August 2008 

### INTRODUCTION

Rule 1146.1 applies to existing boilers, steam generators, and process heate rs with maximum rated heat input capacities greater than 2 million Btu per hour and less than 5 million Btu per hour. The rule does not apply to units in NOx RECLAIM facilities. Instead, the units in those

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



### REGULATORY HISTORY

Rule 1146.1 was originally adopted in October 5, 1990 and developed pursuant to the 1989 Air Quality Management Plan (AQMP) of the South Coast Air Quality Managemen t District (AQMD). As adopted, the rule applied to new and existing boilers, steam generators, and process heaters with a maximum rated heat input greater than or equal to 2 million BTU per hour and less than 5 million BTU per hour. The rule established a 30 ppm NOx emission limit for units with an annual heat input greater than 18,000 therms. For units that did not exceed an annual heat input of 18,000 therms the owner or operator must either install a non

- resetting fuel use totalizing meter or provide fuel use bills from a fuel supply company based on metering of fuel use indicating that the 18,000 therms per year of heat input per unit was not exceeded . In addition these low fuel usage units must comply with the rule by either semiannual tun e

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

At the time of the original rule adoption there were about 2,700 units in the District with a gross heat input between 2 and 5 million Btu per hour. However, in 1993 about 58% of these units were no longer subject to Rule 1146.1 and instead subject to the RECLAIM program.

The first amendment occurred in July 10, 1992. The amendment was the result of a C ARB notification to the AQMD on February 14, 1992, of c ertain deficiencies in Rule 1146.1. These amendments corrected these deficiencies and other concerns raised by the EPA, prior to the rule’s emission limits taking effect on July 1, 1994. The 1992 amendments specified either

District Method 100.1 as the r equired test method for NOx, CO and O 2 , or Methods 7.1 for NOx

and 10.1 for CO and O 2

.

The method of determining emission in pounds per million Btu was not explained in the rule. The 1992 amendment specified that the method in the Code of Federal Regula tions, Title 40, Part 60, Appendix A, Method 19, Sections 2 and 3 must be used for this determination. EPA uses this method to convert the NOx concentration measured in the stack flue gas of a utility boiler to an emission rate in pounds per million B tu ’ s. For standard fuels such as fuel oil or natural gas, only measurements of NOx and O 2 concentrations in the flue gas are required to make the conversion. The conversion is based on combustion stoichiometry and is applicable to boilers and heaters reg ardless of size.PAR 1146.1 Final Staff Report

1

- 2 August 2008 Other amendments in 1992 affected alternative tune

- up procedures and limiting the start

- up and shutdown period of exemption to a maximum of 6 hours.

O n May 13, 1994 Rule 1146.1 was amended to add a tune up procedure for natural

- draft un its. This addition provided guidelines for tuning natural draft

- fired units that have not exceeded 18,000 therms per year gross heat input from all fuels burned. This was deemed necessary since

natural

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

combustion air fans or blowers.

For this amendment the applicability section was changed to apply to boilers with a rated heat input greater than two million Btu per hour in order to conform to AQMD Rule 219.

Based on industry input, a requirement for approval by USEPA, CARB, and District of equivalent tune up procedures was removed to allow more flexibility of implementation. Also, no tune up was required for units that are not used during the whole calenda r year. At the request

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

In October 2000 Non

- Major Source BACT approved a 12 ppm limit for units fired on natural gas

in the 2 to 5 mmBtu /hr size range.

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

Control Measure MCS

- 01, Facility Modernization. Control Measure MCS

- 01 affects a wide variety of permitted equipment and processes, including boilers, steam generators, and process heaters that are subject to Rule 1146.1. PAR 1146.1 may incorporate the facility modernization concept as a means of implementing this control measure. Through the facility modernization
concept, a s a boiler, steam generator, or process heater ag es and reaches the end of useful life, the unit is either upgraded or replaced to meet NOx emissions limits that are consistent with current BACT. This ensures timely upgrade of existing technology to the cleanest emission levels

available. Based on the 18 years from initial rule compliance (July 1, 1994) to the first proposed compliance date (i.e., January 1, 2012) there appears to an already well developed turnover of

Rule 1146.1 burners.

The AQMP was adopted by the Governing Board in June 2007. T he 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 emi ssion reductions from various non

- RECLAIM combustion sources including boilers and heaters.

The proposed amendments address requirements for Best Available Retrofit Control Technology (BARCT) in accordance with California Health and Safety (H&S) Code § 40 440. Reductions in NOx are necessary to enable the Basin to attain ozone and PM 2.5 standards.

The California Clean Air Act (CCAA) requires districts to achieve and maintain state standards by the earliest practicable date and, for extreme non

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

1

- 3 August 2008 California Code of Regulations, § 15364, as a measure “capable of being accomplished in a successful manner within a reasonable per iod of time, taking into account economic, environmental, legal, social, and technological factors.” The required use of BARCT for existing stationary sources is one of the specified feasible measures. H&S Code §§ 40440 (a)&(b)(1) and 40918 require AQMD to adopt rules requiring best available retrofit control technology for existing sources. H&S Code § 40406 specifically defines BARCT as “...best available retrofit technology means an emission limitation that is based on the maximum degree of reduction

ach ievable 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 subject to AQMD Ru le 1146.1. Boilers and steam generators produce hot water or steam for office buildings, commercial establishments, hospitals, schools and universities, hotels and industrial operations. Process heaters are used to heat material streams for industrial op erations. Process heaters can heat process fluids directly or use a heat exchange fluid. For each application there may be several designs of boilers or heaters available. Boilers and heaters can be classified in several ways including the way heat is t ransferred, the material used in the heat exchanger, and the engineering and safety codes for which the unit is designed to comply.

A unit is classified as a boiler if it is designed to meet the safety standards of the American Society of Mechanical Eng ineers (ASME) Boiler and Pressure Vessel Code. While many boilers are used to produce steam, others provide hot water for a variety of purposes. The components and the entire system of a boiler must meet additional standards including those from

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

codes.

Boilers

Historically, boilers have been built using one of three basic designs: fire tube, water tube or cast iron sectional. In a fire tube boiler, the com bustion 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 directio n through each set of tubes. Multiple passes of the hot combustion gasses through the pressure vessel increase efficiency and increase the temperature and pressure of the water or steam. This type of boiler can be built using a horizontal pressure vessel and horizontal tubes or a vertical pressure vessel and tubes.

In a water tube boiler, the combustion gasses pass over and through banks of tubes containing water. Increasing the number and surface area of water tubes will increase the temperature and pressure of water in the tubes and increase the boiler efficiency. Steel water tube boilers can produce very high temperature water or high pressure steam.PAR 1146.1 Final Staff Report

1

- 4 August 2008 Cast boilers pass combustion gasses over the surface of one or more water containing sections

made of cast iron. Cast boiler sections can also be made from brass or bronze. This type of boiler can only be used to produce low temperature water or low pressure steam.

