U.S. ENVIRONMENTAL PROTECTION AGENCY 

REGION IX 

SUPPLEMENTAL STATEMENT OF BASIS AND 

AMBIENT AIR QUALITY IMPACT REPORT FOR 

GREENHOUSE GAS EMISSIONS 

For a Clean Air Act 

Prevention of Significant Deterioration Permit 

Sierra Pacific Industries-Anderson 

PSD Permit Number SAC 12-01 

November 2013 
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Proposed Prevention of Significant Deterioration Permit 

SUPPLEMENTAL STATEMENT OF BASIS AND 

AMBIENT AIR QUALITY IMPACT REPORT 

FOR GREENHOUSE GAS EMISSIONS 

Sierra Pacific Industries – Anderson Division 

(PSD Permit SAC 12-01) 

Table of Contents 

Acronyms & Abbreviations ............................................................................................................ v

Executive Summary ........................................................................................................................ 7

1. Purpose of this Document ......................................................................................................... 8

2. Introduction ............................................................................................................................... 8

3. GHG Emissions from the Proposed Project .............................................................................. 9

3.1 Proposed New Equipment................................................................................................... 9

3.2 Existing Equipment ........................................................................................................... 13

4. Applicability of the Prevention of Significant Deterioration Regulations .............................. 14

5. Best Available Control Technology ........................................................................................ 16

5.1 GHG BACT for a New Biomass Boiler at a Lumber Facility .......................................... 18

5.1.1 Step 1 – Identify Available Control Technologies ................................................... 19

5.1.2 Step 2 – Eliminate Technically Infeasible Control Technologies ............................ 19

5.1.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness ............. 24

5.1.4 Step 4 – Evaluate Most Effective Controls ............................................................... 27

5.1.5 Step 5 – Select BACT ............................................................................................... 29

5.2 GHG BACT Analysis – Emergency Engine ..................................................................... 29

5.2.1 Step 1 – Identify Available Control Technologies ................................................... 29

5.2.2 Step 2 – Eliminate Technically Infeasible Control Technologies ............................ 29

5.2.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness ............. 30

5.2.4 Step 4 – Evaluate Most Effective Controls and Document Results .......................... 30

5.2.5 Step 5 – Select BACT ............................................................................................... 30

6. Ambient Air Quality Impact Analysis .................................................................................... 31

7. Additional Impact Analysis .................................................................................................... 31

7.1 Soils and Vegetation ......................................................................................................... 31

7.2 Visibility Impairment ........................................................................................................ 32

7.3 Growth .............................................................................................................................. 32

8. Endangered Species ................................................................................................................ 32

9. Environmental Justice Screening Analysis ............................................................................. 33

10. Public Comment Period, Procedures for Public Hearing........................................................ 34

10.1 Public Comments ...................................................................................................... 34

10.2 Public Information Meeting and Public Hearing ...................................................... 34

10.3 Availability of Information ....................................................................................... 35

10.4 Final Permit Decision ............................................................................................... 36
iv 

10.5 EPA Contact Information ......................................................................................... 36

11. Conclusion and Proposed Action ............................................................................................ 37
v 

Acronyms & Abbreviations 

AAQIR Ambient Air Quality Impact Report 

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

Agency U.S. Environmental protection Agency 

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.] 

CCS Carbon Capture and Storage (or Sequestration) 

CFR Code of Federal Regulations 

CH4 Methane 

CHP Combined Heat and Power 

CO2 Carbon Dioxide 

CO2e Carbon Dioxide Equivalents 

CO Carbon Monoxide 

CBI Confidential Business Information 

CEMS Continuous Emissions Monitoring System 

CFR Code of Federal Regulations 

EOR Enhanced Oil Recovery 

EPA U.S. Environmental protection Agency 

ESA Endangered Species Act 

Facility Sierra Pacific Industries – Anderson Division 

FLM Federal Land Manager 

FR Federal Register 

FWS U.S. Fish and Wildlife Service 

GEP Good Engineering Practice 

GHG Greenhouse Gases 

hp Horsepower 

HRSG Heat Recovery Steam Generator 

kW kilowatt 

lbs Pounds 

lb CO2e/lb steam Pounds of CO2 Equivalents per Pound of Steam 

lb CO2e/MW-hr Pounds of CO2 Equivalents per Megawatt-hour 

m meter 

MMBtu Million British Thermal Units 

MMBtu/hr Million British Thermal Units per Hour 

MW Megawatts of electrical power 

NAAQS National Ambient Air Quality Standards 

NO Nitrogen oxide or nitric oxide 

NO2 Nitrogen Dioxide 

N2O Nitrous Oxide 

NOx Oxides of Nitrogen (NO + NO2) 

NSCR Non-Selective Catalytic Reduction 
vi 

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 

RATA Relative Accuracy Test Audit

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

SCAQMD Shasta County Air Quality Management District 

SCR Selective Catalytic Reduction 

SNCR Selective Non-Catalytic Reduction 

SPI Sierra Pacific Industries 

tpy Tons per Year 
Sierra Pacific Industries – Anderson Division (SAC 12-01) 

Supplemental Statement of Basis & Ambient Air Quality Impact Report 

November 2013 

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Proposed Prevention of Significant Deterioration (PSD) Permit 

SUPPLEMENTAL STATEMENT OF BASIS AND 

AMBIENT AIR QUALITY IMPACT REPORT 

FOR GREENHOUSE GAS EMISSIONS 

SPI-ANDERSON 

Executive Summary 

Sierra Pacific Industries-Anderson Division (SPI or SPI-Anderson) 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 periods of startup, shutdown and flame stabilization. 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). EPA has previously determined that the proposed major 

Prevention of Significant Deterioration (PSD) permit modification is consistent with the 

requirements of the PSD program for nitrogen oxides (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). We are making a further determination that 

the proposed PSD permit modification is consistent with the requirements of the PSD program 

for greenhouse gas emissions (GHGs) for the following reasons: 

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

greenhouse gases (GHG) emissions, to the greatest extent feasible. There are no National 

Ambient Air Quality Standards (NAAQS) for GHGs. 

 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) due to GHG emissions. 

 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 effect due to GHG emissions on any Federally-listed endangered or threatened 

species or designated critical habitat in the project’s impact area. 
Sierra Pacific Industries – Anderson Division (SAC 12-01) 

Supplemental Statement of Basis & Ambient Air Quality Impact Report 

November 2013 

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1. Purpose of this Document 

This document is a Supplemental Statement of Basis and Ambient Air Quality Impact Report 

(AAQIR) related to greenhouse gas emissions (GHG) for the proposed PSD permit modification 

for the SPI-Anderson facility. This document supplements our Statement of Basis and Ambient 

Air Quality Impact Report dated September 2012, which covers non-GHG emissions -- 

specifically, NOx, CO, PM, PM10 and PM2.5. (See online docket #III.02, SPI-Anderson Ambient 

Air Quality Impact Report_12SEP12.) This Supplemental AAQIR describes the legal and 

factual basis for the best available control technology determination for GHG emissions for the 

proposed PSD permit modification, including requirements under the PSD regulations at Title 40 

of the Code of Federal Regulations (CFR) §52.21. This Supplemental AAQIR also serves as the 

supplemental fact sheet to meet the requirements of 40 CFR Part 124.7 and 124.8. 

2. Introduction 

EPA previously issued a final permit decision regarding this project on February 19, 2013 

(February 2013 Permit). The February 2013 Permit required use of BACT to limit emissions of 

NOx, CO, PM, PM10 and PM2.5, to the greatest extent feasible. EPA also determined that air 

pollution emissions from the new cogeneration unit and ancillary equipment will not cause or 

contribute to violations of any National Ambient Air Quality Standards (NAAQS) or any 

applicable PSD increments for the pollutants regulated under the PSD permit. Ms. Celeste 

Draisner, Mr. Rob Simpson, Ms. Heidi Strand, and Mr. Ed W. Coleman (Petitioners) each 

petitioned the Environmental Appeals Board (EAB or Board) to review the Final Permit. 

On July 18, 2013, the EAB denied review on all but one of the challenges raised by the 

Petitioners, finding that the Region clearly erred in failing to hold a public hearing. In re Sierra 

Pacific Industries, PSD Appeal Nos. 13-01 through 13-04 (EAB July 18, 2013), E.A.D. 15 

_____. The EAB’s decision requires the Region to reopen the permit proceedings and issue a 

final permit decision and a document that responds to any new comments received during the 

public hearing. 

