1 

### Kelly, Shaheerah

From: Dave Brown [DBrown@spi-ind.com] Sent: Monday, August 05, 2013 6:15 PM To: Rios, Gerardo Cc: Kelly, Shaheerah; Christenson, Kara; Drake, Kerry; George Emmerson; 'Sloan, William M. (wsloan@mofo.com)' (wsloan@mofo.com ); Dave Dun; Eric Albright Subject: RE: SPI meeting next tuesday (6th) at 2:30
Attachments: Draft SPI GHG BACT Additional Info Needed-ea_notes.docx; SPIAnderson_GHG_BACT_analysis-revised-final.pdf

Gerardo/Shaheerah

– Attached is the updated BACT analysis for Greenhouse Gases for the Anderson PSD permit. We
have updated the analysis to include the items discussed. One item not discussed that we have intentionally left out of

the analysis is an update on the court deferral of the Tailoring Rule as well as the fairly recent vacatur by the court on the same deferral. While the mandate for the most recent court action has not been finalized, we have the left the

BACT analysis wording to reflect the Tailoring Rule with the anticipating it will soon be in

‐ effect for biomass.

At this time, we are proceeding voluntarily to include GHG emissions, including GHG BACT for biogenic sources in the

PSD permit and understand this to be a discussion point tomorrow.

Also attached is a brief red

‐ line response to the specific items in the prior note. I’ll bring a few hard

‐ copies of the BACT analysis tomorrow. See you at 2:30.

David C. Brown, PE Environmental Affairs & Compliance Manager Sierra Pacific Industries
19794 Riverside Avenue Redding, CA 96049-6028 (530) 378-8179 (530) 378-8139 fax (530) 391-7650 cell

CONFIDENTIALITY STATEMENT: This communication and any accompanying or attached document(s) are confidential and privileged. The y are intended for the sole use of the addressee(s). If you receive this communication in error, you are advised that any use, disclosure, copying, di stribution or taking any action in reliance upon this communication is strictly prohibited. If you received this message in error, please immediately telephone Si erra Pacific Industries at (530) 378- 8179, and delete this message without copying it. Thank you.

From: Rios, Gerardo [ mailto:Rios.Gerardo@epa.gov ]
Sent: Thursday, August 01, 2013 3:15 PM
To: Dave Brown
Cc: Kelly, Shaheerah; Christenson, Kara; Drake, Kerry Subject: RE: SPI meeting next tuesday (6th) at 2:30

Thanks Dave.

Based on our discussion today, here is the draft agenda:

1. Introductions

2. Discuss voluntary inclusion of GHGs in the PSD permit

3. Power Contract

4. Re

‐ notice of Permit

5. Timelines

I’ve also attached for our discussion on Tuesday the items Shaheerah has shared with you regarding additional data

needs for item number 2 in the agenda.

Gerardo C. Rios, PE2 Chief, Permits Office (415) 972

‐ 3974

From: Dave Brown [ mailto:DBrown@spi-ind.com ]
Sent: Thursday, August 01, 2013 8:37 AM
To: Rios, Gerardo Subject: SPI meeting next tuesday (6th) at 2:30

Gerardo

–

For the meeting next week, we’ll have myself, George Emmerson (Owner), and William Sloan (Morrison & Forster

– counsel) for the meeting. There’s a potential we may bring David Branchcomb, our PGE contracts person. I’ll also have

Eric Albright of Environ on standby via phone is we need to dial him in... at this point and thinking not and may have a separate call with just him and technical staff if need be.

Will see you at 2:30 at your offices.

David C. Brown, PE Environmental Affairs & Compliance Manager Sierra Pacific Industries
19794 Riverside Avenue Redding, CA 96049-6028 (530) 378-8179 (530) 378-8139 fax (530) 391-7650 cell

CONFIDENTIALITY STATEMENT: This communication and any accompanying or attached document(s) are confidential and privileged. The y are intended for the sole use of the addressee(s). If you receive this communication in error, you are advised that any use, disclosure, copying, di stribution or taking any action in reliance upon this communication is strictly prohibited. If you received this message in error, please immediately telephone Si erra Pacific Industries at (530) 378- 8179, and delete this message without copying it. Thank you.

## DRAFT

1 Additional Information EPA Will Need from Sierra Pacific Indus tries-Anderson Division to Proceed with a voluntary GHG PSD Permit

E MISSION 

### E STIMATES



### 1. In addition to the information provided in Table 2- 1 in the Sierra Pacific Industries’s (SPI) June
2011 Best Available Control Technology (BAC T) analysis for greenhouse gas (GHG)
emissions :

a. GHG emission estimates and calculations (and assu mptions used in these calculations) for
each of the new and modified emission units (e.g., biomass boiler, emergency engine, circuit breakers,etc) for (1) maximum wo rst case annual emission estimates of GHG pollutants (i.e., CO 2 

### e, CO 2 

### , N 2 

### O, CH 4 

### , SF 6 

### ,etc) expected from the emission units in tons per year (tpy); Revised and expanded Table 2-1

b. Emission estimates of GHG pollutants expect ed during startup peri ods, shutdown periods, and normal operation expected from the emission units in tpy; and Added explanatory text

c. Emission estimates of GHG pollutants for ex isting equipment at the facility in tpy. Added
Table 2-2

GHG BACT A NALYSIS



### 1. An assessment of the use of stoker and fluidized bed boiler in the design of the cogeneration unit for minimizing GHG emissions. For your in formation, EPA’s combined heat and power (CHP) website has information on biomass conve rsion technologies, and includes information on stoker and fluidized bed boilers that may be useful. 1 

### Added explanatory text

2. A GHG assessment of any new circuit breakers that potentially emit SF 6 

### in the GHG BACT analysis. Added explanatory text; existi ng circuit breakers will rema in and be used by proposed cogeneration unit, therefor e, no evaluation is needed

3. A GHG assessment of the proposed natural gas-fired 256 horsepower emergency engine. Added
section 8

4. An assessment that considers GHG BACT determin ations made for other biomass boiler units. We are aware of the following projects in Tabl e 1 that have been eval uated and issued final permits with GHG emission and operational limits. Obtained and reviewed permit materials for all facilities in table below, adde d text briefly summarizing findings

1 

### See the section titled “ Biomass CHP Catalog of Technologies” at http://www.epa.gov/chp/technologies.html

.

## DRAFT

2 Table 1: Recent Permit Decisions containing GHG Determinations Facility State Permit Issuance Date

Montville Power LLC CT 4/6/2010 Beaver Wood Energy Fair Haven LLC VT 2/10/2012 North Springfield Sustainable Energy Project VT 4/19/2013 WE Energies (Rothschild facility) WI 3/28/2011 Abengoa Bioenergy Biomass of Kans as LLC KS 9/16/2011 (Effective date)

5. An evaluation of the technical feasibility of using carbon adsorption in Section 4. Section 3.2 identifies carbon adsorption as a potentia l control technology for minimizing methane
emissions. Added clarifying text

6. An evaluation of the technical basis that explains why thermal oxidation is not technical feasible for the boiler. Section 4.2, under Thermal De struction, eliminates thermal oxidation as technically infeasible for control of methane from the boiler because “it is not clear that use of such system would result in a net reduction in methane.” Added clarifying text

7. An evaluation of the technical basis that explai ns why non-selective cata lytic reduction (NSCR) is not feasible for the boiler. Section 4.3, under Non-Selective Catalytic Reduction Systems, eliminates NSCR as technically infeasible for co ntrol of nitrous oxide from the boiler because “significant differences exist between the exhaust from adipic and nitric acid operations and that of a biomass-fired boiler, it is no t clear that the technology could be transferred effectively.” It would be helpful if SPI would explain these differences. Removed text to jibe with determination that NSCR was not technically feasible, also added clarifying text

8. Emission calculations (and assumptions used) for the estimates of “percent reduction in emitted
GHGs on a CO 2 

### e basis” in section 5 of the analysis. This is currently not provided in the analysis. Added references and reduction calculations

9. Cost calculations (and assumptions used) for th e estimates of “percent reduction in emitted
GHGs on a CO 2 

### e basis” in section 6 of the analysis. This is currently not provided in the analysis. Biomass Fuel Use – no cost calculation needed; CCS – referenced cost calculation from NETL document; Catalytic Destruction – ca lculated cost threshold from calculated potential reduction and value of CO 2 

### e reduction; Removal of SNCR System – unacceptable from environmental standpoint, so no cost calculation needed; Pr oper Combustion/Energy Efficiency – no cost calculation needed

10. A proposed annual CO 2 

### e emission limit in tpy for the proposed project. Proposed GHG BACT limit (annual tpy) providedF I N A L



## Biomass

- Fired Cogeneration Project: Best Available Control Technology Analysis for Greenhouse Gases

Sierra Pacific Industries Lumber Manufacturing Facility

Anderson, California

Prepared for: Sierra Pacific Industries, Inc.

