# R 0 S E BUR G

February 3, 2011

United States Environmental Protection Agency Region 8 1595 Wynkoop Street Denver, Colorado 80202-1129 Attention: Vanessa Hinkle, 8P-AR

Dear Ms. Hinkle:
On November 5, 2010, Roseburg Forest Products ("Roseburg") received an information request made pursuant to Section 114 of the Clean Air Act and relating to Roseburg's Missoula, MT facility. This request required Roseburg to submit an analysis of the possible emission controls for the sander dust boiler and sander dust burners that could be considered in establishing Montana's Reasonable Progress (RP) goals. In evaluating potential RP controls, the Clean Air Act specifies that the regulatory authority must consider (1) the cost of compliance, (2) the time necessary for compliance, (3) the energy and non-air quality envirolUllental impacts, and (4) the remaining useful life. The enclosed analysis evaluated controls for these combustion units in relation to these four criteria and concluded that no additional control is necessary or appropriate. Improvement in visibility is not a criterion for an RP evaluation; therefore we have not included
a modeling analysis. While the individual source need not perform a modeling assessment as a component of an RP evaluation, because the RP evaluation is a component of establishing the Reasonable Progress Goals (RPGs), modeling is a necessary component of the RPG establishment process. Therefore, it is worth noting that the emissions from Roseburg's sander dust combustors are extremely small in relation to the overall emissions inventory. As a result,
we do not believe that the significant cost of adding controls at the Missoula facility is justified by a corresponding significant visibility reduction. We also note that the primary emitter in the Missoula area, the Smurfit-Stone Missoula mill, recently closed down. As the Smurfit-Stone mill accounted for nearly 2,000 tons per year of combined PM, NOx and S02 emissions, significant progress has already been achieved towards meeting the next RPG.
With the closure of the Smurfit-Stone mill, hundreds offamilies' incomes have been reduced or eliminated. The Roseburg Missoula mill is one of the last industrial employers left in that area. With the wood products industry suffering the worst times that it has ever experienced, we believe that it is of extra importance to recognize the severe cost of compliance associated with

P.O. Box 1088 Roseburg, OR 97470 PH 541.679.3311 TF 800.245.1115 FX 541.679.2543 www.Roseburg.com

## adding additional controls, particularly when balanced against the minimal associated improvement in visibility. We also note that with the limited remaining life of our burners, and the Montana SIP requirement to install Best Available Control Teclmology (BACT) on all new sources, our combustion devices will be reevaluated when it comes time to replace them.

In light of these facts, we wish to reaffirm the conclusions drawn in the attached report. Specifically, we do not believe that the statutory factors justify requiring additional controls for the Roseburg sander dust combustion sources.
If you have any questions after reviewing this report, please feel free to contact me at (541) 679- 2130. Sincerely, -)



# , //," )j '---

Ellen Porter Corporate EnvirOlunental Manager
Enclosure

cc: Chad Darby (Golder) Tom Wood (Stoel Rives)

P.O. Box 1088 Roseburg, OR 97470 PH 541.679.3311 TF 800.245.1115 FX 541.679.2543 www.Roseburg.com

### STATEMENT Of CERTIFICATION

J 

### eertiry linda pellalty or law that I have personally e.xamincd and am rarniliar with the infurillillioll 

### submiltL"d in Ihis dm:urncllt 

### and all atHlchmcnts and 

### that. based on my in(]uiry


### or lIHlse individuals immediately responsible 

### 10,. obtaining inrormation, J 

### helieve lhal the inl"oflnali0Jl is true. accurate, and c.:omplete. I mn aware that there are significant 

### penallies ror**submillil1~** 

### blse inlormalion. including the possibility or 

### line or irnpris(lflllll.:nt.

# --~~~---**Si~e** 

# 6J(J

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_ TilleGolder, Golder Associates and the GA globe design are trademarks of Golder Associates Corporation



# REASONABLE PROGRESS ANALYSIS Roseburg Forest Products - Missoula Particleboard

Submitted To: U.S. Environmental Protection Agency Region VIII

1595 Wynkoop Street Denver, Colorado 80202

- 1129 Attention: Vanessa Hinkle 8P

- AR

Submitted For: Roseburg Forest Products Company

P.O. Box 4007 Missoula, Montana 59806

Submitted By: Golder Associates Inc.

9 Monroe Parkway, Suite 270 Lake Oswego, OR 97035 USA

Distribution:

February 2, 2011 Project No. 103
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## EXECUTIVE SUMMARY Golder Associates, Inc. has been retained by Roseburg Forest Products (Roseburg) to prepare a Reasonable Progress (R P) analysis for the sanderdust

- fired combustion units at the Missoula, Montana particleboard manufacturing facility. Although there is currently no deadline for making Reasonable Progress determinations nor any formal agency guidance on how to prepare suc h a determination, EPA requested that Roseburg submit an RP analysis, suggesting that the Best Available Retrofit Technology (BART) Guidelines be used as a reference in evaluating the cost effectiveness factor. Emission controls were evaluated consistent with the BART Guidelines for particulate matter, nitrogen oxides, and sulfur dioxide, the primary contributors to regional haze in the airshed. For additional levels of particulate matter emission control, Golder identified wet electrostatic precipitators , Venturi scrubbers, and fabric filters as technically feasible control solutions. For additional levels of control for emissions of nitrogen oxides, Golder identified regenerative selective catalytic reduction and low NO x 

### burners as the technically feasi ble control solutions. With regard to sulfur dioxide emissions, Golder identified wet scrubbers and dry sorbent injection as technically feasible emission control solutions. All of the sanderdust combustion sources vent to either a pre

- dryer or final dry er and space limitations exist for the boiler and ROEMMC. Due to issues of available space and potential impacts of chemical additives on wood furnish materials, there were no control options that were viable immediately downstream of the combustion sourc es, prior to the drying systems. While a number of technically feasible controls were identified that could reduce pollutants emitted from sanderdust combustion that may contribute to regional haze, none of the controls are cost effective. Therefore, the existing controls on the sander dust boiler and sander dust burners are consistent with the Reasonable Progress requirements under the Clean Air Act.

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# Table of Contents

EXECUTIVE SUMMARY

................................ ................................ ................................ ........................ ES

- 1 1.0 INTRODUCTION

................................ ................................ ................................ .............................. 1 1.1 Applicable Emission Sources, Configuration, and Useful LIfe

................................ ..................... 1 1.1.1 Boiler

- ROEMMC Configuration

................................ ................................ ................................ 2 1.1.2 SolaGen Burner Configuration

................................ ................................ ................................ . 2 1.2 Exhaust Parameters

................................ ................................ ................................ ..................... 2 1.2.1 Boiler

- ROEMMC Burner

................................ ................................ ................................ .......... 2 1.2.2 SolaGen Burner

................................ ................................ ................................ ....................... 2 1.3 RP Analysis Methodology

................................ ................................ ................................ ............ 2 1.3.1 Step 1: Identify all available retrofit control technologies

................................ ......................... 3 1.3.2 Step 2: Eliminate technically infeasible options

................................ ................................ ....... 3 1.3.3 Step 3: Evaluate control effectiveness of the remaining control technologies

........................ 3 1.3.4 Step 4: Evaluate impacts and document results

................................ ................................ ...... 3 1.3.5 Note: Step 5: Evaluate Visibility Impacts (Not conducted as part of this analysis)

.................. 3 2.0 PM RP ANALYSIS

................................ ................................ ................................ ........................... 5 2.1 Step 1

- Identify PM Retrofit Technologies

................................ ................................ .................. 5 2.1.1 Multi

- clones

................................ ................................ ................................ .............................. 5 2.1.2 Wet and Dry Electrostatic Precipitators

................................ ................................ .................. 6 2.1.3 Fabric Filters (Baghouses)

................................ ................................ ................................ ....... 6 2.1.4 Venturi Scrubber

................................ ................................ ................................ ...................... 7 2.2 Step 2

- Eliminate Technically Infeasible Options

................................ ................................ ........ 8 2.2.1 Multi

- clones or Cyclones

................................ ................................ ................................ .......... 8 2. 2.2 Wet and Dry Electrostatic Precipitators

................................ ................................ ................... 8 2.2.3 Fabric Filters (Baghouses)

................................ ................................ ................................ ....... 8 2.2.4 Venturi Scrubber

................................ ................................ ................................ ...................... 8 2.3 Step 3

- Evaluate Control Effectiveness

................................ ................................ ...................... 8 2.4 Step 4

- Evaluate Impacts and Document Results

................................ ................................ ...... 9 2.4.1 Cost Impact

................................ ................................ ................................ .............................. 9 2.4.2 Energy Impacts

................................ ................................ ................................ ........................ 9 2.4.3 Environmental Impacts

................................ ................................ ................................ ............ 9 2.4.4 Useful Life of Control Devices

................................ ................................ ................................ 10 3.0 NO X 

### RP ANALYSIS

................................ ................................ ................................ ........................ 11 3.1 Step 1

- Identify NO x 

### Retrofit Technologies

................................ ................................ ............... 11 3.1.1 Selective Non

- catalytic Reduction (SNCR)

................................ ................................ ............ 11 3.1.2 Selective Catalytic Reduction (SCR) and SNCR/SCR Hybrid Syst ems

................................ 12 3.1.3 Regenerative Selective Catalytic Reduction (RSCR)

................................ ............................ 13 3.1.4 Low NO x 

### Burner

................................ ................................ ................................ ..................... 13

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### 3.2 Step 2

- Eliminate Technically Infeasible Options

................................ ................................ ...... 13 3.2.1 Selective Non

- catalytic Reduction

................................ ................................ ......................... 13 3.2.2 Selective Catalytic Reduction

................................ ................................ ................................ 14 3.2.3 Regenerative Selective Catalytic Reduction

................................ ................................ .......... 14 3.2.4 Low

- NO x 

### Burners

................................ ................................ ................................ ................... 14 3.3 Step 3

- Evaluate Control Effectiveness

................................ ................................ .................... 14 3.4 Step 4

- Evaluate Impacts and Document Results

................................ ................................ .... 14 3.4.1 Cost Impact

................................ ................................ ................................ ............................ 14 3.4.2 Energy Impacts

................................ ................................ ................................ ...................... 15 3.4.3 Environmental Impacts

................................ ................................ ................................ .......... 15 3.4. 4 Useful Life

................................ ................................ ................................ .............................. 16 4.0 SO 2 

### RP ANALYSIS

................................ ................................ ................................ ........................ 17 4.1 Step 1

- Identify SO 2 

### Retrofit Technologies

................................ ................................ ............... 17 4.1.1 Wet Scrubber

................................ ................................ ................................ ......................... 17 4.1.2 Spray Dryer

................................ ................................ ................................ ............................ 17 4.1.3 Dry Sorbent Injection

................................ ................................ ................................ ............. 18 4.2 Step 2

- Eliminate Technically Infeasible Options

................................ ................................ ...... 18 4.2.1 Wet Scrubber

................................ ................................ ................................ ......................... 18 4.2.2 Spray Dryer

................................ ................................ ................................ ............................ 19 4.2.3 Dry Sorbent Injection

................................ ................................ ................................ ............. 19 4.3 Step 3

- Evaluate Control Effectiveness

................................ ................................ .................... 19 4.4 Step 4

- Evaluate Impacts and Document Results

................................ ................................ .... 19 4.4.1 Cost Impact

................................ ................................ ................................ ............................ 19 4.4.2 Energy Impacts

................................ ................................ ................................ ...................... 19 4.4.3 Enviro nmental Impacts

................................ ................................ ................................ .......... 20 4.4.4 Useful Life

................................ ................................ ................................ .............................. 20 5.0 CHOICE OF RP CONTROL S

................................ ................................ ................................ ........ 21 6.0 REFERENCES

................................ ................................ ................................ ............................... 22



## List of Tables Table 1 BART Source Exhaust Pa rameters and Emission Rates Table 2 BART Source Control Options Table 3 PM Control Technology Impact Evaluation Table 4 NO x 

### Control Technology Impact Evaluation Table 5 SO 2 

### Control Technology Impact Evaluation


## List of Figures Figure 1 Boiler and ROEMMC burner configuration Figure 2 SolaGen burner configuration

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## List of Appendices Appendix A Cost Analysis Worksheets Note: Tables and Figures appear at the end of the report

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## 1.0 INTRODUCTION In a letter received by Roseburg Forest Products on November 5, 2010, the U.S. Environmental Protection Agency Region VIII Assistant Regional Administrator, Mr. Stephen S. Tuber, requested that Roseburg conduct a Reasona ble Progress (RP) Analysis for the sanderdust combustion devices operated at the Missoula facility. EPA has issued no comprehensive guidance for how to conduct a RP analysis or how to interpret the four statutory factors considered in evaluating potential RP controls, However, Region VIII suggested that the Best Available Retrofit Technology (BART) Guidelines be consulted for purposes of determining cost

- effectiveness. Roseburg has retained Golder Associates to complete the RP analysis and to provide info rmation on the remaining useful life of the sanderdust

- fired sources. The focus of this RP analysis is on the pollutants that contribute to regional haze: particulate matter (PM), nitrogen oxides (NO x 

### ) and sulfur dioxide (SO 2 

### ).


## 1.1 Applicable Emission Sourc es, Configuration, and Useful LIfe Roseburg Forest Products Company owns and operates a particleboard manufacturing facility in Missoula, Montana. The facility has two production lines, one with a multi

- platen batch press (Line 1) and one with a continuou s press (Line 2). A pre

- dryer is used to reduce the moisture of green wood materials received at the facility. Heat for the pre

- dryer is provided by a 45 MMBtu/hr SolaGen sanderdust burner. There are four final dryers associated with Line 1 and two fina l dryers associated with Line 2 that produce dried wood furnish for face and core material in the particleboard. Heat input for all six of the final dryers is provided by the combined exhaust of a 50 MMBtu/hr ROEMMC sanderdust burner and 55 MMBtu/hr sande rdust

- fired Babcock & Wilcox boiler, which also provides steam for facility processes.

The Babcock & Wilcox boiler is the oldest of the three sanderdust

- fired sources at the facility. It is a stoker type boiler that was installed in 1969. Unlike the othe r facility sanderdust burners, the boiler serves the function of producing steam for facility processes in addition to providing heat input to the final dryers. The useful remaining life of the burner is likely less than 10 years. Roseburg has not curren tly made any project commitments, but is considering a replacement of the burner to improve performance and reduce emissions. A low NO x 

### burner for the boiler has been considered in the RP analysis as one possible emission reduction option.

The ROEMMC bu rner was installed in 1979, although it is a 1978 model burner. The sole purpose of this burner is to provide heat input for the final dryers. The ROEMMC burner is currently 32 years old. The facility replaced a sanderdust fired COEN burner in 2005 that was 29 years old. It is suspected that the ROEMMC burner is nearing its life expectancy and probably has less than 10 years of service remaining.
The SolaGen burner was installed in 2006, although it is a 2005 model. The sole purpose of this burner is t o provide heat input to the pre

- dryer. Based on the previous COEN burner, it is expected that the SolaGen has approximately 25 years of useful life remaining.

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### 1.1.1 Boiler

- ROEMMC Configuration A horizontal manifold connects the boiler and ROEMMC burner exhaus t stacks to provide combined exhaust to the six final dryers for manufacturing lines 1 and 2. Both the boiler and ROEMMC burner stacks allow exhaust to be diverted to atmosphere in the event of an emergency or upset condition. Line 1 dryers (referred to as Dryers 1

- 4 by the facility) exhaust to multi

- clones 1 

### for particulate control. The multi

- clone exhaust is combined and released from a single Line 1 dryer stack. Line 2 dryers (referred to as Dryers 5 and 6 by the facility) exhaust to multi

- clones, whi ch individually emit to atmosphere. Figure 1 shows the configuration of the boiler, ROEMMC and Line 1 dryers.



### 1.1.2 SolaGen Burner Configuration The SolaGen burner exhaust is utilized to dry green furnish materials (ultimately destined for both press lines) in the pre

- dryer. Green materials are typically about 50% moisture so the primary purpose of the pre - dryer is to reduce the moisture by approximately 80% or more so that the pre

- dried material is suitable for final drying in the Line 1 and 2 core and face dr yers. The SolaGen burner is equipped with a low NO x 

### burner and flue gas reinjection to reduce NO x 

### emissions. Exhaust from the pre

- dryer is controlled by a cyclone, a wet electrostatic precipitator (WESP) and a regenerative thermal oxidizer (RTO). These controls significantly reduce emissions of PM. Figure 2 shows the configuration of the SolaGen burner, dryer, and subsequent pollution control devices.


## 1.2 Exhaust Parameters
1.2.1 Boiler

- ROEMMC Burner The boiler exhaust has been measured at 572 ° F, while the ROEMMC exhaust has been measured at 700

- 1050 ° F. However, after combining with ambient air and passing through the final dryers, the exhaust temperatures from all final dryers are in the range of 130

- 155 ° F with a moisture content of 2

- 12%. Table 1 provides sourc e exhaust parameters and emission rates associated with the boiler and ROEMMC burner.



### 1.2.2 SolaGen Burner The SolaGen burner exhausts through the pre

- dryer where a significant amount of moisture is released from the green furnish. The resulting exhaust from the pre

- dryer is approximately 240 ° F with a moisture content of 42%. See Table 1 for additional details on exhaust parameters and emission rates.


## 1.3 RP Analysis Methodology The following analysis has been conducted consistent with the BART Guidelines published in Appendix Y to Title 40 of the Code of Federal Regulations (CFR), Part 51

- GUIDELINES FOR BART

1 

### The multi

- clones controlling the final dryers at the Rose burg Missoula facility are different from multi

clones traditionally used after wood

- fired boilers, which are typically a ganged set of cyclones, each of which is approximately 9” in diameter. The Missoula final dryer cyclones are a ganged set of cyclones , each of which is approximately 2 feet in diameter.

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### DETERMINATION UNDER THE REGIONAL HAZE RULE. These requirements do not apply to RP determinations, but were use d as reference s . The following steps were used in this RP determination:



### 1.3.1 Step 1: Identify all available retrofit control technologies Available and applicable technologies were requested from vendors and identified through EPA data sources and from BART analyses conducted by BART

- eligible sources. Control technologies were considered available if they were licensed and commercially available as discussed in 40 CFR Part 51, Appendix Y. Table 2 lists the available c ontrol technologies that were evaluated for the RP analysis with respect to each source and pollutant combination.



### 1.3.2 Step 2: Eliminate technically infeasible options Each of the control options were evaluated for technical feasibility. For retrofit situatio ns, space limitations, residence time at appropriate temperatures, moisture, particulate loading, and process quality control can all affect the feasibility of the control options. As will be discussed in subsequent sections, the issue of adding ammonia an d sorbent upstream of the dryers for NO x 

### and SO 2 

### control was a concern because of the contact these additives would have with the wood furnish.



### 1.3.3 Step 3: Evaluate control effectiveness of the remaining control technologies After the elimination of technica lly infeasible controls, the remaining controls were evaluated for effectiveness and ranked from highest to lowest. The control efficiencies provided by vendors or obtained through literature were used in ranking the technologies.



### 1.3.4 Step 4: Evaluate impac ts and document results The impact analysis has four parts. The first part is the analysis of the cost of retrofit control options that are feasible. Based on design parameters, source configuration, life expectancy of the control option, and the cost of operation, Golder calculated average cost effectiveness and the incremental cost effectiveness between ranked options. The second part of the analysis is the evaluation of energy impacts. Costs associated with energy use are included in the cost determi nation. However, energy use can also result in greenhouse gas emissions, the impact of which is difficult to quantify, but is still a concern with some options. The third part of the analysis is the evaluation of non

- air quality impacts in a qualitative manner. These include impacts such as disposal of spent catalyst and collected dust; or treatment and discharge of scrubber water. Finally, the fourth part of the analysis is the determination of useful life. This was based on vendor information, past e ngineering experience, and the EPA Office of Air Quality Planning and Standards Cost Control Manual. Documentation of results can be found in Tables 3

- 5.



### 1.3.5 Note: Step 5: Evaluate Visibility Impacts (Not conducted as part of this analysis) Evaluation of visibility impacts is not a source

- specific requirement of a RP determination under the Clean Air Act. EPA Region VIII is conducting an airshed

- wide visibility analysis as part of the effort to establish

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### reasonable progress goals for each Cl ass I area. As a result, no visibility assessment is required or has been prepared as part of this RP control technology assessment. In a communication via email dated December 9, 2010, Ms. Vanessa Hinkle of EPA Region VIII confirmed that dispersion model ing was not expected as part of this submittal.

