1 Final Staff Report with Appendices For Proposed Amendments to Ru le 4352 SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

FINAL STAFF REPORT

Revised Proposed Amendments to Rule 4352 (Solid Fuel Fired Boilers, Steam Generators and Pro cess Heaters)

December 15, 2011

Prepared by: Nichole Corless, Air Quality Specialis t II Frank DeMaris, Air Quality Engineer II

Reviewed by: Anna Myers, Senior Air Quality Special ist 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 Contro l 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 Dist rict’s 2004 Extreme Ozone

Attainment Demonstration Plan. The adopted amendments lowered the applicability threshold to include sources that have the potentia l to emit 10 tons per year or more of oxides of nitrogen (NOx) or volatile organic compou nds (VOC). In addition, the emission limits in the rule were amended to implement “All F easible Control Measures” pursuant to state California Health and Safety Code (CH&SC) Section 40914(a)(2).

Upon evaluation of Rule 4352, Environmental Protect ion Agency (EPA) finalized a limited approval on October 1, 2010 (Revisions to t he California State Implementation Plan, San Joaquin Valley Unified Air Pollution Cont rol District [Rule 4352], 2010, 60623- 60632). A copy of this Federal Register and Techni cal Support Document (TSD) publication are included as Appendix C of this fina l 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) w ithin 18 months after the disapproval, sanctions shall be imposed, until EPA determines th at the State has come into compliance.

The purpose of this rule-amending project is to add ress 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 DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

2 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 II. RULE DEVELOPMENT PROCESS

This rule development process is principally focuse d on ensuring that Rule 4352 meets requirements for RACT. Based on the District’s eva luation of sources subject to Rule 4352, the District proposes to make a number of rel atively small and administrative

amendments to the rule.

As part of the rule development process, District s taff hosted a Technical Working Group meeting in September 2011 to discuss potentia l rule amendments with stakeholders. District staff also hosted a public workshop in October 2011. Staff solicited comments from the public, stakeholders, C alifornia Air Resources Board (ARB), and EPA. Comments received were evaluated a nd incorporated into the rule as appropriate.

District staff contacted the South Coast Air Qualit y Management District (SCAQMD), Bay Area AQMD (BAAQMD), Sacramento Metropolitan AQM D (SMAQMD), YoloSolano AQMD, and Ventura County Air Pollution Contr ol District (VCAPCD) regarding

their rules and current sources. District staff re searched 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 Bioma ss Energy Alliance (CBEA) as the key trade organization and solicited feedback on contro l costs and feasibility of rule amendments. At the October 18, 2011 workshop, Dist rict staff asked for assistance in identifying other trade organizations who can provi de 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 de termine if any new Department of Transportation, Occupational Safety and Health Admi nistration, safety or other requirements that would result from amendments. Th us 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 amendment s on December 15, 2011.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

3 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 III. BACKGROUND

A. Source Category

Boilers, steam generators, and process heaters are used in a broad range of industrial, commercial, and institutional settings. Units subj ect 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 t he rule could be utilized in many settings, all of the operators within the San Joaqu in Valley use the units’ output to generate electricity. There are 16 units subject t o this rule located at 15 facilities.

The two primary methods of controlling NOx emission s from boilers, steam generators, and process heaters are either to change the combus tion parameters to reduce NOx formation (i.e., combustion modification) or to tre at 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 add itional compliance costs as a result

of the rule amendments.

Rule 4352 applies to any boiler, steam generator, o r 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 thr ee types of solid fuels as

summarized in Table 1. Facilities that emit less t han 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 l ow load operational periods at less than 50 percent of the rated heat input provided the ope rator meets the requirements specified

in Section 5.4 of the rule and the Air Pollution Co ntrol Officer (APCO), ARB, and EPA approve higher limits.

Operators shall also submit an Emission Control Pla n outlining actions required to meet the emission limits including emission controls or source testing showing compliance with

the rule emission limits.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

4 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 Table 1 Current Rule Emission Limits Fuel Type NOx Limit CO Limit
Municipal Solid Waste 200 ppmv

corrected to 12% CO 2 400 ppmv

corrected to 3% O 2 Biomass using Multiple

Hearth Furnace 115 ppmv

corrected to 3% O 2 All Others 115 ppmv

corrected to 3% O 2

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) requireme nt 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 d etermined that the District has not

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

recommends the NOx emission limits for these source categories be lowered to ensure implementation of RACT or submit additional informa tion to demonstrate that lower emission limits are not reasonably achievable.

