U.S. ENVIRONMENTAL PROTECTION AGENCY

REGION IX

STATEMENT OF BASIS AND 

AMBIENT AIR QUALITY IMPACT REPORT

For a Clean Air Act 

Prevention of Significant Deterioration Permit

Sierra Pacific Industries-Anderson

PSD Permit Number SAC 12-01

September 2012
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PROPOSED PREVENTION OF SIGNIFICANT DETERIORATION

PERMIT

SPI - Anderson

Statement of Basis and Ambient Air Quality Impact Report

(PSD Permit SAC 12-01)

Table of Contents

Executive Summary........................................................................................................................ 1

1. Purpose of this Document......................................................................................................... 2

2. Applicant................................................................................................................................... 2

3. Project Location........................................................................................................................ 2

4. Project Description.................................................................................................................... 3

5. Emissions from the Proposed Project ....................................................................................... 7

6. Applicability of the Prevention of Significant Deterioration Regulations ............................... 8

7. Best Available Control Technology.......................................................................................... 9

7.1. BACT for a New Boiler at a Lumber Facility .............................................................. 11

7.1.1. Oxides of Nitrogen................................................................................................ 11

7.1.2. Carbon Monoxide ................................................................................................. 16

7.1.3. Particulate Matter- PM, PM10, PM2.5 .................................................................... 19

7.2 BACT for Emergency Engine....................................................................................... 22

7.3. BACT for Cooling Towers ........................................................................................... 24

8. Air Quality Impacts................................................................................................................. 26

8.1 Introduction....................................................................................................................... 26

8.1.1 Overview of PSD Air Impact Requirements ............................................................ 26

8.1.2 Identification of SPI- Anderson Modeling Documentation...................................... 27

8.2. Background Ambient Air Quality................................................................................. 28

8.3 Modeling Methodology for Class II areas........................................................................ 29

8.3.1 Model selection......................................................................................................... 29

8.3.2 Meteorology model inputs........................................................................................ 29

8.3.3 Land characteristics model inputs............................................................................. 29

8.3.4 Model receptors ........................................................................................................ 30

8.3.5 Stack parameter model inputs................................................................................... 30

8.3.6 Good Engineering Practice (GEP) Analysis............................................................ 31

8.4 National Ambient Air Quality Standards (NAAQS) and PSD Class II Increment 

Consumption Analysis............................................................................................................ 31

8.4.1 Pollutants with significant emissions........................................................................ 31

8.4.2 Preliminary analysis: Project-only impacts (Normal Operations and Startup)......... 32

8.4.3 Cumulative impact analysis...................................................................................... 33

8.5 Class I Area Analysis........................................................................................................ 38

8.5.1 Air Quality Related Values....................................................................................... 38

8.5.2 Class I Increment Consumption Analysis................................................................. 39

9. Additional Impact Analysis .................................................................................................... 40

9.1 Soils and Vegetation ......................................................................................................... 40
9.2 Visibility Impairment........................................................................................................ 43

9.3 Growth .............................................................................................................................. 44

10. Endangered Species................................................................................................................ 45

11. Environmental Justice Screening Analysis............................................................................. 45

12. Clean Air Act Title V (Operating Permit) .............................................................................. 46

13. Comment Period, Procedures for Public Hearing

Requests, Final Decision, and EPA Contact........................................................................... 46

14. Conclusion and Proposed Action............................................................................................ 48

Appendix A................................................................................................................................... 49
Acronyms & Abbreviations 

AAQIR Ambient Air Quality Impact Report

ACC Air Cooled Condenser

Act Clean Air Act [42 U.S.C. Section 7401 et seq.]

Agency U.S. Environmental protection Agency

AQRV Air Quality Related Value

BACT Best Available Control Technology

BDT Bone Dry Tons

BTU British thermal units

CAA Clean Air Act [42 U.S.C. Section 7401 et seq.]

CBI Confidential Business Information 

CEMS Continuous Emissions Monitoring System

CFR Code of Federal Regulations

CO Carbon Monoxide

EPA U.S. Environmental protection Agency

ESA Endangered Species Act

FLM Federal Land Manager

FWS U.S. Fish and Wildlife Service

GAQM 40 CFR part 51, Appendix W- Guideline on Air Quality Models

GEP Good engineering practice

hp Horsepower

HRSG Heat Recovery Steam Generator

kW kilowatt

m meter

MMBTU Million British thermal units

MW Megawatts of electrical power

NAAQS National Ambient Air Quality Standards

NLCD92 USGS 1992 National Land Cover 

NO Nitrogen oxide or nitric oxide

NO2 Nitrogen dioxide

NOx Oxides of Nitrogen (NO + NO2)

NP National park

NSPS New Source performance Standards, 40 CFR part 60

NSR New Source Review

PM Total particulate Matter

PM2.5 Particulate Matter less than 2.5 micrometers (μm) in diameter

PM10 Particulate Matter less than 10 micrometers (μm) in diameter

ppb parts per billion

ppm parts per million

PSD Prevention of Significant Deterioration

PTE potential to emit

RBLC U.S. EPA RACT/BACT/LAER Information Clearinghouse

SCAQMD Shasta County Air Quality Management District
SCFM Standard Cubic Feet per Minute

SIA Significant Impact Area

SIL Significant Impact Level

SO2 Sulfur Dioxide

SOx Oxides of Sulfur

SPI Sierra pacific Industries

tpy tons per year

USGS United States Geological Survey

WA Wilderness Area
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Proposed Prevention of Significant Deterioration (PSD) Permit

Statement of Basis and Ambient Air Quality Impact Report

SPI- Anderson

Executive Summary

Sierra Pacific Industries (SPI) has applied for an approval to construct a new 

cogeneration unit capable of generating approximately 31 megawatts (MW) of electricity

by combusting clean cellulosic biomass during normal operation and natural gas for 

startup and shutdown. The cogeneration unit will be constructed within the physical 

boundaries of the current SPI- Anderson Division facility location. The facility is located 

at 19758 Riverside Avenue in Anderson, California 96007 (Assessor’s parcel No. 050-

110-025). The proposed major Prevention of Significant Deterioration (PSD) permit 

modification is consistent with the requirements of the PSD program for the following 

reasons:

 The proposed permit requires the Best Available Control Technology (BACT) for 

Oxides of Nitrogen (NOx), Carbon Monoxide (CO), Total Particulate Matter 

(PM), Particulate Matter under 10 micrometers (μm) in diameter (PM10) and

Particulate Matter under 2.5 μm in diameter (PM2.5);

 The proposed emission limits will protect the National Ambient Air Quality 

Standards (NAAQS) for NO2, CO, PM10 and PM2.5. There is no NAAQS set for 

Total Particulate Matter (PM);

 The facility will not adversely impact soils and vegetation, or air quality, 

visibility, and deposition in Class I areas, which are parks or wilderness areas

given special protection under the Clean Air Act (CAA); 

 After informal consultation with the U.S. Fish and Wildlife Service under Section 

7 of the Endangered Species Act, EPA has concluded that the proposed 

modification will have no likely adverse effect on any Federally-listed endangered 

or threatened species or designated critical habitat in the project’s impact area. 
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1. Purpose of this Document

This document serves as the Statement of Basis and Ambient Air Quality Impact Report

for the proposed PSD permit modification for the SPI– Anderson facility. This document 

describes the legal and factual basis for the proposed permit, including requirements 

under the PSD regulations at Title 40 of the Code of Federal Regulations (CFR) §52.21. 

This document also serves as the fact sheet to meet the requirements of 40 CFR Part 

124.7 and 124.8. 

2. Applicant

Sierra Pacific Industries

P.O. Box 496028

Redding, CA 96049-6028

3. Project Location

The proposed location for the modification of the SPI- Anderson facility will be within 

the physical footprint of the current facility location. The facility is located at 19758 

Riverside Avenue in Anderson, California 96007 (Assessor’s parcel No. 050-110-025). 

The site is approximately 0.5 mile west of Interstate 5, and approximately 2 miles north 

of the city of Anderson. The 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 city of 

Anderson is located within the jurisdiction of the Shasta County Air Quality Management 

District (SCAQMD).

The map on the following page shows the approximate location of SPI- Anderson.
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4. Project Description

SPI has applied for an approval to construct and operate a new cogeneration unit capable 

of generating 31 MW of gross electrical output from the combustion of clean cellulosic 

biomass and natural gas. 

The original PSD permit for this lumber manufacturing facility was issued in 1994 by the 

Shasta County Air Quality Management District (SCAQMD). The site currently contains 

a wood-fired boiler with associated air pollution control equipment and conveyance 

systems that produces steam to dry lumber in existing kilns. On March 3, 2003 USEPA 

revoked and rescinded SCAQMD’s authority to issue and modify federal PSD permits for 
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new and modified major sources of attainment pollutants in Shasta County. Therefore, 

EPA is modifying the PSD permit issued by SCAQMD to incorporate the proposed 

modifications. 

A new cogeneration unit equipped with a stoker boiler is being proposed in order to burn 

additional clean cellulosic biomass fuel. Fuel will be generated on site from the lumber 

operations and delivered from other fuel sources to produce roughly 250,000 pounds per 

hour of steam. This steam be used to dry lumber in existing kilns for the lumber 

operation, as well as feed a turbine that will drive a generator to produce electricity for 

use on site or for sale to the electrical grid. A closed-loop two-cell cooling tower will be 

used to dispose of waste heat from the steam turbine.

Currently, the Anderson lumber operation produces approximately 160,000 bone dry tons 

(BDT) of wood waste per year. Approximately 60,000 BDT are consumed by the existing 

cogeneration unit, 20,000 BDT are trucked to other biomass power plants, and the 

roughly 80,000 BDT balance is trucked to other markets (e.g. wood chips to pulp mills). 

The new proposed boiler will have the capacity to consume a maximum of 219,000 BDT 

per year. Roughly 80,000 BDT will be generated by the facility’s existing lumber 

operations at its current output, additional wood fuel will be transported by truck to the 

facility from SPI’s other lumber operations in California.

The following page contains a design draft and a simplified process flow diagram for the 

proposed boiler.
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Air Pollution Control 

SPI- Anderson will employ several air pollution control alternatives to reduce the 

emissions of some criteria pollutants from the proposed new boiler. Selective Noncatalytic Reduction (SNCR) will be used to reduce NOx emissions. Ammonia will be 

introduced into the furnace at the appropriate temperature window in order to most 

effectively decrease NOx emissions. To reduce particulate matter (PM) emissions, SPI 

will use an electrostatic precipitator (ESP) preceded by a multiclone. 
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Permitted Equipment

Table 4-1 lists the proposed new equipment that will be regulated by this PSD permit:

Table 4-1: Proposed New Equipment List

Stoker Boiler with 

Vibrating Grate

Biomass-fired with natural gas burners for start-up and 

shutdown

Maximum annual average heat input of 468 MMBtu/hr

and steam generation rate of 250,000 lbs/hr

Equipped with two natural gas burners, each with a 

maximum rated heat input of 62.5 MMBtu/hr

Equipped with SNCR system to reduce nitrogen oxides, 

and multiclone with ESP to control PM emissions

Emergency Engine

256 hp at 1,800 rpm

Used to run the emergency boiler recirculation pump

Natural-gas fired

Cooling Tower Composed of two-cells with an expected water load of 

4.24 gallons per minute per square foot. 
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Table 4-2 lists the existing equipment that is not included in this PSD permit. The 

equipment listed below is permitted by SCAQMD, and Table 4-2 is provided for 

reference purposes only.

Table 4-2: Existing Equipment List

Wellons Stoker Boiler

Biomass-fired with natural gas burners for start-up

Maximum annual average heat input of approximately 

116.4 MMBtu/hr

Equipped with SNCR system to reduce nitrogen oxides, 

and multiclone with ESP to control PM emissions

Equipped with one 30,400 ft3fuelstorage bin, 2 hog fuel 

bins, 2 wood chip fuel bins

Conveyance System

2 Cyclones with combined flow rate of 51.004 scfm

1 7,118 ft2 MAC pulse Jet Baghouse with 300hp Blower

1 35” x 45” Rotary Airlock

1 Buhler en-masse, 19”, 22tph Conveyor

2 Overhead Storage Bins with enclosed sides

Spray Unit Closed loop unit equipped with integrated, negative 

pressure, mist collection system and 65’ exhaust stack

Wood Chip Loading 

Facility

1 platform truck dumper

1 Wood chip conveying system with dust containment 

hood

1 200 hp Rader blower

7 De-greasing Tanks Non-solvent based

Gasoline Storage Tank Above ground with 10,000 gallon capacity 

Painting Operation

5. Emissions from the Proposed Project

The PSD program is intended to protect air quality in “attainment areas”, which are areas 

that meet the National Ambient Air Quality Standards (NAAQS). Table 5-1 describes 

which pollutants are covered by the PSD program within the SCAQMD. The U.S. EPA 

is responsible for issuing PSD permits for pollutants in attainment with the NAAQS in 

the SCAQMD. As illustrated in Table 5-1, SCAQMD is attainment/ unclassifiable for 

each NAAQS,
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Table 5-1: NAAQS Attainment Status for SCAQMD

Pollutant Attainment Status Permit program

Lead (Pb) Attainment PSD

Nitrogen Dioxide (NO2) Attainment PSD

Sulfur Dioxide (SO2) Attainment PSD

Carbon Monoxide (CO) Attainment PSD

Sulfuric Acid Mist (H2SO4) n/a1PSD

Particulate Matter (PM) n/a1PSD

Particulate Matter under 2.5 

micrometers diameter (PM2.5)

Attainment PSD

Particulate matter under 10 

micrometers diameter (PM10)

Attainment PSD

Ozone Attainment PSD

Greenhouse Gases (GHG) n/a1PSD

The PSD program (40 CFR 52.21) applies to "major" new sources of attainment

pollutants or “major modifications” at existing major sources of attainment pollutants. 

