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 DI STRICT

FINAL DRAFT STAFF REPORT

October 16, 2008

Proposed Amendments to Rule 4306 (Boilers, Steam Ge nerators, and Process Heaters – Phase 3) Proposed Amendments to Rule 4307 (Boilers, Steam Ge nerators, 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 Engin eer 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 conti nuous inter-mountain valley comprised of eight counties in the southern portion of the San Joaquin Valley of California: Fresno, Kings, Madera, Merced, San Joaq uin, 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 Mounta in 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 format ion 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 NAAQ S. Prior to the United States Environmental Protection Agency’s (EPA’s) implement ation of the eight-hour ozone standard, the SJVAB was also classified as an extre me nonattainment area for the onehour ozone NAAQS. Although EPA revoked the one-hou r ozone NAAQS, the SanSAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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 (Dist rict) 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 Californ ia ozone air quality standard and nonattainment for the California air quality standa rd for particulate matter ten microns in diameter or smaller (PM10).

Since amending Rule 4306 and 4307 are control measu res in the District’s 2007 Ozone Plan, they are subject to Code of Federal Regulatio ns (CFR), Clean Air Act (CAA), and California Health and Safety Code (CH&SC) requireme nts. This rulemaking project is intended to satisfy the attainment goals of the Dis trict’s 2007 Ozone Plan. The proposed amendments to Rule 4306 and Rule 4307 will seek to obtain as much reduction of oxides of nitrogen (NO

x ) from boilers, steam generators, and process heaters as expeditiously practicable and technologi cally and economically feasible, as determined by the District’s Governing Board. Furt hermore, the rules are intended to satisfy the requirements identified in Table 1 belo w.

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 DI STRICT

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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 m inimize air pollution emissions by changing the process to prevent air pollution and/o r installing air pollution control equipment. The terms "RACT," "BACT," and "LAER" ar e acronyms for different program requirements under the NSR program. EPA de fines RACT as “the lowest emission limitation that a particular source is cap able of meeting by the application of control technology that is reasonably available con sidering 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 Proce ss Heaters – Phase 3) and Rule 4320 (Advanced Emission Reduction Options For Boile rs, 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 defic iencies in Rule 4305 (Boilers, Steam Generators, and Process Heaters – Phase 2) and to r educe emissions of NOx pursuant to the District’s ozone and particulate matter atta inment strategies. The rule applies to any gaseous fuel or liquid fuel fired boilers, stea m 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 industrie s, including but not limited to electrical utilities, cogeneration, oil and gas pro duction, petroleum refining, manufacturing and industrial, food and agricultural processing, and service and

commercial facilities.

The draft staff report dated October 30, 2007 state d District staff would amend Rule 4306 to implement an emission control measure (S-CO M-1) in the District’s 2007 EightHour Ozone Plan. The control measure indicates tha t additional NOx emission reductions could be achieved by lowering the curren t NOx limit of 9 ppmv to 6 ppmv for units greater than 20 MMBtu/hr. An estimated 40 pe rcent 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 S ection II C of this report.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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 Proces s 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 ox ides (NOx) and carbon monoxide (CO) pursuant to the District’s ozone and particula te matter attainment (PM10) strategies. Facilities with units subject to this control measure represented a wide range of industries, including but not limited, to medica l facilities, educational institutions, office buildings, prisons, military facilities, hotels, an d 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 Fin al Draft Staff Report, December 15, 2005, staff stated that as a separate control strat egy 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 cat egory. As stated above, Rule 4307 would be amended in this current project by removin g 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 sour ces of future funding to replace/retrofit school boilers, steam generators, and process heate rs:

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

the District will assist in the coordination of dis tributing funds for the replacement

of school units.

• Fees generated by District Rule 9510 (Indirect Sou rce Review Program). The purpose of the District’s ISR Program is to reduce emissions from new development projects. The District anticipates tha t the ISR Program will generate funds for future emission reduction projec ts including the replacement of school boilers, steam generators, and process he aters.

