1 Final Staff Report with Appendices

 For Proposed Amendments to Rule 4352 

SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT 

FINAL STAFF REPORT 

Revised Proposed Amendments to Rule 4352 

(Solid Fuel Fired Boilers, Steam Generators and Process Heaters) 

December 15, 2011 

Prepared by: Nichole Corless, Air Quality Specialist II 

 Frank DeMaris, Air Quality Engineer II 

Reviewed by: Anna Myers, Senior Air Quality Specialist 

 Lupe Jauregui, Senior Air Quality Inspector 

 Jessi Fierro, Rule Development Supervisor 

 Errol Villegas, Strategies and Incentives Manager

 Samir Sheikh, Strategies and Incentives Director 

I. SUMMARY 

The San Joaquin Valley Unified Air Pollution Control District’s (District) Governing Board 

amended Rule 4352 (Solid Fuel Fired Boilers, Steam Generators and Process Heaters) 

on May 18, 2006, to satisfy commitments in the District’s 2004 Extreme Ozone 

Attainment Demonstration Plan. The adopted amendments lowered the applicability 

threshold to include sources that have the potential to emit 10 tons per year or more of 

oxides of nitrogen (NOx) or volatile organic compounds (VOC). In addition, the emission 

limits in the rule were amended to implement “All Feasible Control Measures” pursuant 

to state California Health and Safety Code (CH&SC) Section 40914(a)(2). 

Upon evaluation of Rule 4352, Environmental Protection Agency (EPA) finalized a 

limited approval on October 1, 2010 (Revisions to the California State Implementation 

Plan, San Joaquin Valley Unified Air Pollution Control District [Rule 4352], 2010, 60623-

60632). A copy of this Federal Register and Technical Support Document (TSD) 

publication are included as Appendix C of this final staff report. EPA suggested lowering 

NOx emission limits for existing facilities to more closely match permit limits and 

demonstrate Reasonably Available Control Technology (RACT). 

Pursuant to §179 of the Clean Air Act (CAA), unless the rule has been updated and 

approved into the State Implementation Plan (SIP) within 18 months after the disapproval, 

sanctions shall be imposed, until EPA determines that the State has come into compliance. 

The purpose of this rule-amending project is to address the issues identified by EPA and 

submit adopted revisions to EPA for inclusion into the SIP to end the sanctions clock. 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT

Final Staff Report: Rule 4352 December 15, 2011 

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 Revised Proposed Amendments to Rule 4352 

II. RULE DEVELOPMENT PROCESS 

This rule development process is principally focused on ensuring that Rule 4352 meets 

requirements for RACT. Based on the District’s evaluation of sources subject to Rule 

4352, the District proposes to make a number of relatively small and administrative 

amendments to the rule. 

As part of the rule development process, District staff hosted a Technical Working 

Group meeting in September 2011 to discuss potential rule amendments with 

stakeholders. District staff also hosted a public workshop in October 2011. Staff 

solicited comments from the public, stakeholders, California Air Resources Board 

(ARB), and EPA. Comments received were evaluated and incorporated into the rule as 

appropriate. 

District staff contacted the South Coast Air Quality Management District (SCAQMD), 

Bay Area AQMD (BAAQMD), Sacramento Metropolitan AQMD (SMAQMD), YoloSolano AQMD, and Ventura County Air Pollution Control District (VCAPCD) regarding 

their rules and current sources. District staff researched other facilities as identified in 

the Federal Register and in the RACT/Best Available Control Technology/Lowest 

Achievable Emission Rate Clearinghouse (RBLC). 

As part of our new socioeconomic policy, adopted by the District Governing Board in 

October 2011, staff identified the California Biomass Energy Alliance (CBEA) as the key 

trade organization and solicited feedback on control costs and feasibility of rule 

amendments. At the October 18, 2011 workshop, District staff asked for assistance in 

identifying other trade organizations who can provide additional cost and source specific 

data. No additional trade organizations have been identified at this time. District staff 

also solicited feedback from affected sources to determine if any new Department of 

Transportation, Occupational Safety and Health Administration, safety or other 

requirements that would result from amendments. Thus far no additional requirements 

have been identified. 

The proposed rule and final draft staff report were published and made available to 

affected sources and interested parties prior to a public hearing for the District 

Governing Board to consider adopting rule amendments on December 15, 2011. 
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III. BACKGROUND 

A. Source Category

Boilers, steam generators, and process heaters are used in a broad range of industrial, 

commercial, and institutional settings. Units subject to this rule fire on a variety of solid 

fuels: coal, petroleum coke, biomass, tire-derived fuel, and municipal solid waste 

(MSW). Although the output from units subject to the rule could be utilized in many 

settings, all of the operators within the San Joaquin Valley use the units’ output to 

generate electricity. There are 16 units subject to this rule located at 15 facilities. 

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

and process heaters are either to change the combustion parameters to reduce NOx 

formation (i.e., combustion modification) or to treat the NOx formed in the process before 

the NOx is emitted into the atmosphere (i.e., post-combustion control or flue gas 

treatment). 

B. Existing Rule 4352 

The existing rule was last amended in May of 2006. At that time, operators of units 

subject to Rule 4352 were not expected to incur additional compliance costs as a result 

of the rule amendments. 

Rule 4352 applies to any boiler, steam generator, or process heater fired on solid fuel that 

has a potential to emit more than 10 tons per year (tpy) of NOx or VOC. The rule places 

limits on NOx and carbon monoxide (CO) based on three types of solid fuels as 

summarized in Table 1. Facilities that emit less than 10 tpy are exempt from complying 

with the emission limits, but are required to keep records. 

Rule 4352 outlines provisions covering start-up and shutdown times, stating the duration of 

each shut down shall not exceed 12 hours and start-up shall not exceed 96 hours. The 

rule also allows increased emission limits during low load operational periods at less than 

50 percent of the rated heat input provided the operator meets the requirements specified 

in Section 5.4 of the rule and the Air Pollution Control Officer (APCO), ARB, and EPA 

approve higher limits. 

Operators shall also submit an Emission Control Plan outlining actions required to meet 

the emission limits including emission controls or source testing showing compliance with 

the rule emission limits. 