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

In the combustion process, the rmal NOx is generally the largest contributor of NOx emissions. High flame temperatures trigger the disassociation of nitrogen molecules from combustion air and a chain reaction with oxygen follows to form oxides of nitrogen. Factors that minimize the

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

increased fuel to air ratio.

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

that is bound in fuel combines with oxygen present in combustion air. Because gaseous fuels typically have low nitrogen levels, this mechanism does not play a significant role in NOx formation during natural gas combustion. Similarly, fuel NOx formation does not play a significant role in the combustion of diesel fuel. This fuel is the only non

- gaseous fuel used in significant quantities within the South Coast Air Basin. California has stringent low sulfur standards for diesel fuel. The process used for removing sulfur also removes nitro gen, 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 quanti ties, 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 app roaches can be utilized. Common types of combustion modification include: lowered flame temperature; reduced residence time at high combustion temperature; and reduced oxygen concentration in the high temperature zone. For purposes of complying with the proposed Rule 1146.1 limits the ensuing discussion will be limited to the application of the ultra low

- NOx burner systems.

Ultra Low

- NOx Burner Systems

Often, fuel and air are pre

- mixed prior to combustion. This results in a lower and more uniform

flam e temperature. Some premix burners also use staged combustion with a fuel rich zone to start combustion and stabilize the flame and a fuel lean zone to complete combustion and reduce the peak flame temperature.PAR 1146.1 Final Staff Report

1

- 5 August 2008 Burners can also be designed to spread fl ames 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 flame and produce more radiant heat. When a burner produces more radiant heat, it results in

less hea t 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 int o the burner, is also commonly used. Increasing the amount of primary air and/or use of FGR can reduce flame temperature but it also reduces the temperature of combustion gases through dilution and can reduce efficiency. To maintain efficiency a manufact urer may have to add surface area to the heat exchanger. Increasing the primary air may also destabilize the flame.

Ultra

- low NOx burners require sophisticated controls to maintain emissions levels and efficiency, to stabilize the flame, and to maintain a turndown ratio that is sufficient for the demands of the particular operation.

Ultra low

- NOx burner systems for boilers and process heaters can achieve less than 9 ppm NO x (at 3% oxygen). NOx formation results primarily from thermal NOx and fuel NOx, a nd to a lesser extent from prompt NOx.

Ultra low

- NOx burners have been applied by the San Joaquin Valley Unified Air Pollution Control District (SJVUAPCD) in their Rule 4306. The compliance limit when applying this technology to equivalent boilers and he aters at the upper end of Rule 1146.1 (i.e., 5 mmBtu /hr) ranges from 9 to 15 ppm. Source tests conducted in conjunction with Rule 4306 showed a 95 % compliance rate with 9 ppm NOx limits using ultra low NOx burners. The average NOx

concentration was 7 ppm and the smallest unit tested was at 6 mmBtu /hr. In their March 17, 2008 Proposed Amended Rule (PAR) 4307, for equivalent units in the 2 to 5 mmBtu /hr range,

the proposed limit is 9 ppm. This would apply to new and replaced units effecti ve upon installation on or after January 1, 2010.

In May 2006 AQMD Rule 1146.2 (affecting units between 75,000 Btu /hr and 2 mmBtu /hr) established a NOx limit of 20 ppm. SJVUAPCD is proposing to amend Rule 4306. The current proposal is 9 ppm for all equipment down to 5 mmBtu /hr. The proposed compliance date for PAR 4306 is June 1, 2011.



### AFFECTED INDUSTRIES

PAR 1146.1 affects a wide variety of industries within the South Coast Air Basin. Boilers and heaters subject to PAR 1146.1 includ e those used in medical facilities, educational institutions, office buildings, hotels, and industrial facilities. Staff has estimated that there are about 1,072 active permitted units in the d istrict in the size range affected by this rule. When groupe d according to the Standard Industrial Classification (SIC), the educational services account for about 24% of the units, while health services industry has approximately 10% of the units that are subject to the rule. Next, the food industry contributes a bout 8% of the units and apartments comprise 7% of the total. Hotels and other lodging places have about 4% share of the total RulePAR 1146.1 Final Staff Report

1

- 6 August 2008 1146.1 units. The remaining 47% of the units are distributed over 52 other SIC categories. The distribution by SIC of bo ilers and heaters affected by PAR 1146.1 is shown in Figure 1 below.



### Figure 1

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

Low

- fuel usage boiler s and heaters are units operated at heat input of less than or equal to 18,000 therms per calendar year. Currently, there are about 257 boilers (24% of total) that fall under the

low

- fuel usage category. All units are natural gas fired. Such boilers or heaters are currently exempt from the NOx and CO limits of the rule provided the units are operated at no more than 18,000 therms per year of heat input, and under a compliance plan that specifies certain operating conditions, e.g. periodic tune ups or sta ck gas oxygen concentration of 3% or less, in lieu of meeting the 30 ppm NOx limit. PAR 1146.1 would require these units to meet the current NOx limit of 30 ppm by January 1, 2015 or during burner replacement, whichever is later, through the

use of low

- NO x burners.

Boilers and heaters that exceed 18,000 therms of annual heat input are required to meet the NOx and CO rule requirements. These units use either natural gas or digester gas as fuel. There are about 806 natural gas

- fired boilers and heaters (7 5%) and 9 digester

- fired units (1%). Natural and digester

- gas fired units are expected to comply with the proposed NOx limit of 9 ppm and 15 ppm, respectively, through the use of low

- NOx or ultra

- low NOx burners. Rule 1146.1 Facilities Distributed by Number of Equipment

24%

10%

8% 7% 4% 47% Educational Services

Health Services

Food and Kindred

Products
Apar tments

Hotels and Other Lodging

Places
Remaining 52 CategoriesPAR 1146.1 Final Staff Report

1

- 7 August 2008 The proposed amendment also requires un its fired on landfill gas to meet 25 ppm NOx limit by January 1, 2015. However, there are no landfill gas

- fired boilers for the size range affected by

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



### Figure 2

The total e stima ted NOx emission from all units affected by PAR 1146.1 is 0.41 tons per day. This estimate was taken from AQMD emission database for the year 2002. Figure 3 shows the

distribution of baseline NOx emissions for PAR 1146.1



### Figure 3PAR 1146.1 Final Staff Report

1

- 8 August 2008 

### PUBLIC PROCESS

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

to assess low NO x technologies for boilers, steam generators, and process heaters. There have been five Rule 1146 Task Force meetings from January 2006 to January 2008. These meetings included representatives from the manufacturers, trade organizations, permit holders for units subject to Rule 1146, and other interested parties. At these meetings low NO x technology, equipment useful lives, and proposed emission l imits were discussed.

In parallel with further Rule 1146 rule development efforts, staff held a Rule 1146.1 Task Force meeting on February 5, 2008, a Public Consultation meeting on March 19, 2008, and a Public Workshop on April 2, 2008. In addition, ther e were two joint PAR 1146.1/1146 Task Force held on July 10, 2008 and August 14, 2008. In assessing applicable technology, staff has held individual meetings and conference calls with manufacturers of boilers, steam generators, and process heaters.