SPI- Anderson is an existing PSD major source proposing to modify its existing PSD

permit in order to construct the equipment detailed in Table 4-1.

6. Applicability of the Prevention of Significant

Deterioration Regulations

The estimated emissions in Table 4 shows that the proposed construction will be a major 

modification for NOx, CO, PM, PM10 and PM2.5. The annual emission data in Table 6-1

are based on the applicant’s maximum expected emissions, including emissions from 

startup and shutdown cycles. The applicant assumes that all emissions of PM are of 

diameter less than 2.5 microns (PM2.5), which is a conservative estimate as some

particulate emissions may be much larger than 2.5 micrometers in diameter.

Once a modification to an existing major stationary source is considered a major 

modification for a PSD pollutant, PSD also applies to any other regulated pollutant that is 

emitted in a significant amount. For our PSD applicability determination we are 

conservatively assuming that all sulfur oxide emissions are sulfur dioxide (SO2). The data 

in Table 6-1 show that emissions of SO2, volatile organic compounds (VOC), sulfuric 

acid (H2SO4) and lead (Pb) will be less than the significant emission rate. Therefore, PSD

does not apply for SO2, VOC, H2SO4 and Pb. Total estimated emissions of the PSDregulated pollutants resulting from the emission units in this modification are listed in 

Table 6-1.

 

1 There is no national ambient air quality standard (NAAQS) for PM, H2SO4 or GHG. However, in addition to other 

pollutants for which no NAAQS have been set, PM, H2SO4 and GHG are listed as regulated pollutants with a 

defined applicability threshold under the PSD regulations (40 CFR 52.21).
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Table 6-1: Estimated Emissions and BACT Applicability2

Pollutant

Estimated Annual 

Emissions

(tpy)

Significant Emission 

Rate (tpy)

Does 

BACT 

apply?

CO 472 100 Yes

NOx 267 40 Yes

PM 42.1 25 Yes

PM10 42.1 15 Yes

PM2.5 42.1 10 Yes

VOC 34.9 40 No

SO2 10.3 40 No

H2SO4 4.2 7 No

Lead 0.03 0.6 No

CO2e

420,137 (Total)

38,379 (nondeferred)

CO2e: 75,000

(subject to regulation)

Mass: 0 (significant)

No3

7. Best Available Control Technology

This chapter describes the Best Available Control Technology (BACT) for the control of

CO, NOx, PM, PM10 and PM2.5 emissions from this facility. Section 169(3) of the CAA

defines BACT as follows:

"The term 'best available control technology' means an emission limitation based 

on the maximum degree of reduction of each pollutant subject to regulation under 

the Clean Air Act emitted from or which results from any major emitting facility, 

which the permitting authority, on a case-by-case basis, taking into account 

energy, environmental, and economic impacts and other costs, determines is 

achievable through application of production processes and available methods, 

systems, and techniques, including fuel cleaning or treatment or innovative fuel 

combustion techniques for control of each such pollutant. In no event shall 

application of BACT result in emissions of any pollutants which will exceed the 

emissions allowed by any applicable standard established pursuant to section 111 

(NSPS) or 112 (NESHAPS) of the Clean Air Act."

 

2 Annual emissions estimates differ from the PSD Application submission by SPI and Environ. EPA calculated 

annual emissions estimates at worst case annual heat input of 468 MMBtu/hr, not 425 MMBtu/hr, and the CO 

BACT limit was revised to 0.23 lb/MMBtu. (See SPI Annual Emissions Memo to file)

3 Although the proposed modification identifies an increase in GHG emissions that exceeds the “subject to 

regulation” threshold of 75,000 tpy CO2e and GHG significance rate of 0 tpy, EPA’s Deferral for CO2 emissions 

from Bioenergy and Other Biogenic Sources under the Prevention of Significant Deterioration and Title V programs

(76 FR 43490 July 20, 2011) applies to this project. Since the non-deferred GHG emissions for this project are 

38,252 tpy CO2e, the modification is not subject to BACT for GHG. See Appendix A for relevant emissions 

calculations and further discussion.
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In accordance with 40 CFR 52.21(j), a new major stationary source is required to apply 

BACT for each regulated NSR pollutant for which its PTE exceeds significance 

thresholds. BACT is defined as “an emission limitation (including a visible emission 

standard) based on the maximum degree of reduction of each pollutant subject to 

regulation under the Act ... which the Administrator, on a case-by-case basis, taking into 

account energy, environmental, and economic impacts, and other costs, determines is 

achievable for such source.” BACT must be at least as stringent as any applicable New 

Source Performance Standards (NSPS) under 40 CFR Part 60 or National Emission 

Standard for Hazardous Air Pollutants (NESHAP) under 40 CFR Part 61. EPA outlines 

the process it will use to do this case-by-case analysis (referred to as “top-down” BACT 

analysis) in a June 13, 1989 memorandum. The top-down BACT analysis is a well 

established procedure that the Environmental Appeals Board (EAB) has consistently 

followed in adjudicating PSD permit appeals. See, e.g., In re Knauf, 8 E.A.D. 121, 129-

31 (EAB 1999); In re Maui Electric, 8 E.A.D. 1, 5-6 (EAB 1998). 

In brief, the top-down process requires that all available control technologies be ranked in 

descending order of control effectiveness. The PSD applicant first examines the most 

stringent technology. That technology is established as BACT unless it is demonstrated 

that technical considerations, or energy, environmental, or economic impacts justify a 

conclusion that the most stringent technology is not achievable for the case at hand. If the 

most stringent technology is eliminated, then the next most stringent option is evaluated 

until BACT is determined. The top-down BACT analysis is a case-by-case exercise for 

the particular source under evaluation. In summary, the five steps involved in a top-down 

BACT evaluation are:

1. Identify all available control options with practical potential for application to the 

specific emission unit for the regulated pollutant under evaluation;

2. Eliminate technically infeasible technology options;

3. Rank remaining control technologies by control effectiveness;

4. Evaluate the most effective control alternative and document results; if top option is 

not selected as BACT, evaluate next most effective control option; and

5. Select BACT, which will be the most stringent technology not rejected based on 

technical, energy, environmental, and economic considerations. 

BACT is required for NOx, CO, PM, PM10, and PM2.5 for the new proposed emission 

units. Table 7-1 lists the BACT determinations for NOx, CO, PM, PM10, and PM2.5 from 

the proposed boiler and emergency engine, and PM, PM10, and PM2.5 from the cooling 

tower. For the purposes of this determination, all NOx emissions will be treated as NO2.
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Table 7-1: Summary of BACT Limits4

Unit NOx CO PM PM10 PM2.5

Boiler

(468 MMBtu/hr)

0.15 lb/MMBtu

(3-hour block average)

0.13 lb/MMBtu (12-

month rolling average)

0.23lb/MMBtu

(3-hour block 

average)

0.02 lb/MMBtu

(3-hour block 

average)

0.02 lb/MMBtu

(3-hour block 

average)

0.02 lb/MMBtu 

(3-hour block 

average)

Emergency 

Engine

(256 hp)

0.8 lb/hr

(hourly average)

6.11 lb/hr

(hourly average)

0.03 lb/hr 

(hourly average)

0.03 lb/hr

(hourly average)

0.03 lb/hr

(hourly average)

Cooling tower n/a n/a 0.251 lb/hr, 

(hourly average)

0.251 lb/hr, 

(hourly average)

0.251 lb/hr

(hourly average)

7.1. BACT for a New Boiler at a Lumber Facility

The SPI- Anderson facility will install and operate a new boiler to support lumber 

operations at the sawmill and to sell electricity to the grid. The new boiler will have a 

maximum heat input capacity of 468 MMBtu/hr. The boiler is subject to BACT for NOx, 

CO, PM, PM10, and PM2.5. A top-down BACT analysis for each pollutant has been 

performed and is summarized below.

7.1.1. Oxides of Nitrogen 

NOx is formed at high temperatures during combustion when nitrogen in the combustion 

air or bound in the fuel combines with oxygen to form NO. Depending on conditions in 

the exhaust stream, some portion of the NO will react to form NO2. For the purposes of 

this analysis and the permit, all NOx is assumed to form NO2.

Step 1 - Identify All Control Technologies

A number of existing boiler designs support the combustion of biomass for purpose of 

electricity generation of this megawatt capacity. Therefore, in identifying all possible 

control technologies, the BACT analysis will initially begin with the discussion of two 

boiler design alternatives.

A significant distinction in boiler design for this purpose can be characterized by the 

biomass combustion process that occurs within the boiler’s combustion chamber. 

Biomass boilers can be classified as either being stoker or fluidized bed. Stoker boiler 

means a boiler unit consisting of a mechanically operated fuel-feeding mechanism which 

includes a stationary or moving grate to support the burning of fuel and admit under-grate 

air to the fuel, an overfire air system to complete combustion, and an ash discharge 

system. This definition of stoker includes air swept stokers. Fluidized bed boiler means a 

boiler utilizing a fluidized bed combustion process that is not a pulverized coal boiler.

Fluidized bed combustion means a process where a fuel is burned in a bed of granulated 

particles, which are maintained in a mobile suspension by the forward flow of air and 

combustion products. 

Boiler design technologies include, but are not limited to, the following: 

 

4

SPI- Anderson must keep all records of all testing, fuel use, and fuel testing requirements for a period of five (5) 

years and must report excess emissions to EPA on a semiannual basis.
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Stoker- including vibrating, traveling grate, etc.

Fluidized bed- including pressurized or atmospheric, such as bubbling bed, circulating, 

etc. 

In addition to the boiler design, the available inherent NOx control technology includes:

Good combustion practices

In addition to the inherent available control technology, the add-on NOx control 

technologies include:

Dry Low-NOx burner (DLN)

Selective non-catalytic reduction (SNCR)

Selective Catalytic Reduction (SCR) 

Regenerative SCR (RSCR)

SCR Variants

EMxTM system (formerly SCONOx)

Step 2 – Eliminate Technically Infeasible Options

Boiler Design Alternatives

For the proposed boiler to service SPI- Anderson’s existing primary lumber business and 

consume the wood from SPI’s other locations, the proposed boiler design must be able to 

reliably operate under various conditions. Furthermore, SPI has not entered a binding 

power purchasing agreement with consistent base load electricity demand. With daily 

variations in renewable energy demand and the sawmill’s steam requirements, the new 

boiler at the Anderson facility may have to vary steam production between 20% and 

100% of full load capacity. If electricity demand decreases or the turbine and/or generator 

malfunction, the boiler may need to significantly reduce the amount of steam it generates. 

However, periods of reduced steam demand do not necessarily coincide with reduced 

sawmill requirements. If other pieces of the cogeneration unit are not operating, and the 

boiler cannot reduce steam output, then the boiler must be shut down, rendering some of 

the lumber-drying kilns inoperable. If the kilns are unable to operate, lumber cannot be 

dried and the existing lumber facility may be unable to function normally. Moreover, as 

the modification will not expand beyond the current physical footprint of the SPIAnderson facility, the space for stockpiling wood may be exhausted while the kilns are 

inoperable, thus causing portions of the sawmill to be shut down. Therefore, any boiler 

chosen for the proposed modification must reliably function at low steam-load conditions 

in order to accommodate SPI- Anderson’s existing lumber operation.

The proposed boiler at the SPI- Anderson facility must be guaranteed to reliably operate 

at steam loads ranging from 50,000 lbs/hr to 250,000 lbs/hr. This variability in projected 

steam output is also caused by uncertainty in biomass fuel moisture and the variety of 

wood products and trimmings produced by SPI’s other nearby facilities. As Environ, 

SPI’s project consultant, stated in its January 23, 2012 letter5, “...several examples of 

 

5 Albright, Eric “Supplemental Control Technology Analysis Sierra Pacific Industries Biomass-Fired Cogeneration 

Project Anderson, California” Letter to Gerardo Rios. 23 Jan. 2012
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biomass-fired fluidized-bed boilers [are] in operation. However, most, if not all, produce 

steam solely for power generation, and do not provide process steam. Steam used to heat 

industrial processes is often subject to varying demand, especially for batch processes 

(e.g., lumber dry kilns). The primary reason for fluidized bed boiler designs lack of 

representation among biomass-fired process steam generators is the inability to operate in 

a turndown mode.” The process steam flexibility that SPI desires for its sawmill 

operations cannot reliably or effectively be accommodated by a fluidized bed boiler. 

Therefore, a fluidized bed boiler is technically infeasible for this project. 

EMxTM

To date, EMxTM has been designed and used only on small to medium sized natural gasfired stationary turbines for demonstration purposes. We are not aware of any biomass 

boiler applications currently operating with EMx, or any permit application for a biomass 

boiler that proposes to use the EMx to control NOx emissions.

The EMxTM system is sensitive to sulfur in the exhaust, which can degrade the 

performance of the system. While wood 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 EMxTM applications, has maximum sulfur limit of one grain per 100 

standard cubic feet (gr/scf) of gas in California, where EMxTM has been applied. On a 

heat input basis, this is equivalent to an SO2 emission rate of 0.43 lb/hr.

The lack EMx implementation for biomass boilers, combined with the sensitivity to sulfur 

suggest that EMxTM is technologically infeasible as a control technology for controlling 

NOx emissions from a biomass-fired boiler. Therefore we do not consider this technology 

achievable for biomass-fired boilers at this time.

DLN Burner 

With two or more DLN burners, the biomass combustion fuel would need to be 

pulverized and burned in suspension using wall-mounted burners. This presents a 

significant departure from SPI’s proposed boiler design where combustion occurs on a 

moving grate. DLN burners are designed to limit the amount of fuel-bound nitrogen that 

is converted to NOx during combustion, and are generally suited to boilers that burn 

wood waste containing a high percentage of resins, such as the waste from medium 

density fiberboard, plywood, or veneer operations. The emission rate with DLN burners 

is projected to be 0.35 lb/MMBtu.

