## Biomass-Fired Cogeneration Project Authority to Construct and Prevention of Significant Deterioration Permit Application Anderson, California

Prepared for: Sierra Pacific Industries Redding, California

Prepared by: ENVIRON International Corporation Lynnwood, Washington

Date:
March 2010

Project Number:
29-23586AMarch 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

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# Contents

Page

1 Introduc tion................................................................................................................... .......................... 1

1.1 Organiza tion................................................................................................................... .................. 1

1.2 Summary of Findi ngs ............................................................................................................ ........... 2

2 Project De scription ............................................................................................................ ..................... 3

2.1 Physical De scription........................................................................................................... .............. 3

2.2 Fuel S upply .................................................................................................................... .................. 3

2.3 Pollutant Emi ssion Ra tes ....................................................................................................... .......... 4

2.3.1 Criteria Po llutants ............................................................................................................ ........ 4

2.3.2 Startup Em issions .............................................................................................................. ..... 5

2.3.3 Toxic Air C ontami nants ......................................................................................................... .. 6

3 Regulatory Setting ............................................................................................................. ..................... 7

3.1 Federal R egulati ons............................................................................................................ ............. 7

3.1.1 Prevention of Signific ant Deterior ation.................................................................................... 7

3.1.2 Acid Rain Progr am .............................................................................................................. .... 7

3.1.3 Air Operating Pe rmit Pr ogram................................................................................................. 8

3.1.4 New Source Perfor mance St andards ...................................................................................... 8

3.1.5 Maximum Achievable C ontrol Tec hnology.............................................................................. 8

3.2 State And Local Em ission Regul ations........................................................................................... . 9

3.2.1 Authority to Cons truct Permits ................................................................................................ 9

3.2.2 District Air Pollution Control Regul ations .............................................................................. 10

3.2.3 Air Toxics Hot S pots (AB 2588) ............................................................................................ 10

3.2.4 California Environmental Quality Act (CEQA)....................................................................... 10

3.2.5 Offsets ........................................................................................................................ ........... 10

4 Air Quality Impac ts Analysis................................................................................................... .............. 11

4.1 Model Sele ction................................................................................................................ .............. 11

4.2 Modeling Pr ocedur es ............................................................................................................ ......... 12

4.2.1 Model Setup and A pplicatio n ................................................................................................ 12

4.2.2 Averaging Peri ods .............................................................................................................. ... 12

4.2.3 Chemical Trans formati ons .................................................................................................... 12

4.3 Elevation Data and Re ceptor Ne twork........................................................................................... 1 2

4.4 Meteorologi cal Data ............................................................................................................ ........... 13

4.5 Emission Source Rel ease Parame ters.......................................................................................... 13

4.6 Analysis Results............................................................................................................... .............. 14

4.7 Startup A nalysis ............................................................................................................... .............. 15

4.8 Secondary Impac t Analysis...................................................................................................... ...... 15

4.8.1 Class II Ar ea Grow th ........................................................................................................... .. 15

4.8.2 Class II Vi sibility ............................................................................................................ ........ 16

4.8.3 Soils and V egetatio n ........................................................................................................... .. 16

5 Class I Air Quality Impacts and Air Q uality Related Val ues Anal yses ................................................. 19Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

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# List of Tables

Table 2-1 Proposed Cogenerat ion Unit Emissi ons................................................................................. ....23 Table 2-2 Project Criteria Po llutant Emissi ons Incr ease ........................................................................ ....24 Table 2-3 Project Emission Rates and BACT Th reshol ds..........................................................................2 5 Table 2-4 Cogeneration Unit Toxic Ai r Contaminant Em ission Ra tes........................................................26

Table 3-1 Hazardous Air Po llutant Emi ssion Ra tes............................................................................... .....30

Table 4-1 Point Source Release Pa ramete rs ...................................................................................... .......31

Table 4-2 Struct ure Hei ghts .................................................................................................... ....................32

Table 4-3 Criteria Pollutant NAAQS Complianc e Assessm ent...................................................................33

Table 4-4 Criteria Pollutant CAAQS Complianc e Assessm ent...................................................................34 Table 5-1 Distances from Proposed Pr oject to Nearby Class I Areas........................................................35 Table 5-2 Summary of Q/D Analysis.............................................................................................. .............35



# List of Figures

Figure 2-1. Project Sc hematic Flow Diagr am .................................................................................... ........39 Figure 2-2. Vicinity of Facility and Mode ling Do main.......................................................................... .......41 Figure 4-1. Final Receptor Locations.......................................................................................... ...............42 Figure 4-2. Wind Rose, Redding Munici pal Airport, Jan. 2004 to Dec. 2008............................................43 Figure 4-3. Source and Signi ficant Struct ure Locat ions ........................................................................ ....45 Figure 4-4. Maximum Predicted 1- Hour Average CO Concentra tions ......................................................47 Figure 4-5. Maximum Predicted 8- Hour Average CO Concentra tions ......................................................48 Figure 4-6. Maximum Predicted 1-Hour Average SO 2 Concentra tions .....................................................49 Figure 4-7. Maximum Predicted 3-Hour Average SO 2 Concentra tions .....................................................50 Figure 4-8. Maximum Predicted 24-Hour Average SO 2 Concentra tions ...................................................51 Figure 4-9. Maximum Predicted Annual Average SO 2 Concentra tions.....................................................52 Figure 4-10. Maximum Predicted 24-Hour Average PM 10 Concentra tions................................................53 Figure 4-11. Maximum Predicted Annual Average PM 10 Concentra tions .................................................54 Figure 4-12. Maximum Predicted 1-Hour Average NO 2 Concentra tions...................................................55 Figure 4-13. Maximum Predicted Annual Average NO 2 Concentra tions...................................................56 Figure 5-1. Nearby Class I Area Locations..................................................................................... ...........57



# List of Appendices

Appendix A: SCAQMD Forms Appendix B: BACT Analysis Appendix C: Air Quality Dispersion Modeling Files (CD) Appendix D: Communications From FLMsMarch 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

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# 1 Introduction

Sierra Pacific Industries (SPI) proposes to construct and operate a cogeneration unit at an existing lumber manufacturing facility located in Anderson, California. The boiler associated with the proposed cogeneration unit will burn biomass fuel (i.e., non-treated wood and agricultural crop residues, as well as urban wood-waste and other fuels subject to district approval) generated by the facility, regional lum ber manufacturing facilities, and other biomass fuel sources to produce approximately 250,000 pounds of steam per hour. The steam will be used to dry lumber in existing kilns and for a steam turbine; the steam turbine will drive a generator that will produce electricity for on site use as well as for sale to the grid. Although no steam sales agreements are currently in place, steam may also be sold to other nearby businesses. The existing biomass-fired boiler will remain operational, but will not operate concurrently with the proposed unit other than periods of operational overlap necessary to ensure adequate uninterrupted steam production.

Because the existing lumber manufacturing facility is a major stationary source of emissions, and the proposed cogeneration unit is considered a major modification, a Prevention of Significant Deterioration (PSD) permit must be obtained. On March 3, 2003, the U.S. Environmental Protection Agency (USEPA) withdrew the PSD delegation from several authorities in USEPA Region IX, including Shasta County Air Quality Management District (AQMD), making USEPA the PSD permitting authority for Shasta County. However, AQMD issued the initial PSD permit for the Anderson facility in 1994. Additionally, AQMD Rule 2-1A requires a new or modified emission source to obt ain an Authority to Construct (ATC) from the AQMD prior to commencing construction. SPI has retained ENVIRON International Corp. (ENVIRON) to prepare a combined ATC/PSD permit application to be submitted to the AQMD
on its behalf.

This permit application is a revision and update of a permit application for a similar project involving a smaller version of the same boiler design (200,000 pounds steam per hour instead of 250,000 pounds of steam per hour) that was submitted to the AQMD in May 2007. In addition to revising the emission rate calculations and regulatory analysis to reflect the currently proposed boiler, the air quality modeling was updated to reflect the most current versions and guidance.



### 1.1 Organization
The key components of this permit application are:

• 

### A description of the project and expected air pollutant emissions;

• 

### A discussion of applicable air quality regulations;

• 

### An analysis of Best Available Control Technology (BACT); and

• 

### Analysis of compliance with ambient air quality standards.

Standard forms related to the ATC process are provided in Appendix A.Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

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### 1.2 Summary of Findings
ENVIRON conducted an air quality impact assessment of the project using five years of hourly meteorological surface data collected at Redding Municipal Airport between January 1, 2004 and December 31, 2008. The analysis indicates that predicted ambient air pollutant concentrations attributable to the project will not cause or contribute to an exceedance of the National or California Ambient Air Quality Standards (NAAQS or CAAQS) established to protect human health and welfare, nor increase the ambient concentrations in excess of the PSD increments established to prevent deterioration of the area’s existing air quality.

ENVIRON also conducted a screening analysis to determine the need to assess air quality related values (AQRVs) including regional haze, nitrogen and sulfur deposition and the effects of primary and secondary pollutants on sensitive plants and soils at Class I areas in the region. The screening analysis determined that a regional AQRV modeling analysis was not necessary.March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

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# 2 Project Description

2.1 Physical Description
Sierra Pacific Industries (SPI) is a family -owned wood products company based in Redding, California. SPI currently operates an existing lumber manufacturing facility in Anderson, California. SPI intends to construct a new cogeneration unit at the Anderson facility that would burn biomass fuels in a boiler to produce steam that would be used to generate electricity and to heat existing lumber dry kilns at the facility.

The cogeneration unit will consist of a biomass-fired water-wall boiler with a vibrating grate, a steam turbine, and a generator. The boiler will burn biomass fuels to produce high-pressure
steam for the steam turbine. The steam tu rbine generator will generate up to 23 megawatts (MW) of electricity. Approximately 7 MW will be used to power on-site equipment; the remainder will be sold to a public utility. Low-p ressure steam will be extracted from the steam turbine through a controlled extraction and used to heat the dry kilns.

The final design of the biomass-fired boiler has not been determined, but it will be similar to a unit designed by the McBurney Corp. of Norcross, Georgia. It will have a maximum annual average design heat input of approximately 425.4 million British thermal units per hour (MMBtu/hr) and a maximum steam generation rate of 250,000 pounds per hour (lb/hr). Over short-term periods, the boiler will have the capacity to be fired at heat input rates that exceed the annual average rate: an hourly maximum of 468.0 MMBtu/hr (10 percent greater than the annual average), and a maximum 24-hour average of 446.7 MMBtu/hr (5 percent greater than the annual average). The boiler will be equipped with two natural gas burners, each with a maximum rated heat input of 62.5 MMBtu/hr, for start up and flame stabilization. The cogeneration unit design will incorporate a select ive non-catalytic reduction (SNCR) system that uses annhydrous ammonia to reduce emissions of oxides of nitrogen (NO X 

### ), as well as a multiclone and electrostatic precipitator (ESP) to control emissions of particulate matter (PM/PM 10 

### ). A closed-loop two-cell cooling tower will be used to dispose of waste heat from the steam turbine. A schematic flow diagram for the cogeneration facility is presented in Figure 2-1.

The proposed cogeneration unit will be located near the existing biomass-fired boiler at SPI’s Anderson lumber manufacturing facility. The existing facility is bordered on the northeast by the Sacramento River, on the northwest by a private parcel, on the southwest by Union Pacific Railroad tracks and State Route (SR) 273, and on the southeast by private parcels. The general vicinity of the facility and the modeling domain are shown in Figure 2-2.



### 2.2 Fuel Supply
Fuel for the cogeneration unit will come from the existing SPI facilities in California at Arcata, Anderson, Shasta Lake, and Red Bluff, as well as in-forest materials from SPI-owned or controlled timberlands, and various sources of agricultural and urban wood wastes. The available supply from SPI-owned or controlled facilities and timberlands totals 400,000 bone dry tons (BDT) per year. In addition, there are 50,000 BDT of agricultural and urban wood wastesSierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

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### available to SPI annually. The new boiler will consume an average of approximately 25 BDT of biomass fuel per hour which equates to 219,000 BDT per year since it is expected to operate as near to continuously as is practicable.

The Anderson facility currently produces approxim ately 160,000 BDT of wood wastes per year of which 60,000 BDT are consumed by the existing cogeneration facility, 20,000 BDT are trucked to other biomass power plants, and the balance is trucked to other markets (e.g., wood chips to pulp mills). The new facility will consume a maximum of 219,000 BDT per year, 80,000 BDT of which will be generated by SPI’s Anderson facility at a minimum, while the balance (a maximum of 139,000 BDT) will transported by truck from other SPI sources. At a maximum, an additional 23 truck trips per day will be needed to deliver additional fuel to the facility.

The installation of the boiler will not increase emi ssions from any existing emission units at the Anderson mill. There have been no contemporaneous modifications at the Anderson mill.



### 2.3 Pollutant Emission Rates
This section addresses pollutant emission rates associated with the project. The proposed
boiler will emit NO X 

### , carbon monoxide (CO), particulate matter smaller than ten microns (PM 10 

### ), PM, sulfur dioxide (SO 2 

### ), and volatile organic compounds (VOCs), as well as several substances identified as TACs by the Air Resources Board (ARB).



### 2.3.1 Criteria Pollutants
Table 2-1 presents anticipated criteria pollutant emission rates from the cogeneration unit during normal operation. Boiler emission factors for NO X 

### , CO, PM 10 

### , and VOCs were based on the BACT anslysis and expected guarantees from the boiler and control device manufacturers or
vendors. The SO 2 

### emission factor is based on source test information from the existing biomass-fired boiler. Additional material handling operations associated with the project will be enclosed, and, as a result, fugitive dust emissions associated with the project are expected to be negligible.

The cooling tower will emit only PM 10 

### . The drift eliminators to be used as part of the cooling tower design (DRU-1.5) will achieve a drift of 0.0005 percent or less. Assuming this drift rate, a water flow rate of 27,600 gallons per minute (gpm), and a conservative total dissolved solids (TDS) value of 725 milligrams per liter (mg/l), the PM 10 

### emission rate from the cooling towers is 1.1 ton per year (TPY).

Consistent with the BACT analysis in Appendix B, SPI proposes the following emission limits:

• 

### NO X 

### – 0.13 lb/MMBtu (30-day average)

• 

### CO – 0.35 lb/MMBtu (3-hour average)

• 

### PM 10 

### – 0.02 lb/MMBtu (3-hour average) including filterable and condensable componentsMarch 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

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### SPI does not believe limits are warranted for SO 2 

### or VOC emissions from the cogeneration unit
or for PM 10 

### emissions from the cooling tower because the emission rates are so low.

Table 2-2 presents the calculated annual emission increases associated with the project. Table 2-3 presents the maximum hourly and daily em ission rates compares them to the AQMD BACT thresholds. Chapter 4 presents dispersion modeling analyses used to assess compliance with ambient air quality standards.



### 2.3.2 Startup Emissions
SPI typically shuts down its boilers at least twice per year for maintenance. During the subsequent startup, the boiler is heated gradually to avoid stresses that could physically damage the boiler if it were heated too quickly. The startup period may last up to 24 hours when starting with a “cold” (ambient temperature) furnace, and will be accomplished using the natural gas-fired burners firing pipeline natural gas. Firing at full capacity, these burners will provide only thirty percent of rated boiler heat input and will initially be the sole source of heat input to the boiler during startup. Heating will continue using the natural gas burners until the furnace is hot enough to introduce biomass fuel to the furnace. After biomass fuel is introduced to the furnace, the natural gas firing rate will be reduced to maintain a steady heat rate. For the remainder of the startup period, the biomass-fuel feed rate will increase until the desired firing rate is achieved and the natural gas firing is no longer needed. The startup period will end when stable burning of biomass fuel is established under good combustion practices at the desired firing rate and the boiler reaches is design operating temperature.

During the startup period, CO emission rates will exceed those experienced under normal operation. Unlike normal operation, it is very difficult for the boiler manufacturer to estimate startup CO emission rates, which vary continuously during the startup process. Because exhaust levels of oxygen are high and CO 2 

### levels are low during startup, SPI proposes that the startup CO emission rate limit be a mass-per-unit-time limit rather than a concentration corrected to 12 percent CO 2 

### as is commonly done for normal operation limits. SPI proposes a startup and shutdown CO emission rate lim it of 400 lb/hr averaged over 1 hour.

The natural gas burners are also used during boiler shutdown to burn any remaining wood ash in order to prevent temperature excursions in the ESP. The shutdown process is expected to require up to 24 hours for the furnace to reach ambient temperature, and to experience hourly average CO emission rates similar to those of startup. SPI proposes that the boiler be subject to the startup CO emission rate limits during shutdown.

A modeling analysis was performed to demonstrate that the proposed startup/shutdown emission limits will comply with the CO ambient air quality standards. This analysis is documented in Chapter 4.Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

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### 2.3.3 Toxic Air Contaminants
Most TAC emission factors for wood-residue fuels were based on source tests used to develop emission factors for AP-42 Section 1.6. However, whereas the USEPA combined all source test data to calculate the AP-42 emission factors regardless of control technology, the emission factors used here were calculated using the subset of source tests in which wood-fired boilerswere controlled by ESPs. For the hydrogen chloride (HCl) emission factor, this subset of ESPcontrolled source tests was further reduced by removing source tests performed on units burning municipal solid waste. The hexavalent ch romium emission factor was calculated using biomass-fired boiler source tests from AP-42 source test data, after excluding source tests that included values based on the detection limit. The ammonia (NH 3 

### ) emission rate was based on a maximum exhaust ammonia concentration of 20 par ts per million (ppm). Ammonia emissions are a consequence of operating an SNCR system to reduce boiler NO X 

### emissions to
0.13 lbs/MMBtu.

In cases where no ESP-controlled source test results were available for a particular TAC, results associated with other particulate control equipment were used. Source test data from units not employing particulate controls or not reporting any control equipment were included where no other source test data were available. Table 2-4 presents the TAC emission factors and emission rates associated with the biomass-fired boiler. The cooling tower is not expected to emit any TACs.March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

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# 3 Regulatory Setting

The proposed biomass-fired cogeneration unit project is subject to federal, state, and local regulations. The following section discusses the applicable regulations and why certain regulatory programs are not applicable. It should be noted that the project will be located in an area that is in attainment of all federal ambient air quality standards, but has been designated

as not in attainment with the state ozone and PM 10 

### standards.



### 3.1 Federal Regulations

3.1.1 Prevention of Signi ficant Deterioration
For purposes of new source review, construction of the proposed cogeneration unit is a major modification of an existing major source, and is therefore subject to the requirements of the PSD program because, as shown in Table 2-2, annual CO emissions have the potential to exceed 250 TPY. Table 2-2 also shows that potential NO X 

### , CO, and PM 10 

### emissions exceed the PSD significant emission rates (SERs), indicating that PSD review is required for each of these pollutants.

PSD regulations require a BACT analysis for all air pollutants emitted by a project that exceed the SERs (in this case, NO X 

### , CO, and PM 10 

### ). The BACT analysis evaluates the energy, environmental, economic, and other costs associated with each technology, and weighs those costs against the reduced emissions the technology would provide. BACT analyses are presented in Appendix B for the biomass-fired boiler and the cooling tower.

In addition, PSD regulations require modeling analyses to demonstrate compliance with the applicable NAAQS and PSD increments locally, and in national parks and wilderness areas. Evaluations of additional impacts (i.e., growth, visibility, soils, and vegetation) are also required for both local and regional areas. Local and regional air quality modeling, as well as secondary impact, analyses are provided in Chapters 4 and 5, respectively.