### CHAPTER 2: SUMMARY OF PROPOSED AMENDED RULE 1146.1

PROPOSED AMENDED RUL E 1146.1 REQUIREMENT SPAR 1146.1 Final Staff Report

2

- 1 August 2008 

### PROPOSED AMENDED RUL E 1146.1 REQUIREMENT S

Existing Rule

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

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

The rule does not apply to units in NOx RECLAIM facilities. Instead, the units in the Rule 1146.1 size range are subject to NOx limits established through the RECLAIM program.

U nder Rule 1146.1, units burning liquid, gaseous, and/or solid fuels are required to meet a NOx limit of 30 ppm limit and a CO limit of 400 ppm, if annual fuel usage exceeds 18,000 therms per

year.

Fuel metering requirements apply to units exempt from NOx limits due to low fuel usage. Units that are exempt from NOx limits are also required to either maintain stack gas oxygen concentrations at 3% or less (on a dry basis), or tune the unit(s) at least twice per year according to specified tuning procedures.

All NOx limits are specified in ppm by volume at 3% oxygen. An alternative to meeting a 30 ppm NOx limit is to meet 0.037 pounds per 10 6 Btu of heat input.

Proposed Rule Amendments

Applicability

– Subdivision (a): Other than placing this subdivision ahe ad of the “Definitions” subdivision, there are no changes proposed for this subdivision.

The words landfill and digester gas was added to the definitions of Boiler or Steam Generator and Process Heater. This should provide further clarification that thes e two types of fuels are regulated in this rule in addition to fossil fuels.

Definitions

– Subdivision (b):

D efinition s of thermal fluid heaters, atmospheric units, and health facilities, and schools are proposed to be added . The definition of health fac ilities are proposed to be added to take into consideration an extension in the compliance date for health facilities complying with seismic safety requirements.

Requirements

– Subdivision (c): There is a carryover of the current NOx compliance limit of 30 ppm or 0.037 lb NOx per 10 6 Btu. The optional “lbs per 10 6 Btu of heat input” limit is proposed to provide an incentive and credit

for the installation of fuel efficient equipment. At the time of rule adoption this limit would apply to all units, exc ept low fuel usage units (i.e., less than or equal to 18,000 therms per year). The proposed NOx compliance limits and schedule are presented in Table 1.PAR 1146.1 Final Staff Report

2

- 2 August 2008 Category Limit Submit Application for

Permit to

Construct on or

before Unit Shall be in Full

Compl iance on or before

Any Units Fired on

Landfill Gas 25 ppm January 1, 2014 January 1, 2015

Any Units Fired on Digester Gas 15 ppm January 1, 2014 January 1, 2015

Atmospheric Units 12 ppm or

0.015 lbs/10 6

Btu January 1, 2013 January 1, 2014

Any Units Fi red on Natural Gas, Excluding Units

Located at Schools and Universities, and

Thermal Fluid Heaters 9 ppm or January 1, 2011 January 1, 2012

Any Units Fired on

Natural Gas Located at

Schools and Universities, Excluding Thermal

Fluid Heaters 0.011 lbs/1 0 6

Btu January 1, 2013 January 1, 2014



### Table 1 Proposed NOx Limits and Compliance Dates

Thermal fluid units have been identified as equipment that would not be able to meet the proposed 9 ppm NOx limit. On this basis, these units would be required to c ont inue meeting the 30 ppm NOx limit. For atmospheric units

, achieving the 9 ppm NOx limit would be very challenging and most likely result in fugitive CO emissions. Consequently, a 12 ppm NOx limit has been proposed for these units.

The proposed NOx li mits for landfill and digester gas fired units are 25 and 15 ppm, respectively. These limits are based on source data of units operating in the district, allowing for a certain amount of buffer to assure compliance. It should be noted that there were no landfill gas units

identified in the 2 to 5 mm B tu/hr size range. Thus, any further discussion on existing biogas units will be limited to digester gas fired units.

Rule language was also added stating that on or after January 1, 2015, an owner operator o f any landfill or digester gas (biogas) unit co

- fired with natural gas must not operate the unit in a manner that exceeds the NOx emission concentration limits for the biogas units (i.e., 25 ppm for landfill and 15 ppm for digester gas). Operation at the 15 or 25 ppm NOx limit would be deemedPAR 1146.1 Final Staff Report

2

- 3 August 2008 in

- compliance with Rule 1146 provided that the facility monthly average biogas usage by the biogas units is 90 % or more, based on the higher heating value of the fuels used. Any biogas unit exceeding the approved per cent natural gas would then be required to comply with the weighted average NOx limit specified in paragraph (c)(3). That is, the compliance limit would be based on the thermal input of the biogas and natural gas.

In addition, 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 10% would be shutting down the unit and flaring

m ore bio gas

.

For new digester gas fired units, t he Executive Officer may approve up to 50% natural gas in the digest e r boiler unit at the 15 ppm NOx level, also when it is necessary if: the only alternative to limiting natural gas to 10% would be shutting down the unit and flaring more bio gas . These newly installed units must also demonstrate compliance with the NOx limits applicable to units fired exclusively on natural gas (i.e., 9 ppm)

.

These units that have been permitted to operate at the higher tha n 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 digestor bio gas

- 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 15 digester gas fired units. According to the source test results the NOx emissions ranged from about 4 ppm (low fire) to 10 ppm (high fire).

A follow

- up emission check with a portable analyzer on this unit confirmed these NOx emissions. More recently, AQMD staff conducted NOx emission checks with a portable analyzer on two other digester gas fired un its. The NOx emissions from these two units were measured at 9 and 19 ppm. It should be noted that these digester gas units were installed to meet a 30 ppm NOx emission limit. In conjunction with these emission checks and source test, AQMD staf

f contacted a burner vendor who offers products specifically for digester gas units. The vendor confirmed that the 15 ppm NOx limit would be achievable on a consistent basis for digester gas fired units.

The compliance schedule for landfill and digester gas units took into consideration compliance deadlines for recently amended Rule 1110.2 Emissions from Gaseous

- and Liquid

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

Staff feels that the proposed NOx limits would be in harmony with the compliance limits proposed for Rule 1146.PAR 1146.1 Final Staff Report

2

- 4 August 2008 The proposed rule amendm ent also introduces a weighted average formula for duel fueled co

fired units. The formula for calculating the weighted average compliance limit is as follows:

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 compliance limit. Other units with a primary and standby fuel may not want to utilize th is 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 B tu instead of the 400 ppm limit

.

There is a special consideration for those units that had complied with the NOx BACT requirement of less than or equal to 12 ppm. Thus, for those units in lieu of complying with the 9 ppm NOx limit according to the schedule specified in Table 1, the owner or operator may opt to comply with the 9 ppm or 0.011 lbs/10 6 Btu NOx level when the unit’s burner(s) are replaced.