 
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Table 1 Current Rule Emission Limits 

Fuel Type NOx Limit CO Limit 

Municipal Solid Waste 200 ppmv 

corrected to 12% CO2

400 ppmv 

corrected to 3% O2

Biomass using Multiple 

Hearth Furnace 

115 ppmv 

corrected to 3% O2

All Others 115 ppmv 

corrected to 3% O2

IV. DISCUSSION 

A. EPA Evaluation of Rule 4352 

EPA reviewed Rule 4352 to evaluate compliance with RACT requirements of CAA 

§182(b)(2) and with the CAA §110(a)(2)(A) requirement for enforceability. EPA 

published a final action in the Federal Register on October 1, 2010, as well as a TSD 

outlining their evaluation of Rule 4352. EPA has determined that the District has not 

demonstrated that the emission limits for units firing solid fuels implement RACT. EPA 

recommends the NOx emission limits for these source categories be lowered to ensure 

implementation of RACT or submit additional information to demonstrate that lower 

emission limits are not reasonably achievable. 

B. Section 3.0 – Definitions 

EPA recommended clearly defining the terms “flame stabilization period” and 

“normal operations” in the rule or in the permit to operate. Affected sources also 

suggested revisions to the definition for “shutdown.” 

District staff proposes the following definitions be added or modified in Section 3.0 of 

the rule: 

Flame stabilization period: any period in which supplemental use of a liquid or 

gaseous fuel is required in instances including control of one or more 

pollutants, or to alleviate or prevent unanticipated equipment outages or 

emergencies, directly affecting the public health, safety, or welfare, which 

would result from electric power outages. 

The definition of Flame Stabilization was recommended to be added by EPA. After the 

public workshop, District staff received feedback from affected sources to modify the 

suggested definition to broaden the applicability to include the instances of controlling one 

or more pollutants. 
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Shutdown: the period of time during which a unit is taken from operational to 

non-operational status by allowing the unit to cool from its operating 

temperature and pressure to an ambient temperature, or to a hot standby 

condition. Duration of shutdown shall not exceed 12 hours unless a longer 

time has been authorized under Section 5.3.4. 

The modifications to the definition of Shutdown were suggested by affected sources to 

address concerns with periods of shutdown and maintenance. Since an ambient 

temperature could vary significantly, it is not always reasonable or efficient to let the 

equipment reach that temperature. Therefore, adding “to a hot standby condition” 

addresses the concern and is intended to allow the operator to perform maintenance on 

a boiler that has cooled sufficiently for the work but has not cooled to ambient 

temperature. 

Hot Standby Condition: a condition in which all fuel feed has been curtailed and 

the boiler is secured at a temperature greater than the current ambient 

temperature. 

This definition would be added to further clarify the definition of Shutdown and provide a 

transition from shutdown to startup. This is needed especially during times of 

maintenance where reaching an ambient temperature requires longer shutdown than 

necessary for maintenance required. A shutdown begins when solid fuel feed is 

terminated. Shutdown ends when the unit reaches ambient temperature, or when the 

unit enters a hot standby status at a temperature above ambient but with all fuel flow 

terminated, or when 12 hours has passed since the start of the shutdown. A unit that 

shutdown to ambient temperature is eligible for startup, as is a unit that shutdown to hot 

standby. A unit that is in shutdown for 12 hours (unless authorized longer) will already 

have ceased feeding solid fuel, and would have to cease burning auxiliary fuel (thereby 

entering hot standby). Start-up would be modified to include hot standby condition. 

“Normal operations” vary from unit to unit and should be determined in the Permit to 

Operate. 

C. Section 4.0 – Exemptions 

District staff proposes to remove references in this section from rule language that refer to 

other sections of the rule that will also be removed from rule language. This amendment 

will improve rule clarity and simplify rule language but does not change the intent or 

requirements of the rule. 

D. Section 5.0 – Requirements 

EPA recommends the NOx emission limits for these source categories be lowered to 

ensure implementation of RACT. The requirements in Section 5.1 would be amended 
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to lower NOx limits. The table below identifies the proposed NOx and CO limits for a 

block 24 hour average period. The emission limits in parts per million by volume (ppmv) 

are referenced at dry stack conditions and would be corrected to the applicable percent O2

or CO2 specified in the table. 

Table 2 Current and Proposed NOx and CO Emission Limits 

Fuel Type Current Emission Limits Proposed Emission Limits 

NOx Limit CO Limit NOx Limit CO Limit 

Municipal Solid 

Waste 

200 ppmv 

corrected to 

12% CO2

400 ppmv 

corrected to 

3% O2

165 ppmv 

corrected to 

12% CO2

400 ppmv 

corrected to 

3% O2

Biomass 

115 ppmv 

corrected to 

3% O2

90 ppmv 

corrected to 3% 

O2

All Others 

115 ppmv 

corrected to 

3% O2

65 ppmv 

corrected to 3% 

O2

Municipal Solid Waste 

EPA stated in the TSD and Federal Register that the NOx limit for MSW should be 

lowered to demonstrate RACT or additional information should be provided to 

demonstrate that lower emission limits are not reasonably achievable. 

1. EPA Comment: The 1994 Alternative Control Techniques (ACT) document 

suggests emission levels for MSW-fired units between 44 – 210 ppmv at 3% O2. 

SJVACPD does not provide sufficient information to demonstrate that the 

emission ranges present in the 1994 ACT for Industrial/Commercial/Institutional 

(ICI) boilers are not reasonably achievable or other information to demonstrate 

that Rule 4352 satisfies RACT requirements. 

District Response: District staff is proposing a emission limit of 165 ppmv at 

12% CO2 which is within the range of the 1994 ACT, based on the following 

findings: 

Currently, facilities are generally equipped with Selective Non-Catalytic 

Reduction (SNCR) and utilize this technology to meet emission limits ranging 

between 165 ppmv to 210 ppmv. Although it appears that facilities can 

achieve a lower NOx limit beyond the revised proposed rule amendments, 

additional NOx control technology such as Selective Catalytic Reduction 

(SCR) would be needed. In fact, the installations that are achieving lower 

NOx emissions were installed as new installations equipped with the SCR 
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technology. District staff could not find an example of a SCR installation as a 

retrofit on an existing MSW facility. 

Though a retrofit installation has not been demonstrated in practice, the District 

conducted a cost effectiveness analysis to determine if installing SCR as a 

retrofit would be reasonable. 

District staff used the following methodology and assumptions for this cost 

effectiveness analysis: 

Assumptions

• Baseline emission factor is 0.286 lb-NOx/MMBtu (equivalent to 165 ppmv @ 

12% CO2) 

• SCR provides control to 50 ppmv at 7% O2 (47 ppmv @ 12% CO2) 

• Capital cost annualized at 10% interest for 10 years 

Cost data was obtained from a preconstruction approval by the Florida 

Department of Environmental Protection (FDEP) issued on December 23, 2010. 