In addition, on July 12, 2013, the United States Court of Appeals for the District of Columbia 

Circuit vacated EPA’s rule1

 deferring regulation of biogenic carbon dioxide (CO2) emissions 

from PSD review. Ctr. for Biological Diversity v. EPA, 722 F.3d 401 ( (D.C. Cir. 2013). EPA 

Region 9 relied on the Deferral Rule in issuing the February 2013 Permit, and so did not make 

BACT determinations or include permit conditions regulating GHG emissions in the February 

2013 Permit. The EAB stated in its July 18, 2013 decision that it was declining to address the 

challenge to the Region’s reliance on the Deferral Rule. The EAB stated that it expects that the 

 

1 Deferral for CO2 Emissions from Bioenergy and Other Biogenic Sources Under the Prevention of 

Significant Deterioration (PSD) and Title V Programs (Deferral Rule), 76 Fed. Reg. 43490, 43493 (July 

20, 2011). 
Sierra Pacific Industries – Anderson Division (SAC 12-01) 

Supplemental Statement of Basis & Ambient Air Quality Impact Report 

November 2013 

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Region will consider this challenge in light of the decisions the Agency makes regarding the 

Court’s ruling on the Deferral Rule. 

EPA has not made any decisions at this time with respect to application of PSD permitting 

requirements after the Court’s opinion on the Deferral Rule. Due to its grant of an earlier 

extension request, the D.C. Circuit has not yet issued the mandate in its decision on the biogenic 

CO2 deferral rule, and the decision remains subject to possible additional legal proceedings. On 

October 22, 2013, the intervenors in Center for Biological Diversity filed a second request to 

extend the deadline for petitions for rehearing. To facilitate EPA action on this permit while 

these matters remain unresolved, SPI submitted to EPA PSD application material for GHG 

emissions from the proposed new equipment. SPI requested that EPA review such materials and 

include appropriate emission limits and related requirements in the proposed permit 

modification. The proposed permit modification that EPA Region 9 is announcing today is 

similar to the proposed permit modification that we announced in September 2012; however, it 

now includes GHG emission limits and related requirements.2 The remainder of this document 

provides the EPA’s analysis of the GHG BACT determination for the proposed project. 

3. GHG Emissions from the Proposed Project 

EPA’s PSD permitting regulations define GHGs as an aggregate of: carbon dioxide (CO2), 

methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and 

sulfur hexafluoride (SF6). 40 CFR § 52.21(b)(49)(i). The proposed project has the potential to 

emit only three of these GHGs: CO2, CH4, and N2O. All GHG emissions associated with the 

project will be generated by the cogeneration unit and emergency engine; the cooling tower will 

not emit any GHGs. 

EPA regulations further define CO2e as the sum of the mass emissions of the constituent GHG, 

each multiplied by the appropriate global warming potential (GWP) factor provided in Table A-1 

of the Federal Mandatory GHG Reporting Rule (see 40 CFR Part 98). 40 CFR § 

52.21(b)(49)(ii). 

3.1 Proposed New Equipment 

Table 3-1 lists the proposed new equipment that will be regulated by the PSD permit, and the 

existing equipment currently located at the SPI-Anderson facility. 

 

2

 We are also using this opportunity to revise certain other conditions (primarily related to monitoring, 

performance testing, and recordkeeping) to address minor technical issues we identified since February 

2013. These revisions do not affect our BACT determinations for non-GHG pollutants and do not require 

revision to the September 2012 AAQIR. 
Sierra Pacific Industries – Anderson Division (SAC 12-01) 

Supplemental Statement of Basis & Ambient Air Quality Impact Report 

November 2013 

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Table 3-1: New and Existing Equipment List 

Type Unit Description 

Proposed New 

Equipment

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. 

Existing 

Equipment

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 NOx, and multiclone 

with ESP to control PM emissions 

 Equipped with one 30,400 ft3

, 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) Each 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) 200hp, 59,000CFM Rader blower 

7 De-greasing 

Tanks 

 Non-solvent based tanks 

Gasoline Storage 

Tank 

 Above ground with 10,000 gallon capacity tank 

Painting Operation  Miscellaneous painting operation 

Drying Kilns  (8) steam-heated, double-track, lumber drying kilns

The proposed biomass boiler of the cogeneration unit is expected to have a maximum annual 

average heat input of 468 million British thermal units per hour (MMBtu/hr), and an annual 

average heat input of 425 MMBtu/hr. The biomass boiler will also be equipped with two 62.5 

MMBtu/hr natural gas burners that will be used during startup, and, potentially, during shutdown 

and for flame stabilization. The biomass boiler will combust a small amount of natural gas 
Sierra Pacific Industries – Anderson Division (SAC 12-01) 

Supplemental Statement of Basis & Ambient Air Quality Impact Report 

November 2013 

11 

throughout the year, but the vast majority of emissions will be from combustion of wood and 

wood-residual solid biomass fuel. 

The proposed emergency engine will be natural-gas-fired, and will operate as a feedwater pump 

used to circulate water through the cogeneration unit boiler in case of an emergency shutdown 

while disconnected from the grid. The emergency engine will have a maximum heat input of 

2.16 MMBtu/hr, and will be operated a maximum of 100 hours per year for maintenance and 

testing purposes, in addition to any emergency use. 

Tables 3-2 and 3-3 summarize the GHG emissions for the biomass boiler and emergency engine, 

and total CO2e emissions from the project, and show that the proposed project has the potential 

to generate a maximum of 432,439 tons of CO2e per year. SPI’s GHG emission estimates for the 

proposed boiler are slightly different because values were rounded up, providing a total potential 

of 433,000 tons of CO2e per year. 

Table 3-2: Greenhouse Gas Emissions for Proposed New Equipment

Emission 

Unit 

GHG 

Pollutants 

Emission Factor3

(Heat Input) Global 

Warming 

Potential4

GHG 

Pollutant 

Emission Rate 

(tpy)5

CO2e 

Emission 

Rate 

(tpy) (kg/MMBtu) (lb/MMBtu) 

Stoker 

Boiler 

CO2 93.8 206.60793 1 423,513 423,513

CH4 0.032 0.07048 21 144 3,034

N2O 0.0042 0.00925 310 19 5,879

Total CO2e -- -- -- -- 432,426

Emergency 

Engine 

CO2 53.02 116.78411 1 13 13 

CH4 0.001 0.00220 21 0.00024 06

N2O 0.0001 0.00022 310 0.00002 07

Total CO2e -- -- -- -- 13 

(Source: Table 2-1 of Biomass-Fired Cogeneration Project: Best Available Control Technology Analysis for 

Greenhouse Gases, Sierra Pacific Industries Lumber Manufacturing Facility Anderson, California, August 15, 2013)

 

3

 The kg/MMBtu emission factors for combustion of wood and wood residual solid biomass fuel, and 

natural gas, are from 40 CFR Part 98, Tables C-1 and C-2; the lb/MMBtu emission factors are calculated 

by converting the kg/MMBtu emission factors using 2.2046 lb/kg. 

4 100-year time horizon global warming potential (GWP – from 40 CFR Part 98, Table A-1). 

5 Calculated by multiplying the emission factor by the maximum annual average heat input (468 

MMBtu/hr for the cogeneration unit and 2.16 MMBtu/hr for the emergency pump engine). Annual 

emission rates are based on 8,760 hr/yr operation for the cogeneration unit, and 100 hr/yr for the 

emergency pump engine. CO2e was calculated by multiplying each individual emission rate by the 

applicable GWP factor, and summing. 

6

 CO2e estimate for CH4 is less than 1 tpy. 

7

 CO2e estimate for N2O is less than 1 tpy. 
Sierra Pacific Industries – Anderson Division (SAC 12-01) 

Supplemental Statement of Basis & Ambient Air Quality Impact Report 

November 2013 

12 

Table 3-3: Total Greenhouse Gas Emissions for New Equipment

GHG Pollutants CO2e Emission Rate 

(tpy) 

CO2 423,526 

CH4 3,034 

N2O 5,879 

Total 432,439 

(Source: Table 2-3 of Biomass-Fired Cogeneration Project: Best Available Control Technology Analysis for 

Greenhouse Gases, Sierra Pacific Industries Lumber Manufacturing Facility Anderson, California, August 15, 2013)

The PSD permit limits the annual heat input from natural gas to not exceed 10 percent of the 

total heat input on an annual basis. Operation of the natural gas burners will not exceed 10 

percent of the annual heat input capacity of the boiler, or 409,934 MMBtu/yr (468 MMBtu/hr * 

8.760 hr/yr * 10%). Based on that maximum annual heat input and the CO2e emission factor for 

natural gas combustion from 40 CFR Part 98 (117 lb/MMBtu), the maximum GHG emissions 

from the natural gas burners will be 23,981 tpy.

The proposed cogeneration unit will be started and shutdown as infrequently as possible. SPI 

anticipates at least one outage period each year for maintenance; any additional shutdown-andstartup cycles will be the result of an unscheduled event. It will take approximately 12 hours to 

start the cogeneration unit; natural gas burners will be used to heat the refractory for the first 

6 hours, and then biomass fuel will be phased in and gas firing phased out over the final 6 hours. 