Good combustion practices

A modern biomass-fired boiler furnace, operated with computerized controls to ensure 

good combustion practices would result in a NOx emission limit between 0.20 lb/MMBtu

and 0.26 lb/MMBtu. The boiler design proposed by SPI would emit 0.20 lb/MMBtu 

when utilizing only good combustion practices to reduce NOx emissions. Good 

combustion practices are the result of proper boiler maintenance and design. 

All of the listed add-on technologies described below are technically feasible for the 

proposed project. 
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SNCR (Selective Non-Catalytic Reduction)

With SNCR, ammonia is injected through ammonia-injection nozzles which are 

positioned in the furnace and used at relatively high temperatures to promote the reaction 

of NOx with ammonia. SNCR systems are often incorporated into the overall boiler 

design, and can be located at the furnace exit because they do not rely on a catalyst. 

Catalysts may be problematic for biomass stokers because catalyst beds are susceptible to 

plugging from PM in the flue gases. SNCR is a commonly-employed add-on NOx control 

technology for biomass-fired boilers. Over a long term basis the emission rate from a

design utilizing an SNCR system is projected to be 0.13 lb/MMBtu of NOx.

SCR (Selective Catalytic Reduction), RSCR (Regenerative Selective Catalytic 

Reduction) and other catalyst variants

An SCR system is similar to SNCR in that a reagent reacts with NOx to form nitrogen 

and water; however a catalyst matrix is used to allow the reduction reaction to take place 

at lower temperatures. There are several SCR and SCR variant systems that have been 

permitted for use on biomass boilers in various configurations along the exhaust stream. 

Although many biomass boilers have begun to be permitted with SCR and SCR variant 

systems, the verifiable data and the demonstrated effectiveness of SCR systems at 

constructed biomass facilities remains limited. Moreover, the projected NOx emissions 

from those facilities permitted with SCR vary considerably. 

The RBLC contains references to permitted RSCR and SCR systems with emission limits 

as low as 0.03 lb/MMBtu of NOx on a 12-month rolling basis as seen in Table 7.1-1. The 

lowest referenced NOx emissions limit that EPA has discovered in its review from 

constructed biomass power plants is McNeil Generating Station with a verified 2010 

quarterly calendar emission rate of 0.75 lb/MMBtu of NOx. However, the short term 

emission limit for the main boiler at McNeil while burning wood shall not exceed 0.23 

lb/MMBtu. The installation of that SCR system was permitted through a permit 

amendment. The facility “proposed to install and operate a selective catalytic reduction 

(SCR) system in order to reduce the facility’s emissions of NOx. The reduced NOx

emissions are required for the Facility to qualify for Class 1 renewable energy credits 

(RECs) in New England.”6 Aspen Power’s Lufkin Generating Station in Texas has 

constructed, however, EPA has not been able to verify if this NOx emissions limit has 

been demonstrated in practice over the shorter averaging period. 

Step 3 – Rank Control Technologies

A summary of recent NOx BACT determinations for biomass-fired boilers is provided in 

Table 7.1-1. The applicant has proposed a NOx limit of 0.13 lb/MMBtu, based on a 12-

month rolling average and 0.15 lb/MMBtu, based on a 3-hour block average. 

 

6 McNeil Generating Station Title V Permit
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Table 7.1-1: Summary of Recent NOx BACT Determinations for Similar Units

* McNeil Station is not the result of a BACT Determination as discussed in NOx Step 4 below. 

The remaining technologically feasible control technologies ranked in decreasing order of 

effectiveness are: 

Table 7.1-2: Ranking of NOx control technologies

NOx control technology Emission Rate 

(lb NOx /MMBtu)

SCR, RSCR and variants 0.06

SNCR 0.13

Good combustion practices 0.20

DLN burner 0.35

Step 4 – Economic, Energy and Environmental Impacts

SPI has submitted cost-effectiveness estimates comparing SCR and SNCR with their 

projected NOx emission rates and the cost of installation and operation of the respective 

control technologies. SPI assumed that the new boiler’s emission rate with the use of 

SCR for the cost-effectiveness estimates would be lower than any emissions level that 

EPA has found to be demonstrated in practice. SPI presumes that the rate of NOx

emissions with SCR and SNCR are 0.06 lb/MMBtu and 0.13 lb/MMBtu respectively.

The average cost per ton controlled from SCR and SNCR technologies at the proposed 

emission levels are $4,596 and $1,417 respectively. However, the incremental costeffectiveness separating the two technologies reveals that the cost of each additional ton 

of NOx removed by the implementation of SCR at the projected cost and emission rate is 

$9,191. EPA reviewed the cost estimates provided in the PSD permit modification 

application and determined that it considered the appropriate operation and capital costs 

but calculated improper potential to emit emissions estimates. The additional expense of 

the SCR equipment is due to a higher capital cost in primary equipment along with higher 

operational, maintenance and lost revenue costs. 
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Although the McNeil Generating Station has demonstrated a lower NOx emission limit on 

a calendar quarterly basis, it has a short term NOx emission limit of 0.23 lb/MMBtu. 

Moreover, the possible economic incentives of the Class 1 Renewable Energy Credits in

New England are difficult to quantify and not available to SPI- Anderson. This may 

allow SCR system to be more economically feasible for McNeil Generating Station and 

other proposed systems in the New England area than for SPI- Anderson in California.

EPA does not anticipate additional significant environmental or energy impacts from 

employing the SNCR or SCR technology. Both systems use ammonia as a reagent: 

anhydrous ammonia, aqueous ammonia, or urea mixed with water (which hydrolyzes in 

the hot exhaust to form ammonia). In the case of aqueous ammonia or urea mixed with 

water, additional fuel must be combusted to evaporate the water associated with the 

reagent. Moreover, energy is required to operate the injectors used by either technology 

to introduce the reagent into the exhaust. With either technology, the exhaust leaving the 

boiler stack will contain some small quantity of ammonia.

Step 5 – Select BACT

SPI has proposed the most stringent NOx emissions limit for stoker boilers with SNCR 

demonstrated in practice. Although additional tons of possible NOx emissions may be 

controlled by the installation of an SCR system, the increased annual costs of an SCR 

system or other variants versus the SNCR system is cost prohibitive at this existing 

sawmill facility. 

Based on a review of the available control technologies for NOX emissions from biomass 

boilers selected for this operation, we have concluded that BACT for the stoker boiler to 

perform this purpose is 0.15 lb/MMBtu (3-hour block average) and 0.13 lb/MMBtu (12-

month rolling average) employing SNCR. We are also requiring a lb/hr mass emission 

rate of 60.8 lb/hr (3-hour block average) during normal operations.

7.1.2. Carbon Monoxide

Carbon monoxide (CO) occurs due to incomplete combustion of fuel in the boiler’s 

combustion chamber, and in the Low-NOx burners when they are operated.

Step 1 - Identify All Control Technologies

A number of existing boiler design alternatives support the combustion of biomass at this 

megawatt capacity. Therefore, in identifying all possible control technologies, the BACT 

analysis should begin with a discussion of boiler design alternatives. 

In addition to the boiler design, the available inherent CO control technology includes:

Good combustion practices

In addition to the inherent available control technology, the add-on CO control 

technologies include:

EMxTM 

Catalytic oxidation
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Step 2 – Eliminate Technically Infeasible Options

Boiler Design Alternatives

As discussed in the BACT analysis for NOx in Section 7.1.1 of this document, fluidized 

bed boiler designs were found to be infeasible for this project.

EMxTM

As discussed in the BACT analysis for NOx in Section 7.1.1 of this document, EMx has 

been designed and used only on small to medium sized natural gas-fired stationary 

turbines for demonstration purposes. EMx has not been demonstrated in practice for 

biomass boilers and we do not consider this technology achievable for biomass boilers at 

this time. 

Good combustion practices

A modern biomass-fired boiler furnace, operated with computerized controls to ensure 

good combustion practices would result in a CO emission limit of between 0.23 and 0.35 

lb/MMBtu. The boiler design proposed by SPI would emit 0.23 lb/MMBtu of CO when 

utilizing only good combustion practices to reduce CO emissions. Good combustion 

practices are a technically feasible technology for controlling CO emissions from 

biomass-fired boilers.

The add-on technology described below is technically feasible for this project.

Catalytic Oxidation

Catalytic oxidation can be used to control CO when a matrix coated with noble metals 

facilitates the conversion of a pollutant, such as CO to CO2. Catalytic oxidizers operate in 

a temperature range of approximately 650°F to 1,000°F. At lower temperature the CO 

conversion efficiency falls off rapidly. Although technically feasible, catalytic oxidation 

has not been reliably demonstrated for biomass boilers. SPI projects that with successful 

implementation of a catalytic oxidizer the facility may be able to emit 0.1 lb/MMBtu of 

CO. Other permitted facilities that have not constructed have been permitted at CO 

emission levels as low as 0.075 lb/MMBtu of CO.

Step 3 – Rank Control Technologies 

A summary of recent BACT determinations for biomass-fired stoker boilers with CO 

emission limits is provided below. The applicant has proposed a CO limit of 0.23 

lb/MMBtu (3 hour block average). SPI has proposed the most stringent emission limit of 

constructed biomass stoker boilers that EPA was able to find in its control technology 

review.
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Table 7.1-3: Summary of Recent CO BACT Determinations for Similar Units

However, the new biomass boiler SPI- Anderson has not begun construction at this time. 

Based on this information, oxidation catalyst is being evaluated as the most stringent 

control. The remaining feasible control technologies ranked in decreasing order of 

effectiveness are: 

Table 7.1-4: Ranking of CO control technologies

CO control technology Emission Rate 

(lb CO /MMBtu)

Catalytic Oxidation 0.10

Good combustion practices 0.23

Step 4 – Economic, Energy and Environmental Impacts

SPI has submitted cost-effectiveness estimates comparing catalytic oxidation and good 

combustion practices with their projected CO emission rates and the cost of installation 

and operation of the respective control technologies. SPI assumed that the new boiler’s 

emission rate with the use of an oxidation catalyst for the cost-effectiveness estimates 

would be lower than any emissions level that EPA has found to be demonstrated in 

practice. SPI has presumed that the rate of CO emissions with catalytic oxidation and 

good combustion practices are 0.1 lb/MMBtu and 0.23 lb/MMBtu respectively.

As good combustion practices are the result of proper boiler maintenance and the boiler 

design, SPI only assessed the incremental cost-effectiveness separating the two 

technologies. The cost of each additional ton of CO removed by the implementation of 

catalytic oxidation at the projected cost and emission rate is $8,930. EPA reviewed the 

cost estimates provided in the PSD permit modification application and determined that it 

considered the appropriate costs but calculated improper potential to emit emissions 

estimates. The additional expense of the catalytic oxidizer is due to a higher capital cost 

in primary equipment along with higher operational, maintenance and lost revenue costs.

Step 5 – Select BACT

SPI has proposed the most stringent CO emissions limit for stoker boilers demonstrated 

in practice. Although additional tons of possible CO emissions may be controlled by the 
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installation of an oxidation catalyst, SPI has expressed significant doubts that the catalyst 

will be able to reliably and effectively control CO given its fuel type and operation. In 

addition, the increased annual costs of an oxidation catalyst present a significant financial 

burden at this existing sawmill facility.

Based on a review of the available control technologies for CO emissions from biomass 

boilers selected for this purpose, we have concluded that BACT for the stoker boiler to 

perform this operation is 0.23 lb/MMBtu (3-hour block average) employing good 

combustion practices. We are also requiring a lb/hr mass emission rate of 108 lb/hr (3-

hour block average) during normal operations.

7.1.3. Particulate Matter- PM, PM10, PM2.5

Particulate emissions are the result of unburned solid carbon (soot), unburned vapors or 

gases that subsequently condense, and unburned portions of fuel (ash). Because the 

applicant has assumed that all particulate emissions from the boiler are PM2.5, the BACT 

analyses for PM, PM10 and PM2.5 have been combined. Additionally, the analysis 

evaluates total particulate emissions – condensable and filterable.

Step 1 – Identify All Control Technologies

The following inherent control options for PM, PM10 and PM2.5 emissions include: 

Low sulfur fuels for normal operation, and/or pipeline natural gas for startup and 

shutdown

Good combustion practices 

The available add-on PM, PM10, PM2.5 control technologies include:

Cyclones (including multiclones)

Venturi scrubber

lectrostatic precipitator (ESP)

Baghouse/ Fabric filter.

Low sulfur fuels

The wood fuels to be used predominantly during normal operation along with the 

pipeline natural gas to be used during startup and shutdown are not generally considered 

high-sulfur fuels. 

Good combustion practices

A modern biomass-fired boiler furnace, operated with computerized controls to ensure 

good combustion practices, would result in a PM, PM10 and PM2.5 emission limit between 

0.33 lb/MMBtu and 0.56 lb/MMBtu, based on U.S. EPA’s AP-42 Compilation of Air

Pollutant Emission Factors for wood residue combustion in boilers. 

The add-on technologies described below are technically feasible for this project.

Cyclones or Multiclones
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Cyclones or multiclones, a series of single cyclone particulate matter separators, operate 

in a similar manner. An inlet gas stream enters the cyclone or multiclone at an angle 

causing the gas stream to spin rapidly. The resulting centrifugal forces push the larger 

particulate into and down along the cyclone walls for collection. 

Venturi Scrubbers

Venturi scrubbers reduce particulate by introducing liquid into a converging section of a 

gas stream. The particulate in the gas stream is removed when it mixes with the liquid 

and forms tiny droplets that are collected and removed. With gas-side pressure drops 

exceeding 15 inches of water, particulate collection efficiencies of 85% or greater have 

been reported for venturi scrubbers operating on wood-fired boilers.

lectrostatic precipitator (ESP)

Electrostatic precipitators use electrostatic forces to separate particulate from the gas 

stream. When applied to wood-fired boilers, ESPs are often used downstream of 

mechanical collector pre-cleaners which remove larger-sized particles. Collection 

efficiencies of 90-99% for particulate have been observed for ESPs operating on woodfired boilers.