The approval was issued for an MSW-fired combustor equipped with SCR for 

NOx control. The control equipment costs from the FDEP application include 

uncontrolled NOx emissions of 250 ppmv and controlled NOx emissions of 50 

ppmv which represents an 80% reduction in NOx from the SCR. However, 80% 

reduction from 165 ppmv @ 12% CO2 would yield controlled emissions of 33 

ppmv, which is well below BACT. Therefore, controlled emissions are evaluated 

at the BACT limit of 47 ppmv @ 12% CO2.

 

The SCR installation is sized for a unit rated at approximately 460 MMBtu/hr 

used to produce superheated steam for an electrical generator. District staff 

reviewed the expected exhaust parameters and found them comparable to the 

parameters for solid fuel-fired boilers in SJVAPCD. Therefore, it is believed that 

this cost estimate provides a valid basis for estimating costs for installing SCR on 

boilers in SJVAPCD. 

To maximize the emission reductions and economies of scale in estimating the 

retrofit costs, it is assumed that a 350 MMBtu/hr unit operating at full fire at 100% 

capacity factor year round for the MSW facility. The purpose of these 

assumptions is to err on the conservative side throughout the analysis. 

Emissions are calculated in the following table: 

Fuel Rating 

(MMBtu/hr) 

Time 

(hr/yr) 

EF 

(lb/MMBtu)

Emissions 

(lb/yr) 

Emissions 

(tons/yr) 

MSW (baseline) 350 8,760 0.286 876,000 438 

MSW (controlled) 350 8,760 0.081 248,346 124 
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The capital and operational costs are sized to the facility size using the six-tenths 

rule, where: 

• CA is a known cost of equipment of size A 

• CB is the estimated cost of equipment of size B 

• SB is the size of equipment B 

• SA is the size of equipment A 

CB = CA x (SB ÷ SA)

0.6

It is standard District policy for Best Available Control Technology (BACT) 

analyses to use a 10 year life and 10% interest rate unless information indicates 

otherwise; therefore the capital recovery factor (CRF) of 0.1627 will be used to 

annualize the capital costs. 

It is noted that the FDEP cost analysis is for a new unit with an adequately-sized 

induced draft (ID) fan. However, for a new unit the ductwork can be laid out in a 

way that minimizes pressure losses, allowing for a smaller ID fan than may be 

required for a retrofit. Affected sources have provided some estimates for 

additional electrical costs associated with the larger ID fan required for a retrofit, 

so these have been incorporated into the analysis. In addition, the FDEP 

analysis is for a new unit so it does not include the loss of revenue from taking a 

unit off-line to retrofit the new technology. For each unit it is estimated that the 

retrofit would require at least six months of downtime at $118/MW-hr; this will be 

added to the capital cost. Finally, the FDEP analysis specifically ignored sales 

tax on capital equipment on the grounds it is exempt from sales tax in Florida. 

This would not be the case in California, so 8% sales tax has been included. 

The cost effectiveness analysis for installing SCR on a MSW unit is as follows: 

Description of Cost Cost Factor Cost Source 

Direct Capital Costs (DC):

Purchase Equipment Costs (PE): 

(A) Basic Equipment: 

1) SCR System (Quote from Babcock Power) 6,790,099 FDEP1

2) Additional Ductwork (220 ft) $1,800/ft 336,110 FDEP 

3) Increased ID fan size 7,384 FDEP 

Subtotal of Basic Equipment A 7,133,593 FDEP 

(B) Instrumentation and controls: (1% of A) 0.01 A 71,336 FDEP 

(C) Freight: (5% of A) 0.05 A 356,680 FDEP 

(D) Taxes 0.08 

(A+B+C) 604,929 OAQPS 

 

1

 All costs from FDEP size-adjusted using six-tenths rule from 460 MMBtu/hr to 350 MMBtu/hr. 
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 Revised Proposed Amendments to Rule 4352 

PE Total: 8,166,538

Direct Installation Costs (DI): Assume Modular SCR w/ simple installation

Foundation and Supports: 0.16 PE 1,306,646 FDEP 

Handling and Erection: 0.40 PE 3,266,615 FDEP 

Electrical: (quote from CH2M Hill) 0.10 PE 816,654 Industry 

Piping: (quote from CH2M Hill) 0.20 PE 1,633,308 Industry 

Insulation: 0.01 PE 81,665 OAQPS 

Painting: 0.01 PE 81,665 OAQPS 

Costs for Expansion of APC Building for SCR 

Components (quote Malcolm Pirnie) 366,665 FDEP 

DI Total: 7,553,218

Retrofit (Deconstruct existing building/structures,

estimated equal to DI total) 7,553,218 District 

Natural gas pipeline (replace fuel oil #2) 3,000,000 Industry 

Site Preparation and Buildings 

DC Total = PE + DI + retrofit + pipeline: 26,272,974

Indirect Costs (IC): 

Engineering: 0.10 PE 816,654 OAQPS 

Construction and Field Expenses: 0.05 PE 408,327 OAQPS 

Contractor Fees: 0.10 PE 816,654 OAQPS 

Contingencies: 0.15 PE 1,224,981 FDEP 

Start-up: 0.02 PE 163,331 OAQPS 

Performance Testing: 0.01 PE 81,665 OAQPS 

Retrofit Downtime (6 months minimum, electricity sales 

and tipping fees) 11,000,000 Industry 

IC Total: 14,511,612

Total Capital Investments (TCI = DC + IC): 40,794,586

Direct Annual Costs (DAC): Assume SCR requires 0.5 hrs/shift

Operating Costs (O): (≈ 1,095 shifts/year @ 3 shifts/day) 

Operator: 1.0 hr/shift $50/hr 54,750 FDEP 

Supervisor: 15% operator 8,213 OAQPS 

Maintenance Costs (M): 

Labor: 1.0 hr/shift $50/hr 54,750 FDEP 

Material: 100% labor 54,750 FDEP 

Utility Costs (U): 

Performance loss: $0.08848/k

W-hr 386,495 FDEP 

Electricity Cost: (additional 818 kW2

) $0.08848/kW

hr 634,019 Industry

Catalyst Replace: 123,071 FDEP

Total DAC: 1,316,048

Indirect Annual Costs (IAC):

Overhead: 60% O & M 87,828 OAQPS 

 

2

 Resized from industry estimate of 2 trains, 628 kW/train, for a 715 MMBtu/hr facility, resized to 350

MMBtu/hr 
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Insurance: 0.01 TCI 407,946 OAQPS 

Property Tax: 0.01 TCI 407,946 OAQPS 

Administrative: 0.02 TCI 815,892 OAQPS 

Annualized Total Capital Investment: interest rate (%) 10 

Period (years): 10 0.1627 TCI 6,637,279 District Policy 

Total IAC: 9,672,939

Total Annual Cost (DAC + IAC): 9,672,939

Fuel 

Type 

Baseline 

Emissions 

(tons/yr)