B. Section 3.0 – Definitions

EPA recommended clearly defining the terms “flame s tabilization 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 b e added or modified in Section 3.0 of

the rule:

Flame stabilization period: any period in which sup plemental use of a liquid or gaseous fuel is required in instances including con trol of one or more pollutants, or to alleviate or prevent unanticipate d 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 recommend ed to be added by EPA. After the public workshop, District staff received feedback f rom affected sources to modify the suggested definition to broaden the applicability t o include the instances of controlling one or more pollutants.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

5 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 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 1 2 hours unless a longer

time has been authorized under Section 5.3.4.

The modifications to the definition of Shutdown wer e suggested by affected sources to address concerns with periods of shutdown and maint enance. Since an ambient temperature could vary significantly, it is not alw ays 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 fue l 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 t he definition of Shutdown and provide a transition from shutdown to startup. This is neede d especially during times of maintenance where reaching an ambient temperature r equires longer shutdown than necessary for maintenance required. A shutdown beg ins when solid fuel feed is

terminated. Shutdown ends when the unit reaches am bient temperature, or when the unit enters a hot standby status at a temperature a bove ambient but with all fuel flow terminated, or when 12 hours has passed since the s tart of the shutdown. A unit that shutdown to ambient temperature is eligible for sta rtup, as is a unit that shutdown to hot standby. A unit that is in shutdown for 12 hours (u nless authorized longer) will already have ceased feeding solid fuel, and would have to c ease 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 shou ld be determined in the Permit to Operate.

C. Section 4.0 – Exemptions

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

other sections of the rule that will also be remove d from rule language. This amendment will improve rule clarity and simplify rule languag e but does not change the intent or requirements of the rule.

D. Section 5.0 – Requirements

EPA recommends the NOx emission limits for these so urce categories be lowered to ensure implementation of RACT. The requirements in Section 5.1 would be amendedSAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

6 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 to lower NOx limits. The table below identifies th e 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 O 2 or CO 2 specified in the table.

Table 2 Current and Proposed NOx and CO Em ission 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% CO 2

400 ppmv

corrected to

3% O 2 165 ppmv

corrected to

12% CO 2 400 ppmv

corrected to

3% O 2 Biomass 115 ppmv

corrected to

3% O 2 90 ppmv

corrected to 3%

O 2

All Others 115 ppmv

corrected to

3% O 2 65 ppmv

corrected to 3%

O 2

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 informati on should be provided to

demonstrate that lower emission limits are not reas onably achievable.

1. EPA Comment: The 1994 Alternative Control Techniques (ACT) docum ent suggests emission levels for MSW-fired units betwee n 44 – 210 ppmv at 3% O 2

. SJVACPD does not provide sufficient information to demonstrate that the emission ranges present in the 1994 ACT for Industr ial/Commercial/Institutional (ICI) boilers are not reasonably achievable or othe r information to demonstrate that Rule 4352 satisfies RACT requirements.

District Response: District staff is proposing a emission limit of 165 ppmv at
12% CO 2 which is within the range of the 1994 ACT, based on the following findings:

Currently, facilities are generally equipped with S elective Non-Catalytic Reduction (SNCR) and utilize this technology to mee t emission limits ranging between 165 ppmv to 210 ppmv. Although it appears that facilities can achieve a lower NOx limit beyond the revised propos ed 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 e quipped with the SCRSAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

7 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 technology. District staff could not find an examp le of a SCR installation as a retrofit on an existing MSW facility.

Though a retrofit installation has not been demonst rated in practice, the District conducted a cost effectiveness analysis to determin e if installing SCR as a

retrofit would be reasonable.

District staff used the following methodology and a ssumptions for this cost effectiveness analysis:

Assumptions

• Baseline emission factor is 0.286 lb-NO

x /MMBtu (equivalent to 165 ppmv @

12% CO 2 )

• SCR provides control to 50 ppmv at 7% O 2 (47 ppmv @ 12% CO 2 )

• Capital cost annualized at 10% interest for 10 yea rs

Cost data was obtained from a preconstruction appro val by the Florida Department of Environmental Protection (FDEP) issue d on December 23, 2010. The approval was issued for an MSW-fired combustor equipped with SCR for

NO

x control. The control equipment costs from the FDE P application include uncontrolled NOx emissions of 250 ppmv and controll ed NOx emissions of 50 ppmv which represents an 80% reduction in NOx from the SCR. However, 80% reduction from 165 ppmv @ 12% CO 2 would yield controlled emissions of 33 ppmv, which is well below BACT. Therefore, controll ed emissions are evaluated at the BACT limit of 47 ppmv @ 12% CO 2

.

