Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

FINAL DRAFT STAFF REPORT 

October 16, 2008 

Proposed Amendments to Rule 4306 (Boilers, Steam Generators, and Process 

Heaters – Phase 3) 

Proposed Amendments to Rule 4307 (Boilers, Steam Generators, and Process 

Heaters – 2.0 MMBtu/hr to 5.0 MMBtu/hr)

Proposed New Rule 4320 (Advanced Emission Reduction Options For Boilers, 

Steam Generators, and Process Heaters Greater Than 5.0 MMBtu/hr)

 

Prepared by: Manuel Salinas, Air Quality Engineer 

Reviewed by: Errol Villegas, Planning Manager 

 George Heinen, P.E., Supervising Air Quality Engineer 

 Joven R. Nazareno, Senior Air Quality Engineer 

 Rich Karrs, Senior Air Quality Engineer 

 John Copp, Air Quality Inspector 

 Lucinda Roth, Senior Air Quality Specialist 

 

I. SUMMARY 

A. Reasons for Rule Development and Implementation 

The San Joaquin Valley Air Basin (SJVAB) is a continuous inter-mountain valley 

comprised of eight counties in the southern portion of the San Joaquin Valley of 

California: Fresno, Kings, Madera, Merced, San Joaquin, Stanislaus, Tulare, and the 

Valley portion of Kern. The SJVAB is approximately 250 miles long, averages 80 miles 

wide, and is partially enclosed by the Coast Mountain range on the west, the Tehachapi 

Mountains on the south, and the Sierra Nevada range on the east. These surrounding 

mountains trap pollution. Low wind speeds combined with low-lying inversion layers in 

the winter create a climate conducive to the formation of high particulate matter (PM) 

concentrations. The region’s hot, dry summers are conducive to ozone formation. 

The SJVAB is currently designated as nonattainment for the national ambient air quality 

standard (NAAQS) for particulate matter 2.5 microns in diameter or less (PM2.5) and 

serious nonattainment for the eight-hour ozone NAAQS. Prior to the United States 

Environmental Protection Agency’s (EPA’s) implementation of the eight-hour ozone 

standard, the SJVAB was also classified as an extreme nonattainment area for the onehour ozone NAAQS. Although EPA revoked the one-hour ozone NAAQS, the San 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

2

Joaquin Valley Air Pollution Control District (District) is still required to meet certain 

requirements mandated by the federal Clean Air Act related to the extreme designation. 

In addition to being classified as nonattainment of federal air standards, SJVAB is 

classified as severe nonattainment for the California ozone air quality standard and 

nonattainment for the California air quality standard for particulate matter ten microns in 

diameter or smaller (PM10). 

Since amending Rule 4306 and 4307 are control measures in the District’s 2007 Ozone 

Plan, they are subject to Code of Federal Regulations (CFR), Clean Air Act (CAA), and 

California Health and Safety Code (CH&SC) requirements. This rulemaking project is 

intended to satisfy the attainment goals of the District’s 2007 Ozone Plan. The 

proposed amendments to Rule 4306 and Rule 4307 will seek to obtain as much 

reduction of oxides of nitrogen (NOx) from boilers, steam generators, and process 

heaters as expeditiously practicable and technologically and economically feasible, as 

determined by the District’s Governing Board. Furthermore, the rules are intended to 

satisfy the requirements identified in Table 1 below. 

Table 1: Ozone Plan Commitments 

Subject Reference Requirement 

Timeline CAA Section 

172(c)(1) 

Ozone attainment plans shall implement 

control measures as expeditiously as 

practicable, and provide for attainment. 

RACT 

CAA Sections 

182(b)(2) and 

182(f) 

Ozone attainment plans shall assure that 

reasonable available control technology 

(RACT) for NOx and volatile organic 

compounds (VOC) is in use at sources and 

on source categories at or above the RACT 

threshold. 

BARCT CH&SC 

40919(a)(3) 

Ozone attainment plans should provide for 

best available retrofit technology (BARCT) 

for existing permitted sources. 

All Feasible Controls CH&SC 

40914(a)(2) 

Ozone attainment plans should include "all 

feasible control measures." 

Deadline District 2007 

Ozone Plan Rule adoption by the 3rd quarter of 2008. 

Reductions District 2007 

Ozone Plan 

The plan calls for a total of 1.1 tons per day 

of NOx reductions from the two rules. 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

3

Under EPA's "New Source Review" (NSR) program, if a company is planning to build a 

new plant or modify an existing plant such that air pollution emissions will increase by a 

certain amount, then the company must obtain an NSR permit. The NSR permit is a 

construction permit which requires the company to minimize air pollution emissions by 

changing the process to prevent air pollution and/or installing air pollution control 

equipment. The terms "RACT," "BACT," and "LAER" are acronyms for different 

program requirements under the NSR program. EPA defines RACT as “the lowest 

emission limitation that a particular source is capable of meeting by the application of 

control technology that is reasonably available considering technological and economic 

feasibility.” RACT is required on existing sources in non-attainment areas. Best 

Available Control Technology (BACT), is required on major new or modified sources in 

attainment areas. Lowest Achievable Emission Rate (LAER) is required on major new 

or modified sources in non-attainment areas. BACT and LAER (and sometimes RACT) 

are determined on a case-by-case basis, usually by State or local permitting agencies. 

For this rule project, District staff will focus on RACT limits, as defined by EPA’s NSR 

rule, and BARCT limits as defined by the CH&SC. 