Shutdown will take approximately 1 hour to accomplish, and the natural gas burners will be used 

only if elevated carbon monoxide (CO) levels are indicated by the continuous emissions 

monitoring system (CEMS). Based on the startup protocol outlined above, a calculated estimate 

of GHG emissions is provided in Tables 3-4 and 3-5. 
Sierra Pacific Industries – Anderson Division (SAC 12-01) 

Supplemental Statement of Basis & Ambient Air Quality Impact Report 

November 2013 

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Table 3-4: Greenhouse Gas Emissions for Startup Periods 

Fuel GHG 

Pollutants 

Emission 

Factor8

(lb/MMBtu) 

Hourly Emission 

Rate9

(lb/hr) 

Event Emission 

Rate10 

(lb/event) 

Firing Biomass 

Fuel 

CO2 207 96,770 580,622 

CH4 0.282 132 792 

N2O 0.03702 17 104 

Total CO2e -- 104,916 629,498 

Firing Natural Gas 

CO2 117 14,611 87,666 

CH4 0.0022 0.276 1.65 

N2O 0.00022 0.0276 0.165 

Total CO2e 14,625 87,752 

(Source: Table 2-2 of Biomass-Fired Cogeneration Project: Best Available Control Technology Analysis for 

Greenhouse Gases, Sierra Pacific Industries Lumber Manufacturing Facility Anderson, California, August 15, 2013)

Table 3-5: Total Greenhouse Gas Emissions for Startup Periods

GHG Pollutants 

Average Hourly 

Emission Rate

(lb/hr)

Event Emission 

Rate

(lb/event)

Event Emission 

Rate 

(ton/event) 

CO2 55,691 668,288 334 

CH4 66 794 0.397 

N2O 9 104 0.0521 

Total CO2e 59,771 717,250 359 

(Source: Table 2-2 of Biomass-Fired Cogeneration Project: Best Available Control Technology Analysis for 

Greenhouse Gases, Sierra Pacific Industries Lumber Manufacturing Facility Anderson, California, August 15, 2013)

3.2 Existing Equipment

Existing equipment at the facility includes a biomass-fired boiler with a maximum annual 

average heat input capacity of 116.5 MMBtu/hr, and a circuit breaker and two switches that 

utilize sulfur hexafluoride (SF6) as a dielectric medium. The existing boiler will be 

decommissioned and dismantled after the new cogeneration unit is constructed and operating. 

The existing circuit breaker will be used by the new equipment and will not be modified. There 

are also eight steam-heated, double-track, kilns used for drying lumber at the facility. No 

combustion occurs in the kilns; thus, no GHGs are emitted from the kilns. Tables 3-6 and 3-7 

summarize the GHG emission rate calculations for the existing equipment at the facility. 

 

8

 The CH4 and N2O emission rates were increased by a factor of 4 to reflect incomplete combustion 

during startup; a similar approach was taken when calculating CO and VOC emission rates during startup. 

9 Hourly emission rates are based on 468 MMBtu/hr when firing biomass, and 125 MMBtu/hr when 

firing natural gas.

10 Event emission rate is the hourly emission rate multiplied by 6 hours.
Sierra Pacific Industries – Anderson Division (SAC 12-01) 

Supplemental Statement of Basis & Ambient Air Quality Impact Report 

November 2013 

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Table 3-6: Greenhouse Gas Emissions for Existing Equipment

Emission 

Unit 

GHG 

Pollutants 

Emission Factor11

(Heat Input) Global 

Warming 

Potential 

GHG 

Pollutant 

Emission 

Rate 

(tpy) 

CO2e 

Emission 

Rate12

(tpy) (kg/MMBtu) (lb/MMBtu) 

Boiler 

CO2 93.8 206.60793 1 105,335 105,335 

CH4 0.032 0.07048 21 35.9 755 

N2O 0.0042 0.00925 310 4.7 1,462 

Total CO2e -- -- -- -- 107,552 

Circuit 

Breaker 

SF6 1% leakage/year 23,900 0.000950 5

Total CO2e -- -- -- -- 5 

(Source: Table 2-3 of Biomass-Fired Cogeneration Project: Best Available Control Technology Analysis for 

Greenhouse Gases, Sierra Pacific Industries Lumber Manufacturing Facility Anderson, California, August 15, 2013)

Table 3-7: Total Greenhouse Gas Emissions for Existing Equipment

GHG Pollutants CO2e Emission Rate 

(tpy) 

CO2 105,335

CH4 755

N2O 1,462

SF6 5

Total CO2e 107,557

(Source: Table 2-3 of Biomass-Fired Cogeneration Project: Best Available Control Technology Analysis for 

Greenhouse Gases, Sierra Pacific Industries Lumber Manufacturing Facility Anderson, California, August 15, 2013)

4. Applicability of the Prevention of Significant 

Deterioration Regulations

This section describes the pollutants covered by the PSD permitting program. Under the Clean 

Air Act, EPA has set federal National Ambient Air Quality Standards, or NAAQS, for six 

common air pollutants. These commonly found air pollutants are known as “criteria pollutants” 

and are found all over the United States. They are particulate matter (PM2.5 and PM10), ground-

 

11 The kg/MMBtu emission factors for combustion of wood and wood residual solid biomass fuel, and 

natural gas, are from 40 CFR Part 98, Tables C-1 and C-2; the lb/MMBtu emission factors are calculated 

by converting the kg/MMBtu emission factors using 2.2046 lb/kg. 

12 The emission rate for the existing biomass-fired boiler was calculated by multiplying the emission 

factor by the maximum heat input (116.4 MMBtu/hr); annual emission rates are based on 8,760 hr/yr 

operation. The annual SF6 emission rate for the switchgear was calculated by multiplying the SF6 capacity 

of the existing breaker and two switches (190 lb) by the annual leak rate of (1%, which was the industry 

standard at the time the equipment was installed); the hourly emission rate was based on the assumption 

that the leak rate is uniform throughput the year. CO2e was calculated by multiplying each individual 

emission rate by the applicable GWP factor, and summing. 
Sierra Pacific Industries – Anderson Division (SAC 12-01) 

Supplemental Statement of Basis & Ambient Air Quality Impact Report 

November 2013 

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level ozone, carbon monoxide, sulfur oxides, nitrogen oxides, and lead. EPA has established 

maximum concentrations, called NAAQS, for each criteria pollutant above which adverse effects 

on human health may occur. Areas that meet the NAAQS are classified as being in “attainment” 

of the standards. Areas that do not meet the NAAQS are classified as being “nonattainment.” A 

single area can be attainment for some criteria pollutants and nonattainment for others. 

The PSD permitting program applies to any new major stationary source and any major 

modification of an existing major stationary source located in an area that is designated as in 

attainment or unclassifiable with a NAAQS. The PSD regulations at 40 CFR § 52.21 define a 

“major stationary source” as any source type belonging to a list of 28 source categories which 

emits or has the potential to emit 100 tons per year (tpy) or more of any regulated New Source 

Review (NSR) pollutant, or any other source type which emits or has the potential to emit such 

pollutants in amounts equal to or greater than 250 tpy. 

The PSD regulations defines a “major modification” as a physical change in or change in the 

method of operation of a major stationary source that would result in: a significant emissions 

increase of a regulated NSR pollutant, and a significant net emissions increase of that pollutant 

from the major stationary source. In general, a regulated NSR pollutant includes any pollutant 

for which a NAAQS has been promulgated, and also includes GHG emissions, sulfuric acid mist, 

hydrogen sulfide, total reduced sulfur, reduced sulfur compounds, municipal waste combustor 

organics, municipal waste combustor metals, municipal waste combustor acid gases, and 

municipal solid waste landfill emissions. EPA previously addressed all of these pollutants, 

except for GHG emissions, as part of our February 2013 permit action. (See online docket 

#III.02, SPI-Anderson Ambient Air Quality Impact Report_12SEP12 at pp. 8-9.) Therefore, this 

Supplemental AAQIR addresses GHG emissions from the project. 

On January 2, 2011, GHGs became a pollutant that is “subject to regulation” under the PSD 

permitting program of the CAA. For PSD purposes, GHG is a single air pollutant defined as the 

aggregate of six gases: carbon dioxide (CO2), nitrous oxide (N2O), methane (CH4), 

hydrofluorocarbons (HFC), perfluorocarbons (PFC), and sulfur hexafluoride (SF6). EPA’s 

Tailoring Rule (75 Federal Register 31514, June 3, 2010) established initial GHG applicability 

thresholds for new sources or modifications, which phase in over time. The Tailoring Rule does 

not change the basic PSD applicability process for evaluating whether there is a new major 

source or modification. However, the process for determining whether a source is emitting 

GHGs in an amount that would make the GHGs a regulated NSR pollutant, includes a 

calculation of, and applicability threshold for, the source based on CO2 equivalent (CO2e) 

emissions as well as its GHG mass emissions. A source’s CO2e emissions are computed by 

multiplying the mass amount of emissions in tons per year (tpy) for each of the six GHGs by the 

gas’s associated global warming potential published at Table A-1 of 40 CFR part 98, subpart A. 