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## 2.0 PM RP ANALYSIS PM emission controls have been analyzed for the boiler, ROEMMC, and SolaGen sanderdust combustion devices. Due to space limitations, and the need to retain as much heat as possible for use in the dryers, PM controls upstream of the final dryers and pre

- dryer are not feasible. Therefore, controls were evaluated for the dryer exhaust points. At the dryer exhaust, particulate emissions are the result of both sanderdust combustion and the process of drying wood fiber, which can contribute both filterable and condensable particulate to the exhaust stream. The following RP analysis takes the conservative approach of analyzing cost effectiveness based on emissions from both the combustion sources as well as the dryers and pre

- dryer. Although the Line 2 final dryers currently exhaust individually through multi

clones (see Figure 1), the analysis of control options assumed these exhaust streams would be ducted together to significantly reduce the cost associated with individual emission controls.
Currently, PM emissions from the boiler, ROEMMC burner, and Line 1 and 2 final dryers are controlled by multi

- clones at the dryer outlets. The resulting controlled hourly emission rate, shown in Table 1, was used as the baseline emission rate for assessing additional controls. Therefore, in subsequent analyses shown in Table 3, the “uncontrolled” emission rate is the annual emission rate exhausting from the multi

clones based on actual hours of operation. Fo r the boiler and ROEMMC, actual annual emissions from 2002 were used in the analysis, per the request of EPA.
Similarly, the SolaGen burner and pre

- dryer PM emissions are already controlled by a cyclone, WESP, and RTO. The emission rate from this comple x control system is shown in Table 1 as the controlled hourly emission rate. However, for subsequent cost analyses shown in Table 3, the annual emission rate from the RTO is considered the “uncontrolled” emission rate for purposes of additional RP analyse s. Due to the fact that the SolaGen burner was not in existence in 2002, actual annual operating hours for 2008 were used for the purpose of determining an annual emission rate used in subsequent cost analyses, shown in Table 3.


## 2.1 Step 1
- Identify PM Retrof it Technologies Based on reviews of available and applicable technologies, Golder identified the following technologies for subsequent analysis as particulate control options on the exhaust of the final dryers and pre

- dryer. Note that some of these techno logies are already installed on the pre

- dryer (cyclone and WESP).



### 2.1.1 Multi

- clones Multi

- clones are multiple high efficiency cyclones assembled into a single functional unit through manifold arrangements for the inlet and outlet streams of the cyclones. A mul ti

- clone unit is currently provided as a matter of course for most wood fired combustion sources. At the Missoula facility, all of the combustion sources are ducted to dryers prior to any emissions control device. The ROEMMC burner is equipped with a sin gle, large cyclone and the boiler is equipped with a small set of multiclones prior to exhausting

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### into the dryers. However, the outlets of the final dryers are already controlled with multi

- clones, thereby providing control of the boiler and ROEMMC exhaus t. The pre

- dryer is already controlled by a cyclone and WESP, thereby controlling the SolaGen burner exhaust. Note: The installation of an additional set of multi

- clones after the existing multi

- clones, or the installation of larger (less efficient) cycl ones would not provide a significant further emissions reduction.



### 2.1.2 Wet and Dry Electrostatic Precipitators Electrostatic precipitators (ESPs) are used extensively after combustion devices for control of PM emissions, particularly for wood and oil

- fired c ombustion devices and dryers. An ESP is a particulate control device that uses electrical forces to move particles entrained within an exhaust stream onto collection surfaces. The entrained particles are given an electrical charge when they pass through a corona, a region where gaseous ions flow. Electrodes in the center of the flow lane are maintained at high voltage and generate the electrical field that forces the particles to the collector walls. In wet ESPs, the collectors are either intermittently or continuously washed by a spray of liquid, usually water. Instead of the collection hoppers used by dry ESPs, WESPs utilize a drainage system and water treatment of some sort. In dry ESPs, the collectors are knocked, or "rapped", by various mechanical means to dislodge the collected particles, which slide downward into a hopper where they are collected.
While several factors determine ESP collection efficiency, ESP size is the most important. ESP size determines treatment time; the longer a particle spends in the ESP, the greater its chance of being collected. Maximizing electric field strength will maximize ESP collection efficiency. Collection efficiency is also affected to some extent by dust resistivity, gas temperature, chemical composition (o f the dust and the gas), and particle size distribution. For the exhaust parameters of the Line 1 and 2 final dryers, PPC Industries provided a vendor quote for WESP systems based on achieving 98% collection efficiency. The SolaGen burner and pre

- dryer a re already controlled by a WESP.
Electrostatic precipitators are capable of achieving high control efficiencies, even for small particles , and can handle hot gas streams . WESPs can handle high moisture exhaust streams and can also handle sticky condensabl e organic matter that might result in plugging of a fabric filter control device. The major disadvantages of ESPs are the higher cost and greater complexity , as well as greater difficulty in achieving the highest control efficiencies that fabric filters c an attain . ESPs require a fair amount of maintenance, more complicated control systems, and they have more parameters to monitor. WESPs may also have a waste water stream and wet collected material that are greater housekeeping and disposal issues.



### 2.1.3 Fabri

c Filters (Baghouses) Fabric filters are used extensively as PM control device s for a variety of source types. Fabric filters are frequently referred to as baghouses because the fabric is usually configured in cylindrical bags. They are

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### extremely efficie nt at collecting particulate due to the particle sizes typically produced from wood fired combustion. In a fabric filter, flue gas is passed through a tightly woven or felted fabric, causing PM in the flue gas to be collected on the fabric by sieving and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with a number of the individual fabric filter units housed together in a group. Bags are the most common type of fabric filter. The dust cake that forms on the filter fr om the collected PM can significantly increase collection efficiency.
Typical new equipment design efficiencies are between 99 and 99.9%. Several factors determine fabric filter collection efficiency. These include gas filtration velocity, particle cha racteristics, fabric characteristics, and cleaning mechanism. In general, collection efficiency increases with decreasing filtration velocity and increasing particle size. F abric filters are generally less expensive than electrostatic precipitators and t hey do not require complicated control systems. However, fabric filters are subject to plugging for certain exhaust streams and do require maintenance and inspection to ensure that plugging or holes in the fabric have not developed. The high moisture con tent of exhaust from the pre

- dryer could result in rapid plugging. Therefore, baghouses are only considered feasible on the exhaust from the final Line 1 and Line 2 final dryers.
Regular replacement of the filters is required, resulting in higher mainte nance and operating costs than dry ESPs. Although fabric filters can be used to control wood

- fired combustion devices, the overall system design and operating practices must be carefully designed to prevent fires in the fabric filter and associated equipm ent. For the Missoula facility, baghouses placed downstream of the final dryers, where the temperature is relatively cool, are not likely to be at risk of fire.



### 2.1.4 Venturi Scrubber Wet scrubbers remove PM from gas streams principally by inertial impaction of the particulate onto a water droplet. Particles can be wetted by impingement, diffusion, or condensation mechanisms. To be wetted, PM must either make contact with a spray droplet or impinge upon a wet surface. In a Venturi scrubber, the gas stream is con stricted in a throat section. The large volume of gas passing through a small constriction gives a high gas velocity and a high

- pressure drop across the system. As water is introduced into the throat, the gas is forced to move at a higher velocity causing the water to shear into droplets. Particles in the gas stream then impact onto the water droplets produced. The entrained water droplets are subsequently removed from the gas stream by a cyclone separator. Venturi scrubber collection efficiency increases w ith increasing pressure drops for a given particle size. Collection efficiency will also increase with increasing liquid

- to

- gas ratios up to the point where flooding of the system occurs.
It is expected that the particulate generated from the sanderdust combustion devices will largely consist of particles less than 10 microns in diameter (PM10), much of which will be particles less than 2.5 microns in

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### diameter (PM2.5). Due to the difficulty of capturing emissions of such a small size fraction, it has be en assumed that 75% is the highest control efficiency that can reasonably be achieved with a Venturi scrubber. Higher efficiencies may be achieved, but at significantly greater pressure drops, requiring much higher energy use.


## 2.2 Step 2
- Eliminate Technic ally Infeasible Options See Table 2 for a summary of the feasibility analysis. The following is a detailed discussion of the rationale behind the feasibility determinations.



### 2.2.1 Multi

- clones or Cyclones These are technically feasible, but already installed. Additional multi

- clones or cyclones would have minimal effect due to the fine particle size distribution in the exhaust streams.



### 2.2.2 Wet and Dry Electrostatic Precipitators Due to the low moisture content, high oxygen content, and high particulate loading of t he boiler, ROEMMC, and final dryer exhaust streams, Ray Willingham of PPC Industries indicated to Golder via email on January 19, that a dry ESP would be a potential fire or explosion hazard. For this reason, a dry ESP is not considered technically feasib le for the final dryers, but a WESP is considered a potential control option. The SolaGen burner and pre

- dryer are already controlled by a WESP. The moisture content of the exhaust from the pre

- dryer is too high to be controlled with a dry ESP. Dry ESPs are not considered an available technology for the final dryers or pre
- dryer. WESPs are considered technically feasible for the Line 1 and 2 final dryers.



### 2.2.3 Fabric Filters (Baghouses) Baghouses are considered technically feasible for the final dryer exhaust from Lines 1 and 2. However, the moisture content of the exhaust from the WESP, which controls the pre

- dryer, is considered too high to utilize a subsequent baghouse without significant plug ging concerns. Therefore a baghouse is not considered technically feasible for the SolaGen and pre
- dryer exhaust.



### 2.2.4 Venturi Scrubber A Venturi scrubber is considered technically feasible for control of PM emissions from the Line 1 and 2 final dryers (includ ing the boiler and ROEMMC burner emissions) as well as the pre
- dryer (including the SolaGen burner emissions).


## 2.3 Step 3
- Evaluate Control Effectiveness Table 3 lists the feasible control options by effectiveness. Based on vendor information and/or EPA
reso urces the following efficiencies were identified as achievable:

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### Fabric filter (baghouse) offers the highest level of control in this retrofit situation (99%)  

### Wet ESP (98%)  

### Venturi scrubber (75%) 

## 2.4 Step 4
- Evaluate Impacts and Document Results Table 3 prov ides a summary of the cost analyses and qualitative evaluation of environmental and energy impacts.



### 2.4.1 Cost Impact The cost analysis shown in Table 3 is provided in terms of both average cost effectiveness and incremental cost effectiveness. Average cost e ffectiveness is the annualized cost of control (capital and operating expenses) divided by the total tons of PM emissions eliminated ($/ton). The incremental cost effectiveness is the difference in cost between a control option and the next most effective control option divided by the additional amount of pollutant material collected ( Δ $/ Δ tons). Individual cost analysis spreadsheets can be found in Appendix A.



### 2.4.2 Energy Impacts None of the controls highlighted in Table 3 require fuel to operate. However, th e operation of all three control types requires electricity. The amount and cost of the electricity was estimated and utilized in the cost impact analysis. Venturi scrubbers require the most electricity due to their pressure drop, which increases with in creasing control efficiency. WESPs also require a significant amount of electricity for blowers as well as the electrostatic charging and collection of particulate. Another less quantifiable impact from energy use is the impact from producing the electric ity. This could include greenhouse gases and emissions of other pollutants, impacts from mining fuel to produce electricity, and a variety of impacts associated with renewable energy technologies depending on the source of the electricity used. In Missou la, the electricity is most likely generated by coal

- fired electrical generators.



### 2.4.3 Environmental Impacts All of the controls highlighted in Table 3 have environmental impacts. Baghouses generate solid waste and worn bags that must be disposed of in a landf ill. However, this is a fairly minimal impact. Venturi scrubbers and WESPs, on the other hand, generate wet solids (sludge) that must be dewatered and landfilled as well as contaminated water that must be treated before discharge. Wet control systems ar e much more prone to corrosion and freezing. They may be more likely to result in a visible plume during colder periods. In addition, wet control systems require the use of water which is at a premium in the arid Missoula area where average rainfall is o nly 17 inches per year.
Currently, wastewater discharge is a very significant issue for the Missoula facility. The facility cannot discharge to a publicly owned treatment facility due to its remote location and due to the proximity of the

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### drinking water aquifer below their site, Roseburg cannot release discharges of this nature to evaporation ponds or infiltration ponds. For the biofilter controlling the presses and the WESP currently controlling the pre - dryer, Roseburg is using the water in the process such as adding the waste water to the resin at the blenders. However, if additional waste water is generated, from one or more additional WESPs or scrubbers, Roseburg does not currently have a method to dispose of it.



### 2.4.4 Useful Life of Control Devices For a ll particulate control devices a useful life was conservatively assumed to be 15 years with appropriate maintenance and part replacement.

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## 3.0 NO X 

## RP ANALYSIS NO x 

### emissions result from the combustion of resonated sanderdust due to the nitrogen content of the
wo od and resin (fuel NO x 

### ) as well as from atmospheric nitrogen in the combustion air (thermal NO x 

### ). However, for reasons that are discussed below, it was necessary to consider control options downstream of the wood particle dryer systems. The wood particle dryer systems do not contribute NOx to the combustion air stream.

NO x 

### emission controls have been analyzed for the boiler, ROEMMC, and SolaGen sanderdust combustion devices. Currently there are no NO x 

### add

- on emission controls on these devices. However, t he SolaGen burner was installed in 2006 with a low

- NO x 

### burner and flue gas recirculation. The controlled NO x 

### emission rate from the SolaGen low

- NO x 

### burner determined at the outlet of the pre

- dryer system was considered the “uncontrolled” baseline emission rate for subsequent control option analyses. Due to the fact that the SolaGen burner was not in existence in 2002, actual annual operating hours f or 2008 were used for the purpose of determining an annual emission rate for use in subsequent cost analyses, shown in Table 4.


## 3.1 Step 1
- Identify NO x 

## Retrofit Technologies
3.1.1 Selective Non
- catalytic Reduction (SNCR) SNCR systems have been widely employed for biomass combustion systems globally. SNCR is relatively simple because it utilizes the combustion chamber as the control device reactor, achieving control efficiencies of 30

- 70%. SNCR systems rely on the reaction of ammonia and nitrogen oxide at temperatu res of 1,550 ° F to 1,950 °F to produce molecular nitrogen and water, common atmospheric constituents, in the following reaction:

In the SNCR process, the ammonia or urea is injected into the combustion chamber, where the comb ustion gas temperature is in the proper range for the reaction. Relative to catalytic control devices, SNCR is inexpensive and easy to install, particularly in new applications where the injection points can be placed for optimum mixing of ammonia and com bustion gases. The reduction reaction between ammonia and NO is favored over other chemical reactions at the appropriate combustion temperatures and is, therefore, a selective reaction. One major advantage of SNCR is that it is effective in combustion ga ses with a high particulate loading. Sanderdust combustion devices can produce exhaust that has a very high particulate loading rate from ash carryover to the downstream particulate control device. With use of SNCR, the particulate loading is irrelevant to the gas

- phase reaction of the ammonia and NO.
One disadvantage of SNCR, and any control systems that rely on the ammonia and NO reaction, is that excess ammonia must be injected to ensure the highest level of control. Higher excess ammonia

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### generally results in a higher NO x 

### control efficiency. However, ammonia is also a contributor to atmospheric formation of particulate that can contribute to regional haze. Therefore, the need to reduce NO x 

### emissions must be balanced with the need to keep a mmonia slip levels acceptable. Careful monitoring to ensure an appropriate level of ammonia slip, not too high or too low, is necessary.



### 3.1.2 Selective Catalytic Reduction (SCR) and SNCR/SCR Hybrid Systems Unlike SNCR, SCR reduces NO x 

### emissions with ammonia i n the presence of a catalyst. The major advantages of this are the higher control efficiency (70%

- 90%) and the lower temperatures at which the reaction can take place (400 ° F to 800 ° F, depending upon the catalyst selected). SCR is widely used for combusti on processes where the type of fuel produces a relatively clean combustion gas, such as natural gas turbines. In an SNCR/SCR hybrid system, ammonia or urea is injected into the combustion chamber to provide the initial reaction with NO x 

### emissions, followe d by a catalytic (SCR) section that further enhances the reduction of NO x 

### emissions. The primary reactions that take place in the presence of the catalyst are:

SCR is not widely used with wood fired combustion units due to the amount of particulate that is generated by combustion of wood. The particulate, if not removed, can cause plugging in the catalyst and coat the catalyst such that the surface area for reaction is reduced. Another challenge with wood fired combustion is the presence of alkali metals such as sodium and potassium, which are commonly found in wood, but not fossil fuels. Sodium and potassium will poison catalysts and the effects are ir reversible. 2 

### Other naturally occurring catalyst poisons found in wood are phosphorous and arsenic.
In order to prevent the plugging, blinding, and/or poisoning of the SCR catalyst, it is necessary to first remove particulate from the exhaust gases. It is not considered technically feasible to place an SCR unit upstream of the particulate control device in a wood

- fired boiler or burner application due to the potential for decreasing the useful life of the catalyst and decreasing the control efficiency, whi ch can happen relatively quickly. Use of SCR on a wood

- fired boiler or burner application requires a high temperature particulate control device so that the downstream temperature is still in the range of 400 ° F to 800 ° F, which is necessary for the reducti on of NO x 

### in the presence of the catalyst. In situations where NO x 

### emissions are being controlled downstream of a dryer where the outlet temperature is well below 200 ° F, the catalyst is essentially ineffective at reducing emissions.

2 

### Babcock Power, Inc. presentation on RSCR, Worldwide Pollution Control Association Duke Energy Seminar, September 3

- 5, 2008.

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### 3.1.3 Regenerative Selecti ve Catalytic Reduction (RSCR) RSCR is a commercially demonstrated add

- on control technology by Babcock Power Inc. that combines the technology of a regenerative thermal oxidizer device and SCR. Ammonia is injected upstream of the catalyst just as with a traditional SCR unit. The reactions between ammonia and NO are the same. Intended to be placed downstream of emission control systems where the exhaust gas is clean, but the temperature is below the optimal temperature range for catalytic reduction of NO x 

### , the RSCR unit has a front

- end preheating section that reheats the exhaust stream with a regenerative thermal device. An RSCR unit is approximately 95% efficient at thermal recovery. The exhaust is heated to a temperature in the range optimal for catalyt ic reduction (600 ° F to 800 ° F) prior to entering an SCR unit. These systems have been proven to reduce NO x 

### emissions to less than 0.075 lbs/MMBtu and can achieve emission reductions to as low as 0.05 lbs/MMBtu. Three installations at woody biomass fueled electrical generating stations have been identified.



### 3.1.4 Low NO x 

### Burner Low NO x 

### burners are a viable technology for a number of fuels including sanderdust and gasified biomass. Generally, staged combustion and sub

- stoichiometric conditions can be used to limit the amount of NO x 

### formation. The SolaGen burner at the Missoula facility already utilizes a low

- NO x 

### burner. The ROEMMC burner still has a number of years of remaining useful life. However, as part of the performance upgr ade evaluation of the boiler, low

- NO x 

### burners have been considered. Therefore, the use of such a burner has been considered in the RP analysis for the boiler.


## 3.2 Step 2
- Eliminate Technically Infeasible Options
3.2.1 Selective Non
- catalytic Reduction SNCR relie s on the injection of ammonia in the combustion chamber of the sanderdust fired device. The ROEMMC and SolaGen burners would not have the residence time needed at the critical temperatures for the reaction to take place. It is unknown whether sufficient residence time would occur in the boiler combustion zone. Because these combustion units provide exhaust to the dryers, there is a great deal of concern about the impact of ammonia on the wood furnish. In making particleboard, the wood furnish is combine d with a formaldehyde based resin. According to Steve Paulson (Roseburg), ammonia acts as a scavenger of free formaldehyde, which could have some effect on resin curing if ammonia is trapped within the furnish during forming. Another concern is that ammo nia can darken or blacken certain wood species. It is unknown what impact ammonia would have on the wood species being used by Roseburg for the period of time it would be exposed, the concentrations of excess ammonia, and at the elevated temperatures that occur in the dryers. Golder placed a call to the National Council of Air and Stream Improvement to inquire as to whether they were aware of any installations where ammonia was injected upstream of a wood particle dryer. Golder was unable to find any ins tances where ammonia injection was conducted upstream of a wood particle dryer. Due to the uncertain impact that ammonia could have on

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### wood furnish and resin curing, SNCR is not considered an applicable technology with proven feasibility for any of the sa nderdust combustion devices due to their location upstream of the wood particle dryers.