### 3.1.2 Acid Rain Program
The USEPA’s Acid Rain Program, Title IV of the Clean Air Act, is intended to achieve significant environmental and public health benefits through reductions in emissions of SO 2 

### and NO X 

### , the primary causes of acid rain. The biomass-fired boiler proposed by SPI will not be subject to the requirements of the Acid Rain Program because it is a cogeneration unit with an electrical generating capacity below the program applicability threshold.

40 CFR 72.6 identifies criteria used to determine whether a facility is subject to the Acid Rain Program. Section 72.6(b)(4)(ii) states that a biomass-fired cogeneration unit is not subject to the program if it sells no more than one third of its potential annual electrical output capacity or if it sells less than 219,000 megawatt (electric)-hours (MWe-hrs) of electricity annually. A cogeneration unit meeting either of these criteria is not subject to the Acid Rain Program.Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

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### The biomass-fired cogeneration unit proposed by SPI meets the definition of a “cogeneration unit” in 40 CFR 72.2 because at least a portion of the steam generated by the boiler will be
delivered first to the steam turbine and then used to heat lumber dry kilns at the existing lumber manufacturing facility. Thus, the steam will be “used twice.” Although SPI expects to sell more than one-third of the boiler’s annual potential electrical output capacity, the boiler will be an unaffected source because SPI expects to sell no more than 219,000 MWe-hrs of electricity annually. Due to the proposed boiler’s cogeneration status and proposed electrical sales, this
boiler is considered an unaffected source.



### 3.1.3 Air Operating Permit Program
The lumber manufacturing facility is a major source subject to the Title V air operating permit program. Because the proposed cogeneration unit is a major modification requiring a PSD permit, a significant permit modification is required under AQMD Rule 5, Section IV.B.3. The cogeneration unit may not commence operation until the permit revision is approved.



### 3.1.4 New Source Performance Standards
USEPA has established performance standards for a number of air pollution sources in 40 CFR Part 60. These New Source Performance Standards (NSPS) usually represent a minimum level of control that is required of a new source. NSPS Subpart Db addresses emissions from boilers that have a heat input of greater than 100 MMBtu/hr, and will apply to the cogeneration boiler because the maximum annual average heat input is expected to be 425.4 MMBtu/hr.

Subpart Db limits PM emissions to 0.03 lb/MMBtu for newly constructed units. At the proposed maximum firing rate, this limit translates into an emission rate of 43 lb PM/hr. Subpart Db also requires exhaust opacity to be 20 percent or less (6-minute average), except for one 6-minute period per hour, which cannot exceed 27 percent opacity. These standards do not apply during startup, shutdown, or a malfunction. The emission rates proposed by SPI reflect BACT (which is more stringent than these NSPS limits), and the PM 10 

### emission rates proposed for the cogeneration unit are less than those allowed by NSPS.

The cogeneration unit will burn natural gas during startup. Subpart Db prescribes SO 2 

### and NO X 

### limits on boilers that fire fossil fuels under certain conditions. The SO 2 

### limits do not apply to boilers that combust natural gas. The NO X 

### limits in Subpart Db do not apply to boilers that have an annual fossil fuel capacity factor of less than ten percent. SPI will maintain on-site records of the quantities and times that natural gas is fired in the boiler to ensure that gas provides less than 10 percent of the annual fuel input. Consequently, neither the SO 2 

### nor the NO X 

### emission limits identified in Subpart Db will apply.



### 3.1.5 Maximum Achievable Control Technology
The Clean Air Act Amendments of 1990 require USEPA to establish technology-based standards to control hazardous air pollutants (HAPs). For MACT purposes, a major source isMarch 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

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### defined as one with a potential to emit (PTE) greater than 10 TPY of a single HAP or more than
25 TPY of all HAPs combined.

The existing and proposed boiler would not operate concurrently other than some overlap during startup and shutdown, and the proposed boiler has a greater firing rate, therefore the calculated maximum HAP emissions from the proposed boiler, which is summarized in Table 3- 1, represents the maximum annual HAP PTE for any combined operation of the two boilers (i.e., not concurrent operation, but some combination of the two boilers operating during a given 12- month period).

Considering HAP emissions from the propos ed boiler and the existing lumber dry kilns, 1 

### the HAP emitted in greatest quantity will be methanol at an annual rate 9.2 TPY, and emissions of all 47 HAPs combined will be 34.0 TPY. Consequently, the facility’s post-project HAP potential to emit will exceed the combined HAPs MACT threshold, and the facility will be subject to the MACT program. It is important to note that we believe the current potential to emit HAPs from the existing boiler and kilns does not exceed the major source thresholds; the potential HAP emissions from the proposed boiler will make the existing facility a major source of HAPs. Per 40 CFR Part 63.9(b)(1)(iii), this permit application serves as the initial notification that, when the proposed cogeneration unit begins operation, the Anderson facility will be a major source of HAPs, and affected emission units will be subject to the requirements of the applicable MACT

standards.



### 3.2 State And Local Emission Regulations

3.2.1 Authority to Construct Permits
Shasta County AQMD Rule 2, Part 100 requires new or modified stationary sources to obtain an ATC air quality permit. The ATC permit application must provide a description of the facility, an inventory of pollutant emissions, and proposed control systems for the applicable pollutants. The reviewing agency considers whether BACT has been employed and evaluates predicted ambient concentrations attributable to these emissions to ensure compliance with ambient air quality standards.

BACT applicability is determined based on daily emission thresholds provided in AQMD Rule 2 Part 301. The daily emissions of each pollutant with the potential for requiring BACT are listed in Table 2-2, along with the daily PTE and regulatory threshold. As shown in the table, BACT is required for reactive organic compounds (ROG), NO X 

### , SO 2 

### , PM 10 

### , CO, and beryllium. BACT analyses are presented in Appendix B for the biomass-fired boiler and the cooling tower.

1 The lumber dry kilns were estimated to have a ma ximum annual throughput of 180 m illion board feet per year

(MMbf/yr). This throughput was divided into species-s pecific annual throughputs (i.e., for ponderosa pine, sugar pine, Douglas fir, and white fir) based on the average th roughput fraction of each spec ies using data from 2007 and 2006. The maximum annual species throughputs were combi ned with emission factors for acetaldehyde, acrolein, formaldehyde, methanol, and propionaldehyde developed by t he Oregon Department of En vironmental Quality.Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

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### As stated in AQMD Rule 2, Part 300, an ATC permit cannot be granted unless the agency determines the project (1) will meet applicable st ate and federal emission limits; (2) will employ BACT where required; and (3) will not cause or contribute to violations of ambient air quality standards. This application provides the information to enable the AQMD to make those

determinations.



### 3.2.2 District Air Pollu tion Control Regulations
Regulations addressing emissions of specific air contaminants from a single source are contained in AQMD Rule 3, Part 2. For sources constructed after July 1, 1986, PM emissions are limited to 0.15 grains per dry standard cubic foot (gr/dscf), while PM 10 

### is limited to 0.05 gr/dscf, and combustion PM is limited to 0.10 gr/dscf. SO 2 

### emissions are limited to 200 ppm, and NO X 

### emissions are limited to 300 ppm for solid fuels, and 250 ppm for gaseous fuels. Opacity is limited to Ringelmann #2 and/or 40 percent.



### 3.2.3 Air Toxics Hot Spots (AB 2588)
The “Hot Spots” Act, also known as AB 2588 or the Health and Safety Code Section 44300 et seq., requires facilities to which the act applies to inventory and report air toxic emissions from stationary sources. In addition to the TAC emission increases discussed in Section 2.3.3 and summarized in Table 2-4, a Health Risk Assessment of TAC emission increases associated with the proposed project has been provided to AQMD and the Shasta County Planning Department.



### 3.2.4 California Environmental Quality Act (CEQA)
All ATCs are required to undergo a preliminary review by the AQMD to determine if any possibility of a significant environmental effect exists. Following this review, the AQMD will determine whether further environmental review is required. If further review is warranted, a determination will be made as to whether or not the AQMD is the Lead Agency or a Responsible Agency, and the Environmental Review will proceed as described in AQMD Environmental Review Guidelines (November, 2003).



### 3.2.5 Offsets
Sections 40918, 40919, 40920, and 40920.5 of the California Health & Saftey (H&S) Code require areas that are designated as being in nonattainment with respect to one or more criteria pollutant State or Federal standards to achieve “no net increase” in emissions (i.e., offsets) of those pollutants and their precursors. Although Shasta County has been designated a nonattainment area with respect to the State ozone and PM 10 

### ambient air quality standards, it has further been classified as having “moderate air pollution.” Areas that are not classified hashaving “extreme air pollution” are not required, by H&S Section 40918.5, to implement a no-netincrease permitting program in their attainment plan, and, in 1997, the AQMD repealed Parts 302 and 303 of AQMD Rule 2:1, which had previously implemented such a program. Thus, no offsets are required by the AQMD new source review air permitting program.March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

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# 4 Air Quality Impacts Analysis

Neither an ATC nor a PSD permit can be issued unless the proposed new source or
modification can demonstrate that the allowable emissions will not cause or contribute to violation of any ambient air quality standard or increment. This is typically accomplished using air quality dispersion modeling to predict ambient concentrations. This chapter discusses the methodology used to develop near-field modeling used to predict pollutant concentrations attributable to project emissions in the Class II areas surrounding the proposed facility. Class II areas are essentially the entire country save for areas designated as Class I areas, which are National Parks, Wilderness Areas, and other ar eas where the smallest PSD increments have been imposed to allow the smallest degree of air quality deterioration. Class II areas have been deemed able to accommodate normal, well-managed industrial growth, and, therefore, have higher PSD increments. 2



### 4.1 Model Selection
ENVIRON reviewed regulatory modeling techniques to select the most appropriate air quality dispersion model to simulate dispersion of air pollutants emitted by the proposed project for a near-field air quality impact analysis. The selection of a modeling tool is influenced by the potential for exhaust plumes from point sources to be influenced by nearby on-site structures and to impact complex terrain. The terrain at and immediately surrounding the facility, as well as in the north and east portions of the modeling dom ain, is relatively flat, however, intermediate and complex terrain exists in the southwest portion of the domain. The heights of proposed and existing structures, and the proposed cogeneration unit stack height, suggests that there is the potential for exhaust plume downwash to occur.

AERMOD is currently the model recommended by the USEPA’s Guideline on Air Quality Models (codified as Appendix W to 40 CFR Part 51, hereafter referred to as the Guideline) as the preferred dispersion model for complex source configurations and for sources subject to exhaust plume downwash. AERMOD incorporates numerical plume rise algorithms (called the PRIME algorithm) that include the downwash e ffects a structure may have on an exhaust plume implicitly. Importantly, the PRIME algorithm also treats t he geometry of upwind and downwind structures and their relationship to the emission point more precisely, and is able to calculate concentrations within building cavities.

AERMOD was selected for the modeling analysis primarily because it is the most up-to-date dispersion model currently available. A dditionally, the modeling domains and source configurations suggested the potential for exhaust plume downwash and plume impacts on intermediate and complex terrain.

2 U.S. EPA, New Source Review Workshop Manual, Prevention of Significant Deterioration and Nonattainment Area

Permitting . Draft. October, 1990.Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

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### 4.2 Modeling Procedures
AERMOD was applied to both criteria pollutants and TACs using the regulatory defaults in addition to the options and data discussed in this section. Electronic versions of the modeling files are provided on a compact disk in Appendix C.



### 4.2.1 Model Setup and Application
The most recent version of AERMOD (Version 09292) was applied with the default options for dispersion that depend on local meteorological data, regional upper air data, and the local physical characteristics of land use surrounding the facility. AERMOD contains several options for urban dispersion that were not selected for these analyses. The facility is located near, Anderson, California, and the majority of the study domain is agricultural land, rangeland, or forest. The effects of surface roughness and other physical characteristics associated with the types of land use in the modeling domain were included in the analysis as part of the meteorological database, described in Section 4.4.



### 4.2.2 Averaging Periods
Criteria and toxic air pollutant concentrations predicted by the model were averaged over shortterm (1-, 3-, 8-, and 24-hour) and annual averaging periods as required by the applicable ambient criteria for each modeled pollutant.



### 4.2.3 Chemical Transformations
Per Section 6.2.3 of the Guideline, ENVIRON assumed that 75 percent of the emitted NO X 

### is
converted to NO 2



### .



### 4.3 Elevation Data and Receptor Network
Terrain elevations for receptors and emission sources were prepared using 1/3 rd 

### arc-second National Elevation Dataset (NED) data developed by the United States Geological Survey (USGS), and available on the internet fr om the USGS Seamless Data Server (http://seamless.usgs.gov/index.php). These data have a horizontal spatial resolution of approximately 10 meters (m). Terrain heights surrounding the facility indicate that some of the receptors used in the simulations were located in intermediate or complex terrain (above stack or plume height). The 10-kilometer (km) square simulation domain that was used to assess near-field impacts is shown in Figure 2-2.

Receptors were spaced 500 m apart covering the simulation domain, with 200-m, 50-m, and 25- m spacing receptors grids covering 5-km, 2.5-km, and 1.25-km nested square areas centered on the facility, respectively. Receptors were also located at 25-m intervals along the facility property boundary. The final receptor locations are shown in Figure 4-1.March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

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### 4.4 Meteorological Data
ENVIRON has conducted a survey of available meteorological data for use in the simulations. A representative data set was prepared using a combination of surface data from meteorological station located at the nearby Redding Municipal Airport, supplemented by National Weather Service (NWS) upper air sounding data from Medford, Oregon.

According to the Guideline, five years of representative meteorological data are considered adequate for dispersion modeling applications. Hourly wind speed, wind direction, temperature, ceiling height, and cloud cover data collected from January 1, 2004 until December 31, 2008 at Redding Municipal Airport were extracted from the National Climatic Data Center’s (NCDC’s) Integrated Surface Hourly Weather Observations (ISHWO). The airport is located approximately 4.5 kilometers (2.8 miles) north-northwest of the facility. A wind rose describing the wind speed and wind direction data recorded at the Redding Municipal Airport meteorological monitoring station over the entire five-year dataset is shown in Figure 4-2. The wind rose shows that the winds are generally bimodal, with winds generally coming from the north and south, following the broad Sacramento River valley. Upper air radiosonde data for the same period were obtained for the monitoring station at Medford, Oregon, approximately 215 kilometers (134 miles) north of the facility.

The meteorological data were processed using the AERMOD meteorological preprocessor, AERMET (Version 06341). AERMET was used to check parameter ranges, identify missing data, and calculate boundary layer parameters for use by AERMOD. The program replaces missing or out-of-range data with missing value flags, and AERMOD treats these periods as calms. Data recovery across the 5-year surface meteorology dataset was found to be greater than 90 percent for all variables.

Surface parameters including the surface roughness length, albedo, and Bowen ratio were determined for the area surrounding the Redding Municipal Airport meteorological tower using the AERMET preprocessor, AERSURFACE (Version 08009), and the USGS 1992 National Land Cover (NLCD92) land-use data set. 3 

### The NLCD92 data set used in the analysis has 30 m data point spacing and 21 land-use categories. Seasonal surface parameters were determined using AERSURFACE according to USEPA’s guidance. 4



### 4.5 Emission Source Release Parameters
Figure 4-3 shows the proposed location of the cogeneration unit stack, as well as significant structures that could potentially influence emissions from the stack. Table 4-1 summarizes the release parameters that were used to represent the cogeneration unit stack and the cooling
towers in the simulations.

3 The USGS NLCD92 data set is described and can be accessed at http://landcover.usgs. gov/natllandcover.php

. 4 The AERMOD Implementation Guide (USEPA, 2008) and the AERSURFACE User’s Guide (EPA-454/B-08-001,

January 2008).Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

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### In addition to the release parameters discussed in the previous section, the building dimensions and facility configuration were provided to AERMOD to assess potential plume downwash effects. Wind-direction-specific building profiles were prepared for the modeling using the USEPA’s Building Profile Input Program for the PRIME algorithm (BPIP PRIME). The facility layout and building elevations provided by SPI were used to prepare data for BPIP PRIME, which provides the necessary input data for AERMOD. Figure 4-3 shows the configuration of significant structures, including those of the adjacent lumber manufacturing facility, that were used to develop the BPIP PRIME input files, and Table 4-2 presents the heights of the significant structures included in the simulations.

Based on the site layout shown in Figure 4-3 and the structure heights in Table 4-2, the most significant structure affecting the cogeneration unit stack in the simulations was the boiler building, which is 115 feet (ft), or 32 m, high. For the boiler stack, good engineering practice (GEP) stacks at the same location would have to exceed the maximum creditable GEP height (213 ft or 65 m) to ensure protection against downwash. Therefore, all necessary information provided by BPIP PRIME was included in the simu lations to reflect downwash effects from nearby structures on the boiler stack. A similar analysis indicated that emissions from the cooling towers would also be subject to downwash effects, and the appropriate BPIP PRIME output was included in the simulations for that source as well.



### 4.6 Analysis Results
To evaluate the potential ambient air pollutant concentrations (i.e., impacts on air quality) attributable to the project, the emission rates and source release parameters described in the previous sections were applied in the dispersion modeling analysis. A preliminary analysis included only the emission increase associated with the proposed cogeneration unit and cooling tower, without accounting for the decreased emissions from the existing boiler. Table 4-3 summarizes the predicted maximum concentrations and compares them to both the applicable monitoring de minimis concentrations and the Significant Impact Levels (SILs) established in USEPA’s New Source Review Workshop Manual (October 1990). The SILs represent incremental, project-specific impact levels that USEPA generally accepts as insignificant with respect to maintaining compliance with the NAAQS. As shown in Table 4-3, none of the predicted concentrations exceeded the SILs or the monitoring de minimis concentrations. Figures 4-4 through 4-11 show the spatial variations in the maximum predicted criteria pollutant concentrations, averaged over periods consistent with the applicable ambient standards. The maximum predicted receptor and concentration are also shown.

The State of California has not established screening concentrations analogous to the SILs that can be used to determine compliance with the CAAQS without combining the proposed project with background concentrations. Table 4-4 presents predicted criteria pollutant concentrations, combines them with background concentrations and compares the totals with the applicable
CAAQS.March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

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### 4.7 Startup Analysis
AERMOD was applied using the methodology described in the previous sections to demonstrate that the proposed CO startup emission rate will comply with both the one- and eight-hour average ambient CO standards.

Both the forced-air and the induced-draft fans in the boiler will operate throughout the startup process, but the flow will be controlled by dampers to approximately 30 percent of normal operation flow (approximately 62,000 actual cubic feet per minute). This resulted in an exhaust velocity of 20.5 feet per second. The exhaust temperature during startup will be about 250 oF, approximately 150 oF cooler than normal operation. These conditions were assumed to be constant throughout the startup process regardless of the fuel mix used after the first two hours of startup.

Assuming an hourly average CO emission rate during startup of 400 lb/hr, the maximum predicted 1-hour and 8-hour average concentrations were 249 and 182 μg/m 3 

### , respectively. To determine compliance with the NAAQS, these results were combined with background values based on the most recent maximum monitored 1-hour and 8-hour average concentrations from the CO monitor in Chico, California 5 

### The maximum 1-hour and 8-hour average concentrations were 3.1 ppm (approximately 3,550 μg/m 3 

### ) and 2.4 ppm (approximately 2,750 μg/m 3 

### ), respectively. Because the Anderson area is likely to be less urban than the Chico area, these background values most likely overstate the actual CO concentrations near the facility.