Given that SPI-Anderson is an existing major stationary source under the PSD permitting 

program, and the proposed project is a major modification for non-GHG pollutants, the “subject 

to regulation” threshold for GHGs is 75,000 tpy CO2e. See 40 CFR § 52.21(b)(49)(iv)(b). The 

data in Table 4-1 show that, when CO2 emissions from the combustion of biomass are included, 

the proposed project will be subject to PSD review for GHGs. 
Sierra Pacific Industries – Anderson Division (SAC 12-01) 

Supplemental Statement of Basis & Ambient Air Quality Impact Report 

November 2013 

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Table 4-1: Estimated Emissions and PSD Applicability 

Estimated Annual 

GHG Emissions 

from Project 

(tpy of CO2e) 

Significant Threshold

for GHGs 

(tpy mass) 

“Subject to Regulation” 

Threshold for 

Modification at an 

Existing Source 

(tpy of CO2e) 

Does PSD 

Apply? 

432,439 0 75,000 Yes 

In general, the PSD permitting program requires, among other things, the installation of BACT, 

air quality modeling and ambient monitoring, and public involvement. However, since there are 

no NAAQS or PSD increments for GHGs, the requirements to demonstrate that a source does not 

cause or contribute to a violation of the NAAQS is not applicable to GHGs. Thus, we do not 

recommend that PSD applicants be required to model or conduct ambient monitoring for CO2 or 

GHGs. Ambient air quality monitoring for GHGs is not required because EPA regulations 

provide an exemption in sections 40 CFR 52.21(i)(5)(iii) and 51.166(i)(5)(iii) for pollutants that 

are not listed in the appropriate section of the regulations, and GHGs are not currently included 

in that list. Furthermore, EPA believes it is not necessary to assess impacts from GHGs in the 

context of the additional impacts analysis or Class I area provisions of the PSD regulations. (See

online docket #I.64, PSD and Title V Permitting Guidance for Greenhouse Gases (March 2011) 

at pp. 47-48). 

EPA is currently the PSD permitting authority, and, thus, is responsible for issuing PSD permits 

for air pollution sources located within the jurisdiction of the Shasta County Air Quality 

Management District. 

5. Best Available Control Technology 

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

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.” 

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 
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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 first outlined the process it still uses today to do this case-by-case analysis (referred to as 

“top-down” BACT analysis) in a June 13, 1989 memorandum. Further elaboration on EPA’s 

recommended approach was reflect in the 1990 NSR Workshop Manual. The top-down BACT 

analysis is a well established procedure that the EPA has followed in its permitting decisions and 

that the EAB has consistently considered 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 involves ranking available control technologies 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 GHG emissions for the new proposed emission units. Table 5-1 lists the 

BACT determinations for GHG emissions from the proposed boiler and emergency engine. The 

cooling tower is not expected to produce GHG emissions. 
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Table 5-1: Summary of GHG BACT Requirements

Unit Emission Limits Operational 

Restrictions 

Testing, Monitoring, 

Reporting, and 

Recordkeeping 

Requirements 

Stoker Boiler

(468 MMBtu/hr)

 0.36 lb CO2e per lb 

steam 

 12-month rolling 

average basis 

 Combust biomass fuel 

 Combust natural gas during 

startup and shutdown 

periods, and for flame 

stabilization only 

 Boiler design, good 

combustion practices, and 

efficient operation 

 CO2 CEMS 

 Continuously monitor steam 

production rate 

 Annual CO2 performance 

testing 

 Record efficiency of boiler 

on a daily basis 

Emergency 

Engine 

(256 hp) 

-- NSPS Subpart JJJJ compliant 

engine

NSPS Subpart JJJJ compliant 

engine

5.1 GHG BACT for a New Biomass Boiler at a Lumber Facility 

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

the sawmill operation and to sell electricity to the grid. The new boiler will have a maximum 

heat input capacity of 468 MMBtu/hr, and an annual average heat input of 425 MMBtu/hr. The 

boiler is subject to BACT for GHG emissions. A top-down BACT analysis for this pollutant has 

been performed and is summarized below. 
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5.1.1 Step 1 – Identify Available Control Technologies 

SPI-Anderson identified the control alternatives in Table 5-2 for the proposed biomass boiler. 

Table 5-2: GHG Control Alternatives 

GHG 

Pollutant Add-on Control Options Inherently Lower-Emitting Control Options Other Control Options 

CO2

 Carbon capture and 

sequestration 

 Good boiler design, good 

combustion practices, and 

efficient operation 

 Utilization of biomass fuel 

alone 

 Boiler design alternatives 

(i.e, stoker- including 

vibrating, traveling grate, 

etc.; fluidized bedincluding pressurized or 

atmospheric, such as 

bubbling bed, circulating, 

etc.) 

CH4

 Activated carbon 

adsorption systems 

 Thermal destruction 

 Catalytic destruction 

 Proper combustion 

practices and use of a 

properly designed boiler 

-- 

N2O 

 Non-selective 

catalytic reduction 

(NSCR) 

 Thermal destruction 

 Catalytic destruction 

 Proper combustion 

practices and use of a 

properly designed boiler 

 Removal of SCR and 

SNCR control systems to 

reduce N2O emissions 

 Addition of N2O-Abating 

SCR System 

5.1.2 Step 2 – Eliminate Technically Infeasible Control Technologies 

CO2 Control Options 

Boiler Design Alternatives

EPA evaluated boiler design alternatives in the AAQIR for the proposed permit issued for public 

comment in September 2012. EPA determined that a fluidized bed boiler is not technically 

feasible. (See online docket #III.02, SPI-Anderson Ambient Air Quality Impact Report_12SEP12

at pp. 12-13). Since that time, EPA became aware of New Source Review PSD air permits 

issued for two similar biomass-fired cogeneration projects that propose to use a fluidized bed 

boiler. These projects are North Springfield Sustainable Energy Project in Vermont and WE 

Energies in Wisconsin. SPI provided EPA addition information in a September 13, 2013 

submittal that distinguished its Anderson facility’s operations from those of North Springfield 

Sustainable Energy Project and WE Energies. (See online docket #I.54, SPI-Anderson Info 

Response to EPA 13SEP2013). 
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North Springfield Sustainable Energy Project would recover low grade heat to produce hot water 

for a thermal loop in the North Springfield Industrial Park. The North Springfield Industrial Park 

typically has existing means for generating hot water, and the proposed thermal loop would 

augment the existing system. Thus, the consequences associated with the “low grade heat” from 

the North Springfield Energy Project being unavailable to the North Springfield Industrial Park 

hot water system would be limited to a return to the current hot water system status. SPI will not 

have a similar operational setup. The North Springfield Energy Project does not operate lumber 

dry kilns, or provide process steam of any real consequence, and is not subject to operational 

considerations regarding influences on steam load demand external to power production as with 

the SPI-Anderson facility. 

The WE Energies project would include an 800 MMBtu/hr biomass-fired circulating fluidized 

bed boiler and a 350 MMBtu/hr natural gas-fired package boiler. Steam from the biomass-fired 

boiler will be used to generate electricity, and to provide process steam to the Domtar Mill. 

During periods when the biomass-fired boiler is not available, the natural gas-fired package 

boiler will be used to provide process steam to the Domtar Mill, allowing the Mill to continue 

operation. Again, SPI will not have a similar operational setup. SPI has not proposed installing 

and operating a similar additional fossil-fuel based boiler. In addition, SPI will shut down and 

decommission the existing 116.4 MMBtu/hr biomass boiler after the new cogeneration unit is 

operational; thus, the existing biomass-fired boiler at the SPI-Anderson facility will no longer 

operate and is expected to be decommissioned after the new cogeneration unit is operational. 

SPI also provided additional information from fluidized bed boiler manufacturers which indicate 

a fluidized bed boiler design would not be appropriate for the proposed cogeneration project at 

the SPI-Anderson facility. According to this information, operation of the fluidized bed boiler 

would be unstable at 60 to 70 percent turndown.13 The instability would lead to insufficient 

mixing in the bed and hot spots. This would further lead to associated problems such as higher 

quantities of ash in the bed which form deposits around heat transfer media in the bed. These 

ash and ash-coated particles contain sodium and potassium compounds which react to lower the 

eutectic point of the particles thereby causing them to agglomerate or sinter to become larger 

particles or “rocks.” These particles can stick to the boiler refractory and may damage the 

refractory wall. This process can lead to bed de-fluidization, and the boiler would have to be 

shut down to remove these materials. 

SPI has determined that it would be impractical to employ a fluidized bed boiler that lacked a 20 

to 50 percent turndown capability. When operational, the proposed cogeneration unit will be the 

only source of steam at the SPI-Anderson facility. It will provide steam to the turbine to 

generate electricity, and to the kilns to produce dried lumber. If the biomass cogeneration unit is 

incapable of operating at low loads (i.e., 20 to 50 percent of full load), the kilns would have to 

cease operation any time the power production demand by Pacific Gas and Electric (PG&E) 

decreased significantly, or the turbine was not operating. 

 

13 Turndown mode is, generally, when the boiler is operating at less than its nominal rated capacity (i.e., less than 

100 percent load). 
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For the reasons stated above, EPA agrees that a fluidized bed boiler is not technically feasible for 

the SPI-Anderson facility. 

Utilization of Biomass Fuel Alone

This control option consists of combustion of biomass fuels, alone or in combination with other 

fuels, in boilers to generate steam at the SPI-Anderson facility. Since biomass is the primary fuel 

that will be used at the facility, this control option is technically feasible. 