Baghouse/ Fabric filter

Baghouses or fabric filters have had limited applications to wood-fired boilers. The 

principal drawback to fabric filtration is a fire danger arising from the collection of 

combustible carbonaceous fly ash. Although some fabric filters have demonstrated lower 

collection efficiencies, most fabric filter particle collection efficiencies are 90-99%, 

equivalent to ESPs. 

Step 2 – Eliminate Technically Infeasible Options

All of the available control options identified in Step 1 are technically feasible. Cyclones 

are often used in conjunction with the other control technologies listed above.

Step 3 – Rank Control Technologies 

A summary of recent BACT determinations for biomass-fired stoker boilers with PM,

PM10, and PM2.5 emission limits is provided below. The applicant has proposed a total 

PM, including filterable and condensable particulate, emission limit of 0.02 lb/MMBtu (3 

hour block average)utilizing an ESP preceded by a multiclone. SPI has proposed the most 

stringent PM, PM10, and PM2.5 emission limit of biomass stoker boilers that have 

constructed.
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Table 7.1-5: Recent PM, PM10, PM2.5 BACT Determinations for Similar Units

SPI has estimated that the use of a multiclone followed by an ESP or baghouse will be 

equally effective in the control of particulate matter from the proposed boiler. The 

feasible control technologies ranked in decreasing order of effectiveness are: 

Table 7.1-6: Ranking of PM/ PM10/ PM2.5 control technologies

PM/ PM10/ PM2.5

control technology

Emission Rate 

(lb PM/ PM10/ PM2.5 per MMBtu)

ESP with multiclone 0.02

Baghouse with multiclone 0.02

Venturi Scrubber 0.30

Low sulfur fuels 0.33

Good Combustion practices 0.33-0.56

Step 4 – Economic, Energy and Environmental Impacts

In EPA’s review, three biomass stoker facilities have proposed lower rates of total 

particulate emissions than SPI- Anderson. The 0.01 lb/MMBTu particulate emissions 

limit for Laidlaw Berlin Biopower was only for filterable particulate, not total particulate, 

and the project has been canceled. The succeeding total particulate emission levels in 

Table 7.1-5 for 0.18 lb/MMBtu and 0.19 lb/MMBtu of total particulate have been 

proposed but have not been demonstrated in practice. Moreover, the increased levels of 

control for total particulate in both of cases were proposed with different control 

technologies.

In our review, EPA found that the lowest achievable total particulate emissions 

demonstrated in practice from biomass stoker boilers have been achieved with fabric 

filters or ESPs. With equivalent levels of control, SPI considered the potential economic, 

energy and environmental impacts from each control system. Baghouses require 

additional energy to overcome increased pressure drops that occur during the control of 

particulate. ESP systems use electricity to create an electric field, but typically have 

lower overall energy requirements than baghouses. As stated earlier, fabric filters may 

also have an increased fire danger at biomass facilities due to the carbonaceous fly ash. 

Step 5 – Select BACT

Based on a review of the available control technologies for PM, PM10 and PM2.5

emissions from biomass boilers selected for this purpose, we have concluded that BACT 
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for the stoker boiler to perform this operation is 0.02 lb/MMBtu (3-hour block average)

using a multiclone and ESP. We are also requiring a lb/hr mass emission rate of 9.4 lb/hr

(3-hour block average) during normal operations.

7.1.3. Startup and Shutdown BACT Limits

The boiler startup process begins by igniting a pile of biomass fuel on the grate and firing 

two 62.5 MMBtu/hr natural gas burners located near the steam tubes. After 

approximately 12 hours, the boiler will be at about 50 % of full load and attain a 

sufficient steady state temperature supporting the activation of the SNCR system. Once 

the boiler has reached normal operating temperature, as specified by the boiler 

manufacturer, startup has concluded and the boiler will operate under normal conditions.

Shutdown begins when the fuel feed is curtailed and the unit begins cooling. Shutdown 

ends when the recorded temperature at the superheater outlet reaches 150°F and remains 

so for at least one hour, or 24 hours has elapsed since the shutdown process began. Addon particulate controls will be operating during all phases of startup and shutdown. The 

SNCR will be operating at all appropriate temperature ranges, as specificed by the SNCR 

manufacturer. During startup and shutdown, the generator shall be disconnected from the 

electrical grid.

Table 7.1-7 lists the startup and shutdown BACT emission and averaging times. Table 

7.1-7 also lists the maximum amount of time for a startup and shutdown event. 

Table 7.1-7: BACT for Startup and Shutdown

Pollution and Duration Limits

NOx

(hourly average) 70.2 lb/hr

CO

(hourly average) 108 lb/hr

PM, PM10, PM2.5

(24 hour average) 8.93 lb/hr

SO2

(hourly average) 2.34 lb/hr

Maximum Duration 24 hours

7.2 BACT for Emergency Engine

The project includes a 256hp (190kW) natural gas-fired emergency engine to run the 

emergency boiler recirculation pump. The limited operation of this unit results in 

minimal annual emission rates. This equipment is subject to BACT for NOx, CO, PM,

PM10, PM2.5. A top-down BACT analysis has been performed and is summarized below.

7.2.1 NOx, CO, PM, PM10, PM2.5 Emissions

Step 1 -- Identify all control technologies

The control options for NOx emissions from engines include SCR, NOx reducing catalyst, 

NOx adsorber, catalyzed diesel particulate filter, catalytic converter, and oxidation 

catalyst. A catalytic converter and oxidation catalyst are also control options for CO 
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emissions. A particulate filter/trap can be added for the control of PM, PM10, and PM2.5

emissions,

Unlike the main biomass boiler, the emergency engine will be limited in operation and is 

required to be certified in compliance with NSPS requirements, including emission 

limits, upon purchase. A review of other BACT determinations was not performed 

because it is very unlikely that a more detailed review would change the final 

determination due to the limited use and annual emission rates associated with the 

proposed limits. The potential to emit for all criteria pollutants subject to BACT review is 

less than 200 lbs/yr.

Different types of engines have different emission requirements based on the type of 

engine being purchased. Engine manufacturers may need to employ some of the control 

technologies identified above in order to comply with the NSPS emission limits, 

depending on the type of engine and the applicable limits. The applicant is proposing to

install an emergency engine for infrequent recirculation pump needs. As a result, SPI 

must purchase engines that comply with the NSPS and meet the emission requirements 

for emergency engines. However, we note that the applicant could purchase engines that 

meet the NSPS standards for non-emergency engines, which have more stringent limits, 

and operate them as emergency engines. As a result, this review identifies the control 

technologies to be:

NSPS-compliant emergency engine 

Engine that meets NSPS for non-emergency engines

Limiting use (limits on the hours of operation)

Step 2 – Eliminate technically infeasible control options

All of the control technologies identified are assumed to be technically feasible.

Step 3 – Rank remaining control technologies

The available control technologies are ranked according to control effectiveness in Table 

7.2-1.

Table 7.2-1: NSPS Limits for Engines

Engine Type (190kW) NOx +NMHC

(g/kW-hr)

CO

(g/kW-hr)

PM

(g/kW-hr)

Non-emergency engine 0.59 3.5 0.02

Emergency engine 4.0 3.5 0.20

Step 4 – Economic, Energy and Environmental Impacts

Due to economic impacts and limited environmental benefit, the use of add-on controls 

for the emergency engine and purchasing an engine that meet NSPS standards for a nonemergency engine and operating it as an emergency engine would be impractical in this 

case. This is illustrated in Table 7.2-2 by the potential emissions from the emergency 

engine (based on 100 hours of operation per year and complying with the NSPS for 

emergency engines). Requiring the additional reductions in emissions that would be 
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gained by use of engines that meet NSPS standards for non-emergency engines would 

have very little environmental benefit and not justify the cost. 

Table 7.2-2: Summary of PTE for 190 kW Emergency Engine

Pollutant Emergency Engine (tpy)

NOx 0.039

CO 0.306

PM, PM10, PM2.5 0.0011

Step 5 – Select BACT

Based on a review of the available control technologies, we have concluded that BACT is 

limiting the hours of operation and the emission limits listed in Table 7.2-3 based on a 3-

hour average. It is assumed that newly purchased engines would be the most energy 

efficient available and that operating in compliance with NSPS requirements will ensure 

that each engine is properly maintained and as efficient as possible.

Table 7.2-3: Summary of BACT for 190 kW Emergency Engine

Engine Type NOx +NMHC

(g/kW-hr)

CO

(g/kW-hr)

PM

(g/kW-hr)

Emergency engine 4.0 3.5 0.20

7.3. BACT for Cooling Towers

The proposed project also requires a cooling tower system to dissipate the heat load into 

the atmosphere. The cooling tower system is subject to BACT for PM, PM10, and PM2.5. 

A top-down BACT analysis has been performed and is summarized below. The applicant

conservatively assumed PM, PM10 and PM2.5 emissions from the cooling tower were 

equivalent.

Step 1 - Identify All Control Technologies

The following inherent control options for PM, PM10, and PM2.5 emissions include:

Wet cooling

Dry cooling

Wet-Dry Hybrid cooling

Wet cooling

Cooling towers are heat exchangers that are used to dissipate large heat loads to the

atmosphere. They are used as an important component in many industrial and 

commercial processes needing to dissipate heat. Wet cooling towers rely on the latent 

heat of water evaporation to exchange heat between the process and the air passing 

through the cooling tower.

A two-cell evaporative cooling tower for this project would require a water load 4.24 

gallons per minute per square foot. The expected air velocity is 503 feet per minute. 

Fugitive particulate emissions would be generated from the cooling tower due to the total 

dissolved solids (TDS) in the water.
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Dry cooling

Dry cooling uses an air cooled condenser (ACC) that cools the steam turbine generators’

exhaust steam using a large array of fans that force air over finned tube heat exchangers. 

The exhaust from the steam turbine flows through a large diameter duct to the ACC 

where it is condensed inside the tubes through indirect contact with the ambient air. The 

heat is then released directly to the atmosphere.

Wet-Dry Hybrid cooling

Wet-Dry Hybrid cooling uses wet and dry cooling technologies in parallel, and uses all of

the equipment involved in both wet and dry cooling. Hybrid cooling technology divides

the cooling function between the wet and dry systems depending on the capabilities of

each system under different environmental and operational conditions.

The available add-on PM, PM10, and PM2.5 control technologies include:

Drift eliminators

Drift Eliminators

Drift eliminators are usually incorporated into the tower design to remove as many 

droplets as practical from the air stream before exiting the tower. The drift eliminators 

used in cooling towers rely on inertial separation caused by direction changes while 

passing through the eliminators. Types of drift eliminators include many different 

configurations and various materials. The materials may include other features, such as 

corrugations and water removal channels, to enhance the drift removal further.

Step 2 – Eliminate Technically Infeasible Options

All of the available control options identified in Step 1 are technically feasible.

Step 3 – Rank Control Technologies 

The remaining feasible control technologies ranked in decreasing order of effectiveness are: 

Table 7.3-1: Ranking of PM/ PM10/ PM2.5 control technologies

PM/ PM10/ PM2.5

control technology

Emission Rate 

(tpy of PM, PM10, PM2.5)

Dry cooling 0

Wet-Dry Hybrid cooling 0.557

Wet cooling with 0.0005% 

Drift Eliminators

1.10

The applicant has proposed to use wet cooling with DRU-1.5 high-efficiency mist 

eliminators with a drift loss of less than 0.0005%. This is the equal to the lowest proposed 

amount of drift that EPA has found in its review of similar facilities. 

 

7

The applicant did not estimate potential emissions from a wet-dry hybrid system. We have approximated 

emissions from such a system to be one-half of those from a wet cooling system.
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EPA did not find any sawmill facilities or biomass boilers that use dry cooling or wet-dry 

hybrid cooling as an alternative to wet cooling. As shown in Table 7.3-1 the potential 

impact from the various control options will have a limited effect on the total PM

emissions from the project. The difference in potential to emit resulting from the cooling 

tower options is 1.10 tpy of total PM.

Step 4 – Economic, Energy and Environmental Impacts

The use of a dry or hybrid wet-dry system would reduce the overall efficiency of the 

facility, due to the additional energy requirements for the wet and hybrid systems.

Moreover, dry and wet-dry cooling systems are typically more costly than a more 

conventional wet cooling tower system. On the other hand, the use of wet cooling has a 

potential environmental impact associated with additional consumption of water 

resources.

Step 5 – Select BACT

Based on a review of the available control technologies for PM, PM10, PM2.5emissions 

from cooling towers selected for this operation, and the limited amount of total 

particulate resulting from the cooling tower operation, we have concluded that the 

proposed boiler can utilize wet cooling. 

Utilizing the wet cooling tower option, SPI has elected to use the most stringent control 

option available, by limiting drift to 0.0005%. Therefore, BACT for the cooling tower in 

the proposed modification will be the use of a wet cooling tower with a drift loss of less 

than 0.0005%. 

8. Air Quality Impacts

CAA Section 165 and EPA’s PSD regulations at 40 CFR § 52.21 require an examination 

of the impacts of the proposed SPI- Anderson project on ambient air quality. The 

applicant must demonstrate, using air quality models, that the facility’s emissions of

PSD-regulated air pollutants would not cause or contribute to a violation of (1) the 

applicable NAAQS, or (2) the applicable PSD increments (explained below in Sections 

8.4 and 8.5). These sections of the AAQIR include a discussion of the relevant 

background data and air quality modeling, and EPA’s conclusion that the project will not 

cause or contribute to an exceedance of the applicable NAAQS or applicable PSD

increments and is otherwise consistent with PSD requirements governing air quality.