Using the conservative background concentrations described above, the total predicted maximum concentrations (boiler startup emissions plus background) were a 1-hour average of 3,799 μg/m 3 

### , and an 8-hour average of 2,932 μg/m 3 

### . These concentrations are less than the 1- hour and 8-hour average CO CAAQS of 23,000 and 10,000 μg/m 3 

### , respectively (the corresponding NAAQS are 40,000 and 10,000 μg/m 3 

### ). Based on this analysis, the proposed hourly CO emission startup limit of 400 lb/hr will not cause of contribute to exceedances of the
NAAQS or CAAQS.



### 4.8 Secondary Impact Analysis

4.8.1 Class II Area Growth
Construction of the proposed cogeneration unit would span between 14 and 18 months. Laydown and temporary worker parking areas will be located within the existing facility property boundary. During construction, approximately 40 temporary works would be added, and local demand for skilled crafts people would increase slightly. However, this demand would be temporary (18 months at most), and mitigated by the use of existing permanent employees where possible (there is an existing on-site fabrication shop). The temporary increases in

5 Maximum CO concentrations recorded in 2008 by the CO monitor located at 468 M anzantia Ave. in Chico,

California; data obtained from EPA’s AirData website (http:// www. epa.gov/aqspubl1/annual_summary.html)Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

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### vehicle miles traveled and vehicular emissions associated with temporary workers would be insignificant. Once the cogeneration unit is oper ational, SPI expects to employ approximately eight additional workers. SPI does not expect the new cogeneration unit to cause significant population growth in the area nor significant secondary air quality impacts as a result of that growth.



### 4.8.2 Class II Visibility
On a large spatial scale, visibility is typically evaluated as “regional haze” and is addressed as part of the Class I air quality related values (Section 5). On a local scale, “visibility” is usually evaluated by considering perceptibility of a plume from a stack or cooling tower.

The new biomass-fired cogeneration unit is larger, and will emit air pollutants in larger quantities than the existing boiler. However, the new unit will be of a more modern design than the existing unit, and, as a result, the drift rate from the proposed cooling tower is expected to be significantly more than that of the existing cooling tower.



### 4.8.3 Soils and Vegetation
Air quality permitting regulations require proponents of major modifications to existing major sources to provide an evaluation of potential impacts to air quality related values. These include impacts to visibility, soils and vegetation. In virtually all cases, the impact analysis for soils and vegetation has focused on impacts to Class I areas. The focus on Class I areas occurs because these areas often include sensitive environments, such as alpine lakes and streams, high-elevation vegetation, and sensit ive habitat for threatened or endangered species. Section 5 addresses impacts to soils and vegetation in Class I areas. The potential for such impacts were judged to be unlikely based on screening criteria employed by Federal Land Managers.

For Class II areas, the concern for soil and vegetation impacts is different from Class I areas. Generally, it is not a sensitive habitat that is of concern, but rather the economic well-being of the soils and vegetation for the area. Impacts to agriculture or forestry are the major concerns. There have been instances elsewhere in the U.S. where high levels of sulfur emissions from coal fired power plants, or smelters have c aused localized impacts to vegetation and soils near the facility. In fact, the NAAQS were established to protect the public health and welfare, and secondary standards were identified specifically to protect ecological properties such as soils and vegetation.

The Class II air quality assessment results (Section 4.6) indicate that the maximum ambient impacts due to the proposed project will be less than the applicable SILs for both NO 2 

### and SO 2



### . Because ambient concentrations attributable to the project would be so low, deposition of nitrogen and sulfur compounds would also be very low.

Typically, to alter the pH of soil, quantities of nitrogen or sulfur on the order of a ton per acre per year would be required; in other words, a considerable amount of nitrogen or sulfur is requiredMarch 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 17 

### to have a significant effect on the pH of the soil. Based on deposition modeling conducted previously for a similar emission unit at this same location, nitrogen and sulfur deposition rates in the vicinity of the facility are typically on t he order of ten pounds per acre per year. This very low deposition rate suggests that there would be no acid deposition impacts to commercial
farms in the area.Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

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# 5 Class I Air Quality Impacts and Air Quality Related Values Analyses

PSD guidance requires analysis of potential impacts to air quality and air quality related values (AQRVs) of concern (i.e., visibility, soil, flora, fauna, and aquatic resources) in Federal Class I areas within 100 km (62.1 miles) of the proposed site from pollutants emitted by the project subject to PSD review. However, for most applications the Federal Land Managers (FLMs) request analyses of AQRV impacts for additional Class I areas within 200 km (124 miles) of the

site.

The locations of the proposed project and all nearby Class I areas are shown in Figure 5-1. The Yolla Bolly – Middle Eel Wilderness Area is the Class I area nearest to the Anderson facility, approximately 57 km (35 miles) to the southeast. As shown in Table 5-1, there are four Class I areas within 100 km, and an additional five Class I areas within 200 km.

In June 2008, the Federal Land Managers’ Air Quality Related Values Work Group (FLAG) issued a draft revision of the Phase I report that provides guidance and recommendations for how AQRV analyses should be conducted. The draft report describes an initial screening criteria (often referred to as a “Q/D” analysis) that would exempt a source from AQRV impact review based on annual emission rates and distance from a Class I area. Proposed projects
with total emission increases of NO X 

### , SO 2 

### , PM 10 

### , and sulfuric acid mist (H 2 

### SO 4 

### ), in tons per year (the “Q” in Q/D), which, when divided by the distance to each Class I area, in kilometers (the “D” in Q/D), is 10 or less, would be exempt from AQRV analysis. Although the document containing this screening method is a draft, FLMs have been allowing sources to use it to justify not presenting an AQRV analysis in permit applications.

An AQRV screening analysis was developed for the proposed project using the boiler’s expected potential future emissions (Potential to Emit – or “PTE”). As prescribed by the screening methodology, the maximum hourly emission rates for each pollutant required by the screening analysis were converted to tons per year (by multiplying by 8,760 hr/yr and dividing by 2,000 lb/ton) and summed. The closest Class I area is the Yolla Bolly – Middle Eel Wilderness Area, approximately 57 km from SPI’s Anderson facility. Table 5-2 summarizes the Q/D analysis; the result is a value of approximately 6, which is less than the FLM-prescribed threshold of 10. As a result, no AQRV analysis is presented. AQRV analysis reviewers at the National Park Service (NPS) and U.S. Forest Service (USFS) were provided with a preliminary Q/D analysis in advance of this permit application, and documentation of their concurrence are presented in Appendix D.

The AQRV screening method outlined above does not have any bearing on the PSD program requirement to assess compliance with the Class I increment for pollutants that increase by more than the PSD significant emission rates (SERs). As shown in Table 2-2, NO X 

### and PM 10 

### exceed the PSD SERs. (The maximum annual CO emission rate also exceeds the PSD SER, but no PSD increments have been established for CO.) However, based on the lack of impacts predicted by the Class I analysis presented in the 2007 permit application in addition to theSierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

20 29-23586A 

### current Q/D analysis, USEPA has agreed that an updated and revised Class I PSD increment analysis is not necessary in this case, and none is presented.March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

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## TablesSierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

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### (This page intentionally left blank.)March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

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### Table 2-1 Proposed Cogeneration Unit Emissions

Emission Rate 2

Pollutant 1 Emission Factor 1 (lb/MMBtu) (lb/hr) (TPY)

NO
x 0.13 60.8 242

CO 0.35 164 652

SO 2 0.005 2.34 9.32

PM 10 0.02 9.36 37.3

VOC/ROC 0.017 7.96 31.7

Sulfuric Acid 0.0021 0.986 3.93

Lead 1.19E-05 0.00559 0.0222

1 NO
x , CO, and PM 10 emission factors are based on BACT and vendor guarantees. The SO 2 emission
factor is based on a source test conducted on the exis ting boiler at the facility. The VOC/ROG emission factor is based on a vendor guarantee. The sulfuric acid (H 2 SO 4 ) emission factor is based on the assumption that sulfate comprises 10.038 percent of PM 10 emissions, which was obtained from USEPA’s SPECIATE 3.2 Profile # 12709 for Hogged Fuel Boiler/Stok er Boiler. The lead emission factor is based on source test data used to develop the emission factor is EPA’s AP-42, Section 1.6.
2 Pound per hour emission rate is based on a maxi mum 1-hour average heat input of 468.0 MMBtu/hr, and the tons per year emission rates is based on an annual average heat input rate of 425.4 MMBtu/hr and continuous operation (8,760 hours per year).Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

24 29-23586A 

### Table 2-2 Project Criteria Pollutant Emissions Increase

Annual Emission Rate 2 (TPY)

Pollutant 1 Cogen CT Total PSD SER 3 (TPY) Over SER?

NO
x 242 -- 242 40 Yes

CO 652 -- 652 100 Yes

SO 2 9.32 -- 9.32 40 No

PM 10 /PM 2.5 37.3 1.10 38.4 15/10 Yes/Yes

VOC/ROG 31.7 -- 31.7 40 No

Sulfuric Acid 3.93 -- 3.93 7 No

Lead 0.0222 -- 0.0222 0.6 No

1 NO
x , CO, PM 10 , and VOC/ROG emission factors are based on BACT and/or vendor guarantees, while
the SO 2 emission factor is based on a source test conduc ted on the existing boiler at the facility. The sulfuric acid (H 2 SO 4 ) emission factor is based on the assumpti on that sulfate comprises 10.038 percent
of PM 10 emissions, which was obtained from USEPA’s SPECIATE 3.2 Profile # 12709 for Hogged Fuel
Boiler/Stoker Boiler.
2 Cogeneration unit annual emission rates based on maximum annual average hourly heat input (425.4 MMBtu/hr). Total proposed = Cogen (cogeneration unit) + CT (cooling tower).March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 25 

### Table 2-3 Project Emission Rates and BACT Thresholds

Hourly Emission Rate 2 (lb/hr) 24-Hr Emission Rate 3 (lb/day)

Pollutant 1 Cogen CT Total Cogen CT Total AQMD BACT
Thresh. 4 (lb/day) Over BACT
Thresh?

NO
x 60.8 -- 60.8 1,394 -- 1,394 25.0 Yes

CO 164 -- 164 3,752 -- 3,752 500.0 Yes

SO 2 7.49 -- 7.49 172 -- 172 80.0 Yes

PM/PM 10 9.36 0.251 9.61 214 6.02 220 80.0 Yes

VOC/ROG 6.08 -- 6.08 139 -- 139 25.0 Yes

Sulfuric Acid 0.986 -- 0.986 22.6 -- 22.6 35.0 No

Lead 0.00559 -- 0.00559 0.128 -- 0.128 3.2 No

Beryllium 0.000726 -- 0.000726 0.0166 -- 0.0166 0.002 Yes

Mercury 0.000195 -- 0.000195 0.00446 -- 0.00446 0.5 No

Vinyl Chloride 0.00861 -- 0.00861 0.197 -- 0.197 5.0 No

1 NO
x , CO, PM 10 , and VOC/ROG emission factors are based on vendor guarantees, while the SO 2 emission factor is based on a source test conducted on the existing boiler at the facility. The sulfuric acid (H 2 SO 4 ) emission factor is based on the assumption that sulfate comprises 10.038 percent of PM 10 emissions, which was obtained from USEPA’s SPECIATE 3.2 Profile # 12709 for Hogged Fuel Boiler/Stoker Boiler. Lead, bery llium, mercury, and vinyl chloride emission factors were based on the source test data used to develop the em ission factors in AP-42 Section 1.6.
2 Cogeneration unit hourly emission rates are based on a maximum hourly heat input of 468.0 MMBtu/hr
3 Cogeneration unit hourly emission rates are based on a maximum 24-hour average heat input of 446.7
MMBtu/hr
4 From Sierra County AQMD Rule 2:1, Part 301.Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

26 29-23586A 

### Table 2-4 Cogeneration Unit Toxic Air Contaminant Emission Rates

Emission Rate Compound CAS No. Emission Factor (lb/MMBtu) (lb/hr) 1 (lb/day) 2 (lb/yr) 3

Acenaphthene 83-32-9 7.25E-09 0.00000339 0.0000777 0.027

Acenaphthylene 208-96-8 1. 54E-06 0.000719 0.0165 5.73

Acetaldehyde 75-07-0 1.99E-04 0.093 2.13 741

Acetone 67-64-1 1.62E-04 0.0758 1.74 604

Acetophenone 98-86-2 3.23E-09 0.00000151 0.0000346 0.012

Acrolein 107-02-8 3.15E-05 0.0148 0.338 118

Ammonia 4 7664-41-7 2.02E-02 9.46 217 75,300

Anthracene 120-12-7 4.95E-08 0.0000232 0.000531 0.185

Antimony 7440-36-0 4.61E-07 0.000215 0.00494 1.72

Arsenic 7440-38-2 4.94E-07 0.000231 0.0053 1.84

Barium 7440-39-3 1.52E-04 0.0711 1.63 567

Benzaldehyde 100-52-7 8. 45E-07 0.000395 0.00906 3.15

Benzene 71-43-2 8.61E-04 0.403 9.23 3,210

Benzo(a)anthracene 56-55-3 2.52E-09 0.00000118 0.000027 0.00938

Benzo(a)pyrene 50-32-8 3.27E-09 0.00000153 0.0000351 0.0122

Benzo(b)fluoranthene 205-99-2 2.35E-09 0.0000011 0.0000252 0.00876

Benzo(e)pyrene 192-97-2 2.59E-09 0.00000121 0.0000278 0.00966

Benzo(g,h,i)perylene 191-24- 2 4.62E-09 0.00000216 0.0000496 0.0172

Benzo(j)fluoranthene 205-82-3 1.56E-07 0.0000728 0.00167 0.58

Benzo(k)fluoranthene 207-08-9 2.38E-09 0.00000111 0.0000255 0.00888

Benzoic Acid 65-85-0 4.68E-08 0.0000219 0.000502 0.174

Beryllium 7440-41-7 1.55E-06 0.000726 0.0166 5.78

Bis(2-ethylhexyl)phthalate 117-81-7 4.65E-08 0.0000218 0.000499 0.173

Bromomethane 74-83-9 2.80E-05 0.0131 0.3 104

2-Butanone (MEK) 78-93-3 5.39E-06 0.00252 0.0578 20.1

Cadmium 7440-43-9 2.59E-06 0.00121 0.0278 9.65

Carbazole 86-74-8 1.79E-06 0.000838 0.0192 6.67

Carbon Dioxide (CO 2 ) 5 37210-16-5 2.07E+02 96800 2,220,000 771,000,000

Carbon Tetrachloride 56-23-5 4.54E-05 0.0212 0.487 169

Chlorine 7782-50-5 7.92E-04 0.371 8.49 2,950March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 27 Emission Rate Compound CAS No. Emission Factor (lb/MMBtu) (lb/hr) 1 (lb/day) 2 (lb/yr) 3

Chlorobenzene 108-90-7 3.32E-05 0.0155 0.356 124

Chloroform 67-66-3 2.75E-05 0.0129 0.295 103

Chloromethane 74-87-3 2.31E-05 0.0108 0.248 86.1

2-Chloronaphthalene 91-58-7 2.41E-09 0.00000113 0.0000258 0.00896

2-Chlorophenol 108-43-0 3.37E-08 0.0000158 0.000362 0.126

Chromium, hexavalent 4 18540-29-9 1.75E-07 0.000082 0.00188 0.653

Chromium, trivalent 7440-47- 3 1.24E-06 0.000582 0.0133 4.63

Chrysene 218-01-9 2.75E-09 0.00000129 0.0000295 0.0103

Cobalt 7440-48-4 8.93E-06 0.00418 0.0958 33.3

Copper 7440-50-8 4.11E-06 0.00192 0.044 15.3

Crotonaldehyde 4170-30-3 9. 91E-06 0.00464 0.106 36.9

Decachlorobiphenyl 2051-24-3 2.65E-10 0.000000124 0.00000284 0.000988

Dibenzo(a,h)anthracene 53-70- 3 2.35E-09 0.0000011 0.0000252 0.00875

1,2-Dibromoethene 106-93-4 5.48E-05 0.0256 0.587 204

Dichlorobiphenyl 2050-68-2 3.79E-10 0.000000177 0.00000406 0.00141

1,2-Dichloroethane 107-06-2 2.92E-05 0.0137 0.313 109

Dichloromethane 75-09-2 2.87E-04 0.134 3.08 1,070

1,2-Dichloropropane 78-87-5 3.33E-05 0.0156 0.357 124

2,4-Dinitrophenol 51-28-5 9.33E-08 0.0000436 0.001 0.348

Ethylbenzene 100-41-4 3.13E-05 0.0146 0.336 117

Fluoranthene 206-44-0 5.17E-07 0.000242 0.00554 1.93

Fluorene 86-73-7 5.31E-08 0.0000248 0.000569 0.198

Formaldehyde 50-00-0 1.96E-03 0.917 21 7,300

Heptachlorobiphenyl 28655-71-2 6. 57E-11 3.07E-08 0.000000704 0.000245

Hexachlorobiphenyl 26601-64-9 2.89E-10 0.000000135 0.0000031 0.00108

HpCDD-Total 37871-00-4 3.09E-11 1.44E-08 0.000000331 0.000115

HpCDF-Total 38998-75-3 6.40E- 12 2.99E-09 6.86E-08 0.0000238

HxCDD-Total 34465-46-8 8.55E-11 0.00000004 0.000000917 0.000319

HxCDF-Total 55684-94-1 1.53E -11 7.18E-09 0.000000164 0.0000571

Hexanal 66-25-1 6.96E-06 0.00326 0.0746 25.9

Hydrogen chloride 7647-01-0 3.52E-03 1.65 37.8 13,100

Indeno(1,2,3-c,d)pyrene 193-39- 5 2.37E-09 0.00000111 0.0000255 0.00885Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

28 29-23586A Emission Rate Compound CAS No. Emission Factor (lb/MMBtu) (lb/hr) 1 (lb/day) 2 (lb/yr) 3

Iron 7439-89-6 9.93E-04 0.465 10.6 3,700

Isobutyraldehyde 78-84-2 1. 15E-05 0.00538 0.123 42.9

Lead 7439-92-1 1.19E-05 0.00559 0.128 44.5

Manganese 7439-96-5 1.16E-04 0.0541 1.24 431

Mercury 7439-97-6 4.16E-07 0.000195 0.00446 1.55

Methane 5 74-82-8 7.05E-02 33 756 263,000

Methanol 6 67-56-1 8.30E-04 0.388 8.9 3,090

2-Methylnaphthalene 91-57-6 2.75E-07 0.000129 0.00295 1.02

Molybdenum 7439-98-7 1.13E-06 0.000526 0.0121 4.19

Monochlorobiphenyl 2051-60-7 2.18E-10 0.000000102 0.00000234 0.000812

Naphthalene 91-20-3 8.51E-05 0.0398 0.913 317

Nickel 7440-02-0 2.84E-06 0.00133 0.0304 10.6

Nitric Oxide (NO) 7 10102-43-9 1.30E-01 60.8 1390 484,000

2-Nitrophenol 88-75-5 1.06E-07 0.0000497 0.00114 0.396

4-Nitrophenol 100-02-7 1.71E-07 0.0000801 0.00184 0.638

Nitrous Oxide (N 2 O) 5 10024-97-2 9.26E-03 4.33 99.3 34,500

OCDD 3268-87-9 2.34E-10 0.000000109 0.00000251 0.000871

OCDF 39001-02-0 1.43E-11 6.67E-09 0.000000153 0.0000531

PeCDD-Total 36088-22-9 1.72E-10 8.03E-08 0.00000184 0.000639

PeCDF-Total 30402-15-4 4.19E -11 1.96E-08 0.000000449 0.000156

Pentachlorobiphenyl 25429-29-2 6.49E-10 0.000000304 0.00000696 0.00242

Pentachlorophenol 87-86-5 2.27E-08 0.0000106 0.000243 0.0846

Perylene 198-55-0 5.18E-10 0.000000242 0.00000555 0.00193

Phenanthrene 86-01-8 1.69E-06 0.000793 0.0182 6.32

Phenol 108-95-2 1.25E-05 0.00587 0.134 46.7

Phosphorus 7723-14-0 3.54E-05 0.0166 0.38 132

Potassium 7440-09-7 3.88E-02 18.2 416 145,000

Propionaldehyde 123-38-6 3.15E-06 0.00147 0.0338 11.7

Pyrene 129-00-0 2.99E-07 0.00014 0.00321 1.11

Selenium 7782-49-2 3.38E-06 0.00158 0.0363 12.6

Sodium 7440-23-5 3.63E-04 0.17 3.89 1,350

Strontium 7440-24-6 1.01E-05 0.00471 0.108 37.5March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 29 Emission Rate Compound CAS No. Emission Factor (lb/MMBtu) (lb/hr) 1 (lb/day) 2 (lb/yr) 3