Controlled 

Emissions 

(tons/yr)

Emissions 

Reduced 

(tons/yr)

Adjusted 

Annualized 

Cost 

($/yr)

Cost 

Effectiveness 

($/ton)

MSW 438 124 314 9,672,939 30,806 

The cost effectiveness for installing SCR on a MSW fired boiler is $30,806 per 

ton of NOx reduced. The determination would exceed the cost-effectiveness 

threshold for NOx used in evaluating BACT ($24,500/ton). It is important to note 

that this calculation is based off of a new installation of SCR, not a retrofit as 

would be required by Valley facilities. While some retrofit expenses have been 

included, operators would potentially incur additional costs when retrofitting to 

incorporate SCR including expenses for additional ductwork, installation of a new 

natural gas pipeline to replace the existing fuel oil supply, and labor; therefore, 

District staff assumes the cost effectiveness is even higher then presented in this 

staff report. This NOx level that could be obtained from installing SCR is lower 

than established BACT NOx levels and well beyond RACT thresholds. 

Therefore, even with these conservative assumptions, the installation of SCR is 

not cost effective and does not establish RACT for these types of installations. 

2. EPA Comment: Source test data for the one existing MSW facility in the San 

Joaquin Valley suggests that emission limits lower than required by Rule 

4352 are reasonably achievable. 

District Response: District staff has proposed to lower the NOx emission 

limit to the lowest reasonably achievable limit without cost prohibitive 

alterations or retrofits to implement RACT. (See Response to Comment 1) 

Though Continuous Emissions Monitoring System (CEMS) data shows the 

facility could possibly meet a lower limit, the proposed NOx emission limit 

would implement RACT while also providing a small buffer between normal 

operating conditions and the emission limit to prevent violations resulting from 

minor fluctuations. Ammonia injection could potentially be increased to help 

consistently meet a lower limit, but some affected sources expressed 

concerns of exceeding other permit conditions, such as limits on visible 

emissions, ammonia slip, and condensable particulate matter, to meet lower 

NOx limits. 
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3. EPA Comment: Facilities identified in the Federal Register Notice in other 

areas are able to achieve NOx emission levels between 61 – 152 ppmv @ 

12% CO2. 

District Response: Multiple other MSW burning facilities were identified in 

the Federal Register and RBLC. All of these facilities are subject to New 

Source Performance Standards (NSPS) or Emission Guidelines promulgated 

under Sections 111(d) and 129 of the CAA. The NSPS requirements for 

incinerators include Maximum Achievable Control Technology (MACT) for 

specified pollutants (including NOx), but MACT is more commonly associated 

with the requirements established under the National Emission Standards for 

Hazardous Air Pollutants (NESHAP). These facilities utilize various NOx 

controls to meet a wide range of emission limits depending on when the boiler 

was constructed or modified as outlined in the NSPS in 40 CFR 60, Subpart 

Cb and Subpart Eb. Subpart Cb (referred to as Cb) is a set of emission 

guidelines for MSW combustors constructed before December 19, 1995, 

while Subpart Eb (referred to as Eb) applies to large (250 ton/day) MSW 

combustors that commenced construction after September 20, 1994, or 

commenced modification/reconstruction after June 19, 1996. The facilities 

that were specifically identified are discussed in more detail below. 

Lee County Waste-to-Energy Facility in Florida was identified in the RBLC as 

having three MSW burning units. Two of the Lee County units are Cb boilers 

complying with a NOx limit of 180 ppmv @ 7% O2 (equivalent to 171 ppmv @ 

12% CO2) as a 24 hour average which is higher than the proposed NOx limit. 

The third Lee County unit is an Eb boiler that has a short-term emission limit of 

150 ppmv @ 7% O2 on a block 24-hour average basis, and an annual average 

limit of 110 ppmv @ 7% O2 from the local NSR rule. That unit was constructed 

as a new installation and began operation in August 2007 with the Title V 

operating permit finalized in the summer of 2009. Subpart Eb is not a retrofit 

requirement, but instead applies to any unit that commences construction, 

reconstruction, or modification (as defined in 40 CFR 60.2) after the applicability 

date whereas the Valley facility is subject to a Subpart Cb NOx limit of 205 ppmv 

@ 7% O2 (along with the more stringent PSD limit) for an existing unit. 

The Resource Recovery Facility (RRF) is another facility listed in the Federal 

Register notice. In 2003 the Virginia Department of Environmental Quality 

(VDEQ) issued a permit for two new MSW-fired combustors at the City of 

Harrisonburg RRF. This permit limited NOx emissions from the combustors to 

160 ppmv at 7% O2 based on the perceived similarity of the proposed design to a 

mass burn refractory wall combustor described in EPA Document AP-42, the 

Compilation of Air Pollutant Emission Factors. However, performance and 

diagnostic testing demonstrated that each combustor consistently emitted NOx in 

excess of the 160 ppmv limit. After additional diagnostic testing and technical 
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evaluation, VDEQ revised the emission limit to 250 ppmv at 7% O2 in August, 

2005. This current emission limit is equivalent to 237 ppmv NOx at 12% CO2

which is higher than the Rule’s proposed emission limit. 

The Montenay Pacific Power Corporation facility in Long Beach, California, has 

three units burning MSW. These are Cb units complying with NOx limits of 205 

ppmv @ 7% O2 as a 24 hour average which is also higher than the Rule’s 

proposed NOx emission limit. 

Cited in the Federal Register as Eco/Pittsfield, the Massachusetts Department of 

Environmental Protection staff confirm that Eco/Pittsfield became Covanta, 

Pittsfield around 2006-2007. Covanta, Pittsfield operates three MSW 

combustors units that have a combustion capacity of about 120 ton/day, which is 

less than the 250 ton/day threshold for a large MSW combustor. The draft 

renewed Title V permit includes a NOx limit of 192 ppmv @ 7% O2 on a block 24-

hour average basis (equivalent to 182 ppmv @ 12% CO2). These units have flue 

gas recirculation but do not utilize SNCR or SCR. Based off of this information, 

these units are not comparable to the Valley operation. 

After reviewing the details for each of these units, District staff determined a 

proposed NOx limit of 165 ppmv at 12% CO2 would represent, if not go beyond 

RACT. The units discussed above are either complying with a higher NOx limit 

than the revised proposed rule or go beyond RACT with additional NOx control 

technology that was installed in a newer unit and not as a retrofit. 

Biomass 

EPA stated in the Final Federal Register Notice that the District has not provided 

adequate support that the NOx emission limit in Rule 4352 for biomass-fired units 

satisfies RACT. 