### 3.2.2 Selective Catalytic Reduction Where wood combustion is concerned, SCR requires a clean exhaust stream with temperatures between 400 ° F and 800 ° F. PM in the exhaust from wood combustion can poison, blind, or plug catalyst beds very rapidly in certain conditions. As a result, it is industry practice to have a good PM control device upstream of the catalyst bed. For the boiler and ROEMMC burner at the Missoula facility, t here is not sufficient room for particulate controls and a catalyst bed upstream of the particle dryers. Additionally, the exhaust temperature exiting the catalyst bed would be significantly cooler, which would provide less heat to the dryers. The SCR un it could be located downstream of the dryers and particulate controls, but the dryer exhaust temperature is well below 400 ° F (see Table 1). With regard to the SolaGen burner, the same concerns are valid. Additionally, the location of an SCR unit upstream of any of the dryers would result in ammonia slip into the dryers. For the reasons stated in section 3.2.1 above, ammonia slip into the dryers could have unintended consequences for the wood furnish, thereby affecting the manufacturing process. For thes e reasons, SCR is not considered an applicable technology with proven feasibility for any of the sanderdust combustion devices.



### 3.2.3 Regenerative Selective Catalytic Reduction RSCR is considered an applicable and available control option that could be applied d ownstream of the wood particle dryers

.


### 3.2.4 Low

- NO x 

### Burners A low

- NO x 

### burner technology is already in use for the SolaGen sanderdust burner. A low - NO x 

### burner is considered a technically achievable option for the boiler.


## 3.3 Step 3
- Evaluate Control Effectiveness Table 4 lists the feasible control options by effectiveness. Based on vendor information and/or EPA resources the following control efficiencies were identified as achievable:

 

### RSCR (75%)  

### Low

- NO x 

### burner ( ≈ 20%) 

## 3.4 Step 4
- Evaluate Impacts and Document Result s
3.4.1 Cost Impact The cost analysis shown in Table 4 is provided in terms of average cost effectiveness. Average cost effectiveness is the annualized cost of control (capital and operating expenses) divided by the total tons of

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### NO x 

### emissions eliminated ($/ton ). The incremental cost effectiveness is not presented for NOx controls. Because only one control technology was feasible for each combustion unit, there was no incremental cost to evaluate. Individual cost analysis spreadsheets are located in Appendix A.
It should be noted that the RSCR vendor would not guarantee catalyst life beyond three years due to the potential for poisoning and blinding associated with the combustion products of wood fuels. The vendor, Babcock Power, Inc. was also unable to meet the deadline to provide a quote specific to this project. However, the vendor had provided Golder a quote for a biomass combustion project in California. The cost information for that project was extrapolated based on the size and operating parameters of th e various combustion sources in order to conduct the cost impact analysis for the Missoula sanderdust combustion devices.



### 3.4.2 Energy Impacts The RSCR units evaluated require both fossil fuel and electricity. Fossil fuel would be used to reheat the dryer exhau st gas from approximately 140 ° F to 600 ° F or higher. Additionally, electricity is used to operate the powerful fans required to overcome the pressure drop across the catalyst bed. The energy impacts were estimated in terms of cost and were therefore inclu ded in the cost impact analysis.
Another less quantifiable impact from energy use is the impact from producing the electricity and mining the fossil fuel. Both the production of electricity and the use of fossil fuel for combustion could result in green house gases and other pollutant emissions. In Missoula, the electricity is most likely generated by a coal

- fired electrical generator.

Low

- NO x 

### burners do not require any additional energy.



### 3.4.3 Environmental Impacts RSCR units require the use of catalysts that must be disposed of. The vendor guarantees that the catalysts will remain effective for 3 years. However, the catalysts will most likely be considered a hazardous waste. Additionally, RSCR requires the use of ammonia injected into the exhaust stream and unreacted excess ammonia would be released to the atmosphere. Ammonia slip to the atmosphere is a contributor to fine particle formation, which further exacerbates the regional haze issue. Therefore, there i s a trade

- off between maximizing NO x 

### emission reductions and minimizing ammonia slip.

Low

- NO x 

### burners typically result in increased carbon monoxide emissions as thermal NO x 

### are avoided at the cost of decreased combustion efficiency. The Missoula area was just recently redesignated from a moderate carbon monoxide nonattainment area and remains sensitive to increases in carbon monoxide emissions. Therefore, there is a trade

- off between reducing NO x 

### emissions and increasing in carbon monoxide emissions.

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### 3.4.4 Usef

ul Life Based on vendor guarantees, it is estimated that the useful life of RSCR catalyst is 3 years while the rest of the system has a useful life of 15 years. Low

- NO x 

### burners can have a useful life of approximately 30 years based on experience obtained at the Missoula facility under typical operating conditions.

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## 4.0 SO 2 

## RP ANALYSIS SO 2 

### emissions result solely from the sulfur content of the fuel, which is minimal in resinated wood materials. However, the following RP analysis points out that control technolo gies must be considered downstream of the dryers where additives would not affect the wood furnish.

SO 2 

### emission controls have been analyzed for the boiler, ROEMMC, and SolaGen sanderdust combustion devices. Currently there are no SO 2 

### add

- on emission cont rols on these devices.
Due to the fact that the SolaGen burner was not in existence in 2002, actual annual operating hours for 2008 were used for the purpose of determining an annual emission rate used in subsequent cost analyses, shown in Table 5.


## 4.1 Step 1 - Identify SO 2 

## Retrofit Technologies
4.1.1 Wet Scrubber Wet flue gas desulfurization (FGD) systems (wet scrubbers) remove SO 2 

### from the flue gases by using an alkaline reagent to form sulfite and sulfate salts. Wet FGD systems typically utilize a spray absorbe r tower to establish contact between flue gases and reagent slurry droplets. Counterflow wet scrubbers are common, with the flue gas entering the bottom of the absorber tower, passing through packing, impingement trays, or other means of creating large li quid surface area to maximize the gas/liquid contact. Spray nozzles at the top of the absorber tower generally dispense the reagent/water spray. A mist eliminator is utilized at the exhaust to minimize the droplet carryover out of the scrubber.

Wet FGD has the additional benefit of controlling other pollutants such as H 2 

### SO 4 

### mist, hydrogen chloride and mercury. PM control is not inherent in Wet FGD, but depends on additional design features, such as a venturi scrubbing section being incorporated into th e design.
The wet FGD system generates wastewater and wet sludge streams that require treatment and disposal. It is difficult to adequately capture the actual water and sludge treatment costs when performing the cost effectiveness calculations for a BACT analysis.
The most common reagent employed is lime. Magnesium enhanced lime and dual alkali reagents (using both sodium and calcium) can be used, although the control efficiencies are similar to that of lime.



### 4.1.2 Spray Dryer Dry FGD, or dry scrubber technolo gy, utilizes a particulate control device (generally a fabric filter) as the final component of the dry scrubbing system. The benefit of using a fabric filter is that the dry sorbent is collected in the filter cake on the filter bags, allowing for additio nal contact time with the acid gases in the flue gases, resulting in increased control efficiency as well efficient use of the sorbent. WESPs can be

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### used for particulate control when dry scrubbing is employed. However, it is necessary to make sure there is sufficient reaction time in the flue gas stream for the sorbent material because the WESP will remove unreacted material, unlike a fabric filter where reaction can continue in the filter cake.
Spray dryer absorber technology consists of a reactor vessel upstream of the particulate control device. The alkaline lime slurry is injected into the top of the reactor vessel using a rotary atomizer or spray nozzles. The salts that form from the reaction between the reagent and the acid gases are dried by the h eat in the flue gases. Some of the dried material is removed from the bottom of the reactor vessel and the balance continues on to the PM control device for further reaction and removal.



### 4.1.3 Dry Sorbent Injection Dry sorbent injection is another method of dry FGD. Unlike a spray dryer, dry sorbent injection does not utilize a reactor vessel, but injects the sorbent into the duct upstream of the PM control device. The partially reacted solids then continue on to the fabric filter for further reaction and remo val. Typically dry sorbent injection will require more sorbent usage, but less capital cost than a spray dryer.
According to January 18, 2011 email communications with Dave Surak of Clyde Bergemann EEC, a minimum flue gas temperature of 270 ° F is required for many sorbents. Mr. Surak indicated that hydrated lime could be used in the temperature range presented by the Missoula exhaust streams, but that the likely control efficiency for would be in the 30% to 35% range for SO 2 

### . 

## 4.2 Step 2
- Eliminate Technically Infeasible Options None of the options identified are feasible upstream of the final dryers or pre

- dryer. The pH of the wood furnish is an issue for particleboard manufacturing. Any caustic material injected upstream of final dryers or pre - dryer could a ffect the usefulness of the furnish in unanticipated ways. The SolaGen burner exhaust feeds directly into the pre

- dryer and cannot accommodate any FGD device upstream of the pre

dryer. Due to space limitations, neither the boiler or the ROEMMC burner hav e enough room for a wet scrubber or dry FGD device followed by a particulate control device upstream of the final dryers. As a result of these considerations, none of the FGD technologies are technically feasible upstream of the final dryers or pre

- dryer.



### 4.2.1 Wet Scrubber A wet scrubber is technically feasible downstream for the Line 1 and 2 final dryers and the pre
dryer

.

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### 4.2.2 Spray Dryer Based on vendor provided information, it was determined that the dryer outlet temperature range was too low to spray dry sorbent materials in a reactor downstream. Spray dryers are not technically feasible in this application.



### 4.2.3 Dry Sorbent Injection Dry so rbent injection using hydrated lime upstream of a WESP or baghouse is considered technically feasible.


## 4.3 Step 3
- Evaluate Control Effectiveness Table 5 lists the feasible control options by effectiveness. Based on vendor information and/or EPA resources t he following control efficiencies were identified as achievable:

 

### Wet scrubber (97%)  

### Dry sorbent injection (35%) 

## 4.4 Step 4
- Evaluate Impacts and Document Results
4.4.1 Cost Impact The cost analysis shown in Table 5 is provided in terms of both average cost effecti veness and incremental cost effectiveness. Average cost effectiveness is the annualized cost of control (capital and operating expenses) divided by the total tons of SO 2 

### emissions eliminated ($/ton). The incremental cost effectiveness is difference in co st between a control option and the next most effective control option divided by the additional amount of pollutant material collected ( Δ $/ Δ tons). Individual cost analysis spreadsheets are located in Appendix A.

It should be noted that while there are te chnically feasible solutions, the relatively low emission rate of SO 2 

### from all of the sanderdust combustion devices results in an extremely high average cost effectiveness. As a result, the benefit of installing controls for SO 2 

### is extremely low for such a substantial expense. Additionally, the dry sorbent injection option would require the expense of a downstream particulate control device (baghouse or WESP)



### 4.4.2 Energy Impacts Neither the wet scrubber of the dry sorbent injection control options utilize fuel s directly. However, both would require electricity for pumps and blowers. Although it would be required, the cost and energy use of a particulate matter control device downstream of the dry sorbent injection system was not factored into the cost or ener gy use. The energy impacts were estimated in terms of cost and were therefore included in the cost impact analysis.

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### Another less quantifiable impact from energy use is the impact from producing the electricity. Production of electricity from the use of fossil fuel for combustion could result in greenhouse gases and other pollutant emissions. In Missoula, the electricity is most likely generated by a coal

- fired electrical generator.



### 4.4.3 Environmental Impacts Both wet scrubbers and dry sorbent injection syst ems have environmental impacts. Wet scrubbers produce a wet sludge that must be collected and landfilled as well as liquid that must be treated prior to discharge. Wet scrubbers also require the use of water which is a scarce resource in the arid Missoul a area. Dry sorbent injection systems produce particulate that must be collected and landfilled. Both wet scrubbers and dry sorbent injection systems utilize caustic material that must be mined, processed, and delivered to the site for use. These activi ties have a wide variety of known environmental impacts.
As discussed in Section 2.4.3, wastewater discharge is a very significant issue for the Missoula facility. The facility cannot discharge to a publicly owned treatment facility due to its remote loca tion and due to the proximity of the drinking water aquifer below their site, Roseburg cannot release discharges of this nature to evaporation ponds or infiltration ponds. For the biofilter controlling the presses and the WESP currently controlling the pr e - dryer, Roseburg is using the water in the process such as adding the waste water to the resin at the blenders. However, if additional waste water is generated, from one or more additional scrubbers, Roseburg does not currently have a method to dispose o f it.



### 4.4.4 Useful Life Golder has assumed a reasonable useful life of 15 years for both the wet scrubber and dry sorbent injection system.

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## 5.0 CHOICE OF RP CONTROL S Based on the analysis above, the utilization of the existing controls constitutes the appropriate
re quirements for reasonable progress. The RP factors, identified in CAA Section 169A(g)(1) are: (1) the costs of compliance, (2) the time necessary for compliance, (3) the energy and non

- air quality environmental impacts, and (4) the remaining useful life. Of the three sander dust combustion devices requested to be assessed for RP controls, only one of those units (the SolaGen burner) has a predicted remaining useful life of over ten years. The other two devices (the ROEMMC burner and the Babcock & Wilcox boiler) are projected to have a remaining useful life of less than 10 years. Therefore, the latter two devices are better not addressed as part of this RP assessment , but will be addressed through the replacement permitting process.

None of the control options identified for the sander dust combustion units are considered cost effective. EPA is required to take into account cost effectiveness in establishing RP control requirements. All of the control options are well outside the cost effectiveness env elope for RP controls. In developing the presumptive BART requirements for large coal fired combustion units, EPA determined that controls constituted BART for SO 2 

### emissions when the cost effectiveness values were between $400 and $2,000 per ton of SO 2 

### re moved. Similarly, EPA determined controls for NO x 

### emissions constituted BART when the cost was less than $1,500 per ton of NO x 

### removed. The Roseburg control option with the lowest cost effectiveness is the low

- NO x 

### burner for the boiler. In the context of an RP analysis for a sander dust burner with a remaining useful life of less than 10 years, a cost effectiveness of $3,300 per ton NO x 

### removed should not be considered a viable RP control option. All other control options evaluated were considerably less cost effective and so similarly would not be considered viable.
Based on the statutory criteria, the above assessment of the remaining useful life, cost effectiveness and
non - air quality environmental impacts of e ach of the technically feasible control options for the sander dust burners all support the conclusion that the current controls are adequate and should be the basis for Montana’s reasonable progress goal.

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## 6.0 REFERENCES BPI 2008. Worldwide Pollution Control Association, Duke Energy Seminar, September 3

- 5, 2008, Presentation by Babcock Power Inc. on RSCR, September 2008.
BPI 2009. Phone and email communications between Chad Darby of Golder, and Rich Abrams of Babcock Power Inc re garding RSCR budget quotations, June 2009.

CBEEC 2011. Phone and email communications between J. Patrick Stevens of Golder and Dave Surak of Clyde Bergemann EEC regarding fabric filter, spray dryer and sorbent injection budget quotes and suitability for t he Missoula sources, January 2011.
Drennan, S., Webster, T., “Low NOx Combustion of Biomass Fuels,” Coen Company, Inc.
EPA 1980b. Part II: Factors for Estimating Capital and Operating Costs, Chemical Engineering. Vatavuk, M.V. and R.B. Neveril. 1980a. Part I: Parameters for Sizing Systems, Chemical Engineering.
EPA 1990a. Top

- Down Best Available Control Technology Guidance Document. Office of Air Quality Planning and Standards, Research Triangle Park, NC (Draft).
EPA, 1992. The Use of SNCR As BACT fo r NOx Control in Boilers and Municipal Solid Waste Incinerators, Office of the Administrator, 171

- R

- 92

- 003, February 1992.
Graymont 2011. Phone and email communications between Brian Eagle Golder and Cindy Howard of Graymont (406) 266

- 5221 regarding logis tics and budget cost of delivering hydrated lime to Missoula, MT.
Hinton, Scott W., PhD, P.E., The Effects of Fuel Characteristics on SCR Installations, Foster Wheeler Corporation.
Jeffers, Ken. Johnson Mathey Catalysts. SCR Catalyst Performance Issues, T he McIlvaine Company Hot Topic Hour presentation November 6, 2008.
Kurz, Max, Calculations for Engineering Economic Analysis , 1993. McGraw

- Hill.

P erry, R.H. and C.H. Chilton, editors. 1973. Chemical Engineers Handbook. 5 th 

### Edition. McGraw

- Hill.

PPC 201 1. Phone and email communications between J. Patrick Stevens and Brian Eagle of Golder, and Ray Willingham and Scott Standefer of PPC Industries (903) 758

- 3395 , regarding Wet ESP budget quotations, January 2011.
Vatavuk, M.V. and R.B. Neveril. 1980a. Pa rt I: Parameters for Sizing Systems, Chemical Engineering.

### TABLES

### January, 2011 103-99731

Table 1 BART Reasonable Progress Analysis Source Data

Roseburg Forest Products Missoula, Montana
Stack Flow PM emissions PM 10 emissions PM 2.5 emissions SO 2 emissions NO X emissions
acfm dscfm lbs/hr uncontrolled lbs/hr

controlled lbs/hr

uncontrolled lbs/hr

controlled lbs/hr

uncontrolled lbs/hr

controlled lbs/hr

uncontrolled lbs/hr

controlled lbs/hr

uncontrolled lbs/hr

controlled Boiler 55 (1) 572 (1) 9.9 (1) 29,034 (1) 13,435 (a) 8,047 (2)

-- 9.042 (3)

-- 6.93 (3)

-- 4.6 (3) 1.375 (b)

-- 33.35 (5)

-- Multiclones ROEMMC 50 (1)

-- -- -- -- 7,937 (2)

-- -- -- -- -- -- 1.25 (b)

-- 40.06 (5)

-- Multiclones
Line 1 (7)

-- 136 (8) 2.73 (8) 130,410 (8) 100,767 (8) 7,992 (9)

-- 17.1 (8)

-- 17.1 (8)

-- 12.8 (8) 1.804 (10)

-- 50.46 (10)

--
Line 2 (7)

-- 140 (11) 8.36 (11) 63,674 (11) 45,834 (11) 7,992 (9)

-- 5.8 (11)

-- 5.8 (11)

-- 4.35 (11) 0.821 (10)

-- 22.95 (10)

-- SolaGen Predryer 45 (1) 239 (1) 41.8 (1) 37,478 (1) 16,539 (a) 5,616 (2) 20.7 (1) 3.93 (12) 8.3 (1) 3.93 (12)

-- -- 1.125 (1)

-- 21.03 (1) 20.5 (12) Cyclone, WESP (35,000 cfm), Low NO X burner/flue gas reinjection, RTO

136 (13) 2.73 (13) 130,410 (13) 100,767 (13) 17.1 (13) 17.1 (13) 12.8 (14) (15) 140 (c) 8.36 (c) 63,674 (d) 45,834 (d) 5.8 (d) 5.8 (d) 4.35 (d) 132 (13) 5.84 (13) 37,014 (13) 27,906 (13) 2.8 (13) 2.8 (13) 2.1 (14) 152 (13) 12.3 (13) 26,660 (13) 17,928 (13) 3 (13) 3 (13) 2.25 (14)

Notes (a) Stack flow (dscfm) = (stack flow [acfm]) x (530oR/[460 oR + stack temperature {oF}]) x (1 - [stack moisture {%} / 100]) (b) Emission rate (lbs/hr uncontrolled) = (emission factor [lbs/MMBtu]) x (capacity [MMBtu/hr]) Emission factor (lbs/MMBtu) = 0.025 (4) (c) Line 2 Dryer = (Weighted average (by stack flow) of Line 2 Face and Line 2 Core Dryers) (d) Line 2 Dryer = (Sum of Line 2 Face and Line 2 Core Dryers)

