## 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 2013ii 

### This page left intentionally blankiii 

## Proposed Prevention of Signif icant Deterioration Permit

SUPPLEMENTAL STATEM ENT 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 Si gnificant Deterioration Regulations .............................. 14

5. Best Available Cont rol Technology ........................................................................................ 16

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

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

5.1.2 Step 2 – Eliminate Technically In feasible Control Technologies ............................ 19

5.1.3 Step 3 – Rank Remaining Control Tec hnologies 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 In feasible Control Technologies ............................ 29

5.2.3 Step 3 – Rank Remaining Control Tec hnologies 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 Im pact 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 ............................................................................................... 36iv 10.5 EPA Contact Information ......................................................................................... 36

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

## 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 Availabl e 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

CH 4 Methane
CHP Combined Heat and Power

CO 2 Carbon Dioxide

CO 2 e 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 I ndustries – 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 CO 2 e/lb steam Pounds of CO 2 Equivalents per Pound of Steam
lb CO 2 e/MW-hr Pounds of CO 2 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

NO 2 Nitrogen Dioxide

N 2 O Nitrous Oxide

NO

x Oxides of Nitrogen (NO + NO 2 ) NSCR Non-Selective Catalytic Reductionvi NSPS New Source performance Standards, 40 CFR part 60
NSR New Source Review PM Total particulate Matter

PM 2.5 Particulate Matter less than 2.5 micrometers ( μ m) in diameter

PM 10 Particulate Matter less than 10 micrometers ( μ m) 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/LA ER 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 YearSierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 7 

## Proposed Prevention of Signific ant 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 Di vision (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 bi omass during normal operation, and natural gas for periods of startup, shutdown and flame st abilization. The cogeneration unit will be
constructed within th e physical boundaries of the cu rrent SPI-Anderson Division facility location. The facility is lo cated at 19758 Riverside Avenue in Anderson, California 96007 (Assessor’s parcel No. 050-110-025). EPA has prev iously determined that the proposed major Prevention of Significant Deterioration (PSD) permit modification is consistent with the requirements of the PSD program for nitrogen oxides (NO

x ), carbon monoxide (CO), total particulate matter (PM), particul ate matter under 10 micrometers ( μ m) in diameter (PM 10 ) and particulate matter under 2.5 μ m in diameter (PM 2.5 ). We are making a further determination that the proposed PSD permit modification is consiste nt 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 greates t 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 w ith the U.S. Fish and Wildlife Service under Section 7 of the Endangered Species Act, EPA has concl uded that the proposed modification will have no effect due to GHG emissions on any Federally-listed endange red or threatened species or designated critical habita t 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 8 

## 1. Purpose of this Document

This document is a Supplementa l Statement of Basis and Ambi ent Air Quality Impact Report (AAQIR) related to greenhouse ga s emissions (GHG) for the pr oposed PSD permit modification for the SPI-Anderson facility. This document s upplements our Statement of Basis and Ambient Air Quality Impact Report dated Septembe r 2012, which covers non-GHG emissions -- specifically, NO

x , CO, PM, PM 10 and PM 2.5 . ( 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 avai lable control technology determin ation for GHG emissions for the proposed PSD permit modification , including requirements under th e 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 decisi on regarding this project on February 19, 2013 (February 2013 Permit). The February 2013 Permit required use of BACT to limit emissions of

NO

x , CO, PM, PM 10 and PM 2.5 , 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 Qualit y 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 Appe als 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 respon ds to any new comments received during the public hearing.

In addition, on July 12, 2013, the United States Cour t of Appeals for the Di strict of Columbia
Circuit vacated EPA’s rule 1 deferring regulation of biogenic carbon dioxide (CO 2 ) 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 conditio ns 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 Ru le. The EAB stated that it expects that the

1 Deferral for CO 2 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 9 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 Defe rral 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

CO 2 deferral rule, and the decision remains subject to possible addi tional legal proceedings. On October 22, 2013, the intervenors in Center for Biological Diversity filed a second request to extend the deadline for petitions fo r rehearing. To facilitate EPA action on this permit while these matters remain unresolved, SPI submitted to EPA PSD a pplication material for GHG emissions from the proposed new equipment. SP I requested that EPA review such materials and include appropriate emission limits and re lated requirements in the proposed permit modification. The proposed permit modificatio n that EPA Region 9 is announcing today is similar to the proposed permit modification th at 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 de termination for the proposed project.



## 3. GHG Emissions from the Proposed Project

EPA’s PSD permitting regulations define GHGs as an aggregate of: carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxide (N 2 O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF 6 ). 40 CFR § 52.21(b)(49)(i). The pr oposed project has the potential to emit only three of these GHGs: CO 2 , CH 4 , and N 2 O. All GHG emissions associated with the project will be generated by the cogeneration un it and emergency engine; the cooling tower will not emit any GHGs.

