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: 

29-23586A

March 2010 

Biomass-Fired Cogeneration Project 

 Sierra Pacific Industries – Anderson 

ATC/PSD Permit Application 

29-23586A i 

Contents 

 Page 

1 Introduction............................................................................................................................................. 1

1.1 Organization..................................................................................................................................... 1

1.2 Summary of Findings ....................................................................................................................... 2

2 Project Description ................................................................................................................................. 3

2.1 Physical Description......................................................................................................................... 3

2.2 Fuel Supply ...................................................................................................................................... 3

2.3 Pollutant Emission Rates ................................................................................................................. 4

2.3.1 Criteria Pollutants .................................................................................................................... 4

2.3.2 Startup Emissions ................................................................................................................... 5

2.3.3 Toxic Air Contaminants ........................................................................................................... 6

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

3.1 Federal Regulations......................................................................................................................... 7

3.1.1 Prevention of Significant Deterioration.................................................................................... 7

3.1.2 Acid Rain Program .................................................................................................................. 7

3.1.3 Air Operating Permit Program................................................................................................. 8

3.1.4 New Source Performance Standards...................................................................................... 8

3.1.5 Maximum Achievable Control Technology.............................................................................. 8

3.2 State And Local Emission Regulations............................................................................................ 9

3.2.1 Authority to Construct Permits ................................................................................................ 9

3.2.2 District Air Pollution Control Regulations .............................................................................. 10

3.2.3 Air Toxics Hot Spots (AB 2588) ............................................................................................ 10

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

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

4 Air Quality Impacts Analysis................................................................................................................. 11

4.1 Model Selection.............................................................................................................................. 11

4.2 Modeling Procedures ..................................................................................................................... 12

4.2.1 Model Setup and Application ................................................................................................ 12

4.2.2 Averaging Periods ................................................................................................................. 12

4.2.3 Chemical Transformations .................................................................................................... 12

4.3 Elevation Data and Receptor Network........................................................................................... 12

4.4 Meteorological Data ....................................................................................................................... 13

4.5 Emission Source Release Parameters.......................................................................................... 13

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

4.7 Startup Analysis ............................................................................................................................. 15

4.8 Secondary Impact Analysis............................................................................................................ 15

4.8.1 Class II Area Growth ............................................................................................................. 15

4.8.2 Class II Visibility .................................................................................................................... 16

4.8.3 Soils and Vegetation ............................................................................................................. 16

5 Class I Air Quality Impacts and Air Quality Related Values Analyses ................................................. 19
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List of Tables 

Table 2-1 Proposed Cogeneration Unit Emissions.....................................................................................23

Table 2-2 Project Criteria Pollutant Emissions Increase ............................................................................24

Table 2-3 Project Emission Rates and BACT Thresholds..........................................................................25

Table 2-4 Cogeneration Unit Toxic Air Contaminant Emission Rates........................................................26

Table 3-1 Hazardous Air Pollutant Emission Rates....................................................................................30

Table 4-1 Point Source Release Parameters .............................................................................................31

Table 4-2 Structure Heights ........................................................................................................................32

Table 4-3 Criteria Pollutant NAAQS Compliance Assessment...................................................................33

Table 4-4 Criteria Pollutant CAAQS Compliance Assessment...................................................................34

Table 5-1 Distances from Proposed Project to Nearby Class I Areas........................................................35

Table 5-2 Summary of Q/D Analysis...........................................................................................................35

List of Figures 

Figure 2-1. Project Schematic Flow Diagram ............................................................................................39

Figure 2-2. Vicinity of Facility and Modeling Domain.................................................................................41

Figure 4-1. Final Receptor Locations.........................................................................................................42

Figure 4-2. Wind Rose, Redding Municipal Airport, Jan. 2004 to Dec. 2008............................................43

Figure 4-3. Source and Significant Structure Locations ............................................................................45

Figure 4-4. Maximum Predicted 1-Hour Average CO Concentrations ......................................................47

Figure 4-5. Maximum Predicted 8-Hour Average CO Concentrations ......................................................48

Figure 4-6. Maximum Predicted 1-Hour Average SO2 Concentrations .....................................................49

Figure 4-7. Maximum Predicted 3-Hour Average SO2 Concentrations .....................................................50

Figure 4-8. Maximum Predicted 24-Hour Average SO2 Concentrations ...................................................51

Figure 4-9. Maximum Predicted Annual Average SO2 Concentrations.....................................................52

Figure 4-10. Maximum Predicted 24-Hour Average PM10 Concentrations................................................53

Figure 4-11. Maximum Predicted Annual Average PM10 Concentrations .................................................54

Figure 4-12. Maximum Predicted 1-Hour Average NO2 Concentrations...................................................55

Figure 4-13. Maximum Predicted Annual Average NO2 Concentrations...................................................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 FLMs
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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 lumber 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 obtain 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. 
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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. 
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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 turbine 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-pressure 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 selective non-catalytic reduction (SNCR) system that 

uses annhydrous ammonia to reduce emissions of oxides of nitrogen (NOX), as well as a 

multiclone and electrostatic precipitator (ESP) to control emissions of particulate matter 

(PM/PM10). 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 wastes 
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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 approximately 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 emissions 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 NOX, carbon monoxide (CO), particulate matter smaller than ten microns (PM10), 

PM, sulfur dioxide (SO2), 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 NOX, CO, PM10, and VOCs were based on the 

BACT anslysis and expected guarantees from the boiler and control device manufacturers or 

vendors. The SO2 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 PM10. 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 PM10 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: 

• NOX – 0.13 lb/MMBtu (30-day average) 

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

• PM10 – 0.02 lb/MMBtu (3-hour average) including filterable and condensable components 
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SPI does not believe limits are warranted for SO2 or VOC emissions from the cogeneration unit 

or for PM10 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 emission 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 CO2 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 CO2 as is commonly done for normal operation limits. SPI proposes a 

startup and shutdown CO emission rate limit 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. 
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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 boilers 

were 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 chromium 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 (NH3) emission rate was based on 

a maximum exhaust ammonia concentration of 20 parts per million (ppm). Ammonia emissions 

are a consequence of operating an SNCR system to reduce boiler NOX 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. 
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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 PM10 standards. 