B. Description of the Project 

1. Rule 4306 (Boilers, Steam Generators, and Process Heaters – Phase 3) and Rule 

4320 (Advanced Emission Reduction Options For Boilers, Steam Generators, and 

Process Heaters Greater Than 5.0 MMBtu/hr) 

The District’s Governing Board adopted Rule 4306 on September 18, 2003. The 

current project proposes to address EPA cited deficiencies in Rule 4305 (Boilers, Steam 

Generators, and Process Heaters – Phase 2) and to reduce emissions of NOx pursuant 

to the District’s ozone and particulate matter attainment strategies. The rule applies to 

any gaseous fuel or liquid fuel fired boilers, steam generators, and process heaters with 

a rated heat input greater than 5 million Btu/hour. Facilities with units subject to this 

control measure represent a wide range of industries, including but not limited to 

electrical utilities, cogeneration, oil and gas production, petroleum refining, 

manufacturing and industrial, food and agricultural processing, and service and 

commercial facilities. 

The draft staff report dated October 30, 2007 stated District staff would amend Rule 

4306 to implement an emission control measure (S-COM-1) in the District’s 2007 EightHour Ozone Plan. The control measure indicates that additional NOx emission 

reductions could be achieved by lowering the current NOx limit of 9 ppmv to 6 ppmv for 

units greater than 20 MMBtu/hr. An estimated 40 percent reduction from the current 

emissions level could be achieved. After reviewing the first workshop comments District 

staff have determined that stakeholder concerns and the goals of the control measure 

would best be achieved by developing new Rule 4320 in this project. Rule 4306 will be 

modified to address the EPA concerns discussed in Section II C of this report. 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

4

2. Rule 4307 (Boilers, Steam Generators, and Process Heaters – 2.0 MMBtu/hr to 5.0 

MMBtu/hr) 

The District’s Governing Board adopted Rule 4307 on December 15, 2005. The current 

project proposes to reduce emissions of nitrogen oxides (NOx) and carbon monoxide 

(CO) pursuant to the District’s ozone and particulate matter attainment (PM10) 

strategies. Facilities with units subject to this control measure represented a wide range 

of industries, including but not limited, to medical facilities, educational institutions, office 

buildings, prisons, military facilities, hotels, and industrial facilities. 

In order to alleviate significant adverse economic impacts on public and private schools 

(Kindergarten through Grade 12) in the San Joaquin Valley Rule 4307 provided an 

exemption for units located at schools. In the Final Draft Staff Report, December 15, 

2005, staff stated that as a separate control strategy in the future, the District may seek 

available funding to assist schools in replacing or retrofitting existing units and achieve 

additional emissions reduction from this source category. As stated above, Rule 4307 

would be amended in this current project by removing the exemption to gain the 

emission reductions associated with units that are used at schools. There are no 

current programs that would provide funding for the replacement of these units. The 

District has identified the following possible sources of future funding to replace/retrofit 

school boilers, steam generators, and process heaters: 

• Community Clean Air Fund, funded by donations. If funding becomes available 

the District will assist in the coordination of distributing funds for the replacement 

of school units. 

• Fees generated by District Rule 9510 (Indirect Source Review Program). The 

purpose of the District’s ISR Program is to reduce emissions from new 

development projects. The District anticipates that the ISR Program will 

generate funds for future emission reduction projects including the replacement 

of school boilers, steam generators, and process heaters. 

3. Particulate matter control provisions 

As stated previously the SJVAB is currently designated as nonattainment for the 

NAAQS for particulate matter with aerodynamic diameter of 2.5 micrometers or less 

(PM2.5). As such, the District submitted a PM2.5 Plan to EPA in 2008 with 

commitments to reduce primary and secondary sources of PM2.5. In response to those 

new PM2.5 control measure commitments, District staff have included SO2 and PM 

control requirements in this rule project. While SO2 is not a precursor to ozone 

formation in the SJVAB, SO2 is strongly implicated in atmospheric particle formation. 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

5

C. Rule Development Process 

As part of the rule development process, District staff conducted public workshops to 

present and discuss proposed amendments to Rule 4306, Rule 4307 and proposed new 

Rule 4320. District staff conducted public workshops in October 2007 and in March and 

July 2008. The first two workshops were conducted via the District’s video teleconference 

system. The system was offline for upgrades in July 2008 so those workshops were 

conducted in person in Fresno, Modesto and Bakersfield. In addition to the workshops, 

numerous meetings were held with stakeholders to discuss their individual issues and 

suggestions. 

At the workshops, District staff presented the objectives of the proposed rulemaking 

project and provided the draft rules. District staff solicited information from affected source 

operators, consultants, vendors and manufacturers of control technologies, and trade 

associations on the technological feasibility and compliance cost information that would be 

useful in developing new Rule 4320 and amendments to Rule 4306 and Rule 4307. The 

comments received from the public, affected sources, interested parties, California Air 

Resources Board (ARB), and EPA, during the public workshop process were incorporated 

into the draft rules as appropriate. 

Pursuant to state law, the District is required to perform a socioeconomic impact 

analysis prior to adoption, amendment, or repeal of a rule that has significant air quality 

benefits or that will strengthen emission limitations. As part of the District 

socioeconomic analysis process, District staff met with volunteers from affected 

stakeholders and interested parties at the Socioeconomic Focus Group. The results of 

the socioeconomic analysis are included in this report. 