EPA regulations further define CO 2 e as the sum of the mass emi ssions 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 Ru le (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 th e 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 mi nor technical issues we identified since February
2013. These revisions do not affect our BACT determ inations 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 10 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 NO

x , and multiclone
with ESP to control PM emissions

 Equipped with one 30,400 ft 3

, 2 hog fuel bins, 2 wood chip
fuel bins

Conveyance System  (2) Cyclones with combined flow rate of 51.004 scfm

 (1) 7,118 ft 2 MAC Pulse Jet Baghouse with 300hp Blower

 (1) 35” x 45” Rotary Airlock

 (1) Buhler en-masse, 19”, 22tph Conveyor

 (2) Each overhead storage bi ns 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 biom ass boiler will also be equipped with two 62.5 MMBtu/hr natural gas burners th at will be used during start up, and, potentially, during shutdown
and for flame stabilization. Th e biomass boiler will combust a small amount of natural gasSierra 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 em issions 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 emergenc y 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 CO 2 e emissions from the project, and show th at the proposed project has the potential to generate a maximum of 432,439 tons of CO 2 e per year. SPI’s GHG emission estimates for the proposed boiler are slightly different because va lues were rounded up, providing a total potential of 433,000 tons of CO 2 e per year.

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

Emission
Unit GHG
Pollutants Emission Factor 3 (Heat Input) Global Warming
Potential 4 GHG
Pollutant
Emission Rate (tpy) 5 CO 2 e Emission

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

Stoker
Boiler CO 2 93.8 206.60793 1 423,513 423,513

CH 4 0.032 0.07048 21 144 3,034

N 2 O 0.0042 0.00925 310 19 5,879
Total CO 2 e -- -- --

-- 432,426

Emergency Engine CO 2 53.02 116.78411 1 13 13

CH 4 0.001 0.00220 21 0.00024 0 6

N 2 O 0.0001 0.00022 310 0.00002 0 7

Total CO 2 e -- -- -- -- 13

(Source: Table 2-1 of Biomass-Fired Cogeneration Project: Best Av ailable Control Technology Analysis for Greenhouse Gases, Sierra Pacific Industries Lumber Ma nufacturing 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 MMBt u/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 CO 2 e estimate for CH 4 is less than 1 tpy.

7 CO 2 e estimate for N 2 O 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 CO 2 e Emission Rate (tpy)

CO 2 423,526

CH 4 3,034

N 2 O 5,879
Total 432,439

(Source: Table 2-3 of Biomass-Fired Cogeneration Project: Best Av ailable Control Technology Analysis for Greenhouse Gases, Sierra Pacific Industries Lumber Ma nufacturing Facility Anderson, California, August 15, 2013)

The PSD permit limits the annual heat input from natural gas to not exce ed 10 percent of the total heat input on an annual basis. Operati on of the natural gas burners will not exceed 10 percent of the annual heat i nput capacity of the boiler, or 409,934 MMBtu/yr (468 MMBtu/hr * 8.760 hr/yr * 10%). Based on that ma ximum annual heat input and the CO 2 e emission factor for natural gas combustion from 40 CFR Part 98 (1 17 lb/MMBtu), the maximum GHG emissions from the natural gas burners will be 23,981 tpy.

The proposed cogeneration unit will be started an d shutdown as infrequently as possible. SPIanticipates at least one outage period each year for maintenance; any additional shutdown-andstartup cycles will be the result of an unschedul ed 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 accomp lish, 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 provid ed 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 13 Table 3-4: Greenhouse Gas Emissions for Startup Periods

Fuel GHG
Pollutants Emission

Factor 8 (lb/MMBtu) Hourly Emission

Rate 9 (lb/hr) Event Emission

Rate 10 (lb/event)

Firing Biomass
Fuel CO 2 207 96,770 580,622

CH 4 0.282 132 792

N 2 O 0.03702 17 104
Total CO 2 e -- 104,916 629,498

Firing Natural Gas CO 2 117 14,611 87,666

CH 4 0.0022 0.276 1.65

N 2 O 0.00022 0.0276 0.165
Total CO 2 e 14,625 87,752

(Source: Table 2-2 of Biomass-Fired Cogeneration Project: Best Av ailable Control Technology Analysis for Greenhouse Gases, Sierra Pacific Industries Lumber Ma nufacturing 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)

CO 2 55,691 668,288 334

CH 4 66 794 0.397

N 2 O 9 104 0.0521
Total CO 2 e 59,771 717,250 359

(Source: Table 2-2 of Biomass-Fired Cogeneration Project: Best Av ailable Control Technology Analysis for Greenhouse Gases, Sierra Pacific Industries Lumber Ma nufacturing 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 (SF 6 ) as a dielectric medium. The existing boiler will be decommissioned and dismantled after the new coge neration 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 us ed for drying lumber at the facility. No combustion occurs in the kilns; t hus, 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 CH 4 and N 2 O 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 em ission rate multiplied by 6 hours.Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 14 Table 3-6: Greenhouse Gas Emi ssions for Existing Equipment

Emission
Unit GHG
Pollutants Emission Factor 11 (Heat Input) Global Warming
Potential GHG
Pollutant
Emission

Rate (tpy) CO 2 e Emission

Rate 12 (tpy) (kg/MMBtu) (lb/MMBtu)