3. Particulate matter control provisions

As stated previously the SJVAB is currently designa ted as nonattainment for the NAAQS for particulate matter with aerodynamic diame ter 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 in cluded SO 2 and PM control requirements in this rule project. While S O 2 is not a precursor to ozone formation in the SJVAB, SO 2 is strongly implicated in atmospheric particle for mation.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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 s taff conducted public workshops to present and discuss proposed amendments to Rule 430 6, Rule 4307 and proposed new Rule 4320. District staff conducted public worksho ps 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 Jul y 2008 so those workshops were conducted in person in Fresno, Modesto and Bakersfi eld. In addition to the workshops, numerous meetings were held with stakeholders to di scuss their individual issues and suggestions.

At the workshops, District staff presented the obje ctives of the proposed rulemaking project and provided the draft rules. District sta ff solicited information from affected source operators, consultants, vendors and manufacturers o f control technologies, and trade associations on the technological feasibility and c ompliance cost information that would be useful in developing new Rule 4320 and amendments t o 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 w orkshop 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 limitatio ns. As part of the District socioeconomic analysis process, District staff met with volunteers from affected stakeholders and interested parties at the Socioeco nomic Focus Group. The results of the socioeconomic analysis are included in this rep ort.

The proposed rule and rule amendments, final draft staff report with appendices, and final draft socioeconomic analysis report will be p ublished and mailed to affected sources and interested parties prior to a public he aring 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 hearin g 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 emi ssions from boilers, steam generators, and process heaters. The rule applies to any gaseous fuel or liquid fuel fired boiler, steam generator, and process heater w ith a rated heat input greater than

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

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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 a ddressed by other District rules. These units include solid fuel fired units, dryers, glass melting furnaces, kilns and smelters, unfired or fired waste heat recovery boil ers, and any unit in which the total rated heat input of each burner is less than or equ al to 5 million Btu per hour as specified in the operating permit, and in which eac h burner’s products of combustion does not come in contact with the products of combu stion 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 th e 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 400SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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)

Operated on Gaseous Fuel Operated on Liquid Fuel Category

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 peri odic 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 emissi on level that would have resulted if each unit in operation were individually in complia nce 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 conce rn 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 inc lude a statement that modification of PTO may qualify for exemption from BACT and offs et 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 s ource 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 exemp ts 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 al l of the existing NSR rules to a new review to ensure compliance with the requirements o f 40 CFR 51.165(a)(1).”

C. Existing Rule 4307

The purpose of Rule 4307 is to limit NOx and CO emi ssions from boilers, steam generators, and process heaters. The rule applies to any gaseous fuel or liquid fuelSAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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 w ith 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 exhaus t 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 li quid 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 i n 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; o r certify the unit in accordance with the rule to comply with the applicable emission req uirements. 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 (SO 2 ), 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 Comm ission (PUC) quality natural gas” would be added to the rule.

Section 4.0 – Exemptions

In Section 4.5, the exemption language pertaining t o “units used at a school” would be modified to make such school units subject to the e mission 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 limi ts for new and replacement units. Table 2 of Rule 4307 categorizes these units and li sts the applicable dates. District staffSAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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 wou ld be met through attrition. This provides operators the opportunity to obtain a usef ul 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 limi tations 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 chamb er in which the combustion air and flue gases are drawn through the unit without the u se 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 SO 2 . Units would be required to comply with one of the following thr ee options:

• Fire exclusively on PUC-quality natural gas, comme rcial 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 s ystem that reduces SO 2 and PM10 emissions by at least 95% by weight or limit e xhaust SO 2 to less than or equal to 9 ppmv corrected to 3.0 %O2.

Section 5.5.3 would specify the requirements to mon itor of SO 2 and PM10 based on the system parameters and frequency option chosen by th e operator and submitted to the APCO for approval.

Section 5.2 will change the “Low-use Units” thresho ld 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 dist ricts. Also, on and after July 1, 2015, each atmospheric unit in an oilfield or refinery, each g lycol reboiler, and each unit with a heat input greater than 1.8 billion Btu per calendar yea r shall comply with the emission requirements of Section 5.1. This change would mak e Rule 4307 consistent with other

California air district’s rules and considered to b e an All Feasible Control Measure pursuant to the state Health and Safety Code.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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 SO 2

. Units would be fired only exclusively on PUC-qualit y 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 c urtailment.