Redding , California

Prepared by: ENVIRON International Corporation

Lynnwood

, Washington

Date: August 201 3

Project Number:
29

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## Contents

Page

1 Introduction 1

1.1 Project Information 1

1.2 BACT Analysis Process 2

1.2.1 Step 1

– Id entify Available Control Technologies 3

1.2.2 Step 2

– Eliminate Technically Infeasible Control Technologies 4

1.2.3 Step 3

– Rank Remaining Control Technologies by Control Effectiveness 5

1.2.4 Step 4

– Evaluate Most Effective Controls and Document Results 5

1.2.5 Step 5

– Select BACT 6

1.3 Cost

- Effectiveness Analysis 7

1.3.1 Cost Methodology 7

1.3.2 Cost Criteria 7

2 Project Greenhouse Gas Emissions 11

3 Step 1

– Identify Available Control Alternative s 15

3.1 Carbon Dioxide 16

3.2 Methane 16

3.3 Nitrous Oxide 17

4 Step 2

– Eliminate Technically Infeasible Alternatives 19

4.1 Carbon Dioxide 19

4.2 Methane 20

4.3 Nitrous Oxide 21

5 Step 3

– Rank Technically Feasible Alternatives 23

6 Step 4

– Evaluate Economic, Energy, and Environmental Impacts 27

7 Step 5

– Selection of BACT 29

8 Reciprocating Internal Combustion Engines 31

8.1 Step 1

– Identify Available Control Alternatives 31

8.2 Step 2

– Eliminate Te chnically Infeasible Alternatives 31

8.3 Step 3

– Rank Technically Feasible Alternatives 31

8.4 Step 4

– Evaluate Economic, Energy , and Environmental Impacts 32

8.5 Step 5

– Selection of BACT 32



### List of Tables

Table 2

- 1. Greenhouse Gas Emission Rate Calculations

– Proposed Equipment 11
Table 2

- 2. Greenhouse Gas Emission Rate Calculations

– Existing Equipment 13
Table 5

- 1 Catalytic Oxidation GHG Emission Reduction 25
Table 5

- 2 Removal of SNCR GHG Emission Reduction 25Sierra Pacific Industries

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## 1 Introduction

Sierra Pacific Industries, Inc. (SPI) owns and operates an existing lumber manufacturing facility located in Anderson, California , and proposes to construct and operate a cogeneration unit at that facility . The boiler associated with t he proposed cogeneration unit will be designed to burn biomass fuel to produce approximately 250,000 pou nds of steam per hour. SPI submitted a PSD permit application to USEPA Region 9 and Shasta County Air Quality Management District (SCAQMD) in March 201 0 that included BACT analyses for all criteria pollutants expected to increase by more than the PSD Significant Emission Rates (SERs), as well as pollutants exceeding the emission rate thresholds in SCAQMD Rule 2:1, Part 301

. SPI provided an initial
BACT Analysis for Greenhouse Gases in June 2011. This report in intended to replace the June 2011 report and supplement th e PSD permit application by providing a n updated B ACT analysis for GHG emissions from the biomass

- fired cogeneration unit.

On May 13, 2010

, USEPA issued the final “Tailoring R ule ” with a stated intent to establish a

“ common sense approach ” to addressing greenhouse gas emissions from stationary sources, by “tailoring” the major source applicability thresholds under the PSD and Title V air ope rating permit programs. The first step of the Tailoring Rule, which began on January 2, 2011, and
last s until June 30, 2011, requires sources already subject to the PSD p ermitting programs to
meet that program ’s permitting requirements for greenhouse gase s. New sources or modifications of existing sources expected to increase total greenhouse gas emission rates by 75,000 tpy or more, on a carbon dioxide equivalent ( CO 2 e ) basis, and whose emissions exceed
the PSD threshold for one or more criteria pollutan ts, are subject to PSD review for GHGs

.

The second step of the rule, which starts on July 1, 2011, and lasts until June 30, 2013, casts a
wider net than the first. New construction projects expected emit at least 100,000 tpy of total greenhouse gases on a CO 2 e basis, or modifications at existing facilities that are expected to increase total greenhouse gas emissions by at least 75,000 tpy CO 2 e will be subject to PSD permitting requirements, even if they do not significantly increase emissions of any other pollutant. Because the proposed biomass

- fired cogeneration unit is expected to emit GHGs at a rate greater than 75,000 tpy CO2e, the project is subject to PSD review for GHGs. Because there are no ambient standards or increments for GHGs, the only PSD re quirement that applies to GHGs is that Best Available Control Technology (BACT) must be employed to reduce GHG emissions from the proposed unit.



### 1.1 Project Information
SPI is a family

- owned wood

- products company based in Redding, California. SPI currently

op erates an existing lumber manufacturing facility in Anderson, California. SPI intends to construct a new cogeneration unit at the Anderson facility that would burn biomass fuels in a boiler to produce steam that would be used to generate electricity and t o heat existing lumber dry kilns at the facility.

The cogeneration unit will consist of a biomass

- fired water tube boiler with a step grate and
dual

- chamber pyrolysis and combustion system

, a cooling tower, a steam turbine, and a n electrical generator. T he boiler will burn biomass fuels to produce high

- pressure steam for the
steam turbine. The steam turbine will drive the electrical generator , which will be capable ofSierra Pacific Industries

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- 23586A generating up to 31 megawatts (MW) of electricity, a pproximately 7 MW of which will be used to

power on

- site equipment; the remainder will be sold to a public utility. Low

- press ure steam will
be taken from the steam turbine through a controlled extraction and used to heat the dry kilns.



### 1.2 BACT Analysis Process
BACT is defined at 40 CFR 52.21( b)(12) as:

an emissions limitation (including a visible emission standard) based on the maximum degree of reduction for each pollutant subject to regulation under the Clean Air Act which would be emitted from any proposed major stationary source or major modification 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 or modification through application of production processes or availab le methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of such pollutant. In no event shall application of best available control technology result in emissions of any pollutant which would exceed the emissions allowed by any applicable standard under 40 CFR Parts 60 and 61. If the Administrator determines that technological or economic limitations on the application of measurement methodology to a particular emissions unit would make the imposition of an emissions standard infeasible, a design, equipment, work practice, operational standard, or combination thereof, may be prescribed instead to satisfy the requirement for the application of best available control technology.
Such stand

ard shall, to the degree possible, set forth the emissions reduction achievable by implementation of such design, equipment, work practice or operation, and shall provide for compliance by means which achieve equivalent
results.

The process for conducting BACT analyses for criteria pollutants is relatively well established
because it has been implemented for decades. A lthough there is a wide range of control s and
associated costs that could be considered for criter ia air pollutants, permit

- issuing agencies
have an under standing of which emission control options are appropriate and cost effective. In contrast, BACT analyses , BACT determinations, and cost

- effectivene ss criteria for GHGs are virtually non

- existent.

In November 2010, US EPA issued guidance fo r conducting BACT analyses for GHG s (hereafter
referred to as “the November 2010 G uidance”). US EPA recommended (but did not require) that permitting agencies apply to GHGs the same “top down” process applied to determine criteria pollutant BACT. In this process, potentially available control technologies are identified and evaluated for application to the proposed project. Feasible options are ranked in descending order of control effectiveness. The most stringent alternative is examined and is establish ed as BACT unless the applicant demonstrates and the permitting authority agrees that energy, environmental or economic impacts justify a conclusion that the most stringent technology is not achievable. In that case the next stringent alte rnative is consid ered. The top

- down analysis process is comprised of the following steps:August 201 3 Sierra Pacific Industries

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- 23586A 3  Step 1

– Identify Available Control T echnologies. Identify all available control techniques that could potentially be applied to control emissions of the regulated pollutants from t he
emission units.

 Step 2

– Eliminat e Technically Infeasible Alternatives . If any of the control techniques cannot be successfully used on the emission units due to technical difficulties, document this finding. Such control techniques would not be cons idered further in the BACT analysis.

 Step 3

– Rank Technically Feasible Alternatives . Assess the performance of each control technique and rank them beginning with the most effective control technique.

 Step 4

– Evaluate Economic, Energy, and Environmental Impacts. Estimate emission reductions, annual costs, cost effectiveness, energy impacts, and other environmental impacts of the controls techniques. Detailed cost effectiveness information is presented
for the most effective control and for other contro l techniques that are in the least cost envelope.

 Step 5

– Sele ct BACT. Identify the most effective option not rejected based on energy, environmental, and economic impacts.

Each step is discussed further in the sections that follow.