Boiler CO 2 93.8 206.6079 3 1 105,335 105,335

CH 4 0.032 0.07048 21 35.9 755

N 2 O 0.0042 0.00925 310 4.7 1,462
Total CO 2 e -- -- -- -- 107,552

Circuit
Breaker SF 6 1% leakage/year 23,900 0.000950 5
Total CO 2 e -- -- -- -- 5

(Source: Table 2-3 of Biomass-Fired Cogeneration Project: Best Av ailable Control Technology Analysis for Greenhouse Gases, Sierra Pacific Industries Lumber Ma nufacturing Facility Anderson, California, August 15, 2013)

Table 3-7: Total Greenhouse Gas Em issions for Existing Equipment

GHG Pollutants CO 2 e Emission Rate (tpy)

CO 2 105,335

CH 4 755

N 2 O 1,462

SF 6 5
Total CO 2 e 107,557

(Source: Table 2-3 of Biomass-Fired Cogeneration Project: Best Av ailable Control Technology Analysis for Greenhouse Gases, Sierra Pacific Industries Lumber Ma nufacturing 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 Ambien t Air Quality Standards, or NAAQS, for six common air pollutants. These commonly found ai r pollutants are known as “criteria pollutants”
and are found all over the United States . They are particulate matter (PM 2.5 and PM 10 ), 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 SF 6 emission rate for the switchgear was calculated by multiplying the SF 6 capacity of the existing breaker and two switches (190 lb) by th e 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. CO 2 e 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 15 level ozone, carbon monoxide, sulfur oxides, nitr ogen oxides, and lead. EPA has established maximum concentrations, called NAAQS, for each crit eria pollutant above which adverse effects on human health may occur. Areas that meet the NAAQS are clas sified as being in “attainment”
of the standards. Areas that do not meet the NAA QS are classified as being “nonattainment.” A single area can be attainment for some crite ria 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 locate d 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 t ons 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 p hysical 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 sign ificant 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 al so 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 pr eviously 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 em issions 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 (CO 2 ), nitrous oxide (N 2 O), methane (CH 4 ), hydrofluorocarbons (HFC), perfluorocarbons (PFC), and sulfur hexafluoride (SF 6 ). EPA’s Tailoring Rule (75 Federal Register 31514, June 3, 2010) established initial GHG applicability thresholds for new sources or modifications, whic h phase in over time. The Tailoring Rule does not change the basic PSD applicability proce ss 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 th reshold for, the source based on CO 2 equivalent (CO 2 e)
emissions as well as its GHG mass emissions

. A source’s CO 2 e emissions are computed by multiplying the mass amount of emis sions 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 majo r 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 CO 2 e. See 40 CFR § 52.21(b)(49)(iv)( b ). The data in Table 4-1 show that, when CO 2 emissions from the combustion of biomass are included, the proposed project will be s ubject to PSD review for GHGs.Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 16 Table 4-1: Estimated Emissi ons and PSD Applicability

Estimated Annual

GHG Emissions

from Project (tpy of CO 2 e) Significant Threshold

for GHGs (tpy mass) “Subject to Regulation”
Threshold for
Modification at an

Existing Source (tpy of CO 2 e) 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. Howe ver, since there are no NAAQS or PSD increments for GHGs, the require ments to demonstrate that a source does not
cause or contribute to a viol ation of the NAAQS is not applic able to GHGs. Thus, we do not recommend that PSD applicants be required to model or c onduct ambient monitoring for CO 2 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 ap propriate 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 Cl ass 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 ju risdiction of the Shas ta County Air Quality Management District.



## 5. Best Available Control Technology

This chapter describes the Best Available Cont rol Technology (BACT) fo r 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 und er 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 en ergy, environmental, and economic impacts and other costs, determines is achievable through ap plication of production processes and available methods, systems, and technique s, including fuel cleaning or treatment or innovative fuel combustion techniques for control of each such po llutant. In no event sha ll application of BACT result in emissions of any pollutants which w ill exceed the emissions allowed by any applicable standard established pursuant to section 111 (N SPS) or 112 (NESHAPS) of the Clean Air Act.”

In accordance with 40 CFR § 52.21(j), a new major st ationary source is required to apply BACT for each regulated NSR pollutant for which its PTE exceeds significance thresholds. BACT isSierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 17 defined as “an emission limitation (including a vi sible emission standard) based on the maximum degree of reduction of each pollutant subjec t to regulation under the Act.....which the Administrator, on a case-by-case basis, taking in to account energy, enviro nmental, and economic impacts, and other costs, determines is achievabl e for such source.” BACT must be at least as stringent as any applicable Ne w Source Performance Standards (NSPS) under 40 CFR Part 60 or
National Emission Standard for Hazardous Ai r 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 ad judicating PSD permit appeals. See, e.g., In re Knauf, 8 E.A.D. 121, 129-31 (EAB 1999); In re Ma ui Electric, 8 E.A.D. 1, 5-6 (EAB 1998).