8.1 Introduction

8.1.1 Overview of PSD Air Impact Requirements

Under the PSD regulations, permit applications for major sources must include an air 

quality analysis demonstrating that the facility’s emissions of the PSD-regulated air 

pollutants will not cause or contribute to a violation of the applicable NAAQS or 

applicable PSD increments. (A PSD increment for a pollutant applies only to areas that 

meet the corresponding NAAQS.) The applicant provides separate modeling analyses for 
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each criteria pollutant emitted above the applicable significant emission rate. If a 

preliminary analysis shows that the ambient concentration impact of the project by itself 

is greater than the Significant Impact Level (SIL), then a full or cumulative impact 

analysis is required for that pollutant. The cumulative impact analysis includes nearby 

pollution sources in the modeling, and adds a monitored background concentration to 

account for sources not explicitly included in the model. The cumulative impact analysis 

must demonstrate that the modification will not cause or contribute to a NAAQS or 

increment violation. If a preliminary analysis shows that the ambient concentration 

impact of the project by itself is less than the SIL, then further analysis is generally not 

required. Required model inputs characterize the various emitting units, meteorology, and 

the land surface, and define a set of receptors (spatial locations at which to estimate 

concentrations, typically out to 50 km from the facility). Modeling should be performed 

in accordance with 40 CFR § 51, Appendix W- Guideline on Air Quality Models

(GAQM). AERMOD with its default settings is the standard model choice, with 

CALPUFF available for complex wind situations. 

A PSD permit application typically includes a Good Engineering Practice (GEP) stack 

height analysis, to ensure that downwash is properly considered in the modeling, and 

stack heights used as inputs to the modeling are no greater than GEP height, so as to 

disallow artificial dispersion from the use of overly tall stacks. The application may also 

include initial “load screening,” in which a variety of source operating loads and ambient 

temperatures are modeled, to determine the worst-case scenario for use in the rest of the 

modeling.

The PSD regulations also require an analysis of the impact on nearby Class I areas, 

generally those within 100 km, though the relevant Federal Land Manager (FLM) may 

specify additional or fewer areas. This analysis includes the NAAQS, PSD increments, 

and Air Quality Related Values (AQRVs). AQRVs are defined by the FLM, and typically 

limit visibility degradation and the deposition of sulfur and nitrogen. Generally, 

CALPUFF is the standard model choice for Class I analyses because it can handle 

visibility chemistry as well as the typically large distances (over 50 km) to Class I areas.

Finally, the PSD regulations require an additional impact analysis, showing the project's 

effect on visibility, soils, vegetation, and growth. This visibility analysis is independent 

of the Class I visibility AQRV analysis. The additional impact analysis for the SPIAnderson project is discussed in Section 9.

8.1.2 Identification of SPI- Anderson Modeling Documentation

The applicant, SPI, submitted numerous documents and materials which comprise the 

entire modeling analysis. PSD and ATC permit Application (May 2007) contains the 

results of the original modeling and most of the Class I analyses. The updated PSD and 

ATC Application and associated compact disc (March 2010) contain updated modeling

results. Response to Incompleteness Determination #1 (July 2010), containing a full 

impact analysis for compliance with the 1-hour NO2 NAAQS and a partial Additional 

Impacts Analysis. Response to Incompleteness Determination #2 (September 2010) 

revisits the 1-hour NO2 NAAQS compliance analysis and provides monitoring and 
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meteorology background information. Startup/Shutdown Information (December 2010) 

contains proposed limits on the number of annual startups and shutdowns. Response to 

Additional Information Request (June 2011) provides further information on proposed 

startup and shutdown emission limits. Updated Air Dispersion Modeling Analysis (May 

2012) contains modeling files and an updated modeling analysis that reflects project 

changes since the March 2010 submittal. Surface Characteristics (June 2012) describes 

the surface characteristics between the meteorology site and the project site as well as 

modeling receptor network. Background Concentration Information (June 2012) supplies 

information regarding the monitoring background concentrations. CALPUFF Modeling 

Files (June 2012) contains archived CALPUFF modeling files developed for the original 

May 2007 PSD application and used in subsequent submittals.

8.2. Background Ambient Air Quality

The PSD regulations require the air quality analysis to contain air quality monitoring data 

as needed to assess ambient air quality in the area for the PSD-regulated pollutants for 

which there are NAAQS that may be affected by the source. In addition, for 

demonstrating compliance with the NAAQS, a background concentration is added to 

represent those sources not explicitly included in the modeling, so that the total accounts 

for all contributions to current air quality.

The applicant used ambient air concentrations of NO2, which were recorded at Manzanita 

Avenue in Chico 55.5 miles (90 km) south of the facility’s current location. This was the 

closest and most representative NO2 monitor to the site. For PM2.5 background 

concentrations, the applicant used data from a monitor at the Redding Department of 

Health which is approximately 6.5 miles (10.5 km) northeast from the facility. The 

applicant took PM10 background concentrations from Anderson, which is around 6.5 

miles southeast from the facility site.

Table 8.2-1 describes the maximum background concentrations (from 2011) of the PSDregulated pollutants for which there are NAAQS that may be affected by the project’s 

emissions, and the corresponding NAAQS.

Table 8.2-1: Maximum Background Concentrations and NAAQS

Pollutant,

Averaging Time

Background Concentration 

(μg/m3)

NAAQS

(μg/m3)

NO2, 1-hour 62.7 (33 ppb) 188 (100 ppb)

NO2, annual 33.1 (17 ppb) 100 (53 ppb)

PM10, 24-hour 42 150

PM2.5, 24-hour 15.3 35

PM2.5, annual 5.3 15

CO, 1-hour 2,976 (2.6 ppm) 40,000 (35 ppm)

CO, 8-hour 2,404 (2.1 ppm) 10,000 (9 ppm)

Ozone, 8-hour 71 ppb 75 ppb

Note: The PM2.5 24-hr value is 98th percentile averaged over three years rather than maximum

The NO2 1-hr value is 98th percentile averaged over three years rather than maximum

The Ozone 8-hour value is the fourth highest 8-hour concentration averaged over three years
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8.3 Modeling Methodology for Class II areas

The applicant modeled the impact of SPI- Anderson on the NAAQS and PSD Class II 

increments using AERMOD in accordance with GAQM. The modeling analyses included 

the maximum air quality impacts during normal operations and startups and shutdowns, 

as well as a variety of conditions to determine worst case, short-term air impacts.

8.3.1 Model selection

As discussed in the PSD Application (Updated PSD Application, March 2010, 

p.11pdf15), the model that the applicant selected for analyzing air quality impacts in 

Class II areas is AERMOD, along with AERMAP for terrain processing and AERMET 

for meteorological data processing. This is in accordance with the default 

recommendations in Section 4.2.2 on Refined Analytical Techniques in GAQM.

8.3.2 Meteorology model inputs

AERMOD requires representative meteorological data in order to accurately simulate air 

quality impacts. The applicant used surface meteorological data collected for a five 

consecutive-year period (2004-2008) at the Redding Municipal Airport meteorological

station. This station is located approximately 2.8 (4.5 km) miles from the project site. 

The applicant processed these data using EPA’s AERMET data processor. EPA concurs

that the chosen 2004-2008 Redding data is the most representative for the SPI- Anderson

analysis.

For upper air data, the applicant obtained data from the 2004-2008 Medford, Oregon 

upper air site located approximately 134 miles (215 km) northwest of the project site as 

being the most representative site available that had data complete enough to use. No 

other upper air meteorological monitoring stations are located closer to the project site. 

(Updated PSD Application,p.13pdf.17). EPA agrees that it is appropriate to use 

Medford, Oregon upper air data for the SPI- Anderson analysis.

8.3.3 Land characteristics model inputs

Land characteristics are used in the AERMOD modeling system in three ways: 1) via 

elevation within AERMOD to assess plume interaction with the ground; 2) via a choice 

of rural versus urban algorithm within AERMOD; and 3) via specific values of AERMET 

parameters that affect turbulence and dispersion, namely surface roughness length, 

Bowen ratio, and albedo. The surface roughness length is related to the height of 

obstacles to the wind flow and is an important factor in determining the magnitude of 

mechanical turbulence. The Bowen ratio is an indicator of surface moisture. The albedo 

is the fraction of total incident solar radiation reflected by the surface back to space 

without absorption. 

Terrain elevations for receptors and emission sources were prepared using 1/3rd arcsecond National Elevation Dataset 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. Terrain heights surrounding the facility indicate that some of 
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the receptors used in the simulations were located in intermediate or complex terrain 

(above stack or plume height). For determining concentrations in elevated terrain, SPI 

chose the AERMAP terrain preprocessor receptor-output file option.

SPI determined surface parameters including the surface roughness length, albedo, and 

Bowen ratio 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. The NLCD92 data set used in 

the analysis has 30 meter data point spacing and 21 land-use categories. Seasonal surface 

parameters were determined using AERSURFACE according to EPA’s guidance.

EPA requested additional detail characterizing the surface parameters surrounding the 

SPI-Anderson site for comparison with the airport site. Based on this comparison, the 

applicant and EPA conclude that the use of Redding meteorological data is adequately 

representative of the project site.

8.3.4 Model receptors

Receptors in the model are geographic locations at which the model estimates 

concentrations. The applicant places the receptors such that they have good area coverage 

and are closely spaced enough so that the maximum model concentrations can be found. 

At larger distances, spacing between receptors may be greater than it is close to the 

source, since concentrations vary less with increasing distance. The spatial extent of the 

receptors is limited by the applicable range of the model (roughly 50 km for AERMOD), 

and possibly by knowledge of the distance at which impacts fall to negligible levels. 

Receptors need be placed only in ambient air, that is, locations to which the public has 

access, and that are not inside the project fence line. 

The applicant used Cartesian coordinate receptor grids to provide adequate spatial 

coverage surrounding the project area and to identify the extent of significant impacts and 

the maximum impact location. For all analyses except 1-hour average NO2, receptors 

were spaced 500 m apart covering the 10 km square 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. For the 1-hour average NO2 analysis, the 

modeling domain was extended to 20 km, and the additional area was covered by 

receptors placed 500 m apart. (Surface Characteristics, p.1pdf1)

8.3.5 Stack parameter model inputs

The modeling conducted by the applicant used the corresponding stack parameters in 

Table 8.3-1 for normal operations and during startup and shutdown to provide 

conservative estimates of SPI- Anderson impacts.
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Table 8.3-1: Load Screening and Stack Parameters for Cogeneration Unit

Operating 

Mode

Stack Height

(ft)

Stack Diameter

(ft)

Stack Velocity

(ft/sec)

Stack Temperature

(°F)

SU/SD 85 8.5 36.7 294

Normal 85 8.5 61.1 350

Operating 

Mode

NOx

(lb/hr)

PM10/ PM2.5

(lb/hr)

CO

(lb/hr)

SU/SD 70.2 8.93 432

Normal 70.2 8.93 108

Source for both parts of table 8-3: Updated Air Dispersion Modeling Analysis (May 2012), p.3, Tables 1,2 

and 5pdf.3, 7 and 10.

8.3.6 Good Engineering Practice (GEP) Analysis

The applicant performed a Good Engineering practice (GEP) stack height analysis to 

ensure that downwash is properly considered and that stack heights used as inputs to the 

modeling are no greater than GEP height. This disallows artificial dispersion from the use 

of overly tall stacks. As is typical, the GEP analysis was performed with EPA’s Building

Profile Input Program software, which uses building dimensions and stack heights as 

inputs. Based on the analysis, the applicant shows that the GEP stack height for the 

boiler stack would have to exceed the maximum creditable GEP height of 65 m in order 

to ensure protection against downwash. The applicant showed that the GEP stack height 

for the other equipment was similarly greater than the planned heights. So, for all 

emitting units, the applicant used the planned actual stack heights for inputs in AERMOD 

modeling, and included wind direction-specific Equivalent Building Dimensions to 

properly account for downwash. (PSD Application p.14pdf.18)

8.4 National Ambient Air Quality Standards (NAAQS) and PSD Class 

II Increment Consumption Analysis

8.4.1 Pollutants with significant emissions

40 CFR § 52.21 requires an air quality impact analysis for each PSD-regulated pollutant 

(for which there is a NAAQS) that a major source has the PTE in a significant amount, 

i.e., an amount greater than the Significant Emission Rate (SER) for the pollutant. 

Applicable SPI- Anderson emissions and the SERs are shown in Table 8.4-1. As shown 

in Table 8.4-1, EPA does not expect SPI- Anderson to emit Pb, VOC and SO2 in 

significant amounts. However, based on the estimates submitted by the applicant, EPA 

expects SPI- Anderson to emit CO, NOx, PM10, and PM2.5 in significant amounts. 

Therefore, this project triggers the air impact analyses requirements for CO, NO2, PM10

and PM2.5.
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Table 8.4-1: PSD Applicability to SPI- Anderson: SER

Pollutant Emissions

(tpy)

SER

(tpy)

Does PSD

Apply?

CO 472 100 Yes

NOx 267 40 Yes

PM10 42.1 15 Yes

PM2.5 42.1 10 Yes

SO2 10.3 40 No

Pb 0.03 0.6 No

VOC 34.8 40 No

8.4.2 Preliminary analysis: Project-only impacts (Normal Operations 

and Startup)

EPA has established Significant Impact Levels (SILs) to characterize air quality impacts.

A SIL is the ambient concentration resulting from the facility’s emissions, for a given 

pollutant and averaging period, below which the source is considered to have an 

insignificant impact. For maximum modeled concentrations below the SIL, further air 

quality analysis for the pollutant is generally not necessary. In some cases it may be 

appropriate to consider additional information in order to conclude that a source will not 

be responsible for creating a new NAAQS exceedance, however. For maximum 

concentrations that exceed the SIL, EPA requires a cumulative modeling analysis, which 

incorporates the combined impact of nearby sources of air pollution to determine 

compliance with the NAAQS and PSD increments.