Good Boiler Design, Good Combustion Practices, and Efficient Operation

This control option consists of: (1) altering the combustion process to reduce CO2 emissions; and 

(2) maximizing the heat transfer efficiency of the boiler and the mechanical efficiency of the 

steam turbine and generator, which minimizes the quantity of fuel combusted and, therefore, the 

quantity of CO2 generated per unit of steam or electricity generated. According to SPI, at 

maximum operation, the efficiency of the proposed boiler (i.e., the fraction of the energy in the 

fuel that is transferred to the steam) is expected to be approximately 70 percent. The efficiency 

of the electrical generator is, at full load, approximately 96 percent. The overall efficiency of the 

cogeneration unit will vary depending upon the quantities of steam used to heat the kilns and 

generate electricity, but is expected to vary between 37 and 53 percent. This control option is 

technically feasible. 

Carbon Capture and Sequestration (CCS)

This control option consists of removing CO2 from the post-combustion exhaust stream. 

Following capture, the CO2 would be transported and stored permanently, or “sequestered,” in a 

geologic formation. Potential CO2 sequestration sites include geological formations (including 

oil and gas fields for enhanced recovery) and ocean storage. SPI-Anderson identified three 

approaches to CO2 capture that are generally applicable to power generation: (1) pre-combustion 

systems designed to separate CO2 and hydrogen (H2) from produced syngas, (2) post-combustion 

systems designed to separate CO2 from flue gas, and (3) oxy-combustion that uses high-purity 

oxygen (O2) instead of air, which produces flue gas composed largely of CO2. Use of a precombustion system would require a gasification unit to produce syngas from the biomass fuel, 

which would amount to redefining the source. Oxy-combustion of biomass fuels is typically in 

the context of being co-fired with coal, a fossil fuel which will not be used at the facility. 

Therefore, SPI determined that post-combustion CCS is the only technical feasible control option 

that will be considered for application on the proposed biomass-fired boiler. 

CH4 Control Options 

Proper Combustion Practices and Use of a Properly Designed Boiler

CH4 emissions are generally the result of incomplete fuel combustion. In the case of biomass, 

volatile compounds (including CH4) are released as the fuel is heated in the furnace, some 

portion of which escapes combustion by improper mixing with oxygen or being confined to 

zones of relatively low temperature. Proper combustion practices and use of a properly designed 

boiler maximizes complete combustion, which minimizes formation of CH4. This control option 

is technically feasible. 
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Activated Carbon Adsorption Systems

Adsorption systems pass the gas stream though canisters filled with activated carbon, and the 

CH4 is trapped in pores located on the carbon particles. When the carbon approaches saturation, 

the canister is replaced and processed to remove the CH4, which is recovered or destroyed. 

Adsorption systems are usually limited to sources generating organic compounds having a 

molecular weight of more than 50 and less than approximately 200. Low molecular weight 

organics, such as CH4 which has a molecular weight of 16, usually do not adsorb sufficiently. 

(See online docket #I.65, EPA Activated Carbon Adsorber Website 27SEPT2013). In addition, 

the CH4 concentration in the cogeneration unit exhaust stream will be very small (i.e., less than 1 

percent by volume). For these reasons, using adsorption technology to reduce CH4 emissions 

from a biomass-fired boiler in not considered technically feasible. 

Thermal Destruction Systems

Oxidation systems increase the temperature of the gas stream until the CH4 oxidizes, forming 

CO2 and water. Thermal oxidizers destroy CH4 using a flame. To thermally oxidize a pollutant 

in an exhaust stream, a combustor is located in the exhaust duct, and fuel (typically natural gas) 

and enough supplemental air to support a flame are introduced. While the thermal oxidizer may 

destroy a portion of the small amount of CH4 present in the exhaust (i.e., less than 1 percent by 

volume), the oxidizer itself is likely to generate additional air pollutants (e.g., NOx, CO, VOCs, 

and CH4) such that there is a net increase in emissions. In addition, a thermal oxidizer has never 

been used to reduce CH4 emissions from a biomass-fired boiler. SPI has determined that control 

of CH4 using thermal oxidation is considered speculative and not achieved in practice for a 

biomass-fired boiler, and, therefore, not technically feasible for reducing CH4 emissions from a 

biomass-fired boiler. 

Catalytic Destruction Systems

Oxidation systems increase the temperature of the gas stream until the CH4 oxidizes, forming 

CO2 and water. Thermal oxidizers destroy volatile compounds using a flame, while catalytic 

oxidation uses a catalyst to promote the oxidation reaction at a temperature lower than the 

combustion temperature of volatile compounds such as CH4. Regardless of whether the catalyst 

is located upstream or downstream of a particulate control device (e.g., an electrostatic 

precipitator), alkali compounds in the exhaust gas deactivate the catalyst. To counteract the 

deactivation, large quantities of catalyst must be deployed and frequently replaced, resulting in 

unpredictable boiler availability and control system costs. However, SPI-Anderson determined 

that a catalytic oxidation system to reduce CH4 emissions from the proposed biomass-fired boiler 

is technically feasible. 

N2O Control Options 

Proper Combustion Practices and Use of a Properly Designed Boiler

Typically, furnace conditions that favor CH4 formation, also favor N2O formation. N2O is the 

result of lower combustion temperatures (less than 800°C or 1,475°F). Its formation can be 

limited to some extent by using proper combustion techniques and a properly designed boiler 

that promotes uniform furnace temperatures. This control option is technically feasible. 
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Non-Selective Catalytic Reduction 

NSCR systems are typically used to reduce emissions from reciprocating engines operated in a 

rich-burn or stoichiometric mode. In general, NSCR systems pass the exhaust gases over 

catalysts, which use metals (e.g., platinum, rhodium, palladium) to convert NOx, carbon 

monoxide (CO), and volatile organic compounds (VOCs) to water, nitrogen, and CO2. NSCR 

systems have primarily been developed to reduce N2O emissions from adipic and nitric acid 

production operations. There are no instances of an NSCR system being applied to reduce N2O 

emissions from a biomass-fired boiler. Because significant differences exist between the exhaust 

from adipic and nitric acid operations and that of a biomass-fired boiler (i.e., typical N2O 

concentration in exhaust from a nitric acid plant is typically over 1,000 ppm, while the 

concentration in biomass-fired boiler exhaust is approximately 10 ppm), it is not clear that the 

technology could be transferred effectively, and is therefore considered technically infeasible for 

control of N2O from proposed biomass-fired boiler. 

Thermal Destruction Systems 

Thermal destruction of N2O is achieved using a reducing flame burner combusting premixed 

methane or natural gas. The flame temperature must be maintained high enough to destroy the 

N2O, but below 1,500°C to minimize NOx formation. To thermally oxidize a pollutant in an 

exhaust stream, a combustor is located in the exhaust duct, and fuel (typically natural gas) and 

enough supplemental air to support a flame are introduced. A thermal oxidizer may destroy a 

small amount of N2O present in the exhaust (i.e., less than 1 percent by volume); however, the 

oxidizer itself is likely to generate additional air pollutants (e.g., NOx, CO, VOCs, and CH4) such 

that there is a net increase in emissions. In addition, a thermal oxidizer has never been used to 

reduce CH4 emissions from a biomass-fired boiler. SPI determined that a thermal oxidizer is not 

achieved in practice for a biomass-fired boiler, and, therefore, not technically feasible for 

reducing N2O emissions from a biomass-fired boiler. 

Catalytic Destruction Systems

Catalytic destruction is accomplished at lower temperatures (400°C to 700°C) using metal- or 

zeolite-based N2O-decomposing catalysts. As previously mentioned above, this control is 

considered technically feasible. 

Removal of SCR and SNCR Control Systems to Reduce N2O Emissions

Conventional commercially-available selective catalytic reduction (SCR) systems (i.e., those 

using titanium, tungsten, and vanadium-based catalysts) used to reduce emissions of nitric oxide 

(NO) and nitrogen dioxide (NO2), as well as selective non-catalytic reduction (SNCR) systems, 

generate N2O, so removal of such control systems would reduce N2O emissions. Since no SCR 

system is proposed for installation on the proposed biomass-fired boiler, it is technically 

infeasible to not install such a system. An SNCR system is proposed by SPI to reduce NOx

emissions from the biomass-fired boiler. It is technically feasible to not install such a system. 

Addition of N2O-Abating SCR System 

The criteria pollutant BACT analysis provided with the PSD permit application concluded that 

conventional SCR systems were technically feasible for reducing NOX emissions from biomassfired boiler; therefore, N2O-abating SCR systems are also considered technically feasible. 
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5.1.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness 

After elimination of technically infeasible control options, the remaining control methods are 

provided as follows. 