In brief, the top-down process involves ranking available contro l 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 te chnical 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 st ringent 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 exerci se for the particular source under evaluation. In summary, the five steps involved in a t op-down BACT evaluation are:

1. Identify all available control options with prac tical potential for application to the specific emission unit for the regulate d pollutant unde r evaluation;

2. Eliminate technically inf easible technology options;

3. Rank remaining control technolog ies by control effectiveness;

4. Evaluate the most effective control alternativ e 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 stringe nt 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 th e proposed boiler and emergency engine. The cooling tower is not expected to produce GHG emissions.Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 18 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 CO 2 e 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  CO 2 CEMS

 Continuously monitor steam

production rate

 Annual CO 2 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 averag e 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.Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 19 5.1.1 Step 1 – Identify A vailable Control Technologies

SPI-Anderson identified the contro l alternatives in Table 5-2 fo r the proposed biomass boiler.

Table 5-2: GHG Control Alternatives

GHG

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

CO 2  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.)

CH 4  Activated carbon adsorption systems

 Thermal destruction

 Catalytic destruction  Proper combustion practices and use of a properly designed boiler --

N 2 O  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 N 2 O emissions

 Addition of N 2 O-Abating SCR System

5.1.2 Step 2 – Eliminate Technical ly Infeasible Control Technologies

CO 2 Control Options

Boiler Design Alternatives EPA evaluated boiler design alternatives in th e 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 Q uality 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 cogeneratio n projects that propose to use a fluidized bed boiler. These projects are North Springfield Sustainable Energy Projec t 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 ).Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 20 North Springfield Sustainable Energy Project w ould recover low grade heat to produce hot water for a thermal loop in the North Sp ringfield Industrial Park. The No rth Springfield Industrial Park typically has existing means for generating hot water, and the proposed thermal loop would augment the existing system. Thus, the consequen ces associated with the “low grade heat” from the North Springfield Energy Proj ect being unavailable to the Nort h 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 Spri ngfield Energy Project does not operate lumber dry kilns, or provide process st eam of any real consequence, a nd is not subject to operational considerations regarding influences on steam lo ad demand external to power production as with the SPI-Anderson facility.

The WE Energies project woul d include an 800 MMBtu/hr bioma ss-fired circulating fluidized bed boiler and a 350 MMBtu/hr natural gas-fired p ackage 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 oper ational setup. SPI has not proposed installing and operating a similar additional fossil-fuel base d 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 bi omass-fired boiler at the SPI-Ande rson facility will no longer operate and is expected to be decommissioned after the new cogeneratio n unit is operational.

SPI also provided additional information from fluidized bed boiler manufacturers which indicate a fluidized bed boiler design would not be approp riate for the proposed cogeneration project at the SPI-Anderson facility. According to this information, ope ration 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 furt her lead to associated problems such as higher quantities of ash in the bed which form deposits around heat transfer media in the bed. T hese ash and ash-coated particles contain sodium a nd 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 boile r 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 operati onal, the proposed cogeneration unit will be the only source of steam at the SPI-A nderson facility. It will provi de 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), th e 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).Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 21 For the reasons stated above, EPA ag rees 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 biom ass fuels, alone or in combination with other fuels, in boilers to generate steam at the SPI-A nderson 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 Pr actices, and Efficient Operation This control option consists of: (1) altering the com bustion process to reduce CO 2 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 CO 2 generated per unit of steam or electrici ty generated. According to SPI, at maximum operation, the efficiency of the proposed boiler (i.e., the fractio n of the energy in the
fuel that is transferred to the steam) is expected to be approxima tely 70 percent. The efficiency of the electrical generator is, at full load, approximately 96 percent. The overall efficiency of the cogeneration unit will vary depe nding upon the quantities of steam used to heat the kilns and generate electricity, but is expected to vary be tween 37 and 53 percent. This control option is technically feasible.

Carbon Capture and Sequestration (CCS) This control option consists of removing CO 2 from the post-combustion exhaust stream. Following capture, the CO 2 would be transported and stored pe rmanently, or “sequestered,” in a geologic formation. Potential CO 2 sequestration sites include ge ological formations (including oil and gas fields for enhanced recovery) and ocean storage. SPI-Ande rson identified three approaches to CO 2 capture that are generally applicable to power generation: (1) pre-combustion systems designed to separate CO 2 and hydrogen (H 2 ) from produced syngas, (2) post-combustion systems designed to separate CO 2 from flue gas, and (3) oxy-co mbustion that uses high-purity oxygen (O 2 ) instead of air, which produces flue gas composed largely of CO 2 . 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 fo r application on the proposed biomass-fired boiler.