The proposed rule and rule amendments, final draft staff report with appendices, and 

final draft socioeconomic analysis report will be published and mailed to affected 

sources and interested parties prior to a public hearing to consider the adoption of 

proposed new Rule 4320 and proposed rule amendments to Rule 4306 and Rule 4307 

by the District Governing Board. The public hearing is scheduled on September 18, 

2008. 

II. CURRENT AND PROPOSED REGULATIONS 

A. Existing Rule 4306 

The purpose of Rule 4306 is to limit NOx and CO emissions from boilers, steam 

generators, and process heaters. The rule applies to any gaseous fuel or liquid fuel 

fired boiler, steam generator, and process heater with a rated heat input greater than 

5.0 million Btu/hr. 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

6

The current rule does not apply to units that are addressed by other District rules. 

These units include solid fuel fired units, dryers, glass melting furnaces, kilns and 

smelters, unfired or fired waste heat recovery boilers, and any unit in which the total 

rated heat input of each burner is less than or equal to 5 million Btu per hour as 

specified in the operating permit, and in which each burner’s products of combustion 

does not come in contact with the products of combustion of any other burner. The rule 

also contains certain exemptions such as burning of any fuel other than natural gas 

during natural gas curtailment for no more than 168 hours. Units subject to the rule 

must comply with the NOx and CO limits listed in the following table. 

Table 2: Rule 4306 NOx and CO Limits 

Operated on Gaseous Fuel Operated on Liquid Fuel 

NOx Limit 

Category 

Standard Option Enhanced Option 

CO 

Limit 

(ppmv) 

NOx Limit CO Limit 

(ppmv) 

A. Units with a rated heat input 

equal to or less than 20.0 

MMBtu/hour, except for 

Categories C, D, E, F, G, H, 

and I units 

15 ppmv or 

0.018 lb/MMBtu 

9 ppmv or 

0.011 lb/MMBtu 

400 40 ppmv or 

0.052 

lb/MMBtu 

400 

B. Units with a rated heat input 

greater than 20.0 

MMBtu/hour, except for 

Categories C, D, E, F, G, H, 

and I units 

9 ppmv or 

0.011 lb/MMBtu 

6 ppmv or 

0.007 lb/MMBtu 

400 40 ppmv or 

0.052 

lb/MMBtu 

400 

C. Oilfield Steam Generators 15 ppmv or 

0.018 lb/MMBtu No option 400 

40 ppmv or 

0.052 

lb/MMBtu 

400 

D. Refinery units with a rated 

heat input greater than 5 

MMBtu/hr up to 65 

MMBtu/hr 

30 ppmv or 0.036 

lb/MMBtu 

No option 400 40 ppmv or 

0.052 

lb/MMBtu 

400 

E. Refinery units with a rated 

heat input greater than 65 

MMBtu/hr up to 110 

MMBtu/hr 

25 ppmv or 

0.031 lb/MMBtu 

No option 400 40 ppmv or 

0.052 

lb/MMBtu 

400 

F. Refinery units with a rated 

heat input greater than 110 

MMBtu/hr 

5 ppmv or 

0.0062 lb/MMBtu No option 400 

40 ppmv or 

0.052 

lb/MMBtu 

400 

G. Load-following units 15 ppmv or 0.018 

lb/MMBtu 

9 ppmv or 

0.011 lb/MMBtu 400 

40 ppmv or 

0.052 

lb/MMBtu 

400 

H. Units limited by a Permit to 

Operate to an annual heat 

input of 9 billion Btu/year to 

30 billion Btu/year 

30 ppmv or 0.036 

lb/MMBtu No option 400 

40 ppmv or 

0.052 

lb/MMBtu 

400 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

7

Table 2: Rule 4306 NOx and CO Limits (continued) 

Category Operated on Gaseous Fuel Operated on Liquid Fuel 

NOx Limit CO 

Limit 

(ppmv) 

NOx Limit CO Limit 

(ppmv) 

I. Units in which the rated heat 

input of each burner is less 

than or equal to 5 MMBtu/hr 

but the total rated heat input 

of all the burners in a unit is 

greater than 5 MMBtu/hr, as 

specified in the Permit to 

Operate, and in which the 

products of combustion do 

not come in contact with the 

products of combustion of 

any other burner. 

30 ppmv or 0.036 

lb/MMBtu 

No option 400 40 ppmv or 

0.052 

lb/MMBtu 

400 

Other provisions contained in the rule include periodic source testing, monitoring, and 

recordkeeping. Additionally, the rule also allows operators to comply with the emission 

limits of the rule through an Alternative Emission Control by achieving an aggregated 

emission level no higher than the aggregated emission level that would have resulted if 

each unit in operation were individually in compliance with the specified emission limits. 

B. Summary of Proposed Amendments to Rule 4306 

Section 5.0 – Requirements 

Rule 4306 would be modified to address an EPA concern regarding the exemption from 

BACT and offset exemption to include provisions of start-up or shutdown in the Permit 

to Operate (PTO). The modified provision would include a statement that modification 

of PTO may qualify for exemption from BACT and offset provided it meets the criteria 

specified in Rule 2201 (New and Modified Stationary Source Review Rule), Section 4.4 

(BACT Exemption) and Section 4.6 (Offset Exemption). US EPA commented it is not 

appropriate to include such an exemption from new source review (NSR) requirements 

and it would not be approvable for inclusion in the State Implementation Plan (SIP). US 

EPA also stated “any regulatory language that exempts sources from NSR is subject to 

review as a revision to the District's NSR program. Adding a specific NSR exemption or 

new terms to provide an exemption already provided for in Rule 2201 to any rule not 

previously evaluated by EPA would likely open up all of the existing NSR rules to a new 

review to ensure compliance with the requirements of 40 CFR 51.165(a)(1).” 