### 1.2.1 Step 1

– Identify Ava ilable Control Technologies
The first step in the top

- down procedure is to identify all available control technologies and emission reduction options for each subject pollutant. Available control technologies are those with a practical potential for appli cation to the emission unit. For criteria pollutants, applicants typically identify appropriate control technologies by reviewing the following sources of
information:

 USEPA RACT/BACT/LAER Clearinghouse (RBLC)

 USEPA Control Technology Center (CTC)

 Recent Permit A ctions by other State and Local Agencies , and

 Vendor Information

Because BACT for GHG s is a new requirement, there are few BACT preceden ts, let alone precedents for a biomass

- fired cogeneration unit . In preparing this BACT analysis, ENVIRON
revie wed B ACT analyses for combined cyc le power plant s ( e.g., Russell Energy Center, Avenal Energy Power Plant, and CPV Vaca Station Power Plant ), a proposed combination refinery and integrated gasification combined cycle (IGCC) facility in South Dakota (Hyperi on Ener gy Center), and several recent biomass

- fired electric generation and cogeneration facilit ies ( e.g., Mon t ville Power, We Energies/ Domtar Biomass Energy Project , Abengoa Bioenergy Biomass, Beaver Wood Energy, and North Springfield Sustainable Energy )

. The b iomass

- fired projects
all indicated that BACT for GHGs is good boiler design , good combustion practices , and efficient operation.Sierra Pacific Industries

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- 23586A Consistent with these precedents and EPA’s November 2010 G uidance, this analysis
demonstrates that the design of the proposed biomass

- fired cogeneration unit will achieve a very high degree of energy efficiency. In BACT parlance, this is considered “lower

- polluting

process es/practices” as opposed to post

- combustion or “end

- of

- stack ” controls. Given the
limited technolo gical options available for end

- of

- stack GHG emission controls, EPA’s initial

BA CT guidance emphasizes energy efficiency. In addition to reducing GHG emissions, energy efficiency also minimizes criteri a and toxic air pollutant emissions

.

A control techn ology must be “available” to be considered BACT. According to EPA’s draft
1990 NSR manual “‘[a]vailable’ means that the method’s systems and techniques are commercially available. ” BACT also does not require the applicant to participate in a research
and development project to determine if a technology is “available” for a particular use.

Theoretical, experimental or developing technologies are not “available” under BACT. Technologies with questionable or dubious reliability are likewise not considered " available" under BACT, and the applicant is not required to use them. BACT does not require an applicant to speculate as to whether an undemonstrated technology will effectively control the pollutant in question from the proposed source. Applicants are n ot required to accept the risk that a theoretically feasible, but unproven , technology will effectively and economically reduce
emissions from the proposed source.



### 1.2.2 Step 2

– Eliminate Technically Infeasible Control Technologies
The second step in performing the top

- down BACT analysis is to eliminate all technically infeasible options. The determination that a control technology is technically infeasible is

source

- specific and based upon physical, chemical, and engineering principles. Technical feasibility is addressed in EPA’s November 2010 G uidance:

EPA considers a technology to be technically feasible if it has been demonstrated in practice or is available and applicable to the source type under review. The term “demonstrated” is focused on the technology being used in the same type of source, such as a similar plant producing the same product. Therefore, EPA considers a technology to be “demonstrated,” if it has been installed and operated successfully on t he type of source at issue.

Prior guidance and ju dicial decisions confirm that "feasible technology" means design or equipment that has progressed beyond the conceptual and pilot testing phases, is commercially available, and has been demonstrated on a full

- scale emission unit of the type of that is the subject of the BACT analysis

, for a period of time sufficient to indicate reliable operation . These criteria are especially important for GHG BACT analyses due to the unproven nature of many
GHG control schemes.

“D emonstrated in practice ” is a n other impor tant concept that addresses the question of whether a technology should be considered available. In its New Source Review Improvement Rule (issued November 22, 2002) , EPA included a definition of “demonstra ted in practice

. ” This definition prescribes whi ch technologies must be considered in BACT and LAER determinations by defining the information that must be reviewed to identify candidate technologies, the amountAugust 201 3 Sierra Pacific Industries

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- 23586A 5 of time the technology must be in use, and its performance during that time. A technology

i nstalled and operating on an emissions unit (or units) must meet the following criteria to be
considered “demonstra ted in practice:”

 Has operated at a minimum of 50 percent of design capacity for at least 6 months; and

 The pollution control efficiency perf ormance has been verified by either :
1) a performance test , or
2) performance data collected at the maximum design capacity of the emissions unit (or units) being controlled, or 90 percent or more of the control technology's designed specifications.

Althou gh this definition of “ demonstrated in practice ” does not have any regulatory standing in the analysis presented in this report, it does provide some useful guidance for evaluating whether certain technologies are “ available ,” and therefore worthy of consi deration as BACT.



### 1.2.3 Step 3

– Rank Remaining Control Technologies by Control Effectiveness
The third step in the top

- down BACT analysis is to rank all remaining control technologies with respect to control effectiveness (i.e., by emission limit or removal ef ficiency, as applicable). The emission limit or removal efficiency used in the ranking process is that which the technology has demonstrated can be achieved consistently under reasonably foreseeable worst

- case conditions with an adequat e margin of safety. A limit or removal efficiency that can be achieved only occasionally under best

- case circumstances is not to be considered

.

For GHGs, control options are ranked based on total CO 2 e rather than the total mass or mass of
individual GHGs

.



### 1.2.4 Step 4

– Evaluate Most Effective Controls and Document Results
In this step, an analysis is performed on each remaining control technology to determine whether the energy, economic

, or environmental impacts from a given technology outwe igh their
benefits. Factors such as c ontrol efficiency, anticipated emission rate, expected emissions reduction, and economic, environmental

, and energy impacts

, are to be considered.

If the top

- ranked technology is chosen

, and there are no significant or unusual environmental impacts associa ted with that technology that have the potential to affect its selection, the BACT analysis is complete

, and no further analysis is required. However, if the chosen technology is
not the top

- ranked option , the economic, environmental, and energy impacts o f the chosen technology, and each more

- effective technology, must be evaluated and compared to justify application of the selected technology.

In performing economic analyses, USEPA’s Air Pollution Control Cost Manual, published in January 2002 (EPA/452/B

- 02

- 001) provides capital and annual operating cost factors that can be used in determining the installation and operating costs of each control technology. Actual vendor installation and operation costs were used where applicable.Sierra Pacific Industries

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- 23586A C ost

- effectiveness ev aluations for greenhouse gases are to be conducted based on reductions
in CO 2 e. H owever
, a s ackno wledged by EPA in its November 2010 G uidance

, no cost
effectiveness criteria have been established for GHGs. Furthermore, there are no means by
which to eval uate the environmental impacts of GHG emissions at the stationary source level. Consequently, comparisons of environme ntal impacts associated with GHG emissi ons with
those of collateral criteria pollutant emissions are not possible.



### 1.2.5 Step 5

– Select BACT

T he fin al step is selection of the most stringent and technically feasible emission limit and corresponding technology that was not eliminated based upon adverse economic, environmental, and e nergy impacts. EPA’s November 2010 G uidance notes that a GHG per mit may limit CO 2 e based on a mass emission rate (lb/hr) or other metrics. EPA also notes that “since the environmental concern with greenhouse gases is with their cumulative impact in the environment, metrics should focus on longer

- term averages (e.g., 3 0

- or 365

- day rolling average) rather than short

- term averages (e.g., 3

- or 24

- hr rolling average).”

Although this process might appear to be tightly prescribed, 20 years of experience with the top

down BACT analysis process has resulted in a number of age ncy and judicial decisions that
have served to guide subsequent BACT determinations:

 BACT d eterm inations are made “on a case

- by

- case basis,” taking into account site

- specific
and source

- specific characteristics. These characteristics may include, among ot her things, the type of fuel or raw materials that will be used, and the type and size of the emissions unit. A high degree of technical judgment must be exercised in any BACT analysis as there are various sizes and ages of the emissions units covered by an analysis.

 BACT must be a chievable

. The Environmental Appeals Board (EAB) has recently sta ted that, while BACT is forward

- looking, “the word ‘achievable’...constrains the permit issuer’s discretion by prohibiting BACT limits that would require pollution reductions greater than what can be achieved with available methods.” The EAB concluded that “the permit issuer may take into account the absence of long

- term data, or the unproven long

- term effectiveness of the technology, in setting the emissions limit ation that is BACT for the facility.” The EAB further stated that the BACT analysis “must be solidly grounded on what is presently known about the selected technology’s effectiveness

, ” and that “emissions limitations achieved by other facilities

, and corr esponding control technologies used at other facilities are an important source of information in determining” BACT.

EPA’s November 2010 G uidance affirms that vendor confidence in emission control efficiency
should be considered: “[t] he willingness of v endors to guarantee a certain level of performance should be considered by the permitting authority later in the BACT process when proposing a specific emissions limit or level of performance in the PSD permit.”