CH 4 Control Options

Proper Combustion Practices and Use of a Properly Designed Boiler
CH 4 emissions are generally the result of incomple te fuel combustion. In the case of biomass, volatile compounds (including CH 4 ) are released as the fuel is heated in the furnace, some portion of which escapes combustion by imprope r mixing with oxygen or being confined to zones of relatively low temperature. Proper co mbustion practices and use of a properly designed boiler maximizes complete combustion, which minimizes formation of CH 4 . This control option is technically feasible.Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 22 Activated Carbon Adsorption Systems Adsorption systems pass the gas stream though canis ters filled with acti vated carbon, and the

CH 4 is trapped in pores located on the carbon particles. When the carbon approaches saturation, the canister is replaced and processed to remove the CH 4 , which is recovered or destroyed. Adsorption systems are usually limited to s ources generating organic compounds having a molecular weight of more than 50 and less th an approximately 200. Low molecular weight organics, such as CH 4 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 CH 4 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 CH 4 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 CH 4 oxidizes, forming

CO 2 and water. Thermal oxidizers destroy CH 4 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 ar e introduced. While th e thermal oxidizer may destroy a portion of the small amount of CH 4 present in the exhaust (i.e., less than 1 percent by volume), the oxidizer itself is likely to generate additional air pollutants (e.g., NO

x , CO, VOCs,
and CH 4 ) such that there is a net increase in emissi ons. In addition, a thermal oxidizer has never
been used to reduce CH 4 emissions from a biomass-fired boiler. SPI has determined that control
of CH 4 using thermal oxidation is considered spec ulative and not achieved in practice for a biomass-fired boiler, and, therefore, not technically feasible for reducing CH 4 emissions from a
biomass-fired boiler.

Catalytic Destruction Systems Oxidation systems increase the temperature of the gas stream until the CH 4 oxidizes, forming

CO 2 and water. Thermal oxidizers destroy volat ile compounds using a flame, while catalytic oxidation uses a catalyst to promote the oxidati on reaction at a temperature lower than the combustion temperature of volatile compounds such as CH 4 . Regardless of whether the catalyst is located upstream or downstream of a part iculate control device (e.g., an electrostatic precipitator), alkali compounds in the exhaust ga s deactivate the catalyst . To counteract the deactivation, large quantities of catalyst must be deployed and frequently replaced, resulting in unpredictable boiler availa bility and control system costs. However, SPI-Anderson determined that a catalytic oxidati on system to reduce CH 4 emissions from the proposed biomass-fired boiler is technically feasible.

N

2 O Control Options

Proper Combustion Practices and Use of a Properly Designed Boiler Typically, furnace conditions that favor CH 4 formation, also favor N 2 O formation. N 2 O is the result of lower combustion temperatures (le ss than 800°C or 1,475°F). Its formation can be limited to some extent by using proper combusti on techniques and a properly designed boiler that promotes uniform furnace temperatures. This control option is technically feasible.Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 23 Non-Selective Catalytic Reduction NSCR systems are typically used to reduce emissi ons from reciprocating engines operated in a rich-burn or stoichiometric mode. In gene ral, NSCR systems pass the exhaust gases over catalysts, which use metals (e.g., platinum, rhodium, palladium) to convert NO

x , carbon monoxide (CO), and volatile organic compound s (VOCs) to water, nitrogen, and CO 2 . NSCR systems have primarily been developed to reduce N 2 O emissions from adipic and nitric acid production operations. There are no instances of an NSCR system being applied to reduce N 2 O
emissions from a biomass-fired boiler. Because significant differences exist between the exhaust from adipic and nitric acid operations and th at of a biomass-fired boiler (i.e., typical N 2 O
concentration in exhaust from a nitric acid plant is typi cally 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 eff ectively, and is therefore consider ed technically infeasible for
control of N 2 O from proposed biomass-fired boiler.

Thermal Destruction Systems
Thermal destruction of N 2 O is achieved using a reducing fl ame burner combusting premixed methane or natural gas. The flame temperatur e must be maintained high enough to destroy the

N 2 O, but below 1,500°C to minimize NO

x formation. To thermally oxidize a pollutant in an exhaust stream, a combustor is located in the ex haust duct, and fuel (typically natural gas) and enough supplemental air to support a flame are in troduced. A thermal oxidizer may destroy a
small amount of N 2 O present in the exhaust (i.e., less th an 1 percent by volume); however, the oxidizer itself is likely to genera te additional air pollutants (e.g., NO

x , CO, VOCs, and CH 4 ) such
that there is a net increase in emissions. In addition, a thermal oxidizer has never been used to
reduce CH 4 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 N 2 O 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 N 2 O-decomposing catalysts. As previous ly mentioned above, this control is considered technically feasible.

Removal of SCR and SNCR Control Systems to Reduce N 2 O Emissions Conventional commercially-available selective catalytic reduction (SCR) systems (i.e., those using titanium, tungsten, and vanadium-based catal ysts) used to reduce emi ssions of nitric oxide (NO) and nitrogen dioxide (NO 2 ), as well as selective non-catal ytic reduction (SNCR) systems, generate N 2 O, so removal of such control systems would reduce N 2 O emissions. Since no SCR system is proposed for installation on the pr oposed biomass-fired boile r, it is technically infeasible to not install such a system. An SNCR system is proposed by SPI to reduce NO

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

Addition of N 2 O-Abating SCR System The criteria pollutant BACT analysis provided with the PSD permit application concluded that conventional SCR systems were tec hnically feasible for reducing NO X emissions from biomassfired boiler; therefore, N 2 O-abating SCR systems are also co nsidered technically feasible.Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 24 5.1.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness

After elimination of technically infeasible control options, th e remaining control methods are provided as follows.