1. EPA Comment: Four other California district rules have been identified that 

contain emission limits of 40 ppmv at 3% O2 for units firing ‘‘nongaseous 

fuels’’: The SCAQMD Rule 1146; SMAQMD Rule 411; BAAQMD Regulation 9 

Rule 7; and VCAPCD Rule 74.15. 

District Response: District staff is proposing a emission limit of 90 ppmv at 

3% O2 based on the following findings: 

District staff contacted the air districts listed above as well as Yolo-Solano 

AQMD to determine the number of sources subjected to each of the districts’ 

rules. Both SMAQMD and Yolo-Solano AQMD have rules specifically 

pertaining to biomass fired boilers. SMAQMD Rule 411 has a NOx limit of 70 

ppmv @ 12% CO2, which is roughly equivalent to 100 ppmv @ 3% O2. There 

has only been one biomass fired unit subject to the SMAQMD rule and it has 

been shut down since 1996. Yolo-Solano’s Rule 2.43 has a NOx limit of 90 
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 Revised Proposed Amendments to Rule 4352 

ppmv @ 3% O2 with one unit subject to the rule. The facility has a circulating 

fluidized bed (CFB) unit with SNCR which is similar to some of the units 

subject to Rule 4352. The proposed 90 ppmv @ 3% O2 NOx limit is 

consistent with Yolo-Solano’s rule. 

BAAQMD Regulation 9 Rule 7 pertains to solid fuel fired boilers and sets a 

NOx emission limit of 40 ppmv @ 3% O2. District staff verified with BAAQMD 

staff there are currently no sources subject to the rule. District staff also 

reviewed VCAPCD Rule 74.15 and SCAQMD Rule 1146. Both rules apply to 

boilers combusting on liquid or gaseous fuels and SCAQMD Rule 1146 also 

applies to units burning solid fossil fuels. Therefore, these rules would not 

apply to Valley biomass facilities.

 

After reviewing the details for each of these rules, District staff determined a 

proposed NOx limit of 90 ppmv @ 3% O2 would represent RACT for biomass 

fired units. The rules discussed above have either a higher limit than the 

proposed NOx limit, do not have any applicable sources, or the rule would not 

apply to Valley facilities for varying reasons. 

2. EPA Comment: Source test data show facilities with lower operating 

emissions than the current NOx emission limit in the rule. 

District Response: There are 9 facilities with 10 units burning biomass 

operating in the Valley. Currently, facilities are generally equipped with 

SNCR and although it appears that facilities could possibly achieve a lower 

NOx limit beyond the revised proposed rule amendments, additional NOx 

control technology such as SCR would be needed. In fact, the installations 

that are achieving lower NOx emissions are typically installed as new 

installations equipped with the SCR technology, with one exception. One 

facility in the Valley has installed SCR on a smaller existing boiler under an 

experimental research exemption approved in February 2008. In March 

2009, the District approved the facility’s application to replace the existing 

SNCR (which had become inoperable) with the SCR installed under the 

experimental research exemption. This modification did not result in any 

reduction in permitted emissions as the SCR-equipped boiler is only required 

to comply with the same emission limit the SNCR-equipped boiler was. This 

modification was incorporated into the Title V permit in September 2010. 

While this example may indicate that SCR is technologically feasible as a 

retrofit for smaller sized biomass-fired boilers, there are many other 

considerations unique to each facility that may inhibit the retrofit of a SCR 

system. Additionally, it does not prove to be cost effective at this time based 

on the following analysis. 

District staff used the following methodology and assumptions for this cost 

effectiveness analysis: 
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Assumptions

• Baseline emission factor is 0.11 lb-NOx/MMBtu for Biomass(equivalent to 

85ppmv @ 3% O2) 

• SCR provides 80% control efficiency (from the provided cost estimates) 

• Capital cost annualized at 10% interest for 10 years 

Cost data was obtained from a preconstruction approval by the FDEP issued on 

December 23, 2010 as described above in the MSW section. 

To maximize the emission reductions and economies of scale in estimating the 

retrofit costs, it is assumed that a 700 MMBtu/hr unit is operating at full fire at 

100% capacity factor year round is representative for the Valley biomass 

facilities. The purpose of these assumptions is to err on the conservative side 

throughout the analysis. 

Emissions are calculated in the following table: 

Fuel 

Type 

Rating 

(MMBtu/hr)

Time 

(hr/yr) 

EF 

(lb/MMBtu) 

Emissions 

(tons/yr) 

Control 

Efficiency

Emissions 

Reduced 

(tons/yr) 

Biomass 700 8,760 0.11 337.26 80% 269.8 

The capital and operational costs are sized to the facility size using the six-tenths 

rule, as described in the MSW section above. 

CB = CA x (SB ÷ SA)

0.6

Therefore; 

 CB = $9,672,939/year x (700 MMBtu/hr ÷ 350 MMBtu/hr)0.6 

 = $14,661,434/year 

It is standard District policy for Best Available Control Technology (BACT) 

analyses to use a 10 year life and 10% interest rate unless information indicates 

otherwise; therefore the capital recovery factor (CRF) of 0.1627 will be used to 

annualize the capital costs. 

Fuel 

Type 

Adjusted

Annualized 

Cost ($/yr) 

Emissions 

Reduced 

(tons/yr) 

Cost 

Effectiveness 

($/ton) 

Biomass 14,661,434 269.8 54,342 

It is estimated based on the above data and assumptions that requiring the 

installation of SCR would provide a cost effectiveness of $54,342/ton for a 
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biomass-fired boiler. The determination would exceed the cost-effectiveness 

threshold for NOx used in evaluating BACT ($24,500/ton), so SCR would not be 

considered BACT for biomass on that basis, let alone the less stringent RACT. 

The cost effectiveness was evaluated without taking into account additional 

potential costs involved in a retrofit of the facility. It should also be noted that the 

District’s cost effective analysis is very conservative since the installation of the 

SCR technology with an 80% control efficiency assumes a NOx emission level of 

approximately 17 ppmv @ 3% O2. This level is lower than established BACT 

levels and well beyond RACT thresholds. Therefore, even with these 

conservative assumptions, the installation of SCR is not cost effective and does 

not establish RACT for these types of installations. 