C. Existing Rule 4307 

The purpose of Rule 4307 is to limit NOx and CO emissions from boilers, steam 

generators, and process heaters. The rule applies to any gaseous fuel or liquid fuel 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

8

fired boiler, steam generator, and process heater with a rated heat input of 2.0 million 

Btu/hr up to and including 5.0 million Btu/hr. 

The current rule does not apply to solid fuel fired units, dryers, glass melting furnaces, 

kilns, humidifiers and smelters where the products of combustion come into direct 

contact with the material to be heated, unfired or fired waste heat recovery boilers that 

are used to recover or augment heat from the exhaust of combustion turbines or internal 

combustion engines, and units used at a school. 

Units subject to Rule 4307 are to be certified that they comply with the NOx and CO 

emission limits specified in the rule. For gaseous fuel-fired units the NOx limit is 30 

ppmv or 0.036 lb/MMBtu and 400 ppmv for CO. For liquid fuel-fired units the NOx limit 

is 40 ppmv or 0.052 lb/MMBtu and 400 ppmv for CO. Natural draft units operated in an 

oilfield or refinery, glycol reboilers, or low-use units, which are limited by Permit to 

Operate or Permit-Exempt Equipment Registration to operate at no more than 5.0 billion 

Btu per calendar year heat input, are not required to meet a specific emission limits. 

Operators of such units must either tune the unit in accordance with the rule procedure; 

operate the unit in a manner that maintains exhaust oxygen concentrations at less than 

or equal to 3.0 percent by volume on a dry basis; or certify the unit in accordance with 

the rule to comply with the applicable emission requirements. Rule 4307 also contains 

provisions for equipment certification requirements, monitoring and testing, compliance 

determination, and recordkeeping requirements. 

D. Summary of Proposed Amendments To Rule 4307 

Section 2.0 (Applicability): The purpose of the rule would be modified so that in 

addition to NOx and CO emissions requirements, the rule would also limit emissions of 

oxides of sulfur (SO2), and particulate matter 10 microns or less (PM10) from boilers, 

steam generators, and process heaters. 

Section 3.0 (Definition): A definition of “California Public Utilities Commission (PUC) 

quality natural gas” would be added to the rule. 

Section 4.0 – Exemptions 

In Section 4.5, the exemption language pertaining to “units used at a school” would be 

modified to make such school units subject to the emission limits of the rule. The current 

exemption will be in place until June 30, 2015. On and after July 1, 2015, school units are 

to comply with the NOx and CO limits of Section 5.1. Due to school funding restrictions, 

an earlier compliance date is not considered to be possible for all school districts. 

Section 5.0 – Requirements 

Section 5.1 would be revised to add NOx and CO limits for new and replacement units. 

Table 2 of Rule 4307 categorizes these units and lists the applicable dates. District staff 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

9

believes burner technology that can meet 9 ppmv NOx is emerging. Since it is not 

commercially available widespread the new limit would be met through attrition. This 

provides operators the opportunity to obtain a useful service life from their equipment. 

Burner manufacturers have a lower, but longer-term demand for the 9 ppmv technology 

and are better able to respond compared to dealing with a sudden surge and then little 

or no further orders for a while. 

Further, after receiving comments on technical limitations for atmospheric units, Table 2 

of Rule 4307 has been modified. As defined in the rule atmospheric units are gaseous 

fuel-fired units with a non-sealed combustion chamber in which the combustion air and 

flue gases are drawn through the unit without the use of a fan. This design causes 

variations that cause difficulty in meeting a lower NOx limit. New and replacement units 

that are atmospheric type would be required to meet 12 ppmv instead of 9 ppmv. This 

provision is similar to that proposed by the South Coast Air Quality Management District 

for this category of units. 

Section 5.3 would contain provisions to limit emissions of PM10 and SO2. Units would 

be required to comply with one of the following three options: 

• Fire exclusively on PUC-quality natural gas, commercial propane, butane, or 

liquefied petroleum gas, or a combination of these gases; or 

• Limit fuel sulfur content to no more than five (5) grains of total sulfur per one 

hundred (100) standard cubic feet; or 

• Install and properly operate an emission control system that reduces SO2 and 

PM10 emissions by at least 95% by weight or limit exhaust SO2 to less than or 

equal to 9 ppmv corrected to 3.0 %O2. 

Section 5.5.3 would specify the requirements to monitor of SO2 and PM10 based on the 

system parameters and frequency option chosen by the operator and submitted to the 

APCO for approval. 

Section 5.2 will change the “Low-use Units” threshold from no more than 5.0 billion Btu per 

calendar year heat input to less than or equal to 1.8 billion Btu per calendar year heat 

input. This provision is similar to other air districts. Also, on and after July 1, 2015, each 

atmospheric unit in an oilfield or refinery, each glycol reboiler, and each unit with a heat 

input greater than 1.8 billion Btu per calendar year shall comply with the emission 

requirements of Section 5.1. This change would make Rule 4307 consistent with other 

California air district’s rules and considered to be an All Feasible Control Measure 

pursuant to the state Health and Safety Code. 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

10

New Section 5.3 would establish the requirements to limit emissions of PM10 and SO2. 