Post-Combustion CCS Currently available technology can theoretically capture approx imately 90 percent of the postcombustion CO 2 in flue gas. It is not expected to impact CH 4 or N 2 O in the exhaust. Table 5-3 shows estimates for the potential GHG emissi on reductions resulting from the use of post combustion CCS technology of 88.1 percent on a CO 2 e basis. SPI estimated a potential GHG
emission reduction level of a pproximately 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. Theref ore, our analysis incl udes the estimate of 88.1
percent.
Table 5-3: Post Combustion CCS

GHG Emission Rate (tpy) GWP Uncontrolled CO 2 e (tpy) % Control Controlled CO 2 e (tpy)

CO 2 423,513 1 423,513 90 381,162

CH 4 144 21 3,034 0 0

N 2 O 19 310 5,879 0 0 Total -- -- 432,426 -- 381,162

Percent GHG Reduction: 88.1%

Catalytic Destruction/Oxidation of CH 4 and N 2 O Table 5-4 shows SPI’s estimates for the poten tial GHG emission reducti ons resulting from the use of oxidation catalyst technol ogy. This technology would result in a reduction of 1.6 percent

on a CO 2 e basis.

Table 5-4: Catalytic Destruction/Oxidation

GHG Emission Rate (tpy) GWP Uncontrolled CO 2 e (tpy) % Control Controlled CO 2 e (tpy)

CO 2 423,513 1 423,513 0 0

CH 4 144 21 3,034 40 1,214

N 2 O 19 310 5,879 95 5,585 Total -- -- 432,426 -- 6,798

Percent GHG Reduction: 1.6%

Removal of NO

x Control System (SNCR) SPI estimated that SNCR systems convert, depending upon the reagent and furnace conditions, between 10 and 20 percent of NO

x in the exhaust to N 2 O. SPI estimated that the proposed biomass boiler would have a PTE of 267 tpy for NO

x . Assuming up to 20 percent of the NO

x inSierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 25 the exhaust is converted to N 2 O results in a conservative estimate of 53.4 tpy of N 2 O emissions. SNCR systems do not generate any CO 2 or CH 4 , 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 CO 2 e basis. EPA notes that this is a very conservative
estimate.

Table 5-5: Removal of SNCR System

GHG Emission Rate (tpy) GWP Uncontrolled CO 2 e (tpy) % Control Controlled CO 2 e (tpy)

CO 2 423,513 1 423,513 0 0

CH 4 144 21 3,034 0 0

N 2 O (combustion) 19 310 5,879 0 0

N 2 O (SNCR control) 53.4 310 16,554 100 16,554

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

Percent GHG Reduction: 3.7%

Addition of N 2 O-Abating SCR System
Addition of a N 2 O-abating SCR system would capture all N 2 O 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 N 2 O-abating SCR system. The reduction in GHG emissions would be 1.4 percent on a CO 2 e basis. EPA notes that th is is a very conservative
estimate.

Table 5-6: Addition of N 2 O-Abating SCR System

GHG Emission Rate (tpy) GWP Uncontrolled CO 2 e (tpy) % Control Controlled CO 2 e (tpy)

CO 2 423,513 1 423,513 0 0

CH 4 144 21 3,034 0 0

N 2 O 19 310 5,879 100 5,879

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

Percent GHG Reduction: 1.4%Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 26 Good Boiler Design, Good Combustion Practices, and Efficient Operation / Proper Combustion Practices and Use of a Properly Designed Bo iler / 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 fro m 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. SPIexpects 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 re sidues, agricultural residues from orchards in the Sacramento Valley, and urban wood residues diverted from la ndfills. 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 alte rnatives, in orde r of most to
least effective on a CO 2 e 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 CO 2 e basis

Removal of NO

x Control System (SNCR) 3.7 percent reduction on a CO 2 e basis Catalytic Destruction 1.6 percent reduction on a CO 2 e basis

Addition of N 2 O-Abating SCR System 1.4 percent reduction on a CO 2 e 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 facilit ies 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 CO 2 e per lb steam produced based on a 12-month rolling block average.Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 27 Table 5-8: Summary of Recent GHG BACT De terminations for Similar Biomass Boilers 14

Facility State Permit

Issuance

Date Size (MMBtu/hr) Control Methods CO 2 e 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 contro ls, 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 sa me order as the cost previously borne by other sources of the same type in applying the contro l alternative, then the control alternative is considered economically feasible, an d therefore accepta ble as BACT.

Post Combustion CCS CCS systems require additional energy to remove CO 2 from the boiler exhaust, as well as to compress it for transport and storage. Th e relatively dilutee concentration of CO 2 in the exhaust gas of a biomass boiler (i.e., between 10 and 20 percent by weight) wo uld require a strong solvent to capture the CO 2 , as well as a considerable amount of energy to regenerate the solvent. The additional energy required to compress the captured CO 2 to approximately 2,200 psig would increase the energy footprint (including emission of criteri a pollutants and GHGs) of the proposed boiler by 40 to 60 percen t. Captured and compressed CO 2 must be transported to a storage facility or end use, such as enhanced oil recovery. Storage f acilities are not currently

14 The RBLC decisions listed in Table 5-8 are based on BACT decisions poste d on EPA’s RBLC website as of July 26, 2013.Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 28 commercially available within the vicinity of the SPI-Anderson site . There are no nearby petroleum extraction operations or industrial pro cesses that would be able to accept the volume
of CO 2 SPI would be emitting. SPI estimated that the o il 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 th e cost of installing a CCS system would be woul d cost approximately $29,000,000 15 , and the cost of constructing a pipeline to transport CO 2 from the Anderson facility to Brentwood, California would cost approximately $109,907,547 16 . 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. Furthermor e, SPI estimated that to
construct a lumber manufacturi ng facility with a production cap acity similar to that of the existing Anderson facility would cost appr oximately $80,000,000. Accordingly, based on these costs, CCS is being eliminated as a GHG cont rol option due to its di sproportionate costs.