 

Furthermore, the emission factors used above are short-term emission limits 

on a block 24-hour average basis and in all probability will not be 

representative of actual annual emission rates. Indeed, the post-SCR 

emission factors for biomass is 0.022 lb/MMBtu, which is well below the shortterm emission limits for recently issued biomass-fired boiler ATCs. If, as 

appears possible, the post-SCR emission rates are higher than assumed 

above, then the quantity of emission reductions will be lower and the cost of 

emission reductions greater. Finally, it is vital to remember that the 700 

MMBtu/hr boiler assumed for biomass boilers above is an idealized 

hypothetical chosen to maximize the economies of scale in using the sixtenths rule to scale the cost estimate. For any actual plant within the 

population of solid fuel-fired boilers in SJVAPCD, the boiler rating will be 

lower (as small as 171.2 MMBtu/hr) and the cost of emission reductions will 

be correspondingly higher. 

After reviewing information from affected sources, District staff found some 

facilities would be more likely to retrofit with Regenerative SCR (RSCR) due to 

the current configurations of their facility and placement of equipment. Cost data 

and information was provided by one facility to retrofit the two units at that facility 

based on budgetary costs provided by the RSCR vendor, Babcock Power. As 

these units are among the larger solid fuel-fired boilers in the District, as well as 

operating at a comparatively high NOx limit of 0.1 lb/MMBtu, it is expected that 

the cost effectiveness analysis will be reasonably representative. 

The capital cost of refitting the two units with RSCR systems is estimated at a 

total of $24,833,445, plus $25,437,024 in lost revenue for six months of 

downtime at $118/MW-hr. This comes to a total capital cost of $50,270,469 

which is annualized to $8,179,005 per year. Replacing the catalyst after a fiveyear life is estimated to cost $1,524,000, which is annualized to 

$402,031. Operating costs are estimated at $3,457,819 including additional 

utilities, maintenance, overhead, and taxes, making the total annualized cost of 

control $12,038,855 per year. 
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The facility currently operates under a NOx emission limit of 0.1 lb/MMBtu. In 

comparison, the most recently-issued ATC for a biomass-fired boiler includes a 

NOx emission target of 0.040 lb/MMBtu as BACT. If the emission limit in the rule 

were reduced to match BACT, the cost of reductions would be $64,000/ton, 

which exceeds the cost-effectiveness threshold for BACT. If the emission limit 

were reduced to 0.02 lb/MMBtu, well below the BACT limit, the cost of reductions 

would still be $48,000/ton. 

It is noted that the costs provided by affected sources significantly exceed the 

costs developed from the FDEP analysis cited above. This is to be expected, as 

the facility analyzed by FDEP is a completely new unit with a new SCR 

installation, whereas the affected source provided a cost estimate for a retrofit of 

an existing unit using RSCR. A retrofit can generally be expected to have higher 

costs than a new installation in order to account for the additional parts and labor 

involved in tearing down the existing equipment to clear the way for the new 

equipment, and to fit the new control equipment into the existing space 

constraints. 

After reviewing the CEMS data, differences in boiler design, and varying 

operating conditions for each of the subjected facilities, District staff is 

proposing to lower the NOx emission limit to 90 ppmv @ 3% O2 to 

demonstrate RACT. Though CEMS data shows the facility could possibly 

meet a lower limit, the proposed NOx emission limit would implement RACT 

while also providing a small buffer between normal operating conditions and 

the emission limit to prevent violations resulting from minor fluctuations. 

Other Fuels 

EPA stated in the TSD and Federal Register that the NOx limit for Other Fuels should 

be lowered to demonstrate RACT or additional information should be provided to 

demonstrate that lower emission limits are not reasonably achievable. 

1. EPA Comment: Both the 1994 ACT and RBLC provide NOX emission levels 

ranging from 29 - 65 ppmv at 3% O2. Boilers in the SJV are achieving lower 

levels than required in the rule. 

District Response: District staff is proposing to lower the NOx emission limit to 

65 ppmv at 3% O2 which is within the range of the 1994 ACT recommendation, 

based on the following findings: 

Currently, facilities are equipped with SNCR and although facilities may be able 

to achieve a lower NOx limit beyond the revised proposed rule amendments, 

additional NOx control technology such as SCR would be needed. District staff 

conducted a cost effectiveness analysis to determine if installing SCR as a 

retrofit would be reasonable. 
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District staff used the following methodology and assumptions for this cost 

effectiveness analysis: 

Assumptions

• Baseline emission factor is 0.10 lb-NOx/MMBtu (equivalent to 73 ppmv @ 

3% O2) 

• SCR provides 80% control efficiency (from the provided cost estimates) 

• Capital cost annualized at 10% interest for 10 years 

Cost data to install the SCR technology was obtained from a preconstruction 

approval the FDEP issued on December 23, 2010 as described above in the 

MSW section. 

To maximize the emission reductions and economies of scale in estimating the 

retrofit costs, it is assumed that a 700 MMBtu/hr unit operating at full fire at 100% 

capacity factor year round is representative for boilers firing on “other” fuels. The 

purpose of these assumptions is to err on the conservative side throughout the 

analysis. 

Emissions are calculated in the following table: 

Fuel 

Type 

Rating 

(MMBtu/hr)

Time 

(hr/yr) 

EF 

(lb/MMBtu) 

Emissions 

(tons/yr) 

Control 

Efficiency

Emissions 

Reduced 

(tons/yr) 

Other 700 8,760 0.10 306.6 80% 245.3 

The capital and operational costs are sized to the facility size using the six-tenths 

rule, as described in the MSW section above. 

CB = CA x (SB ÷ SA)

0.6

Therefore; 

 CB = $9,672,939/year x (700 MMBtu/hr ÷ 350 MMBtu/hr)0.6 

 = $14,661,434/year 

It is standard District policy for Best Available Control Technology (BACT) 

analyses to use a 10 year life and 10% interest rate unless information indicates 

otherwise; therefore the capital recovery factor (CRF) of 0.163 will be used to 

annualize the capital costs. 

Fuel

Type 

Adjusted

Annualized 

Emissions 

Reduced 

Cost 

Effectiveness 
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Cost ($/yr) (tons/yr) ($/ton)

Other 14,661,434 245.3 59,769 

It is estimated based on the above data and assumptions that requiring the 

installation of SCR would result in a cost effectiveness of $59,769/ton for an 

Other Fuel-fired boiler. The determination would exceed the cost-effectiveness 

threshold for NOx used in evaluating BACT ($24,500/ton), so SCR would not be 

considered BACT for Other Fuels on that basis, let alone the less stringent 

RACT. The cost effectiveness was evaluated without taking into account 

additional potential costs involved in a retrofit of the facility. District staff has 

determined that is not economically feasibility to require SCR as RACT based on 

this cost effectiveness analysis and did not further evaluate additional costs 

associated with a retrofit. It should also be noted that the District’s cost effective 

analysis is very conservative since the installation of the SCR technology with an 

80% control efficiency assumes a NOx emission level of approximately 15 ppmv 

@ 3% O2. This level is lower than established BACT levels and well beyond 

RACT thresholds. Therefore, even with these conservative assumptions, the 

installation of SCR is not cost effective and does not establish RACT for these 

types of installations. 