The SCR installation is sized for a unit rated at a pproximately 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 estim ating costs for installing SCR on

boilers in SJVAPCD.

To maximize the emission reductions and economies o f scale in estimating the retrofit costs, it is assumed that a 350 MMBtu/hr u nit operating at full fire at 100% capacity factor year round for the MSW facility. Th e purpose of these assumptions is to err on the conservative side thro ughout 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 124SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

8 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 The capital and operational costs are sized to the facility size using the six-tenths rule, where:

• C A is a known cost of equipment of size A

• C B is the estimated cost of equipment of size B

• S B is the size of equipment B

• S A is the size of equipment A

C B = C A x (S B ÷ S A ) 0.6

It is standard District policy for Best Available C ontrol Technology (BACT) analyses to use a 10 year life and 10% interest rat e unless information indicates otherwise; therefore the capital recovery factor (C RF) of 0.1627 will be used to annualize the capital costs.

It is noted that the FDEP cost analysis is for a ne w unit with an adequately-sized induced draft (ID) fan. However, for a new unit th e 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 pro vided some estimates for

additional electrical costs associated with the lar ger 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 t he 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 downt ime at $118/MW-hr; this will be added to the capital cost. Finally, the FDEP analy sis specifically ignored sales tax on capital equipment on the grounds it is exemp t from sales tax in Florida. This would not be the case in California, so 8% sal es 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 FDEP 1 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.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

9 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 PE Total: 8,166,538

Direct Installation Costs (DI): Assume Modular SCR w/ simple installati on 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) 3,000,0 00 Industry Site Preparation and Buildings

DC Total = PE + DI + retrofit + pipeline: 26,272,97 4

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 sa les 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 kW 2 ) $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/hrSAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

10 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 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 install ation of SCR, not a retrofit as would be required by Valley facilities. While some retrofit expenses have been included, operators would potentially incur additio nal costs when retrofitting to incorporate SCR including expenses for additional d uctwork, installation of a new natural gas pipeline to replace the existing fuel o il supply, and labor; therefore,

District staff assumes the cost effectiveness is ev en higher then presented in this staff report. This NOx level that could be obtaine d from installing SCR is lower than established BACT NOx levels and well beyond RA CT 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 emissi on limit to the lowest reasonably achievable limit wit hout cost prohibitive alterations or retrofits to implement RACT. (See R esponse to Comment 1) Though Continuous Emissions Monitoring System (CEMS ) data shows the facility could possibly meet a lower limit, the pro posed NOx emission limit would implement RACT while also providing a small b uffer between normal operating conditions and the emission limit to prev ent violations resulting from minor fluctuations. Ammonia injection could potent ially 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 particulat e matter, to meet lower

NOx limits.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

11 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 3. EPA Comment: Facilities identified in the Federal Register Notic e in other

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

12% CO 2

.

District Response: Multiple other MSW burning facilities were identifi ed in the Federal Register and RBLC. All of these facili ties are subject to New Source Performance Standards (NSPS) or Emission Gui delines promulgated under Sections 111(d) and 129 of the CAA. The NSPS requirements for

incinerators include Maximum Achievable Control Tec hnology (MACT) for specified pollutants (including NOx), but MACT is m ore commonly associated with the requirements established under the Nationa l Emission Standards for Hazardous Air Pollutants (NESHAP). These facilitie s utilize various NOx controls to meet a wide range of emission limits de pending 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) i s a set of emission guidelines for MSW combustors constructed before De cember 19, 1995, while Subpart Eb (referred to as Eb) applies to lar ge (250 ton/day) MSW combustors that commenced construction after Septem ber 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 Cou nty units are Cb boilers complying with a NOx limit of 180 ppmv @ 7% O 2 (equivalent to 171 ppmv @

12% CO 2 ) as a 24 hour average which is higher than the pro posed NOx limit. The third Lee County unit is an Eb boiler that has a short-term emission limit of 150 ppmv @ 7% O 2 on a block 24-hour average basis, and an annual av erage limit of 110 ppmv @ 7% O 2 from the local NSR rule. That unit was constructe d 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 c ommences construction, reconstruction, or modification (as defined in 40 C FR 60.2) after the applicability date whereas the Valley facility is subject to a Su bpart Cb NOx limit of 205 ppmv @ 7% O 2 (along with the more stringent PSD limit) for an e xisting unit.