Removal of NO

x Control System (SNCR) Elimination of the SNCR sy stem used to reduce NO

x emissions from the boiler would potentially reduce 53.4 tpy of N 2 O emissions, which is only 3.7% of the total CO 2 e that is estimated to be emitted from the cogeneration project. Additiona lly, this alternative would result in increased

NO

x emissions (i.e., 267 tpy NO

x 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 woul d have an annualized cost of approximately $2,379,713. However, this cost woul d potentially reduce onl y 1.6 percent of the total GHG emissions (i.e., CH 4 and N 2 O expressed as CO 2 e), as shown in Table 5-4. Since CH 4 and N 2 O emissions are expected to be very low, particularly in terms of CO 2 e, EPA considers the construction and operating costs of a catalytic de struction / oxidation system to control these pollutants to be excessive. Therefore, EPA is eliminating this control option.

Addition of N 2 O-Abating SCR System
SPI estimated that the addition of a N 2 O-abating SCR system would ha ve an annualized cost of approximately $1,276,065. However, this cost woul d potentially reduce onl y 1.4 percent of the total GHG emissions (i.e., CH 4 and N 2 O expressed as CO 2 e), as shown in Table 5-4. Since N 2 O emissions are expected to be very low, particularly in terms of CO 2 e, EPA considers the construction and operating costs for the c ontrol 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 Bo iler / Utilization of Biomass Fuel Alone These control options are consid ered the baseline level. SPI anticipates that the proposed
biomass boiler will be constructed with an ener gy 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.Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 29 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 envi ronmental 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 ev aluate the feasibility of these methods, we have concluded that BACT for the proposed bioma ss-fired stoker boiler is (1) 0.36 pounds of CO 2 e per pound of steam (12-month rolling average basi s), (2) combustion of biomass at all times except during periods of startup, shutdown and fl ame stabilization (in which natural gas fuel is allowed to be combusted), and (3) energy e fficient design and use of good combustion and operational and maintenance practices as describe d in SPI’s permit application and subsequent submissions to the EPA, which include, but ar e not limited to, (i) construction and operation of an efficient, state-of-the-art, air-cooled, reciprocat ing stepgrate stoker boiler that ensures good combustion; (ii) operation of the boiler as a coge neration unit at the Faci lity; and (iii) operation
and maintenance of the boiler in accordance w ith the manufacturer’s recommendations. The

CO 2 e limit applies at all times, includi ng during startups and shutdowns.



### 5.2 GHG BACT Analysis – Emergency Engine

The project includes a 256 hp (190 kW) natura l gas-fired emergency engine to run the emergency boiler recirculation pump. This emissi on 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 to p-down BACT analysis has been performed and
is summarized below.

5.2.1 Step 1 – Identify A vailable Control Technologies

In general, the options for reducing GHGs from th e emergency engine fall into three categories: inherently low-emitting processes, clean fuels, and add-on control technologies.

5.2.2 Step 2 – Eliminate Technical ly 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 po wer from the grid is not available to operate theSierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 30 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 wa y to minimize the emissions of
GHGs from these sources. Since the EPA’s e ngine emission standards for other criteria pollutants are based on the emission rate of th e pollutant per unit of energy output, engine manufactures have employed a combination of reducing the mass em ission rate of the pollutant(s) and increasing the overall efficiency of the engines. Therefore, compliance with EPA’s engine standards is considered tec hnically 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 em issions. Natural gas is considered the fossil fuel that generates the least GHG emissions per un it of energy produced. The only clean fuel to consider for the engine is natural gas. This c ontrol 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 compli cates operation and potentially reduces engine readiness, and compromises the em ergency role of the engine. Installing an addon control technology, such as CCS, is not feas ible 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 na tural gas-fired engine th at meets EPA’s engine standards for emergency engines.