References (1) Provided by RFP in initial response to EPA. (2) Data provided by Roseburg Forest Products. Boiler and ROEMMC hours are from 2002, and the SolaGen hours are from 2008 (after the WESP and RTO had been installed). (3) Source test of boiler conducted February 3, 2000. PM 10 and PM 2.5 emission rates are calculated based on particle size distribution reports by Micromeritics Analytical Services, samples 74004 and 74007, provided by RFP. (4) AP-42 1.6, Table 1.6.-2. Emission Factors for NO X , SO 2 , and CO from Wood Residue Combustion, dry wood, September 2003. (5) Source test conducted April 3, 2007. ROEMMC NO X emission rates based on the average of 2 high-fire test runs. Boiler NO X emission rate based on the average of 2 low-fire test runs. (6) ROEMMC particulate emission rates based on the sum of Line 1 and Line 2 dryer emission rates, and as a result, represent particulate emissions from drying as well. (7) The Boiler and ROEMMC are assumed to vent through the dryers, and each line will have its own emissions control devices. (8) Equal to Line 1 Dryer value. (9) Hours of operation for Line 1 and Line 2 are the average of the boiler and ROEMMC hours of operation. (10) Value is the sum of emission from the boiler and ROEMMC burner apportioned based on the Line 1 dryer and Line 2 dryer (face and core) stack flows (dscfm). (11) Equal to Line 2 Dryer (Face and Core) value. (12) Source test of SolaGen burner/predryer conducted November 4, 2008. Includes control by cyclone, wet ESP, low NO X burner, RTO, and FGR. (13) Source test of Line 1 and Line 2 dryers conducted September 30, 2004. (14) Assumes PM 2.5 is 75% of PM 10 based on a conservative engineering estimate. Condensible PM emissions would be expected to be primarily PM 2.5 or less, and data from AP-42 shows that filterable emission rates from a rotary dryer controlled by a cyclone are similar to condensible emission rates. It is estimated that less than 50% of the filterable PM 10 emissions would be PM 2.5 . (15) Line 2 dryer emissions represent both Line 1 Face dryer and Line 2 Core dryer emissions, which are assumed to be ducted together for purposes of pollution control for this analysis. Source Control Devices Stack Moisture % Stack Temperature oF Capacity MMBtu/hr Actual Hours of Operation hrs/yr

Line 1 Dryers Line 2 Dryers Line 2 Dryers (Face) Line 2 Dryers (Core)

Appendix A ESP update.xlsx Golder Associates

## January, 2011 103-99731

Table 2 BART Reasonable Progress Analysis Source Control Options

Roseburg Forest Products Missoula, Montana
Line 1 Line 2 SolaGen Predryer Feasible? Yes/No Reasoning Feasible? Yes/No Reasoning Feasible? Yes/No Reasoning PM Wet ESP Yes Proceed to Cost Analysis Yes Proceed to Cost Analysis N/A Currently installed
Dry ESP No Too dry, could result in fire or explosion No Too dry, could result in fire or explosion No Exhaust moisture content too high

Venturi Scrubber Yes Proceed to Cost Analysis Yes Proceed to Cost Analysis Yes Proceed to Cost Analysis

Multiclone N/A Currently Installed N/A Currently Installed N/A Already has a cyclone ESP installed
Baghouse/Fabric Filter Yes Vendor Budget Quote Yes Vendor Budget Quote No Exhaust moisture content too high

SO 2 

### Wet Scrubber Yes Proceed to Cost Analysis Yes Proceed to Cost Analysis Yes Proceed to Cost Analysis
Spray Dryer No Exhaust too cool No Exhaust too cool No Exhaust too cool Dry Sorbent Injection (downstream of dryers) Yes w/WESP or fabric filter - Hydrated Lime sorbent Yes w/WESP or fabric filter - Hydrated Lime sorbent Yes w/ Wet ESP (need room) - Hydrated Lime sorbent Dry Sorbent Injection or Spray Dryer (upstream of dryers) No Sorbent may impact wood quality No Sorbent may impact wood quality No Sorbent may impact wood quality
NO X 

### SNCR No Potential ammonia staining of furnish No Potential ammonia staining of furnish No Potential ammonia staining of furnish

SCR No Potential ammonia staining of furnish No Potential ammonia staining of furnish No Potential ammonia staining of furnish

RSCR Yes w/ PM - Need Quote from Babcock Yes w/ PM - Need Quote from Babcock Yes Need Quote from Babcock

Low NO X 

### Burner Yes Boiler Only - Info from vendor N/A Boiler Only - Info from vendor N/A Currently installed

Good Combustion Yes Yes N/A

Appendix A ESP update.xlsx 

### Golder Associates

## January, 2011 103-99731

Table 3 PM Control Technology Impact Evaluation Summary of Top-Down BART Reasonable Progress Analysis Results

Roseburg Forest Productions, Missoula, Montana Economic Impacts Total Annualized Cost (2) 

### Average Cost

Effectiveness (3) 

### Incremental Cost

Effectiveness (4) 

### (tons/yr) % (tons/yr) ($/yr) ($/ton) ($/ton) (Yes/No)

LINE 1 Baghouse 68 99.0% 68 $890,274 $13,160 -$270,843 Yes None Low Wet ESP 68 98.0% 67 $1,075,344 $16,058 $30,350 Yes None Medium Venturi Scrubber 68 75.0% 51 $598,359 $11,676 $11,676 Yes None High No Control 68 0 0 N/A No None None
LINE 2 Baghouse 23 99.0% 23 $729,984 $31,815 $643,888 Yes None Low Wet ESP 23 98.0% 23 $580,752 $25,569 $25,230 Yes None Medium Venturi Scrubber 23 75.0% 17 $446,259 $25,673 $25,673 Yes None High No Control 23 0 0 N/A No None None SOLAGEN Predryer

Venturi Scrubber 11 75.0% 8.3 $237,583 $28,704 $28,704 Yes None High No Control 11 0 0 N/A No None None

References: (1) Emissions controlled based on the destruction efficiency of each control technology, as specified by the vendor. (2) Total annualized cost (capital, direct, and indirect) of purchasing, installing, and operating the proposed control alternative. A capital recovery factor approach using a real interest rate (i.e. absent inflation) is used to express capital costs in present-day annual costs. (3) Average cost effectiveness is total annualized cost for the control option, divided by the emissions reductions resulting from the option. (4) The incremental cost effectiveness is the difference in annualized cost for the control option and the next most effective control option, divided by the difference in emissions reductions resulting from the respective alternatives. A negative incremental cost effectiveness implies that the less effective control option also has a higher Total Annualized Cost. (5) Wet ESP's and venturi scrubbers generate polluted water that requires treatment prior to disposal. Baghouses create particulate that must be landfilled, but no additional air or water pollution after use. (6) Wet ESP's and venturi scrubbers use significant amounts of electricity for pumping, venturi scrubbers being the highest. Dry sorbent injection uses relatively little additional electricity. 

### Energy Impacts (6)



### Fuel Electricity Source Control

Alternative Uncontrolled Emissions Control

Effectiveness Emissions

Controlled (1) 

### Environmental Impacts (5)

Appendix A ESP update.xlsx 

### Golder Associates

## January, 2011 103-99731

Table 4 NO x 

### Control Technology Impact Evaluation Summary of Top-Down BART Reasonable Progress Analysis Results

Roseburg Forest Productions, Missoula, Montana Economic Impacts Total Annualized Cost (2) 

### Average Cost

Effectiveness (3) 

### Incremental Cost

Effectiveness (4) 

### (tons/yr) % (tons/yr) ($/yr) ($/ton) ($/ton) (Yes/No)

LINE 1 Regenerative Selective Catalytic

Reduction (RSCR) 202 75.0% 151 $2,662,043 $17,603 N/A Yes Medium High Good Combustion Practices 202 N/A No None None No Control 202 N/A No None None
LINE 2 Regenerative Selective Catalytic

Reduction (RSCR) 92 75.0% 69 $1,435,929 $20,876 N/A Yes Medium High Good Combustion Practices 92 N/A No None None No Control 92 N/A No None None SOLAGEN Predryer

Regenerative Selective Catalytic Reduction (RSCR) 58 75.0% 43 $980,444 $22,709 N/A Yes Medium High Good Combustion Practices 58 N/A No None None No Control 58 N/A No None None BOILER - Burner Replacement

Low-NOX Burner (Boiler Only) 134 22.2% 30 $98,400 $3,296 N/A Yes None None

References: (1) Emissions controlled based on the destruction efficiency of each control technology, as specified by the vendor. (2) Total annualized cost (capital, direct, and indirect) of purchasing, installing, and operating the proposed control alternative. A capital recovery factor approach using a real interest rate (i.e. absent inflation) is used to express capital costs in present-day annual costs. (3) Average cost effectiveness is total annualized cost for the control option, divided by the emissions reductions resulting from the option. (4) The incremental cost effectiveness is not shown for NO X . Since only the boiler is subject to Low NO X burner replacement, it is not directly comparable to the emission control devices placed on Line 1, Line 2, and the Predryer. (5) RSCR results in spent catalyst which has environmental impacts associated with mining, manufacturing, and disposal. Additionally, RSCR result in ammonia slip, a potential haze contributor. (6) RSCR requires both fossil fuel and electricity for conveying exhaust and pumping the injected ammonia. Fossil fuel combustion results in greenhouse gas formation. 

### Energy Impacts (6)



### Fuel Electricity Source Control Alternative Uncontrolled Emissions Control

Effectiveness Emissions

Controlled (1) 

### Environmental Impacts (5)

Appendix A ESP update.xlsx 

### Golder Associates

## January, 2011 103-99731

Table 5 SO 2 

### Control Technology Impact Evaluation Summary of Top-Down BART Reasonable Progress Analysis Results

Roseburg Forest Productions, Missoula, Montana Economic Impacts Total Annualized Cost (2) 

### Average Cost

Effectiveness (3) 

### Incremental Cost

Effectiveness (4) 

### (tons/yr) % (tons/yr) ($/yr) ($/ton) ($/ton) (Yes/No)

LINE 1 Wet Scrubber 7.2 97.0% 7.0 $354,911 $50,747 $45,444 Yes None High

Dry Sorbent Injection 7.2 35.0% 2.5 $151,766 $60,141 $60,141 Yes None Low No Control 7.2 0 0 N/A No None None
LINE 2 Wet Scrubber 3.3 97.0% 3.2 $261,211 $82,114 $53,827 Yes None High

Dry Sorbent Injection 3.3 35.0% 1.1 $151,766 $132,222 $132,222 Yes None Low No Control 3.3 0 0 N/A No None None SOLAGEN Predryer Wet Scrubber 3.2 97.0% 3.1 $127,028 $41,453 -$13,882 Yes None High

Dry Sorbent Injection 3.2 35.0% 1.1 $154,218 $139,476 $139,476 Yes None Low No Control 3.2 0 0 N/A No None None

References: (1) Emissions controlled based on the destruction efficiency of each control technology, as specified by the vendor. (2) Total annualized cost (capital, direct, and indirect) of purchasing, installing, and operating the proposed control alternative. A capital recovery factor approach using a real interest rate (i.e. absent inflation) is used to express capital costs in present-day annual costs. (3) Average cost effectiveness is total annualized cost for the control option, divided by the emissions reductions resulting from the option. (4) The incremental cost effectiveness is the difference in annualized cost for the control option and the next most effective control option, divided by the difference in emissions reductions resulting from the respective alternatives. A negative incremental cost effectiveness implies that the less effective control option also has a higher Total Annualized Cost. (5) Wet scrubbers generate polluted water that requires treatment prior to disposal. Dry sorbent injection creates particulate that must be landfilled, but no additional air or water pollution after use. (6) Wet scrubbers use significant amounts of electricity for pumping. Dry sorbent injection uses relatively little additional electricity. 

### Energy Impacts (6)



### Fuel Electricity Source Control

Alternative Uncontrolled Emissions Control

Effectiveness Emissions

Controlled (1) 

### Environmental Impacts (5)

Appendix A ESP update.xlsx 

### Golder Associates

### FIGURES

### Atm Atm



# Boiler ROEMMC burner Line 2 Final Dryers

Atm 

# Line 1 Final Dryers Multi

- clones

Multi

- clones


# Figure 1. Boiler and ROEMMC burner configuration

# Pre

- Dry Storage Silo Atm



# SolaGen

burner Pre

- dryer Cyclone

WESP RTO



# Figure 2. SolaGen burner configuration

### APPENDIX AJanuary, 2011 103-99731

Page 1 of 2 REGENERATIVE SELECTIVE CATALYTIC REDUCTION COST DATA

LINE 1 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

NO X Removal

Cost Cost Source / Reference
TOTAL CAPITAL COST FOR REGENERATIVE SELECTIVE CATALYTIC REDUCTION
DIRECT COSTS (capital investment) (1) Purchased Equipment Costs: (a) Basic Equipment and Auxiliaries (A) $5,315,332 Based on similar budgetary quote from Babcock Power (b) Instrumentation

-- Included in (1A) (c) Freight and Taxes

-- Included in (1A) (d) Urea to Ammonia Conversion Plant $0 uneeded; System uses aqueous ammonia Total Equipment Cost (B): $5,315,332
(2) Direct Installation Costs: (a) Foundations and Supports (0.04B) $212,613 APC Manual; Costs fators for baghouse, assumed equal to RSCR (b) Erection and Handling (Mechnical Installation) (0.5B) $2,657,666 APC Manual; Costs fators for baghouse, assumed equal to RSCR (c) Electrical (0.08B) $425,227 APC Manual; Costs fators for baghouse, assumed equal to RSCR (d) Piping (0.01B) $53,153 APC Manual; Costs fators for baghouse, assumed equal to RSCR (e) Initial Reagent Volume $5,956 Assumes 12,000 gallons at $0.50 per gallon (f) Auxiliary equipment

-- Included in 1A (g) Painting (0.04B) $212,613 APC Manual; Costs fators for baghouse, assumed equal to RSCR (h) Fan and Stack Ductwork $750,000 Engineering Estimate Total Installation Cost (C) $4,317,229 Calculation Total Direct Costs of Capital Investment (DCCI) = (B + C) $9,632,560 Calculation INDIRECT COSTS (capital investment): (1) Engineering Costs (0.1A) $531,533 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (2) Process Contingencies (0.05A) $265,767 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (2) General Facilities (0.05A) $265,767 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. Total Indirect Costs of Capital Investment (ICCI) $1,063,066 Calculation Project Contingency (0.15[A+B]) $1,604,344 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. TOTAL CAPITAL INVESTMENT (TCI) = (DCCI + ICCI + PC): $12,299,970 Calculation ANNUALIZED COST OF CAPITAL INVESTMENT (CATALYST) (1) Interest Rate 10.0% Assumed (2) Control System Economic Life (years) (3) Vendor Guarantee (3) Price of Replacement Catalyst (C C ) $421,167 Based on similar budgetary quote from Babcock Power (5) Capital Recovery Factor (CRF) (0.402) Calculation (6) Capital Recovery Cost (CCRC) = (CRF x C C ) $169,400 Calculation ADJUSTED CAPITAL INVESTMENT (ATCI) = (TCI) - (C C ) $11,878,804 Calculation
ANNUALIZED COST OF CAPITAL INVESTMENT (1) Interest Rate 10.0% Assumed (2) Control System Economic Life (years) (15) EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (3) Capital Recovery Factor (CRF) (0.131) Calculation (4) Capital Recovery Cost (CRC) = (CRF X TCI) $1,561,800 Calculation Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 2 of 2 REGENERATIVE SELECTIVE CATALYTIC REDUCTION COST DATA

LINE 1 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

NO X Removal

Cost Cost Source / Reference

DIRECT COSTS (O&M): (1) Variable Costs (a) Aqueous Ammonia Aqueous Ammonia ($/gal) = 0.50 Estimate based on information provided by facility

Aqueous Ammonia usage rate (gal/hr) = 54.20 Based on similar budgetary quote from Babcock Power Assumed hours of operation (hrs/yr) = 7,992 Maximum hours of operation $215,007 Calculation (b) Natural Gas Costs Natural gas cost ($/1000 scf) = 4.84 Provided by facility Natural gas uasge rate (scf/min) = 20.27 Based on similar budgetary quote from Babcock Power Assumed hours of operation (hrs/yr) = 7,992 Maximum hours of operation $47,054 Calculation (c) Electricity Electricity cost ($/kWh) = 0.07 Provided by facility

Electricity uasge rate (RSCR System) (kW) = 445.2 Based on similar budgetary quote from Babcock Power Assumed hours of operation (hrs/yr) = 7,992 Maximum hours of operation $241,934 Calculation (d) Compressed Air Compressed air cost ($/1000 scf) = 0.36 Estimate Compressed air usage rate (scf/min) = 15 Based on similar budgetary quote from Babcock Power Assumed hours of operation (hrs/yr) = 7,992 Maximum hours of operation $2,666 Calculation

Total Direct Variable Costs (D) $506,661 Calculation (2) Semivariable Costs (a) Labor O = $17.00 M = $25.00 Provided by facility (a1) Operating (O) = (0.0 hrs/shift x 3 shifts/day x day/24hrs x 7,992 hrs/yr x $17.0/hr) $0 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (a2) Supervisory (0.15 O) $0 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (b) Maintenance Materials and Labor (M) = (0.015 x ATCI) $178,182 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. Total Semivariable Costs (E) $178,182 Calculation Total Annual Direct Cost of O&M (DCO&M) = (D + E) $684,843 Calculation INDIRECT COSTS (O&M): (1) Overhead (60% of Sum of Operating & Supervisory Labor) $0 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (2) Property Tax (0.01 TCI) $123,000 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (3) Insurance (0.01 TCI) $123,000 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. Total Annual Indirect Costs of O&M (ICO&M) $245,999 Calculation TOTAL ANNUAL COSTS of O&M (TAO&M) = (DCO&M + ICO&M): $930,843 Calculation

COST EFFECTIVENESS OF REGENERATIVE SELECTIVE CATALYTIC REDUCTION

Capital Recovery Cost of Catalyst (CRCc) $169,400 Capital Recovery Cost of Device (CRCd) $1,561,800 Total Annual Costs of O&M (TAO&M) $930,843 Total Annualized Cost (TAC) = (CRCc + CRCd + TAO&M) $2,662,043 Control Device Loading Rate (tons/yr) 202 Control Device efficiency (%) 75% Pollutant Removed (tons/yr) 151 Pollutant Emitted from New Device (tons/year) 50 COST EFFECTIVENESS ($/ton of pollutant removed) $17,603.31 TOTAL ANNUAL O&M COST FOR REGENERATIVE SELECTIVE CATALYTIC REDUCTION Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 1 of 2 REGENERATIVE SELECTIVE CATALYTIC REDUCTION COST DATA

LINE 2 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

NO X Removal

Cost Cost Source / Reference
TOTAL CAPITAL COST FOR REGENERATIVE SELECTIVE CATALYTIC REDUCTION
DIRECT COSTS (capital investment) (1) Purchased Equipment Costs: (a) Basic Equipment and Auxiliaries (A) $2,595,264 Based on similar budgetary quote from Babcock Power (b) Instrumentation

-- Included in (1A) (c) Freight and Taxes

-- Included in (1A) (d) Urea to Ammonia Conversion Plant $0 uneeded; System uses aqueous ammonia Total Equipment Cost (B): $2,595,264
(2) Direct Installation Costs: (a) Foundations and Supports (0.04B) $103,811 APC Manual; Costs fators for baghouse, assumed equal to RSCR (b) Erection and Handling (Mechnical Installation) (0.5B) $1,297,632 APC Manual; Costs fators for baghouse, assumed equal to RSCR (c) Electrical (0.08B) $207,621 APC Manual; Costs fators for baghouse, assumed equal to RSCR (d) Piping (0.01B) $25,953 APC Manual; Costs fators for baghouse, assumed equal to RSCR (e) Initial Reagent Volume $5,956 Assumes 12,000 gallons at $0.50 per gallon (f) Auxiliary equipment

-- Included in 1A (g) Painting (0.04B) $103,811 APC Manual; Costs fators for baghouse, assumed equal to RSCR (h) Fan and Stack Ductwork $500,000 Engineering Estimate Total Installation Cost (C) $2,244,783 Calculation Total Direct Costs of Capital Investment (DCCI) = (B + C) $4,840,048 Calculation INDIRECT COSTS (capital investment): (1) Engineering Costs (0.1A) $259,526 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (2) Process Contingencies (0.05A) $129,763 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (2) General Facilities (0.05A) $129,763 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. Total Indirect Costs of Capital Investment (ICCI) $519,053 Calculation Project Contingency (0.15[A+B]) $803,865 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. TOTAL CAPITAL INVESTMENT (TCI) = (DCCI + ICCI + PC): $6,162,966 Calculation ANNUALIZED COST OF CAPITAL INVESTMENT (CATALYST) (1) Interest Rate 10.0% Assumed (2) Control System Economic Life (years) (3) Vendor Guarantee (3) Price of Replacement Catalyst (C C ) $205,639 Based on similar budgetary quote from Babcock Power (5) Capital Recovery Factor (CRF) (0.402) Calculation (6) Capital Recovery Cost (CCRC) = (CRF x C C ) $82,700 Calculation ADJUSTED CAPITAL INVESTMENT (ATCI) = (TCI) - (C C ) $5,957,327 Calculation
ANNUALIZED COST OF CAPITAL INVESTMENT (1) Interest Rate 10.0% Assumed (2) Control System Economic Life (years) (15) EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (3) Capital Recovery Factor (CRF) (0.131) Calculation (4) Capital Recovery Cost (CRC) = (CRF X TCI) $783,200 Calculation Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 2 of 2 REGENERATIVE SELECTIVE CATALYTIC REDUCTION COST DATA