The Resource Recovery Facility (RRF) is another fac ility listed in the Federal Register notice. In 2003 the Virginia Department of Environmental Quality (VDEQ) issued a permit for two new MSW-fired combus tors at the City of Harrisonburg RRF. This permit limited NOx emissions from the combustors to 160 ppmv at 7% O 2 based on the perceived similarity of the proposed design to a mass burn refractory wall combustor described in EP A Document AP-42, the Compilation of Air Pollutant Emission Factors. Howe ver, performance and diagnostic testing demonstrated that each combustor consistently emitted NOx in excess of the 160 ppmv limit. After additional diag nostic testing and technicalSAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

12 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 evaluation, VDEQ revised the emission limit to 250 ppmv at 7% O 2 in August, 2005. This current emission limit is equivalent to 237 ppmv NOx at 12% CO 2 which is higher than the Rule’s proposed emission l imit.

The Montenay Pacific Power Corporation facility in Long Beach, California, has three units burning MSW. These are Cb units comply ing with NOx limits of 205 ppmv @ 7% O 2 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, th e Massachusetts Department of

Environmental Protection staff confirm that Eco/Pit tsfield became Covanta, Pittsfield around 2006-2007. Covanta, Pittsfield o perates 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% O 2 on a block 24- hour average basis (equivalent to 182 ppmv @ 12% CO 2 ). 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 operat ion.

After reviewing the details for each of these units , District staff determined a proposed NOx limit of 165 ppmv at 12% CO 2 would represent, if not go beyond RACT. The units discussed above are either complyi ng with a higher NOx limit than the revised proposed rule or go beyond RACT wi th additional NOx control technology that was installed in a newer unit and n ot as a retrofit.

Biomass EPA stated in the Final Federal Register Notice tha t the District has not provided adequate support that the NOx emission limit in Rul e 4352 for biomass-fired units

satisfies RACT.

1. EPA Comment: Four other California district rules have been iden tified that contain emission limits of 40 ppmv at 3% O 2 for units firing ‘‘nongaseous fuels’’: The SCAQMD Rule 1146; SMAQMD Rule 411; BAA QMD Regulation 9 Rule 7; and VCAPCD Rule 74.15.

District Response: District staff is proposing a emission limit of 90 ppmv at
3% O 2 based on the following findings:

District staff contacted the air districts listed a bove as well as Yolo-Solano AQMD to determine the number of sources subjected t o each of the districts’
rules. Both SMAQMD and Yolo-Solano AQMD have rules specifically pertaining to biomass fired boilers. SMAQMD Rule 4 11 has a NOx limit of 70 ppmv @ 12% CO 2 , which is roughly equivalent to 100 ppmv @ 3% O 2 . 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 90SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

13 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 ppmv @ 3% O 2 with one unit subject to the rule. The facility h as 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% O 2 NOx limit is

consistent with Yolo-Solano’s rule.

BAAQMD Regulation 9 Rule 7 pertains to solid fuel f ired boilers and sets a NOx emission limit of 40 ppmv @ 3% O 2 . 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. B oth rules apply to boilers combusting on liquid or gaseous fuels and S CAQMD Rule 1146 also applies to units burning solid fossil fuels. There fore, 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% O 2 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 sour ces, or the rule would not apply to Valley facilities for varying reasons.

2. EPA Comment: Source test data show facilities with lower operati ng emissions than the current NOx emission limit in th e rule.