Section 6.0 – Administrative Requirements

Section 6.1 Recordkeeping would be modified to incl ude required records for units firing on liquid fuel during PUC-quality natural gas curtailm ent 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 S Ox and PM10 emission control system.

The word “exemption” would be changed to “certifica tion” 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 Sch edule, 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 hea t input greater than 1.8 billion Btu per calendar year. These units are required to be in f ull compliance by July 1, 2015.

E. Summary of Proposed New Rule 4320

Operators have made great strides in achieving emis sion reductions in this source category. Large capital and operating expenditures were dedicated in meeting the RACT

limits of Rule 4306. District staff understand tha t Rule 4320 would go above and beyond federal standards of reasonably available control t echnology 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 P urpose, 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 Emiss ion Reduction Options for rule compliance:

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

2. Pay an annual emissions fee to the District and meet the particulate matter control requirements; orSAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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 tha n 5.0 MMBtu/hr to 20.0 MMBtu/hr, B) Units with a total rated heat input greater tha n 20.0 MMBtu/hr, C) Oilfield steam generators of all ratings and fu el 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 b illion 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 produ cer.

These categories were created, after significant di scussions 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 prop osed low-use level of less than or equal to 1.8 billion Btu/yr.

For four categories in Rule 4320 Table 1 there is a lso an option to comply with an Enhanced Compliance Schedule with lower emissions l evels. 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 long er 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 u nits that could reach intermediate

levels in the near future and then later achieve lo wer limits with more advanced technology. For example, oilfield generators may c omply 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 mi tigates rule impacts and allows operators to take advantage of emerging technologie s 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 R ule 4320 may not be able to be achievable by all units due to space limitations an d 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 DI STRICT

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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 emiss ions 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 dem onstrated 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 applicab le 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/MMBt u, and the actual annual fuel usage, in MMBtu, for the past year. The total annual fee wou ld 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 redu ctions, in dollars per ton, as established pursuant to Sections 7.2 and 7.6 of Dis trict Rule 9510 (Indirect Source Review (ISR)), as adopted on December 15, 2005. The emiss ions fee is capped to not exceed the cost effectiveness threshold for the Carl Moyer Cos t Effectiveness as established by the applicable state law. Currently, the ISR is able t o produce the lowest cost reductions, so it

is reasonable to use that rate for the emissions fe e. 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 t hreshold is $16,000/ton.

Provisions were added for units designated as compl ying with a Staged Enhanced Schedule to switch to an annual fee prior to the Fi nal Compliance date. This recognizes the possibility that the Final Limit may not be eco nomically 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 pay ing both past and future emissions fees. The past fees will be based on the Fee Rate in plac e 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 wou ld 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 provi sion. Given the economic feasibility of meeting the Staged Enhanced limits, the modified fe e option is considered a reasonable solution for compliance.

Section 5.4 – Particulate Matter Control Requiremen ts

Section 5.4 would contain provisions to limit emiss ions 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 precu rsors. To that end, units would be required to comply with one of the following three options:SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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, com mercial 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 SO 2 emissions by at least 95% by weight; or limit exhau st SO 2 to less than or equal to 9 ppmv corrected to 3.0 % O2.

The second fuel sulfur limit would allow a fuel wit h a similar sulfur content as PUCquality natural gas to be used. This recognizes th at 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 ex haust control efficiencies. Because it may not be possible to control extremely dilute con centrations of SOx, staff have also included an optional limit of 9 ppmv. This is equi valent to emissions which would be generated by a unit firing on PUC-quality natural g as.

Liquid fuel would only be allowed during PUC qualit y natural gas curtailment and provided that it contains no more than 15 ppm of su lfur.