Units would be fired only exclusively on PUC-quality natural gas, commercial propane, 

butane, or liquefied petroleum gas, or combination of such gases. Liquid fuel use would 

be allowed only during periods of PUC natural gas curtailment. 

Section 6.0 – Administrative Requirements 

Section 6.1 Recordkeeping would be modified to include required records for units firing on 

liquid fuel during PUC-quality natural gas curtailment and for start-up or shutdown. 

Section 6.2 Test Methods would include test methods for determination of total sulfur as 

hydrogen sulfide (H2S), oxides of sulfur, and PM10. Also included are the calculation 

methods for determining the control efficiency of SOx and PM10 emission control system. 

The word “exemption” would be changed to “certification” in the last sentence of Section 

6.3.3. This is a non-significant change to address a typographical error during the original 

adoption of Rule 4307. 

Section 7.0 – Compliance Schedule 

Group 3 would be added, to Table 2 – Compliance Schedule, to specify the full 

compliance deadline for units located at a school, natural draft units operated in an oilfield 

or refinery, glycol reboilers, and units with a heat input greater than 1.8 billion Btu per 

calendar year. These units are required to be in full compliance by July 1, 2015. 

E. Summary of Proposed New Rule 4320 

Operators have made great strides in achieving emission reductions in this source 

category. Large capital and operating expenditures were dedicated in meeting the RACT 

limits of Rule 4306. District staff understand that Rule 4320 would go above and beyond 

federal standards of reasonably available control technology to gain further emission 

reductions and have included special provisions to mitigate impacts in this rule. 

The first four sections of Rule 4320, Section 1.0 Purpose, Section 2.0 Applicability, Section 

3.0 Definitions, and Section 4.0 Exemptions are all similar to Rule 4306. Rule 4320 would 

contain the following major provisions.

Section 5.0 – Requirements 

Section 5.1 would provide three main Advanced Emission Reduction Options for rule 

compliance: 

1. Meet the specific NOx emission and the particulate matter control requirements; or 

 

2. Pay an annual emissions fee to the District and meet the particulate matter control 

requirements; or 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

11

3. Limit fuel input to comply with the low-use unit provision specified in Section 5.5. 

The NOx limits in Table 1 of the rule contain major categories with associated NOx levels 

and deadlines. These categories include 

A) Units with a total rated heat input greater than 5.0 MMBtu/hr to 20.0 MMBtu/hr, 

B) Units with a total rated heat input greater than 20.0 MMBtu/hr, 

C) Oilfield steam generators of all ratings and fuel types, 

D) Refinery units of all ratings and fuel types, 

E) Low-use units limited by a Permit to Operate to an annual heat input greater than 

1.8 billion Btu/year but less than or equal to 30 billion Btu/year, 

F) Units at a wastewater treatment facility using less than 50% PUC quality fuel, and 

G) Small specialty units operated by a small producer. 

These categories were created, after significant discussions with stakeholders, to 

recognize the operational and technical differences between the categories and to more 

specifically address those differences. Category E is proposed to coordinate low-use 

levels between Rule 4320 and 4307, which has a proposed low-use level of less than or 

equal to 1.8 billion Btu/yr. 

For four categories in Rule 4320 Table 1 there is also an option to comply with an 

Enhanced Compliance Schedule with lower emissions levels. This provision addresses 

the situation where some units can meet acceptably low levels in a quicker time under the 

Standard Schedule while other units may need a longer time but can reach lower limits 

using enhanced emission controls. For example, an operator with a Category A unit can 

show full compliance with the Standard NOx limit of 9 ppmv by January 1, 2012 or with an 

Enhanced NOx level of 6 ppmv by January 1, 2014. 

Staged Enhanced Schedules were also developed for units that could reach intermediate 

levels in the near future and then later achieve lower limits with more advanced 

technology. For example, oilfield generators may comply with an Initial NOx limit of 9 

ppmv by July 1, 2012 and then the final limit of 5 ppmv by January 1, 2014. This allows 

operators to minimize their emissions by maximizing existing equipment and controls and 

then postponing larger capital investments for SCR or more advanced burners into the 

future. The Staged Enhanced compliance schedule mitigates rule impacts and allows 

operators to take advantage of emerging technologies for more cost-effective controls and 

lower final emissions. 

 

Section 5.3 – Annual Emissions Fee 

The low level of emissions proposed in Table 1 of Rule 4320 may not be able to be 

achievable by all units due to space limitations and economic considerations. Most of the 

affected units have typically had several levels of controls and can only reach the new 

limits with a Selective Catalytic Reduction (SCR). To offset the higher costs associated 

with the proposed controls, the District developed the concept of an annual emissions fee. 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

12

Operators have the option of paying an annual emissions fee based on the actual 

emissions of the unit during the previous calendar year. These fees would be used by the 

District to purchase emission reduction at a better cost effectiveness rate than the 

proposed controls. The first payment would be due in 2010 for the 2009 emissions. 

Payments would continue annually until the unit demonstrated compliance with 

appropriate limits or was permanently removed from use in the District. 

To insure federal approvability, the emissions fee would be based on the total emissions 

from the units that do not comply with the applicable NOx limits, and not the difference 

between the actual and rule limits. The emissions would be calculated using the NOx 

emission limit in the Permit to Operate, in lb/MMBtu, and the actual annual fuel usage, in 

MMBtu, for the past year. The total annual fee would be calculated by multiplying the total 

emissions by a fee rate plus an administrative fee. 