District Response: There are 9 facilities with 10 units burning biomas s 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 amendmen ts, additional NOx control technology such as SCR would be needed. In fact, the installations that are achieving lower NOx emissions are typicall y installed as new installations equipped with the SCR technology, wit h one exception. One facility in the Valley has installed SCR on a small er existing boiler under an experimental research exemption approved in Februar y 2008. In March 2009, the District approved the facility’s applicat ion to replace the existing SNCR (which had become inoperable) with the SCR ins talled under the experimental research exemption. This modification did not result in any reduction in permitted emissions as the SCR-equippe d boiler is only required to comply with the same emission limit the SNCR-equ ipped boiler was. This modification was incorporated into the Title V perm it in September 2010. While this example may indicate that SCR is technol ogically feasible as a retrofit for smaller sized biomass-fired boilers, t here are many other considerations unique to each facility that may inh ibit 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 a ssumptions for this cost effectiveness analysis:SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

14 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 Assumptions

• Baseline emission factor is 0.11 lb-NO

x /MMBtu for Biomass(equivalent to 85ppmv @ 3% O 2 )

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

• Capital cost annualized at 10% interest for 10 yea rs

Cost data was obtained from a preconstruction appro val by the FDEP issued on December 23, 2010 as described above in the MSW sec tion.

To maximize the emission reductions and economies o f scale in estimating the retrofit costs, it is assumed that a 700 MMBtu/hr u nit is operating at full fire at 100% capacity factor year round is representative f or 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.

C B = C A x (S B ÷ S A ) 0.6

Therefore;

C B = $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 C ontrol Technology (BACT) analyses to use a 10 year life and 10% interest rat e unless information indicates otherwise; therefore the capital recovery factor (C RF) 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 assumpt ions that requiring the installation of SCR would provide a cost effectiven ess of $54,342/ton for aSAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

15 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 biomass-fired boiler. The determination would exce ed 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 alon e the less stringent RACT. The cost effectiveness was evaluated without taking into account additional potential costs involved in a retrofit of the facil ity. It should also be noted that the District’s cost effective analysis is very conserva tive since the installation of the SCR technology with an 80% control efficiency assum es a NOx emission level of approximately 17 ppmv @ 3% O 2 . This level is lower than established BACT levels and well beyond RACT thresholds. Therefore, even with these conservative assumptions, the installation of SCR i s not cost effective and does not establish RACT for these types of installations

.

Furthermore, the emission factors used above are sh ort-term emission limits on a block 24-hour average basis and in all probabi lity will not be representative of actual annual emission rates. In deed, the post-SCR emission factors for biomass is 0.022 lb/MMBtu, whi ch is well below the shortterm emission limits for recently issued biomass-fi red boiler ATCs. If, as appears possible, the post-SCR emission rates are h igher than assumed above, then the quantity of emission reductions wil l 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 i s an idealized hypothetical chosen to maximize the economies of sc ale in using the sixtenths rule to scale the cost estimate. For any ac tual 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 Re generative SCR (RSCR) due to the current configurations of their facility and pl acement of equipment. Cost data and information was provided by one facility to ret rofit the two units at that facility based on budgetary costs provided by the RSCR vendo r, Babcock Power. As these units are among the larger solid fuel-fired b oilers in the District, as well as operating at a comparatively high NO

x 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 RS CR systems is estimated at a total of $24,833,445, plus $25,437,024 in lost reve nue for six months of downtime at $118/MW-hr. This comes to a total capi tal cost of $50,270,469 which is annualized to $8,179,005 per year. Replac ing 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.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

16 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 The facility currently operates under a NO

x emission limit of 0.1 lb/MMBtu. In comparison, the most recently-issued ATC for a biom ass-fired boiler includes a

NO

x 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 sou rces 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 u nit 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 genera lly be expected to have higher

costs than a new installation in order to account f or 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 int o the existing space

constraints.

After reviewing the CEMS data, differences in boile r design, and varying operating conditions for each of the subjected faci lities, District staff is proposing to lower the NOx emission limit to 90 ppm v @ 3% O 2 to demonstrate RACT. Though CEMS data shows the facil ity 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 inform ation should be provided to

demonstrate that lower emission limits are not reas onably achievable.

1. EPA Comment: Both the 1994 ACT and RBLC provide NOX emission lev els 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 emissi on limit to 65 ppmv at 3% O 2 which is within the range of the 1994 ACT recommen dation, based on the following findings:

Currently, facilities are equipped with SNCR and al though facilities may be able to achieve a lower NOx limit beyond the revised pro posed rule amendments, additional NOx control technology such as SCR would be needed. District staff conducted a cost effectiveness analysis to determin e if installing SCR as a

retrofit would be reasonable.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

17 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 District staff used the following methodology and a ssumptions for this cost effectiveness analysis:

Assumptions

• Baseline emission factor is 0.10 lb-NO

x /MMBtu (equivalent to 73 ppmv @

3% O 2 )

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

• Capital cost annualized at 10% interest for 10 yea rs

Cost data to install the SCR technology was obtaine d from a preconstruction approval the FDEP issued on December 23, 2010 as de scribed above in the

MSW section.