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 curr ent controls in place on federal operating permits. Some of the largest refiner uni ts are already in compliance with the NOx limit due to changes made for Rule 4306, but ne eded 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 demonstrat e 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 un its limited to less than 1.8 billion Btu per calendar year heat input pursuant to a Permit t o Operate provided the unit is installed prior to rule adoption date. Such low-use units ha ve a relatively high cost-effectiveness level since emissions are limited by fuel use restr ictions and meeting the limit may mean replacing the entire unit. The 1.8 billion Btu/yea r heat input limit places these units in the same category as those in Rule 4307. New units, h owever, would be expected to meet the applicable limits at the time of installation s ince 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 billi on Btu/year will have an extended compliance period to mitigate the impact of replaci ng or retrofitting these limited-use units.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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 flu id 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 com ply with the applicable limits since the cost of the new units would be considered a replace ment cost and not a compliance cost, thus improving cost-effectiveness calculations. Fo r the purposes of this rule, a unit is defined as the boiler, process heater or steam gene rator, and not the individual burner(s). Replacement of an individual burner does not trigge r 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 provis ions 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 install ed for the sole purpose of complying with the requirements of this rule may be exempt fr om Best Available Control Technology (BACT) and emission offset requirements if the PTO modifications meet the requirements of Rule 2201 (New or Modified Stationary Source Rev iew Rule) Section 4.2 (BACT Exemptions) and Rule 2201 Section 4.6 (Offset Exemp tions). This language has been previously approved by EPA and is similar to langua ge 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 Ru le 4306 but add monitoring of SOx emissions. Frequency and test methods for SOx moni toring have also been added, depending on the compliance option chosen. Monitor ing and testing for fuel SOx was based on annual fuel analysis reports, unless other wise 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 conte nt may be analyzed continuously as part of the operating permits. In setting the monitorin g, staff strove to minimize unnecessary paperwork while not overlooking potentially signifi cant SOx sources.

Section 6.0 – Administrative Requirements

Recordkeeping includes a list of specific records t hat are to be maintained for five calendar years and made available to the APCO upon request a nd include required records for units firing on liquid fuel during PUC-quality natu ral gas curtailment. These records are required to demonstrate compliance with the rule li mits or to justify exemptions for low-use

units.

Test Methods that are used to verifying rule compli ance are listed including test methods specific to oxides of sulfur and SOx emission contr ol system efficiency.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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 d eadline 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 com pliance, stakeholder recommendations,

and emission reduction commitments in the attainmen t plans. When necessary to generate additional reductions or mitigate impacts, Compliance Deadlines were extended. The use of the emissions fee may also allow a sligh tly extended compliance schedule for some units while still providing the District fundi ng to generate emission reductions in the

interim.

III. CURRENT EMISSIONS AND EMISSIONS REDUCTION

Base on the calculations detailed in Appendix B, th e potential emissions reductions for Rule 4320 and Rule 4307 total 4.5 tons/day of NOx a nd 3.6 tons/day of SOx. Please see Appendix B of this draft staff report for further d etails.

IV. EMISSION CONTROL TECHNOLOGIES

The two primary methods of controlling NOx emission s from boilers, steam generators, and process heaters are either to change the combus tion parameters (i.e., combustion modification) to reduce NOx formation or to treat t he NOx formed before it is emitted into the atmosphere (i.e., exhaust gas treatment).

Combustion Modification

Combustion modification systems are designed to red uce thermal NOx formation by changing the flame characteristics to reduce peak f lame temperature. Combustion controls include low excess air operation, staged c ombustion, overfire air ports, biased firing, and placing selected burners out-of-service

.

Combustion modification is also achieved by differe nt burner designs such as Low NOx and Ultra Low NOx burners. Some of the design prin ciples 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 o r 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 format ion by reducing the peak temperature and by reducing oxygen in the combustio n zone.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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 MMBt u/hr up to 182 MMBtu/hr with Ultra Low NOx burners and with or without FGR meeting less th an 5 ppmv NOx. District source test results also show units from 6 MMBtu/hr up to 220 M MBtu/hr with Ultra Low NOx burners and with or without FGR meeting less than 9 ppmv NO x.