5.2.4 Step 4 – Evaluate Most Effect ive Controls and Document Results

The remaining control options are the use of a na tural gas-fired engine th at 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, S ubpart JJJJ for emergency engines.Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 31 

## 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 dete rmine whether they woul d cause or contribute to a violation of (1) th e applicable NAAQS, or (2) the applic able Class I and II PSD increments. EPA has determined that this permit modificatio n 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 e nvironment, 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 cha nges in emissions orders of magnitude larger than the emissions from individual projects th at 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 c limate 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 th at the most practical way to
address the considerations reflec ted 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 pr esent 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, th e quantity of emissions, and th e 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 potentia l impacts to soils and vegetation associated with the SPI’s emissions. Although it is clear that GHG emi ssions 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 em issions is typically conducted for changes in emissions orders of magnitude larger than the em issions 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 currentSierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 32 climate change modeling. Given these consider ations, GHG emissions would serve as the more appropriate and credible proxy fo r assessing the impact of a given facility. Thus, EPA believes that the most practical way to address the considerations re flected 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 impact s 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 evaluate s 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 Se ptember 13, 2012, we concluded that we do not expect the proposed project will cont ribute 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 visibi lity 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, industr ial, and other growth associated with SPI-Anderson. This analysis considers emissions generated by grow th that will occur in the area due to the modification. In conducting this review, we focus on residentia l, 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 lo cal population and housing needs.

In EPA’s Statement of Basis and Ambient Air Qu ality 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 faci lity is still expected to employ approximately eight additional workers. In addi tion, the project will utilize existing roads and infrastructure, and no additional roads or tr ansportation infrastructures are proposed for construction. Therefore, our growth assessment ha s 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, EP A is required to ensure that any actionSierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 33 authorized, funded, or carried out by EPA is not likely to jeopardi ze the continued existence of any endangered or threatened spec ies 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 Ai r 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. EP A is correcting this statement, to clarify that the EPA has conc luded that the project will have no effect on any endangered or threatened species or designated critical habi tat. As stated in EPA’s September 2012 AAQIR, construction activities resulting from the pr oposed modification will occur on SPI-Anderson’s existing facility footprint and construction activ ities 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 pa rticular by the July 9, 1999 Conservation Guidelines for the Valley Elderberry Longhorn Beetle from the USFWS, which state th at “complete avoidance (i.e., no adverse effects) may be assumed when a 100-foot (or wider) buffer is established and maintained around elderberry plants containi ng 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. Fi sh and Wildlife Service (FWS) support EPA’s conclusion, and have confirmed that this conclu sion 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 hi gh and adverse human health or environmental effects of its programs, policies, and activit ies on minority populations and lo w-income populations.” Section 1-101 of Exec. Order 12898, 59 Fed. Reg. 7629 (Feb. 16, 1994).

EPA previously concluded that the proposed mo dification will not cause or contribute to air quality levels in excess of h ealth standards for the pollutant s regulated under EPA’s proposed PSD permit for the proposed modification, a nd 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 cha nged as a result of the PSD review of GHG
emissions.Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 34 

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

10.1 Public Comments

Any interested person may submit written co mments regarding today’s proposed PSD permit
modification. All written comments on toda y’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 Shah eerah Kelly at one of th e 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 perm it modification including, but not limited to,
such matters as:

1. The Best Available Control T echnology (BACT) determinations; 2. The effects, if any, on Class I areas; 3. The effect of the proposed fac ility 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 opportun ities for interested persons to provide informed oral presentations at the public hearing describe be low, EPA Region 9 will hold a Public Information Meeting for the purpose of providing interested parties with additional information and an opportunity to ask questi ons 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 96007Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 35 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 disab ility 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 busine ss 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 availabl e as part of the administrative record. The proposed PSD permit modification, this Suppl emental AAQIR, the AAQIR dated September 2012, the permit application and other supporting in formation are available on the EPA Region 9
website at http://www.epa.gov/region09/air/perm it/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 admi nistrative record can be mailed to individuals upon request in accordance with Freedom of Inform ation Act requirements as described on the EPA Region 9 website at http://www.epa.gov/region9/foia/

.

EPA Region 9’s proposed PSD permit modificat ion, this Supplemental AAQIR, and the AAQIR dated September 2012 are also available for re view at the (1) Shasta County Air Quality Management District at 1855 Pl acer St., Suite 101 in Redding, CA 96001; (2) Anderson Public Library at 3200 W. Center St reet in Anderson, CA 96007; (3) Redding Public Library at 1100 Parkview Ave. in Redding, CA 96001; and (4) Sh asta Lake Gateway Libr ary at 4150 Asby Court in Shasta Lake, CA 96019.

All written comments that are received on toda y’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 Confiden tial Business Information (CBI) or other information whose disclosure is restricted by st atute. Information that you consider CBI orotherwise 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 partSierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 36 of the public comment. Please note that an e-ma il or postal address must be provided with your comments if you wish to receive di rect 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 ta king final action on the PSD permit modification. EPA Region 9 will se nd 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 provi ded at the public hearing; or (i i) 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 pursu ant 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 fi nal permit decision and the Board’s decision in this matter become final agency action s ubject to judicial review. 40 CFR §124.19(l). . . . The Board is not requiring, and will not accep t, 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 sh all 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, s ubject 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 Shaheer ah 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

.Sierra Pacific Industries – Anderson Division (SAC 12-01) Supplemental Statement of Basis & Ambient Air Quality Impact Report
November 2013 37 

## 11. Conclusion and Proposed Action

EPA is proposing to modify the PSD permit fo r 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, PM 10 and PM 2.5 . We have made this determination based on the information supplied by the applicant and our re view 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 th e public for review, and make a final decision after considering any public comments on our proposal.