LINE 2 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

NO X Removal

Cost Cost Source / Reference

DIRECT COSTS (O&M): (1) Variable Costs (a) Aqueous Ammonia Aqueous Ammonia ($/gal) = 0.50 Estimate based on information provided by facility

Aqueous Ammonia usage rate (gal/hr) = 54.20 Based on similar budgetary quote from Babcock Power Assumed hours of operation (hrs/yr) = 7,992 Maximum hours of operation $215,007 Calculation (b) Natural Gas Costs Natural gas cost ($/1000 scf) = 4.84 Provided by facility Natural gas uasge rate (scf/min) = 9.90 Based on similar budgetary quote from Babcock Power Assumed hours of operation (hrs/yr) = 7,992 Maximum hours of operation $22,975 Calculation (c) Electricity Electricity cost ($/kWh) = 0.07 Provided by facility

Electricity uasge rate (RSCR System) (kW) = 217.4 Based on similar budgetary quote from Babcock Power Assumed hours of operation (hrs/yr) = 7,992 Maximum hours of operation $118,127 Calculation (d) Compressed Air Compressed air cost ($/1000 scf) = 0.36 Estimate

Compressed air usage rate (scf/min) = 8 Based on similar budgetary quote from Babcock Power Assumed hours of operation (hrs/yr) = 7,992 Maximum hours of operation $1,302 Calculation

Total Direct Variable Costs (D) $357,410 Calculation (2) Semivariable Costs (a) Labor O = $17.00 M = $25.00 Provided by facility (a1) Operating (O) = (0.0 hrs/shift x 3 shifts/day x day/24hrs x 7,992 hrs/yr x $17.0/hr) $0 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (a2) Supervisory (0.15 O) $0 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (b) Maintenance Materials and Labor (M) = (0.015 x ATCI) $89,360 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. Total Semivariable Costs (E) $89,360 Calculation Total Annual Direct Cost of O&M (DCO&M) = (D + E) $446,770 Calculation INDIRECT COSTS (O&M): (1) Overhead (60% of Sum of Operating & Supervisory Labor) $0 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (2) Property Tax (0.01 TCI) $61,630 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (3) Insurance (0.01 TCI) $61,630 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. Total Annual Indirect Costs of O&M (ICO&M) $123,259 Calculation TOTAL ANNUAL COSTS of O&M (TAO&M) = (DCO&M + ICO&M): $570,029 Calculation

COST EFFECTIVENESS OF REGENERATIVE SELECTIVE CATALYTIC REDUCTION

Capital Recovery Cost of Catalyst (CRCc) $82,700 Capital Recovery Cost of Device (CRCd) $783,200 Total Annual Costs of O&M (TAO&M) $570,029 Total Annualized Cost (TAC) = (CRCc + CRCd + TAO&M) $1,435,929 Control Device Loading Rate (tons/yr) 92 Control Device efficiency (%) 75% Pollutant Removed (tons/yr) 69 Pollutant Emitted from New Device (tons/year) 23 COST EFFECTIVENESS ($/ton of pollutant removed) $20,875.79 Line Item
TOTAL ANNUAL O&M COST FOR REGENERATIVE SELECTIVE CATALYTIC REDUCTION

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 1 of 2 REGENERATIVE SELECTIVE CATALYTIC REDUCTION COST DATA

SOLAGEN Predryer CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

NO X Removal

Cost Cost Source / Reference
TOTAL CAPITAL COST FOR REGENERATIVE SELECTIVE CATALYTIC REDUCTION
DIRECT COSTS (capital investment) (1) Purchased Equipment Costs: (a) Basic Equipment and Auxiliaries (A) $1,527,552 Based on similar budgetary quote from Babcock Power (b) Instrumentation

-- Included in (1A) (c) Freight and Taxes

-- Included in (1A) (d) Urea to Ammonia Conversion Plant $0 uneeded; System uses aqueous ammonia Total Equipment Cost (B): $1,527,552
(2) Direct Installation Costs: (a) Foundations and Supports (0.04B) $61,102 APC Manual; Costs fators for baghouse, assumed equal to RSCR (b) Erection and Handling (Mechnical Installation) (0.5B) $763,776 APC Manual; Costs fators for baghouse, assumed equal to RSCR (c) Electrical (0.08B) $122,204 APC Manual; Costs fators for baghouse, assumed equal to RSCR (d) Piping (0.01B) $15,276 APC Manual; Costs fators for baghouse, assumed equal to RSCR (e) Initial Reagent Volume $5,956 Assumes 12,000 gallons at $0.50 per gallon (f) Auxiliary equipment

-- Included in 1A (g) Painting (0.04B) $61,102 APC Manual; Costs fators for baghouse, assumed equal to RSCR (h) Fan and Stack Ductwork $1,000,000 Engineering Estimate Total Installation Cost (C) $2,029,416 Calculation Total Direct Costs of Capital Investment (DCCI) = (B + C) $3,556,967 Calculation INDIRECT COSTS (capital investment): (1) Engineering Costs (0.1A) $152,755 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (2) Process Contingencies (0.05A) $76,378 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (2) General Facilities (0.05A) $76,378 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. Total Indirect Costs of Capital Investment (ICCI) $305,510 Calculation Project Contingency (0.15[A+B]) $579,372 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. TOTAL CAPITAL INVESTMENT (TCI) = (DCCI + ICCI + PC): $4,441,849 Calculation ANNUALIZED COST OF CAPITAL INVESTMENT (CATALYST) (1) Interest Rate 10.0% Assumed (2) Control System Economic Life (years) (3) Vendor Guarantee (3) Price of Replacement Catalyst (C C ) $121,037 Based on similar budgetary quote from Babcock Power (5) Capital Recovery Factor (CRF) (0.402) Calculation (6) Capital Recovery Cost (CCRC) = (CRF x C C ) $48,700 Calculation ADJUSTED CAPITAL INVESTMENT (ATCI) = (TCI) - (C C ) $4,320,812 Calculation
ANNUALIZED COST OF CAPITAL INVESTMENT (1) Interest Rate 10.0% Assumed (2) Control System Economic Life (years) (15) EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (3) Capital Recovery Factor (CRF) (0.131) Calculation (4) Capital Recovery Cost (CRC) = (CRF X TCI) $568,100 Calculation Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 2 of 2 REGENERATIVE SELECTIVE CATALYTIC REDUCTION COST DATA

SOLAGEN Predryer CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

NO X Removal

Cost Cost Source / Reference

DIRECT COSTS (O&M): (1) Variable Costs (a) Aqueous Ammonia Aqueous Ammonia ($/gal) = 0.50 Estimate based on information provided by facility

Aqueous Ammonia usage rate (gal/hr) = 54.20 Based on similar budgetary quote from Babcock Power Assumed hours of operation (hrs/yr) = 5,616 Maximum hours of operation $151,094 Calculation (b) Natural Gas Costs Natural gas cost ($/1000 scf) = 4.84 Provided by facility Natural gas uasge rate (scf/min) = 5.83 Based on similar budgetary quote from Babcock Power Assumed hours of operation (hrs/yr) = 5,616 Maximum hours of operation $9,503 Calculation (c) Electricity Electricity cost ($/kWh) = 0.07 Provided by facility

Electricity uasge rate (RSCR System) (kW) = 127.9 Based on similar budgetary quote from Babcock Power Assumed hours of operation (hrs/yr) = 5,616 Maximum hours of operation $48,860 Calculation (d) Compressed Air Compressed air cost ($/1000 scf) = 0.36 Estimate

Compressed air usage rate (scf/min) = 4 Based on similar budgetary quote from Babcock Power Assumed hours of operation (hrs/yr) = 5,616 Maximum hours of operation $538 Calculation

Total Direct Variable Costs (D) $209,995 Calculation (2) Semivariable Costs (a) Labor O = $17.00 M = $25.00 Provided by facility (a1) Operating (O) = (0.0 hrs/shift x 3 shifts/day x day/24hrs x 7,992 hrs/yr x $17.0/hr) $0 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (a2) Supervisory (0.15 O) $0 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (b) Maintenance Materials and Labor (M) = (0.015 x ATCI) $64,812 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. Total Semivariable Costs (E) $64,812 Calculation Total Annual Direct Cost of O&M (DCO&M) = (D + E) $274,807 Calculation INDIRECT COSTS (O&M): (1) Overhead (60% of Sum of Operating & Supervisory Labor) $0 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (2) Property Tax (0.01 TCI) $44,418 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. (3) Insurance (0.01 TCI) $44,418 EPA APC Manual; Cost factors for SCR, assumed equal to RSCR. Total Annual Indirect Costs of O&M (ICO&M) $88,837 Calculation TOTAL ANNUAL COSTS of O&M (TAO&M) = (DCO&M + ICO&M): $363,644 Calculation

COST EFFECTIVENESS OF REGENERATIVE SELECTIVE CATALYTIC REDUCTION

Capital Recovery Cost of Catalyst (CRCc) $48,700 Capital Recovery Cost of Device (CRCd) $568,100 Total Annual Costs of O&M (TAO&M) $363,644 Total Annualized Cost (TAC) = (CRCc + CRCd + TAO&M) $980,444 Control Device Loading Rate (tons/yr) 58 Control Device efficiency (%) 75% Pollutant Removed (tons/yr) 43 Pollutant Emitted from New Device (tons/year) 14 COST EFFECTIVENESS ($/ton of pollutant removed) $22,708.65 Line Item
TOTAL ANNUAL O&M COST FOR REGENERATIVE SELECTIVE CATALYTIC REDUCTION

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 1 of 2 BAGHOUSE COST DATA LINE 1 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

PM Removal
Cost Cost Source / Reference
TOTAL CAPITAL COST FOR BAGHOUSE
DIRECT COSTS (capital investment) (1) Purchased Equipment Costs: (a) Fabric Filter + Bags + Auxiliaries Equipment (A) $1,600,000 Vendor quotes (b) Instrumentation (0.10 A) Included in (1) (c) Freight and Taxes (0.08 A) Included in (1) Total Equipment Cost (B): $1,600,000
(2) Direct Installation Costs: (a) Foundations and Supports (0.04 B) $64,000 EPA APC Manual, baghouse (b) Erection and Handling (0.50 B) $800,000 EPA APC Manual, baghouse (c) Electrical (0.08 B) $128,000 EPA APC Manual, baghouse (d) Piping (0.01 B) $16,000 EPA APC Manual, baghouse (e) Fan + ductwork $134,933 Calculated in Assumptions (f) Painting (0.04 B) $64,000 EPA APC Manual, baghouse (g) Building and Site Preparation (0.01 B) $16,000 Calculation Total Installation Cost (C) $1,222,933 Total Direct Costs of Capital Investment (DCCI) = (B + C) $2,822,933 Calculation INDIRECT COSTS (capital investment): (1) Engineering Costs (0.10 B) $160,000 EPA APC Manual, baghouse (2) Construction and Field Expenses (0.20 B) $320,000 EPA APC Manual, baghouse (3) Contractor Fees (0.10 B) $160,000 EPA APC Manual, baghouse (4) Startup (0.01 B) $16,000 EPA APC Manual, baghouse (5) Performance Test $10,000 (6) Contingencies (0.03 B) $48,000 EPA APC Manual, baghouse Total Indirect Costs of Capital Investment (ICCI) $714,000

TOTAL CAPITAL INVESTMENT (TCI) = (DCCI + ICCI): $3,536,933
ANNUALIZED COST OF CAPITAL INVESTMENT (BAGS) (1) Interest Rate 10.0% (2) Control System Economic Life (years) (2) (3) Total Price of Full Set of Bags (including taxes and freight) (C B ) $19,140 638 bags @ $30 / bag (4) Bag Replacement Labor (C L = B PM /60 x B N X B L ) $3,190 EPA APC Manual, baghouse - Total Person Minutes Required to Change One Bag (B PM ) 12 - Number of Bag to be Replaced (B N ) 638 Calculation - Hourly Labor Rate for Bag Replacement ($/hr) (B L ) $25 (5) Capital Recovery Factor (CRF) (0.576) EPA APC Manual, baghouse (6) Capital Recovery Cost (BCRC) = (CRF x (C B + C L )) $12,900 EPA APC Manual, baghouse ADJUSTED CAPITAL INVESTMENT (ATCI) = (TCI) - (TCB) $3,517,793
ANNUALIZED COST OF CAPITAL INVESTMENT (ALL EQUIPMENT) (1) Interest Rate 10.0% (2) Control System Economic Life (years) (15) (3) Capital Recovery Factor (CRF) (0.131) EPA APC Manual, baghouse (4) Capital Recovery Cost (CRC) = (CRF X ATCI) $462,500 EPA APC Manual, baghouse Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 2 of 2 LINE 1 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

PM Removal

Cost Cost Source / Reference
TOTAL ANNUAL O&M COST FOR BAGHOUSE
DIRECT COSTS (O&M): (1) Variable Costs (a) Utilities Electricity cost ($/kW-h) = 0.0680 Provided by facility Electricity uasge rate (kW-h/yr) = 1,185,299 Calculation $80,600 Calculation (b) Landfill Costs Landfill cost ($/ton) = 59.26 Provided by facility Material to be disposed (ton/yr) = 68 Calculation $4,009 Calculation (c) Compressed Air Costs Compressed air cost ($/1,000 scf) = 0.36 Compressed air usage rate (1,000 scf/yr) = 125,068 Calculation $45,024 Calculation Total Direct Variable Costs (D) $129,633
(2) Semivariable Costs (a) Labor O = $17.00 M = $25.00 Provided by facility

(a1) Operating (O) = (2 hrs/shift x 3 shifts/day x day/24hrs x 7991.95 hrs/yr x $/hr) $33,966 Calculation (a2) Supervisory (0.15 O) $5,100 Calculation (a3) Maintenance (M) = (1 hrs/shift x 3 shifts/day x day/24hrs x 7991.95 hrs/yr x $/hr) $24,975 Calculation (b) Maintenance Materials (M) $16,000 Calculation (c) Replacement Parts

(c1) Initial cost of replacement parts (Cp) = (0.05 B) $80,000 EPA APC Manual, baghouse (c2) Cost of parts replacement labor (Cpl) = (0.01 B) $16,000 EPA APC Manual, baghouse (c3) Interest rate (i) 10% (c4) Replacement parts Economic Life (n) (years) 5 (c5) Capital recovery factor of replacement parts (CRFp) 0.26 EPA APC Manual, baghouse (c6) Capital Recovery Cost of replacement parts ([Cp+Cpl] X CRFp) $25,300 EPA APC Manual, baghouse Total Semivariable Costs (E) $105,341
Total Annual Direct Cost of O&M (DCO&M) = (D + E) $234,974
INDIRECT COSTS (O&M): (1) Overhead (60% of Sum of Operating, Supervisory, & Maintenance Labor) $38,400 EPA APC Manual, baghouse (2) Property Tax (0.01 TCI) $35,400 EPA APC Manual, baghouse (3) Insurance (0.01 TCI) $35,400 EPA APC Manual, baghouse (4) Administration (0.02 TCI) $70,700 EPA APC Manual, baghouse Total Annual Indirect Costs of O&M (ICO&M) $179,900
TOTAL ANNUAL COSTS of O&M (TAO&M) = (DCO&M + ICO&M): $414,874
COST EFFECTIVENESS OF BAGHOUSE
Capital Recovery Cost Of Bags (BCRC) $12,900 Capital Recovery Cost of Equipment (CRC) $462,500 Total Annual Costs of O&M (TAO&M) $414,874 Total Annualized Cost (TAC) = (CRC + TAO&M) $890,274 Pollutant Cost ($/ton) $13,160 Tons Pollutant Controlled per Year (tons/yr) 67.6 Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 1 of 2 BAGHOUSE COST DATA LINE 2 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

PM Removal
Cost Cost Source / Reference
TOTAL CAPITAL COST FOR BAGHOUSE
DIRECT COSTS (capital investment) (1) Purchased Equipment Costs: (a) Fabric Filter + Bags + Auxiliaries Equipment (A) $1,300,000 Vendor quotes (b) Instrumentation (0.10 A) Included in (1) (c) Freight and Taxes (0.08 A) Included in (1) Total Equipment Cost (B): $1,300,000
(2) Direct Installation Costs: (a) Foundations and Supports (0.04 B) $52,000 EPA APC Manual, baghouse (b) Erection and Handling (0.50 B) $650,000 EPA APC Manual, baghouse (c) Electrical (0.08 B) $104,000 EPA APC Manual, baghouse (d) Piping (0.01 B) $13,000 EPA APC Manual, baghouse (e) Fan + ductwork $132,027 Calculated in Assumptions (f) Painting (0.04 B) $52,000 EPA APC Manual, baghouse (g) Building and Site Preparation (0.01 B) $13,000 Calculation (h) Elevated Platform $200,000 Total Installation Cost (C) $1,216,027 Calculation Total Direct Costs of Capital Investment (DCCI) = (B + C) $2,516,027 INDIRECT COSTS (capital investment): EPA APC Manual, baghouse (1) Engineering Costs (0.10 B) $130,000 EPA APC Manual, baghouse (2) Construction and Field Expenses (0.20 B) $260,000 EPA APC Manual, baghouse (3) Contractor Fees (0.10 B) $130,000 EPA APC Manual, baghouse (4) Startup (0.01 B) $13,000 (5) Performance Test $10,000 EPA APC Manual, baghouse (6) Contingencies (0.03 B) $39,000 Total Indirect Costs of Capital Investment (ICCI) $582,000

TOTAL CAPITAL INVESTMENT (TCI) = (DCCI + ICCI): $3,098,027
ANNUALIZED COST OF CAPITAL INVESTMENT (BAGS) (1) Interest Rate 10.0% (2) Control System Economic Life (years) (2) 464 bags @ $30 / bag (3) Total Price of Full Set of Bags (including taxes and freight) (C B ) $13,920 EPA APC Manual, baghouse (4) Bag Replacement Labor (C L = B PM /60 x B N X B L ) $2,320 - Total Person Minutes Required to Change One Bag (B PM ) 12 Calculation - Number of Bag to be Replaced (B N ) 464 - Hourly Labor Rate for Bag Replacement ($/hr) (B L ) $25 EPA APC Manual, baghouse (5) Capital Recovery Factor (CRF) (0.576) EPA APC Manual, baghouse (6) Capital Recovery Cost (BCRC) = (CRF x (C B + C L )) $9,400
ADJUSTED CAPITAL INVESTMENT (ATCI) = (TCI) - (TCB) $3,084,107
ANNUALIZED COST OF CAPITAL INVESTMENT (ALL EQUIPMENT) (1) Interest Rate 10.0% (2) Control System Economic Life (years) (15) EPA APC Manual, baghouse (3) Capital Recovery Factor (CRF) (0.131) EPA APC Manual, baghouse (4) Capital Recovery Cost (CRC) = (CRF X ATCI) $405,500 Page 2 of 2 Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

LINE 2 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana PM Removal

Cost Cost Source / Reference
TOTAL ANNUAL O&M COST FOR BAGHOUSE
DIRECT COSTS (O&M): (1) Variable Costs (a) Utilities Provided by facility Electricity cost ($/kW-h) = 0.0680 Calculation Electricity uasge rate (kW-h/yr) = 466,737 Calculation $31,700 (b) Landfill Costs Provided by facility Landfill cost ($/ton) = 59.26 Calculation Material to be disposed (ton/yr) = 23 Calculation $1,360 (c) Compressed Air Costs Compressed air cost ($/1,000 scf) = 0.36 Calculation Compressed air usage rate (1,000 scf/yr) = 61,066 Calculation $21,984
Total Direct Variable Costs (D) $55,043
(2) Semivariable Costs Provided by facility (a) Labor O = $17.00 M = $25.00 Calculation

(a1) Operating (O) = (2 hrs/shift x 3 shifts/day x day/24hrs x 7991.95 hrs/yr x $/hr) $33,966 Calculation (a2) Supervisory (0.15 O) $5,100 Calculation (a3) Maintenance (M) = (1 hrs/shift x 3 shifts/day x day/24hrs x 7991.95 hrs/yr x $/hr) $24,975 Calculation (b) Maintenance Materials (M) $13,000 (c) Replacement Parts EPA APC Manual, baghouse