Finally, the chosen BACT emission limit mus t not be less stringent than any applicable federal NSPS, NESHAP, or stat e

- specific emission standard. It should be noted, h owever, that thereAugust 201 3 Sierra Pacific Industries

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- 23586A 7 are no federal NSPS, NESHAP, or California State GHG emission standards that apply to
biomass

- fired cogeneration units

.



### 1.3 Cost

- Effectiveness Analysis
In Step 4 of the top

- down BACT analysis process, cost effectiveness is used to assess the economic impact of emission reduction alternatives. The cost effectiveness of a control option is defined as dollars per ton ($/ ton) of pollutant removed or avoided when compared with some baseline (usually the uncontrolled emission rate), and is calculated as follows:

In cases where more than one control option is being considered, an incremental cost
effectiveness is often calc ulated, as follows, to determine the cost per ton of the additional quantity of pollutant reduced at some additional expense:



### 1.3.1 Cost Methodology

T he total annual ized cost of each control is calculated as follows:

i) Total Annual Costs = Annual ized Capital Costs + Annual Operations &
Maintenance Costs

ii) Annualized Capital Costs = Capital Recovery Factor x Total Direct and Indirect Capital Costs

Where:

Cap ital Recovery Factor (CRF) =

and, assuming:

Life of Equipment, n = 20 years

Annual Interest Rate, i = 7%

CRF = 0.094393



### 1.3.2 Cost C riteria
Step 4 of the BACT process addresses economic, energy, and environmental impacts associated with feasible control options. The economic evaluation enables an applicant an opportunity to demonstrate that the costs of poll utant removal for a particular control option are disproportionately high. However, EPA’s November 2010 G uidance acknowledges “there is not a wealth of GHG cost effectiveness data from prior permitting actions for a permitting authority to review and rely upon when determining what cost level is considered acceptable for GHGSierra Pacific Industries

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- 23586A BACT.” EPA also acknowledges that cost effectiveness criteria historically applied to criteria pollutant emissions are not appropriate for greenhouse gases because greenhouse gas
emis sions tend to be orders of magnitude greater than criteria pollutant emissions. In fact, we find that at this early stage of greenhouse gas BACT review, there is virtually no information that enables applicants or reviewing agencies to determine whether a control option is cost effective.

An Interim Repo rt issued in February 2010 by the Climate Change Work G roup of the Permits, New Source Review and Toxics Subcommittee to the EPA’s Clean Air Act Advisory Committee,
which includes industry, environmental, a nd regulatory groups

, provided no consensus on greenhouse gas cost effectiveness, with values ranging from $3 per ton to $150 per ton. Some
members supported not setting fixed cost effectiveness threshold s
, and recommended that EPA provide guidance to per mitting authorities on the range of cost effectiveness values based on
the status of various control technologies.

An obvious source of carbon cost information is the value of carbon allowance s or offset s

. Analogous to EPA’s acid rain program, an allowanc e is a n authorization under a regulatory program to emit a certain quantity of carbon. However, a carbon offset is an emission reduction established outside of a regulatory program, and may or may not be recognized by a regulatory

program.

The Regional Greenhouse Gas Initiative (RGGI, http://www.rggi.org) is the first mandatory,
market

- based effort in the United States to reduce greenhouse gas emissions. Ten
Northeastern and Mid

- Atlantic states have implemented a CO 2 cap, effective until 2014, after
whic h the cap will be reduce d by 2.5 percent each year until a total reduction of 10 percent is achieved by 2018. States sell nearly all emission allowances through auctions and invest the proceeds in consumer benefits such as energy efficiency, renewable ene rgy, and other clean energy technologies.

At a RGGI auction held March 9 , 2 011, allowances averaged $1.89 per ton of CO 2 . “Future”
allowance s also averaged $1.89 per ton , implying that the value of CO 2 allowances is no t expected to change significantly in the near future. Eighty

- five percent of the allowances
available at the auction were purchased by electric utilities and affiliates

.

RGGI

- participating states currently allow regulated power plants to use a carefully

- chosen group of qualifying offsets to meet up to 3.3 percent of their CO 2 compliance obligation. Examples of
offset

- eligible project categories include those that capture or destroy methane from landfills or through agricultural manure management operations.

Similar in nature to RGGI allo w ances, European Union Allowance units (EUAs) are sold in Europe as a mechanism for achieving an EU objective of a 20 percent reduction in carbon
emissions by 2020 (compared to 1990 levels) . The price of an EUA in April 2011 was approximately 16 euros (eq uivalent to about $23) per metric tonne.

The Chicago Climate Exchange (CCX) wa s a voluntary, legally binding, GHG reduction and trading system until it closed in November 2010. At that time, the price of carbon credits (whichAugust 201 3 Sierra Pacific Industries

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- 23586A 9 had not traded on the CCX s ince February 2010) ranged between $0.05 and $0.10 per metric

tonne of CO 2 e

.

When developing the GHG Tailoring Rule , EPA used scaling to derive a Significant Emission Rate for greenhouse gases from the Significant Emission Rates for criteria pollutants. Applying a similar rationale, one could derive a greenhouse gas cost effectiveness criterion by scaling
CO 2 emissions from CO emissions. Using a relatively conservative cost effectiveness criterion of $10,000/ton , and emission factors for external natural gas combustion from EPA’s AP

- 42 emission factor database ( 84 and 120,000 lb/scf for CO and CO 2 , respectively), a comparable

cost

- effectiveness criterion for CO 2 would be $7/ton ( i.e., $10/000 x 84 / 120,000 ).

In October 2010, Hyperion Energy Center (a p roposed combination oil refinery and integrated gasification combined

- cycle power plant) submitted a greenhouse gas BACT analysis to South Dakota Department of Environment and Natural Resources in support of a renewal of a previ ously issued PSD permit that calculated the cost effectiveness of implementing Carbon Capture and Storage (CCS) on a CO 2 vent, refinery process heaters, and combined cycle gas
turbines. The calculated c ost effectiveness of the various control options ranged from $43 to $124 per ton of CO 2 e. Absent any established cost effectiveness criteria, the Hyperion BACT analysis cited the Chicago Climate Exchange offset price s (less than $1 per ton at the time) and the EU allowance prices ($12 per ton ne at the time ) and concluded that CCS was not cost effective. South Dakota has not yet renewed the PSD pe rmit for the Hyperion facility, and a contested case hearing is scheduled for July 25, 2011.

We Energies provided a GHG BACT analysis in support of a permit application submitted to
Wisconsin Department of Natural Resources proposing to install and operate a biomass

- fired boiler. The GHG BACT analysis included cost

- effectiveness calculations for systems to control methane ( CH 4 ) and nitrous oxide ( N 2 O ), but did not provide any cost

- effectivenes s criteria for comparison.

Lacking specific guidance from EPA or local agencies, and weighting several sources that imply values less than $2/ton against an EU Allowance of $23/tonne, SPI proposes a GHG cost

effectiveness threshold of $7/ton

, derived by sc aling the commonly

- accepted cost

- effectiveness threshold for criteria pollutants ( $10,000/ t on ) using natural gas combustion emission factors.Sierra Pacific Industries

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## 2 Project Greenhouse Gas Emissions

The Tailoring Rule defined GHGs as an a ggregate of: carbon dioxide ( CO 2 ), methane ( CH 4 ), nitrous oxide ( N 2 O ), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF 6 ). The proposed project has the potential to emit only three of these: CO 2 , CH 4 , and N 2 O . All GHG emi ssions associated with the project will be generated by the cogeneration unit; the cooling tower will not emit any GHGs. The Tailoring Rule further defined CO2e as the sum of the mass emissions of the constituent GHG, each multiplied by the appropriate gl obal warming potential (GWP) factor provided in Table A

- 1 of the Federal Mandatory GHG Reporting Rule (MRR, codified in 40 CFR Part 98).

The proposed cogeneration unit is assumed to have a maximum annu al average heat input of

4 68 million British ther mal units per hour (MMBtu/hr). A natural

- gas

- fired emergency feedwater pump used to circulate water through the cogeneration unit boiler in case of an emergency shutdown while disconnected from the grid, will have a maximum heat input of 2.16 MMBtu/hr,
and wi ll be operated, for maintenance and testing purposes, a maximum of 100 hours per year.
Table 2

- 1 summarizes the calculations and shows that the proposed project has the potential to generate a maximum of approximately 4 33,000 tons of CO 2 e per year.