Post-Combustion CCS

Currently available technology can theoretically capture approximately 90 percent of the postcombustion CO2 in flue gas. It is not expected to impact CH4 or N2O in the exhaust. Table 5-3 

shows estimates for the potential GHG emission reductions resulting from the use of post 

combustion CCS technology of 88.1 percent on a CO2e basis. SPI estimated a potential GHG 

emission reduction level of approximately 83 percent which considers GHG emission increases 

as a result of the additional capacity needed to power the CCS systems, and which would 

degrade the net GHG reduction. However, SPI did not provide specific information on GHG 

emissions for this additional capacity. Therefore, our analysis includes the estimate of 88.1 

percent. 

Table 5-3: Post Combustion CCS 

GHG

Emission Rate

(tpy) GWP

Uncontrolled CO2e

(tpy) % Control

Controlled CO2e

(tpy)

CO2 423,513 1 423,513 90 381,162

CH4 144 21 3,034 0 0

N2O 19 310 5,879 0 0 

Total -- -- 432,426 -- 381,162 

Percent GHG Reduction: 88.1% 

Catalytic Destruction/Oxidation of CH4 and N2O

Table 5-4 shows SPI’s estimates for the potential GHG emission reductions resulting from the 

use of oxidation catalyst technology. This technology would result in a reduction of 1.6 percent 

on a CO2e basis. 

Table 5-4: Catalytic Destruction/Oxidation 

GHG 

Emission Rate 

(tpy) GWP 

Uncontrolled CO2e 

(tpy) % Control 

Controlled CO2e 

(tpy) 

CO2 423,513 1 423,513 0 0 

CH4 144 21 3,034 40 1,214 

N2O 19 310 5,879 95 5,585 

Total -- -- 432,426 -- 6,798 

Percent GHG Reduction: 1.6% 

Removal of NOx Control System (SNCR)

SPI estimated that SNCR systems convert, depending upon the reagent and furnace conditions, 

between 10 and 20 percent of NOx in the exhaust to N2O. SPI estimated that the proposed 

biomass boiler would have a PTE of 267 tpy for NOx. Assuming up to 20 percent of the NOx in 
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the exhaust is converted to N2O results in a conservative estimate of 53.4 tpy of N2O emissions. 

SNCR systems do not generate any CO2 or CH4, so elimination of the system would not affect 

concentrations of these compounds in the exhaust gas. Table 5-5 shows the estimated potential 

GHG emission reduction resulting from removal of the SNCR control system. The reduction in 

GHG emissions would be 3.7 percent on a CO2e basis. EPA notes that this is a very conservative 

estimate. 

Table 5-5: Removal of SNCR System 

GHG 

Emission Rate 

(tpy) GWP 

Uncontrolled CO2e 

(tpy) % Control 

Controlled CO2e 

(tpy) 

CO2 423,513 1 423,513 0 0 

CH4 144 21 3,034 0 0 

N2O (combustion) 19 310 5,879 0 0 

N2O (SNCR control) 53.4 310 16,554 100 16,554 

Total -- -- 448,980 -- 16,554 

Percent GHG Reduction: 3.7% 

Addition of N2O-Abating SCR System

Addition of a N2O-abating SCR system would capture all N2O emissions generated in the 

combustion process by the boiler. Table 5-6 shows the estimated potential GHG emission 

reductions resulting from the addition of a N2O-abating SCR system. The reduction in GHG 

emissions would be 1.4 percent on a CO2e basis. EPA notes that this is a very conservative 

estimate. 

Table 5-6: Addition of N2O-Abating SCR System 

GHG 

Emission Rate 

(tpy) GWP 

Uncontrolled CO2e 

(tpy) % Control 

Controlled CO2e 

(tpy) 

CO2 423,513 1 423,513 0 0 

CH4 144 21 3,034 0 0 

N2O 19 310 5,879 100 5,879 

Total -- -- 432,426 -- 5,879 

Percent GHG Reduction: 1.4% 
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Good Boiler Design, Good Combustion Practices, and Efficient Operation / Proper Combustion 

Practices and Use of a Properly Designed Boiler / Utilization of Biomass Fuel Alone

SPI proposed to operate the proposed project in a manner that minimizes emissions of all 

pollutants, and maximizes the energy derived from the fuel consumed. In addition, biomass is 

the primary fuel combusted in the boiler during all modes of operation. SPI uses natural gas 

during startup and shutdown periods, and periods in which flame stabilization is needed. SPI 

expects approximately 75 percent of that fuel to be comprised of sawmill residues from the SPIAnderson sawmill and the nearby Shasta Lake sawmill. The remaining 25 percent is expected to 

be a combination of in-forest residues, agricultural residues from orchards in the Sacramento 

Valley, and urban wood residues diverted from landfills. These measures, in combination, are 

considered the baseline from which all other alternatives will be evaluated. All other control 

alternatives would be applied in addition to these measures. 

Table 5-7 provides the ranking of the technically feasible control alternatives, in order of most to 

least effective on a CO2e basis, based on the above control evaluations. 

Table 5-7: GHG Control Methods Ranked by Control Effectiveness 

Control Method Effectiveness 

Post Combustion CCS 88.1 percent reduction on a CO2e basis

Removal of NOx Control System (SNCR) 3.7 percent reduction on a CO2e basis 

Catalytic Destruction 1.6 percent reduction on a CO2e basis 

Addition of N2O-Abating SCR System 1.4 percent reduction on a CO2e basis 

Good Boiler Design, Good Combustion 

Practices, and Efficient Operation / Proper 

Combustion Practices and Use of a Properly 

Designed Boiler / Utilization of Biomass Fuel 

Alone 

Baseline 

Table 5-8 provides recent GHG BACT determinations made at similar facilities according to the 

RACT/BACT/LAER Clearinghouse (RBLC), as well as other permit determinations not 

included in the RBLC. SPI proposed a GHG limit of 0.36 lb CO2e per lb steam produced based 

on a 12-month rolling block average. 
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Table 5-8: Summary of Recent GHG BACT Determinations for Similar Biomass Boilers14 

Facility State 

Permit 

Issuance 

Date 

Size 

(MMBtu/hr) Control Methods CO2e Emission 

Limits 

Averaging 

Period Source 

North 

Springfield 

Sustainable 

Energy Project 

VT 4/19/2013 464

 Energy efficiency 

design/ measures 

 Good operating and 

maintenance practices 

 2,668 lb/MW-hr 

(first 2 years of 

operation) ; 

 2,675 lb/MW-hr 

(starting the 3rd 

year of operation) 

12-month 

rolling avg 

RBLC # 

*VT-0039 

Beaver Wood 

Energy Fair 

Haven LLC 

VT 2/10/2012 482 

 Energy efficiency 

design/ measures 

 Good operating and 

maintenance practices 

 2,993 lb/MW-hr 30-day 

rolling avg 

RBLC # 

VT-0037 

Abengoa 

Bioenergy 

Biomass of 

Kansas LLC 

KS 

9/16/2011 

(Effective 

date) 

22 MW 

 Energy efficiency 

design/ measures 

 Good operating and 

maintenance practices 

 0.34 lb/lb of steam 

produced 

30-day 

rolling avg 

Final PSD 

Permit 

WE Energies 

(Rothschild 

facility) 

WI 

3/28/2011 

(Revised 

4/4/2013 & 

5/21/2013)

800 

 Energy efficiency 

design/ measures 

 Good operating and 

maintenance practices 

 3,120 lb/MW-hr 12-month 

rolling avg 

Final PSD 

Permit 

Montville 

Power LLC CT 

4/6/2010 

(Revised 

5/20/2013) 

600 

 Energy efficiency 

design/ measures 

 Good operating and 

maintenance practices 

 590,103 tpy; 

 15,564 BTU/kWhr 

12-month 

rolling avg 

RBLC # 

CT-0156 

5.1.4 Step 4 – Evaluate Most Effective Controls 

In our evaluation of the most effective controls, we review the economic, environmental, and 

energy impacts for control methods under consideration. The economic impact analysis is used 

to quantify the cost of control. Usually, if the cost of reducing emissions, as expressed in dollars 

per ton of pollutant removed ($/ton), is on the same order as the cost previously borne by other 

sources of the same type in applying the control alternative, then the control alternative is 

considered economically feasible, and therefore acceptable as BACT. 

Post Combustion CCS

CCS systems require additional energy to remove CO2 from the boiler exhaust, as well as to 

compress it for transport and storage. The relatively dilutee concentration of CO2 in the exhaust 

gas of a biomass boiler (i.e., between 10 and 20 percent by weight) would require a strong 

solvent to capture the CO2, as well as a considerable amount of energy to regenerate the solvent. 