3.1 Federal Regulations 

3.1.1 Prevention of Significant 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 NOX, CO, and PM10 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, NOX, CO, and PM10). 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 SO2 and NOX, 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. 
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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 PM10 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 SO2 and NOX

limits on boilers that fire fossil fuels under certain conditions. The SO2 limits do not apply to 

boilers that combust natural gas. The NOX 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 SO2 nor the NOX 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 is 
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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 proposed 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), NOX, SO2, PM10, 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 maximum annual throughput of 180 million board feet per year 

(MMbf/yr). This throughput was divided into species-specific annual throughputs (i.e., for ponderosa pine, sugar 

pine, Douglas fir, and white fir) based on the average throughput fraction of each species using data from 2007 and 

2006. The maximum annual species throughputs were combined with emission factors for acetaldehyde, acrolein, 

formaldehyde, methanol, and propionaldehyde developed by the Oregon Department of Environmental Quality. 
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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 state 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 Pollution 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 PM10 is limited to 

0.05 gr/dscf, and combustion PM is limited to 0.10 gr/dscf. SO2 emissions are limited to 

200 ppm, and NOX 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 PM10 ambient air quality standards, it 

has further been classified as having “moderate air pollution.” Areas that are not classified has 

having “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. 
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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 areas 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 domain, 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 effects a structure may have on an exhaust plume 

implicitly. Importantly, the PRIME algorithm also treats the 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. Additionally, 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. 
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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 NOX is 

converted to NO2. 

4.3 Elevation Data and Receptor Network 

Terrain elevations for receptors and emission sources were prepared using 1/3rd arc-second 

National Elevation Dataset (NED) data developed by the United States Geological Survey 

(USGS), and available on the internet from 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. 
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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). 
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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 simulations 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. 
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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/m3

, 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, California5

 The maximum 1-hour and 8-hour average concentrations 

were 3.1 ppm (approximately 3,550 μg/m3

) and 2.4 ppm (approximately 2,750 μg/m3), 

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/m3

, and an 8-hour average of 2,932 μg/m3. These concentrations are less than the 1-

hour and 8-hour average CO CAAQS of 23,000 and 10,000 μg/m3

, respectively (the 

corresponding NAAQS are 40,000 and 10,000 μg/m3

). 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 Manzantia Ave. in Chico, 

California; data obtained from EPA’s AirData website (http://www.epa.gov/aqspubl1/annual_summary.html) 
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vehicle miles traveled and vehicular emissions associated with temporary workers would be 

insignificant. Once the cogeneration unit is operational, 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 sensitive 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 caused 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 NO2 and SO2. 

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 required 
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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 the 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. 
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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 NOX, SO2, PM10, and sulfuric acid mist (H2SO4), 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, NOX and PM10

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 the 
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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. 
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Tables
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Table 2-1 

Proposed Cogeneration Unit Emissions 

Emission Rate2

Pollutant1

Emission Factor1

(lb/MMBtu) (lb/hr) (TPY) 

NOx 0.13 60.8 242 

CO 0.35 164 652 

SO2 0.005 2.34 9.32 

PM10 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 NOx, CO, and PM10 emission factors are based on BACT and vendor guarantees. The SO2 emission 

factor is based on a source test conducted on the existing boiler at the facility. The VOC/ROG emission 

factor is based on a vendor guarantee. The sulfuric acid (H2SO4) emission factor is based on the 

assumption that sulfate comprises 10.038 percent of PM10 emissions, which was obtained from USEPA’s 

SPECIATE 3.2 Profile # 12709 for Hogged Fuel Boiler/Stoker 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 maximum 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). 
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Table 2-2 

Project Criteria Pollutant Emissions Increase 

Annual Emission Rate2

(TPY) 

Pollutant1 Cogen CT Total 

PSD 

SER3

(TPY) 

Over 

SER? 

NOx 242 -- 242 40 Yes 

CO 652 -- 652 100 Yes 

SO2 9.32 -- 9.32 40 No 

PM10/PM2.5 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 NOx, CO, PM10, and VOC/ROG emission factors are based on BACT and/or vendor guarantees, while 

the SO2 emission factor is based on a source test conducted on the existing boiler at the facility. The 

sulfuric acid (H2SO4) emission factor is based on the assumption that sulfate comprises 10.038 percent 

of PM10 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). 
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Table 2-3 

Project Emission Rates and BACT Thresholds 

Hourly Emission Rate2

(lb/hr) 

24-Hr Emission Rate3

(lb/day) 

Pollutant1

Cogen CT Total Cogen CT Total 

AQMD 

BACT 

Thresh.4

(lb/day) 

Over 

BACT 

Thresh? 

NOx 60.8 -- 60.8 1,394 -- 1,394 25.0 Yes 

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

SO2 7.49 -- 7.49 172 -- 172 80.0 Yes 

PM/PM10 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 NOx, CO, PM10, and VOC/ROG emission factors are based on vendor guarantees, while the SO2

emission factor is based on a source test conducted on the existing boiler at the facility. The sulfuric acid 

(H2SO4) emission factor is based on the assumption that sulfate comprises 10.038 percent of PM10

emissions, which was obtained from USEPA’s SPECIATE 3.2 Profile # 12709 for Hogged Fuel 

Boiler/Stoker Boiler. Lead, beryllium, mercury, and vinyl chloride emission factors were based on the 

source test data used to develop the emission 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. 
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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 

Ammonia4 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 (CO2)

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 2,950 
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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, hexavalent4 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 0.00885 
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ATC/PSD Permit Application 

March 2010 

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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 

Methane5 74-82-8 7.05E-02 33 756 263,000 

Methanol6 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 (N2O)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 37.5 
March 2010 

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Emission Rate 

Compound CAS No. 