Table 8.4-2 shows the results of the preliminary or project-only analysis based on 

maximum operations for SPI- Anderson. Startup emissions are used for determining the 

maximum 1-hour NO2, 1-hour and 8-hour CO, and 24-hour PM10, PM2.5 impacts with 

maximum project impacts from normal operations included in parentheses. Startup CO 

emissions are expected to exceed those experienced during normal operating conditions. 

Startup and normal 1-hour NO2 and 24-hour PM10, PM2.5 emissions are the same; only the 

flow rates are lower for the startup case. 1-hour NO2 impacts are based on the 

assumption that 80% of the NO is converted to NO2, while the annual average NO2

concentrations are based on the assumption that 75% of the NO is converted to NO2. 

Based on Table 8.4-2, SPI- Anderson’s impacts are significant only for annual and 1-hour 

NO2, and 24-hour PM2.5, and we have determined that in this case cumulative impacts 

analyses are required only for these pollutants and averaging periods.
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Table 8.4-2: SPI- Anderson Significant Impacts

NAAQS pollutant,

Averaging Time

Project-only 

Modeled Impact 

(μg/m3

)

Significant 

Impact Level

(μg/m3)

Significant 

Impact?

NO2, 1-hour 38.6 (26.3) 7.5 (4 ppb) Yes

NO2, annual 1.35 1 Yes

PM10, 24-hour 3.36 (2.23) 5 No

PM2.5, 24-hour 3.11 (1.84) 1.2 Yes

PM2.5, annual 0.27 0.3 No

CO, 1-hour 307 (122) 2000 No

CO, 8-hour 212 (36) 500 No

Sources: Updated Modeling Analysis (May 2012), Tables 3 and 6pdf8,11

8.4.3 Cumulative impact analysis

A cumulative impact analysis considers impacts from nearby sources in addition to

impacts from the project itself. For demonstrating compliance with the NAAQS the 

applicant also adds a background concentration to represent those sources not explicitly 

included in the modeling, so that the total accounts for all contributions to current air 

quality. In this case, the applicant submitted cumulative impact analyses demonstrating 

compliance with the 24-hour PM2.5 NAAQS and the annual and 1-hour NO2 NAAQS.

PSD increments are limits on cumulative air quality degradation. They are set to prevent 

air with pollutant concentrations lower than the NAAQS from being degraded to the level 

of the NAAQS. PSD increments apply in addition to the NAAQS. Increments have been 

established for some pollutants, such as for this project, specifically for NO2, PM10 and

PM2.5. For demonstrating compliance with the PSD increment, only incrementconsuming sources need to be included because the increment concerns only changes 

occurring since the applicable baseline date.

There is an annual NO2 PSD increment, but there is no 1-hour NO2 PSD increment; 

therefore, only 24-hour PM2.5 and annual NO2 require cumulative PSD increment 

analyses. 

For evaluating NO2 annual increment in this analysis, the applicant used all of the same 

sources that were in the NAAQS inventory, which is conservative.

With respect to the PSD increment analysis for PM2.5, the applicable trigger date when 

the PM2.5 increments become effective under the Federal PSD program is October 20, 

2011. The SPI- Anderson PSD permit application was determined to be administratively 

complete by EPA on October 4, 2010. However, EPA is requiring each source that 

receives its PSD permit after the trigger date, regardless of when the application was 

submitted, to provide a demonstration that the proposed emissions increase, along with 

other increment consuming emissions will not cause or contribute to a violation of the 

PM2.5 increments. Also the major source baseline, which precedes the trigger date is the 

date after which actual emissions increases associated with construction at any major 

stationary source consume PSD increment. That date is October 20, 2010. With this PSD 
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permit, SPI-Anderson would begin construction after this date. In general, for PM2.5, the 

minor source baseline date is the earliest date after the trigger date of a complete PSD

permit application for a source with a proposed increase in emissions of PM2.5 that is 

significant. No source has triggered the minor source baseline date in the area at issue. 

Other than SPI- Anderson’s projected construction emissions, there have been no actual 

emissions changes of PM2.5 from any new or modified major stationary source on which 

construction commenced after October 20, 2010. Therefore, the only source to consume 

PM2.5 increment in the area is SPI- Anderson. The applicant considered only the 

allowable emissions increase from the SPI- Anderson project in the 24-hour PM2.5

increment analysis.

8.4.3.1 Nearby source emission inventory

For both the PSD increment and NAAQS analyses, there may be a large number of 

sources that could potentially be included. Only sources with a significant concentration 

gradient in the vicinity of the source need to be included; the number of such sources is 

expected to be small, except in unusual situations. (GAQM 8.2.3)

Shasta and Tehama Counties provided a list of all stationary sources within their counties 

and within 55.4 km of the project site (approximate distance to the farthest significant 

impact plus 50 km) for NO2 and 51.0 km for PM2.5. A comprehensive procedure was 

used to determine which sources were included in the emissions inventory to be modeled. 

This included screening out a source by whether it had a significant impact where the 

project was predicted to have a significant impact. 

 

We note that short-term maximum emission rates are used rather than annual emission 

rates to determine the distance over which a facility might have a significant impact for 

short-term standards (e.g., hourly NO2). Use of short-term rates results in the greatest 

impacts at the farthest distance. Thus, the peak rates that occur during startup determine 

the SPI- Anderson significant impact area (SIA) for hourly NO2.

SPI identified nine facilities nearby for inclusion in the emission inventory for the 1-hour 

NO2 cumulative analysis, based on data from Shasta and Tehama Counties. The 

following non-SPI- Anderson facilities and their NOx and PM2.5 emissions are included in 

the cumulative compliance demonstration: Kiara Co Gen project, Wheelabrator Shasta 

Co-Gen (NOx only), Wheelabrator Lassen Gas Turbine (NOx only), City of Redding

power plant (NOx only), Ag Products Asphalt (NOx only), JF Shea Smith Road Asphalt, 

Lehigh Cement (NOx only), North State Asphalt (NOx only), and Tehama Processing 

(NOx only). These facilities are large enough and close enough to the project site to have 

the potential to directly impact the project’s SIA. (Updated Air Dispersion Modeling 

Analysis, Tables 13-14pdf.20-21). 

Current EPA NO2 guidance recommends that emphasis on determining which nearby 

sources to include in the nearby source inventory should focus on the area within about 

10 km of the project location in most cases. This indicates that the SPI- Anderson

inventory is adequate for performing these cumulative analyses (p.16 of “Additional 

Clarification Regarding Application of Appendix W Modeling Guidance for the 1-hour 
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NO2 National Ambient Air Quality Standard”, Memorandum from Tyler Fox, EPA Air 

Quality Modeling Group to EPA Regional Air Division Directors, March 1, 2011). 

Considering a focus on sources within 10 km, EPA concludes that the combination of 

representative background monitored concentrations and the additional consideration of 

sources out to 50 km provide sufficient justification for the inventories used in the 

cumulative analysis.

8.4.3.2 Discussion of Certain PM2.5-Specific Considerations

EPA has issued guidance on how to combine modeled results with monitored background 

concentrations which the applicant adequately followed. (“Modeling procedures for 

Demonstrating Compliance with PM2.5 NAAQS”, memorandum from Stephen D. Page, 

Director, EPA OAQPS, March 23, 2010.) 

SPI provided a cumulative PM2.5 24-hour analysis. The applicant’s analysis 

conservatively assumed that all PM10 emissions were comprised of PM2.5 emissions, and 

therefore used PM10 emissions data as input to the modeling. Thus, actual PM2.5 impacts 

are expected to be lower than those indicated in the model results. 

PM2.5 is either directly emitted from a source (primary emissions) or formed through 

chemical reactions with pollutants already in the atmosphere (secondary formation). 

EPA has not developed and recommended a near-field model that includes the necessary 

chemistry algorithms to estimate secondary impacts in an ambient air analysis. 

The SPI- Anderson application does not specifically address secondarily formed PM2.5

(as distinguished from directly emitted primary PM2.5). Secondary PM2.5 is formed 

through the emission of non-particulates (i.e., gases) – such as SO2 and NOx – that turn 

into fine particulates in the atmosphere through chemical reactions or condensation. 

Using the results for PM2.5 impacts given in Tables 8.4-2 and 8.4-3 and the projected 

emission rates of SO2, NOx and PM2.5, EPA notes that the SPI- Anderson emissions of 

10.3 tpy SO2 are less than the SO2 SER of 40 tpy, and would not be expected to result in 

significant secondary PM2.5. The SPI- Anderson NOx emissions of 267 tpy are above the 

NOx SER of 40 tpy. However, secondary PM2.5 formation occurs only as a result of 

chemical transformations that would affect only a portion of those emissions. Moreover, 

the formation occurs gradually over time as the plume travels and becomes increasingly 

diffuse and would be expected to be considerably smaller than the impacts from the 42.1

tpy of directly emitted primary PM2.5. The maximum impact of source primary PM2.5 was 

3.11 μg/m3for 24-hour PM2.5 and 0.27 μg/m3for annual PM2.5. The 24-hour PM2.5 

cumulative impacts analysis which gives a maximum impact of 28.8 ug/m3, with a 

background concentration of 15.3 ug/m3, indicates that at least 6.2 μg/m3remains

available for the 24-hour averaging time before the NAAQS is challenged (35 μg/m3–

28.8 μg/m3). For the annual averaging time no cumulative impact analysis was required 

because the project’s annual impacts were less than the SIL. However, the background 

concentration was 5.3 μg /m3. Adding this result to the project’s predicted impact of 0.27 

μg /m3yields a concentration of 5.57 μg /m

3

. This result is less than a third of the 

NAAQS and leaves about 9 μg /m3remaining before the NAAQS is challenged. The 
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monitored background PM2.5 concentrations would also conservatively include 

secondarily formed PM2.5 from the surrounding/nearby sources. Because the secondary

PM2.5 formation from SPI- Anderson’s NOx emissions would be expected to be 

considerably smaller than the primary PM2.5 impacts, they would also be smaller than the 

additional 6.2 μg/m3or 9 μg/m3needed to cause or contribute to a PM2.5 NAAQS 

violation. In addition, most of these chemical transformations in the atmosphere occur 

slowly (over hours or even days, depending on atmospheric conditions and other 

variables), causing secondary PM2.5 impacts to occur generally at some distance from the 

source of its gaseous emissions precursors, and are unlikely to overlap with nearby 

maximum primary PM2.5 impacts.

8.4.3.3 Discussion of Certain 1-hour NO2-Specific Considerations

While the new 1-hour NO2 NAAQS is defined relative to ambient concentrations of NO2, 

the majority of NOx emissions from stationary sources are in the form of nitric oxide 

(NO) rather than NO2. GAQM notes that the impact of an individual source on ambient 

NO2 depends in part “on the chemical environment into which the source’s plume is to be 

emitted” (see Section 5.1.j). Because of the role NOx chemistry plays in determining 

ambient impact levels of NO2 based on modeled NOx emissions, Section 5.2.4 of GAQM

recommends a three-tiered screening approach for NO2 modeling. Later guidance 

documents issued by EPA expand on this approach. Tier 1 assumes full conversion of 

NO to NO2. Tiers 2 and 3 are refinements of the amount of conversion of NO to NO2. 

The applicant used the Tier 2 approach, in which the 1-hour NO2 impacts are based on 

the assumption that 80% of the NO is converted to NO2, while the annual average NO2

concentrations are based on the assumption that 75% of the NO is converted to NO2.

A. NO2 monitor representativeness/conservativeness

The applicant chose the Manzanita Avenue monitor in Chico for background NO2

concentrations. This monitor is approximately 90 km from the SPI- Anderson site and is 

the closest NO2 monitor to the project site. No other NO2 monitor is located within 90

km of the site. Despite its distance from the project site, the monitor from Chico is 

conservative based on its proximity to a more industrial area at the north end of the 

Sacramento Valley.

B. Combining modeled and monitored values

SPI used one of the approaches in an EPA March 2011 memo which recommends using 

the 98th percentile of the annual distribution of daily maximum 1-hour values averaged 

across the most recent three years of monitored data as a uniform background 

contribution to the modeled results. This procedure is based on a conservative 

assumption.

EPA believes that the applicant’s overall approach to the 1-hour NO2 analysis for the 

SPI- Anderson project, including the emission inventory, background concentrations of 

NO2 and the method for combining model results with monitored values, is adequately 

conservative.
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8.4.3.4 Startup and Shutdown Analyses

As stated in Section 8.3.5, the applicant estimated boiler NOx emissions during startup 

and shutdown to be the same as those during normal operations, but with lower flow 

rates, thus the applicant also modeled for startup and shutdown. The stack parameters 

input into the model such as exit temperature and exhaust velocity were consistent with a 

flow rate equal to approximately 60% of that associated with a full load, and a reduced 

exhaust temperature of 250 °F or 394 degrees K (Updated Air Dispersion Modeling 

Analysis, May 2012). The startup period may last up to 24 hours from a “cold” (ambient 

temperature) furnace with the initial fire employing natural gas-fired burners combusting 

pipeline natural gas. SPI- Anderson anticipates only two planned cold startup and 

shutdown events during the year for maintenance. 

8.4.3.5 Results of the Cumulative Impacts Analysis

The results of the PSD cumulative impacts analysis for SPI- Anderson’s normal 

operations for PM2.5 and startup emissions for 1-hour NO2 are shown in Table 8.4-3. The 

analysis demonstrates that emissions from SPI- Anderson will not cause or contribute to 

exceedances of the NAAQS for annual and 1-hour NO2 or 24-hour PM2.5 or for the 

increments for annual NO2 or 24-hour PM2.5. The background concentrations were taken 

from Table 8.2-1. 