Tabl e 2

- 1. Greenhouse Gas Emission Rate Calculations

– Proposed Equipment

Emission Unit GHG Emission Factor (Heat Input) 1 Global Warming Potential 2 Emission Rate 3

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

Cogeneration
Unit CO 2 93.8 207 1 96,800 424,000

CH 4 3 .20E

- 02 0.0705 21 3 3 .0 1 45

N 2 O 4.20E

- 03 0.00926 310 4.3 3 1 9.0

CO 2 e

-- -- -- 9 8,8 00 43 3, 000

Gas

- Fired Emergency
Feedwater Pump CO 2 53.02 116.9 1 253 12.6

CH 4 0.001 0.0022 21 0.00476 0.000238

N 2 O 0.0001 0.00022 310 0.000476 0.0000238
CO 2 e

-- -- -- 253 12.6

Total CO 2 -- -- 1 97,000 424,000

CH 4 -- -- 21 33.0 145

N 2 O

-- -- 310 4.33 19.0
CO 2 e

-- -- -- 99,100 433,000

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

from 40 CFR Par t 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

. 2 100

- year time horizon global warming potential (GWP

– from 40 CFR Part 98, Table A

- 1.

3 C alculated by multiplying the emission factor by the maximum annual average heat input (4 68 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 e mergency pump engine. CO 2 e was calculated by
multiplying each individual emission rate by the applicable GWP factor, and summing.

While the vast majority of emissions will be from combustion of wood and wood

- residual solid
biomass fuel

, t he proposed unit will 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.Sierra Pacific Industries

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- 23586A Operation of the natural gas burners will not exceed 10 percent of the annual heat input capacity o f the boiler, or 409,934 MMBtu/yr (468 MMBtu/hr * 8.760 hr/yr * 10%). Based on that maximum annual heat input and the CO 2 e emission factor for natural gas combustion from 40 CFR Part 98 (117 lb/MMBtu), the maximum GHG emisisons from the natural gas burners will be 23,981 tpy. It should be noted that the CO 2 e emission factor for natural gas combustion is less
than the CO 2 e emission factor for biomass fuel, so any displacement of biomass fuel by natural gas combustion would reduce the maximum annual GHG emiss ion potential of the unit.

The proposed cogene r a t ion unit will be started and shutdown as infrequently as possible. There is typically at least one outage period each year for maintenance; any additional shutdown

- and

startup cycles will be the result of a n unscheduled event. It takes approximately 12 hours to start the cogeneration unit; natural gas burners are used to heat the refractory for the first

6 hours, and then biomass fuel is phased in, which the gas firing is phased out over the final

6 hours. Shutdown takes approximately 1 hour to accomplish, and the natural gas burners are used only if elevated carbon monoxide (CO) levels are indicated by the continuous emissions monitoring system (CEMS). Based on the startup protocol outlined above, the GHG emission rate during startup is estimated to be approximately 60 percent of that during normal operations.
Increases in CH 4 and N 2 O emissions during startup and shutdown because of reduced furnace temperatures are expected to be minimized by the use of th e natural gas burners.

The facility currently 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 ex isting boiler will not be used concurrent with the proposed cogeneration unit, but the existing switchgear will continue to be used by the new unit, unchanged from its current configuration. Table 2

- 2 summarizes the GHG emission rate
calculations for the exist ing equipment at the facility.August 201 3 Sierra Pacific Industries

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- 23586A 13 Table 2

- 2 . Greenhouse Gas Emission Rate Calculations

– Existing Equipment

Emission Unit GHG Emission Factor (Heat Input) 1 Global Warming Potential 2 Emission Rate 3

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

Biomass

F ired
Boiler CO 2 93.8 207 1 24,100 105,000

CH 4 3.20E

- 02 0.0705 21 8.21 36.0

N 2 O 4.20E

- 03 0.00926 310 1.08 4.72
CO 2 e

-- -- -- 24,600 108,000

Switchgear SF 6 1% leakage/year 23,900 0.000217 0.000950

CO 2 e

-- -- -- 5.18 22.7

Total CO 2 -- -- 1 24,100 10 5,000

CH 4 -- -- 21 8.21 36.0

N 2 O

-- -- 310 1.08 4.72
SF 6 -- -- 23,900 0.000217 0.000950
CO 2 e

-- -- -- 24,600 108,000

1 The kg/MMBtu emission factors for combustion of wood and wood residual solid biomass fuel are from 40 CFR
Part 98, Tables C

- 1 a nd C

- 2; the lb/MMBtu emission factors are calculated by converting the kg/MMBtu emission

factors using 2.2046 lb/kg

. 2 100

- year time horizon global warming potential (GWP

– from 40 CFR Part 98, Table A

- 1.

3 The hourly emission rate for the existing bioma ss

- fired boiler was c alculated 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 c apacity 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 throughpu t the year.

CO 2 e was calculated by multiplying each individual emission rate by the applicable GWP factor, and summing.Sierra Pacific Industries

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## 3 Step 1

– Identify Available Control Alternatives

The first step of a top

- down BACT analysis is to identify all available pollutant reduction options. Options typically fall into three categories: inherently low

- emitting processes, clean fuels, and
add

- on control technologies. While step 1 is intended to include all possibilities, there are lim its to the scope of the first two option categories (i.e., inherently low

- emitting processes and clean fuels). The list of options in step 1 need not include those that fundamentally redefine the nature of the proposed source or modification.

Considerab le argument and litigation has been generated over what constitutes “redefinition of the source.” The most recent approach outlined by the Environmental Appeals Board (EAB) is contained in a 2009 ruling to remand a permit issued to Desert Rock Energy Co., LLC. In that ruling, which referred extensively to a previous ruling (Prairie State Generation Co., LLC), the EAB says that the reviewing agency should seek to answer the question: “ when does the imposition of control technology require enough of a rede sign of the proposed facility that it strays over the dividing line to become an impermissibl e redefinition of the source?”

In response to its own question, the EAB stated that “ the permit applicant initially defines the proposed facility’s end, object, ai m, or purpose

– that is the facility’s basic design, although the applicant’s definition must be for reasons independent of air permitting. ” Furthermore, the permit issuer should “take a ‘hard look’ at the application determination in order to discern whi ch design elements are inherent for the applicant’s pur pose and which design elements may be changed to achieve pollutant emissions reductions without disrupting the applicant’s basic business pur pose for the proposed facility, while keeping in mind that B ACT, in most cases, should not be applied to regulate the applicant’s purpose or objective for the proposed facility.”

In the November 2010 Guidance document, USEPA acknowledges that, although “clean fuels” are to be considered in step 1 of the BACT analys is, the initial list of control options does not need to include “clean fuel” options that that would fundamentally redefine the source. In this case, use of the biomass fuel generated by the existing facility is part of the original motivation for the pr oject. Clearly, substitution of any other fuel, lower

- carbon

- containing or otherwise, would drastically alter the overall goals of the proposed project.

Similarly, as discussed in a letter sent to US EPA Region 9 on January 23, 2012 by ENVIRON
on behalf of SPI, a stoker boiler design was chosen for the project because a fluidized bed design would not accommodate the manner in which the boiler will be operated (i. e., at less than 50 of maximum steam production capacity). There is evidence that fluidized b ed boiler designs are capable of achieving more thorough fuel combustion, and, therefore, higher efficiency. A USEPA information document estimates that fluidized bed boiler designs are capable of unburned fuel rates as low as 0.25 percent. 1 Teaford, the designer and
manufacturer of the boiler selected by SPI for the proposed cogeneration unit , estimates that their design can achieve an unburned fuel rate of approximately 1 percent. Even if a fluidized

1 USEPA, Combined Heat and Power Partnership. “Biomass Combined Heat and Power Catalog of Technologies.” September 2007.Sierra Pacific Industries

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- 23586A bed design was available that produced less unburnt fuel, and was, therefore, more efficient, it
could not deliver the operational flexibility required by SPI to meet the project’s intended business objectives , and would be rejected as a viable alternative

.



### 3.1 Carbon Dioxide
Carbon dioxide (CO 2 ) is a by

- produc t of complete combustion. Altering the combustion process
to reduce CO 2 emissions would increase emissions of “ traditional ” air pollutants such as carbon monoxide (CO) and volatile organic compounds (VOCs). Maximizing the heat transfer efficiency of the boiler and the mechanical efficiency of the steam tur bine and generator
minimizes the quantity of fuel combusted, and therefore the quantity of CO 2 generated, per unit of steam or electricity generated. Add

- on technologies that are able to remove, or “cap ture,”
CO 2 from the post

- combustion exhaust stream have been developed. Following capture, the
CO 2 would be transported and stored permanently, or “sequestered,” in a geologic formation. Such systems, referred to as “carbon capture and sequestration” (CC S), are not yet commercially available, and the U.S. Department of Energy does not expect them to be available until approximately 2025.