Emission Factor

(lb/MMBtu) (lb/hr)1

 (lb/day)2 (lb/yr)3

Sulfuric Acid7 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 CO2, CH4, and N2O 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 NOX was assumed be NO, which is conservative because 75 percent of NOX was 

assumed to be converted to NO2. 
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Table 3-1 

Hazardous Air Pollutant Emission Rates 

Compound CAS No. 

Emission 

Rate1 Compound CAS No. Emission Rate1

Acetaldehyde2 75-07-0 9.05 Formaldehyde2 50-00-0 3.857 

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

Acrolein2 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 Methanol2 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 Pentachlorophenol 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 Propionaldehyde2 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 

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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 91 
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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 4.88 
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Table 4-3 

Criteria Pollutant NAAQS Compliance Assessment 

Pollutant 

Averaging 

Period 

Maximum 

Predicted1 SIL1,2

Over 

SIL? 

Monitoring 

de 

Minimis1,3

Over de 

Minimis? 

1-Hour 12.3 -- -- -- -- 

NO2

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 

PM10

Annual 0.213 1 No -- --

24-Hour 1.43 -- -- -- -- 

PM2.5

5

Annual 0.213 -- -- -- -- 

3-Hour 2.04 25 No -- --

SO2 24-Hour 1.09 5 No 13 No 

Annual 0.149 1 No -- --

1 Concentrations are in micrograms per cubic meter (μg/m3) 

2 SIL = Significant Impact Level, from USEPA’s New Source Review Workshop Manual (October, 1990), 

Table C-4. 

3 Monitoring de Minimis concentrations from 40 CFR 52.21(i)(8)(i). 

4 NO2 was assumed to be 75 percent of the emitted NOX 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 NO2 concentration shown is the maximum 8th-highest daily 1-hour maximum concentration 

averaged across the five modeled years. SILs and monitoring de minimis concentrations have not yet 

been established for NO2. A NAAQS compliance assessment was performed by combining the modeled 

NO2 concentration with a background concentration. Because 3-year average of the 98th percentile of 

the annual distribution of the daily maximum 1-hour average NO2 concentrations are not yet available for 

recent ambient monitoring data to use as a background concentration, the maximum 1-hour average NO2

concentration from the monitor at 468 Manzanita Ave in Chico, California was used as a background, 

which is a conservative approach. Adding the modeled concentration (12.3 μg/m3

) to the background 

(80.9 μg/m3

) gives a total concentration of 93.2 μg/m3, which is less than the applicable NAAQS 

(188 μg/m3

). 

5 SILs and monitoring de minimis concentrations have not yet been established for PM2.5. A NAAQS 

compliance assessment was performed by combining the modeled PM2.5 concentrations (which assume 

that all PM10 is PM2.5) with the most recent maximum concentrations from the monitor on the roof of the 

Redding Department of Health (24-hour average – 20.2 μg/m3

, and annual average – 5.49 μg/m3), gives 

total concentrations of 21.7 μg/m3

 (24-hour average) and 5.73 μg/m3 (annual average), which are less 

than the applicable NAAQS (24-hour average – 35 μg/m3

, and annual average – 15 μg/m3). 
Sierra Pacific Industries – Anderson 

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Table 4-4 

Criteria Pollutant CAAQS Compliance Assessment 

Pollutant 

Averaging 

Period 

Maximum 

Predicted1

Background 2

 Total3 CAAQS 

Over 

CAAQS?

1-Hour 14.0 80.9 94.9 339 No 

NO2

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 

PM10

Annual 0.213 18.2 18.4 20 No

PM2.5

5

 Annual 0.213 5.49 5.70 12 No 

1-Hour 2.30 7.85 10.1 655 No 

SO2

24-Hour 1.09 5.23 6.32 105 No

1 Concentrations are in micrograms per cubic meter (μg/m3) 

2 Background concentrations are the most recent maximum monitored concentrations (with exceptional 

event data removed, where applicable) from the following stations and years: 

 NO2 & CO: Chico – Manzanita Ave; 2008 

 PM10: Anderson – North Street; 2009 

 PM2.5: Redding – Health Department Roof; 2009 

 SO2: North Highlands – Blackfoot Way; 2009 

 Monitoring data are from EPA’s AirData website (http://www.epa.gov/aqspubl1/annual_summary.html) 

3 Total = Maximum Predicted + Background 

4 NO2 was assumed to be 75 percent of the emitted NOX 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 PM10 was assumed to be PM2.5

 
March 2010 

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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 Value1 Units 

Project NOX Emission Increase 254 tpy 

Project SO2 Emission Increase 9.78 tpy 

Project PM10 Emission Increase 39.1 tpy 

Project H2SO4 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. 
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Figures
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29-23586A 39 

Figure 2-1. Project Schematic Flow Diagram 
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Figure 2-2. Vicinity of Facility and Modeling Domain 

Sacramento River

Anderson

Cottonwood

Redding

Municipal

Airport

Redding

Modeling

Domain

SPI-Anderson

012345Miles
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March 2010

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Figure 4-1. Final Receptor Locations

552000 553000 554000 555000 556000 557000 558000 559000 560000 561000 562000 563000

UTM Easting (meters)

4475000

4476000

4477000

4478000

4479000

4480000

4481000

4482000

4483000

4484000

4485000

4486000

UTM Northing (meters)
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Figure 4-2. Wind Rose, Redding Municipal Airport, Jan. 2004 to Dec. 2008 
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Figure 4-3. Source and Significant Structure Locations 