Other proposed changes include clarification on the tune

- up schedule for low fuel usage unit s 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 determinatio n at least 250 operating hours or at least 30 days after tuning or servicing of the unit, unless it is an unscheduled repair. Essentially, a unit that is scheduled for compliance determination (i.e. source test) must not have been subject to a tune

- up or servicing within the previous 250 of operating hours or 30 days. For example, let’s say that a unit which operates 16 hours per day,

six days per week was tuned

- up on May 1 st

. For this situation, the next earliest emission

determination would be within t he last six 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 would be more applicable to units that operate less

fr equently.

In this same paragraph, pre

- tests for emission determinations were prohibited.

Additional test methods, Conditional Test Method CTM

- 030, Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Emissions from Natural Gas

- Fired Engines, B oilers and Process (CL A x Q A ) + (CL B x Q B )PAR 1146.1 Final Staff Report

2

- 5 August 2008 Heaters Using Portable Analyzers and ASTM D6522

- 00(2005) Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas

- Fired Reciprocating Engines, Combustion Turbines , Boilers, and Process Heaters Using Portable Analyzers , have been added to the rule. All emission determinations must be made by a AQMD approved contractor under the Laboratory Approval Program. These methods allow the owner or operator of a sub ject boiler to use a portable analyzer to determine emission compliance. Another alternative to source tests is the use of a continuous in

- stack NOx

monitor.

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

once every five years. The current rule only required a source test to demonstrate initial compliance. This requirement was added to match the same type of requirement for similar size units in the RECLAIM program (ref: Rule 2012 (e)(1)(ii) and 2012(j)(4)).

On or after July 1, 2009, under the proposed amendment the owner or operator must check NOx emissions with a portable NOx, CO and oxygen analyzer according to the Protocol for the Periodic Monitoring of Nitrogen Oxides, Carbon Monoxide, and Oxygen from Uni ts Subject to South Coast Air Quality Management District Rules 1146 and 1146.1 . This monitoring must be

conducted quarterly or every 2,000 unit operating hours, whichever occurs later. If a unit is in compliance for four consecutive emission checks, wit hout any adjustments to the oxygen sensor set points, then the unit may be checked semi

- annually or every 4,000 unit operating hours, whichever occurs later, until there is a noncompliant emission check.

Compliance determination for CO emissions would be accomplished by applying the source test requirements once every five years for units

. Alternatively , in lieu of conducting f u ll source
tests, the owner or operator on or after July 1, 2009 has the option to conduct periodic monitoring

and check CO emissi ons with a portable NOx, CO and oxygen analyzer according to the Protocol for the Periodic Monitoring of Nitrogen Oxides, Carbon Monoxide, and Oxygen from Units Subject to South Coast Air Quality Management District Rules 1146 and 1146.1 . As with

the NOx emissions, this monitoring must be conducted monthly or every 2,000 unit operating hours, whichever occurs later. If a unit is in compliance for four consecutive emission checks, without any adjustments to the oxygen sensor set points, then the unit may b e checked quarterly or every 4,000 unit operating hours, whichever occurs later, until there is a noncompliant

emission check.

Records of all monitoring data must be maintained for a rolling twelve month period of two years (5 years for Title V facilities ) and made available to AQMD staff upon request. Any emission check conducted by AQMD staff that finds excess emissions would be a violation.

If the source test or emission check finds NOx or CO emissions in excess of those al lowed 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 k new of excess emissions, or reasonably should have known, whichever is sooner.PAR 1146.1 Final Staff Report

2

- 6 August 2008 Starting in 2003, AQMD staff conducted a four year testing program (222 tests) emissions from

Rule 1146 .1 boilers and heaters. Using portable analyzers, the study rev ealed a 40% 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 AQ MD

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

.

Owners and operators will continue to have the option to derate their equipment. However, 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 condition . The 2 million Btu per hour lower limit would prohibit units from complying under Rule 1146.2.

Compliance Schedule

– Subdivision (e): The proposed schedule for compliance limits is presented in subdivision (c) “Requirements” (See Table 1 in this report). Schedule for other rule requirements are as follows:



###  Boilers with an annual heat input less than or equal to 18,000 therms per year will be exempt from the proposed emission limits. However, these units would need to meet the 30 ppm or 0.037 lbs per 10 6 Btu NOx emission limit by January 1, 2015 or when the unit has its burners replaced, whichever occurs later.



###  The requirement re lated to the loss of exemption for low fuel usage was moved from subdivision (f) of the current rule to this subdivision and modified to reflect reference to the proposed NOx compliance limits.



###  A time extension would be granted to the full compliance date with the applicable NOx compliance limits for any natural gas fired units for any health facility as defined in Section 1250 of the California Health and Safety Code that can demonstrate that the Office of Statewide Health Planning and Development has appr oved an extension of time to comply with seismic safety requirements pursuant to Health and Safety Code Sections

130060 and 130061.5. The extension of time granted must be consistent with the time extension granted pursuant to Health and Safety Code Sect ion 130060, but not to exceed January 1, 2015, and must be consistent with the time extension granted pursuant to Health and Safety Code Section 130061.5 but not to exceed January 1, 2020. Those health facilities granted a time extension must submit a com pliance plan to the Executive Officer on or before January 1, 2010

Exemptions: The 18,000 therm s exemption will no longer apply to future units. On this basis, this subdivision

has been removed from the existing version of the rule

.

Loss of Exemption :PAR 1146.1 Final Staff Report

2

- 7 August 2008 The loss of exemption provision in the existing version of the rule has been moved to subdivision (e) “Compliance Schedule” of the proposed rule

.

Attachment 1: Figures 1 and 2 have been re

- introduced to Attachment. These example Oxygen/CO and Oxygen/S moke characteristic curves were in the original adopted rule. Also some clarifying language was added to A.8 and B.1.e.ii.

Throughout PAR 1146.1 there are minor amendments to improve the clarity and enforceability of the rule. Compliance dates that have passed have been removed from the rule and equipment now subject to the same requirements has been consolidated into a single paragraph.

### CHAPTER 3: IMPACT ASSESSMENT

EMISSION REDUCTIONS

COST EFFECTIVENESS

CALIFORNIA ENVIRONME NTAL QUALITY ACT (CEQA) ANALYSIS

SOCIOECONOMIC ASSESS MENT

DRAFT FINDINGS UNDER CALIFORNIA HEALTH & SAFETY CODE

SECTION 40727

INCREMENTAL COST

- EFFECTIVENESS

COMPARATIVE ANALYSISPAR 1146.1 Final Staff Report

3

- 1 August 2008 

### EMISSION REDUCTIONS

As mentioned earlier, emission data was extracted from operating data in the AQMD inventory database. Control efficiency for the ultra low

- NOx burners was provided by vendors. Emission reductions were calculated for each unit category using the difference between the emission factor for the existing emission limit and the pr oposed emission factors presented in Table 1. Emission Reduction = Emission Inventory x (Current Limit

– New Limit)/Current Limit

.