In March 2011, USEPA issued “Guidance for Determining Best Available Control Technology for Reducing Carbon Dioxide Emi ssions from Bioen ergy Production” (hereafter referred to as the “March 2011 Guidance”) which states that, if the proposed emission unit “can demonstrate that utilizing a particular type of biogenic fuel is fundamental to the primary purpose of the project, ” then “the options listed as Step 1 of a top

- down BACT analysis of GHGs may be limited to (1) utilization of biomass fuel alone, (2) energy efficiency improvements, and (3) carbon capture and sequestration.”



### 3.2 Methane
Like carbon monoxide (CO) and volatil e organic compounds ( VOC s), methane (CH 4 ) emissions are generally the result of incomplete fuel combustion. I n the case of biomass, volatile compounds (including CH 4 ) are released as the fuel is heated in the furnace, some portion of which escapes combust ion 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, and minimizes emissions of volatiles, including CH 4 . Add

- on contr ols used to

remove volatile compounds from gas streams include adsorption systems and thermal or catalytic oxidation systems. Adsorption systems pass the gas stream though canisters filled
with activated carbon or zeolite , and the volatile compounds are t rapped in pores located on the
carbon or zeolite particles. When the carbon approaches saturation, the canister is replaced and processed to remove the volatile compounds , which are recovered or destroyed. Oxidation systems increase the temperature of th e gas stream until the CH 4 oxidizes, forming CO 2 and water. Thermal oxidizers destroy volatile compounds using a flame, while catalytic oxidation uses a catalyst to promote oxidation reaction s at temperature s lower than th os e at which
combustion typically takes place

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### 3.3 Nitrous Oxide
Unlike nitric oxide (NO), whic h is the product of high combustion temperature s (greater than

730 ° C or 1,350 ° F) , nitrous oxide (N 2 O) is the result of lower combustion temperature s (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 . Typically, furnace conditions that favor CH 4 formation, also favor N 2 O formation.

Add

- on controls to reduce N 2 O emissions include: non

- selective catalytic reduction (NSCR), thermal destruction, and catalytic destruction. In the 1970s, NSCR systems were widely used to
control N 2 O (and oxides of nitrogen

– NO X ) emissions from adipic and nitric acid production operat ions, but high energy costs reduced the popularity of this approach. Currently, NSCR

sys tems have been used to reduce emissions from reciprocating engines operated in a rich

burn or stoichiometric mode

. In general, NSCR systems pass t he exhaust gas es ove r catalyst s, which use metals (e.g., platinum, rhodium, palladium) to convert NO X , CO, and VOCs to water, nitrogen, and carbon dioxide. Unburned hydrocarbons in the exhaust are used as a reducing agent to enable one catalyst to convert N 2 O and NO X , while CO and VOCs are oxidized by another catalyst . In cases where the option to consistently operate in a fuel

- rich or
stoichiometric mode to provide the reducing agent is not available, natural gas can be injected to act as the reducing agent.

Thermal destr uction of N 2 O is achieved using a reducing flame burner combusting premixed methane or natural gas. The flame temperature must be maintained high enough to destroy the
N 2 O , but below 1,500 ° C to minimize NO X formation. Catalytic destruction is accomplish ed at lower temperatures (400 to 700 ° C) using metal

- or zeolite

- based N 2 O

- decomposing catalysts

.

Conventional commercially

- available s elective 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 ( NO 2 )

, as well as selective non

- catalytic reduction (SNCR) systems, generate N 2 O, so removal of such control systems would reduce N 2 O emissions. However, at least two companies (BASF and Heraeu s) have developed catalyst s designed to simultaneously remove both N 2 O as well as NO and NO 2

.Sierra Pacific Industries

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## 4 Step 2

– Eliminate Technically Infeasible Alternatives

In the second step of a top

- down BACT analysis, the available polluta nt reduction options listed in Step 1 are considered, and, if found to be technically infeasible for the specific emission unit under review, eliminated.



### 4.1 Carbon Dioxide
In Step 1, use of biomass fuel, energy efficiency, and CCS were identified as potential control technologies.

Biomass Fuel

Combustion of biomass fuels, alone or in combination with other fuels, in boilers to generate

steam is a long

- standing practice. B iomass is one of the original boiler fuels , and it remains a
feasible and often

- used fu el.

Energy Efficiency

Maximizing the quantity of steam or electricity gener ated per unit of fuel combusted is the goal of most boiler designers and operators. Striving for energy effi ciency is technically feasible
within the limitations of the second law of thermodynamics. At maximum operation, the efficiency of the proposed boiler (i.e., the fraction of the energy in the fuel that is transfe rred to the steam) is expected to be approximately 70 percent. The efficiency of the electrical generator is, at f ull 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.

Carbon Capture and Seq uestration

In its findings and recommendations report, issued on January 24, 2011, the California Carbon Capture and Storage Review Panel concluded, among other things, that the technology “for the safe and effective capture, transport, and geological stor age of CO 2 from power plants and other large industrial facilities” currently exists. Therefore, CCS is considered to be technically
feasible.

There are three approaches to CO 2 capture that are generally applicable to power generation:

 Pre

- combustion syst ems designed to separate CO 2 and hydrogen (H 2 ) from produced

syngas,

 Post

- combustion systems designed to separate CO 2 from flue gas, and

 Oxy

- combustion that uses high

- purity oxygen (O 2 ) instead of air, which produces flue gas composed largely of CO 2

.

Of th ese, only post

- combustion systems will be considered for application to a biomass

- fired
boiler. Use of a pre

- combustion system would require a gasification unit to produce syngasSierra Pacific Industries

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- 23586A from the biomass fuel, which would amount to redefining the source. Oxy

- com bustion of biomass fuels is currently in the experimental phase, and is typically in the context of being co

fired with coal.



### 4.2 Methane
In Step 1, proper combustion, adsorption, thermal oxidation, and catalytic oxidation were identified as possible alternati ves for CH 4 reduction.

Proper Combustion

For boilers combusting biomass, proper combustion is a ubiquitous control technology used to reduce CO and hydrocarbon (including CH 4 ) emissions, therefore it is considered technically
feasible for control of CH 4 em issions.

Adsorption

Due to the large exhaust volume, and relatively low concentrations, adsorption systems are typically not used to capture volatile compounds from combustion unit exhaust streams. In addition, low

- molecular

- weight compounds like CH 4 are poorly adsorbed, and, therefore, removal efficiencies are typically less than 50 percent. Using adsorption technology to reduce
CH 4 emis s ions from a biomass

- fired boiler in not considered technically feasible.

Thermal Destruction

To thermally oxidize a po llutant 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 CH 4 in the exhaust, the oxidizer itself will

g enerate air pollutants, including NO X , CO, VOCs, and additional CH 4 . Because a thermal
oxidizer has never been used to reduce CH 4 emissions from a biomass

- fired boiler, would generate additional critiera pollutants, and may not result in a net reduction i n CH 4 emissions

, this technology is considered technically infeasible for reducing CH 4 emissions from a biomass

fired boiler.

Catalytic Destruction

When applied to boilers, the intent of a catalytic oxidation system is to reduce CO and, to a lesser extent, VOC and PM emissions. As discussed in the criteria pollutant BACT analysis submitted with the PSD permit application, while catalytic oxidation is not experimental, application to biomass

- fired boilers is uncommon and difficult. Regardless of whether th e catalyst is located upstream of 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. Nevertheless, application of a catalytic oxidation system to reduce CH 4 emissions from a biomass

- fired boiler is technically
feasible.August 201 3 Sierra Pacific Industries

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### 4.3 Nitrous Oxide
In Step 1, proper combustion, thermal destruction, catalytic destruction, NSCR, removal of SCR systems, and addition of N 2 O

- abating SCR systems were identified as possible alternatives for

N 2 O reduction.

Proper Combustion

For boilers combusting biomass, proper com bustion is a ubiquitous control technology used to reduce CO and hydrocarbon emissions, therefore it is considered technically feasible for control
of N 2 O emissions.

Thermal Destruction

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 N 2 O in the exhaust, the combustor itself will generate a certain quantity of air pollutants , including N 2 O . Because a thermal oxidizer has
never been used to reduce N 2 O emissions from a biomass

- fired boiler, and it is not clear that use of such a system would result in a net reducti on in N 2 O in the exhaust stream, this technology is considered not techni cally feasible for reducing N 2 O emissions from a biomass

fired boiler.

Catalytic Destruction

When applied to boilers, the intent of a catalytic oxidation system is to reduce CO and, to a lesser extent, VOC and PM emissions. As discussed in the c riteria pollutant BACT analysis submitted with the PSD permit application, while catalytic oxidation is not experimental, application to biomass

- fired boilers is uncommon and difficult. Regardless of whether the catalyst is located upstream of downstream of a particulate control device (e.g., an electrostatic precipitator), alkali compounds present in the exhaust gas deactivate the catalyst. To counteract the deactivation, large quantities of catalyst must be deployed and frequently replaced, resu lting in unpredictable boiler availability and control system costs. Nevertheless, application of a catalytic oxidation system to reduce N 2 O emissions from a biomass

- fired boiler is technically feasible.