The fee rate would be based on the cost of NOx reductions, in dollars per ton, as 

established pursuant to Sections 7.2 and 7.6 of District Rule 9510 (Indirect Source Review 

(ISR)), as adopted on December 15, 2005. The emissions fee is capped to not exceed the 

cost effectiveness threshold for the Carl Moyer Cost Effectiveness as established by the 

applicable state law. Currently, the ISR is able to produce the lowest cost reductions, so it 

is reasonable to use that rate for the emissions fee. As more of the lowest cost reductions 

are funded, the situation may change and the Moyer threshold could become the lower 

value. If that occurs, then the Moyer rate will be used for the emission fee calculations. 

Currently the ISR fee is $9,300/ton and the Moyer threshold is $16,000/ton. 

Provisions were added for units designated as complying with a Staged Enhanced 

Schedule to switch to an annual fee prior to the Final Compliance date. This recognizes 

the possibility that the Final Limit may not be economically feasible for all units and 

provides an additional compliance option for these units. This provision is conditioned on 

the unit meeting the Initial Emission limit and paying both past and future emissions fees. 

The past fees will be based on the Fee Rate in place on the day the calculation is 

performed so it is likely to be higher than the fee for a unit which had been paying starting 

in 2010. This reflects the fact that the District would have to buy the emission reductions 

at the future rate, not the lower rates that it would have enjoyed in the past. The future 

annual payments, after the past fees payment, would be the same as for any other unit 

that was initially complying with the payment provision. Given the economic feasibility of 

meeting the Staged Enhanced limits, the modified fee option is considered a reasonable 

solution for compliance. 

Section 5.4 – Particulate Matter Control Requirements 

Section 5.4 would contain provisions to limit emissions of particulate matter (PM), as 

required by the District’s 2008 PM2.5 Plan. Since PM emissions from these sources are 

primarily from the precursors, specifically NOx and SOx, rather than directly emitted PM, 

the PM controls will focus on controlling the precursors. To that end, units would be 

required to comply with one of the following three options: 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

13

1. Fire exclusively on PUC-quality natural gas, commercial propane, butane, or 

liquefied petroleum gas, or a combination of these gases; or 

2. Limit fuel sulfur content to no more than five (5) grains of total sulfur per one 

hundred (100) standard cubic feet; or 

3. Install and properly operate an emission control system that reduces SO2

emissions by at least 95% by weight; or limit exhaust SO2 to less than or equal to 9 

ppmv corrected to 3.0 % O2. 

 

The second fuel sulfur limit would allow a fuel with a similar sulfur content as PUCquality natural gas to be used. This recognizes that initially high sulfur fuels may be 

scrubbed during processing and result in equivalent PM2.5 emissions as PUC quality 

natural gas. 

The third fuel sulfur limit is based on existing exhaust control efficiencies. Because it 

may not be possible to control extremely dilute concentrations of SOx, staff have also 

included an optional limit of 9 ppmv. This is equivalent to emissions which would be 

generated by a unit firing on PUC-quality natural gas. 

Liquid fuel would only be allowed during PUC quality natural gas curtailment and 

provided that it contains no more than 15 ppm of sulfur. 

The majority of units in this category are expected to already comply under first option 

since they burn PUC-Quality Natural Gas. Units at refineries are primarily expected to 

be in compliance with the second option due to current controls in place on federal 

operating permits. Some of the largest refiner units are already in compliance with the 

NOx limit due to changes made for Rule 4306, but needed additional time to add the 

SOx controls so a special schedule was included in Rule 4320. To simplify testing and 

operational issues, all other units will demonstrate compliance with the SOx provisions 

at the same time as they comply with the NOx limits. 

 

Section 5.5 – Low-use Unit 

Section 5.5 would contain provisions for low use units limited to less than 1.8 billion Btu 

per calendar year heat input pursuant to a Permit to Operate provided the unit is installed 

prior to rule adoption date. Such low-use units have a relatively high cost-effectiveness 

level since emissions are limited by fuel use restrictions and meeting the limit may mean 

replacing the entire unit. The 1.8 billion Btu/year heat input limit places these units in the 

same category as those in Rule 4307. New units, however, would be expected to meet 

the applicable limits at the time of installation since the cost for the compliant new unit is 

not expected to be significantly different than the cost for a unit with higher emissions. 

Units currently limited to between 1.8 and 30 billion Btu/year will have an extended 

compliance period to mitigate the impact of replacing or retrofitting these limited-use units. 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

14

Many of the units in this category are vertical fluid heaters, which may not have retrofit 

burners available at this time, but for which such burners are being developed. If the unit 

is replaced before that date, the new unit must comply with the applicable limits since the 

cost of the new units would be considered a replacement cost and not a compliance cost, 

thus improving cost-effectiveness calculations. For the purposes of this rule, a unit is 

defined as the boiler, process heater or steam generator, and not the individual burner(s). 

Replacement of an individual burner does not trigger the applicable emission limit. A 

Compliance Deadline has been included, however, to ensure these units don’t continue 

operations indefinitely. 

Section 5.6 – Start-up and Shutdown Provision 

Rule 4320 would contain startup and shutdown provisions similar to those in Rule 4306. 