Sulfuric Acid 7 7664-93-9 2.11E-03 0.986 22.6 7,860

TCDD-Total 1746-01-6 2.05E-10 9.57E-08 0.00000219 0.000762

TCDF-Total 30402-14-3 1. 63E-10 0.000000076 0.00000174 0.000606

Tetrachlorobiphenyl 26914-33-0 1.60E-09 0.000000749 0.0000172 0.00596

Tetrachloroethene 127-18-4 3.82E-05 0.0179 0.41 142

Tin 7440-31-5 3.91E-05 0.0183 0.419 146

Titanium 7440-32-6 2.01E-05 0.00941 0.215 74.9

o-Tolualdehyde 529-20-4 7.15E-06 0.00335 0.0767 26.6

p-Tolualdehyde 104-87-0 1.13E-05 0.00529 0.121 42.1

Toluene 108-88-3 2.13E-05 0.00994 0.228 79.2

Trichlorobiphenyl 15862-07-4 1.78E-09 0.000000833 0.0000191 0.00663

1,1,1-Trichloroethane 71-55- 6 3.07E-05 0.0144 0.329 115

Trichloroethene 79-01-6 3.03E-05 0.0142 0.325 113

Trichlorofluoromethane 75- 69-4 4.05E-05 0.019 0.434 151

2,4,6-Trichlorophenol 88-06- 2 1.14E-08 0.00000531 0.000122 0.0423

Vanadium 1314-62-1 5.94E-07 0.000278 0.00637 2.21

Vinyl Chloride 75-01-4 1.84E-05 0.00861 0.197 68.6

Xylene 1330-20-7 2.45E-05 0.0115 0.262 91.2

Yttrium 7440-65-5 3.01E-07 0.000141 0.00323 1.12

Zinc 7440-66-6 1.74E-04 0.0814 1.86 648
1 Based on a maximum hourly heat input rate of 468.0 MMBtu/hr.
2 Based on a maximum daily average heat input rate of 446.7 MMBtu/hr and continuous 24-hour operation.
3 Based on an annual average heat input rate of 425. 4 MMBtu/hr and 8,760 hours of operation per year.
4 Based on 20 ppm exhaust concentration

5 CO 2 , CH 4 , and N 2 O emission factors taken from 40 CFR 98, Subpart C, Table C-1.

6 Methanol emission factor for wood-fired boilers from NCASI Technical Bulletin No. 858 (February 2003).
7 100 percent of NO X was assumed be NO, which is cons ervative because 75 percent of NO X was assumed to be converted to NO 2

.Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

30 29-23586A 

### Table 3-1
Hazardous Air Pollutant Emission Rates

Compound CAS No. Emission
Rate 1 Compound CAS No. Emission Rate 1

Acetaldehyde 2 75-07-0 9.05 Formaldehyde 2 50-00-0 3.857

Acetophenone 98-86-2 6.01E-06 Hydrogen chloride 7647-01-0 6.57

Acrolein 2 107-02-8 0.178 Lead 7439-92-1 0.0222

Antimony 7440-36-0 0.000858 Manganese 7439-96-5 0.215

Arsenic 7440-38-2 0.000920 Mercury 7439-97-6 0.000775

Benzene 71-43-2 1.60 Methanol 2 67-56-1 9.20

Beryllium 7440-41-7 0.00289 Naphthalene 91-20-3 0.159

Bis(2-ethylhexyl)phthalate 117- 81-7 8.66E-05 Nickel 7440-02-0 0.00529

Bromomethane 74-83-9 0.0522 4-Nitrophenol 100-02-7 0.000319

2-Butanone (MEK) 78-93-3 0.0100 P entachlorophenol 87-86-5 4.23E-05

Cadmium 7440-43-9 0.00483 Phenol 108-95-2 0.101

Carbon Tetrachloride 56-23-5 0.0846 Phosphorus 7723-14-0 0.0660

Chlorine 7782-50-5 1.48 Propionaldehyde 2 123-38-6 0.00587

Chlorobenzene 108-90-7 0.0619 Selenium 7782-49-2 0.00630

Chloroform 67-66-3 0.0513 TCDD-Total 1746-01-6 3.81E-07

Chloromethane 74-87-3 0.0430 Tetrachloroethene 127-18-4 0.0712

Chromium, trivalent 7440-47-3 0.00232 Toluene 108-88-3 0.0396

Cobalt 7440-48-4 0.0166 1,1,1-Trichloroethane 71-55-6 0.0573

1,2-Dibromoethene 106-93-4 0.102 Trichloroethene 79-01-6 0.0565

1,2-Dichloroethane 107-06-2 0.0544 2,4, 6-Trichlorophenol 88-06-2 2.11E-05

Dichloromethane 75-09-2 0.539 Vinyl Chloride 75-01-4 0.0343

1,2-Dichloropropane 78-87-5 0.0620 Xylene 1330-20-7 0.0456

2,4-Dinitrophenol 51-28-5 0.000174 Total HAPs 34.0

Ethylbenzene 100-41-4 0.0583 Maximum Ind. HAP 9.20
1 All emission rates in tons per year (tpy).
2 Cogeneration unit and lumber dry kiln emission rates combined.March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 31 

### Table 4-1 Point Source Release Parameters

Source Height (ft) Diameter (ft) Exit Velocity (ft/s) Temperature (°F)

Proposed Cogeneration Unit 115 8.0 68.4 400

Cooling Tower (each of 2 cells) 41 31.6 24.2 91Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

32 29-23586A 

### Table 4-2 Structure Heights

Height

Structure (feet) (meters)

Truck Shop 16 4.88

Equipment Shop 27 8.23

Fabrication Shop 43 13.11

Warehouse 32 9.75

Dry Shed 52 15.85

Planer 60 18.29

Kilns 24 7.32

Existing Cooling Tower 30 9.14

Diesel Fuel 16 4.88

Forestry Lab 29 8.84

Lumber Storage Shed 26 7.92

Existing Boiler 43 13.11

Sawmill 54 16.46

Chipper/Hog 29 8.84

Fuel House 52 15.85

Turbine 40 12.19

Proposed Cooling
Tower 30 9.14

Proposed Boiler 115 35.05

Proposed Economizer 50 15.24

ESP 50 15.24

Truck Shop 16 4.88March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 33 

### Table 4-3 Criteria Pollutant NAAQS Compliance Assessment

Pollutant Averaging
Period Maximum
Predicted 1 SIL 1,2 Over SIL? Monitoring
de
Minimis 1,3 Over de Minimis?

1-Hour 12.3 -- -- -- -- NO 2 4
Annual 0.906 1 No 14 No

1-Hour 86.3 2,000 No -- -- CO 8-Hour 63.0 500 No 575 No

24-Hour 1.43 5 No 10 No PM 10 Annual 0.213 1 No --

--

24-Hour 1.43 -- -- -- -- PM 2.5 5
Annual 0.213 -- -- -- --

3-Hour 2.04 25 No --

--

24-Hour 1.09 5 No 13 No SO 2

Annual 0.149 1 No --

-- 1 Concentrations are in micrograms per cubic meter (μg/m 3 )
2 SIL = Significant Impact Level, from USEPA’s Ne w Source Review Workshop Manual (October, 1990),
Table C-4.
3 Monitoring de Minimis concentrati ons from 40 CFR 52.21(i)(8)(i).

4 NO 2 was assumed to be 75 percent of the emitted NO X based on guidance in Section 6.2.3 of the USEPA’s Guideline on Air Quality Models (codified as Appendix W to 40 CFR Part 51). The 1-hour average NO 2 concentration shown is the maximum 8 th -highest daily 1-hour maximum concentration averaged across the five modeled years. SILs and monitoring de minimis concentrations have not yet
been established for NO 2 . A NAAQS compliance assessment was performed by combining the modeled
NO 2 concentration with a background concentrati on. Because 3-year average of the 98 th percentile of
the annual distribution of the daily maximum 1-hour average NO 2 concentrations are not yet available for recent ambient monitoring data to use as a ba ckground concentration, the maximum 1-hour average NO 2 concentration from the monitor at 468 Manzanita Av e in Chico, California was used as a background, which is a conservative approach. Adding the modeled concentration (12.3 μ g/m 3 ) to the background (80.9 μ g/m 3 ) gives a total concentration of 93.2 μ g/m 3 , which is less than the applicable NAAQS (188 μ g/m 3 ).
5 SILs and monitoring de minimis concentrations have not yet been established for PM 2.5 . A NAAQS compliance assessment was performed by combining the modeled PM 2.5 concentrations (which assume
that all PM 10 is PM 2.5 ) with the most recent maximum concentrati ons from the monitor on the roof of the Redding Department of Health (24-hour average – 20.2 μ g/m 3 , and annual average – 5.49 μ g/m 3 ), gives
total concentrations of 21.7 μ g/m 3 (24-hour average) and 5.73 μ g/m 3 (annual average), which are less than the applicable NAAQS (24-hour average – 35 μ g/m 3 , and annual average – 15 μ g/m 3 ).Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

34 29-23586A 

### Table 4-4 Criteria Pollutant CAAQS Compliance Assessment

Pollutant Averaging
Period Maximum
Predicted 1 Background

2 Total 3 CAAQS Over CAAQS?

1-Hour 14.0 80.9 94.9 339 No NO 2 4
Annual 0.906 15.0 15.1 57 No

1-Hour 86.3 3,550 3,636 23,000 No CO 8-Hour 63.0 2,750 2,813 10,000 No

24-Hour 1.43 37.0 38.4 50 No PM 10 Annual 0.213 18.2 18.4 20 No

PM 2.5 5 Annual 0.213 5.49 5.70 12 No

1-Hour 2.30 7.85 10.1 655 No SO 2 24-Hour 1.09 5.23 6.32 105 No
1 Concentrations are in micrograms per cubic meter (μg/m 3 )
2 Background concentrations are the most recent ma ximum monitored concentrations (with exceptional event data removed, where applicable) fr om the following stations and years:

NO 2 & CO: Chico – Manzanita Ave; 2008

PM 10 : Anderson – North Street; 2009

PM 2.5 : Redding – Health Department Roof; 2009

SO 2 : North Highlands – Blackfoot Way; 2009
Monitoring data are from EPA’s AirData webs ite (http://www.epa.gov/aqspubl 1/annual_summary.html)
3 Total = Maximum Predicted + Background

4 NO 2 was assumed to be 75 percent of the emitted NO X based on guidance in Section 6.2.3 of the USEPA’s Guideline on Air Quality Models (codified as Appendix W to 40 CFR Part 51).

5 All PM 10 was assumed to be PM 2.5March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 35 

### Table 5-1 Distances from Proposed Project to Nearby Class I Areas

Class I Area Distance (km)

Caribou Wilderness Area 89

Lassen Volcanic National Park 64

Lava Beds National Monument 148

Marble Mountain Wilderness Area 116

Redwood National Park 147

South Warner Wilderness Area 192

Thousand Lakes Wilderness Area 62

Yolla Bolly-Middle Eel Wilderness Area 57



### Table 5-2 Summary of Q/D Analysis

Parameter Value 1 Units

Project NO X Emission Increase 254 tpy

Project SO 2 Emission Increase 9.78 tpy

Project PM 10 Emission Increase 39.1 tpy

Project H 2 SO 4 Emission Increase 4.12 tpy

Total Project Emission Increase 307 tpy

Distance to Closest Class I Area 57 km

Q/D 5.39 tpy/km

Q/D Threshold of Concern 10 tpy/km

1 Emission rate increases are based on maximum 24-hour average emission rates.Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

36 29-23586A 

### (This page intentionally left blank.)March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 37 

## FiguresSierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

38 29-23586A 

### (This page intentionally left blank.)March 2010Biomass-Fired Cogeneration ProjectSierra Pacific Industries – AndersonATC/PSD Permit Application29-23586A39Figure 2-1. Project Schematic Flow DiagramSierra Pacific Industries – AndersonATC/PSD Permit ApplicationMarch 2010Biomass-Fired Cogeneration Project4029-23586A(This page intentionally left blank.)March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 41 

### Figure 2-2. Vicinity of Facility and Modeling Domain S

a

c

r a

m

e

n

t o

R

i v

e

r 

## Anderson

Cottonwood Redding Municipal

Airport Redding

Modeling

Domain SPI-Anderson

012345 

## MilesSierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

42 29-23586A 

### Figure 4-1. Final Receptor Locations 552000 553000 554000 555000 556000 557000 558000 559000 560000 561000 562000 563000

UTM Eastin g ( meters ) 4475000 4476000 4477000 4478000 4479000 4480000 4481000 4482000 4483000 4484000 4485000 4486000UTM Northing (meters)March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 43 

### Figure 4-2. Wind Rose, Redding Munici pal Airport, Jan. 2004 to Dec. 2008Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

44 29-23586A 

### (This page intentionally left blank.)March 2010Biomass-Fired Cogeneration ProjectSierra Pacific Industries – AndersonATC/PSD Permit Application29-23586A45Figure 4-3. Source and Significant Structure Locations1234567891011121314151617181920211 Truck Shop2 Equipment Shop3 Fab Shop4 Warehouse5 Dry Shed6 Planer7 N Kilns8 Old Cooling Tower9 Diesel Fuel10 Forestry Lab11 Lumber Storage Shed12 Old Boiler & Stack13 Sawmill14 Chipper/Hog15 S Kilns16 Fuel House17 Turbine18 New Cooling Tower19 New Boiler20 Economizer21 ESP & New Boiler Stack0 250 500 750 1000FeetProperty BoundarySierra Pacific Industries – AndersonATC/PSD Permit ApplicationMarch 2010Biomass-Fired Cogeneration Project4629-23586A(This page intentionally left blank.)March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 47 

### Figure 4-4. Maximum Predicted 1- Hour Average CO Concentrations Concentration isopleths in micrograms per cubic meter (μg/m 3 

### ) 553000 554000 555000 556000 557000 558000 559000 560000 561000 562000
UTM Easting (meters) 4476000 4477000 4478000 4479000 4480000 4481000 4482000 4483000 4484000 4485000UTM Northing (meters)



### = maximum predicted concentration (86.3 μg/m3)Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

48 29-23586A 

### Figure 4-5. Maximum Predicted 8- Hour Average CO Concentrations Concentration isopleths in micrograms per cubic meter (μg/m 3 

### ) 553000 554000 555000 556000 557000 558000 559000 560000 561000 562000
UTM Easting (meters) 4476000 4477000 4478000 4479000 4480000 4481000 4482000 4483000 4484000 4485000UTM Northing (meters)



### = maximum predicted concentration (63.0 μg/m3)March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 49 

### Figure 4-6. Maximum Predicted 1-Hour Average SO 2 

### Concentrations Concentration isopleths in micrograms per cubic meter (μg/m 3 

### ) 553000 554000 555000 556000 557000 558000 559000 560000 561000 562000
UTM Easting (meters) 4476000 4477000 4478000 4479000 4480000 4481000 4482000 4483000 4484000 4485000UTM Northing (meters)



### = maximum predicted concentration ( 2.30 μ g /m3 )Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

50 29-23586A 

### Figure 4-7. Maximum Predicted 3-Hour Average SO 2 

### Concentrations Concentration isopleths in micrograms per cubic meter (μg/m 3 

### ) 553000 554000 555000 556000 557000 558000 559000 560000 561000 562000
UTM Easting (meters) 4476000 4477000 4478000 4479000 4480000 4481000 4482000 4483000 4484000 4485000UTM Northing (meters)



### = maximum predicted concentration (2.04 μg/m3)March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 51 

### Figure 4-8. Maximum Predicted 24-Hour Average SO 2 

### Concentrations Concentration isopleths in micrograms per cubic meter (μg/m 3 

### ) 553000 554000 555000 556000 557000 558000 559000 560000 561000 562000
UTM Easting (meters) 4476000 4477000 4478000 4479000 4480000 4481000 4482000 4483000 4484000 4485000UTM Northing (meters)



### = maximum predicted concentration (1.09 μg/m3)Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

52 29-23586A 

### Figure 4-9. Maximum Predicted Annual Average SO 2 

### Concentrations Concentration isopleths in micrograms per cubic meter (μg/m 3 

### ) 553000 554000 555000 556000 557000 558000 559000 560000 561000 562000
UTM Easting (meters) 4476000 4477000 4478000 4479000 4480000 4481000 4482000 4483000 4484000 4485000UTM Northing (meters)



### = maximum predicted concentration (0.149 μg/m3)March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 53 

### Figure 4-10. Maximum Predicted 24-Hour Average PM 10 

### Concentrations Concentration isopleths in micrograms per cubic meter (μg/m 3 

### ) 553000 554000 555000 556000 557000 558000 559000 560000 561000 562000
UTM Easting (meters) 4476000 4477000 4478000 4479000 4480000 4481000 4482000 4483000 4484000 4485000UTM Northing (meters)



### = maximum predicted concentration (1.43 μg/m3)Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

54 29-23586A 

### Figure 4-11. Maximum Predicted Annual Average PM 10 

### Concentrations Concentration isopleths in micrograms per cubic meter (μg/m 3 

### ) 553000 554000 555000 556000 557000 558000 559000 560000 561000 562000
UTM Easting (meters) 4476000 4477000 4478000 4479000 4480000 4481000 4482000 4483000 4484000 4485000UTM Northing (meters)



### = maximum predicted concentration (0.213 μg/m3)March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 55 

### Figure 4-12. Maximum Predicted 1-Hour Average NO 2 

### Concentrations Concentration isopleths in micrograms per cubic meter (μg/m 3 

### ) 553000 554000 555000 556000 557000 558000 559000 560000 561000 562000
UTM Easting (meters) 4476000 4477000 4478000 4479000 4480000 4481000 4482000 4483000 4484000 4485000UTM Northing (meters)



### = maximum predicted concentration (14.0 μg/m3)Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

56 29-23586A 

### Figure 4-13. Maximum Predicted Annual Average NO 2 

### Concentrations Concentration isopleths in micrograms per cubic meter (μg/m 3 

### ) 553000 554000 555000 556000 557000 558000 559000 560000 561000 562000
UTM Easting (meters) 4476000 4477000 4478000 4479000 4480000 4481000 4482000 4483000 4484000 4485000UTM Northing (meters)



### = maximum predicted concentration (0.906 μg/m3)March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 57 

### Figure 5-1. Nearby Class I Area Locations 200 km 100 km 50 km Marble Mtn. WA Lava Beds NM

Redwood NP

Yolly Bolly
Middle Eel WA Thousand Lakes WA
Lassen Volcanic NP
Caribou WA S. Warner WA

SPI-Anderson

Desolation WA

Mountain Lakes WA Kalmiopsis WA

Gearhart Mountain WA

Point Reyes NS Mokelumne WA

Emigrant WA California Oregon

NevadaSierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

58 29-23586A 

### (This page intentionally left blank.)March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

29-23586A 

## Appendix A:

SCAQMD FormsSierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

29-23586A 

### (This page intentionally left blank.)

### SHASTA COUNTY DEPARTMENT OF RESOURCE MANAGEMENT AIR QUALITY MANAGEMENT DISTRICT 1855 PLACER STREET, SUITE 101, REDDING, CALIFORNIA 96001 VOICE (530)225-5674/FAX (530)225-5237
APPLICATION FOR AUTHORITY TO CONSTRUCT/PERMIT TO OPERATE

INSTRUCTIONS PERMIT NUMBER # -POEach applicant for an Authority to Construct shall provide to the District the following: A. One application form for each emission unit or multi-component system at the facility. B. A $75 one time filing fee for each application or a $15 transfer of ownership * or name change fee made payable to the Shas ta County AQMD. (*Furnish a copy of the sales agreement or a signed statement from the seller.) C. Adequate drawings of each emissions unit, including plot pl an and area map indicating receptors within 1/4 mile of the faci lity. Any public or private school with an outer boundary within 1000 feet of the emissions unit must be included on the map. D. A signature of a responsible member of the organization on each application. E. An annual permit fee must be paid before a Permit to Operate is granted. The District shall notify the applicant of the a ppropriate amount due following an initial inspection of the permitted device(s).