The proposed rule amendment is estimated to reduce approximately 0.29 tons per day of NOx emissions by 2015. Natural gas

- fired boilers and heaters operating at an annual heat input of greater than 18,000 therms account for a majority (91%) of the NOx emission reductions. The estimated emission reductions also take into account units that may be exempt due to low fuel

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



### Figure 4

COST EFFECTIVENESS

Cost

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

expres sed in terms of dollars per ton of pollutant reduced. Determination of cost

- effectiveness is required by section 40440(c) of the California Health and Safety Code. Costs can include equipment, materials, energy, or any other costs associated with meeting new regulatory requirements.PAR 1146.1 Final Staff Report

3

- 2 August 2008 The approach for estimating cost

- effectiveness is as follows:

($ Meet New Limits

- $ Continue w/ Existing Limits + $ Early Retirement) Emission Reductions from Existing to New Limits over Equipment Useful Life

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

current dollars. The assumed useful life for ultra

- low NOx burners used in this cost effectiveness calculation is fifteen years. Fifteen years was applied in the recent amendments to Rule 1146.2 (May 2006).

The costs to meet the proposed emission limits were estimated from information obtained through manufacturers and vendors of units for the size range affected by Rule 1146.1. These estimates incorporate capital cost s (including installation) for retrofitting equipment subject to this rule, and costs for any additional fuel and/or electricity use that are associated with meeting the more stringent NOx limits. For instance, some ultra low NOx burner systems require th e use of additional excess air and/or flue gas recirculation. This reduces fuel efficiency and also requires the use of additional electricity for operation of the air blower. These additional costs were estimated using vendor data for excess air and flu e gas recirculation.

In addition to the cost elements mentioned above, staff has also included any incremental costs associated with the proposed monitoring and testing requirements in determining total cost for meeting the new rule requirements. Propo sed Amended Rule 1146.1 includes provisions for quarterly or semi

- annual monitoring of NOx emissions using a portable analyzer, and source testing requirement every five years.

In estimating the total cost of continuing to meet the existing rule requireme nts, staff used equipment, operating and maintenance costs data obtained from various manufacturers and vendors for units that meet the current 30 ppm NOx limit. This cost is deducted from the total cost of meeting the new limits in determining cost effec tiveness of Proposed Amended Rule

1146.1.

The proposed rule amendment is estimated to reduce approximately 0.29 tons per day of NOx emissions by 2015.

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

op erating capacity. The cost effectiveness estimates for units rated at 2 to 5 mmBtu /hr is expected to range from $14, 4 00 to $3 3

, 5 00 per ton of NOx reduced

, depending on the cost differential is attributed to unit size, types of burners, and the unit’s operation and load. The table below shows the cost effectiveness values for the size range affected by P A R 1146.1. It should be noted that this table reflects units reducing the NOx limit from 30 to 9 ppm. For atmospheric units reduci ng the NOx emissions to 12 ppm, the cost effectiveness would be increase by about 17 percent. CE =PAR 1146.1 Final Staff Report

3

- 3 August 2008 Operating Capacity Factor Cost Effectiveness ($/ton NOx reduced)

100% $14, 400

75% $16, 60 0

50% $20, 8 00

25% $3 3

, 5 00



### Table 2 Summary of Cost Effectiv eness Analysis

2 to 5 mmBtu /hr

INCREMENTAL COST

- EFFECTIVENESS

Health and Safety Code Section 40920.6 requires an incremental cost

- effectiveness analysis for Best Available Retrofit Control Technology (BARCT) rules or emission reduction strategies

wh en there is more than one control option which would achieve the emission reduction objective of the proposed amendments, relative to ozone, CO, SOx, NO x , and their precursors.

Incremental cost effectiveness is defined as the difference in control costs d ivided by the difference in emission reductions between two potential control options that can achieve the same emission reduction goal of a regulation.

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

the use of selective catalytic reduction (SCR) to meet the more stringent 5 ppm NOx limit for units affected by PAR 1146 are compared to the control cost and emission reduction of the same units using ultra low

- NOx burners meeting the 9 ppm NOx limit.

For S CR, staff considered various cost factors such as equipment and installation, electricity, ammonia, other operating and maintenance costs, and recurring catalyst replacement cost in determining total cost. A 25

- year s useful life is assumed for SCR and 15 years for ultra low

NOx burners.

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

and ultra low

- NOx burner (9 ppm NOx limit) ranges from $106,000 to $282,700 per ton of NOx reduced depending on the operatin g capacity of the unit. The table below shows the incremental cost effectiveness values for the size range affected by PAR 1146.1.PAR 1146.1 Final Staff Report

3

- 4 August 2008 Capacity Factor (%) Incremental Cost Effectiveness ($/ton NOx reduced)

100 $106,000

75 $124,900

50 $167,300

25 $2 82,700



### Table 3 Summary of Incremental Cost Effectiveness Analysis

2 to 5 mmBtu /hr

CALIFORNIA ENVIRONME NTAL QUALITY ACT (CE QA) ANALYSIS Pursuant to California Environmental Quality Act (CEQA) Guidelines § 15252 and AQMD Rule 110, the AQMD has prepar ed an Environmental Assessment (EA) proposed

amended Rule 1146.1 . The Draft EA was released for a 30

- day public review and comment period from July 2, 2008 to July 31, 2008 and no comment letters were received from the public regarding the Draft EA. The environmental analysis in the Draft EA concluded that proposed amended Rule 1146.1 would not generate any significant adverse environmental impacts.

Since the release of the Draft EA, minor modifications have been made to the document. However, none of the modifications alter any conclusions reached in the Draft EA, nor provide new information of substantial importance relative to the draft document. As a result, these minor revisions do not require recirculation of the Draft EA pursuant to CEQA Guideli nes §15073.5. Therefore, the Draft EA is now a Final EA and is included as an attachment to this Governing Board package.PAR 1146.1 Final Staff Report

3

- 5 August 2008 

### SOCIOECONO MIC ASSESSMENT

Proposed amendments to Rule 1146.1 (PAR 1146.1) would affect 618 facilities with at least one boiler or process heater (a total of 1,072 units) in the d istrict. The affected facilities belong to a number of industries. The most affected in terms of number of units are in the sectors of educational services, professional, scientific, and technical services, and government.

The average annual cost of PAR 1146.1 is estimated at $2.6 million between 2012 and 2020. The majority of the cost will incur in the sectors of educational services ($0.36 million), government ($0.26 million), health care services ($0.26 million), and professional, scientific and technical services ($0.23 million).

PAR 1146.1 is projected to have 16 jobs forgone annu ally in the entire four

- county economy between 2012 and 2020 (less than one

- hundredth of one percent of the total

four

- county employment).