1

2

3 4

7

8

9

10

12

13

14

15

16

17

18

19

20

21

1 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 Stack

0 250 500 

Property Boundary
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Figure 4-4. Maximum Predicted 1-Hour Average CO Concentrations 

Concentration isopleths in micrograms per cubic meter (μg/m3) 

553000 554000 555000 556000 557000 558000 559000 560000 561000 562000

UTM Easting (meters)

4476000

4477000

4478000

4479000

4480000

4481000

4482000

4483000

4484000

4485000

UTM Northing (meters)

= maximum predicted concentration (86.3 μg/m3)
Sierra Pacific Industries – Anderson 

ATC/PSD Permit Application 

March 2010

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Figure 4-5. Maximum Predicted 8-Hour Average CO Concentrations 

Concentration isopleths in micrograms per cubic meter (μg/m3) 

553000 554000 555000 556000 557000 558000 559000 560000 561000 562000

UTM Easting (meters)

4476000

4477000

4478000

4479000

4480000

4481000

4482000

4483000

4484000

4485000

UTM Northing (meters)

= maximum predicted concentration (63.0 μg/m3)
March 2010 

Biomass-Fired Cogeneration Project 

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Figure 4-6. Maximum Predicted 1-Hour Average SO2 Concentrations 

Concentration isopleths in micrograms per cubic meter (μg/m3

) 

553000 554000 555000 556000 557000 558000 559000 560000 561000 562000

UTM Easting (meters)

4476000

4477000

4478000

4479000

4480000

4481000

4482000

4483000

4484000

4485000

UTM Northing (meters)

= maximum predicted concentration (2.30 μg/m3)
Sierra Pacific Industries – Anderson 

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March 2010

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Figure 4-7. Maximum Predicted 3-Hour Average SO2 Concentrations 

Concentration isopleths in micrograms per cubic meter (μg/m3

) 

553000 554000 555000 556000 557000 558000 559000 560000 561000 562000

UTM Easting (meters)

4476000

4477000

4478000

4479000

4480000

4481000

4482000

4483000

4484000

4485000

UTM Northing (meters)

= maximum predicted concentration (2.04 μg/m3)
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Figure 4-8. Maximum Predicted 24-Hour Average SO2 Concentrations 

Concentration isopleths in micrograms per cubic meter (μg/m3) 

553000 554000 555000 556000 557000 558000 559000 560000 561000 562000

UTM Easting (meters)

4476000

4477000

4478000

4479000

4480000

4481000

4482000

4483000

4484000

4485000

UTM Northing (meters)

= maximum predicted concentration (1.09 μg/m3)
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March 2010

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Figure 4-9. Maximum Predicted Annual Average SO2 Concentrations 

Concentration isopleths in micrograms per cubic meter (μg/m3

) 

553000 554000 555000 556000 557000 558000 559000 560000 561000 562000

UTM Easting (meters)

4476000

4477000

4478000

4479000

4480000

4481000

4482000

4483000

4484000

4485000

UTM Northing (meters)

= maximum predicted concentration (0.149 μg/m3)
March 2010 

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Figure 4-10. Maximum Predicted 24-Hour Average PM10 Concentrations 

Concentration isopleths in micrograms per cubic meter (μg/m3) 

553000 554000 555000 556000 557000 558000 559000 560000 561000 562000

UTM Easting (meters)

4476000

4477000

4478000

4479000

4480000

4481000

4482000

4483000

4484000

4485000

UTM Northing (meters)

= maximum predicted concentration (1.43 μg/m3)
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Figure 4-11. Maximum Predicted Annual Average PM10 Concentrations 

Concentration isopleths in micrograms per cubic meter (μg/m3

) 

553000 554000 555000 556000 557000 558000 559000 560000 561000 562000

UTM Easting (meters)

4476000

4477000

4478000

4479000

4480000

4481000

4482000

4483000

4484000

4485000

UTM Northing (meters)

= maximum predicted concentration (0.213 μg/m3)
March 2010 

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Figure 4-12. Maximum Predicted 1-Hour Average NO2 Concentrations 

Concentration isopleths in micrograms per cubic meter (μg/m3

) 

553000 554000 555000 556000 557000 558000 559000 560000 561000 562000

UTM Easting (meters)

4476000

4477000

4478000

4479000

4480000

4481000

4482000

4483000

4484000

4485000

UTM Northing (meters)

= maximum predicted concentration (14.0 μg/m3)
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Figure 4-13. Maximum Predicted Annual Average NO2 Concentrations 

Concentration isopleths in micrograms per cubic meter (μg/m3

) 

553000 554000 555000 556000 557000 558000 559000 560000 561000 562000

UTM Easting (meters)

4476000

4477000

4478000

4479000

4480000

4481000

4482000

4483000

4484000

4485000

UTM Northing (meters)

= maximum predicted concentration (0.906 μg/m3)
March 2010 

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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

Nevada
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Appendix A:

SCAQMD Forms
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 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 Shasta 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 plan and area map indicating receptors within 1/4 mile of the facility. 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 appropriate 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/PROPERTY OWNER AGREES TO DEFEND, INDEMNIFY, AND HOLD THE SHASTA COUNTY AIR QUALITY MANAGEMENT 

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 boiler or process heater? Generate steam for lumber drying kilns and to generate electricity 

 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 

NO2

 (as ppmv at 7% O2, dry, or lb/MMBtu) 

0.13 lb/MMBtu 

INSIDE DIAMETER OF EXHAUST STACK 

 (in feet) 

8.0 feet 

CO

 (as ppmv at 7% O2, 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% O2, dry) 

20 ppmvd @ 3% 

O2

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% 

SO2 

 (as ppmv at 12% CO2, std conditions) 

2.0 ppmvd @ 

12% CO2

TEMPERATURE OF EXHAUST AIR 

 (in OF) 

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% O2, dry) 

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

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

If the boiler/process heater has a rated heat 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 requested. 