Furthermore, the emission factors used above are short-term emission limits on a 

block 24-hour average basis and in all probability will not be representative of 

actual annual emission rates. Indeed, the post-SCR emission factors for “other” 

fuels is 0.020 lb/MMBtu, which is well below the short-term emission limits for 

recently issued ATCs. If, as appears possible, the post-SCR emission rates are 

higher than assumed above, then the quantity of emission reductions will be 

lower and the cost of emission reductions greater. Finally, it is vital to remember 

that the 700 MMBtu/hr boiler assumed for “other” fuels above is an idealized 

hypothetical chosen to maximize the economies of scale in using the six-tenths 

rule to scale the cost estimate. For any actual plant within the pollution of solid 

fuel-fired boilers in SJVAPCD, the boiler rating will be lower (as small as 171.2 

MMBtu/hr) and the cost of emission reductions will be correspondingly higher. 

Based off of this information, it would not be cost effective to require Valley 

facilities to retrofit with additional NOx reduction technology beyond what is 

currently being used. 

CEMS data shows facilities could possibly meet a lower limit, the proposed NOx 

emission limit would implement RACT while also providing a small buffer 

between normal operating conditions and the emission limit to prevent violations 

resulting from minor fluctuations. Ammonia injection could potentially be 

increased to help consistently meet a lower limit, but affected sources expressed 

concerns of exceeding other permit conditions, such as limits on visible 

emissions and ammonia slip, to meet lower NOx limits. 
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2. EPA Comment: Multiple other Air Districts have rules that place NOx limits 

on boilers burning Other Fuels. 

District Response: District staff reviewed various other air district rules 

pertaining to boilers and made the following findings: 

District staff verified that there are no existing solid fuel-fired sources 

complying with the NOx emission limit in BAAQMD Regulation 9 Rules 7 and 

11, VCAPCD Rule 74.15, SCAQMD Rule 1146, and SMAQMD Rule 411. 

VCAPCD Rule 59, Rule 74.15, and SCAQMD Rule 1135 exempt sources 

burning solid fuels. 

After reviewing the details for each of these rules, District staff determined a 

proposed NOx limit of 65 ppmv @ 3% O2 would represent, if not go beyond 

RACT for units burning Other Fuels. The rules discussed above either do not 

have any applicable sources or the rule would exempt the Valley facilities for 

varying reasons. 

General Requirements 

EPA Comment: Section 5.4.2 should indicate that source test information at 

the reduced load should be included in a request for increased emission limits 

for units operating at less than 50% of the rated heat input. 

District Response: After the public workshop, EPA commented (as outlined 

in Appendix A) to remove Section 5.4 completely or revise it to clarify that any 

alternate RACT limits must go through the SIP rulemaking process. District 

staff researched permits and contacted affected sources to verify that 

operators were not using the provision. Therefore, the entire Section 5.4 will 

be removed from rule language. 

E. Section 6.0 – Administrative Requirements and Test Methods 

EPA Comment: The Rule should specify required controls for direct PM2.5 

emissions. 

District Response: This rule amendment project is solely to address RACT 

deficiencies identified by EPA. District staff will explore requiring controls for 

direct PM2.5 when creating the next attainment plan, but will not incorporate it 

at this time. 

Section 6.1 Emission Control Plan would be removed as no new facilities will be 

subject to the rule as a result of the revised proposed amendments. Any new 

source to become subject to this rule in the future would fall under New Source 

Review. 
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Section 6.4.1.7 would also be modified to remove the withdrawn ASTM D 2015-96 

(Gross Calorific Value of Coal and Coke by the Adiabatic Bomb Calorimeter) which 

covers the higher heating value for solid fuels. It will be replaced with ASTM Method D 

5865-10 (Gross Calorific Value of Coal and Coke). 

F. Section 7.0 – Compliance Schedule 

District staff proposes to remove this section from rule language. This amendment will 

improve rule clarity and simplify rule language but does not change the intent or 

requirements of the rule. Compliance deadlines are specified in Table 1 of the rule. 

V. GLOBAL CLIMATE CHANGE AND GREENHOUSE GASES 

The California Global Warming Solutions Act of 2006 (AB 32) created a comprehensive, 

multi-year program to reduce greenhouse gas (GHG) emissions in California, with the 

overall goal of restoring emissions to 1990 levels by the year 2020. In the coming 

years, the Air Resources Board (ARB) and the Legislature will be developing policies 

and programs to implement AB 32. The District believes that the evidence and the 

rationale that climate change is occurring is compelling and convincing. In addition to 

the long-term consequences of climate change, the District is concerned with the 

potential ramifications of more moderate but imminent changes in weather patterns. 

The Valley depends heavily on agriculture for its economy and has developed 

agricultural practices based on the last several decades of weather patterns. 

Unanticipated and large fluctuations in these patterns could have a devastating effect 

on the Valley’s economy. 

While there are many win-win strategies that can reduce both GHG and criteria/toxic 

pollutant emissions, when faced with situations that involve tradeoffs between the two, 

District staff believes that the more immediate public health concerns that may arise 

from an increase in criteria or toxic pollutant emissions should take precedence. The 

San Joaquin Valley Air Pollution Control District’s Governing Board adopted the Climate 

Change Action Plan (CCAP) in August 2008. For California Environmental Quality Act 

(CEQA) requirements, one of the goals of the CCAP is to establish District processes 

for assessing the significance of greenhouse gas impacts. The District has developed a 

policy and guidance for addressing greenhouse gases under CEQA. 
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VI. HEALTH BENEFITS 

This rule amendment contributes to the Valley’s progress towards federal health-based 

air quality standards (National Ambient Air Quality Standards, or NAAQS). Progressing 

the Valley towards attainment of the NAAQS helps reduce the Valley’s air pollutionrelated health impacts and health-related costs. The District periodically compiles 

attainment plans to quantify the amount of emissions reductions needed and identify the 

individual control measures that will achieve these reductions. The control strategy as a 

whole has important public health benefits and health costs savings. 