### COMPARATIVE ANALYSIS

Under Health and Safety Code Section 40727.2, the AQMD is required to perform a comparative written analysis when adopting, amending, or repealing a rule or regulation. The comparative analysis is relative to existing federal requirements, exist ing 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 AQM D, state or federal requirements regulating air pollution that are applicable to Rule 1146.1

- type units. The amendment does make an existing AQMD limit or standard more stringent. However, as there are no other existing air pollution requirements for Rul e 1146.1 type units, the proposed amendments are not in conflict with and do not duplicate existing AQMD, state or federal requirements. Since PAR 1146.1 applies to existing industrial, institutional, and commercial boilers, steam generators, and process heaters, Best Available Control Technology requirements under the AQMD’s New Source Review Program are also not applicable.

### REFERENCESPAR 1146.1 Final Staff Report

R

- 1 August 2008 

### REFERENCES

SCAQMD, 2005. Preliminary Draft Staff Report: Proposed Rule 1146.2

- Emissions of Oxides

o f Nitrogen from Large Water Heaters and Small Boilers . South Coast Air Quality Management District, September 2005.

SCAQMD, 2007. Addendum to the Proposed Modifications to the Draft 2007 Air Quality Management Plan, Appendices , South Coast Air Quality Management District, May 2007.

SCAQMD, 2008. Amended Rule 1110.2

- Emissions from Gaseous

- and Liquid

- Fueled Engines , South Coast Air Quality Management District, January 2008

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

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

Webster Timothy, John Zink Company LLC, TODD Combustion Group, Burner Technology for Single Digit NOx Emissions in Boiler Applications, John Zink Company LLC, March 2001.

Lifshits Vladimir, Coen Company, Inc., Development of a High Performance Versatile Low NOx
Burner, Coen Company, Inc., January 2002

### APPENDIX A: PAR 114 6 PUBLIC COMMENTS AN D RESPONSESPAR 1146.1 Fi nal Staff Report

Appendix A A

- 1 August 2008 

### PAR 1146.1: PUBLIC C OMMENTS AND RESPONSE S

The fol lowing comments include those received on or after a Task Force meeting held on February 5, 2008, Public Consultation meeting held on March 19, 2008, and the Joint PAR 1146 and 1146.1 Public Workshop meeting held on April 2, 2008. The comment period for

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

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

Response: The exemption was a carryover from previous AQMD practices for agricultural operation s in the Rule 1146.1 size range. However, due to changes in state law requiring any units operated by agricultural sources to be treated similarly to units operated by other stationary sources, these units are now subject to Rule 1146.1. Current data sug gest that there are no agricultural operations subject to Rule 1146 .1 . On this basis, the exemption has

been removed from P A R 1146.1.

2. Comment: The applicability in PAR 1146.1 has been widened from boiler, steam generators and proc ess heaters rated at 2 mmBtu/hr to include “facilities with multiple units with a total rated heat input of more than 3 million Btu per hour.” The stated reason for this revision is to prevent boiler owner/operators from circumventing rule requirements by operating or installing multiple, smaller units in one facility to accomplish a single function, or by derating existing Rule 1146.1 boilers. Since emissions from these smaller units would be captured in Rule 1146.2, this addition seems unnecessary and w ill likely confuse operators. It is recommended that rule applicability simply apply to units with a rated input greater than

2 mmBtu/hr.

Response: It is correct that staff’s intent for adding the multiple unit approach to the applicability section of PAR 1146.1 is to prevent circumvention of the rule requirements. That is, staff wanted to add safeguards in the rule to prevent a facility owner from operating more than one unit in a size range outside of the Rule 1146.1 applicability with the sole

purpo se to comply with a less stringent requirement. The rule governing smaller size boilers and heaters is Rule 1146.2 (0.075 to 2 mmBtu /hr).

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

different from both R ule 1146.1 in that the rule requirements are meant for compliance to be achieved by the equipment manufacturer rather than the end user. Thus, there is an essential difference in rule applicability.

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

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

On the basis of the proposed amendments there is no longer any need for the rule language to address multiple units in PAR 1146.1.

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

distance between co

- located units and whether the units serve common function.PAR 1146.1 Fi nal Staff Report

Appendix A A

- 2 August 2008 Response: Based on the reasons provided in the Response to Comment #2, the proposed multiple unit re quirement has been removed from PAR 1146.1.

4. Comment: We do not see the value of the proposed provision allowing capacity derating within a specific time frame. If owner/operators are willing to permanently limit a boiler’s operation, accept a permit con dition 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 prohibi t rule circumvention capacity derating to below 2 mm B tu/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 lim it 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 rigorous “achieved in practice” criteria has been demonstrated (for instance, a technology that is operated reliably for one year, with routine operating data to facilitate an evaluation). We also request that such emissions information and identification of specific projects be provided in the PAR 1146.1 staff report.

Response: The proposed limits for landfill and d igester gases are 3 and 5 ppm, respectively, above the corresponding source test results. Given this fact and that the low

- NOx burners used in these applications reflect current technology, staff feels that the proposed limits for landfill and digester gases are within the “achieved in practice” criteria, providing the operation with an adequate compliance margin. Staff has provided more details in the staff report on these source test results. However, to protect the confidentiality of the facility, project identification will not be provided.

6. Comment: We ask that AQMD staff provide cost effectiveness calculations in the staff report to substantiate the information presented in recent public meetings.

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

7. Comment: We request that the staff report or environmental assessment include an evaluation of the greenhouse gas impact of PAR 1146.1.

Response: The environmental assessment will include an evaluation of the greenhouse gas impact of PAR 1146.1.

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

- NO x burners. This increase may trigger Best Available Control Technology (BACT) CO limits under new Proposed Rule (PR) 407.1. PR 407.1 requires all new and modified sources with increases of more than 1 pound per day of CO to be subject to BACT. Current minor source BACT for boilers is 100 ppm CO (50 ppm for fire tube boilers), which is much lower than the RulePAR 1146.1 Fi nal Staff Report

Appendix A A

- 3 August 2008 1146.1 CO limit of 400 ppm . This limit could unacceptably restrict the operating range of retrofitted units and require additional CO controls. We request that the staff report and

environmental assessment for PAR 1146.1 address this issue.

Response: 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 appears that CO emissions under ultra

low

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

9. Comment: PAR 1146.1 allows portable analyzers for compliance determinations, if EPA Conditional Test Method (CTM)

- 030 is followed . We strongly disagree with the reliance upon CTM

- 030 because of its complexity. Instead, we again refer to PAR 1110.2, for which a portable analyzer protocol has been developed that is more workable than EPA CTM

- 030.

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

10. Comment: PAR 1146.1 provides a new formula for dual fuel boilers in which the NOx limit is defined as a weighted average of two fuels’ annual heat input and respective compliance

limits. While we un derstand this simple approach creates flexibility for multiple

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

fuel but no co

- firing capability. We are more comfortable with a dual compliance limit, each consistent with the NOx limit for the respective fuel.

Response: Staff is proposing an optional approach that will allow co

- fired units to apply the weighted average approach and those with standby fuel to utilize a dual compliance limit,

each cons istent with the NOx limit for the respective fuel.