Non

- Selective Catalytic Reduction Systems

NSCR systems have primarily been developed to reduce N 2 O emissions from adipic and nitric acid production operations , and, as facility designs improve, NSCR is being used less often in
favor of other alternatives . There are no instances of an NSCR system being applied to reduce
N 2 O emi ssions from a biomass

- fired boiler. Because significant differences (e.g., concentration
of N 2 O ) exist between the exhaust from adipic and nitric acid operations and that of a biomass

fired boiler, it is unlikely that the technology could be transferred effectively, and is therefore considered not technically feasible for control of N 2 O from biomass

- fired boilers.Sierra Pacific Industries

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- 23586A Removal of Selective Non

- Catalytic Reduction Systems

An SNCR system is proposed by SPI to reduce NO X emissions from the biomass

- f ired boiler. It is technically feasible to not install such a system.

Removal of Conventional Selective Catalytic Reduction Systems

SPI does not propose to install a conventional SCR system to reduce NO X emissions from the
biomass

- fired boiler. The crite ria pollutant BACT analysis provided with the PSD permit application indicated that SCR was technically feasible, but had a still

- unproven track record of reliable performance associated with biomass

- fired boilers. Since no SCR system is proposed
for inst allation on the biomass

- fired boiler, it is technically infeasible to not install such a system.

Addition of N 2 O

- Abating Selective Catalytic Reduction Systems

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

conv entional SCR systems were technically feasible for reducing NO X emissions from biomass

fired boiler; therefore, N 2 O

- abating SCR systems are also considered technically feasible.August 201 3 Sierra Pacific Industries

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## 5 Step 3

– Rank Technically Feasible Alternatives

In Step 3, the remaining alt ernatives that have not been removed from consideration due to
technical in feasi bility, are ranked, starting with the most effective. The November 2010
G uidance says that “to best reflect the impact on the environment, the ranking of control options
shoul d be based on the total CO 2 e rather than the total mass or mass for the individual GHGs. Before ranking all feasible control alternatives from the previous section are ranked together,
the effectiveness of each on a CO 2 e basis is discussed.

Proper Combus tion/Energy Efficiency

The proposed project would operate in a manner that minimizes emissions of all pollutants, and maximizes the energy derived from the f uel consumed. Thus, these measures , in combination,
are considered the baseline from which all oth er alternatives will be evaluated, and it is assumed that all other options would be applied in addition to these measures.

Biomass Fuel

The proposed boiler will be fired exclusively using biomass fuel, and SPI expects approximately 75 percent of that fuel to be comprised of sawmill residues from the Anderson 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. E fficiently combusting mill residues, in

- forest residues, and agricultural residues to generate steam and electricity results in less net GHG emissions (i.e.,
less CH 4 and N 2 O are generated) than if those same residues w ere allowed to decompose or be subject to open burning. In the March 2011 Guidance, EPA acknowledges that the combustion of lumber manufacturing residues to generate energy does not increase net atmospheric GHG

sto ck

.

Furthermore, SPI manages nearly 1.7 million acres of forest land in California using sustainable forestry practices, and most of the carbon in the wood harvested from those forest lands remains sequestered in produced lumber. SPI replants harvested areas within a year, and plants an average of 6 million seedlings each year. The combined effect of : (1) younger trees taking up more carbon than harvested mature trees, (2) the sequestration of carbon in produced lumber, and (3) the most

- effective conversion of residues to CO 2 by combustion in the proposed
boiler is that SPI’s operation s serve to reduce atmospheric CO 2 stocks.

Carbon Capture and Sequestration

A CCS system is comprised of three parts: (1) capturing the CO 2 , (2) transporting the CO 2 , and (3) permanently storing the CO 2

. The ef fectiveness of the system to reduce CO 2 emissions is determined by the removal rate of CO 2 from the flue gas, and degree to which the CO 2 is
retained while being transported and stored. Currently available technology can captureSierra Pacific Industries

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- 23586A approximately 90 percent o f the post

- combustion CO 2 in flue gas. 2 However, due to the considerable energy requirements for the capture and compression of the CO 2 , the electrical generating capacity of the proposed cogeneration unit would have to be increased by up to

40 percent. Although 90 percent of the additional CO 2 generated would also be captured, the

net CO 2 reduction would be reduced from 90 percent to 86 percent. 3

Transport of CO 2 by pipeline is a mature technology, and expected losses of CO 2 in a pipeline
would be minima l. Experimental o bservations and models suggest that properly selected and maintained geological storage sites could trap over 99 percent of injected CO 2 for at least 10 0, and up to 1 million, years.

A CCS system would not decrease the quantities of CH 4 a nd N 2 O in the exhaust ; in fact, the
increase in emissions of those GHG compounds as a result of th e additional capacity needed to

power the CCS systems would degrade the net GHG reduction . On a CO 2 e basis, CCS has the potential to reduce G HG emissions by approximately 83 percent.

Catalytic Destruction

Catalysts are a notoriously ineffective means of destroying CH 4 at typical exhaust temperatures (i.e., less than 45 0 ° C), and the low availability of oxygen in combustion exhaust would further degrade the eff ectiveness. At best, a 4 0 percent reduction in CH 4 emissions has been documented when applied to internal combustion engines. 4

When applied to exhaust from an adipic acid operation, catalytic destruction systems are effective, reducing N 2 O emissions by up to 95 percent. 5 Although it is unclear that the same
reduction s w ould be realized when similar catalysts are applied to a biomass

- fired boiler, the
stated level s of control will be assumed valid

. Catalysts would have no effect on CO 2 in the
exhaust. A s shown in Table 5

- 1, a pplying oxidation catalysts technology would result in a potential GHG emission reduction of, at most, 1. 6 percent on a CO 2 e basis.

2 National Energy Technology Laboratory (NETL), “Cost and Performance Baseline for Fossil Energy

Plants

– Volume 1: Bituminous Coal and Natural Gas to Electricity, Revision 2,” November 2010.

DOE/NETL

- 2010/1397. Page 18.

3 424,000 tpy CO 2 increased by 40 p ercent to account for the additional energy requirements of a CCS system is approximately 593,600 tpy CO 2 ; assuming 90 percent of the CO 2 is removed from the exhaust, results in an emission rate of approximately 59,360 tpy CO 2 . The net reduction in CO 2 em issions is 1

– (59,360 / 424,000) = 0.86.

4 Wark, K. and C.F. Warner, “Air Pollution: Its Origin and Control,” 2 nd Edition, Harper Collins Publishers, 1981. Page 333.

5 Intergovernmental Panel on Climate Change (IPCC), “Good Practice Guidance and Uncertai nty Management in National Greenhouse Gas Inventories,” 2000. Page 188.August 201 3 Sierra Pacific Industries

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- 23586A 25 Table 5

- 1 Catalytic Destruc tion GHG Emission Reduction

GHG Emission Rate

( tpy ) GWP Uncontrolled CO 2 e (tpy) % Control Controlled CO 2 e (tpy)
CO 2 424,000 1 424,000 0 424,000
CH 4 145 21 3,0 50 40 1,8 30

N 2 O 19 .0 310 5,890 95 295

Total

-- -- 43 3,000

-- 426,000

Net Control Efficiency (1

– Controlled CO 2 e / Uncontrolled CO 2 e ) 1

. 6 %

Removal of NO X Control Sys tem (SNCR)

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

. 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. Assuming the SNCR system accounts for all of the N 2 O generated by the boiler, and that removal of the SNCR system would reduce N 2 O emissions to zero, the reduction in GHG emissions would be 1.4 percent on a CO 2 e basis.

Table 5

- 2 Removal of SNCR GHG Emission Reduction

GHG Emission Rate

( tpy ) GWP Uncontrolled CO 2 e (tpy) % Control Controlled CO 2 e (tpy)
CO 2 424,000 1 424,000 0 424,000
CH 4 145 21 3,0 50 0 3,05 0

N 2 O 19 .0 310 5,890 100 0

Total

-- -- 43 3,000

-- 427 ,000

Net Contro l Efficiency (1

– Controlled CO 2 e / Uncontrolled CO 2 e ) 1

. 4 %

Ranking GHG Control Alternatives by Effectiveness

Below is a ranking of the technically feasible GHG control alternatives, starting with the most effective, on a CO 2 e basis:

 Biomass Fuel

– Net r eduction in atmospheric CO 2 stocks

 Carbon Capture and Sequestration

– 83 percent reduction in emitted GHGs on a CO 2 e basis

 Catalytic Destruction

– 1.4 percent reduction in emitted GHGs on a CO 2 e basis

 Removal of NO X Control System (SNCR)

– 1.4 percent redu ction in emitted GHGs on a
CO 2 e basis

 Proper Combustion/Energy Efficiency

– BaselineSierra Pacific Industries

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## 6 Step 4

– Evaluate Economic, Energy, and Environmental Impacts

In the March 201 0 Guidance, EPA suggests that, instead of the more traditional approach where the options are considered and either eliminated or adopted in order of effectiveness, the economic, energy, and environmental impacts of all options are considered. In light of this guidance, ea ch technically feasible option wa s evaluated , regardless of the Step 3 ranking.