1. Business Name: Sierra Pacific Industries

2. Email: syoung@spi-ind.com

3. Assessor's Parcel Number: 05011025 Telephone: (530) 378-8350 Fax: (530) 378-8360

4. Type of Business: Lumber manufacturing

5. Mailing Address: P.O. Box 10939, Anderson, CA 96007

6. Address of Equipment: 19758 Riverside Ave., Anderson, CA 96007

7. Equipment Description (use additional sheets if required): See permit application documentation

8. Application to: (check one) 9. Type of Organization: Operate Existing Equipment _ _ Corporation _x

_ New Construction _ _ Partnership _

_ Change of Location _ _ Individual Owner _

_ Modification _x _ Government Agency _

_ Exempt Equipment _

_ Change of Ownership* _ _ (Copy of agreement or statement attached? Yes No )

10. Planned construction dates; Start: 9/1/2010 End: 8/31/2011

11. Is a plot plan attached? Yes: See permit application documentation No:

12. Is this emission unit within 1000 feet from the outer boundary of any public or private school? Yes: No: X__

13. Name of Owner(s)/Principles: Sierra Pacific Industries

14. Signature of Applicant: Date: March 25, 2010

15. Type/Print Signer's Name: Shane Young Title: Division Manager

BY SIGNING THIS APPLICATION, THE APPLICANT/PR OPERTY OWNER AGREES TO DEFEND, INDEMNIFY, AND HOLD THE SHASTA COUNTY AIR QUALITY M ANAGEMENT DISTRICT HARMLESS FROM ANY CLAIM, ACTION, OR PROCEEDING BROUGHT TO ATTACK, SET ASIDE, VOID OR ANNUL THE DISTRICT’S APPROVAL OF THIS APPLICATION, ISSUANCE OF ANY ASSOCIATED PERMIT, AND ANY ENVIRONMENTAL REVIEW ASSOCIATED WITH THE PROPOSED PROJECT.

Other Division Review Air Quality Fees Collected

General Plan/Zoning: Type Date Amount Receipt # Rec'd By

Use requires use permit: Yes No Filing

Use requires building permit: Yes No Permit

Planning: Building:
Date: Date:

Z:\My Documents\Stationary Source Permitting Forms\01_APPLICATION_030404.wpd

# SHASTA COUNTY DEPARTMENT OF RESOURCE MANAGEMENT AIR QUALITY MANAGEMENT DISTRICT

1855 PLACER STREET, SUITE 101, REDDING, CA 96001 VOICE (530)225-5674/FAX (530)225-5237 

### SUPPLEMENTAL INFORMATION: BOILER/PROCESS HEATER

Company: Sierra Pacific Industries, Inc.

Specifications / Information :

Manufacturer: To be determined Model Number: To be determined

Fuel Type(s): Biomass, including: wood, agricultural, and urban wood waste Serial Number: To be determined

Rated heat input capacity (specified on nameplate): 425,419,000 (estimated) BTU/hr

What is the primary purpose of the boile r or process heater? Generate steam for lumber drying kilns and to generate electri city

Operation schedule (maximum): 24 hours/day 7 days/week 52 weeks/year

If operated seasonally, indicate the percent use in each quarter: 25 % Jan-Mar 25 % Apr-Jun 25 % Jul-Sep 25 %Oct-Dec

Fuel Usage Rate (maximum-daily): 1,380 tons/day N/A cuft/day N/A gallons/day

Fuel Usage Rate (maximum-annual): 503,989 tons/yr N/A cuft/yr N/A gallons/yr

Exhaust Emission Information:

HEIGHT OF EXHAUST STACK ABOVE
THE GROUND (in feet) 115 feet
NO 2 (as ppmv at 7% O 2 , dry, or lb/MMBtu) 0.13 lb/MMBtu

INSIDE DIAMETER OF EXHAUST STACK
(in feet) 8.0 feet
CO (as ppmv at 7% O 2 , dry or lb/MMBtu) 0.35 lb/MMBtu

AVERAGE FLOW OF EXHAUST AIR (specify acfm or dscfm) 206,425 acfm
AMMONIA SLIP
(as ppmv at 3% O 2 , dry) 20 ppmvd @ 3% O 2

MAXIMUM FLOW OF EXHAUST AIR (specify acfm or dscfm) 237,486 acfm
STACK GAS OXYGEN
(as %) 6.04% (dry basis)

PERCENT MOISTURE OF EXHAUST AIR 21.19%
SO 2 (as ppmv at 12% CO 2 , std conditions) 2.0 ppmvd @ 12% CO 2

TEMPERATURE OF EXHAUST AIR
(in O F) 400 °F
PARTICULATE MATTER (as gr/dscf or lb/MMBtu) 0.02 lb/MMBtu 0.01 gr/dscf

If the boiler/process heater has a rated heat input of more than 1,000,000 BTU/hr and less than 5,000,000 BTU/hr , check one of the following options you will accept as a permit condition to control NOx emissions:

Perform an annual tune-up for compliance (tune-up procedures specified in District Rule 3:26)

Compliance to emission limit set for NOx (as specified in District Rule 3:26 -- NOx ≤ 70 ppmvd at 3% O 2 , dry)

Operate with a stack gas oxygen trim system set at 3% oxygen by volume.

Operate with a stack gas oxygen concentr ation less than or equal to 3% by volume for any 15 minute averaging period.

If the boiler/process heater has a rated h eat input of greater than 5,000,000 BTU/hr , regulations require installation of a dedicated non-resettable totalizing volumetric or mass-flow fuel meter (if gaseous and/or liquid fuel only). Meter specifications are re quested.

Filer's Printed Name:_Shane Young_______Signature: Date: March 25, 2010

NOTICE: After the Authority to Construct is granted, any deviation from approved plans is not permitted without first securing addition al approval from the Air Pollution Control Officer. As stated in the Health and Safety Code Sections 41510, 41511, and 42304, the Air Quality Management District shall make random audits on submitted data to insure the appropriateness of such data. The willful
submission of false or inaccurate data constitutes a misdemeanor per Health and Safety Code Section 42400.

Z:\My Documents\Stationary Source Pe rmitting Forms\18 Boiler Supplemental.wpdMarch 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC/PSD Permit Application

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## Appendix B:
BACT AnalysisSierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

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### (This page intentionally left blank.)

## Biomass-Fired Cogeneration Project Best Available Control Technology Analysis Anderson, California

Prepared for: Sierra Pacific Industries, Inc. Redding, California

Prepared by: ENVIRON International Corporation Lynnwood, Washington

Date:
March 2010

Project Number:
29-23586AMarch 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson Best Available Control Technology Analysis

29-23586A i 

# Contents

Page

1 Introduc tion ................................................................................................................... ................... 1

1.1 BACT Review Proces s ............................................................................................................ ....1
1.2 Technical F easibilit y .......................................................................................................... ..........2
1.3 Economic Just ifiab ility........................................................................................................ ..........3

2 NO X BACT A nalysis ................................................................................................................. ........ 5

2.1 Identification of Possible Control Alte rnatives .............................................................................5
2.2 Technical Feasibility of Control Alte rnatives................................................................................8
2.3 Effectiveness of Rema ining Tec hnologies ................................................................................10
2.4 Cost-Effectivene ss Evaluation.................................................................................................. .11
2.5 Selection of BACT for NO X ........................................................................................................12

3 CO BACT A nalysis............................................................................................................... .......... 13

3.1 Identification of Possible Control Alte rnativ es ...........................................................................13
3.2 Technical Feasibility of Control Alte rnativ es..............................................................................15
3.3 Effectiveness of Rema ining Tec hnologies ................................................................................16
3.4 Cost Effectivene ss Evaluation .................................................................................................. .17
3.5 Selection of BACT fo r CO

....................................................................................................... ...17

4 PM 10 BACT ANALYSIS................................................................................................................. . 19

4.1 Identification of Possible Control Alte rnativ es ...........................................................................19
4.2 Technical Feasibility of Control Alte rnativ es..............................................................................20
4.3 Effectiveness of Rema ining Tec hnologies ................................................................................20
4.4 Cost Effectivene ss Evaluation .................................................................................................. .21
4.5 Selection of BACT for PM 10 .......................................................................................................21

5 ROG/VOC BACT Analysis .......................................................................................................... ... 23

5.1 Identification of Possible Control Alte rnativ es ...........................................................................23
5.2 Technical Feasibility of Control Alte rnativ es..............................................................................24
5.3 Effectiveness of Rema ining Tec hnologies ................................................................................24
5.4 Cost Effectivene ss Evaluation .................................................................................................. .24
5.5 Selection of BACT for ROG/ VOCs ............................................................................................24

6 SO 2 BACT ANALYSIS ................................................................................................................. .. 25

6.1 Identification of Possible Control Alte rnativ es ...........................................................................25
6.2 Technical Feasibility of Control Alte rnativ es..............................................................................26
6.3 Effectiveness of Rema ining Tec hnologies ................................................................................26
6.4 Cost Effectivene ss Evaluation .................................................................................................. .26
6.5 Selection of BACT for SO 2 .........................................................................................................26

7 Beryllium BACT Analysis ........................................................................................................ ....... 27

8 Cooling Tower BACT Analysis.................................................................................................... ... 29Sierra Pacific Industries - Anderson Best Available Control Technology Analysis March 2010 Biomass-Fired Cogeneration Project

ii 29-23586A 

# List of Tables

Page

Table 1 NO X Control Technology Search Re sults ...................................................................................... 33

Table 2 NO X Control Technology Cost-E ffectiveness Co mparis on............................................................ 34

Table 3 CO Control Tec hnology Search Results................................................................................... ..... 35

Table 4 PM 10 Control Technology Search Re sults ..................................................................................... 36

Table 5 ROG/VOC Control Tec hnology Search Result s ............................................................................ 37

Table 6 SO 2 Control Technology Search Re sults....................................................................................... 38



# List of Appendices

Appendix A: Cost Effectiveness CalculationsMarch 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson Best Available Control Technology Analysis

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# 1 Introduction

Sierra Pacific Industries (SPI) proposes to construct and operate a new biomass-fired cogeneration unit at an existing lumber manufacturing facility in Anderson, California. The project would consist of a biomass-fired cogeneration unit, a steam turbine, and a cooling tower. The boiler associated with the cogeneration unit would have a maximum annual average heat input of up to 425 million British thermal units per hour (MMBtu/hr).

A new or modified source requiring an air permit, and required by regulations to apply the best available control technology (BACT) for a given pollutant to one or more emission units, must conduct an analysis to ensure that BACT is being proposed in the permit application. The project is a major modification of a major source, and is therefore subject to U.S. Environmental Protection Agency’s (USEPA’s) Prevention of Significant Deterioration (PSD) program. 1 

### In addition, Shasta County has established daily emission rate thresholds for various pollutants, which, if exceeded by the proposed project, require each proposed emission unit to apply BACT to control emissions of that pollutant. 2



### As new sources of emissions, BACT analyses are required for the biomass-fired cogeneration unit and the cooling tower. Based on the calculated annual emission rates for the proposed project and USEPA and Shasta County BACT thresholds (see the permit application for emissions rates and comparison to the thresholds), analyses are required for oxides of nitrogen (NO X 

### ), carbon monoxide (CO), particulate matter equal to or less than ten microns in diameter (PM 10 

### ), reactive organic compounds (ROG), sulfur dioxide (SO 2 

### ), and beryllium.



### 1.1 BACT Review Process
A BACT analysis evaluates the energy, environm ental, economic, and other costs associated with each potential control technology, and weighs those costs against the reduced emissions the technology would provide. The BACT analysis presented here is consistent with general EPA guidance. The EPA BACT guidance document details a “top-down” approach for selecting the appropriate control technology. The steps are as follows:

• 

### Step 1. Identify all control technologies. Identify all available control techniques that could potentially be applied to control emissions of regulated pollutants from the proposed boiler.

• 

### Step 2. Eliminate technically infeasible options. If any of the control techniques cannot be successfully used on plant units due to technical difficulties, document this finding. Such control techniques would not be considered further in the BACT analysis.

1 40 CFR 51.21(b)(23)(i) 2 Shasta County Air Quality Management District Rule 2:1, Part 301.Sierra Pacific Industries - Anderson Best Available Control Technology Analysis March 2010 Biomass-Fired Cogeneration Project

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• 

### Step 3. Rank remaining control technologies by control effectiveness. Assess the performance of each control technique and rank them beginning with the most effective control technique.

• 

### Step 4. Evaluate most cost effective controls. Estimate emission reductions, annual costs, cost effectiveness, energy impacts, and other environmental impacts of the controls techniques. Detailed cost effectiveness information is presented for the most effective control and for other control techniques that are in the least cost envelope.

• 

### Step 5. Select BACT. This will generally be the most effective option not rejected based on energy, environmental, and economic impacts.

The only new emission unit proposed by the project is the wood-fired stoker-type boiler, so ENVIRON queried EPA’s Reasonably Available Control Technology (RACT)/BACT/Lowest Achievable Control Technology (LAER) Clearinghouse (RBLC) database for BACT determinations involving biomass-fired, stoker-type boilers made after January 1, 1990. This initial broad search was refined by adding similar sources of which ENVIRON is aware that are not included in the RBLC database, and eliminating sources that operate in a significantly
different manner.

USEPA’s Reasonably Available Control Technology (RACT)/BACT/Lowest Achievable Control Technology (LAER) Clearinghouse (RBLC) database was queried for recent BACT determinations involving biomass-fired boilers. The search included all entries made after January 1, 1990 for biomass-fired, stoker-type boilers. This initial broad search was refined by eliminating sources that did not emit pollutants as a result of similar operation (e.g., fluidized bed boiler designs, use of fuels other than or in combination with wood). The sections that follow discuss the control alternatives available, the effectiveness and feasibility of those alternatives, and, ultimately, the selection of BACT for each pollutant.

All biomass-fired boiler permits meeting the criteria outlined above were included in the review. Permitted emission limits were compared on a heat input rate basis in units of pounds per million British thermal unit (lb/MMBtu). Equivalent emission limits, in lb/MMBtu, were calculated for sources with permit limits expressed only as an emission rate over some period (e.g., pounds per hour [lb/hr], pounds per day [lb/day], or tons per year [tpy]) by combining the permitted emission rate with a provided heat input rate.



### 1.2 Technical Feasibility
EPA's new source review guidance suggests that "...control alternatives should include not only existing controls for the source category in question, but also (through technology transfer) controls applied to similar source categories and gas streams." EPA guidance also indicates that in order for such a technology transfer to be judged technically feasible, its application should be relatively seamless and free of technical speculation. For this BACT analysis, technical feasibility was determined using the following criteria:

• 

### The control technology was previously applied to emission streams sufficiently similar to the one being proposed. Any differences between the proposed current and previousMarch 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson Best Available Control Technology Analysis

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### applications should not impact the performance of the control technology. The control technology and emission limit should not cause deterioration of the related process equipment, or irretrievably affect product quality.

• 

### The emission limit associated with the control technology, including consideration for normal and reasonable variability in the level control, should be consistently achievable under normal and conscientious operating practices.

• 

### The emission limits should not result in frequent violations despite a well-designed and installed, and conscientiously operated control system. Frequent violations increase costs to both the source and the regulatory agency (and consequently the public) as a result of investigation, litigation, and reconstruction, and do not benefit the environment.



### 1.3 Economic Justifiability
An economically justifiable control technology is neither the maximum amount a source is able to spend, nor the maximum amount any source in the same source category has spent in the past. For this BACT analysis, economic justifiability was determined based on cost effectiveness. If the cost per ton of pollutant reduced for a particular technically feasible control system is disproportionately high compared to the cost per ton in recent BACT determinationsfor other sources in the same source category, the control technology is deemed not costeffective, and can be rejected as economically unjustifiable.Sierra Pacific Industries - Anderson Best Available Control Technology Analysis March 2010 Biomass-Fired Cogeneration Project

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# 2 NO X 

# BACT Analysis

NO X 

### is generated when combustion temperatures are high enough for the nitrogen in the combustion air or bound in the fuel to combine with oxygen to form NO. Depending upon conditions in the exhaust stream, some portion of the NO will react to form NO 2



### .



### 2.1 Identification of Possi ble Control Alternatives
There are a variety of options available for controlling NO X 

### emissions from combustion sources. Some options involve combustion controls that reduce NO X 

### formation, while others utilize addon control devices to remove NO X 

### after it is formed.



### 2.1.1 Combustion Controls

Combustion controls reduce NO X 

### emissions by controlling the combustion temperature and the availability of oxygen. Combustion air containing both nitrogen and oxygen can combine in a high temperature environment to form “thermal NO X 

### .” The oxidation of nitrogen that is chemically bound in fuel sources can also form what is called “fuel-bound NO X 

### .”

Proper combustion generally refers to control, gener ally computerized, of the amount of flue gas recirculation (FGR), the fuel feed rate, and the amount of over- or under-fire combustion air in the furnace. This type of control is common on boilers constructed in the last few decades.

Dry low-NO X 

### (DLN) burners control thermal NO X 

### formation by avoiding high temperature combustion zones and uneven oxygen distribution. This is accomplished by burner designs that carefully control the mixing of fuel and combustion air. Generally, use of DLN burners requires a wall-fired furnace and pulverized biomass fuel that is burned in suspension with coal or natural gas.



### 2.1.2 Add-on Controls

Add-on controls such as selective non-cata lytic reduction (SNCR) and selective catalytic reduction (SCR) systems are widely used technologies for controlling NO X 

### emissions from combustion sources. In the SNCR process, ammonia is mixed with the exhaust from the
combustion device and the NO X 

### in the exhaust reacts with the introduced ammonia to form nitrogen and water. The reagent, which can be anhydrous ammonia, aqueous ammonia, or urea dissolved in water, is typically injected at the exit of the furnace to mix with the hot flue

gases.