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 additional 

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 Permitting Forms\18 Boiler Supplemental.wpd
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Appendix B:

BACT Analysis
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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: 

29-23586A

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Contents 

 Page 

1 Introduction ...................................................................................................................................... 1

1.1 BACT Review Process ................................................................................................................1

1.2 Technical Feasibility ....................................................................................................................2

1.3 Economic Justifiability..................................................................................................................3

2 NOX BACT Analysis ......................................................................................................................... 5

2.1 Identification of Possible Control Alternatives .............................................................................5

2.2 Technical Feasibility of Control Alternatives................................................................................8

2.3 Effectiveness of Remaining Technologies ................................................................................10

2.4 Cost-Effectiveness Evaluation...................................................................................................11

2.5 Selection of BACT for NOX ........................................................................................................12

3 CO BACT Analysis......................................................................................................................... 13

3.1 Identification of Possible Control Alternatives ...........................................................................13

3.2 Technical Feasibility of Control Alternatives..............................................................................15

3.3 Effectiveness of Remaining Technologies ................................................................................16

3.4 Cost Effectiveness Evaluation ...................................................................................................17

3.5 Selection of BACT for CO..........................................................................................................17

4 PM10 BACT ANALYSIS.................................................................................................................. 19

4.1 Identification of Possible Control Alternatives ...........................................................................19

4.2 Technical Feasibility of Control Alternatives..............................................................................20

4.3 Effectiveness of Remaining Technologies ................................................................................20

4.4 Cost Effectiveness Evaluation ...................................................................................................21

4.5 Selection of BACT for PM10 .......................................................................................................21

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

5.1 Identification of Possible Control Alternatives ...........................................................................23

5.2 Technical Feasibility of Control Alternatives..............................................................................24

5.3 Effectiveness of Remaining Technologies ................................................................................24

5.4 Cost Effectiveness Evaluation ...................................................................................................24

5.5 Selection of BACT for ROG/VOCs ............................................................................................24

6 SO2 BACT ANALYSIS ................................................................................................................... 25

6.1 Identification of Possible Control Alternatives ...........................................................................25

6.2 Technical Feasibility of Control Alternatives..............................................................................26

6.3 Effectiveness of Remaining Technologies ................................................................................26

6.4 Cost Effectiveness Evaluation ...................................................................................................26

6.5 Selection of BACT for SO2.........................................................................................................26

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

8 Cooling Tower BACT Analysis....................................................................................................... 29
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List of Tables 

 Page 

Table 1 NOX Control Technology Search Results ...................................................................................... 33

Table 2 NOX Control Technology Cost-Effectiveness Comparison............................................................ 34

Table 3 CO Control Technology Search Results........................................................................................ 35

Table 4 PM10 Control Technology Search Results ..................................................................................... 36

Table 5 ROG/VOC Control Technology Search Results ............................................................................ 37

Table 6 SO2 Control Technology Search Results....................................................................................... 38

List of Appendices 

Appendix A: Cost Effectiveness Calculations 
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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 

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

(PM10), reactive organic compounds (ROG), sulfur dioxide (SO2), and beryllium. 

1.1 BACT Review Process 

A BACT analysis evaluates the energy, environmental, 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. 
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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 previous 
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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 determinations 

for other sources in the same source category, the control technology is deemed not costeffective, and can be rejected as economically unjustifiable. 
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2 NOX BACT Analysis 

NOX 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 NO2. 

2.1 Identification of Possible Control Alternatives 

There are a variety of options available for controlling NOX emissions from combustion sources. 

Some options involve combustion controls that reduce NOX formation, while others utilize addon control devices to remove NOX after it is formed. 

2.1.1 Combustion Controls 

Combustion controls reduce NOX 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 NOX.” The oxidation of nitrogen that is 

chemically bound in fuel sources can also form what is called “fuel-bound NOX.” 

Proper combustion generally refers to control, generally 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-NOX (DLN) burners control thermal NOX 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-catalytic reduction (SNCR) and selective catalytic 

reduction (SCR) systems are widely used technologies for controlling NOX emissions from 

combustion sources. In the SNCR process, ammonia is mixed with the exhaust from the 

combustion device and the NOX 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 NOX 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 NOX 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 that 
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reaches the catalyst have resulted in exhaust gas temperatures too low for conventional 

catalysts to promote the reduction reaction. Additionally, 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 inefficient 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 conventional 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 the 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 NOX 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 application 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 have typically been limited to existing boilers, 

where it would be expensive and difficult to rearrange 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 NOX in the exhaust stream reacts 

with potassium carbonate (K2CO3) to form potassium nitrate (KNO3). This compound is reacted 

with hydrogen to form gaseous nitrogen (N2), and regenerate the K2CO3. 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 NOX 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 a 
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“cold-side” SCR system (2 catalyst beds with a 450 °F inlet temperature) that would limit NOX

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-fired stoker-type boilers to achieve a quarterly 

average NOX 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 NOX

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 NOX emissions to 0.060 lb/MMBtu using a two-layer RSCR system. The Massachusetts 

RPS program has a more stringent NOX 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 NOX 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 NOX 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 NOX emissions to 

0.012 lb/MMBtu on a short-term basis4

, 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 NOX 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 NOX limit of 0.13 lb/MMBtu, and a 12-month rolling average NOX

limit of 0.1 lb/MMBtu. In August 2009, the 12-month rolling average NOX limit was eliminated in an effort to address 

a secondary plume that resulted from excessive ammonia use in the SNCR system. 

4 For the initial 12-month period following startup, the 24-hour average NOX limit would be 0.024 lb/MMBtu. During 

that period, a study would determine whether or not the 0.012 lb/MMBtu limit was achievable, and, if not, an 

alternative NOX limit would be proposed. 
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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 NOX emission rate of 0.35 lb/MMBtu at the 

furnace exit has been achieved. 