The additional energy required to compress the captured CO2 to approximately 2,200 psig would 

increase the energy footprint (including emission of criteria pollutants and GHGs) of the 

proposed boiler by 40 to 60 percent. Captured and compressed CO2 must be transported to a 

storage facility or end use, such as enhanced oil recovery. Storage facilities are not currently 

 

14 The RBLC decisions listed in Table 5-8 are based on BACT decisions posted on EPA’s RBLC website 

as of July 26, 2013. 
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commercially available within the vicinity of the SPI-Anderson site. There are no nearby 

petroleum extraction operations or industrial processes that would be able to accept the volume 

of CO2 SPI would be emitting. SPI estimated that the oil field nearest to the Anderson facility is 

located in Brentwood, California, approximately 25 miles west of Stockton, California. Using 

estimates from a study by the Global CCS Institute, SPI estimated that the cost of installing a 

CCS system would be would cost approximately $29,000,00015, and the cost of constructing a 

pipeline to transport CO2 from the Anderson facility to Brentwood, California would cost 

approximately $109,907,54716. Both of these figures exceed the cost of a new or modified 

facility. SPI estimated that adding a cogeneration unit similar to that proposed by SPI for the 

Anderson facility would cost approximately $75,000,000. Furthermore, SPI estimated that to 

construct a lumber manufacturing facility with a production capacity similar to that of the 

existing Anderson facility would cost approximately $80,000,000. Accordingly, based on these 

costs, CCS is being eliminated as a GHG control option due to its disproportionate costs. 

Removal of NOx Control System (SNCR) 

Elimination of the SNCR system used to reduce NOx emissions from the boiler would potentially 

reduce 53.4 tpy of N2O emissions, which is only 3.7% of the total CO2e that is estimated to be 

emitted from the cogeneration project. Additionally, this alternative would result in increased 

NOx emissions (i.e., 267 tpy NOx projected to be emitted from the boiler). Therefore, EPA is 

eliminating this control option. 

Catalytic Destruction/Oxidation 

SPI estimated that a catalytic destruction/oxidation system would have an annualized cost of 

approximately $2,379,713. However, this cost would potentially reduce only 1.6 percent of the 

total GHG emissions (i.e., CH4 and N2O expressed as CO2e), as shown in Table 5-4. Since CH4

and N2O emissions are expected to be very low, particularly in terms of CO2e, EPA considers the 

construction and operating costs of a catalytic destruction / oxidation system to control these 

pollutants to be excessive. Therefore, EPA is eliminating this control option. 

Addition of N2O-Abating SCR System

SPI estimated that the addition of a N2O-abating SCR system would have an annualized cost of 

approximately $1,276,065. However, this cost would potentially reduce only 1.4 percent of the 

total GHG emissions (i.e., CH4 and N2O expressed as CO2e), as shown in Table 5-4. Since N2O 

emissions are expected to be very low, particularly in terms of CO2e, EPA considers the 

construction and operating costs for the control alternative to be excessive. Therefore, EPA is 

eliminating this control option. 

Good Boiler Design, Good Combustion Practices, and Efficient Operation / Proper Combustion 

Practices and Use of a Properly Designed Boiler / Utilization of Biomass Fuel Alone

These control options are considered the baseline level. SPI anticipates that the proposed 

biomass boiler will be constructed with an energy efficient design that will ensure proper 

 

15 Biomass-Fired Cogeneration Project: Best Available Control Technology Analysis for Greenhouse Gases, Sierra 

Pacific Industries Lumber Manufacturing Facility Anderson, California, August 15, 2013, section 6, p. 28. 16 SPI Anderson email response to EPA dated September 14, 2013. 
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combustion. SPI will operate the boiler according to the manufacturer’s specifications to ensure 

that it is operated efficiently. SPI will operate the boiler in a cogeneration unit, generating 

electricity as well as steam for drying lumber. SPI will use biomass as its primary fuel. These 

control options are expected to have a positive energy and environmental impacts. 

5.1.5 Step 5 – Select BACT 

Based on a review of the available control methods for GHG emissions from biomass-fired 

boilers and other pertinent information used to evaluate the feasibility of these methods, we have 

concluded that BACT for the proposed biomass-fired stoker boiler is (1) 0.36 pounds of CO2e 

per pound of steam (12-month rolling average basis), (2) combustion of biomass at all times 

except during periods of startup, shutdown and flame stabilization (in which natural gas fuel is 

allowed to be combusted), and (3) energy efficient design and use of good combustion and 

operational and maintenance practices as described in SPI’s permit application and subsequent 

submissions to the EPA, which include, but are not limited to, (i) construction and operation of 

an efficient, state-of-the-art, air-cooled, reciprocating stepgrate stoker boiler that ensures good 

combustion; (ii) operation of the boiler as a cogeneration unit at the Facility; and (iii) operation 

and maintenance of the boiler in accordance with the manufacturer’s recommendations. The 

CO2e limit applies at all times, including during startups and shutdowns. 

5.2 GHG BACT Analysis – Emergency Engine 

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

emergency boiler recirculation pump. This emission unit would be used if the cogeneration unit 

had to be shut down when power from the grid was unavailable. Planned operation for this piece 

of emergency equipment will be restricted to testing and maintenance (i.e., a maximum of 100 

hours per year). The limited operation of this unit results in minimal annual emission rates. This 

equipment is subject to BACT for GHGs. A top-down BACT analysis has been performed and 

is summarized below. 

 

5.2.1 Step 1 – Identify Available Control Technologies 

In general, the options for reducing GHGs from the emergency engine fall into three categories: 

inherently low-emitting processes, clean fuels, and add-on control technologies. 

5.2.2 Step 2 – Eliminate Technically Infeasible Control Technologies 

Inherently Low-Emitting Processes

The purpose of the emergency boiler feedwater pump is to provide a quickly deployable source 

of power that will be available when electrical power from the grid is not available to operate the 
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electric motors that power the feedwater pumps that would be relied upon to circulate water 

through the boiler during a normal shutdown process. EPA is not aware of any technologies that 

have been designed to reduce the GHG emissions from natural gas-powered emergency engines 

generators. Energy efficiency of the engine design is the best way to minimize the emissions of 

GHGs from these sources. Since the EPA’s engine emission standards for other criteria 

pollutants are based on the emission rate of the pollutant per unit of energy output, engine 

manufactures have employed a combination of reducing the mass emission rate of the 

pollutant(s) and increasing the overall efficiency of the engines. Therefore, compliance with 

EPA’s engine standards is considered technically feasible for this control option. 

Clean Fuels

SPI has determined that the only real alternative to a natural gas-fired pump is a diesel-fired 

pump, which can produce the same or more GHG emissions. Natural gas is considered the fossil 

fuel that generates the least GHG emissions per unit of energy produced. The only clean fuel to 

consider for the engine is natural gas. This control option is technically feasible only for natural 

gas since already SPI proposes to use this fuel in the engine. 

Add-On Control Technologies

The emergency engine is limited to 100 hours of operation for maintenance, and must be 

available quickly and reliably, an add-on control that complicates operation and potentially 

reduces engine readiness, and compromises the emergency role of the engine. Installing an addon control technology, such as CCS, is not feasible due to the nature of the engine. 

5.2.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness 

The remaining control options are the use of a natural gas-fired engine that meets EPA’s engine 

standards for emergency engines. 

5.2.4 Step 4 – Evaluate Most Effective Controls and Document Results 

The remaining control options are the use of a natural gas-fired engine that meets EPA’s engine 

standards for emergency engines. 

5.2.5 Step 5 – Select BACT 

EPA proposes that BACT for GHGs is the use of a natural gas-fired engine that meets EPA’s 

engine standards in 40 CFR Part 60, Subpart JJJJ for emergency engines. 
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6. Ambient Air Quality Impact Analysis 

CAA Section 165 and EPA’s PSD regulations at 40 CFR 52.21 specify that a facility’s emissions 

of NAAQS pollutants should be evaluated to determine whether they would cause or contribute 

to a violation of (1) the applicable NAAQS, or (2) the applicable Class I and II PSD increments. 

EPA has determined that this permit modification does not require an ambient air quality impact 

analysis for GHG emissions because there is no NAAQS or PSD Increments for GHG pollutants 

and it is therefore not possible to compare the modification’s GHG emissions to a standard or 

increment. 

Furthermore, although it is clear that GHG emissions contribute to global warming and other 

climate changes that result in impacts on the environment, including impacts on Class I areas due 

to the global scope of the problem, climate change modeling and evaluations of risks and impacts 

of GHG emissions is typically conducted for changes in emissions orders of magnitude larger 

than the emissions from individual projects that might be analyzed in PSD permit reviews. 

Quantifying the exact impacts attributable to a specific GHG source obtaining a permit in 

specific places and points would not be possible with current climate change modeling. Given 

these considerations, GHG emissions would serve as the more appropriate and credible proxy for 

assessing the impact of a given facility. Thus, EPA believes that the most practical way to 

address the considerations reflected in the Class I area is to focus on reducing GHG emissions to 

the maximum extent. In light of these analytical challenges, compliance with the BACT analysis 

is the best technique that can be employed at present to satisfy the additional impacts analysis 

and Class I area requirements of the rules related to GHGs. (See online docket #I.64, PSD and 

Title V Permitting Guidance for Greenhouse Gases (March 2011) at p. 48). 

7. Additional Impact Analysis 

The PSD regulations at 40 CFR 52.21(o) require that EPA evaluate other potential impacts on 1) 

soils and vegetation; 2) visibility impairment; and 3) growth. The scope 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. 