The SCR process is similar to SNCR, in that a reagent reacts with NO X 

### to form nitrogen and water, but a catalyst matrix is used to allow the reduction reaction to take place at lower temperatures (600 oF for SCR as opposed to 1,650 oF for SNCR). While SCR systems have
been utilized to reduce NO X 

### from biomass-fired boilers, such installations are relatively rare because the ash in the exhaust tends to obstruct and deactivate the catalyst. Schemes that position the SCR downstream of a particulate control device to reduce the amount of ash thatSierra Pacific Industries - Anderson Best Available Control Technology Analysis March 2010 Biomass-Fired Cogeneration Project

6 29-23586A 

### reaches the catalyst have resulted in exhaust gas temperatures too low for conventional catalysts to promote the reduction reaction. A dditionally, potassium in the fuel vaporizes and becomes an extremely fine aerosol that often eludes particulate controls in sufficient quantities to accelerate deactivation of the catalyst. Solutions to these problems have included: reheating the flue gas with natural gas or diesel fuel, using low-temperature catalysts located downstream of particulate controls, and increasing catalyst size and replacement frequency to maintain the desired effectiveness. Unfortunately, each of these approaches involve significant additional expense: exhaust reheat is expensive and an ineffici ent use of fuel, low-temperature catalysts are expensive and even more prone to deactivation than conventional catalysts, and increasing the size and replacement frequency of convent ional catalyst is inherently expensive.

There are several SCR variants that have been applied to biomass-fired boilers including: SNCR/SCR hybrids, Regenerative SCR (RSCR), and low-temperature, or “cold-side,” SCR (CSCR). Hybrid SNCR/SCR systems locate t he catalyst bed downstream of an SNCR system, and the unreacted ammonia injected by the SNCR system (and additional ammonia, if necessary) is used by the SCR catalyst to further reduce NO X 

### emissions. In practice, unreacted ammonia from the SNCR is not distributed evenly enough in the exhaust gases to be used effectively by the catalyst, and, as a result, ammonia use and ammonia slip levels tend to be higher than for a similarly effective SCR-only system.

RSCR systems were developed to make applicat ion of an SCR system downstream of a particulate control device more economical by using a regenerative ceramic bed to recover heat from reheated exhaust gas. RSCR applications hav e typically been limited to existing boilers, where it would be expensive and difficult to rea rrange the exhaust system to locate an SCR or CSCR system for the optimum range of exhaust temperatures.

CSCR systems are also positioned downstream of a particulate control device, but the use more advanced catalysts that enable the reduction reaction to proceed at lower temperatures (350 oF to 450 oF). These catalysts are typically more expensive and are even more prone to deactivation by potassium and sulfur than standard SCR catalysts.

EMx (formerly called SCONOx) is similar to SCR, except that NO X 

### in the exhaust stream reacts with potassium carbonate (K 2 

### CO 3 

### ) to form potassium nitrate (KNO 3 

### ). This compound is reacted with hydrogen to form gaseous nitrogen (N 2 

### ), and regenerate the K 2 

### CO 3 

### . The lower exhaust temperature limit required for the reactions to take place is less than that of SCR (300 oF as opposed to 450 to 600 oF, depending on the catalyst used). The EMx system is also said to control CO and VOCs by oxidation.



### 2.1.3 Control Alternative Review
The database queries did not produce any instances of NO X 

### emissions from biomass-fired boilers controlled by DLN burner or SNCR/SCR hybrid systems. The most recent biomassfired, stoker-type boiler BACT determination in the RBLC was by the New Hampshire Department of Environmental Services (NHDES) in a permit issued to Concord Steam for a 305 MMBtu/hr wood-fired, stoker-type boiler on January 16, 2009. NHDES determined that aMarch 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson Best Available Control Technology Analysis

29-23586A 7 

### “cold-side” SCR system (2 catalyst beds with a 450 °F inlet temperature) that would limit NO X 

### emissions to 0.065 lb/MMBtu on a 30-day rolling average was LAER.

In 2007 and 2008, several New England facilities received permits allowing them to add RSCR or SNCR/SCR hybrid systems to biomass-fir ed stoker-type boilers to achieve a quarterly average NO X 

### emission rate of 0.075 lb/MMBtu and qualify for Connecticut’s Renewable Portfolio Standard (RPS) program. RSCR systems were installed at Boralex Energy in Stratton, Maine, Bridgewater Power in Bridgewater, New Hampshire, and DG Energy in Whitefield, New Hampshire. SNCR/SCR hybrid systems were installed at Springfield Power in Springfield, New Hampshire, and the Pinetree Power facilities in Tamworth and Bethlehem, New Hampshire. All of these facilities were originally permitted before 1990, and have less stringent short-term NO X 

### permit limits based on either a PSD permit or RACT. It should be noted that while these emission units have demonstrated the ability to meet the Connecticut RPS qualification threshold, compliance is entirely voluntary, and none have corresponding enforceable permit
limits.

Also not represented in the RBLC, is a recently issued conditional permit for Russell Biomass in Massachusetts, which includes an option to construct a stoker-type biomass boiler that would
limit NO X 

### emissions to 0.060 lb/MMBtu using a two-layer RSCR system. The Massachusetts RPS program has a more stringent NO X 

### emissions criterion (0.065 lb/MMBtu with no averaging period). This air and water permits issued for this project have been appealed, the facility has not yet obtained a wetlands permit, and there is significant public opposition to the fuel delivery
truck traffic volumes and routes.

The most recently permitted biomass-fired, stoker-type boiler in California is a 289 MMBtu/hr unit at the Sierra Pacific Industries facility in Lincoln, California, which was permitted in 2004
with a NO X 

### limit of 0.13 lb/MMBtu. A larger boiler (430 MMBtu/hr) of similar design was permitted in 2006 at an SPI facility near Burlington, Washington with the same NO X 

### permit limit. 3 

### Valley BioEnergy, LLC has submitted a permit application for a biomass-fired boiler in Modesto, California that proposes to use an SNCR/SCR hybrid system to limit NO X 

### emissions to
0.012 lb/MMBtu on a short-term basis 4 

### , and 0.0055 lb/MMBtu on an annual average in order to avoid purchasing offsets in an ozone nonattainment area. The facility has been neither permitted nor constructed.

There are several instances of biomass-fired boilers using DLN burner technology to limit the
amount of NO X 

### generated during combustion. Coen manufactures the Dual Air Zone (DAZ) scroll burner, which can be used to fire pulverized wood along with some natural gas

3 The original permit included a 24-hour average NO X limit of 0.13 lb/MMBtu, and a 12-month rolling average NO X

limit of 0.1 lb/MMBtu. In Augus t 2009, the 12-month rolling average NO X limit was eliminated in an effort to address a secondary plume that resulted from exce ssive ammonia use in the SNCR system. 4 For the initial 12-month period fo llowing startup, t he 24-hour average NO X limit would be 0.024 lb/MMBtu. During

that period, a study would determine whether or not the 0.012 lb/MMBtu lim it was achievable, and, if not, an alternative NO X limit would be proposed.Sierra Pacific Industries - Anderson Best Available Control Technology Analysis March 2010 Biomass-Fired Cogeneration Project

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### (approximately ten percent of total heat input). These burners have generally been installed in units with a maximum heat input of less than 100 MMBtu/hr, and require additional fuel processing to reduce the fuel to an average size of approximately 1/32 of an inch. With some flue gas recirculation and staged combustion, a NO X 

### emission rate of 0.35 lb/MMBtu at the
furnace exit has been achieved.

The results of the database queries and permit investigations for NO X 

### control alternatives are presented in Table 1, sorted by permit limit.



### 2.1.4 Summary of Possible Control Alternatives
Based on literature and database searches the following alternatives are possible for controlling
NO X 

### emissions from a biomass-fired boiler:

• 

### Proper combustion

• 

### DLN burner

• 

### SNCR

• 

### SCR and variations

• 

### EMx



### 2.2 Technical Feasibility of Control Alternatives

2.2.1 Proper Combustion
Proper combustion refers to the application of state-of-the-art design to, and appropriate operation of, a combustion unit. Current design biomass-fired mass-burner-type boilers can generally achieve NO X 

### emission rates of between 0.20 to 0.26 lb/MMBtu, depending upon the degree of optimization for controlling NO X 

### emissions (lower NO X 

### emissions mean higher CO and VOC emissions), when operated in the manner recommended by the boiler designer and manufacturer. Proper combustion is a ubiquitous and technically feasible technology for controlling NO X 

### emissions from biomass-fired boilers.



### 2.2.2 DLN Burner
For a boiler of the size proposed, two or more DLN burners would be required. With such burners, the fuel would be pulverized and burned in suspension using wall-mounted burners, which would be a significant departure from the proposed boiler design, which has combustionoccurring on a moving grate. These burners are generally intended to limit the amount of fuelbound nitrogen that is converted to NO X 

### during combustion, and are generally suited to smaller boilers that burn wood products industry residuals containing a high percentage of resins, such as residuals from medium density fiberboard (MDF ), plywood, or veneer operations. In this case, the emission rate with DLN burners (0.35 lb/MMBtu) is higher than could be achieved by a current state-of-the-art mass burner-type boiler using a combustion grate and no add-onMarch 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson Best Available Control Technology Analysis

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### controls (approximately 0.20 lb/MMBtu), so this technology will be eliminated from consideration
as BACT.



### 2.2.3 SNCR
Ammonia injection nozzles are positioned in the furnace where temperatures are expected to be between 1600 °F and 1800 °F and use the relatively high temperatures there to promote the
reaction of NO X 

### and ammonia. SNCR system design is often incorporated into biomass-fired boiler design because SNCR systems do not rely on a catalyst which is subject to plugging from particulate matter in the flue gases. The relative simplicity of SNCR systems makes them technically feasible, and has resulted in them becoming the most popular add-on NO X 

### control technology for biomass-fired boilers.



### 2.2.4 SCR and related variations
As indicated in the previous section, S CR, SNCR/SCR hybrid, RSCR, and CSCR systems have been applied to a limited number of biomass-fired, stoker-type boilers. Among the variations, an SCR system placed downstream of particulate collector (e.g., a multiclone and an ESP) is likely to be cost-effective operation while reducing NO X 

### emissions to 0.060 lb/MMBtu. Because most of these installations have been within the past year or two, experience with this application of SCR technology is limited. Many of the pr ojects using SCR have experienced catalyst deactivation and/or erosion at rates that were higher than anticipated, and, as a result, have required additional assistance from catalyst suppliers and control technology consultants. SCR systems are known to effectively control NO X 

### emitted by biomass-fired boilers, but the ability of such systems to remain effective over time and not negatively impact the economic performance of the boiler is questionable.



### 2.2.5 EMx
To date, EMx has been designed and used only on small- to medium-sized natural gas-fired stationary turbines for demonstration purposes. The technology has never been applied to a biomass-fired boiler. Also, the EMx system is sensitive to sulfur in the exhaust, which can degrade the performance of the system. While biomass fuels are not generally considered high-sulfur fuels, the AP-42 SO 2 

### emission factor for wood-fired boilers is 0.025 lb/MMBtu, which is equivalent to about 7.2 lb/hr of SO 2 

### . Natural gas, the combustion fuel most commonly associated with EMx applications, has maximum sulfur limit of one grain per 100 standard cubic feet (gr/scf) of gas in California, where EMx has been applied. On a heat input basis, this is equivalent to an SO 2 

### emission rate of 0.43 lb/hr. The sensitivity to sulfur, combined with a lack of comparable existing applications suggests that EMx is technologically infeasible as a control technology for controlling NO X 

### emissions from a biomass-fired boiler.



### 2.2.6 Summary of Technically Feasible Control Alternatives
The following is a list of control alternatives determined to be technically feasible for controlling
NO X 

### emitted by a biomass-fired, stoker-type boiler:Sierra Pacific Industries - Anderson Best Available Control Technology Analysis March 2010 Biomass-Fired Cogeneration Project

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• 

### Proper combustion

• 

### SNCR

• 

### SCR/CSCR/RSCR



### 2.3 Effectiveness of Remaining Technologies
This section describes the remaining technologies in more detail and ranks them by
effectiveness.



### 2.3.1 Proper Combustion
A modern biomass-fired boiler furnace, operated with computerized controls to ensure proper
combustion would result in a NO X 

### emission limit of between 0.20 and 0.26 lb/MMBtu. The proposed boiler design would emit 0.20 lb/MMBtu when utilizing only proper combustion techniques to limit NO X 

### emissions.



### 2.3.2 SNCR
Currently, SNCR systems are the most common add-on control device used to reduce NO X 

### emissions from large biomass-fired boilers. SNCR systems rely on high temperatures to promote the reaction of NO X 

### with the introduced ammonia. As a result, the control system is incorporated into the boiler design to facilitate the introduction of the ammonia into the furnace at the proper temperature window to increase NOx reduction effectiveness. Short-term
emission limits of between 0.13 and 0.2 lb/MMB tu have been achieved using SNCR systems to
control NO X 

### emitted by biomass-fired, stoker-type boilers.



### 2.3.3 SCR/CSCR/RSCR
The recently permitting Concord Steam project proposed to use a CSCR system to limit NO X 

### emissions to 0.065 lb/MMBtu on a 30-day rolling average. Russell Biomass, if constructed, would use a two-layer RSCR to limit NO X 

### emissions to 0.060 lb/MMBtu. The Concord Steam LAER determination issued by NHDES acknowledged the Russell Biomass limit, while pointing
out that the limit would be “difficult to meet” using the proposed system, and that the project is not likely to be built. A permit has not been issued for Valley BioEnergy in Modesto, California, though the pemit application has been deemed complete; the proposal is to use both an SNCR as well as an SCR system with the catalyst pl aced downstream of particulate control devices.



### 2.3.4 Ranking by Effectiveness
The remaining technologically feasible control technologies ranked in decreasing order of
effectiveness are:

• 

### SCR/CSCR/RSCR

• 

### SNCRMarch 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson Best Available Control Technology Analysis

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• 

### Proper combustion



### 2.4 Cost-Effectiveness Evaluation
SNCR is the most common add-on technology used to reduce NO X 

### emissions from a stokertype, biomass-fired boiler. The uncertainties that drive the ranges of cost and control effectiveness are well understood by manufacturers and vendors. Biomass-fired boiler projects can propose well-established emission limits as BACT with confidence that, based on an extensive body of knowledge and experience, an SNCR system will be able to achieve the proposed emission limits. A cost-effectiveness anal ysis indicates that utilizing an SNCR system
to reduce biomass-fired boiler emissions from 0.20 lb/MMBtu to 0.13 lb/MMBtu would cost $661 per ton of NO X 

### reduced (see Attachment A).

Although application of an SCR system to a bioma ss-fired boiler is not considered experimental, it cannot be assumed that, due to a lack of practica l experience, such a system will perform in a reliable and cost-effective manner. Because of the high level of uncertainty associated with the rate of deactivation of the SCR catalyst by trace amounts of alkaline elements in the exhaust (e.g., potassium), it is difficult, if not impossible, to determine both capital and operating cost ranges in advance. In addition to the number of catalyst beds that the project must purchase, the catalyst deactivation rate determines how often a boiler will be required to shut down for installation of fresh catalyst in order to continually comply with a permit limit. SPI estimates that approximately $150,000 in revenue would be lost each time the boiler was shut down to replace or wash the catalyst. Additionally, SPI’s power contract, which stipulates a minimum level of power availability, could be jeopardized if a high deactivation rate required frequent catalyst replacement or washing.

Despite the difficulty in estimating the actual operating and capital costs associated with such a system, the cost-effectiveness of an SCR control system, as applied to a biomass-fired boiler, was calculated. The calculations are presented in Attachment A, and summarized, along with those of the SNCR system, in Table 2. The SNCR system would reduce NO X 

### emissions by 130 tons year at an annual expense of approx imately $203,000, while an SCR system, under best-case operating conditions, would reduce NO X 

### emissions by approximately 260 tons per year at an annual expense of nearly $1,320,000. Thus, an additional $1,116,000 per year would be spent to capture an additional 130 tons of NO X 

### , which is equivalent to an incremental cost effectiveness of over $8,500 per ton of NO X 

### removed. However, judging by the experiences of other biomass-fired boiler fa cilities employing SCR systems, this costeffectiveness analysis likely underestimates the number of replacement catalyst beds needed each year (2), as well as the number downtim e events needed each year to replace or clean the catalyst beds (3), so the cost effectiveness c ould easily be twice that of the calculated “best case” scenario. Based on this analysis, SNCR is deemed to be the most reliable, cost-effective
NO X 

### control technology for biomass-fired, stoker-type boilers.Sierra Pacific Industries - Anderson Best Available Control Technology Analysis March 2010 Biomass-Fired Cogeneration Project

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### 2.5 Selection of BACT for NO X 

### Based on the analysis presented in this section, SPI proposes that BACT for the control of NO X 

### from biomass-fired, stoker-type boilers is the use of an integral SNCR system. NO X 

### emissions would be limited to 0.13 lb/MMBtu, which is approximately equivalent to 242 tpy at the anticipated annual average operating capacity.March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson Best Available Control Technology Analysis

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# 3 CO BACT Analysis

Carbon monoxide (CO) is a product of the chemical reaction between carbonaceous fuels and oxygen. In fuel-rich mixtures, CO occurs as the product of combustion. In fuel-lean mixtures CO can result due to poor mixing of fuel and air in the combustion zone (so the sub-region is fuel-rich) or through dissociation of CO 2 

### into CO which can occur in high-temperature regions (above 1,700 °C) of the combustion zone.



### 3.1 Identification of Possi ble Control Alternatives

As for NO X 

### , the control technology options available for reducing CO emissions from combustion sources include combustion controls that encourage complete combustion to reduce CO formation, as well as add-on control devices that oxidize CO to CO 2 

### after leaving the
combustion area.



### 3.1.1 Combustion Controls
Combustion controls for CO include adequate fuel residence times to ensure CO 2 

### formation, proper fuel-air mixing, and temperature control. These measures, however, can result in an
increase in the NO X 

### emissions from a combustion unit. Modern boiler designs strive to balance these competing factors, and when combined with appropriate operation of the boiler, are commonly referred to as “proper combustion” practices. The design of the boiler and the type of fuel combusted can significantly influence the level of CO emissions that can be achieved through the use of proper combustion practices. Older boiler designs tend to provide less combustion gas residence time within the boiler and have less extensive over-fire air supply systems. These factors typically result in hi gher CO emissions in comparison to newer boiler designs. Dry fuel tends to allow lower CO emissions in comparison to combustion of wet biomass fuels because of lower combustion zone temperatures.



### 3.1.2 Add-On Controls
Catalytic oxidizers use a matrix or “bed” coated with noble metals (e.g., platinum) to facilitate the conversion of a criteria pollutant to a non-pollutant (in this case CO to CO 2 

### ). Catalytic oxidizers operate in a temperature range of approximately 650 °F to 1,000 °F. At lower temperatures the CO conversion efficiency falls off rapidly.

Because higher temperatures are desirabl e for improved conversion of CO to CO 2 

### by the catalyst, the exhaust temperature must be increased, resulting in higher fuel use. In order to reduce catalyst masking and pressure drop across the device, a particulate control device must be located upstream of the catalyst bed. Also, the size of the particulate control system must be increased to accommodate the higher temperature, and therefore higher volume, exhaust flow. Although the catalyst would be located downstream of a particulate control device, a steam injection system is used to periodically re move particulate matter from the catalyst.Sierra Pacific Industries - Anderson Best Available Control Technology Analysis March 2010 Biomass-Fired Cogeneration Project

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### EMx (described in the NO X 

### BACT analysis section) also utilizes a catalytic technique that
oxidizes CO to CO 2 

### in addition to controlling NO X 

### emissions.



### 3.1.3 Control Alternative Review
The results of the database queries for CO control technologies are presented in Table 3, sorted by permit limit, beginning with the CO limit proposed for the project.