The results of the database queries and permit investigations for NOX 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 

NOX 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 NOX emission rates of between 0.20 to 0.26 lb/MMBtu, depending upon the 

degree of optimization for controlling NOX emissions (lower NOX 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 NOX 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 combustion 

occurring on a moving grate. These burners are generally intended to limit the amount of fuelbound nitrogen that is converted to NOX 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-on 
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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 NOX 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 NOX control 

technology for biomass-fired boilers. 

2.2.4 SCR and related variations 

As indicated in the previous section, SCR, 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 NOX 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 projects 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 NOX 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 SO2 emission factor for wood-fired boilers is 0.025 lb/MMBtu, which 

is equivalent to about 7.2 lb/hr of SO2. 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 SO2 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 NOX 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 

NOX emitted by a biomass-fired, stoker-type boiler: 
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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 NOX 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 NOX emissions. 

2.3.2 SNCR 

Currently, SNCR systems are the most common add-on control device used to reduce NOX

emissions from large biomass-fired boilers. SNCR systems rely on high temperatures to 

promote the reaction of NOX 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/MMBtu have been achieved using SNCR systems to 

control NOX 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 NOX

emissions to 0.065 lb/MMBtu on a 30-day rolling average. Russell Biomass, if constructed, 

would use a two-layer RSCR to limit NOX 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 placed 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 

• SNCR 
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• Proper combustion 

2.4 Cost-Effectiveness Evaluation 

SNCR is the most common add-on technology used to reduce NOX 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 analysis 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 NOX reduced (see Attachment A). 

Although application of an SCR system to a biomass-fired boiler is not considered experimental, 

it cannot be assumed that, due to a lack of practical 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 NOX emissions by 

130 tons year at an annual expense of approximately $203,000, while an SCR system, under 

best-case operating conditions, would reduce NOX 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 NOX, which is equivalent to an incremental 

cost effectiveness of over $8,500 per ton of NOX removed. However, judging by the 

experiences of other biomass-fired boiler facilities employing SCR systems, this costeffectiveness analysis likely underestimates the number of replacement catalyst beds needed 

each year (2), as well as the number downtime events needed each year to replace or clean the 

catalyst beds (3), so the cost effectiveness could easily be twice that of the calculated “best 

case” scenario. Based on this analysis, SNCR is deemed to be the most reliable, cost-effective 

NOX control technology for biomass-fired, stoker-type boilers. 
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2.5 Selection of BACT for NOX

Based on the analysis presented in this section, SPI proposes that BACT for the control of NOX

from biomass-fired, stoker-type boilers is the use of an integral SNCR system. NOX emissions 

would be limited to 0.13 lb/MMBtu, which is approximately equivalent to 242 tpy at the 

anticipated annual average operating capacity. 
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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 CO2 into CO which can occur in high-temperature regions 

(above 1,700 °C) of the combustion zone. 

3.1 Identification of Possible Control Alternatives 

As for NOX, 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 CO2 after leaving the 

combustion area. 

3.1.1 Combustion Controls 

Combustion controls for CO include adequate fuel residence times to ensure CO2 formation, 

proper fuel-air mixing, and temperature control. These measures, however, can result in an 

increase in the NOX 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 higher 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 CO2). 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 desirable for improved conversion of CO to CO2 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 remove particulate matter from the catalyst. 
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EMx (described in the NOX BACT analysis section) also utilizes a catalytic technique that 

oxidizes CO to CO2 in addition to controlling NOX 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 reduce 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 oxidation 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 oxidation 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 NOX. 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 was 
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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 proposes 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 NOX creation, at the expense of 

slightly higher CO emissions, to reduce the reduction burden placed on add-on NOX 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 are 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-fired stoker boiler while not negatively impacting 

facility operations. 

3.2.3 EMx 

As discussed in the NOX 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 technically feasible for controlling CO emissions from 

a wood-fired boiler. 
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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, emissions resulting from incomplete combustion (CO 

and VOC) are balanced with emissions related to high furnace temperatures (NOX) to achieve 

optimally low emissions of all pollutants. However, in order to achieve the proposed NOX

emission limit (0.13 lb/MMBtu) while not exceeding 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 NOX 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 providing 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 overall 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: 
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• Catalytic oxidation 

• Proper combustion 

3.4 Cost Effectiveness Evaluation 

Proper combustion is the most common technique used 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 considered experimental, it cannot be assumed that 

this control technology will perform in a reliable 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 wash 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 control 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. 
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4 PM10 BACT ANALYSIS 

PM10 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 Possible Control Alternatives 

4.1.1 Combustion Controls 

The concept of applying combustion controls or “proper combustion” to minimize PM10

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 PM10 control can result in an increase in the NOX 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 PM10 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 less 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 PM10. 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 PM10 control technologies are presented in Table 4, 

sorted by permit limit, beginning with the PM10 limit proposed by SPI for the new biomass-fired 

cogeneration unit. 
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A review of the RBL Clearinghouse indicates that the most stringent control technology for PM10

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

control PM10 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 technology is at Kimberly-Clark in Everett, 

Washington, which has a PM10 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 

PM10 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 PM10 test method to confirm compliance with the permit limit. The proposed Valley 

BioEnergy facility in Modesto would use an ESP to limit PM10 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 PM10 emissions from a biomass-fired boiler is an 

ESP preceded by a multiclone. Baghouses have been employed to control PM10 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 expensive flame-proof bags are purchased. Venturi 

scrubbers are generally employed to control PM10 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. 
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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 PM10 from exhaust flows. Units with pressure drops of 20 inches of 

water or greater can remove greater than 99 percent of PM10. 