The rule also provides that Permit to Operate (PTO) modifications solely to include start-up 

or shutdown conditions or replacement units installed for the sole purpose of complying 

with the requirements of this rule may be exempt from Best Available Control Technology 

(BACT) and emission offset requirements if the PTO modifications meet the requirements 

of Rule 2201 (New or Modified Stationary Source Review Rule) Section 4.2 (BACT 

Exemptions) and Rule 2201 Section 4.6 (Offset Exemptions). This language has been 

previously approved by EPA and is similar to language in Rule 4703 (Stationary Gas 

Turbines) and Rule 4307 (Boilers, Steam Generators, and Process Heaters – 2.0 

MMBtu/hr to 5.0 MMBtu/hr). 

Section 5.7 – Monitoring Provisions 

Section 5.7 Monitoring Provisions are similar to Rule 4306 but add monitoring of SOx 

emissions. Frequency and test methods for SOx monitoring have also been added, 

depending on the compliance option chosen. Monitoring and testing for fuel SOx was 

based on annual fuel analysis reports, unless otherwise required by permit condition. For 

the majority of units, the fuel content is fixed. For high-sulfur, variable, high-flow 

operations such as oil refineries, the sulfur content may be analyzed continuously as part 

of the operating permits. In setting the monitoring, staff strove to minimize unnecessary 

paperwork while not overlooking potentially significant SOx sources. 

Section 6.0 – Administrative Requirements 

Recordkeeping includes a list of specific records that are to be maintained for five calendar 

years and made available to the APCO upon request and include required records for 

units firing on liquid fuel during PUC-quality natural gas curtailment. These records are 

required to demonstrate compliance with the rule limits or to justify exemptions for low-use 

units. 

Test Methods that are used to verifying rule compliance are listed including test methods 

specific to oxides of sulfur and SOx emission control system efficiency. 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

15

Section 7.0 – Compliance Schedule 

The deadline to submit an Emission Control Plan is by January 1, 2010, the deadline for 

an Authority to Construct and the full compliance deadline varies in accordance with Table 

1 NOx Limits or Section 5.3 Annual Emissions Fee. In setting the Compliance Deadlines, 

staff considered the level of effort needed for compliance, stakeholder recommendations, 

and emission reduction commitments in the attainment plans. When necessary to 

generate additional reductions or mitigate impacts, Compliance Deadlines were extended. 

The use of the emissions fee may also allow a slightly extended compliance schedule for 

some units while still providing the District funding to generate emission reductions in the 

interim. 

III. CURRENT EMISSIONS AND EMISSIONS REDUCTION 

Base on the calculations detailed in Appendix B, the potential emissions reductions for 

Rule 4320 and Rule 4307 total 4.5 tons/day of NOx and 3.6 tons/day of SOx. Please see 

Appendix B of this draft staff report for further details. 

IV. EMISSION CONTROL TECHNOLOGIES 

The two primary methods of controlling NOx emissions from boilers, steam generators, 

and process heaters are either to change the combustion parameters (i.e., combustion 

modification) to reduce NOx formation or to treat the NOx formed before it is emitted into 

the atmosphere (i.e., exhaust gas treatment). 

Combustion Modification

Combustion modification systems are designed to reduce thermal NOx formation by 

changing the flame characteristics to reduce peak flame temperature. Combustion 

controls include low excess air operation, staged combustion, overfire air ports, biased 

firing, and placing selected burners out-of-service. 

Combustion modification is also achieved by different burner designs such as Low NOx 

and Ultra Low NOx burners. Some of the design principles used in Ultra low NOx and Low 

NOx burner include staged air burners, staged fuel burners, pre-mix burners, internal 

recirculation, and radiant burners. 

A combustion control system may be used by itself or in combination with Flue Gas 

Recirculation (FGR). FGR recycles a portion of the exhaust stream back into the burner 

windbox, mixing low oxygen air with combustion air prior to entering the combustion 

chamber. This technique reduces thermal NOx formation by reducing the peak 

temperature and by reducing oxygen in the combustion zone. 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

16

District source test results show units from 6 MMBtu/hr up to 182 MMBtu/hr with Ultra Low 

NOx burners and with or without FGR meeting less than 5 ppmv NOx. District source test 

results also show units from 6 MMBtu/hr up to 220 MMBtu/hr with Ultra Low NOx burners 

and with or without FGR meeting less than 9 ppmv NOx. 

Exhaust Gas Treatment

Exhaust Gas treatment (EGT) is another way to reduce NOx. NOx is reduced to 

molecular nitrogen by adding flue gas treatment systems located after the boiler firebox. 

EGT includes Selective Catalytic Reduction (SCR) and Selective Noncatalytic Reduction 

(SNCR). EGT operate at a certain temperature range to effectively reduce NOx in the 

exhaust gas by injecting either urea or ammonia into the post-combustion zone of the 

boiler. 

The main issues associated with the SCR system is ammonia slip, or unreacted ammonia. 

Operating problems and ammonia emissions are generally prevented under specific 

conditions and operating limits as suggested by SCR manufacturers. SCR systems use 

ammonia stored in aqueous form, anhydrous form, generated on demand, or released 

from urea. 

District source test results show units from 31 MMBtu/hr up to 142 MMBtu/hr with SCR 

systems are capable of emitting less than 3 ppmv NOx. Such results are not necessarily 

typical, but demonstrate the feasibility of the proposed limits. 

Particulate Matter Post-Combustion Controls

Post-combustion control devices remove pollutants from the flue gases downstream of the 

unit. These controls are effective at removing PM, SO2, and NOx. PM post-combustion 

controls include fabric filters, electrostatic precipitators (ESPs), and wet scrubbers. SO2 

post-combustion controls include flue gas desulfurization and dry sorbent injection. 