11. Comment: The financial burden placed on owners and operators of stationary equipment far exceeds the financial burden placed on owners and operators of mobile sources. Stationary

sources contribute less than 10% of the NOx inventory. Stationary source owners and operators must solely pay for the control of their equipment. Yet mobile source owners and operators rarely have to directly pay for emission controls on their vehicles. The costs are

included in the vehicle price, which is subject to market place competition that keeps the manufacturer from fully passing on the true cost. And most recently, mobile source owners and operators will be receiving incentives totaling hundreds of millions of dollar s to retrofit or replace their higher emitting vehicles. There are clearly two classes of regulated entities and stationary sources are being asked to do more financially than other sources.

Certainly, we understand the difficult task AQMD has in meeting national air quality standards without control over mobile sources. However, as AQMD pushes industry with even more stringent emission regulations, there is very questionable emission benefit for the correspondingly high costs.PAR 1146.1 Fi nal Staff Report

Appendix A A

- 4 August 2008 Response: As indicated i n the 2007 AQMP, given the state of air quality and health impacts

on the sixteen million residents in the Basin and the substantial emission reductions this region has to achieve by the fast approaching attainment deadlines, we have no choice but to

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

- hour

PM2.5 and 8

- hour standard will necessitate even further reductions, above and beyond to those indicated in the 2007 AQMP.

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

SJVUAPCD. Lower emission limits should not be based on source test data because this data does not demonstrate extended, continuous operation at these levels. As the AQMD is aware, historically equipment may be tuned b efore a source test and does not reflect consistent and commercially verifiable performance.

Response: Staff disagrees with the assertion that compliance limits should not be based on source test data. Given the fact that this data is based on existing units retrofitted with ultra

low

- NOx burners provides ample evidence that the units will demonstrate extended, continuous operation at these levels. The possible circumvention of recently tuned equipment would be mitigated with the proposed rule language that an emission determination must be conducted at least 250 operating hours, or 30 days subsequent to tuning or servicing the unit as part of the proposed monitoring requirements.

13. Comment: For some of the equipment categories in PAR 1146.1 the propose d NOx compliance limits are more stringent than Non

- Major BACT. It is recommended that the AQMD set emission levels at the current BACT level. This approach will provide the operator some flexibility in meeting these more stringent emission levels.

Res ponse: Staff will set the PAR 1146.1 compliance on technically achievable and cost effective control options. Non

- Major BACT may need to be reevaluated for a more stringent

limit.

14. Comment: The proposed limit of 9 ppm NOx for is equivalent to BACT for u nits greater than or equal to 20 mmBtu /hr and significantly lower than BARCT in other air districts (15 ppm in SJVUAPCD). New products meeting BACT have typically gone through years of development work at a factory or in the laboratory before they ar e commercialized. Burner technology is matched specifically for the boiler heat exchanger design to maximize unit efficiency and minimize air pollutants.

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

should refl ect emission levels that are attainable by a wider range of products to accommodate variations in boiler designs when applying low NOx burner technology. Higher emission levels are also needed to accommodate load following units where significant turndown is needed in an operation.

It is recommended that the AQMD set emission levels at the lowest established BARCT levels. Currently SJVUAPCD has the lowest emission levels in a BARCT rule for this sizePAR 1146.1 Fi nal Staff Report

Appendix A A

- 5 August 2008 equipment at 15 ppm NOx. This slightly higher emissio n level will provide a small cushion for operators to meet permit limits on a continuous basis. Boiler service companies have stated that achieving lower emission levels is very difficult for load following units below a 3 to 1 turndown. Significantly hi gher NOx and CO emission levels may be required for load following units when operating at lower inputs. It is also suggested that AQMD meet with established burner/boiler manufacturers and service companies to determine more realistic,

achievable emissio n levels for load following boilers.

Response: AQMD staff has relied upon SJVUAPCD source test data and vendor information in proposing the various NOx emission limits. All of this information is based on realistic, achievable emission levels for a wid e range of boiler applications and operations, including load following units. It should also be noted that the SJVUAPCD is in the process of revising their compliance limits to 9 ppm for units between 2 and 5 mm B tu/hr. The SJVUAPCD proposal is based on source test data on retrofitted units well below the proposed compliance limits.

15. Comment: We suggest that the proposed language in paragraph (d)(2) be rewritten as follows: “An emissions determination shall be conducted at least 250 operating hours, or at least thirty days subsequent to the tuning or servicing of the burner system of any unit”.

Response: AQMD agrees and has made these changes to the proposed language in paragraph (d)(2).

16. Comment: PAR 1146.1 would require low fuel use boilers, which i ncludes stand

- by boilers, to meet a 30 ppm NO x level if greater than 15 years old starting in 2015. This approach is consistent with timelines adopted for Rule 1146.2 for boilers with a rated input less than 2 mmBtu/hr. However, SCAQMD should consider th at 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. Manufac turers indicate that atmospheric units will have to be replaced to meet 30 ppm 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 i s recommended a longer life of 20 years be considered for this equipment category

Response: For low fuel usage units, AQMD staff agrees with the commentor’s suggestion for more time to comply with the 30 ppm limit. Consequently, PAR 1146.1 has been

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

whichever occurs later.

17. Comment: With regards to Attachment 1 it is recommended that staff includes the following changes:PAR 1146.1 Fi nal Staff Report

Appendix A A

- 6 August 2008 A8. “Add 0.5 to 2.0 percent of O2 to the m inimum excess oxygen level found in Step

7 and ....”

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

Response: Staff has changed the A8 provision in accordance to the commentor’s request but has changed the B.1.e.ii provision as follows: Draf t at inlet to above draft hood or barometric damper. This language should accommodate both the draft hood and barometric damper.

18. Comment: We feel that the staff is taking a great approach in recognizing energy efficiency. We do hope the staff will provi de a means to correctly evaluate the ultra

- low

- NOx burner and its negative impact to energy efficiency.

Response: Staff will continue to evaluate the impact of ultra low

- NOx burners on energy efficiency and ascertain an appropriate trade

- off for advance d technologies in conserving fuel consumption.

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

year.

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

retrofit control technol ogy (BARCT). By definition BARCT means an emission limitation that is based on the maximum degree of reduction achievable taking into account environmental, energy, and economic impacts by each class or category of source. Selection of BARCT does not req uire the six months to one year demonstration. AQMD staff has based the 9 ppm selection on over 250 source tests conducted in the SJVUAPCD as well as guaranteed levels made by various ultra low

- NOx burner manufacturers.

20. Comment: Biogas (landf ill and digester) should be defined by up to a volume of 25% natural gas. New digester gas fired units may need to be defined by more than 25% natural

gas

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

Response:

. Subsequent to receiving this comment, AQMD staff had further discussions with the commentator on this issue. In addition, staff reviewed available source tests in which

lan dfill was co

- fired with natural gas and discussed this issue with a burner manufacturer for landfill and digester gas units. Based on this investigation, staff concluded that biogas when

co

- fired with natural gas may have problems complying with proposed NOx limit. On this basis, the rule has been changed to allow up to 10 % natural and still be considered a landfill or biogas unit. However, any unit exceeding the 10 % natural gas will be required to comply with the weighted average specified in paragraph (c)(3).