Biomass Fuel

Over 75 percent of the fuel combusted in the proposed boiler is expected to be derived from residues generated by SPI’s primary business (i.e., harvesting logs and manufacturing lumber).
Use of t his fuel provides an economic benefit by allowing SPI to avoid the cost of purchasing
fuel to heat the on

- site lumber dry kilns, purchasing electricity to power the facility, and to generate revenue by the sale of excess electricity

. Similarly, an energy benefit is derived by combusting a renewable fuel instead of a fossil fuel to generate steam.

The March 2010 Guidance states that “a case

- by

- case analysis of the net atmospheric impact of biomass fuels would likely be prohibitively time

- consuming and compl ex for facilities and permitting authorities.” I lieu of such an analysis, the net environmental benefit described in Step 3 is realized through the combination of converting virtually all of the carbon in the fuel to
CO 2 , replanting harvested forest land with saplings, and sequestering the majority of the carbon
harvested from forest land in produced lumber. Because of t he positive economic, energy, and
environmental impacts of burning biomass fuel in lieu of fossil fuels , this alternative is
considered BACT for GHG emissions from the proposed boiler.

Carbon Capture and Sequestration

As discussed in Step 3, CCS systems require a dditional energy to remove CO 2 from the boiler flue gas, as well as to compress it for transport and storage. In the case of a b iomass boiler, the
concentration of CO 2 in the exhaust gas is relatively dilute (i.e., between 15 and 20 percent b y weight ), which would require a strong solvent to capture the CO 2 , as well as a considerable amount of energy to regenerate the solvent. The economic impact s of this a dditional energy requirement would be in addition to the capital and operating costs associated with equipping and maintaining a CCS system.

Most cost information related to CCS technology focuses on fossil fuel (particularly c oal) combustion, natural gas processing, and syngas production operations. U.S. Department of Energy analyses indicat e that application of post

- combustion CCS technology to a new

55 0 MWe net output coal

- fired power plant would cost approximately $86 per t on of CO 2 avoided. 6 This is over ten times the cost

- effectiveness threshold of $7 per ton proposed in

6 National Energy Technology Laboratory (NETL), “Cost and Performance Baseline for Fossil Energy

Plants

– Volume 1: Bituminous Coal and Natural Gas to Electricity, Revision 2,” Novemb er 2010.

DOE/NETL

- 2010/1397. Page 300.Sierra Pacific Industries

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- 23586A Section 1.3.2, even without accounting for the economy of scale realized by a 550 MWe unit as compared to that of a 31 MWe unit.

The considerable monetar y and energy requirements of a CCS system suggest unacceptable economic, energy , and environmental impacts. The increased energy requiremen ts would
result in additional emissions of all pollutants other than CO 2 , and, therefore, CCS systems have

an unacce ptable collateral environmental impact as well. As a result, CCS systems are removed from consideration as BACT for GHGs emitted by the proposed boiler.

Catalytic Destruction

Because th i s alternative reduce s emissions of GHGs other than CO 2 , the cost effe ctiveness was
calculated on a CO 2 e basis . Catalytic oxidation was estimated to reduce GHG emission by less than 6,000 tons per year. T o be considere d cost effective, and assuming the cost

- effectiveness threshold of $7 pe r ton proposed in Section 1.3.2, the annual cost would have to be less than $42,000 annually , which is unlikely, based on the costs of catalytic systems used to reduce criteria pollutants

. The economic analysis provided in the criteria pollutant BACT analysis for a catalytic oxidation sy stem to reduce CO and VOC emissions indicated that the economic impact of these systems, due to uncertainties regarding the reliability and cost of the systems, would be unacceptable. Because the GHG reduction associated with these systems (on a percent b asis)
is less than the expected reduction in CO and VOC associated with an oxidation catalyst system , and the cost

- effectiveness threshold for GHGs is lower than what is typical for CO and VOC, th i s alternative is considered to have unacceptably high colla teral economic impacts, and
is removed from consideration as BACT for GHG emissions from the proposed boiler

.

Removal of NO X Control System (SNCR)

Elimination of the SNCR system used to reduce NO X emissions from the boiler would result in
an increase in NO X emissions. Because the criteria pollutant BACT analysis associated with the submitted PSD permit application proposed SNCR as BACT for NO X emissions from the boiler, elimination of the SNCR system would result in unacceptable NO X emissions from the boil er, and is therefore not an acceptable alternative for GHG BACT based on unacceptable collateral environmental impacts , and are removed from consideration as BACT for GHG emissions from the proposed boiler

.

Proper Combustion/Energy Efficiency

Utilizing an efficient boiler design, and then operating the boiler to produce the most steam and electricity per unit of fuel combusted are control alternatives that SPI proposes to incorporate in the project. As stated previously, these options are considered the ba seline for the BACT analysis, and all other options were considered to be applied over and above these two. These alternatives have a positive energy and environmental, and most likely economic, impact, and
are considered to be BACT for GHG emissions from the proposed boiler.August 201 3 Sierra Pacific Industries

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## 7 Step 5

– Selection of BACT

Based on the analysis presented here, SPI proposes that BACT for GHGs from biomass

- fired boilers is the exclusive use of biomass fuel (aside from natural gas use during startup and f or flame stabilization), energy

- efficient system design, and proper combustion practices. For the cogeneration unit, SPI proposes an annual GHG BACT limit of 433,000 tpy CO 2 e

.Sierra Pacific Industries

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## 8 Reciprocating Internal Combustion Engines

The proposed facility des ign includes a natural gas

- fired emergency boiler feedwater pump, that 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
testi ng and maintenance (i.e., a maximum of 100 hours per year).



### 8.1 Step 1

– Identify Available Control Alternatives The first step of a top

- down BACT analysis is to identify all available pollutant reduction options. Options typically fall into three categories: inherently low

- emitting processes, clean fuels, and
add

- on control technologies.

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 grid is not available to operate the electric motors that power the feedwater pumps that would be relied upon to circilute water through the boiler during a normal shutdown process. Natural gas is considered the fossil fuel that generates the least GHG emissions per unit of ene rgy produced. The only real alternative to a natural gas

- fired pump is a diesel

- fired pump, and diesel fuel is less desirea ble from a GHG emission perspective. For this reason, no alternative processes or fuels are considered for this analysis. However, w ithin the category of reliable natural gas

- fired engines that provide sufficient power for the assigned task, use of the most efficient model available will result in the
least GHG emissions.

GH G

- reducing add

- on technology exist s (e.g., carbon capture and storage), and has been discussed at length elsewhere in this document. B ecause the pump must be available quickly and reliably, an add

- on control that complicate s operation and potentially reduce s engine
readiness

, compromise s t he emergency role of the en gine, and is therefore unacceptable for
consideration as GHG

- reducing technolog y for the proposed emergency natural gas

- fired engine

.



### 8.2 Step 2

– Eliminate Technically Infeasible Alternatives In the second step of a top

- down BACT analysis, the available pol lutant reduction options listed in Step 1 are considered, and, if found to be technically infeasible for the specific emission unit under review, eliminated.

Use of the most efficient commercially available natural

- gas fired engine that is capable of
relia bly operating an appropriate boiler feedwater pump in a timely manner is a technically feasible means of limiting GHG emissions from the emergency natural gas

- fired engines.



### 8.3 Step 3

– Rank Technically Feasible Alternatives In Step 3, the remaining alternati ves that have not been removed from consideration due to technical infeasibility, are ranked, starting with the most effective.

The only alternative considered is the use of the most efficient commercially available, natural

gas

- fired engine that do es no t compromise the availability and rapid deployment of the boiler feedwater pump for emergency duty.32 29

- 23586A



### 8.4 Step 4

– Evaluate Economic, Energy, and Environmental Impacts Because only one alternative is considered, there is no opportunity to compare and contrast th e collateral impacts of competing technologies.



### 8.5 Step 5

– Selection of BACT Based on the analysis presented here, Sundrop proposes that BACT for GHGs from the natural

gas

- f ired engine used to power the emergency boiler fee d water pump is the use of the most

e fficient commercially

- available engine capable of providing reliable and timely operation to fulf ill the assigned emergency role

.