ESPs use an electrical charge to separate the particles in the flue gas. The ESP particles 

in the flue gas are then attracted to an oppositely charged plate or tube and collected to a 

hopper by vibrating the collection surface. ESPs have been reported to achieve 99 

percent PM2.5 removal efficiency. ESPs are not common to units affected by Rule 4306. 

Fabric filters known as a baghouse trap particulates in the flue gas before they exit the 

stack. These cylindrical bags or flat envelope systems include a dust collection hopper 

and a cleaning mechanism for removal of the particulates. Fabric filters are not 

recommended for units that use oil exclusively. A baghouse downstream of an ESP 

provides high rates of PM2.5 removal. Baghouses can capture up to 99.9 percent of total 

particulates. Baghouses are not common to units affected by Rule 4306. 

Flue gas desulfurization typically uses lime or limestone as a sorbent to remove SO2 from 

the exhaust gas. The two most common flue gas desulfurization scrubbers are wet and 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

17

spray dry. Wet scrubbers have a reduction efficiency of greater than 90 percent and 

newer dry scrubbers are capable of achieving a reduction efficiency of near 90 percent. 

 

Currently there are a few crude oil-fired or field gas-fired steam generators operated in 

crude oil production facilities in the District that are required by permit condition to 

operate SO2 scrubbers or desulfurization equipment. Other permitted units firing on 

natural gas or back-up distillate oil are not required to operate PM2.5 or SO2 control 

devices. Control devices such as baghouses, electrostatic precipitators, and scrubbers 

are available, but they have not yet been demonstrated or achieved-in-practice for 

gaseous-fired or liquid-fired units. 

Units firing on natural gas, propane, liquefied petroleum gas, or low sulfur diesel tend to 

emit very low levels of PM2.5 and SO2. AP-42 indicates that the uncontrolled total PM 

(condensable and filterable) is 0.007 pound per million Btu and uncontrolled SO2 is 

0.0006 pound per million Btu for boilers firing on natural gas. 

A large majority of the units that are already firing on PUC quality natural gas, propane, 

butane, or LPG would be in compliance with the proposed SO2 control requirements. 

Units firing on refinery gas or thermally enhanced oil recovery gas along with a mixture of 

such gases and PUC quality natural gas could comply by limiting the fuel gas sulfur 

content to the level being proposed in the draft rule. Preliminary information obtained from 

some stakeholders indicate that the fuel gas sulfur content being proposed is currently 

being achieved without installing additional sulfur control systems. 

V. COST EFFECTIVENESS ANALYSIS 

Cost effectiveness will depend on the current level of controls, unit size, fuel usage and 

final emission levels. Some units have previously installed state-of-the-art controls and 

are in compliance with the most stringent emission limits and will therefore have no 

additional compliance costs. For larger, full time units, SCR costs may be as low as 

$20,000 per ton. SCR costs for smaller units, with lower total emissions, can be as high 

as $200,000 per ton. To mitigate these costs, the District is proposing an option for an 

annual emissions fee, which was discussed above. Also, compliance dates for some of 

the lower emission limits have been extended to allow additional time for technology 

development of new burners which are typically less expensive than SCR systems. 

 

The majority of these units are fired on PUC-quality natural gas or are able to meet the 

fuel sulfur limits based on existing controls so they will have no compliance costs. The 

remaining units which will have to add sulfur controls at costs ranging from roughly 

$20,000 to $120,000 per ton with some operator estimates exceeding $200,000 per ton. 

The cost effectiveness analysis is located in Appendix C of this draft staff report. 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

Final Draft Staff Report for Rules 4306, 4307 and 4320 October 16, 2008 

 Final Draft Staff Report with Appendices 

 For Proposed Amendments to Rule 4306 

 and Rule 4307 and Proposed New Rule 4320

18

VI. SOCIOECONOMIC ANALYSIS 

State law requires the District to analyze the socioeconomic impacts of any proposed 

rule or rule amendment that significantly affects air quality or strengthens an emission 

limitation. District staff conducted the socioeconomic analysis based on stakeholder 

input. The socioeconomic analysis has been used to further refine the rule 

amendments. The final socioeconomic report is attached to this staff report. 

VII. ENVIRONMENTAL IMPACTS 

Pursuant to the California Environmental Quality Act (CEQA), District staff investigated the 

likely environmental impacts of the proposed rule amendments and that information is 

attached to this staff report. 

VIII. RULE CONSISTENCY ANALYSIS 

Pursuant to state Health and Safety Code, Section 40272.2, District staff prepared a rule 

consistency analysis and that analysis is attached to this staff report. 

IX. REFERENCES 

1. San Joaquin Valley Unified Air Pollution Control District 2007 Ozone Plan, April 30, 

2007. 

2. Final Draft Staff Report for Rule 4306 (Boilers, Steam Generators, and Process 

Heaters – Phase 3), September 18, 2003. 

3. Federal Clean Air Act, Amended 1990. 

4. San Joaquin Valley Unified Air Pollution Control District, Rules and Regulations. 

5. Sheth, Atul and Tom Giel. “Understanding the PM-2.5 Problem.” Pollution 

Engineering On-line. March 2000. 

6. STAPPA (State and Territorial Air Pollution Program Administrators), ALAPCO 

(Association of Local Air Pollution Control Officials). “Controlling Fine Particulate 

Matter Under the Clean Air Act: A Menu of Options”. March 2006