To maximize the emission reductions and economies o f scale in estimating the retrofit costs, it is assumed that a 700 MMBtu/hr u nit operating at full fire at 100% capacity factor year round is representative for bo ilers firing on “other” fuels. The purpose of these assumptions is to err on the conse rvative 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.

C B = C A x (S B ÷ S A ) 0.6

Therefore;

C B = $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 C ontrol Technology (BACT) analyses to use a 10 year life and 10% interest rat e unless information indicates otherwise; therefore the capital recovery factor (C RF) of 0.163 will be used to annualize the capital costs.

Fuel Type Adjusted

Annualized Emissions

Reduced Cost

EffectivenessSAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

18 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 Cost ($/yr) (tons/yr) ($/ton)
Other 14,661,434 245.3 59,769

It is estimated based on the above data and assumpt ions that requiring the

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

Other Fuel-fired boiler. The determination would e xceed 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 o f 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 furthe r evaluate additional costs

associated with a retrofit. It should also be note d that the District’s cost effective analysis is very conservative since the installatio n of the SCR technology with an 80% control efficiency assumes a NOx emission level of approximately 15 ppmv @ 3% O 2 . This level is lower than established BACT levels and well beyond RACT thresholds. Therefore, even with these conser vative 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 sh ort-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 sh ort-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 emi ssion 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” fu els above is an idealized hypothetical chosen to maximize the economies of sc ale in using the six-tenths rule to scale the cost estimate. For any actual pl ant within the pollution of solid fuel-fired boilers in SJVAPCD, the boiler rating wi ll 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 reductio n technology beyond what is currently being used.

CEMS data shows facilities could possibly meet a lo wer limit, the proposed NOx emission limit would implement RACT while also prov iding a small buffer between normal operating conditions and the emissio n limit to prevent violations resulting from minor fluctuations. Ammonia injecti on 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 limit s.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

19 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 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 findin gs:

District staff verified that there are no existing solid fuel-fired sources complying with the NOx emission limit in BAAQMD Reg ulation 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 ex empt sources burning solid fuels.

After reviewing the details for each of these rules , District staff determined a proposed NOx limit of 65 ppmv @ 3% O 2 would represent, if not go beyond RACT for units burning Other Fuels. The rules disc ussed above either do not have any applicable sources or the rule would exemp t the Valley facilities for varying reasons.

General Requirements

EPA Comment: Section 5.4.2 should indicate that source test info rmation at the reduced load should be included in a request fo r increased emission limits for units operating at less than 50% of the rated h eat input.

District Response: After the public workshop, EPA commented (as outlin ed in Appendix A) to remove Section 5.4 completely or revise it to clarify that any alternate RACT limits must go through the SIP rulem aking process. District staff researched permits and contacted affected sou rces 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 Te st Methods

EPA Comment: The Rule should specify required controls for direct PM 2.5

emissions.

District Response: This rule amendment project is solely to address RA CT 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 prop osed amendments. Any new source to become subject to this rule in the future would fall under New Source

Review.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

20 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 Section 6.4.1.7 would also be modified to remove th e withdrawn ASTM D 2015-96 (Gross Calorific Value of Coal and Coke by the Adia batic Bomb Calorimeter) which covers the higher heating value for solid fuels. I t 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) e missions 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 Legisl ature will be developing policies and programs to implement AB 32. The District beli eves that the evidence and the rationale that climate change is occurring is compe lling and convincing. In addition to the long-term consequences of climate change, the D istrict is concerned with the potential ramifications of more moderate but immine nt changes in weather patterns. The Valley depends heavily on agriculture for its e conomy and has developed agricultural practices based on the last several de cades of weather patterns. Unanticipated and large fluctuations in these patte rns could have a devastating effect on the Valley’s economy.