EPA also considered additional information to ensure that the modification would not be 

responsible for causing a new NAAQS exceedance outside this modeling area. EPA 

considered sources in Shasta and Tehama Counties (no sources of interest were located 

outside of these counties) that were not included, but which had been evaluated for 

inclusion/exclusion in the cumulative impacts modeling. EPA concluded that these 

sources are either small enough or distant enough that the project’s expected emissions 

along with emissions from these sources would not create any new NAAQS exceedance 

in the modeling area outside of the SIA.

Table 8.4-3: SPI- Anderson Compliance with Class II PSD Increments and NAAQS

Pollutant.

Averaging 

Time

All Sources 

Modeled 

Impact

Background 

Concentration

Cumulative 

Impact w/ 

Background

NAAQS 

(μg/m3)

PSD 

Increment 

Consumption

PSD 

Increment

NO2,

1-hour

94 62.7 157 188

(100 ppb) NA NA

NO2, 

annual 1.75 33.1 34.8 100 (53) 1.75 25

PM2.5,

24-hour

13.5 15.3 28.8 35 3.36 9

Notes: - There are no PSD increments defined for 1-hour NO2.

Sources:

NO2, PM2.5 (NAAQS): Updated Air Dispersion Modeling Analysis (May 2012) Tables 15 and 16pdf22-23: PM2.5 

increment consumption less than all sources modeled impact due to non-increment consuming fugitive source at 

SPI- Anderson being included in NAAQS analysis.
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8.4.3.6 Impact on Ozone Levels

There is a projected 267 tpy increase in NOx emissions. Shasta County is an attainment 

area for O3. There are four O3 monitors located in the Redding area. The highest design 

value from these monitors is 71 ppb. The monitor with the highest value is located on the 

north side of Redding about 25 km from SPI-Anderson. The NAAQS is exceeded if the 

design value is 75 ppb. As explained further below, there is no evidence in any recent O3

regional modeling that an increase in 267 tpy of NOx would result in a 4 ppb O3 increase 

and threaten the NAAQS. 

The emissions of VOC and NOx that react to form O3 come from a variety of local and 

regional anthropogenic and natural source categories. Anthropogenic VOC emissions are 

associated with evaporation and combustion processes, especially industrial processes 

and transportation. Natural VOC emissions from vegetation are much larger than those 

from anthropogenic sources. Anthropogenic NOx emissions are associated with 

combustion processes, especially mobile sources and electric power generation plants.

Major natural sources of NOx include lightning, soils, and wildfires. Given the large 

number of local and regional VOC and NOx sources affecting O3 concentrations in a 

given area, the impact of any single emission source is generally very small. 

Furthermore, given the complex nature of O3 chemistry, the response of the O3 system 

can be rather stiff in certain areas, meaning that it generally takes a substantial change in 

precursor emissions to produce a discernible change in O3 concentrations on a single day.

For example, modeling performed for the San Joaquin Valley 2007 Ozone Plan for the 

Hanford site indicates changes in NOx emissions over the entire air basin on the order of 

20% may increase O3 by approximately 6% to 7%. Another assessment tool used in the 

San Joaquin Valley scaled the San Joaquin Valley 2007 Ozone Plan's Arvin 2023 Ozone 

Response Diagram to estimate the change in ozone per change in NOx emissions. Using 

this information and scaling the 267 tpy of NOx emissions from the proposed 

modification would result in O3 increases well below 1 ppb.

8.5 Class I Area Analysis

8.5.1 Air Quality Related Values

The four nearest Class I areas are all within 100km of the project site and are listed 

below:

Yolla Bolly – Middle Eel Wilderness Area (57 km)

Thousand Lakes Wilderness (62 km)

Lassen National park (64 km)

Caribou Wilderness Area (89 km)

There are five additional areas within 200 km: Marble Mountain Wilderness Area (116

km), Redwood National Park (147km), Lava Beds National Monument (148 km) and 

South Warner Wilderness Area (192km).
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Based on the most recent Federal Land Managers’Air Quality Related Values (AQRV) 

Work Group (FLAG) (2010) published guidance, the following screening approach is 

used to determine whether a more refined Class I Air Quality Analysis is required. This 

approach only applies to projects located more than 50 km from a Class I area, and it 

requires adding all of the visibility-related emissions (SO2, NOx, PM10 and sulfuric acid 

mist) from a project (based on 24-hour maximum allowable emissions expressed in units 

of tpy), known as Q, and dividing Q by the distance D between the project and Yolla 

Bolly, the nearest Class I area. If the result (Q/D) is less than 10, the project is presumed 

to have negligible impacts to Class I AQRVs. Table 8.5-1 shows that the project’s Q/D is 

5.39, well below the FLAG screening criteria. Therefore, no further Class I AQRV 

analysis is required.

Table 8.5-1 Summary of Q/D Analysis

Project parameter Value

NOx Emissions Increase (tpy) 254 (1)

SO2 Emissions Increase (tpy) 9.78 (2)

PM10 Emissions Increase (tpy) 39.1 (3)

H2SO4 Emissions Increase (tpy) 4.12 (4)

Q = project Emissions Increase (tpy)

= (1) + (2) + (3)+ (4) 307

D= Distance to Closest Class I Area (km) 57

Q/D (tpy/km) 5.39

Q/D Threshold (tpy/km) 10

8.5.2 Class I Increment Consumption Analysis

EPA requires an analysis addressing Class I increment impacts for applicable pollutants,

regardless of the results of the Class I AQRV analysis. The analysis for annual NO2 and

PM10 and for PM10 24-hour was included in the original application submitted in 2007.

Based on the results, EPA did not require updated modeling to be submitted with the 

2010 PSD application because of the very low predicted impacts. The applicant provided 

a PM2.5 Class I increment analysis in Updated Air Dispersion Modeling Analysis (May 

2012) for Yolla Bolly, the closest Class I area, because this would provide the most 

conservative results. The applicant used the original CALPUFF results from the Original

PSD Application (May 2007) and the CALPUFF post processing programs. To obtain 

PM2.5 concentrations, coarse PM, sulfate, and nitrate fractions were removed from the 

post-processing originally used to develop PM10 concentrations. The results are presented 

in Table 8.5-2.

SPI’s application was complete on October 4, 2010. There have been no changes in actual 

emissions of PM2.5 from any major stationary source on which construction commenced 

after October 20, 2010, the major source baseline date for PM2.5, for purposes of 

analyzing PM2.5 increment consumption here. Also, no source has triggered the minor 

source baseline date in the area at issue. Therefore, for purposes of this Class I PM2.5

increment analysis, we consider only SPI- Anderson’s increment consumption. Because 
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SPI- Anderson’s impacts are much less than the Class I SILs, and the Class I SILs are 

much lower than the increments, SPI- Anderson’s maximum impacts are well below the 

PM2.5 increments. Therefore, the applicant has demonstrated that the project will not 

cause or contribute to any Class I PSD increment violation for PM2.5. Additionally, NO2

and PM10 impacts are well below their respective significant impact levels; therefore, the 

applicant has demonstrated the project will not cause or contribute to any Class I 

violation for PM10 or NO2.

Table 8.5-2: SPI- Anderson Class I Increment Impacts at Two Closest Class I Areas

Class I Area Pollutant,

Averaging Time

Project Impact 

(μg/m3)

Significant 

Impact Level 

(μg/m3)

Class I PSD

Increment, 

(μg/m3)

Yolla BollyMiddle Eel 

Wilderness

NO2, annual 0.0006 0.1 2.5

PM2.5, 24-hour 0.012 0.07 2

PM2.5, annual 0.0006 0.06 1

PM10, 24-hour 0.06 0.3 8

PM10, annual 0.002 0.2 4

Thousand Lakes 

Wilderness

NO2, annual 0.0009 0.1 2.5

PM10, 24-hour 0.018 0.3 8

PM10, annual 0.001 0.2 4

Source: For NO2 and PM10 impacts: Original PSD Application, Table 5-3 pdf.48. For PM2.5 impacts: 

Updated Air Dispersion Modeling Analysis, p.6pdf.6.

9. Additional Impact Analysis

In addition to assessing the ambient air quality impacts expected from a proposed new 

source, the PSD regulations require that EPA evaluate other potential impacts on 1) soils 

and vegetation; 2) growth; and 3) visibility impairment. 40 CFR § 52.21(o). The depth of 

the analysis generally depends on existing air quality, the quantity of emissions, and the 

sensitivity of local soils, vegetation, and visibility in the source's impact area. 

9.1 Soils and Vegetation 

The additional impact analysis includes consideration of potential impacts to soils and 

vegetation associated with the SPI- Anderson emissions. 40 CFR § 52.21(o). This 

component generally includes: 

a screening analysis to determine if maximum modelled ground-level 

concentrations of project pollutants could have an impact on plants; and

a discussion of soils and vegetation that may be affected by proposed project 

emissions and the potential impacts on such soils and vegetation associated with 

such emissions.

The proposed project will be within the physical footprint of disturbed land that is part of 

the existing facility operations of the SPI- Anderson sawmill parcel located in Shasta 

County, California. The applicant presented its discussion of potential impacts on soils 
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and vegetation as part of its PSD application and supplemental application information 

(from 2007 through 2012 submittals) and its biological review information (from 2007 

and 2010). This information is further discussed below regarding the modification’s 

potential deposition on soils and the project’s modeled impacts compared to EPA’s 

screening concentrations and secondary NAAQS.

The potential impact on soils from air pollutants through deposition is presented in the 

2007 application (Section 5.0) as part of the Class I AQRV analysis. Additionally, the 

applicant reviewed the U.S. Department of Agriculture Natural Resources Conservation 

Service’s Web Soil Survey8; soils in the area had pH ratings of between 5.3 and 6.5. A 

current review of the same area indicates that the same soil types (primarily various types 

of loam with some cobbly alluvial areas) and pH (5.3 to 6.5) are present. Then, as now, 

the modeled deposition fluxes of nitrogen and sulfur attributable to the project are 

unlikely to alter or influence the pH of soils in the area. 

With respect to the April 2010 updated biological review, the applicant included an 

expanded project study area beyond the original 2007 evaluation. Soil characteristics of 

the habitat of the federally listed plant species, the slender Orcutt grass, are described. Its 

general habitat includes vernal pools (and similar habitat), reservoir edges of stream 

floodplains, clay soils with seasonal inundation in valley grassland to coniferous forest or 

sagebrush scrub. Likewise, it is not expected that the project’s emissions will adversely 

affect the habitat of this species.

The applicant’s May 2012 application supplement presents an updated air dispersion 

modeling analysis from its 2010 application update. Project impacts are presented for 

normal project-only (refer to May 2012, Table 3) and startup and shutdown project-only 

(refer to May 2012, Table 6) modeling results.9The project’s SO2, NO2 and CO 

concentrations were compared to EPA screening concentrations in EPA’s "Screening

procedure for the Impacts of Air pollution Sources on plants, Soils and Animals" 

(1980)10. The screening procedure is used as a tool to identify if the project could have an 

impact on plants, soils, and animals. The project’s impacts do not exceed the screening 

concentrations for these pollutants. Table 9.1-1 summarizes this information. 

 

8 Web Soil Survey: http://websoilsurvey.nrcs.usda.gov

9 Tables 4 and 6 of the May 2012 correspondence were not relied upon because these tables refer to the State and 

local permit process, which rely on the State ambient air standards; Tables 3 and 5 are relevant for the federal PSD 

permit process. 

10 “

Screening Procedure for the Impacts of Air Pollution Sources on Plants, Soils, and Animals,” EPA 450/2-81-078, 

December 1980.
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Table 9.1-1: Project Maximum Concentrations and EPA Guidance Levels 

for Screening Concentrations for Ambient Exposures

Criteria pollutant, 

Guidance Averaging 

Time

EPA Screening 

Concentration 

(μg/m3)

Modeled Maximum 

Concentrations

(μg/m3)

Model 

Averaging 

Time

SO2, 1-Hour 917 1.67 1 hour

SO2, 3-Hours

786

(0.30 ppm)

1.55

(0.0006 ppm) 3 hour

SO2, Annual 18 0.07 Annual

NO2, 4-Hours 3,760 40.0 1 hour

NO2, 8-Hours 3,760 40.0 1 hour

NO2, 1-Month 564 40,0 1 hour

NO2, Annual 94

(0.05 ppm)

1.35

(0.0007 ppm) Annual

CO, Weekly 1,800,000 212 8 hour

The project’s impacts were also compared to the secondary NAAQS. For most types of 

soils and vegetation, ambient concentrations of criteria pollutants below the secondary 

NAAQS will not result in harmful effects because the secondary NAAQS are set to 

protect public welfare, including animals, plants, soils, and materials. The modeled 

maximum concentrations of SO2, NO2, PM2.5, and PM10 are also significantly below the 

secondary NAAQS that have been established by EPA:11

Table 9.1-2: Project Maximum Concentrations and 

Secondary NAAQS Standards

Pollutant,

Averaging Time

Secondary

NAAQS

(μg/m3)

Modeled Maximum 

Concentrations

(μg/m3)

SO2, 3-hour

1,300

(0.5 ppm)

1.55 

(0.0006 ppm)

NO2, Annual 100

(0.053 ppm)

1.35 

(0.0007 ppm)

PM10, 24-hour 150 3.36

PM2.5, 24-hour 35 3.11

PM2.5, Annual 15 0.27

In sum, based on our consideration of the information and analysis provided by the 

applicant, and other relevant information, we do not believe that emissions associated 

with the project will generally result in adverse impacts to soils or vegetation. 

 

11 EPA has not promulgated a secondary NAAQS for CO.
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9.2 Visibility Impairment

The additional impact analysis also evaluates the potential for visibility impairment (e.g., 

plume blight) associated with SPI- Anderson. 40 CFR § 52.21(o). Using procedures from 

EPA’s Workbook for Plume Visual Impact Screening and Analysis12, the potential for 

visibility impairment is characterized for:

Class I areas located within 50 km of the proposed SPI- Anderson modification; 

and 

Class II areas identified as potentially sensitive state or federal parks, forests, 

monuments, or recreation areas. 