(c1) Initial cost of replacement parts (Cp) = (0.05 B) $65,000 EPA APC Manual, baghouse (c2) Cost of parts replacement labor (Cpl) = (0.01 B) $13,000 (c3) Interest rate (i) 10% (c4) Replacement parts Economic Life (n) (years) 5 EPA APC Manual, baghouse (c5) Capital recovery factor of replacement parts (CRFp) 0.26 EPA APC Manual, baghouse (c6) Capital Recovery Cost of replacement parts ([Cp+Cpl] X CRFp) $20,600 Total Semivariable Costs (E) $97,641
Total Annual Direct Cost of O&M (DCO&M) = (D + E) $152,684
INDIRECT COSTS (O&M): EPA APC Manual, baghouse (1) Overhead (60% of Sum of Operating, Supervisory, & Maintenance Labor) $38,400 EPA APC Manual, baghouse (2) Property Tax (0.01 TCI) $31,000 EPA APC Manual, baghouse (3) Insurance (0.01 TCI) $31,000 EPA APC Manual, baghouse (4) Administration (0.02 TCI) $62,000 Total Annual Indirect Costs of O&M (ICO&M) $162,400
TOTAL ANNUAL COSTS of O&M (TAO&M) = (DCO&M + ICO&M): $315,084
COST EFFECTIVENESS OF BAGHOUSE
Capital Recovery Cost Of Bags (BCRC) $9,400 Capital Recovery Cost of Equipment (CRC) $405,500 Total Annual Costs of O&M (TAO&M) $315,084 Total Annualized Cost (TAC) = (CRC + TAO&M) $729,984 Pollutant Cost ($/ton) $31,815 Tons Pollutant Controlled per Year (tons/yr) 22.9 Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 1 of 2 WET ELECTROSTATIC PRECIPITATOR COST DATA

LINE 1 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

PM Removal
Cost Cost Source / Reference
TOTAL CAPITAL COST FOR WET ELECTROSTATIC PRECIPITATOR
Estimated Size of ESP (From Above, ft 2 ) 7,800 EPA APC Manual, ESP Vendor Supplied Quote for ESP ($) $2,250,000 DIRECT COSTS (capital investment) (1) Purchased Equipment Costs: (a) Basic Equipment and Auxiliaries (A) $2,250,000 (b) Instrumentation (0.10 A) Included in (A) (c) Freight and Taxes (0.08 A) Included in (A) Total Equipment Cost (B): $2,250,000
(2) Direct Installation Costs: (a) Foundations and Supports (0.04 B) $90,000 EPA APC Manual, ESP (b) Erection and Handling (0.50 B) $1,125,000 EPA APC Manual, ESP (c) Electrical (0.08 B) $180,000 EPA APC Manual, ESP (d) Piping (0.01 B) $22,500 EPA APC Manual, ESP (e) Fan + Ductwork $134,933 Calculated in Assumptions (f) Painting (0.02 B) $45,000 EPA APC Manual, ESP (g) Building and Site Preparation (0.01 B) $22,500 (h) Water Treatment System $475,000 Calculated in Assumptions Total Installation Cost (C) $2,094,933 Total Direct Costs of Capital Investment (DCCI) = (B + C) $4,344,933 INDIRECT COSTS (capital investment): (1) Engineering Costs (0.20 B) $450,000 EPA APC Manual, ESP (2) Construction and Field Expenses (0.20 B) $450,000 EPA APC Manual, ESP (3) Contractor Fees (0.10 B) $225,000 EPA APC Manual, ESP (4) Startup (0.01 B) $22,500 EPA APC Manual, ESP (5) Performance Test $10,000 (6) Model Study (0.02 B) $45,000 EPA APC Manual, ESP (7) Contingencies (0.03 B) $67,500 EPA APC Manual, ESP Total Indirect Costs of Capital Investment (ICCI) $1,270,000
TOTAL CAPITAL INVESTMENT (TCI) = (DCCI + ICCI): $5,614,933

ANNUALIZED COST OF CAPITAL INVESTMENT (1) Interest Rate 10.0% (2) Control System Economic Life (years) (15) (3) Capital Recovery Factor (CRF) (0.131) EPA APC Manual, ESP (4) Capital Recovery Cost (CRC) = (CRF X TCB) $738,200 EPA APC Manual, ESP Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 2 of 2 WET ELECTROSTATIC PRECIPITATOR COST DATA

LINE 1 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

PM Removal
Cost Cost Source / Reference
TOTAL ANNUAL O&M COST FOR WET ELECTROSTATIC PRECIPITATOR
DIRECT COSTS (O&M): (1) Variable Costs (a) Utilities Electricity cost ($/kW-h) = 0.07 Provided by facility Electricity uasge rate (kW-h/yr) = 192,675 Calculation $13,100 Calculation (b) Landfill Costs Landfill cost ($/ton) = 59.26 Provided by facility Material to be disposed (ton/yr) = 67 Calculation $3,968 Calculation (c) Water Wash water cost ($/1,000 gal) = 3.16 Wash water usage rate (Mgal/yr) = 386 Calculation $1,218 Calculation Wash treatment cost ($/1,000 gal) = 1.50 Water treatment rate (Mgal/yr) = 386 Calculation $579 Calculation

Total Direct Variable Costs (D) $18,865
(2) Semivariable Costs (a) Labor O = $17.00 M = $25.00 Provided by facility

(a1) Operating (O) = (0.5 hrs/shift x 3 shifts/day x day/24hrs x 7991.95 hrs/yr x $17/hr) $8,491 (a2) Supervisory (0.15 O) $1,300 (a3) Maintenance (M) = (0.5 hrs/shift x 3 shifts/day x day/24hrs x 7991.95 hrs/yr x $25/hr) $12,487 (b) Maintenance Materials (M) (1% of Purchased Equipment Costs) $22,500 (c) Replacement Parts

(c1) Initial cost of replacement parts (Cp) = (0.05 B) $112,500 EPA APC Manual, ESP (c2) Cost of parts replacement labor (Cpl) = (0.01 B) $22,500 EPA APC Manual, ESP (c3) Interest rate (i) 10% (c4) Replacement parts Economic Life (n) (years) 5 (c5) Capital recovery factor of replacement parts (CRFp) 0.26 EPA APC Manual, ESP (c6) Capital Recovery Cost of replacement parts ([Cp+Cpl] X CRFp) $35,600 EPA APC Manual, ESP Total Semivariable Costs (E) $80,379
Total Annual Direct Cost of O&M (DCO&M) = (D + E) $99,244
INDIRECT COSTS (O&M): (1) Overhead (60% of Sum of Operating, Supervisory, & Maintenance Labor) $13,400 EPA APC Manual, ESP (2) Property Tax (0.01 TCI) $56,100 EPA APC Manual, ESP (3) Insurance (0.01 TCI) $56,100 EPA APC Manual, ESP (4) Administration (0.02 TCI) $112,300 EPA APC Manual, ESP Total Annual Indirect Costs of O&M (ICO&M) $237,900
TOTAL ANNUAL COSTS of O&M (TAO&M) = (DCO&M + ICO&M): $337,144
COST EFFECTIVENESS OF WET ELECTROSTATIC PRECIPITATOR
Capital Recovery Cost (CRC) $738,200 Total Annual Costs of Operation and Maintenance (TAO&M) $337,144 Total Annualized Cost (TAC) = (CRC + TAO&M) $1,075,344 Pollutant Cost ($/ton) $16,058 Tons Pollutant Controlled per Year (tons/yr) 67.0 Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 1 of 2 WET ELECTROSTATIC PRECIPITATOR COST DATA

LINE 2 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

PM Removal
Cost Cost Source / Reference
TOTAL CAPITAL COST FOR WET ELECTROSTATIC PRECIPITATOR
Estimated Size of ESP (From Above, ft 2 ) 3,900 EPA APC Manual, ESP Vendor Supplied Quote for ESP ($) $1,125,000 DIRECT COSTS (capital investment) (1) Purchased Equipment Costs: (a) Basic Equipment and Auxiliaries (A) $1,125,000 (b) Instrumentation (0.10 A) Included in (A) (c) Freight and Taxes (0.08 A) Included in (A) Total Equipment Cost (B): $1,125,000
(2) Direct Installation Costs: (a) Foundations and Supports (0.04 B) $45,000 EPA APC Manual, ESP (b) Erection and Handling (0.50 B) $562,500 EPA APC Manual, ESP (c) Electrical (0.08 B) $90,000 EPA APC Manual, ESP (d) Piping (0.01 B) $11,250 EPA APC Manual, ESP (e) Fan + Ductwork $50,257 Calculated in Assumptions (f) Painting (0.02 B) $22,500 EPA APC Manual, ESP (g) Building and Site Preparation (0.01 B) $11,250 (h) Water Treatment System $400,000 Calculated in Assumptions Total Installation Cost (C) $1,192,757 Total Direct Costs of Capital Investment (DCCI) = (B + C) $2,317,757 INDIRECT COSTS (capital investment): (1) Engineering Costs (0.20 B) $225,000 EPA APC Manual, ESP (2) Construction and Field Expenses (0.20 B) $225,000 EPA APC Manual, ESP (3) Contractor Fees (0.10 B) $112,500 EPA APC Manual, ESP (4) Startup (0.01 B) $11,250 EPA APC Manual, ESP (5) Performance Test $10,000 (6) Model Study (0.02 B) $22,500 EPA APC Manual, ESP (7) Contingencies (0.03 B) $33,750 EPA APC Manual, ESP Total Indirect Costs of Capital Investment (ICCI) $640,000
TOTAL CAPITAL INVESTMENT (TCI) = (DCCI + ICCI): $2,957,757

ANNUALIZED COST OF CAPITAL INVESTMENT (1) Interest Rate 10.0% (2) Control System Economic Life (years) (15) (3) Capital Recovery Factor (CRF) (0.131) EPA APC Manual, ESP (4) Capital Recovery Cost (CRC) = (CRF X TCB) $388,900 EPA APC Manual, ESP Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 2 of 2 WET ELECTROSTATIC PRECIPITATOR COST DATA

LINE 2 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

PM Removal
Cost Cost Source / Reference
TOTAL ANNUAL O&M COST FOR WET ELECTROSTATIC PRECIPITATOR
DIRECT COSTS (O&M): (1) Variable Costs (a) Utilities Electricity cost ($/kW-h) = 0.07 Provided by facility Electricity uasge rate (kW-h/yr) = 95,495 Calculation $6,500 Calculation (b) Landfill Costs Landfill cost ($/ton) = 59.26 Provided by facility Material to be disposed (ton/yr) = 23 Calculation $1,346 Calculation (c) Water Wash water cost ($/1,000 gal) = 3.16 Wash water usage rate (Mgal/yr) = 188 Calculation $595 Calculation Wash treatment cost ($/1,000 gal) = 1.50 Water treatment rate (Mgal/yr) = 188 Calculation $283 Calculation

Total Direct Variable Costs (D) $8,723
(2) Semivariable Costs (a) Labor O = $17.00 M = $25.00 Provided by facility

(a1) Operating (O) = (0.5 hrs/shift x 3 shifts/day x day/24hrs x 7991.95 hrs/yr x $17/hr) $8,491 (a2) Supervisory (0.15 O) $1,300 (a3) Maintenance (M) = (0.5 hrs/shift x 3 shifts/day x day/24hrs x 7991.95 hrs/yr x $25/hr) $12,487 (b) Maintenance Materials (M) (1% of Purchased Equipment Costs) $11,250 (c) Replacement Parts

(c1) Initial cost of replacement parts (Cp) = (0.05 B) $56,300 EPA APC Manual, ESP (c2) Cost of parts replacement labor (Cpl) = (0.01 B) $11,300 EPA APC Manual, ESP (c3) Interest rate (i) 10% (c4) Replacement parts Economic Life (n) (years) 5 (c5) Capital recovery factor of replacement parts (CRFp) 0.26 EPA APC Manual, ESP (c6) Capital Recovery Cost of replacement parts ([Cp+Cpl] X CRFp) $17,800 EPA APC Manual, ESP Total Semivariable Costs (E) $51,329
Total Annual Direct Cost of O&M (DCO&M) = (D + E) $60,052
INDIRECT COSTS (O&M): (1) Overhead (60% of Sum of Operating, Supervisory, & Maintenance Labor) $13,400 EPA APC Manual, ESP (2) Property Tax (0.01 TCI) $29,600 EPA APC Manual, ESP (3) Insurance (0.01 TCI) $29,600 EPA APC Manual, ESP (4) Administration (0.02 TCI) $59,200 EPA APC Manual, ESP Total Annual Indirect Costs of O&M (ICO&M) $131,800
TOTAL ANNUAL COSTS of O&M (TAO&M) = (DCO&M + ICO&M): $191,852
COST EFFECTIVENESS OF WET ELECTROSTATIC PRECIPITATOR
Capital Recovery Cost (CRC) $388,900 Total Annual Costs of Operation and Maintenance (TAO&M) $191,852 Total Annualized Cost (TAC) = (CRC + TAO&M) $580,752 Pollutant Cost ($/ton) $25,569 Tons Pollutant Controlled per Year (tons/yr) 22.7 Line Item

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Cost Cost Source / Reference
TOTAL CAPITAL COST FOR VENTURI SCRUBBER

CEPCI 2002 395.6 CEPCI 2006 499.6

GENERAL INPUT DATA Total Saturated Flow Out (acfm) 131,015

Scrubber Options Material of Construction Carbon Steel Type of Venturi Unit Fixed Throat A 170 B 0.56 C 0 Calculated Basic Equipment and Auxiliaries Cost (2002 Cost in $ US) $249,562 EPA APC Manual, Wet Scrubber Calculated Basic Equipment and Auxiliaries Cost (2006 Cost in $ US) $315,170 Calculation DIRECT COSTS (capital investment) (1) Purchased Equipment Costs: (a) Basic Equipment and Auxiliaries (A) $315,170 EPA APC Manual, Wet Scrubber (b) Instrumentation (0.10 A) $31,517 EPA APC Manual, Wet Scrubber (c) Freight and Taxes (0.08 A) $25,214 EPA APC Manual, Wet Scrubber Total Equipment Cost (B): $371,900
(2) Direct Installation Costs: (a) Foundations and Supports (0.06 B) $22,314 (b) Erection and Handling (0.4 B) $148,760 EPA APC Manual, Wet Scrubber (c) Electrical (0.01 B) $3,719 EPA APC Manual, Wet Scrubber (d) Piping (0.05 B) $18,595 EPA APC Manual, Wet Scrubber (e) Fan + ductwork $134,933 Calculated in Assumptions (f) Painting (0.01 B) $3,719 EPA APC Manual, Wet Scrubber Total Installation Cost (C) $332,040 Total Direct Costs of Capital Investment (DCCI) = (B + C) $703,940 INDIRECT COSTS (capital investment): (1) Engineering Costs (0.10 B) $37,190 EPA APC Manual, Wet Scrubber (2) Construction and Field Expenses (0.10 B) $37,190 EPA APC Manual, Wet Scrubber (3) Contractor Fees (0.10 B) $37,190 EPA APC Manual, Wet Scrubber (4) Startup (0.01 B) $3,719 EPA APC Manual, Wet Scrubber (5) Performance Test $10,000 (6) Contingencies (.03 B) $11,157 EPA APC Manual, Wet Scrubber Total Indirect Costs of Capital Investment (ICCI) $136,446

TOTAL CAPITAL INVESTMENT (TCI) = (DCCI + ICCI): $840,386

ANNUALIZED COST OF CAPITAL INVESTMENT (1) Interest Rate 10% (2) Control System Economic Life (years) (15) (3) Capital Recovery Factor (CRF) (0.131) EPA APC Manual, Wet Scrubber (4) Capital Recovery Cost (CRC) = (CRF X TCI) $110,500 EPA APC Manual, Wet Scrubber

Line Item

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Cost Cost Source / Reference
TOTAL ANNUAL O&M COST FOR VENTURI SCRUBBER
DIRECT COSTS (O&M): (1) Variable Costs (a) Utilities Electricity cost ($/kW-h) = 0.068 Provided by facility

Electricity uasge rate (kW-h/yr) = 2,754,170 Calculation $187,300 Calculation Water cost ($/1,000 gal) = $3.16 Water usage rate (Mgal/yr) = 16,540 Calculation $52,200 Calculation (b) Waste Treatment Wash treatment cost ($/1,000 gal) = $1.50 Water treatment rate (Mgal/yr) = 16,540 Calculation $24,800 Calculation Total Direct Variable Costs (D) $264,300
(2) Semivariable Costs (a) Labor O = $17.00 M = $25.00 Provided by facility

(a1) Operating (O) = (5 hrs/shift x 2 shifts/day x day/24hrs x 7991.95 hrs/yr x $/hr) $56,610 Calculation (a2) Supervisory (0.15O) $8,500 EPA APC Manual, Wet Scrubber (a3) Maintenance (M) = (1.5 hrs/shift x 2 shifts/day x day/24hrs x 7991.95 hrs/yr x $/hr) $24,975 Calculation (b) Maintenance Materials (M) $24,975 (c) Replacement Parts

(c1) Initial cost of replacement parts (Cp) = (0.05B) $18,600 EPA APC Manual, Wet Scrubber (c2) Cost of parts replacement labor (Cpl) = (0.01B) $3,700 EPA APC Manual, Wet Scrubber (c3) Interest rate (i) 10% (c4) Replacement parts Economic Life (n) (years) 5 (c5) Capital recovery factor of replacement parts (CRFp) 0.264 EPA APC Manual, Wet Scrubber (c6) Capital Recovery Cost of replacement parts ([Cp+Cpl] X CRFp) $5,900 EPA APC Manual, Wet Scrubber Total Semivariable Costs (E) $120,959
Total Annual Direct Cost of O&M (DCO&M) = (D + E) $385,259
INDIRECT COSTS (O&M): (1) Overhead (60% of Sum of Operating, Supervisory, & Maintenance Labor & Material Costs) $69,000 EPA APC Manual, Wet Scrubber (2) Property Tax (0.01 TCI) $8,400 EPA APC Manual, Wet Scrubber (3) Insurance (0.01 TCI) $8,400 EPA APC Manual, Wet Scrubber (4) Administration (0.02 TCI) $16,800 EPA APC Manual, Wet Scrubber Total Annual Indirect Costs of O&M (ICO&M) $102,600
TOTAL ANNUAL COSTS of O&M (TAO&M) = (DCO&M + ICO&M): $487,859
COST EFFECTIVENESS OF VENTURI SCRUBBER
Capital Recovery Cost (CRC) $110,500 Total Annual Costs of O&M (TAO&M) $487,859 Total Annualized Cost (TAC) = (CRC + TAO&M) $598,359 Pollutant Cost ($/ton) $11,676 Tons Pollutant Controlled per Year (tons/yr) 51.2 Line Item

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Page 1 of 2 VENTURI SCRUBBER COST DATA LINE 2 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

PM Removal
Cost Cost Source / Reference
TOTAL CAPITAL COST FOR VENTURI SCRUBBER

CEPCI 2002 395.6 CEPCI 2006 499.6

GENERAL INPUT DATA Total Saturated Flow Out (acfm) 63,674

Scrubber Options Material of Construction Carbon Steel Type of Venturi Unit Fixed Throat A 170 B 0.56 C 0 Calculated Basic Equipment and Auxiliaries Cost (2002 Cost in $ US) $166,609 EPA APC Manual, Wet Scrubber Calculated Basic Equipment and Auxiliaries Cost (2006 Cost in $ US) $210,409 Calculation DIRECT COSTS (capital investment) (1) Purchased Equipment Costs: (a) Basic Equipment and Auxiliaries (A) $210,409 EPA APC Manual, Wet Scrubber (b) Instrumentation (0.10 A) $21,041 EPA APC Manual, Wet Scrubber (c) Freight and Taxes (0.08 A) $16,833 EPA APC Manual, Wet Scrubber Total Equipment Cost (B): $248,282
(2) Direct Installation Costs: (a) Foundations and Supports (0.06 B) $14,897 (b) Erection and Handling (0.4 B) $99,313 EPA APC Manual, Wet Scrubber (c) Electrical (0.01 B) $2,483 EPA APC Manual, Wet Scrubber (d) Piping (0.05 B) $12,414 EPA APC Manual, Wet Scrubber (e) Fan + ductwork $50,257 Calculated in Assumptions (f) Painting (0.01 B) $2,483 EPA APC Manual, Wet Scrubber Total Installation Cost (C) $181,846 Total Direct Costs of Capital Investment (DCCI) = (B + C) $430,129 INDIRECT COSTS (capital investment): (1) Engineering Costs (0.10 B) $24,828 EPA APC Manual, Wet Scrubber (2) Construction and Field Expenses (0.10 B) $24,828 EPA APC Manual, Wet Scrubber (3) Contractor Fees (0.10 B) $24,828 EPA APC Manual, Wet Scrubber (4) Startup (0.01 B) $2,483 EPA APC Manual, Wet Scrubber (5) Performance Test $10,000 (6) Contingencies (.03 B) $7,448 EPA APC Manual, Wet Scrubber Total Indirect Costs of Capital Investment (ICCI) $94,416