4.3.2 Baghouses 

Baghouses typically operate with pressure drops between 2 and 12 inches of water. PM10

control efficiencies are capable of removing over 99 percent of PM10 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 PM10 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 PM10 emissions from the biomass-fired, stoker-type boiler. 

4.5 Selection of BACT for PM10

SPI proposes that BACT for PM10 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. 
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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 Possible Control Alternatives 

Combustion controls, or proper combustion techniques, provide wide range of control 

effectiveness depending on the configuration of the system. Generally, emissions resulting from 

incomplete combustion (CO and VOC) are balanced with emissions related to high furnace 

temperatures (NOX) 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 emissions 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 NOX, 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. 
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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., NOX). 

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. 
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6 SO2 BACT ANALYSIS 

Sulfur dioxide (SO2) 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 

SO2. 

6.1 Identification of Possible Control Alternatives 

There are two alternatives for reducing SO2 emissions combustion sources: removal of sulfur 

from the fuel before it is combusted, and removal of SO2 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 SO2 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 SO2 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 SO2 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 SO2 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 SO2 control technologies are presented in Table 6, 

sorted by permit limit, beginning with the SO2 limit proposed by SPI for the new boiler. The 

RBLC does not indicate that any FGD systems have been used to reduce SO2 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 SO2 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: 

• None 
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• 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 SO2 emissions from a biomass-fired boiler. 

6.3 Effectiveness of Remaining Technologies 

Wet FGD systems are considered the most effective, and can achieve greater than 90 percent 

reduction in SO2 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 SO2 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 SO2

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 SO2 controlled is more than $45,000, which is clearly outside the envelope of 

acceptable costs. 

6.5 Selection of BACT for SO2

SPI proposes that no control system is BACT for reducing SO2 emissions from a biomass-fired 

boiler, and that the SO2 permit limit will be determined by the initial source test. 
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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 from 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). 
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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/ft2

) 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. 
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Tables
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Table 1 

NOX Control Technology Search Results 

Facility Name Location 

Date of 

Permit 

Heat Input 

(MMBtu/hr) 

Permit Limit 

(lb/MMBtu) 

Control 

Technology Bas

Sierra Pacific Industries Anderson, CA Proposed 425 0.13 SNCR BACT-O

Valley BioEnergy Modesto, CA Proposed 402 0.012 SNCR/SCR BACT-O

Russell Biomass Russell, MA 12/30/08 740 0.06 RSCR LAER-O

Concord Steam Concord, NH 2/27/09 305 0.065 SCR LAER-O

Darrington 

Cogeneration Darrington, WA 1/18/05 403 0.12/0.1 SNCR BACT-

Sierra Pacific Industries Burlington, WA 1/25/06 430 0.13 SNCR BACT-Sierra Pacific Industries Aberdeen, WA 10/17/02 310 0.15/0.1 SNCR BACT-

Virginia DPU Virginia, MN 6/30/06 230 0.15 SNCR BACT-

Hibbing PUC Hibbing, MN 6/30/06 230 0.15 SNCR BACT-

Hampton Lumber Darrington, WA 6/1/05 245 0.15 SNCR BACT-O

District Energy St. Paul St. Paul, MN 11/15/01 550 0.15 SNCR BACT-

Simpson Tacoma Kraft Tacoma, WA 5/22/07 595 0.20 Proper combustion BACT-

Boise Cascade Florien, LA 7/18/07 225 0.22 Proper combustion BACT-

Boralex, Stratton Stratton, ME 1/4/05 672 0.24 SNCR/RSCR BACT-O

Koda Energy Shakopee, MN 8/23/07 308 0.25 SNCR BACT-

U.S. Sugar Clewiston, FL 12/6/07 738 0.31 Proper combustion BACT-

Bridgewater Power Bridgewater, NH 9/12/07 250 0.33/0.075 SNCR/RSCR RACT/O

DG Whitefield Whitefield, NH 9/10/04 220 0.33/0.075 RSCR RACT/O

South Point Power South Point, OH 4/4/06 318 0.44 SCR BACT-
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Table 2 

NOX Control Technology Cost-Effectiveness Comparison 

Control System 

Annual Cost 

($/yr) 

NOX Reduction 

(tpy) 

Cost Effectivness 

($/ton) 

SNCR 203,318 130.4 1,559 

SCR 1,318,989 260.9 5,056 
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Table 3 

CO Control Technology Search Results 

Facility Name Location 

Date of 

Permit 

Heat Input 

(MMBtu/hr) 

Permit Limit 

(lb/MMBtu) 

Control 

Technology 

Sierra Pacific Industries Anderson, CA Proposed 425 0.35 Proper combustion BA

Valley Bio-Energy Modesto, CA Proposed 402 0.046 Oxidation catalyst BA

Russell Biomass Russell, MA 12/30/08 740 0.075 Oxidation catalyst BA

South Point Power South Point, OH 4/4/06 318 0.10 Oxidation catalyst B

Hampton Lumber Darrington, WA 6/1/05 245 0.23 Proper combustion BA

Virginia DPU Virginia, MN 6/30/06 230 0.3 Proper combustion B

Hibbing PUC Hibbing, MN 6/30/06 230 0.3 Proper combustion B

District Energy St. Paul St. Paul, MN 11/15/01 550 0.3 Proper combustion B

Willamette Industries, Inc. Marlboro, SC 4/17/96 470 0.3 Proper combustion BA

Boralex Ashland Ashland, ME 4/2/92 586 0.3 Proper combustion BA

Sierra Pacific Industries Burlington, WA 1/25/06 430 0.35 Proper combustion B

Darrington Cogeneration Darrington, WA 1/18/05 403 0.35 Proper combustion B

Sierra Pacific Industries Aberdeen, WA 10/17/02 310 0.35 Proper combustion B

KES Chateaugay Project Chateaugay, NY 12/19/94 275 0.35 Proper combustion BA

Pittsylvania Power Hurt, VA 2/21/92 374 0.35 Proper combustion B

Smurfit-Stone Container Stevenson, AL 1/15/97 620 0.4 Proper combustion B

Weyerhaeuser Company Bruce, MS 5/9/95 90 0.4 Proper combustion B

Gulf States Paper Corp Moundville, AL 10/14/98 98 0.5 Proper combustion B

Bio Energy Corp. West Hopkinton, NH 7/23/98 225 1.0/0.253 Oxidation catalyst BA

Plum Creek – Columbia Falls Columbia Falls, MT 7/26/95 292 1.6 Proper combustion B
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Table 4 