There are no Federal Class I areas located within 50 km of the project site; the nearest 

Class I area is Yolla Bolly-Middle Eel (57 km away). The next nearest Class I area is 

Thousand Lakes Wilderness Area (62 km away). For nearby Class II areas or recreation 

areas, the applicant evaluated visibility impairment for the following within 50 km of the 

project site:

Sacramento River National Wildlife Refuge (NWR) 38.8 km at its closest point;

Whiskeytown National Recreation Area (NRA) 18.3 km at its closest point.

EPA has not yet established a quantitative visibility impairment threshold for Class II 

areas (similar to what exists for Class I areas). We requested that the applicant conduct a 

Level 1 VISCREEN analysis, and, if necessary, a Level 2 screening analysis for these 

two areas. 

For Whiskeytown NRA and Sacramento River NWR, the impact of the project on 

visibility impairment, also known as plume blight, was assessed. The EPA VISCREEN 

screening model was used to estimate visibility impairment to these two areas from the 

project’s emissions. Effects of plume blight are assessed as changes in plume 

perceptibility (ΔE) and plume contrast (Cp) for sky and terrain backgrounds. A Level 1 

analysis, using default meteorological data and no site-specific conditions, was 

conducted. Because the results of the Level 1 screening analyses indicated that some of 

the screening criteria were exceeded, a Level 2 analysis was conducted for both areas. A 

detailed discussion of the VISCREEN plume blight impact analysis is presented in the 

applicant’s Class II Area Visibility analysis submitted by the applicant to EPA in July 

2012. 

The results of the Level 2 VISCREEN modelling runs are presented below in Tables 9.2-

1, 9.2-2, 9.2-3 and 9.2-4. The VISCREEN results are presented for the two default worst

case theta angles – theta equal to 10 degrees representing the sun being in front of an 

observer, and theta equal to 140 degrees representing the sun being behind the observer. 

A negative plume contrast means the plume has a darker contrast than the background 

sky.

 

12 “Workbook for Plume Visual Impact Screening and Analysis (Revised)”, EPA, EPA–454/R–92–023, 1992.
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Table 9.2-1: Whiskeytown NRA Class II VISCREEN 

Modelling Results of Changes in Plume Perceptibility (ΔE)

Background Distance

(km)

Plume Perceptibility (ΔE)

Theta 10 Theta 140 Criteria

Sky 37.1 0.408 0.24 2.00

Terrain 37.1 0.911 0.187 2.00

Table 9.2-2: Whiskeytown NRA Class II VISCREEN 

Modeling Results of Changes in Plume Contrast (Cp)

Background Distance

(km)

Plume Contrast (Cp)

Theta 10 Theta 140 Criteria

Sky 37.1 0.005 -0.003 0.05

Terrain 37.1 0.007 0.001 0.05

Table 9.2-3: Sacramento River NWR Class II VISCREEN 

Modelling Results of Changes in Plume Perceptibility (ΔE)

Background Distance

(km)

Plume Perceptibility (ΔE)

Theta 10 Theta 140 Criteria

Sky 50.0 0.724 0.47 2.00

Terrain 38.9 1.209 0.104 2.00

Table 9.2-4: Sacramento River NWR Class II VISCREEN 

Modelling Results of Changes in Plume Contrast (Cp)

Background Distance

(km)

Plume Contrast (Cp)

Theta 10 Theta 140 Criteria

Sky 50.0 0.01 -0.006 0.05

Terrain 38.9 0.008 0.001 0.05

The results from the VISCREEN model show that changes in plume perceptibility and 

plume contrast for sky and terrain backgrounds inside these two areas are below the 

criteria thresholds. Therefore, the plume would not be perceptible against a sky or terrain 

background.

Consequently, EPA guidance indicates that these results may be used to determine that 

the project will not contribute to visibility impairment, and no further analysis is required. 

9.3 Growth

The growth component of the additional impact analysis involves a discussion of general 

commercial, residential, industrial, and other growth associated with SPI- Anderson.

40 CFR § 52.21(o). This analysis considers emissions generated by growth that will 

occur in the area due to the modification. In conducting this review, we focus on 

residential, commercial and industrial growth that is likely to occur to support the source 

under review including employment expected during construction and operations and 
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potential growth impacts associated with this employment, this as impacts to local 

population and housing needs

EPA does not expect this project to result in any significant 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 workers would be added, 

however this demand would be mitigated by the use of existing employees.

Once the cogeneration unit is operational, the facility expects to employ approximately 

eight additional workers. The project will utilize existing roads and infrastructure, and no 

additional roads or transportation infrastructures are proposed for construction. We do not 

expect the new cogeneration unit to cause significant growth in the area. 

10. Endangered Species

Pursuant to Section 7 of the Endangered Species Act (ESA), 16 U.S.C. 1536, and its 

implementing regulations at 50 CFR Part 402, EPA is required to ensure that any action 

authorized, funded, or carried out by EPA is not likely to jeopardize the continued 

existence of any endangered or threatened species or result in the destruction or adverse 

modification of such species’ designated critical habitat. EPA has determined that this

PSD permitting action is subject to ESA Section 7 requirements. 

The construction activities resulting from the proposed modification will occur on SPIAnderson’s existing facility footprint. All storm water runoff will be contained on the 

site. Power lines to be constructed between the new transformer and the existing switch 

yard will be strung overhead. It is anticipated that there will be three sets of suspended 

wooden poles to span the distance between the existing switch yard and the transformer 

to be located near the turbine building. 

SPI has confirmed that construction activities will not occur within 100 feet of the 

elderberry shrubs that are in the Pacific Gas and Electric power line Right of Way. The 

nearest construction activity to the existing elderberry plants will be the erection of the 

electrical power poles at the existing electrical sub-station which are 137 feet away from 

the nearest elderberry shrub. The main construction area, where the boiler, turbine 

building, fuel shed, electrical substation cooling tower, and ESP will be built, is 

approximately 1,000 feet from the nearest elderberry shrub.

EPA concludes that the project will have no likely adverse effect on any endangered or 

threatened species or designated critical habitat. Discussions with the United States Fish 

and Wildlife Service support EPA’s conclusion.

11. Environmental Justice Screening Analysis

Executive Order 12898, entitled “Federal Actions To Address Environmental Justice in 
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Minority populations and Low-Income populations,” states in relevant part that “each 

Federal agency shall make achieving environmental justice part of its mission by 

identifying and addressing, as appropriate, disproportionately high and adverse human 

health or environmental effects of its programs, policies, and activities on minority 

populations and low-income populations.” Section 1-101 of Exec. Order 12898, 59 Fed. 

Reg. 7629 (Feb. 16, 1994). 

This AAQIR concludes that the proposed modification will not cause or contribute to air 

quality levels in excess of health standards for the pollutants regulated under EPA’s 

proposed PSD permit for the proposed modification, and that the project will not result in 

disproportionately high and adverse human health or environmental effects with respect 

to these air pollutants on populations residing near the SPI- Anderson site, or on the 

community as a whole.

12. Clean Air Act Title V (Operating Permit)

The SPI Anderson facility already must comply with a Title V Operating Permit, 

SCAQMD Permit #94VP18c. After the proposed cogeneration unit is constructed, 

SCAQMD Permit #94VP18c will need to be revised to appropriately reflect the facility’s 

current operations. The SCAQMD has jurisdiction to issue the Title V Operating Permit 

for SPI- Anderson.

13. Comment Period, Procedures for Public Hearing

Requests, Final Decision, and EPA Contact

The comment period for EPA’s proposed PSD permit for the project begins on

September 12, 2012. Pursuant to 40 CFR 124.12, EPA has discretion to hold a Public 

Hearing if we determine there is a significant amount of public interest in the proposed 

permit. Requests for a Public Hearing must state the nature of the issues proposed to be 

raised in the hearing. If a Public Hearing is to be held, a public notice stating the date, 

time and place of the hearing will be made at least 30 days prior to the hearing.

Reasonable attempts will be made to notify directly any person who has commented on 

this proposal of any pending Public Hearing, provided contact information has been 

given to the EPA contact person listed below.

Any interested person may submit written comments or request a Public Hearing 

regarding EPA’s proposed PSD permit for this modification. All written comments and 

requests on EPA’s proposed action must be received by EPA via e-mail by October 17, 

2012, or postmarked by October 17, 2012. Comments or requests must be sent or 

delivered in writing to Omer Shalev at one of the following addresses:

E-mail: R9airpermits@epa.gov

U.S. Mail: Omer Shalev (AIR-3)

U.S. EPA Region 9
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75 Hawthorne Street

San Francisco, CA 94105-3901

Phone: (415) 972-3538

Comments should address the proposed permit modification and facility, including such 

matters as:

1. The Best Available Control Technology (BACT) determinations;

2. The effects, if any, on Class I areas;

3. The effect of the proposed facility on ambient air quality; and

4. The attainment and maintenance of the NAAQS.

All information submitted by the applicant is available as part of the administrative 

record. The proposed air permit, fact sheet/ambient air quality impact report, permit 

application and other supporting information are available on the EPA Region 9 website 

at http://www.epa.gov/region09/air/permit/r9-permits-issued.html#pubcomment. The 

administrative record may also be viewed in person, Monday through Friday (excluding 

federal holidays) from 9:00 AM to 4:00 PM, at the EPA Region 9 address above. Due to 

building security procedures, please call Omer Shalev at (415) 972-3538 at least 24 hours 

in advance to arrange a visit. Hard copies of the administrative record can be mailed to 

individuals upon request in accordance with Freedom of Information Act requirements as 

described on the EPA Region 9 website at http://www.epa.gov/region9/foia/.

EPA’s proposed PSD permit for the proposed modification and the accompanying fact 

sheet/ambient air quality impact report are also available for review at the Shasta County 

Air Quality Management District at 1855 Placer St., Suite 101 in Redding, CA 96001, 

and the Redding Public Library at 1100 Parkview Ave. in Redding, CA 96001.

All comments that are received will be included in the public docket without change and 

will be available to the public, including any personal information provided, unless the 

comment includes Confidential Business Information (CBI) or other information whose 

disclosure is restricted by statute. Information that you consider CBI or otherwise 

protected should be clearly identified as such and should not be submitted through e-mail. 

If you send e-mail directly to the EPA, your e-mail address will be automatically 

captured and included as part of the public comment. Please note that an e-mail or postal 

address must be provided with your comments if you wish to receive direct notification 

of EPA’s final decision regarding the permit.

EPA will consider all written and oral comments submitted during the public comment 

period before taking final action on the PSD permit modification and will send notice of 

the final decision to each person who submitted comments and contact information 

during the public comment period or requested notice of the final permit decision. EPA 

will respond to all substantive comments in a document accompanying EPA’s final 

permit decision.

EPA’s final permit decision will become effective 30 days after the service of notice of 

the decision unless:
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1. A later effective date is specified in the decision; or

2. The decision is appealed to EPA’s Environmental Appeals Board pursuant to 40 

CFR Part 124.19; or

3. There are no comments requesting a change to the proposed permit decision, in 

which case the final decision shall become effective immediately upon issuance.

If EPA issues a final decision granting the PSD permit for this modification, and there is 

no appeal, construction of the modification may commence, subject to the conditions of 

the PSD permit and other applicable permit and legal requirements.

If you have questions, please contact Omer Shalev at (415) 972-3538 or e-mail at 

R9airpermits@epa.gov. If you would like to be added to our mailing list to receive future 

information about this proposed permit decision or other PSD permit decisions issued by 

EPA Region 9, please contact Omer Shalev at (415) 972-3538 or send an e-mail to 

R9airpermits@epa.gov, or visit EPA Region 9's website at 

http://www.epa.gov/region09/air/permit/psd-public-guidelines.html.

14. Conclusion and Proposed Action

EPA is proposing to modify the PSD permit for SPI-Anderson facility owned and 

operated by SPI. We believe that the proposed project will comply with PSD

requirements including the installation and operation of BACT, and will not cause or 

contribute to a violation of the NAAQS, or of any PSD increment. We have made this 

determination based on the information supplied by the applicant and our review of the 

analyses contained in the permit application. EPA will provide the proposed permit and 

this AAQIR to the public for review, and make a final decision after considering any 

public comments on our proposal.
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Appendix A- Greenhouse Gas Emissions Estimates

Discussion: EPA’s Deferral for CO2 emissions from Bioenergy and Other Biogenic 

Sources under the Prevention of Significant Deterioration and Title V programs (76 FR 

43490 July 20, 2011) applies to this modification. Therefore, the determination of PSD 

applicability for GHG will exclude CO2 emissions from the burning of biomass fuel for 

this proposed modification. The boiler is allowed to burn natural gas during startup and 

shutdown, but the proposed PSD permit limits the annual heat input from natural gas to 

not exceed 10% of total heat input on an annual basis. Assuming 8,760 hours of operation 

per year, the total maximum non-deferred emissions of GHG from this boiler are:

i

Total Boiler CO2e without CO2 from biomass

= 2,741 (from CH4) + 5,310 (from N2O) + 30,201 (from Natural Gas CO2)

= 38,252 CO2e
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Total Emergency Engine CO2e from Natural Gas

= 127 CO2e

Total Project CO2e 

= Boiler CO2e + Emergency Engine CO2e

= 38,252 CO2e +127 CO2e

= 38,379 CO2e

As calculated above, total annual CO2e emissions excluding CO2 are 38,379 tpy of CO2e,

which is below the GHG “subject to regulation” threshold of 75,000 tpy. As a result, the 

modification is not subject to BACT requirements for GHG.ii

 

i The kg/MMBtu emission factors for combustion of wood and wood residual solid biomass fuel, as well as natural 

gas, are from 40 CFR Part 98, Tables C-1 and C-2; 1kg= 2.2046 lb

ii The emergency engine is limited to 100 hours of nonemergency use per year. The table conservatively assumes 

500 hours of use per year.