While there are many win-win strategies that can re duce both GHG and criteria/toxic pollutant emissions, when faced with situations tha t involve tradeoffs between the two, District staff believes that the more immediate pub lic health concerns that may arise from an increase in criteria or toxic pollutant emi ssions 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 Cali fornia Environmental Quality Act (CEQA) requirements, one of the goals of the CCAP i s to establish District processes for assessing the significance of greenhouse gas im pacts. The District has developed a policy and guidance for addressing greenhouse gases under CEQA.SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

21 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 VI. HEALTH BENEFITS

This rule amendment contributes to the Valley’s pro gress towards federal health-based air quality standards (National Ambient Air Quality Standards, or NAAQS). Progressing the Valley towards attainment of the NAAQS helps re duce the Valley’s air pollutionrelated health impacts and health-related costs. T he District periodically compiles attainment plans to quantify the amount of emission s 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 heal th costs savings.

However, for a number of reasons, it can be difficu lt 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 precur sor 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. Al so, considering the extensive emissions reductions that have already been achieve d in the Valley over the past several years, some emissions sources may appear re latively small and inconsequential from a health perspective. In real ity, 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 t o address the limited approval from EPA concerning RACT by lowering NOx emission l imits. District staff reviewed all subjected facility’s CEMS data and determined units are operating at or below the proposed emission limits. Therefore, no emission r eductions 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 pl anning 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 mea sures, 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 sign ificant emission reductions or compliance costs expected from these rule changes, a cost effectiveness analysis has notSAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

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 int ends to propose the adoption, amendment, or repeal of a rule or regulation that w ill significantly affect air quality or emissions limitations, that agency shall, to the ex tent data is available, perform an assessment of the socioeconomic impacts of the adop tion, amendment, or repeal of the rule or regulation.”

The source category covers boilers, steam generator s, and process heaters used in a broad range of industrial, commercial, and institut ional settings. Units subject to this rule fire on a variety of solid fuels: coal, petro leum coke, biomass, tire-derived fuel, and municipal solid waste (MSW). Although the output f rom 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-am ending project, if adopted, would make the NOx emission limits more stringent for all thre e fuel categories.

District staff reviewed CEMS data for affected sour ces and found that all facilities were within the range of the proposed NOx limits. Affec ted sources could be impacted by needing to increase ammonia injection or altering o ther operating conditions to ensure compliance with the proposed NOx limits on a 24-hou r averaging basis.

This rule-amending project is not expected to have significant costs associated with it. Further discussion of the cost effectiveness analys is 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 Implementa tion of the California Environmental Quality Act (CEQA), District staff in vestigated 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 prop osed amendments to the rule will not have any significant adverse effect on the environm ent. Staff recommends filing a Notice of Exemption under the provisions of Califor nia Code of Regulations §15061(b)(3).

E. Rule Consistency

Pursuant to CH&SC §40727.2, District staff evaluate d 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. Dis trict staff found that the revised proposed amendments and requirements of this rule w ould not conflict with federalSAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Final Staff Report: Rule 4352 December 15, 2011

23 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 rules, regulations, or policies covering similar st ationary sources. The rule consistency analysis is presented in Appendix B of the final st aff report.

F. RACT

CAA §182(b)(2) states that ozone attainment plans s hall assure that RACT for VOC is applied at certain sources. A RACT analysis requir es an examination of a rule against Federal rules, regulations, and technology guidelin es as well as comparing it against

rules from other air districts in California. On O ctober 1, 2010, EPA published in the Federal Register a RACT analysis of District Rule 4 352. As documented in the Federal Register, EPA determined that Rule 4352 satisfies R ACT with a few exceptions. This rule-amending project addresses the RACT deficienci es 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, Div ision of Air Resource Management. (2010). Technical Evaluation and Preliminary Determination – Project File No. 0990234- 017-AC (PSD-FL-413).

Massachusetts Department of Environmental Protectio n. (2011). Draft Air Quality Operating Permit – Application No. : 1-O-07-022.

RACT/BACT/LAER Clearinghouse [RBLC]. (2011) Retriev ed September 22, 2011, http://cfpub.epa.gov/RBLC/

Revisions to the California State Implementation Pl an, 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 DI STRICT

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 Di vision. (October 2009). Technical Support Document for EPA’s Notice of Proposed Rulem aking for the California State Implementation Plan San Joaquin Valley Unifie d Air Pollution Control District’s Rule 4352, Solid Fuel Fired Boilers, Ste am Generators and Process

Heaters.