7.1 Soils and Vegetation 

The additional impact analysis includes consideration of potential impacts to soils and vegetation 

associated with the SPI’s emissions. Although it is clear that GHG emissions contribute to 

global warming and other climate changes that result in impacts on the environment, including 

impacts on soils and vegetation due to the global scope of the problem, climate change modeling 

and evaluations of risks and impacts of GHG emissions is typically conducted for changes in 

emissions orders of magnitude larger than the emissions from individual projects that might be 

analyzed in PSD permit reviews. Quantifying the exact impacts attributable to a specific GHG 

source obtaining a permit in specific places and points would not be possible with current 
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climate change modeling. Given these considerations, GHG emissions would serve as the more 

appropriate and credible proxy for assessing the impact of a given facility. Thus, EPA believes 

that the most practical way to address the considerations reflected in the additional impacts 

analysis is to focus on reducing GHG emissions to the maximum extent. In light of these 

analytical challenges, compliance with the BACT analysis is the best technique that can be 

employed at present to satisfy the additional impacts analysis requirements of the rules related to 

GHGs. (See online docket #I.64, PSD and Title V Permitting Guidance for Greenhouse Gases 

(March 2011) at p. 48). 

7.2 Visibility Impairment 

The additional impact analysis also evaluates the potential for visibility impairment (e.g., plume 

blight) associated with SPI-Anderson. In EPA’s Statement of Basis and Ambient Air Quality 

Impact Report issued for public comment on September 13, 2012, we concluded that we do not 

expect the proposed project will contribute to visibility impairment. (See online docket #III.02, 

SPI-Anderson Ambient Air Quality Impact Report_12SEP12 at pp. 43-44). GHG emissions are 

not known to affect visibility. Therefore, we conclude that our visibility assessment has not 

changed as a result of the PSD review of GHG emissions. 

7.3 Growth 

The growth component of the additional impact analysis involves a discussion of general 

commercial, residential, industrial, and other growth associated with SPI-Anderson. 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 potential growth impacts associated with this 

employment, this as impacts to local population and housing needs. 

In EPA’s Statement of Basis and Ambient Air Quality Impact Report issued for public comment 

on September 13, 2012, we concluded that the proposed project is not expected to result in any 

significant growth in the area. (See online docket #III.02, SPI-Anderson Ambient Air Quality 

Impact Report_12SEP12 at pp. 44-45). Specifically, the facility is still expected to employ 

approximately eight additional workers. In addition, the project will utilize existing roads and 

infrastructure, and no additional roads or transportation infrastructures are proposed for 

construction. Therefore, our growth assessment has not changed as a result of the PSD review of 

GHG emissions. 

8. 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 
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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. 

In EPA’s Statement of Basis and Ambient Air Quality Impact Report dated September 2012, 

EPA stated that it had concluded that the project will have no likely adverse effect on any 

endangered or threatened species or designated critical habitat. EPA is correcting this statement, 

to clarify that the EPA has concluded that the project will have no effect on any endangered or 

threatened species or designated critical habitat. As stated in EPA’s September 2012 AAQIR, 

construction activities resulting from the proposed modification will occur on SPI-Anderson’s 

existing facility footprint and 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. (See online 

docket #III.02, SPI-Anderson Ambient Air Quality Impact Report_12SEP12 at p. 45) This 

conclusion is supported in particular by the July 9, 1999 Conservation Guidelines for the Valley 

Elderberry Longhorn Beetle from the USFWS, which state that “complete avoidance (i.e., no 

adverse effects) may be assumed when a 100-foot (or wider) buffer is established and maintained 

around elderberry plants containing stems measuring 1.0 inch or greater in diameter at ground 

level.” (See online docket #II.03: USFWS Conservation Guidelines of Elderberry Longhorn 

Beetle at p. 3). Discussions with the U.S. Fish and Wildlife Service (FWS) support EPA’s 

conclusion, and have confirmed that this conclusion will not change as a result of the PSD 

review of GHG emissions from the project. 

9. Environmental Justice Screening Analysis 

Executive Order 12898, entitled “Federal Actions To Address Environmental Justice in 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). 

EPA previously concluded 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. Our previous conclusion has not changed as a result of the PSD review of GHG 

emissions.
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10. Public Comment Period, Procedures for Public Hearing 

10.1 Public Comments 

Any interested person may submit written comments regarding today’s proposed PSD permit 

modification. All written comments on today’s proposed action must be received by EPA 

Region 9 via e-mail by December 13, 2013, or postmarked by December 13, 2013. Comments 

must be sent or delivered in writing to Shaheerah Kelly at one of the following addresses: 

E-mail: R9airpermits@epa.gov

U.S. Mail: Shaheerah Kelly 

U.S. Environmental Protection Agency, Region 9 (AIR-3) 

75 Hawthorne Street 

San Francisco, CA 94105-3901 

Phone: (415) 947-4156 

Alternatively, written comments may be submitted to EPA Region 9 at the Public Hearing for 

this matter that will be held on December 10, 2013, as described below. 

Comments should address the proposed PSD permit modification including, but not limited to, 

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. 

10.2 Public Information Meeting and Public Hearing 

Public Information Meeting: To facilitate opportunities for interested persons to provide 

informed oral presentations at the public hearing describe below, EPA Region 9 will hold a 

Public Information Meeting for the purpose of providing interested parties with additional 

information and an opportunity to ask questions and obtain answers to questions about for 

informal discussion of the proposed Project. The date, time and location of the Public 

Information Meeting are as follows: 

Date: December 10, 2013 

Time: 4:30 PM – 6:00 PM 

Location: City of Anderson Community Center 

1887 Howard Street 

 Anderson, California 96007 
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Public Hearing: Pursuant to 40 CFR 124.12, EPA Region 9 also intends to hold a Public 

Hearing to provide the public with further opportunity to comment on today’s proposed PSD 

permit modification. At this Public Hearing, any interested person may provide written or oral 

comments and data pertaining to today’s PSD permit modification. The date, time and location 

of the Public Hearing are as follows: 

Date: December 10, 2013 

Time: 7:00 PM – 9:00 PM 

Location: City of Anderson Community Center 

1887 Howard Street 

 Anderson, California 96007 

If you are a person with a disability and require a reasonable accommodation for this event, 

please contact Philip Kum at kum.philip@epa.gov or at (415) 947-3566. If possible, requests 

should be made at least 5 business days in advance of the event to ensure proper arrangements 

can be made.

10.3 Availability of Information 

All information submitted by the applicant is available as part of the administrative record. The 

proposed PSD permit modification, this Supplemental AAQIR, the AAQIR dated September 

2012, the 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 Shaheerah Kelly at (415) 947-4156 at least 72 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 Region 9’s proposed PSD permit modification, this Supplemental AAQIR, and the AAQIR 

dated September 2012 are also available for review at the (1) Shasta County Air Quality 

Management District at 1855 Placer St., Suite 101 in Redding, CA 96001; (2) Anderson Public 

Library at 3200 W. Center Street in Anderson, CA 96007; (3) Redding Public Library at 1100 

Parkview Ave. in Redding, CA 96001; and (4) Shasta Lake Gateway Library at 4150 Asby Court 

in Shasta Lake, CA 96019. 

All written comments that are received on today’s proposed action 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 email. A transcript of the public hearing will also be included in the public docket. If you send email directly to the EPA, your e-mail address will be automatically captured and included as part 
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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. 

10.4 Final Permit Decision

EPA Region 9 will consider all new written and oral comments submitted during the public 

comment period, including those provided at the public hearing, before taking final action on the 

PSD permit modification. EPA Region 9 will send notice of the final decision to each person 

who provides contact information and who: (i) submits comments during the public comment 

period, including oral comments provided at the public hearing; or (ii) requests notice of the final 

permit decision. EPA Region 9 will respond to all new 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: 

1. A later effective date is specified in the decision; or 

2. Our decision is appealed to the EAB pursuant to 40 CFR Part 124.19. Please note that 

the EAB’s July 18, 2013 decision remanding EPA Region 9’s February 19, 2013 permit 

modification stated: “Once [EPA Region 9] issues a final permit decision following the 

public hearing required by the remand, that final permit decision and the Board’s decision 

in this matter become final agency action subject to judicial review. 40 CFR §124.19(l). . 

. . The Board is not requiring, and will not accept, an appeal to the Board of the final 

permit decision for the Project following remand in this case.” In re Sierra Pacific 

Industries, PSD Appeal Nos. 13-01 to 13-04, slip op. at 67 (EAB July 18, 2013); 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 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. 

10.5 EPA Contact Information

If you have questions, please contact Shaheerah Kelly at (415) 947-4156 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 Shaheerah Kelly at (415) 947-4156 or send an e-mail at R9airpermits@epa.gov, 

or visit EPA Region 9’s website at http://www.epa.gov/region09/air/permit/psd-publicguidelines.html. 
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11. 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 for GHG 

emissions as well as NOx, CO, PM, PM10 and PM2.5. 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, our AAQIR dated September 2012, this 

Supplemental AAQIR, and related materials to the public for review, and make a final decision 

after considering any public comments on our proposal.