Several biomass-fired stoker-type boilers have CO permit limits of 0.3 lb/MMBtu that are met using proper combustion practices. The most recent of these are two 230 MMBtu/hr public utility boilers in Minnesota (Hibbing and Virginia Departments of Public Utilities in association with the Laurentian Energy Authority) that were permitted on June 30, 2005. Several boilers of different design (e.g., a fuel-cell design boiler in Darrington, Washington, and fluidized bed units at Schiller Station in New Hampshire and Tate & Lyle Ingredients in Fort Dodge, Iowa) have lower CO permit limits, but only stoker boilers were considered in the analysis.

Oxidation using a catalyst has been employed to r educe CO emissions from a stoker boiler in at least one instance (Bio Energy in West Hopkinton, NH), and is therefore considered technically feasible, although the facility employing the technology is no longer operating. The CO permit limits for the project are not especially stringent (equivalent to 1.0 lb/MMBtu on a daily average basis and 0.25 lb/MMBtu on a rolling annual average basis), and the permit requires periodic steam sootblowing and periodic chemical cleaning or replacement of the catalyst, so the reliability of the control system when the facility was operating is questionable.

A project in South Point, OH has proposed to use ox idation catalysts to limit CO emissions from retrofitted coal boilers to 0.1 lb/MMBtu, and, while the project was issued a permit (January 5, 2004) as well as a reissued permit (April 4, 2006), construction has not commenced, and a vendor has not been identified that will supply the catalyst to meet the permit limit. A more recent permit issued by Minnesota Pollution Control Agency (Koda Energy, issued on August 3, 2007) determined that an oxidation catalyst was technically infeasible for a biomass-fired boiler because of catalyst poisoning concerns.

In 2005, DG Energy in Whitefield, NH added an ox idation catalyst to a previously-installed RSCR system. No CO permit limits were associated with the installation, and the facility is not required to use the catalyst.

Russell Biomass was issued a conditional permit by Massachusetts Department of Environmental Protection on December 30, 2008 for a project that has the option to build a biomass-fired boiler of either a fluidized bed or a vibrating-grate stoker design. The stoker design was issued a permit limit of 0.075 lb/MMBtu that would be achieved using an oxidation catalyst added to the RSCR system used to control NO X 

### . As of writing of this analysis, the facility has not commenced construction.

Concord Steam Corp. received a permit for a 305 MMBtu/hr biomass-fired stoker boiler on January 16, 2009 from NHDES which indicated that good combustion control and/or an oxidation catalyst would used to achieve a CO permit limit of 0.18 lb/MMBtu. This limit wasMarch 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson Best Available Control Technology Analysis

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### requested by Concord Steam to avoid PSD review and was not part of a BACT analysis, so it is not considered a BACT determination. The currently unpermitted and unconstructed Valley BioEnergy project in Modesto, California propos es to add an oxidation catalyst to the SCR system limit that would limit CO emission to 0.046 lb/MMBtu on a 24-hour average basis to
avoid PSD review.



### 3.1.4 Summary of Possible Control Alternatives
Based on literature and database searches the following control alternatives are possible for the
boiler:

• 

### Proper combustion

• 

### Catalytic oxidation

• 

### EMx



### 3.2 Technical Feasibility of Control Alternatives

3.2.1 Proper Combustion

Proper combustion is the most common technique used to limit CO emissions from wood-fired stoker-type boilers. Boiler designs tend to focus on limiting NO X 

### creation, at the expense of slightly higher CO emissions, to reduce the reduction burden placed on add-on NO X 

### control systems.



### 3.2.2 Oxidation Catalyst
The only instances of a biomass-fired stoker-type boiler utilizing, or proposing to utilize, an oxidation catalyst to control CO emissions ar e a project that operated for a limited period with uncertain reliability (Bio Energy), and permits issued for projects that may never be realized (South Point, Concord Steam, and Valley BioEnergy). Therefore, catalytic oxidation is considered technically feasible, but not yet fully demonstrated in practice for reliably controlling
CO emissions from a base-load biomass-fir ed stoker boiler while not negatively impacting facility operations.



### 3.2.3 EMx

As discussed in the NO X 

### BACT analysis section, EMx is extremely sensitive to presence of sulfur in the exhaust stream, and has never been demonstrated on a boiler of the size proposed by SPI. Therefore, EMx is not considered technica lly feasible for controlling CO emissions from
a wood-fired boiler.Sierra Pacific Industries - Anderson Best Available Control Technology Analysis March 2010 Biomass-Fired Cogeneration Project

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### 3.2.4 Summary of Technically Feasible Control Alternatives
The following is a list of control alternatives determined to be technically feasible for controlling CO emitted by a biomass-fired, stoker-type boiler:

• 

### Proper combustion

• 

### Oxidation Catalyst



### 3.3 Effectiveness of Remaining Technologies
This section describes the remaining technologies in more detail and ranks them by
effectiveness.



### 3.3.1 Proper Combustion
Proper combustion provides a wide range of control effectiveness, depending on the configuration of the system. Generally, emissi ons resulting from incomplete combustion (CO and VOC) are balanced with emissions related to high furnace temperatures (NO X 

### ) to achieve optimally low emissions of all pollutants. However, in order to achieve the proposed NO X 

### emission limit (0.13 lb/MMBtu) while not exceedi ng 20 parts per million (ppm) ammonia slip, as required by Shasta County (Shasta County AQMD Rule 3:26.c.4), boiler operation will favor
reduced NO X 

### creation over reduced CO creation.

SPI currently operates biomass-fired boilers at their Lincoln, California, Burlington, Washington, and Aberdeen, Washington lumber manufacturing facilities that are similar in design to the proposed boiler. Each of these boilers was permitted with a CO permit limit of (or equivalent to)
0.35 lb/MMBtu.



### 3.3.2 Oxidation Catalyst
Oxidation catalysts are capable of provid ing between 40 and 90 percent reduction in CO emissions, depending upon the amount of catalyst used and the exhaust gas temperature. Because combusting fuel (e.g., natural gas) to increase the exhaust temperature is not a realistic option, and the catalyst would be positioned downstream of the particulate control devices (i.e., multiclones and ESP), the catalyst temperature would be in the lower portion of the range over which the oxidation reaction occurs (~ 600 °F). However, control efficiencies up to 90 percent can still be achieved by adding larger quantities of catalyst, though doing so would add considerable additional expense, as well as increase the overall pressure drop of the exhaust system and decrease over all system reliability due to more frequent catalyst cleaning and replacement.



### 3.3.3 Ranking by Effectiveness
The remaining technologically feasible control technologies ranked in decreasing order of
effectiveness are:March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson Best Available Control Technology Analysis

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• 

### Catalytic oxidation

• 

### Proper combustion



### 3.4 Cost Effectiveness Evaluation
Proper combustion is the most common technique us ed to control CO emissions from a stokertype, biomass-fired boiler. Boiler designers and boiler operators have decades of experience to
draw on to deal with situations that can cause excess CO emissions such as variations in fuel moisture, or boiler operation transients. Because proper combustion design and techniques are so common in boilers, it is considered the baseline control scheme, and no additional cost is
associated with it.

Similar to the situation with applying SCR to a biomass-fired boiler as discussed in the previous section, while oxidation catalysts are not c onsidered experimental, it cannot be assumed that this control technology will perform in a reliabl e and cost-effective manner. Oxidation catalysts are subject to the same, if not more, uncertainty related to deactivation of the catalyst by trace amounts of alkaline compounds and metals in the exhaust. The rate of catalyst deactivation cannot be predicted, and while it is possible that catalyst beds can be reactivated by removal and washing, it is impossible to know how many wa sh cycles will result in adequate reactivation.

Table 3 in Attachment A summarizes cost-effectiveness calculations for an oxidation catalyst system that uses assumptions similar to those of the SCR cost-effectiveness calculations. An additional 466 tons per year of CO would be reduced at an annual cost of nearly $2,400,000, or over $5,100 per ton of CO removed. As for the SCR analysis, this estimate probably underestimates the number of catalyst beds needed each year (2), and the number of downtime events needed to replace or clean the catalyst (6 ) each year, so the cost effectiveness could easily be twice that of this “best case” scenario. Based on this analysis, proper combustion is deemed to be the most reliable, cost-effective CO c ontrol strategy for biomass-fired, stoker-type
boilers.



### 3.5 Selection of BACT for CO
Based on the analysis presented in this section, SPI proposes that BACT for CO emitted from the proposed biomass-fired stoker boiler is 0.35 lb/MMBtu on a 24-hour average basis, which is equivalent to 156.3 lb/hr at the maximum 24-hour average operating rate, and 652 tpy at the maximum annual average operating rate of the proposed boiler.Sierra Pacific Industries - Anderson Best Available Control Technology Analysis March 2010 Biomass-Fired Cogeneration Project

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# 4 PM 10 

# BACT ANALYSIS

PM 10 

### is produced by combustion processes as unburned solid carbon (soot), unburned vapors or gases that subsequently condense, and the unburnable portion of the fuel (ash).



### 4.1 Identification of Possi ble Control Alternatives

4.1.1 Combustion Controls
The concept of applying combustion controls or “proper combustion” to minimize PM 10 

### emissions is similar to the strategy used to control CO and includes adequate fuel residence time, proper fuel-air mixing, and temperature control to ensure the maximum amount of fuel is combusted. As discussed in the analysis of BACT for CO emissions, optimization of these
factors for PM 10 

### control can result in an increase in the NO X 

### emissions. Thus, operators strive to balance the factors under their control to achieve the lowest possible emissions of all pollutants.



### 4.1.2 Add-On Controls
The two most popular add-on control technologies for control of PM 10 

### emissions from a boiler are electrostatic precipitators (ESPs) and baghouses. ESPs remove particles from an exhaust stream by imposing an electrical charge on the particles and then attracting them to an oppositely charged plate. The dust collected on the charged plates is periodically removed by vibrating or rapping of the plates.

Baghouses, or fabric filters, use various types of materials (generally fabrics) to trap particles while the gas passes through the voids in the material. The dust that becomes caked on the fabric bags is removed periodically by shaking, by blowing jets of air, or by using sonic horns. Often a mechanical collector, such as a multiclone, is used to remove larger particulate matter before the exhaust reaches the primary control device.

Wet scrubbers, such as venturi scrubbers are le ss common because they typically have lower control efficiencies than either ESPs or baghouses. They also complicate waste disposal by introducing liquids that create sludge when combined with the removed PM 10 

### . A venturi is a narrowed section of duct followed by an expanded section of duct, with scrubbing liquid injected at the constricted section. The liquid in atomized by the increased velocity exhaust flow, and the particles impact the droplets and are collected. Because the liquid must be atomized to ensure high collection efficiency, a high-energy exhaust flow is required.



### 4.1.3 Control Alternative Review
The results of the database queries for PM 10 

### control technologies are presented in Table 4, sorted by permit limit, beginning with the PM 10 

### limit proposed by SPI for the new biomass-fired cogeneration unit.Sierra Pacific Industries - Anderson Best Available Control Technology Analysis March 2010 Biomass-Fired Cogeneration Project

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### A review of the RBL Clearinghouse indicates that the most stringent control technology for PM 10 

### is use of an ESP or a baghouse. The most stringent permit limit employing ESP technology to

control PM 10 

### emissions is 0.02 lb/MMBtu at Sierra Pacific Industries facilities in Aberdeen and Skagit County, Washington, Boralex in Livermore Falls, Maine, Multitrade Limited Partnership in Hurt, Virginia, and Hampton Lumber in Darrington, Washington. Until recently, many permit limits did not include both the filterable and condensable portions of particulate emissions, so some of the emission limits from permits issued several years ago may be less stringent than they appear.

The most stringent permit limit employing baghouse te chnology is at Kimberly-Clark in Everett, Washington, which has a PM 10 

### permit limit of 0.0084 gr/dscf at 7 percent oxygen, equivalent to 0.016 lb/MMBtu. However, the testing required for the Kimberly-Clark boiler is for filterable

PM 10 

### only. The Wheelabrator Ridge Energy facility in Ashland, Florida, has a permit limit of 0.008 gr/dscf at 7 percent oxygen, equivalent to 0.02 lb/MMBtu. This facility also requires only a
filterable PM 10 

### test method to confirm compliance with the permit limit. The proposed Valley BioEnergy facility in Modesto would use an ESP to limit PM 10 

### emissions to 0.02 lb/MMBtu.



### 4.1.4 Summary of Possible Control Alternatives
Based on literature and database searches the following control alternatives are possible for the
boiler:

• 

### ESP preceded by a multiclone

• 

### Baghouse

• 

### Venturi scrubber



### 4.2 Technical Feasibility of Control Alternatives
The most common technology for controlling PM 10 

### emissions from a biomass-fired boiler is an ESP preceded by a multiclone. Baghouses have been employed to control PM 10 

### emissions from fluidized-bed boilers, and boilers in which biomass is fired with solid fossil fuels such as coal or tires. The likelihood of fires in downstream ducting or control devices is significant because of the high carbon content of the ash from boilers that burn biomass fuels, but many operators and manufacturers have engineered designs to minimize this risk. ESPs, constructed mostly of metal, suffer considerably less damage from fires than baghouses, which generally have combustible fabric filters, unless expens ive flame-proof bags are purchased. Venturi scrubbers are generally employed to control PM 10 

### from smaller boilers with lower exhaust flow, and typically have lower control efficiencies than ESPs or baghouses



### 4.3 Effectiveness of Remaining Technologies
This section briefly describes the effectiveness of the remaining technologies ranks them in
order of effectiveness.March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson Best Available Control Technology Analysis

29-23586A 21 

### 4.3.1 Venturi Scrubbers
Venturi scrubbers with pressure drops of between 5 and 10 inches of water typically remove less than 99 percent of PM 10 

### from exhaust flows. Units with pressure drops of 20 inches of water or greater can remove greater than 99 percent of PM 10



### .



### 4.3.2 Baghouses
Baghouses typically operate with pressure drops between 2 and 12 inches of water. PM 10 

### control efficiencies are capable of removing over 99 percent of PM 10 

### from gas streams.



### 4.3.3 ESPs
ESPs, which typically experience pressure losses of around 0.5 inches of water, are capable of removing over 99 percent of PM 10 

### from exhaust flows.



### 4.3.4 Ranking by Effectiveness
The remaining technologically feasible control technologies ranked in decreasing order of
effectiveness are:

• 

### ESP; Baghouse (judged to be equally effective)

• 

### Venturi Scrubber



### 4.4 Cost Effectiveness Evaluation
No cost effectiveness evaluation comparing the baghouse or scrubber is presented because SPI is proposing ESP to control PM 10 

### emissions from the biomass-fired, stoker-type boiler.



### 4.5 Selection of BACT for PM 10 

### SPI proposes that BACT for PM 10 

### emissions from a biomass-fired, stoker-type boiler is an emission rate of 0.02 lb/MMBtu, equivalent to 37.3 TPY at the anticipated annual operating capacity, and achieved using a mechanical collector followed by an ESP.Sierra Pacific Industries - Anderson Best Available Control Technology Analysis March 2010 Biomass-Fired Cogeneration Project

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# 5 ROG/VOC BACT Analysis

With the exception of various chloro- and fluorocarbons, ROG is the same as EPA’s definition of volatile organic compounds (VOC). Because most permits include limits for VOCs instead of ROG, and because they are so similar, this BACT analysis is for VOC, but all statements and
conclusions could be drawn for ROG as well.

VOC emissions are generally the result of incomplete fuel combustion. In the case of biomass, volatiles are released as the fuel is heated in the furnace, some portion of which escapes combustion by improper mixing with oxygen or zones of relatively low temperature.



### 5.1 Identification of Possi ble Control Alternatives
Combustion controls, or proper combustion techniques, provide wide range of control effectiveness depending on the configuration of the sy stem. Generally, emissions resulting from incomplete combustion (CO and VOC) are balanced with emissions related to high furnace temperatures (NO X 

### ) to achieve optimally low emissions of all pollutants.

Add-on controls used to reduce VOCs generally fall into three categories: adsorption onto a solid (e.g., activated carbon), absorption by a liquid, and incineration by a flame or using a catalyst. There are no instances in the RBLC of any of these approaches having been used to
control VOCs from a biomass-fired boiler.



### 5.1.1 Control Alternative Review
The results of the database queries for VOC control technologies are presented in Table 5, sorted by permit limit, beginning with the VOC limit proposed by SPI for the new cogeneration

unit.

The only technology employed as BACT for VOC em issions from a biomass-fired boiler is maintaining proper combustion of the fuel. As shown in Table 5, permit limits vary considerably, ranging over an order of magnitude. Clearly , agencies approving permit limits for VOC have been flexible, understanding the tradeoffs between emissions of NO X 

### , CO, and VOC that are inherent to maintaining proper combustion. Two permit limits have been identified that are lower than the VOC limit proposed by SPI for the new wood-fired cogeneration unit. In both cases, higher permit limits have been deemed BACT after the lower permit limits were approved. In one case, the Maine Department of Environmental Protection determined that a limit of 0.02 lb/MMBtu was BACT for a facility constructed in 1991, and that 0.03 lb/MMBtu was BACT for another facility in 1999. In Washington, SPI’s facility in Aberdeen received permit limit for 0.025 lb/MMBtu in 2002, and SPI’s Burlington facility received a permit limit of 0.019 lb/MMBtu in 2006. The Valley BioEnergy facility in Modesto, California proposes to limit VOC emissions to 0.005 lb/MMBtu through incidental control provided by an oxidation catalyst installed primarily to reduce CO emissions and avoid PSD review.Sierra Pacific Industries - Anderson Best Available Control Technology Analysis March 2010 Biomass-Fired Cogeneration Project

24 29-23586A 

### 5.1.2 Summary of Possible Control Alternatives
Based on database queries and other research, proper combustion is the only possible VOC
control alternative for a biomass-fired boiler.



### 5.2 Technical Feasibility of Control Alternatives
Proper combustion is a technically feasible control alternative that is used to control VOC
emissions from most biomass-fired boilers. As for CO, oxidation catalysts have been installed on stoker-type, biomass-fired boilers, but this application of the technology is not mature, and has not been demonstrated in practice.



### 5.3 Effectiveness of Remaining Technologies
The effectiveness of proper combustion as a VOC control technology varies considerably, and is largely dependent on tradeoffs made in the design and operation of the boiler to minimize other pollutants (e.g., NO X 

### ).



### 5.3.1 Ranking by Effectiveness
Proper combustion is the only feasible, proven control technology for limiting VOCs from a stoker-type, biomass-fired boiler, therefore it is the most effective.



### 5.4 Cost Effectiveness Evaluation
Because proper combustion is the only remaining alternative, it is, by default, the most cost
effective.



### 5.5 Selection of BACT for ROG/VOCs
Based on the above discussion, proper combustion is proposed to be BACT for VOC emissions from the biomass-fired boiler. SPI proposes a VOC emission rate of 0.017 lb/MMBtu, equivalent to 31.7 TPY at the anticipated annual operating capacity.March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson Best Available Control Technology Analysis

29-23586A 25 

# 6 SO 2 

# BACT ANALYSIS

Sulfur dioxide (SO 2 

### ) emissions are entirely dependent upon the amount of sulfur present in the fuel. Sulfur contained in the fuel combines with oxygen at combustion temperatures to form
SO 2



### .



### 6.1 Identification of Possi ble Control Alternatives
There are two alternatives for reducing SO 2 

### emissions combustion sources: removal of sulfur from the fuel before it is combusted, and removal of SO 2 

### from the exhaust gas after combustion.

Removing sulfur from fuel before it is combusted has been employed to remove sulfurcontaining nonorganically-bound minerals (e.g., pyrites) from coal, but this practice is not feasible for biomass fuels, where the sulfur is organically bound in the fuel. All permitted
biomass-fired boilers have no SO 2 

### control requirement other than the exclusive use of biomass, and perhaps a limit on the sulfur content of a start-up or co-fired fuel.