TOTAL CAPITAL INVESTMENT (TCI) = (DCCI + ICCI): $524,545

ANNUALIZED COST OF CAPITAL INVESTMENT (1) Interest Rate 10% (2) Control System Economic Life (years) (15) (3) Capital Recovery Factor (CRF) (0.131) EPA APC Manual, Wet Scrubber (4) Capital Recovery Cost (CRC) = (CRF X TCI) $69,000 EPA APC Manual, Wet Scrubber

Line Item

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Cost Cost Source / Reference
TOTAL ANNUAL O&M COST FOR VENTURI SCRUBBER
DIRECT COSTS (O&M): (1) Variable Costs (a) Utilities Electricity cost ($/kW-h) = 0.068 Provided by facility

Electricity uasge rate (kW-h/yr) = 1,344,751 Calculation $91,400 Calculation Water cost ($/1,000 gal) = $3.16 Water usage rate (Mgal/yr) = 16,540 Calculation $52,200 Calculation (b) Waste Treatment Wash treatment cost ($/1,000 gal) = $1.50 Water treatment rate (Mgal/yr) = 16,540 Calculation $24,800 Calculation Total Direct Variable Costs (D) $168,400
(2) Semivariable Costs (a) Labor O = $17.00 M = $25.00 Provided by facility

(a1) Operating (O) = (5 hrs/shift x 2 shifts/day x day/24hrs x 7991.95 hrs/yr x $/hr) $56,610 Calculation (a2) Supervisory (0.15O) $8,500 EPA APC Manual, Wet Scrubber (a3) Maintenance (M) = (1.5 hrs/shift x 2 shifts/day x day/24hrs x 7991.95 hrs/yr x $/hr) $24,975 Calculation (b) Maintenance Materials (M) $24,975 (c) Replacement Parts

(c1) Initial cost of replacement parts (Cp) = (0.05B) $12,400 EPA APC Manual, Wet Scrubber (c2) Cost of parts replacement labor (Cpl) = (0.01B) $2,500 EPA APC Manual, Wet Scrubber (c3) Interest rate (i) 10% (c4) Replacement parts Economic Life (n) (years) 5 (c5) Capital recovery factor of replacement parts (CRFp) 0.264 EPA APC Manual, Wet Scrubber (c6) Capital Recovery Cost of replacement parts ([Cp+Cpl] X CRFp) $3,900 EPA APC Manual, Wet Scrubber Total Semivariable Costs (E) $118,959
Total Annual Direct Cost of O&M (DCO&M) = (D + E) $287,359
INDIRECT COSTS (O&M): (1) Overhead (60% of Sum of Operating, Supervisory, & Maintenance Labor & Material Costs) $69,000 EPA APC Manual, Wet Scrubber (2) Property Tax (0.01 TCI) $5,200 EPA APC Manual, Wet Scrubber (3) Insurance (0.01 TCI) $5,200 EPA APC Manual, Wet Scrubber (4) Administration (0.02 TCI) $10,500 EPA APC Manual, Wet Scrubber Total Annual Indirect Costs of O&M (ICO&M) $89,900
TOTAL ANNUAL COSTS of O&M (TAO&M) = (DCO&M + ICO&M): $377,259
COST EFFECTIVENESS OF VENTURI SCRUBBER
Capital Recovery Cost (CRC) $69,000 Total Annual Costs of O&M (TAO&M) $377,259 Total Annualized Cost (TAC) = (CRC + TAO&M) $446,259 Pollutant Cost ($/ton) $25,673 Tons Pollutant Controlled per Year (tons/yr) 17.4 Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 1 of 2 VENTURI SCRUBBER COST DATA SOLAGEN Predryer CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

PM Removal
Cost Cost Source / Reference
TOTAL CAPITAL COST FOR VENTURI SCRUBBER

CEPCI 2002 395.6 CEPCI 2006 499.6

GENERAL INPUT DATA Total Saturated Flow Out (acfm) 37,478

Scrubber Options Material of Construction Carbon Steel Type of Venturi Unit Fixed Throat A 170 B 0.56 C 0 Calculated Basic Equipment and Auxiliaries Cost (2002 Cost in $ US) $123,821 EPA APC Manual, Wet Scrubber Calculated Basic Equipment and Auxiliaries Cost (2006 Cost in $ US) $156,372 Calculation DIRECT COSTS (capital investment) (1) Purchased Equipment Costs: (a) Basic Equipment and Auxiliaries (A) $156,372 EPA APC Manual, Wet Scrubber (b) Instrumentation (0.10 A) $15,637 EPA APC Manual, Wet Scrubber (c) Freight and Taxes (0.08 A) $12,510 EPA APC Manual, Wet Scrubber Total Equipment Cost (B): $184,519
(2) Direct Installation Costs: (a) Foundations and Supports (0.06 B) $11,071 (b) Erection and Handling (0.4 B) $73,808 EPA APC Manual, Wet Scrubber (c) Electrical (0.01 B) $1,845 EPA APC Manual, Wet Scrubber (d) Piping (0.05 B) $9,226 EPA APC Manual, Wet Scrubber (e) Fan + ductwork $21,883 Calculated in Assumptions (f) Painting (0.01 B) $1,845 EPA APC Manual, Wet Scrubber Total Installation Cost (C) $119,678 Total Direct Costs of Capital Investment (DCCI) = (B + C) $304,197 INDIRECT COSTS (capital investment): (1) Engineering Costs (0.10 B) $18,452 EPA APC Manual, Wet Scrubber (2) Construction and Field Expenses (0.10 B) $18,452 EPA APC Manual, Wet Scrubber (3) Contractor Fees (0.10 B) $18,452 EPA APC Manual, Wet Scrubber (4) Startup (0.01 B) $1,845 EPA APC Manual, Wet Scrubber (5) Performance Test $10,000 (6) Contingencies (.03 B) $5,536 EPA APC Manual, Wet Scrubber Total Indirect Costs of Capital Investment (ICCI) $72,737

TOTAL CAPITAL INVESTMENT (TCI) = (DCCI + ICCI): $376,934

ANNUALIZED COST OF CAPITAL INVESTMENT (1) Interest Rate 10% (2) Control System Economic Life (years) (15) (3) Capital Recovery Factor (CRF) (0.131) EPA APC Manual, Wet Scrubber (4) Capital Recovery Cost (CRC) = (CRF X TCI) $49,600 EPA APC Manual, Wet Scrubber

Line Item

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Page 2 of 2 VENTURI SCRUBBER COST DATA SOLAGEN Predryer CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

PM Removal
Cost Cost Source / Reference
TOTAL ANNUAL O&M COST FOR VENTURI SCRUBBER
DIRECT COSTS (O&M): (1) Variable Costs (a) Utilities Electricity cost ($/kW-h) = 0.068 Provided by facility

Electricity uasge rate (kW-h/yr) = 556,224 Calculation $37,800 Calculation Water cost ($/1,000 gal) = $3.16 Water usage rate (Mgal/yr) = 611 Calculation $1,900 Calculation (b) Waste Treatment Wash treatment cost ($/1,000 gal) = $1.50 Water treatment rate (Mgal/yr) = 611 Calculation $900 Calculation Total Direct Variable Costs (D) $40,600
(2) Semivariable Costs (a) Labor O = $17.00 M = $25.00 Provided by facility

(a1) Operating (O) = (5 hrs/shift x 2 shifts/day x day/24hrs x 5616.25 hrs/yr x $/hr) $39,782 Calculation (a2) Supervisory (0.15O) $6,000 EPA APC Manual, Wet Scrubber (a3) Maintenance (M) = (1.5 hrs/shift x 2 shifts/day x day/24hrs x 5616.25 hrs/yr x $/hr) $17,551 Calculation (b) Maintenance Materials (M) $17,551 (c) Replacement Parts

(c1) Initial cost of replacement parts (Cp) = (0.05B) $9,200 EPA APC Manual, Wet Scrubber (c2) Cost of parts replacement labor (Cpl) = (0.01B) $1,800 EPA APC Manual, Wet Scrubber (c3) Interest rate (i) 10% (c4) Replacement parts Economic Life (n) (years) 5 (c5) Capital recovery factor of replacement parts (CRFp) 0.264 EPA APC Manual, Wet Scrubber (c6) Capital Recovery Cost of replacement parts ([Cp+Cpl] X CRFp) $2,900 EPA APC Manual, Wet Scrubber Total Semivariable Costs (E) $83,783
Total Annual Direct Cost of O&M (DCO&M) = (D + E) $124,383
INDIRECT COSTS (O&M): (1) Overhead (60% of Sum of Operating, Supervisory, & Maintenance Labor & Material Costs) $48,500 EPA APC Manual, Wet Scrubber (2) Property Tax (0.01 TCI) $3,800 EPA APC Manual, Wet Scrubber (3) Insurance (0.01 TCI) $3,800 EPA APC Manual, Wet Scrubber (4) Administration (0.02 TCI) $7,500 EPA APC Manual, Wet Scrubber Total Annual Indirect Costs of O&M (ICO&M) $63,600
TOTAL ANNUAL COSTS of O&M (TAO&M) = (DCO&M + ICO&M): $187,983
COST EFFECTIVENESS OF VENTURI SCRUBBER
Capital Recovery Cost (CRC) $49,600 Total Annual Costs of O&M (TAO&M) $187,983 Total Annualized Cost (TAC) = (CRC + TAO&M) $237,583 Pollutant Cost ($/ton) $28,704 Tons Pollutant Controlled per Year (tons/yr) 8.3 Line Item

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Page 1 of 2
LINE 1 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

PM Removal

Cost Cost Source / Reference

CEPCI 1988 342.5 CEPCI 2006 499.6

GENERAL INPUT DATA
Material of Construction Carbon Steel Total Saturated Flow Out (acfm) 130,410 Stages 3 A 63 B 0.61 Calculated Basic Equipment and Auxiliaries Cost (1988 Cost in $ US) $166,230 EPA APC Manual, Wet Scrubber Calculated Basic Equipment and Auxiliaries Cost (2006 Cost in $ US) $242,478 Calculation DIRECT COSTS (capital investment) (1) Purchased Equipment Costs: (a) Basic Equipment and Auxiliaries (A) $242,478 EPA APC Manual, Wet Scrubber (b) Instrumentation (0.10 A) $24,248 EPA APC Manual, Wet Scrubber (c) Freight and Taxes (0.08 A) $19,398 EPA APC Manual, Wet Scrubber Total Equipment Cost (B): $286,124
(2) Direct Installation Costs: (a) Foundations and Supports (0.06 B) $17,167 EPA APC Manual, Wet Scrubber (b) Erection and Handling (0.4 B) $114,450 EPA APC Manual, Wet Scrubber (c) Electrical (0.01 B) $2,861 EPA APC Manual, Wet Scrubber (d) Piping (0.05 B) $14,306 EPA APC Manual, Wet Scrubber (e) Fan + ductwork $134,933 Calculated in Assumptions (f) Painting (0.01 B) $2,861 EPA APC Manual, Wet Scrubber Total Installation Cost (C) $286,579 Total Direct Costs of Capital Investment (DCCI) = (B + C) $572,703 INDIRECT COSTS (capital investment): (1) Engineering Costs (0.10 B) $28,612 EPA APC Manual, Wet Scrubber (2) Construction and Field Expenses (0.10 B) $28,612 EPA APC Manual, Wet Scrubber (3) Contractor Fees (0.10 B) $28,612 EPA APC Manual, Wet Scrubber (4) Startup (0.01 B) $2,861 EPA APC Manual, Wet Scrubber (5) Performance Test $10,000 (6) Contingencies (.03 B) $8,584 EPA APC Manual, Wet Scrubber Total Indirect Costs of Capital Investment (ICCI) $107,282

TOTAL CAPITAL INVESTMENT (TCI) = (DCCI + ICCI): $679,985

ANNUALIZED COST OF CAPITAL INVESTMENT (1) Interest Rate 10% (2) Control System Economic Life (years) (15) (3) Capital Recovery Factor (CRF) (0.131) EPA APC Manual, Wet Scrubber (4) Capital Recovery Cost (CRC) = (CRF X TCI) $89,400 EPA APC Manual, Wet Scrubber Line Item WET IMPINGEMENT SCRUBBER COST DATA

TOTAL CAPITAL COST FOR WET IMPINGEMENT SCRUBBER

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Cost Cost Source / Reference
TOTAL ANNUAL O&M COST FOR WET IMPINGEMENT SCRUBBER
DIRECT COSTS (O&M): (1) Variable Costs (a) Utilities (a1) Electricity - Electricity cost ($/kW-h) = $0.068 Provided by facility Electricity uasge rate (kW-h/yr) = 1,711,515 Calculation $116,400 Calculation (a2) Water - Water cost ($/1,000 gal) = $3.16 Water usage rate (Mgal/yr) = 17,959 Calculation $56,700 Calculation (b) Waste Treatment Wash treatment cost ($/1,000 gal) = $1.50 Water treatment rate (Mgal/yr) = 17,959 Calculation $26,900 Calculation

Total Direct Variable Costs (D) $200,000
(2) Semivariable Costs (a) Labor O = $17.00 M = $25.00 Provided by facility (a1) Operating (O) = (0.5 hrs/shift x 2 shifts/day x day/24hrs x 7991.95 hrs/yr x $/hr) $5,661 (a2) Supervisory (0.15O) $800 (a3) Maintenance (M) = (0.5 hrs/shift x 2 shifts/day x day/24hrs x 7991.95 hrs/yr x $/hr) $9,025 (b) Maintenance Materials (M) $9,025 (c) Replacement Parts (c1) Initial cost of replacement parts (Cp) = (0.05B) $14,300 EPA APC Manual, Wet Scrubber (c2) Cost of parts replacement labor (Cpl) = (0.01B) $2,900 EPA APC Manual, Wet Scrubber (c3) Interest rate (i) 10% (c4) Replacement parts Economic Life (n) (years) 5 (c5) Capital recovery factor of replacement parts (CRFp) 0.264 EPA APC Manual, Wet Scrubber (c6) Capital Recovery Cost of replacement parts ([Cp+Cpl] X CRFp) $4,500 EPA APC Manual, Wet Scrubber Total Semivariable Costs (E) $29,011
Total Annual Direct Cost of O&M (DCO&M) = (D + E) $229,011
INDIRECT COSTS (O&M): (1) Overhead (60% of Sum of Operating, Supervisory, & Maintenance Labor) $9,300 EPA APC Manual, Wet Scrubber (2) Property Tax (0.01 TCI) $6,800 EPA APC Manual, Wet Scrubber (3) Insurance (0.01 TCI) $6,800 EPA APC Manual, Wet Scrubber (4) Administration (0.02 TCI) $13,600 EPA APC Manual, Wet Scrubber Total Annual Indirect Costs of O&M (ICO&M) $36,500
TOTAL ANNUAL COSTS of O&M (TAO&M) = (DCO&M + ICO&M): $265,511
COST EFFECTIVENESS OF WET IMPINGEMENT SCRUBBER
Capital Recovery Cost (CRC) $89,400 Total Annual Costs of O&M (TAO&M) $265,511 Total Annualized Cost (TAC) = (CRC + TAO&M) $354,911 Pollutant Cost ($/ton) $5,771.09 Tons Pollutant Controlled per Year (tons/yr) 61

Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 1 of 2
LINE 2 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

PM Removal

Cost Cost Source / Reference

CEPCI 1988 342.5 CEPCI 2006 499.6

GENERAL INPUT DATA
Material of Construction Carbon Steel Total Saturated Flow Out (acfm) 63,674 Stages 3 A 63 B 0.61 Calculated Basic Equipment and Auxiliaries Cost (1988 Cost in $ US) $107,346 EPA APC Manual, Wet Scrubber Calculated Basic Equipment and Auxiliaries Cost (2006 Cost in $ US) $156,585 Calculation DIRECT COSTS (capital investment) (1) Purchased Equipment Costs: (a) Basic Equipment and Auxiliaries (A) $156,585 EPA APC Manual, Wet Scrubber (b) Instrumentation (0.10 A) $15,658 EPA APC Manual, Wet Scrubber (c) Freight and Taxes (0.08 A) $12,527 EPA APC Manual, Wet Scrubber Total Equipment Cost (B): $184,770
(2) Direct Installation Costs: (a) Foundations and Supports (0.06 B) $11,086 EPA APC Manual, Wet Scrubber (b) Erection and Handling (0.4 B) $73,908 EPA APC Manual, Wet Scrubber (c) Electrical (0.01 B) $1,848 EPA APC Manual, Wet Scrubber (d) Piping (0.05 B) $9,238 EPA APC Manual, Wet Scrubber (e) Fan + ductwork $134,933 Calculated in Assumptions (f) Painting (0.01 B) $1,848 EPA APC Manual, Wet Scrubber Total Installation Cost (C) $232,861 Total Direct Costs of Capital Investment (DCCI) = (B + C) $417,631 INDIRECT COSTS (capital investment): (1) Engineering Costs (0.10 B) $18,477 EPA APC Manual, Wet Scrubber (2) Construction and Field Expenses (0.10 B) $18,477 EPA APC Manual, Wet Scrubber (3) Contractor Fees (0.10 B) $18,477 EPA APC Manual, Wet Scrubber (4) Startup (0.01 B) $1,848 EPA APC Manual, Wet Scrubber (5) Performance Test $10,000 (6) Contingencies (.03 B) $5,543 EPA APC Manual, Wet Scrubber Total Indirect Costs of Capital Investment (ICCI) $72,822

TOTAL CAPITAL INVESTMENT (TCI) = (DCCI + ICCI): $490,453

ANNUALIZED COST OF CAPITAL INVESTMENT (1) Interest Rate 10% (2) Control System Economic Life (years) (15) (3) Capital Recovery Factor (CRF) (0.131) EPA APC Manual, Wet Scrubber (4) Capital Recovery Cost (CRC) = (CRF X TCI) $64,500 EPA APC Manual, Wet Scrubber TOTAL CAPITAL COST FOR WET IMPINGEMENT SCRUBBER Line Item WET IMPINGEMENT SCRUBBER COST DATA

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

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PM Removal

Cost Cost Source / Reference
TOTAL ANNUAL O&M COST FOR WET IMPINGEMENT SCRUBBER
DIRECT COSTS (O&M): (1) Variable Costs (a) Utilities (a1) Electricity - Electricity cost ($/kW-h) = $0.068 Provided by facility Electricity uasge rate (kW-h/yr) = 835,664 Calculation $56,800 Calculation (a2) Water - Water cost ($/1,000 gal) = $3.16 Water usage rate (Mgal/yr) = 17,959 Calculation $56,700 Calculation (b) Waste Treatment Wash treatment cost ($/1,000 gal) = $1.50 Water treatment rate (Mgal/yr) = 17,959 Calculation $26,900 Calculation

Total Direct Variable Costs (D) $140,400
(2) Semivariable Costs (a) Labor O = $17.00 M = $25.00 Provided by facility (a1) Operating (O) = (0.5 hrs/shift x 2 shifts/day x day/24hrs x 7991.95 hrs/yr x $/hr) $5,661 (a2) Supervisory (0.15O) $800 (a3) Maintenance (M) = (0.5 hrs/shift x 2 shifts/day x day/24hrs x 7991.95 hrs/yr x $/hr) $9,025 (b) Maintenance Materials (M) $9,025 (c) Replacement Parts (c1) Initial cost of replacement parts (Cp) = (0.05B) $9,200 EPA APC Manual, Wet Scrubber (c2) Cost of parts replacement labor (Cpl) = (0.01B) $1,800 EPA APC Manual, Wet Scrubber (c3) Interest rate (i) 10% (c4) Replacement parts Economic Life (n) (years) 5 (c5) Capital recovery factor of replacement parts (CRFp) 0.264 EPA APC Manual, Wet Scrubber (c6) Capital Recovery Cost of replacement parts ([Cp+Cpl] X CRFp) $2,900 EPA APC Manual, Wet Scrubber Total Semivariable Costs (E) $27,411
Total Annual Direct Cost of O&M (DCO&M) = (D + E) $167,811
INDIRECT COSTS (O&M): (1) Overhead (60% of Sum of Operating, Supervisory, & Maintenance Labor) $9,300 EPA APC Manual, Wet Scrubber (2) Property Tax (0.01 TCI) $4,900 EPA APC Manual, Wet Scrubber (3) Insurance (0.01 TCI) $4,900 EPA APC Manual, Wet Scrubber (4) Administration (0.02 TCI) $9,800 EPA APC Manual, Wet Scrubber Total Annual Indirect Costs of O&M (ICO&M) $28,900
TOTAL ANNUAL COSTS of O&M (TAO&M) = (DCO&M + ICO&M): $196,711
COST EFFECTIVENESS OF WET IMPINGEMENT SCRUBBER
Capital Recovery Cost (CRC) $64,500 Total Annual Costs of O&M (TAO&M) $196,711 Total Annualized Cost (TAC) = (CRC + TAO&M) $261,211 Pollutant Cost ($/ton) $12,522.70 Tons Pollutant Controlled per Year (tons/yr) 21

Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 1 of 2
SOLAGEN Predryer CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

PM Removal

Cost Cost Source / Reference

CEPCI 1988 342.5 CEPCI 2006 499.6

GENERAL INPUT DATA
Material of Construction Carbon Steel Total Saturated Flow Out (acfm) 37,478 Stages 3 A 63 B 0.61 Calculated Basic Equipment and Auxiliaries Cost (1988 Cost in $ US) $77,692 EPA APC Manual, Wet Scrubber Calculated Basic Equipment and Auxiliaries Cost (2006 Cost in $ US) $113,328 Calculation DIRECT COSTS (capital investment) (1) Purchased Equipment Costs: (a) Basic Equipment and Auxiliaries (A) $113,328 EPA APC Manual, Wet Scrubber (b) Instrumentation (0.10 A) $11,333 EPA APC Manual, Wet Scrubber (c) Freight and Taxes (0.08 A) $9,066 EPA APC Manual, Wet Scrubber Total Equipment Cost (B): $133,727
(2) Direct Installation Costs: (a) Foundations and Supports (0.06 B) $8,024 EPA APC Manual, Wet Scrubber (b) Erection and Handling (0.4 B) $53,491 EPA APC Manual, Wet Scrubber (c) Electrical (0.01 B) $1,337 EPA APC Manual, Wet Scrubber (d) Piping (0.05 B) $6,686 EPA APC Manual, Wet Scrubber (e) Fan + ductwork $134,933 Calculated in Assumptions (f) Painting (0.01 B) $1,337 EPA APC Manual, Wet Scrubber Total Installation Cost (C) $205,808 Total Direct Costs of Capital Investment (DCCI) = (B + C) $339,535 INDIRECT COSTS (capital investment): (1) Engineering Costs (0.10 B) $13,373 EPA APC Manual, Wet Scrubber (2) Construction and Field Expenses (0.10 B) $13,373 EPA APC Manual, Wet Scrubber (3) Contractor Fees (0.10 B) $13,373 EPA APC Manual, Wet Scrubber (4) Startup (0.01 B) $1,337 EPA APC Manual, Wet Scrubber (5) Performance Test $10,000 (6) Contingencies (.03 B) $4,012 EPA APC Manual, Wet Scrubber Total Indirect Costs of Capital Investment (ICCI) $55,467

TOTAL CAPITAL INVESTMENT (TCI) = (DCCI + ICCI): $395,002

ANNUALIZED COST OF CAPITAL INVESTMENT (1) Interest Rate 10% (2) Control System Economic Life (years) (15) (3) Capital Recovery Factor (CRF) (0.131) EPA APC Manual, Wet Scrubber (4) Capital Recovery Cost (CRC) = (CRF X TCI) $51,900 EPA APC Manual, Wet Scrubber TOTAL CAPITAL COST FOR WET IMPINGEMENT SCRUBBER Line Item WET IMPINGEMENT SCRUBBER COST DATA

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 2 of 2 WET IMPINGEMENT SCRUBBER COST DATA SOLAGEN Predryer CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

PM Removal

Cost Cost Source / Reference
TOTAL ANNUAL O&M COST FOR WET IMPINGEMENT SCRUBBER
DIRECT COSTS (O&M): (1) Variable Costs (a) Utilities (a1) Electricity - Electricity cost ($/kW-h) = $0.068 Provided by facility Electricity uasge rate (kW-h/yr) = 345,653 Calculation $23,500 Calculation (a2) Water - Water cost ($/1,000 gal) = $3.16 Water usage rate (Mgal/yr) = 611 Calculation $1,900 Calculation (b) Waste Treatment Wash treatment cost ($/1,000 gal) = $1.50 Water treatment rate (Mgal/yr) = 611 Calculation $900 Calculation

Total Direct Variable Costs (D) $26,300
(2) Semivariable Costs (a) Labor O = $17.00 M = $25.00 Provided by facility (a1) Operating (O) = (0.5 hrs/shift x 2 shifts/day x day/24hrs x 5616.25 hrs/yr x $/hr) $3,978 (a2) Supervisory (0.15O) $600 (a3) Maintenance (M) = (0.5 hrs/shift x 2 shifts/day x day/24hrs x 5616.25 hrs/yr x $/hr) $9,025 (b) Maintenance Materials (M) $9,025 (c) Replacement Parts (c1) Initial cost of replacement parts (Cp) = (0.05B) $6,700 EPA APC Manual, Wet Scrubber (c2) Cost of parts replacement labor (Cpl) = (0.01B) $1,300 EPA APC Manual, Wet Scrubber (c3) Interest rate (i) 10% (c4) Replacement parts Economic Life (n) (years) 5 (c5) Capital recovery factor of replacement parts (CRFp) 0.264 EPA APC Manual, Wet Scrubber (c6) Capital Recovery Cost of replacement parts ([Cp+Cpl] X CRFp) $2,100 EPA APC Manual, Wet Scrubber Total Semivariable Costs (E) $24,728
Total Annual Direct Cost of O&M (DCO&M) = (D + E) $51,028
INDIRECT COSTS (O&M): (1) Overhead (60% of Sum of Operating, Supervisory, & Maintenance Labor) $8,200 EPA APC Manual, Wet Scrubber (2) Property Tax (0.01 TCI) $4,000 EPA APC Manual, Wet Scrubber (3) Insurance (0.01 TCI) $4,000 EPA APC Manual, Wet Scrubber (4) Administration (0.02 TCI) $7,900 EPA APC Manual, Wet Scrubber Total Annual Indirect Costs of O&M (ICO&M) $24,100
TOTAL ANNUAL COSTS of O&M (TAO&M) = (DCO&M + ICO&M): $75,128
COST EFFECTIVENESS OF WET IMPINGEMENT SCRUBBER
Capital Recovery Cost (CRC) $51,900 Total Annual Costs of O&M (TAO&M) $75,128 Total Annualized Cost (TAC) = (CRC + TAO&M) $127,028 Pollutant Cost ($/ton) $12,789.35 Tons Pollutant Controlled per Year (tons/yr) 10

Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 1 of 1 DRY SORBENT INJECTION SCRUBBER COST DATA

LINE 1 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

SO 2 Removal

Cost Cost Source / Reference
TOTAL CAPITAL COST FOR DRY SORBENT INJECTION SCRUBBER

DIRECT COSTS (capital investment) (1) Purchased Equipment Costs: (a) Basic Equipment and Auxiliaries (A) $275,000 Vendor Budgetary Quote (b) Instrumentation (0.10 A)

-- Included in A (c) Freight and Taxes (0.08 A) $22,000 Total Equipment Cost (B): $297,000
(2) Direct Installation Costs: (a) Foundations and Supports (0.12 B)

-- Included in A (b) Erection and Handling (0.4 B)

-- Included in A (c) Electrical (0.01 B)

-- Included in A (d) Piping (0.3 B)

-- Included in A (e) Insulation for ductwork (0.01 B)

-- Included in A (f) Painting (0.01 B)

-- Included in A Total Installation Cost (C) $0 Total Direct Costs of Capital Investment (DCCI) = (B + C) $297,000 INDIRECT COSTS (capital investment): (1) Engineering Costs (0.10 B)

-- Included in A (2) Construction and Field Expenses (0.10 B)

-- Included in A (3) Contractor Fees (0.10 B)

-- Included in A (4) Startup (0.01 B)

-- Included in A (5) Performance Test (0.01 B)

-- Included in A (6) Contingencies (.03 B)

-- Included in A Total Indirect Costs of Capital Investment (ICCI) $0

TOTAL CAPITAL INVESTMENT (TCI) = (DCCI + ICCI): $297,000

ANNUALIZED COST OF CAPITAL INVESTMENT (1) Interest Rate 10% (2) Control System Economic Life (years) (15) (3) Capital Recovery Factor (CRF) (0.131) (4) Capital Recovery Cost (CRC) = (CRF X TCI) $39,000
TOTAL ANNUAL O&M COST FOR DRY SORBENT INJECTION SCRUBBER
DIRECT COSTS (O&M): (1) Variable Costs (a) Electricity

Electricity cost ($/kW-hr) = $0.068 Provided by facility Electricity usage rate (kW-hr) = 97 Assumed hours of operation (hrs/yr) = 7,992 $52,700 Calculation (c) Adsorbent

Hydrated lime cost ($/lb) = 0.09 Vendor quote Hydrated lime usage rate (lb/hr) = 4.2 Assumed hours of operation (hrs/yr) = 7,992 $3,100 Calculation Total Direct Variable Costs (D) $52,700
(2) Semivariable Costs (a) Labor O = $17.00 M = $25.00 Provided by facility

(a1) Operating (O) = (0.5 hrs/shift X 3 shifts/day X day/24hrs X 7,992 hrs/yr X $17.0/hr) $8,491 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (a2) Supervisory (0.15 O) $1,300 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (a3) Maintenance (M) = (0.5 hrs/shift X 3 shifts/day X day/24hrs X 7,992 hrs/yr X $25.0/hr) $12,487 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (b) Maintenance Materials (M) $12,487 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. Total Semivariable Costs (E) $34,766 Calculation Total Annual Direct Cost of O&M (DCO&M) = (D + E) $87,466 Calculation INDIRECT COSTS (O&M): (1) Overhead (60% of Sum of Operating, Supervisory, & Maintenance Labor) $13,400 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (2) Property Tax (0.01 TCI) $3,000 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (3) Insurance (0.01 TCI) $3,000 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (4) Administration (0.02 TCI) $5,900 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. Total Annual Indirect Costs of O&M (ICO&M) $25,300 Calculation TOTAL ANNUAL COSTS of O&M (TAO&M) = (DCO&M + ICO&M): $112,766 Calculation COST EFFECTIVENESS OF DRY SORBENT INJECTION SCRUBBER
Capital Recovery Cost (CRC) $39,000 Total Annual Costs of O&M (TAO&M) $112,766 Total Annualized Cost (TAC) = (CRC + TAO&M) $151,766 Control Device Loading Rate (tons/yr) 7 Control Device efficiency (%) 35% Pollutant Removed (tons/yr) 3 Pollutant Emitted from New Device (tons/year) 5 COST EFFECTIVENESS ($/ton of pollutant removed) $60,141.44 Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 1 of 1 DRY SORBENT INJECTION SCRUBBER COST DATA

LINE 2 CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

SO 2 Removal

Cost Cost Source / Reference
TOTAL CAPITAL COST FOR DRY SORBENT INJECTION SCRUBBER

DIRECT COSTS (capital investment) (1) Purchased Equipment Costs: (a) Basic Equipment and Auxiliaries (A) $275,000 Vendor Budgetary Quote (b) Instrumentation (0.10 A)

-- Included in A (c) Freight and Taxes (0.08 A) $22,000 Total Equipment Cost (B): $297,000
(2) Direct Installation Costs: (a) Foundations and Supports (0.12 B)

-- Included in A (b) Erection and Handling (0.4 B)

-- Included in A (c) Electrical (0.01 B)

-- Included in A (d) Piping (0.3 B)

-- Included in A (e) Insulation for ductwork (0.01 B)

-- Included in A (f) Painting (0.01 B)

-- Included in A Total Installation Cost (C) $0 Total Direct Costs of Capital Investment (DCCI) = (B + C) $297,000 INDIRECT COSTS (capital investment): (1) Engineering Costs (0.10 B)

-- Included in A (2) Construction and Field Expenses (0.10 B)

-- Included in A (3) Contractor Fees (0.10 B)

-- Included in A (4) Startup (0.01 B)

-- Included in A (5) Performance Test (0.01 B)

-- Included in A (6) Contingencies (.03 B)

-- Included in A Total Indirect Costs of Capital Investment (ICCI) $0

TOTAL CAPITAL INVESTMENT (TCI) = (DCCI + ICCI): $297,000

ANNUALIZED COST OF CAPITAL INVESTMENT (1) Interest Rate 10% (2) Control System Economic Life (years) (15) (3) Capital Recovery Factor (CRF) (0.131) (4) Capital Recovery Cost (CRC) = (CRF X TCI) $39,000
TOTAL ANNUAL O&M COST FOR DRY SORBENT INJECTION SCRUBBER
DIRECT COSTS (O&M): (1) Variable Costs (a) Electricity

Electricity cost ($/kW-hr) = $0.068 Provided by facility Electricity usage rate (kW-hr) = 97 Assumed hours of operation (hrs/yr) = 7,992 $52,700 Calculation (c) Adsorbent

Hydrated lime cost ($/lb) = 0.09 Vendor quote Hydrated lime usage rate (lb/hr) = 1.9 Assumed hours of operation (hrs/yr) = 7,992 $1,400 Calculation Total Direct Variable Costs (D) $52,700
(2) Semivariable Costs (a) Labor O = $17.00 M = $25.00 Provided by facility

(a1) Operating (O) = (0.5 hrs/shift X 3 shifts/day X day/24hrs X 7,992 hrs/yr X $17.0/hr) $8,491 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (a2) Supervisory (0.15 O) $1,300 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (a3) Maintenance (M) = (0.5 hrs/shift X 3 shifts/day X day/24hrs X 7,992 hrs/yr X $25.0/hr) $12,487 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (b) Maintenance Materials (M) $12,487 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. Total Semivariable Costs (E) $34,766 Calculation Total Annual Direct Cost of O&M (DCO&M) = (D + E) $87,466 Calculation INDIRECT COSTS (O&M): (1) Overhead (60% of Sum of Operating, Supervisory, & Maintenance Labor) $13,400 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (2) Property Tax (0.01 TCI) $3,000 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (3) Insurance (0.01 TCI) $3,000 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (4) Administration (0.02 TCI) $5,900 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. Total Annual Indirect Costs of O&M (ICO&M) $25,300 Calculation TOTAL ANNUAL COSTS of O&M (TAO&M) = (DCO&M + ICO&M): $112,766 Calculation COST EFFECTIVENESS OF DRY SORBENT INJECTION SCRUBBER
Capital Recovery Cost (CRC) $39,000 Total Annual Costs of O&M (TAO&M) $112,766 Total Annualized Cost (TAC) = (CRC + TAO&M) $151,766 Control Device Loading Rate (tons/yr) 3 Control Device efficiency (%) 35% Pollutant Removed (tons/yr) 1 Pollutant Emitted from New Device (tons/year) 2 COST EFFECTIVENESS ($/ton of pollutant removed) $132,222.20 Line Item

Appendix A ESP update.xlsx Golder AssociatesJanuary, 2011 103-99731

Page 1 of 1 DRY SORBENT INJECTION SCRUBBER COST DATA SOLAGEN Predryer CONTROL EQUIPMENT ANALYSIS Roseburg Forest Products, Missoula, Montana

SO 2 Removal

Cost Cost Source / Reference
TOTAL CAPITAL COST FOR DRY SORBENT INJECTION SCRUBBER

DIRECT COSTS (capital investment) (1) Purchased Equipment Costs: (a) Basic Equipment and Auxiliaries (A) $450,000 Vendor Budgetary Quote (b) Instrumentation (0.10 A)

-- Included in A (c) Freight and Taxes (0.08 A) $36,000 Total Equipment Cost (B): $486,000
(2) Direct Installation Costs: (a) Foundations and Supports (0.12 B)

-- Included in A (b) Erection and Handling (0.4 B)

-- Included in A (c) Electrical (0.01 B)

-- Included in A (d) Piping (0.3 B)

-- Included in A (e) Insulation for ductwork (0.01 B)

-- Included in A (f) Painting (0.01 B)

-- Included in A Total Installation Cost (C) $0 Total Direct Costs of Capital Investment (DCCI) = (B + C) $486,000 INDIRECT COSTS (capital investment): (1) Engineering Costs (0.10 B)

-- Included in A (2) Construction and Field Expenses (0.10 B)

-- Included in A (3) Contractor Fees (0.10 B)

-- Included in A (4) Startup (0.01 B)

-- Included in A (5) Performance Test (0.01 B)

-- Included in A (6) Contingencies (.03 B)

-- Included in A Total Indirect Costs of Capital Investment (ICCI) $0

TOTAL CAPITAL INVESTMENT (TCI) = (DCCI + ICCI): $486,000

ANNUALIZED COST OF CAPITAL INVESTMENT (1) Interest Rate 10% (2) Control System Economic Life (years) (15) (3) Capital Recovery Factor (CRF) (0.131) (4) Capital Recovery Cost (CRC) = (CRF X TCI) $63,900
TOTAL ANNUAL O&M COST FOR DRY SORBENT INJECTION SCRUBBER
DIRECT COSTS (O&M): (1) Variable Costs (a) Electricity

Electricity cost ($/kW-hr) = $0.068 Provided by facility Electricity usage rate (kW-hr) = 97 Assumed hours of operation (hrs/yr) = 5,616 $37,000 Calculation (c) Adsorbent

Hydrated lime cost ($/lb) = 0.09 Vendor quote Hydrated lime usage rate (lb/hr) = 2.6 Assumed hours of operation (hrs/yr) = 5,616 $1,400 Calculation Total Direct Variable Costs (D) $37,000
(2) Semivariable Costs (a) Labor O = $17.00 M = $25.00 Provided by facility

(a1) Operating (O) = (0.5 hrs/shift X 3 shifts/day X day/24hrs X 5,616 hrs/yr X $17.0/hr) $5,967 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (a2) Supervisory (0.15 O) $900 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (a3) Maintenance (M) = (0.5 hrs/shift X 3 shifts/day X day/24hrs X 5,616 hrs/yr X $25.0/hr) $8,775 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (b) Maintenance Materials (M) $8,775 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. Total Semivariable Costs (E) $24,418 Calculation Total Annual Direct Cost of O&M (DCO&M) = (D + E) $61,418 Calculation INDIRECT COSTS (O&M): (1) Overhead (60% of Sum of Operating, Supervisory, & Maintenance Labor) $9,400 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (2) Property Tax (0.01 TCI) $4,900 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (3) Insurance (0.01 TCI) $4,900 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. (4) Administration (0.02 TCI) $9,700 EPA APC Manual; Cost factors for Wet Scrubber, assumed equal to Dry Inject. Total Annual Indirect Costs of O&M (ICO&M) $28,900 Calculation TOTAL ANNUAL COSTS of O&M (TAO&M) = (DCO&M + ICO&M): $90,318 Calculation COST EFFECTIVENESS OF DRY SORBENT INJECTION SCRUBBER
Capital Recovery Cost (CRC) $63,900 Total Annual Costs of O&M (TAO&M) $90,318 Total Annualized Cost (TAC) = (CRC + TAO&M) $154,218 Control Device Loading Rate (tons/yr) 3 Control Device efficiency (%) 35% Pollutant Removed (tons/yr) 1 Pollutant Emitted from New Device (tons/year) 2 COST EFFECTIVENESS ($/ton of pollutant removed) $139,475.59 Line Item

Appendix A ESP update.xlsx Golder AssociatesPage 1 of 1 LOW NO X BURNER COST DATA BOILER BURNER REPLACEMENT CONTROL EQUIPMENT ANALYSIS

Roseburg Forest Products, Missoula, Montana

NO X Removal

Cost Cost Source / Reference Capital Cost $498,793 Manufacturer quote Installation Cost $249,397 Manufacturer quote Total Capital Cost (capital cost + installation cost) $748,190

ANNUALIZED COST OF CAPITAL INVESTMENT (1) Interest Rate 10% (2) Control System Economic Life (years) (15) (3) Capital Recovery Factor (CRF) (0.131) (4) Capital Recovery Cost (CRC) = (CRF X TCI) $98,400

COST EFFECTIVENESS OF LOW NO X BURNER
Capital Recovery Cost (CRC) $98,400 Total Annual Costs of O&M (TAO&M) $0 Total Annualized Cost (TAC) = (CRC + TAO&M) $98,400 Control Device Loading Rate (tons/yr) 134 Vendor Quoted Outlet Emissions (tons/yr) 104 Control Device efficiency (%) 22% Pollutant Removed (tons/yr) 30 COST EFFECTIVENESS ($/ton of pollutant removed) $3,295.84 Line ItemGolder, Golder Associates and the GA globe design are trademarks of Golder Associates Corporation 

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