In addition, 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 10 % would be shutting down the

unit and flaring more bio gas

.PAR 1146.1 Fi nal Staff Report

Appendix A A

- 7 August 2008 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 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., 9 ppm)

.

These units that ha ve 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 gas

- fired engine unit burn more th an 50% the approved percent natural gas then the owner or operator would need to demonstrate compl iance with the weighted average

NOx limit.

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

annual basis consistent wit h the frequency of tune

- ups required by RECLAIM.

Response: For CO emissions the proposal has been changed to give the owner or operator the option to source test or monitor with a portable analyzer. The testing would be conducted

every five year s. The option to monitor with a portable analyzer would be conducted quarterly or every 2,000 unit operating hours, whichever occurs later. If a unit is in compliance for four consecutive emission checks, without any adjustments to the oxygen

sensor set points, then the unit may be checked semi

- annually or every 4,000 unit operating hours, whichever occurs later, until there is a noncompliant emission check.

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

Response: These units would be required to replace their existing burners starting January 1, 2015 or when they replace their burners, whichever occurs later. The 30 ppm burner has been the standard for many years in achieving the minimal amount of NOx emissions f rom these units. In addition, the cost of the burners is relatively low, they are commercially available for all types of applications, and the proposed amendment calls for a long lead time for burner replacement. On this basis, AQMD staff does not feel that burner replacement

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

23. Comment: The establishment of a 9 or 12 ppm level is beyond what many boilers can do, not practical for retrofit, and extremely costly for our type of boil er 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 co sts associated with retrofitting units with the 9 ppm burner.PAR 1146.1 Fi nal Staff Report

Appendix A A

- 8 August 2008 24. Comment: The current language is not clear on how the equation for the weighted average option should be applied for co

- fired units. For example, there is no mention of the averaging period a nd there is no effective date for the formula. We suggest a monthly weighted limit based on monthly average fuel flows.

Response: There may be a misunderstanding on the application of this formula. The formula would be used during the compliance determ ination testing. Thus, for dual fuels one

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

25. Comment: In Table 1146.1

- 1, please change “Compliance Plan” to “Submit Compliance Plan on or Before”, update the “Permi ts to Construct” to “Submit Application for Permit to Construct on or before” and update “Full Compliance” to “Unit in Full Compliance by”.

Response: Staff has incorporated these recommended changes.

26. Comment: The 9 ppm NOx level should not apply to the rmal fluid heaters. The combustion temperature and other operating parameters would not make it possible for these units to comply with the proposed standard.

Response: AQMD staff has examined the ability of these relatively few units to comply with the 9 ppm NOx level. Based on our review, we agree with the commentator and have allowed these thermal fluid heaters to remain at the 30 ppm NOx level.

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

Response: To allow time for the industry to apply the newly developed protocol, the start date for the portable analyzers will be July 1, 2009.

28. Comment: Is a low use boiler as specified in paragraph (c)(5) subject to paragraph (d)(7)? If so, then I don’t believe a f acility should have to perform the semi

- annual tune

- ups if they perform the emission checks as specified in paragraph (d)(7). The rigorous emission checks should be enough to ensure the unit is in compliance with the emission limits.

Response: Low fuel use boilers would be subject to the monitoring requirements specified in paragraph (d)(7). However, the proposal has been changed to require the monitoring to be conducted along with the semi

- annual or annual tune

- up. In addition, the monitoring with the portable analyzer would not occur until after January 1, 2015 or during burner replacement,

whichever occurs later.

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

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

Response: The proposed rule language has been modified to clarify that records should be maintained for at least two years and for five years if the units are to be operated in a Title V facility.PAR 1146.1 Fi nal Staff Report

Appendix A A

- 9 August 2008 30. Comment: According to paragraph (d)(7), is a facility required to install an hour meter?

Response: Only units applying the pound per million Btu option or weighted average emission limit would be required to install an hour meter.

31. Comment: The proposed limit s pecified in Table 1146.1

- 1 for natural gas fired units should be changed, in certain situations, to an alternative limit. For example, a boiler rated at 2.5

mmBtu /hr with a NOx limit of 12 ppm will not exceed 1 lb/day operating at 24 hours per day. Even a unit with a NOx limit of 30 ppm that is limited to a fuel usage that is equivalent to 10 hours per day will not exceed 1 lb/day. The 1 lb/day value is the threshold that triggers Best Available Control Technology (BACT). I don’t believe that these units should have to be replaced to achieve the 9 ppm limit. If the AQMD feels that it’s still necessary then I think that these units should be provided more time to replace the equipment.

Response: AQMD staff appreciates the time an d effort the commenter has spent in deriving this approach to establish NOx emission limits. However, in order to ascertain compliance with this method the owner or operator would need to measure NOx emissions in intervals

less than a one

- day per iod. Only continuous emissions monitoring systems (CEMS) would be capable of providing these emission measurements. For the 2 to 5 mmBtu /hr size range the application of such measurement devices would be costly. On this basis, AQMD staff

d eclines in pursuing this approach to establish NOx emission limits.

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

each unit. Some permitting engineers issue permits with no testing requirement or if a facility submits multiple identical units the permitting engineer may only ask to have one unit

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

tested? After adoption, if the AQMD engineer does not specify a testing condition does the facility still need to test the unit? Are these initial tests required to be submitted to the AQMD ?

Response: According to PAR 1146.1 all existing units will be subject to source testing every 5 years. All s ource tests, including initial source tests, will be required to be stored onsite. For existing sources the first source test would need to be conducted within 5 years of rule adoption. However, independent of PAR 1146.1, the AQMD engineer may r equire a copy of

the source test.

33. Comment: Atmospheric units with non

- sealed combustion would not be able to achieve the proposed 9 ppm NOx limit. At these lower NOx levels there are real safety concerns in that fugitive CO emissions would emanate from t he burner during operation.

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

. Therefore staff has proposed a 12 ppm limit for natural gas fired atmospheric units with non

sealed combustion.PAR 1146.1 Fi nal Staff Report

Appendix A A

- 10 August 2008 The following comment s include those received on or after the Joint PAR 1146 and 1146 .1 Task Force meeting s held on July 10, 2008 and August 14, 20 08.

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

1146 .1 (b)( 3 ) and the definition for PROCESS HEATE R under PAR 1146 .1 (b)( 7 ) refer to "...combustion equipment fired with liquid and/or gaseous and/or solid fossil fuel..."

which may be read to exclude biogas or non

- fossil fuel units. In order to clarify rule applicability to biogas, please consider re vising 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.

35. Comment: Is there going to be a training program for those individuals using portable analyzers to establish NOx or CO compliance at their facility?

Response: Yes

, there will be a training program for individu als using portable analyzers to establish NOx or CO compliance at their facility . Language has been added to PAR 1146 .1 requiring these individual to undergo this training.