Scrubbing, or flue gas desulfurization (FGD) systems remove SO 2 

### from the exhaust gases after they leave the furnace using a slurry of lime or limestone (some systems use sodium or other sorbent materials) and water into a chamber which the gases pass through. The sorbent in the slurry comes in contact with the SO 2 

### in the exhaust gas and reacts with it. Depending upon the design of the system, the reacted sorbent slurry can remain wet or be dried by the hot exhaust such that only dry reacted sorbent remains. In dry FGD systems and spray driers, the particulate control system (usually a fabric filter) must be sized to handle the additional load created by the SO 2 

### control system. Both wet and dry FGD systems require significantly expanded waste handling operations to remove the reacted sorbent material.



### 6.1.1 Control Alternative Review
The results of the database queries for SO 2 

### control technologies are presented in Table 6, sorted by permit limit, beginning with the SO 2 

### limit proposed by SPI for the new boiler. The RBLC does not indicate that any FGD systems have been used to reduce SO 2 

### emissions from a stoker-type, biomass-fired boiler. Based on analysis of the anticipated fuel source (almond and walnut orchard trimmings), Valley BioEnergy in Modesto, California has proposed to utilize a dry sorbent duct injection system to reduce acid gases, particularly hydrogen chloride, but the system will also reduce SO 2 

### emissions. The Valley BioEnergy has been deemed complete, but no permit has been issued, and it has not been constructed or operated.



### 6.1.2 Summary of Possible Control Alternatives
Based on literature and database searches the following control alternatives are possible for the
boiler:

• 

### NoneSierra Pacific Industries - Anderson Best Available Control Technology Analysis March 2010 Biomass-Fired Cogeneration Project

26 29-23586A

• 

### FGD



### 6.2 Technical Feasibility of Control Alternatives
FGD systems are more commonly applied to coal-fired boilers, and, while there are no apparent technical restrictions to application of FGD systems to biomass-fired boilers, there are no instances of this technology being used to reduce SO 2 

### emissions from a biomass-fired boiler.



### 6.3 Effectiveness of Remaining Technologies
Wet FGD systems are considered the most effe ctive, and can achieve greater than 90 percent
reduction in SO 2 

### emissions. Dry scrubbers and spray driers are capable of control efficiencies on the order of 90 percent.



### 6.3.1 Ranking by Effectiveness
The remaining technologically feasible control technologies ranked in decreasing order of
effectiveness are:

• 

### None

• 

### FGD



### 6.4 Cost Effectiveness Evaluation
Based on a source test conducted on the existing boiler in 2002, an SO 2 

### emission factor of approximately 0.0025 lb/MMBtu is likely, as the fuel supply for the proposed boiler is not expected to differ significantly from that of the existing boiler. Assuming that the maximum SO 2 

### emission factor for the proposed boiler is twice that indicated by the 2002 source test (0.005 lb/MMBtu), and using the trona injection system capital and operating costs used by Valley BioEnergy for a slightly smaller boiler (402 MMBtu/hr versus 425.4 MMBtu/hr), the cost per ton of SO 2 

### controlled is more than $45,000, which is clearly outside the envelope of acceptable costs.



### 6.5 Selection of BACT for SO 2 

### SPI proposes that no control system is BACT for reducing SO 2 

### emissions from a biomass-fired boiler, and that the SO 2 

### permit limit will be determined by the initial source test.March 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson Best Available Control Technology Analysis

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# 7 Beryllium BACT Analysis

Beryllium emissions are entirely a function of the beryllium content of the fuel. The RBLC contains three biomass-fired units with beryllium permit limits: one co-fires fossil fuels (oil and coal), and the other two burn tires in addition to biomass fuel. SPI proposes that no control system is BACT for reducing beryllium emissions fr om a biomass-fired boiler. An AP-42 source
test-derived emission factor of 1.55 x 10 -6 

### lb/MMBtu was used to calculate emissions from the proposed cogeneration unit (approximately 5.78 lb/yr).Sierra Pacific Industries - Anderson Best Available Control Technology Analysis March 2010 Biomass-Fired Cogeneration Project

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# 8 Cooling Tower BACT Analysis

In 2002, the Olympic Region Clean Air Agency (ORCAA) permitted a cooling tower for a new Sierra Pacific sawmill in Aberdeen, Washington. ORCAA determined that BACT for cooling towers was the use of DRU-1.5 high-efficiency mist eliminators with a drift loss of less than 0.0005 percent. This drift eliminator design is based on the D-15, originated by Munters Corporation, which is now owned by Brentwood Industries, Inc. The principal difference is that the DRU-1.5 removes the side plates on each panel, allowing the panels to be nested for a seamless installation. The water loading expected for the cooling towers is 4.24 gallons per minute per square foot (gpm/ft 2 

### ) and an air velocity of 503 feet per minute (fpm). The D-15 drift
test results indicate that the drift rate associated with these values should be less than 0.0005 percent.

Of the three most recent instances of permits issued for projects including cooling towers in the RBLC, one (Western Greenbrier Cogeneration in West Virginia, permit issued April 26, 2006) deemed 0.00005 percent drift eliminators BACT, another (Marathon Petroleum in Louisiana, permit issued December 27, 2006) deemed 0.005 percent drift eliminators BACT, and the third (Valero Refining in Louisiana, permit issued Feburary 8, 2007) deemed drift eliminators BACT without specifying an effectiveness. The cooling tower proposed for the new cogeneration unit project at SPI’s Anderson lumber manufacturing facility would use the same high-efficiency mist eliminators as the cogeneration unit cooling towers at SPI’s Aberdeen and Burlington facilities in Washington, and SPI proposes that this technology remains BACT for cooling towers.Sierra Pacific Industries - Anderson Best Available Control Technology Analysis March 2010 Biomass-Fired Cogeneration Project

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## TablesSierra Pacific Industries – Anderson ATC and PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

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### (This page intentionally left blank.)March 2010Biomass-Fired Cogeneration ProjectSierra Pacific Industries – AndersonATC and PSD Permit Application29-23586A33Table 1NOXControl Technology Search ResultsFacility Name LocationDate ofPermitHeat Input(MMBtu/hr)Permit Limit(lb/MMBtu)ControlTechnology Basis NotesSierra Pacific Industries Anderson,CA Proposed 425 0.13 SNCR BACT-OTHERValley BioEnergy Modesto, CA Proposed 4020.012 SNCR/SCR BACT-OTHER Not permittedRussell Biomass Russell, MA 12/30/08 740 0.06 RSCR LAER-OTHERNot constructed;annual avgConcord Steam Concord, NH 2/27/09 305 0.065 SCR LAER-OTHERNot constructed;30-day rolling avgDarringtonCogenerationDarrington, WA 1/18/05 4030.12/0.1 SNCR BACT-PSDNot constructed;0.1 annual avgSierra Pacific Industries Burlington, WA 1/25/06 430 0.13 SNCR BACT-PSDSierra Pacific Industries Aberdeen, WA 10/17/02 310 0.15/0.1 SNCR BACT-PSD 0.1 is annual avgVirginia DPU Virginia, MN 6/30/06 230 0.15 SNCR BACT-PSD 30-day averageHibbing PUC Hibbing, MN 6/30/06 2300.15 SNCR BACT-PSD 30-day averageHampton Lumber Darrington, WA6/1/05 245 0.15 SNCR BACT-OTHERDistrict Energy St. Paul St. Paul, MN 11/15/01 550 0.15 SNCR BACT-PSDSimpson Tacoma Kraft Tacoma, WA 5/22/07 595 0.20 Proper combustion BACT-PSDBoise Cascade Florien, LA 7/18/07225 0.22 Proper combustion BACT-PSDBoralex, Stratton Stratton, ME1/4/05 672 0.24 SNCR/RSCR BACT-OTHERKoda Energy Shakopee, MN 8/23/07 308 0.25 SNCR BACT-PSDU.S. Sugar Clewiston, FL 12/6/07738 0.31 Proper combustion BACT-PSDBridgewater Power Bridgewater, NH 9/12/07 250 0.33/0.075 SNCR/RSCR RACT/OTHER 0.075 quarterly avgDG Whitefield Whitefield, NH 9/10/04 220 0.33/0.075 RSCR RACT/OTHER 0.075 quarterly avgSouth Point Power South Point, OH 4/4/06 318 0.44 SCR BACT-PSD Not constructedSierra Pacific Industries – AndersonATC and PSD Permit ApplicationMarch 2010Biomass-Fired Cogeneration Project34 29-23586ATable 2NOXControl Technology Cost-Effectiveness ComparisonControl SystemAnnual Cost($/yr)NOXReduction(tpy)Cost Effectivness($/ton)IncrementalCost Effectiveness($/ton)SNCR 203,318 130.4 1,559 N/ASCR 1,318,989 260.9 5,056 8,554March 2010Biomass-Fired Cogeneration ProjectSierra Pacific Industries – AndersonATC and PSD Permit Application29-23586A35Table 3CO Control Technology Search ResultsFacility Name LocationDate ofPermitHeat Input(MMBtu/hr)Permit Limit(lb/MMBtu)ControlTechnology Basis NotesSierra Pacific Industries Anderson, CAProposed 425 0.35 Proper combustion BACT-OTHERValley Bio-Energy Modesto, CA Proposed 402 0.046Oxidation catalyst BACT-OTHER Not permittedRussell Biomass Russell, MA 12/30/08 7400.075 Oxidation catalyst BACT-OTHERNot constructed;annual avgSouth Point Power South Point, OH 4/4/06 318 0.10Oxidation catalyst BACT-PSD Not constructedHampton Lumber Darrington, WA 6/1/05 245 0.23 Proper combustion BACT-OTHER Fuel-cell designVirginia DPU Virginia, MN 6/30/06230 0.3 Proper combustion BACT-PSDHibbing PUC Hibbing, MN 6/30/06 230 0.3 Proper combustion BACT-PSDDistrict Energy St. Paul St. Paul, MN11/15/01 550 0.3 Proper combustion BACT-PSDWillamette Industries, Inc. Marlboro, SC4/17/96 470 0.3 Proper combustion BACT-OTHERBoralex Ashland Ashland, ME 4/2/92 586 0.3 Proper combustion BACT-OTHERSierra Pacific Industries Burlington, WA1/25/06 430 0.35 Proper combustion BACT-PSDDarrington Cogeneration Darrington,WA 1/18/05 403 0.35 Proper combustion BACT-PSD Not constructedSierra Pacific Industries Aberdeen, WA10/17/02 310 0.35 Proper combustion BACT-PSDKES Chateaugay Project Chateaugay, NY 12/19/94275 0.35 Proper combustion BACT-OTHERPittsylvania Power Hurt, VA 2/21/92374 0.35 Proper combustion BACT-PSDSmurfit-Stone Container Stevenson, AL 1/15/97 620 0.4 Proper combustion BACT-PSDWeyerhaeuser Company Bruce, MS 5/9/95 90 0.4 Proper combustion BACT-PSDGulf States Paper Corp Moundville, AL10/14/98 98 0.5 Proper combustion BACT-PSDBio Energy Corp. West Hopkinton, NH 7/23/98 225 1.0/0.253 Oxidationcatalyst BACT-OTHERNot operating;0.253 annual avgPlum Creek – Columbia Falls Columbia Falls, MT 7/26/95 292 1.6 Proper combustion BACT-PSDSierra Pacific Industries – AndersonATC and PSD Permit ApplicationMarch 2010Biomass-Fired Cogeneration Project36 29-23586ATable 4PM10Control Technology Search ResultsFacility Name LocationDate ofPermitHeat Input(MMBtu/hr)Permit Limit(lb/MMBtu)ControlTechnology Basis NotesSierra Pacific Industries Anderson, CAProposed 425 0.015 Multiclone, ESP BACT-OTHERValley Bio-Energy Modesto, CA Proposed 402 0.02 Multiclone, ESP BACT-OTHER Not permittedSouth Point Power South Point, OH 4/4/06 318 0.0125 Baghouse BACT-PSDNot constructed;filterable onlySimpson Tacoma Kraft Tacoma,WA 5/22/07 595 0.02 ESP BACT-PSDSierra Pacific Industries Burlington, WA1/25/06 430 0.02 Multiclone, ESP BACT-PSDHampton Lumber Darrington, WA 6/1/05245 0.02 Multiclone, ESP BACT-OTHERDarrington Cogeneration Darrington,WA 1/18/05 403 0.02 Multiclone,ESP BACT-PSD Not constructedSierra Pacific Industries Aberdeen, WA10/17/02 315 0.02 Mulitclone, ESP BACT-PSDDecker Energy International East Ryegate, VT7/11/90 300 0.02 Mech. Collector, ESP BACT-PSDBoralex Livermore Falls, ME 9/5/91 534 0.02 Multiclone, ESP BACT-PSDPittsylvania Power Hurt, VA 2/21/92374 0.02 Multiclone, ESP BACT-PSDRussell Biomass Russell, MA 12/30/08740 0.026 Multiclone, ESP BACT-OTHERNot constructed;annual avgSmurfit-Stone Container Stevenson, AL1/15/97 620 0.03 Multiclone, ESP BACT-PSDWheelabrator Sherman Energy Sherman Station, ME 4/9/99 630 0.036 Baghouse BACT-PSDBoralex Chateaugay, NY 12/19/94 275 0.038 Multiclone, ESP BACTWillamette Industries, Inc. Marlboro, SC 4/17/96 470 0.05 ESP BACT-OTHERGulf States Paper Corp. Moundville, AL10/14/98 98 0.1 Multiclone, ESP BACT-PSDWeyerhaeuser Co. Millport, AL 10/28/9491 0.15 Venturi Scrubber BACT-PSDMarch 2010Biomass-Fired Cogeneration ProjectSierra Pacific Industries – AndersonATC and PSD Permit Application29-23586A37Table 5ROG/VOC Control Technology Search ResultsFacility Name LocationDate ofPermitHeat Input(MMBtu/hr)Emission Factor(lb/MMBtu)ControlTechnology Basis NotesSierra Pacific Industries Anderson, CAProposed 425 0.017 Proper combustion BACT-OTHERValley Bio-Energy Modesto, CA Proposed 402 0.005Oxidation catalyst BACT-OTHER Not permittedRussell Biomass Russell, MA 12/30/08 7400.01 Oxidation catalyst BACT-OTHERNot constructed;annual avgDuke Solutions Evendale, OH 11/24/99 28.7 0.01 Proper combustion OTHERNo testingrequiredSouth Point Power South Point, OH 4/4/06 318 0.013Oxidation catalyst BACT-PSD Not constructedBoise Cascade Florien, LA 7/18/07225 0.017 Proper combustion BACT-PSDSierra Pacific Industries Burlington, WA1/25/06 430 0.019 Proper combustion BACT-PSDHampton Lumber Darrington, WA 6/1/05245 0.025 Proper combustion BACT-OTHERDarrington Cogeneration Darrington, WA1/18/05 403 0.025 Proper combustion BACT-OTHER Not constructedSierra Pacific Industries Aberdeen, WA10/17/02 310 0.025 Proper combustion BACT-PSDWheelabrator Sherman Energy Co. Penobscott, ME4/9/99 315 0.03 Proper combustion BACT-PSDPotlatch Corp. Ozan, AR 7/26/05175 0.034 Proper combustion BACT-PSDSouthern Soya Corp. Estill, SC 10/2/95 58 0.05 Proper combustion LAERSierra Pacific Industries – AndersonATC and PSD Permit ApplicationMarch 2010Biomass-Fired Cogeneration Project38 29-23586ATable 6SO2Control Technology Search ResultsFacility Name LocationDate ofPermitHeat Input(MMBtu/hr)Emission Factor(lb/MMBtu)ControlTechnology Basis NotesSierra Pacific Industries Anderson, CA Proposed 425 -- None BACT-OTHEREF to bedeterminedValley Bio-Energy Modesto, CA Proposed 402 0.012 Acid gas scrubber BACT-OTHER Not permittedDuke Solutions Evendale, OH11/24/99 28.7 0.01 None OTHERNo testingrequiredRussell Biomass Russell, MA 12/30/08 740 0.025 Fuelspecification BACT-OTHER Not constructedSierra Pacific Industries Burlington, WA 1/25/06 430 0.025 None BACT-PSDHampton Lumber Darrington, WA6/1/05 245 0.025 None BACT-OTHERDarrington Cogeneration Darrington,WA 1/18/05 403 0.025 None BACT-OTHER Not constructedSierra Pacific Industries Aberdeen,WA 10/17/02 310 0.025 None BACT-PSDSouth Point Power South Point, OH 4/4/06 318 0.087 Acid gas scrubber BACT-PSD Not constructedSmurfit-Stone Container Stevenson,AL 7/14/06 620 0.15 None BACT-PSDWillamette Industries, Inc. Marlboro,SC 4/17/96 470 0.1 None BACT-OTHERWheelabrator Sherman Energy Co. Penobscott, ME4/9/99 315 0.12 Fuel specification BACT-PSDGulf States Paper Corp Demopolis, AL12/10/97 775 0.46 Proper combustion BACT-PSDNorthern Sun ADM Enderlin, ND 5/1/06 280 0.47 None BACT-PSDMarch 2010 Biomass-Fired Cogeneration Project Sierra Pacific Industries – Anderson ATC and PSD Permit Application

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## Appendix A:

Cost-Effectiveness CalculationsSierra Pacific Industries – Anderson ATC and PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

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## Appendix C:
Air Quality Dispersion Modeling Files (CD)Sierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

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## Appendix D:

Communications From FLMsSierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

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29-23586ASierra Pacific Industries – Anderson ATC/PSD Permit Application March 2010 Biomass-Fired Cogeneration Project

29-23586A File Code: 

### 2580-3

Date: 

### February 5, 2010

Eric Albright
ENVIRON International
19020 33rd Ave West
Suite #310 Lynnwood, WA 98036

Dear Mr. Albright:

On November 17, 2009, we received a memo from you on behalf of Sierra Pacific Industries (SPI) notifying us of the planned modification to the original wood-fired boiler at the SPI facility in Anderson, California. The steam production capacity of the boiler is proposed to increase from 200,000 lbs/hr to 250,000 lbs/hr.

The total emissions (for NO
x 

### , SO
x 

### , and PM 10 

### ) is proposed to increase from 256 tpy (tons per year) to 320 tpy. The closest Class I area is Yolla Bolly-Middle Eel Wilderness which lies 57 miles from the facility.

We are currently utilizing a methodology to screen proposed facilities from the more intensive analysis requirements. Based on a combination of emissions and distance from the Class I area, we have determined that this facility will not require further analysis. However, if SPI further modifies this facility in the future, we will request analysis on total emissions and not those resulting from the modification alone.

Thanks again for the opportunity to be involved in the review process. If you have any questions, please contact Trent Procter at 559-784-1500, x1114 / tprocter@fs.fed.us or Dr. Suraj Ahuja at 530-521-7394 / sahuja@fs.fed.us/

. Sincerely,

/S/ JAMES M. PEÑA (FOR)

RANDY MOORE
Regional Forester