Exhaust Gas Treatment

Exhaust Gas treatment (EGT) is another way to reduc e NOx. NOx is reduced to molecular nitrogen by adding flue gas treatment sys tems located after the boiler firebox. EGT includes Selective Catalytic Reduction (SCR) an d 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 int o the post-combustion zone of the

boiler.

The main issues associated with the SCR system is a mmonia slip, or unreacted ammonia. Operating problems and ammonia emissions are genera lly prevented under specific conditions and operating limits as suggested by SCR manufacturers. SCR systems use ammonia stored in aqueous form, anhydrous form, gen erated on demand, or released

from urea.

District source test results show units from 31 MMB tu/hr up to 142 MMBtu/hr with SCR systems are capable of emitting less than 3 ppmv NO x. Such results are not necessarily typical, but demonstrate the feasibility of the pro posed limits.

Particulate Matter Post-Combustion Controls

Post-combustion control devices remove pollutants f rom the flue gases downstream of the unit. These controls are effective at removing PM, SO 2 , and NOx. PM post-combustion controls include fabric filters, electrostatic prec ipitators (ESPs), and wet scrubbers. SO 2 post-combustion controls include flue gas desulfuri zation and dry sorbent injection.

ESPs use an electrical charge to separate the parti cles 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 h ave been reported to achieve 99 percent PM2.5 removal efficiency. ESPs are not common to units a ffected by Rule 4306.

Fabric filters known as a baghouse trap particulate s in the flue gas before they exit the stack. These cylindrical bags or flat envelope sys tems include a dust collection hopper and a cleaning mechanism for removal of the particu lates. 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 af fected by Rule 4306.

Flue gas desulfurization typically uses lime or lim estone as a sorbent to remove SO 2 from the exhaust gas. The two most common flue gas desu lfurization scrubbers are wet andSAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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 efficien cy of greater than 90 percent and newer dry scrubbers are capable of achieving a redu ction 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 tha t are required by permit condition to operate SO 2 scrubbers or desulfurization equipment. Other perm itted units firing on natural gas or back-up distillate oil are not requi red to operate PM2.5 or SO 2 control devices. Control devices such as baghouses, electr ostatic precipitators, and scrubbers are available, but they have not yet been demonstra ted or achieved-in-practice for gaseous-fired or liquid-fired units.

Units firing on natural gas, propane, liquefied pet roleum gas, or low sulfur diesel tend to emit very low levels of PM2.5 and SO 2 . AP-42 indicates that the uncontrolled total PM (condensable and filterable) is 0.007 pound per mil lion Btu and uncontrolled SO 2 is 0.0006 pound per million Btu for boilers firing on natural gas.

A large majority of the units that are already firi ng on PUC quality natural gas, propane, butane, or LPG would be in compliance with the prop osed 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 ru le. 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. A lso, compliance dates for some of

the lower emission limits have been extended to all ow 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-qualit y natural gas or are able to meet the fuel sulfur limits based on existing controls so th ey will have no compliance costs. The remaining units which will have to add sulfur contr ols at costs ranging from roughly $20,000 to $120,000 per ton with some operator esti mates exceeding $200,000 per ton. The cost effectiveness analysis is located in Appen dix C of this draft staff report.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Draft Staff Report for Rules 4306, 4307 and 4 320 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 soci oeconomic impacts of any proposed rule or rule amendment that significantly affects a ir quality or strengthens an emission

limitation. District staff conducted the socioecon omic analysis based on stakeholder input. The socioeconomic analysis has been used to further refine the rule amendments. The final socioeconomic report is atta ched to this staff report.

VII. ENVIRONMENTAL IMPACTS

Pursuant to the California Environmental Quality Ac t (CEQA), District staff investigated the likely environmental impacts of the proposed rule a mendments and that information is attached to this staff report.

VIII. RULE CONSISTENCY ANALYSIS

Pursuant to state Health and Safety Code, Section 4 0272.2, 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 Prog ram Administrators), ALAPCO (Association of Local Air Pollution Control Officia ls). “Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options”. March 2006