However, for a number of reasons, it can be difficult or even misleading to attempt to 

subdivide this total plan benefit on a rule-by-rule basis. For example, photochemical 

reactions in the Valley’s atmosphere combine precursor emissions to generate ozone 

and particulate matter in the atmosphere, so it is not always appropriate to attribute the 

health and cost benefits to just one precursor. Also, considering the extensive 

emissions reductions that have already been achieved in the Valley over the past 

several years, some emissions sources may appear relatively small and 

inconsequential from a health perspective. In reality, all attainment plan rule 

commitments are important to the District’s overall strategy for reducing ambient air 

pollutant concentrations and the associated health impacts and costs. As part of the 

2004 Extreme Ozone Attainment Demonstration Plan, Rule 4352 is contributing to 

reduced NOx concentrations in the Valley, and this contributes to improved public 

health and decreased health costs. 

VII. ANALYSES 

A. Emission Reduction 

The revised proposed rule amendments are intended to address the limited approval 

from EPA concerning RACT by lowering NOx emission limits. District staff reviewed all 

subjected facility’s CEMS data and determined units are operating at or below the 

proposed emission limits. Therefore, no emission reductions are expected from this 

rule making project. 

B. Cost Effectiveness 

Pursuant to California Health & Safety Code Section 40920.6(a), the District is required to 

analyze the cost effectiveness of new rules or rule amendments that implement Best 

Available Retrofit Control Technology (BARCT) or planning requirements to incorporate all 

feasible measures. The revised proposed amendments to this rule would only add federal 

RACT requirements but not BARCT or all feasible measures, and are therefore not subject 

to the cost effectiveness analysis mandate. Given that operators are generally complying 

with the new limits currently and there are no significant emission reductions or 

compliance costs expected from these rule changes, a cost effectiveness analysis has not 
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Final Staff Report: Rule 4352 December 15, 2011 

22 Final Staff Report with Appendices for

 Revised Proposed Amendments to Rule 4352 

been performed. 

C. Socioeconomic 

Pursuant to CH&SC 40728.5, “whenever a district intends to propose the adoption, 

amendment, or repeal of a rule or regulation that will significantly affect air quality or 

emissions limitations, that agency shall, to the extent data is available, perform an 

assessment of the socioeconomic impacts of the adoption, amendment, or repeal of the 

rule or regulation.” 

The source category covers boilers, steam generators, and process heaters used in a 

broad range of industrial, commercial, and institutional settings. Units subject to this 

rule fire on a variety of solid fuels: coal, petroleum coke, biomass, tire-derived fuel, and 

municipal solid waste (MSW). Although the output from units subject to the rule could 

be utilized in many settings, all of the operators within the San Joaquin Valley use the 

units’ output to generate electricity. This rule-amending project, if adopted, would make 

the NOx emission limits more stringent for all three fuel categories. 

District staff reviewed CEMS data for affected sources and found that all facilities were 

within the range of the proposed NOx limits. Affected sources could be impacted by 

needing to increase ammonia injection or altering other operating conditions to ensure 

compliance with the proposed NOx limits on a 24-hour averaging basis. 

 

This rule-amending project is not expected to have significant costs associated with it. 

Further discussion of the cost effectiveness analysis is presented in this final staff 

report. As there would be no costs associated with this rule-amending project, therefore 

no additional socio-economic impacts. 

D. Environmental Impact 

Pursuant to §15061 of the Guidelines for Implementation of the California 

Environmental Quality Act (CEQA), District staff investigated the likely environmental 

impacts of the revised proposed amendments to Rule 4352. District staff concludes that 

it can be seen with certainty that the revised proposed amendments to the rule will not 

have any significant adverse effect on the environment. Staff recommends filing a 

Notice of Exemption under the provisions of California Code of Regulations 

§15061(b)(3). 

E. Rule Consistency 

Pursuant to CH&SC §40727.2, District staff evaluated the elements of amendments with 

the corresponding elements of other District rules and federal regulations that apply to 

the same source category or type of equipment. District staff found that the revised 

proposed amendments and requirements of this rule would not conflict with federal 
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23 Final Staff Report with Appendices for

 Revised Proposed Amendments to Rule 4352 

rules, regulations, or policies covering similar stationary sources. The rule consistency 

analysis is presented in Appendix B of the final staff report. 

F. RACT 

CAA §182(b)(2) states that ozone attainment plans shall assure that RACT for VOC is 

applied at certain sources. A RACT analysis requires an examination of a rule against 

Federal rules, regulations, and technology guidelines as well as comparing it against 

rules from other air districts in California. On October 1, 2010, EPA published in the 

Federal Register a RACT analysis of District Rule 4352. As documented in the Federal 

Register, EPA determined that Rule 4352 satisfies RACT with a few exceptions. This 

rule-amending project addresses the RACT deficiencies as identified by EPA and as 

discussed in this Final Staff Report. As such, this rule satisfies RACT requirements. 

VIII. REFERENCES 

Babcock Power. (2009). A Comparison of a Biomass 50MW Modern Stoker Fired 

System and a Bubbling Fluidized Bed System. 

CA EPA and Air Resources Board Compliance Training Course 274: Biomass Boilers 

Materials, 2011. 

Florida Department of Environmental Protection, Division of Air Resource Management. 

(2010). Technical Evaluation and Preliminary Determination – Project File No. 0990234-

017-AC (PSD-FL-413). 

Massachusetts Department of Environmental Protection. (2011). Draft Air Quality 

Operating Permit – Application No. : 1-O-07-022. 

RACT/BACT/LAER Clearinghouse [RBLC]. (2011) Retrieved September 22, 2011, 

http://cfpub.epa.gov/RBLC/ 

Revisions to the California State Implementation Plan, San Joaquin Valley Unified Air 

Pollution Control District [Rule 4352], 75 Fed. Reg. 190, pp. 60623 – 60632. 

(2010, October 1). 

San Joaquin Valley Air Pollution Control District [SJVUAPCD]. (2004, October 8) 2004 

Extreme Ozone Attainment Demonstration Plan [2004 EOADP]. Fresno: CA. 

US Environmental Protection Agency [EPA]. (1994). Alternative Control Techniques 

Document – NOx Emissions from Industrial/Commercial/Institutional (ICI) Boilers 

(US EPA 453/R-94-022). 
SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT

Final Staff Report: Rule 4352 December 15, 2011 

24 Final Staff Report with Appendices for

 Revised Proposed Amendments to Rule 4352 

US Environmental Protection Agency [EPA]. (1994). Alternative Control Techniques 

Document – NOx Emissions from Utility Boilers (US EPA 453/R-94-023). 

US Environmental Protection Agency, Region 9 Air Division. (October 2009). Technical 

Support Document for EPA’s Notice of Proposed Rulemaking for the California 

State Implementation Plan San Joaquin Valley Unified Air Pollution Control 

District’s Rule 4352, Solid Fuel Fired Boilers, Steam Generators and Process 

Heaters.