PM10 Control Technology Search Results 

Facility Name Location 

Date of 

Permit 

Heat Input 

(MMBtu/hr) 

Permit Limit 

(lb/MMBtu) 

Control 

Technology 

Sierra Pacific Industries Anderson, CA Proposed 425 0.015 Multiclone, ESP 

Valley Bio-Energy Modesto, CA Proposed 402 0.02 Multiclone, ESP 

South Point Power South Point, OH 4/4/06 318 0.0125 Baghouse 

Simpson Tacoma Kraft Tacoma, WA 5/22/07 595 0.02 ESP 

Sierra Pacific Industries Burlington, WA 1/25/06 430 0.02 Multiclone, ESP 

Hampton Lumber Darrington, WA 6/1/05 245 0.02 Multiclone, ESP 

Darrington Cogeneration Darrington, WA 1/18/05 403 0.02 Multiclone, ESP 

Sierra Pacific Industries Aberdeen, WA 10/17/02 315 0.02 Mulitclone, ESP 

Decker Energy International East Ryegate, VT 7/11/90 300 0.02 Mech. Collector, ESP 

Boralex Livermore Falls, ME 9/5/91 534 0.02 Multiclone, ESP 

Pittsylvania Power Hurt, VA 2/21/92 374 0.02 Multiclone, ESP 

Russell Biomass Russell, MA 12/30/08 740 0.026 Multiclone, ESP 

Smurfit-Stone Container Stevenson, AL 1/15/97 620 0.03 Multiclone, ESP 

Wheelabrator Sherman Energy Sherman Station, ME 4/9/99 630 0.036 Baghouse 

Boralex Chateaugay, NY 12/19/94 275 0.038 Multiclone, ESP 

Willamette Industries, Inc. Marlboro, SC 4/17/96 470 0.05 ESP 

Gulf States Paper Corp. Moundville, AL 10/14/98 98 0.1 Multiclone, ESP 

Weyerhaeuser Co. Millport, AL 10/28/94 91 0.15 Venturi Scrubber 
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Table 5 

ROG/VOC Control Technology Search Results 

Facility Name Location 

Date of 

Permit 

Heat Input 

(MMBtu/hr) 

Emission Factor

(lb/MMBtu) 

Control 

Technology 

Sierra Pacific Industries Anderson, CA Proposed 425 0.017 Proper combustion B

Valley Bio-Energy Modesto, CA Proposed 402 0.005 Oxidation catalyst B

Russell Biomass Russell, MA 12/30/08 740 0.01 Oxidation catalyst B

Duke Solutions Evendale, OH 11/24/99 28.7 0.01 Proper combustion 

South Point Power South Point, OH 4/4/06 318 0.013 Oxidation catalyst 

Boise Cascade Florien, LA 7/18/07 225 0.017 Proper combustion 

Sierra Pacific Industries Burlington, WA 1/25/06 430 0.019 Proper combustion 

Hampton Lumber Darrington, WA 6/1/05 245 0.025 Proper combustion B

Darrington Cogeneration Darrington, WA 1/18/05 403 0.025 Proper combustion B

Sierra Pacific Industries Aberdeen, WA 10/17/02 310 0.025 Proper combustion 

Wheelabrator Sherman Energy Co. Penobscott, ME 4/9/99 315 0.03 Proper combustion 

Potlatch Corp. Ozan, AR 7/26/05 175 0.034 Proper combustion 

Southern Soya Corp. Estill, SC 10/2/95 58 0.05 Proper combustion 
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Table 6 

SO2 Control Technology Search Results 

Facility Name Location 

Date of 

Permit 

Heat Input 

(MMBtu/hr) 

Emission Factor

(lb/MMBtu) 

Control 

Technology 

Sierra Pacific Industries Anderson, CA Proposed 425 -- None B

Valley Bio-Energy Modesto, CA Proposed 402 0.012 Acid gas scrubber B

Duke Solutions Evendale, OH 11/24/99 28.7 0.01 None 

Russell Biomass Russell, MA 12/30/08 740 0.025 Fuel specification B

Sierra Pacific Industries Burlington, WA 1/25/06 430 0.025 None 

Hampton Lumber Darrington, WA 6/1/05 245 0.025 None B

Darrington Cogeneration Darrington, WA 1/18/05 403 0.025 None B

Sierra Pacific Industries Aberdeen, WA 10/17/02 310 0.025 None 

South Point Power South Point, OH 4/4/06 318 0.087 Acid gas scrubber 

Smurfit-Stone Container Stevenson, AL 7/14/06 620 0.15 None 

Willamette Industries, Inc. Marlboro, SC 4/17/96 470 0.1 None B

Wheelabrator Sherman Energy Co. Penobscott, ME 4/9/99 315 0.12 Fuel specification 

Gulf States Paper Corp Demopolis, AL 12/10/97 775 0.46 Proper combustion 

Northern Sun ADM Enderlin, ND 5/1/06 280 0.47 None 
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Appendix A:

Cost-Effectiveness Calculations
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Appendix C:

Air Quality Dispersion Modeling Files (CD)
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Appendix D:

Communications From FLMs
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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 NOx, SOx, and PM10) 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