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 ofthe Clean Air Act and relating to Roseburg's Missoula, MT

facility. This request required Roseburg to submit an analysis ofthe 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 ofthe 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 ofthe Smurfit-Stone mill, hundreds offamilies' incomes have been reduced or

eliminated. The Roseburg Missoula mill is one ofthe 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 ofthese 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__. _ Tille
Golder, Golder Associates and the GA globe design are trademarks of Golder Associates Corporation 

A world of

capabilities

delivered locally

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. 103-99731

REPORT
February 2011 ES-1 Project No.103-99731

Final RP Analysis.docx

EXECUTIVE SUMMARY

Golder Associates, Inc. has been retained by Roseburg Forest Products (Roseburg) to prepare a 

Reasonable Progress (RP) 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 such 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 NOx burners as the technically feasible 

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 dryer 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 sources, 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 NOX RP ANALYSIS........................................................................................................................11

3.1 Step 1 - Identify NOx Retrofit Technologies ...............................................................................11

3.1.1 Selective Non-catalytic Reduction (SNCR)............................................................................11

3.1.2 Selective Catalytic Reduction (SCR) and SNCR/SCR Hybrid Systems................................12

3.1.3 Regenerative Selective Catalytic Reduction (RSCR) ............................................................13

3.1.4 Low NOx 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-NOx 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 SO2 RP ANALYSIS ........................................................................................................................17

4.1 Step 1 - Identify SO2 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 Environmental Impacts ..........................................................................................................20

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

5.0 CHOICE OF RP CONTROLS........................................................................................................21

6.0 REFERENCES...............................................................................................................................22

List of Tables

Table 1 BART Source Exhaust Parameters and Emission Rates

Table 2 BART Source Control Options 

Table 3 PM Control Technology Impact Evaluation

Table 4 NOx Control Technology Impact Evaluation

Table 5 SO2 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 Reasonable 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 information 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 

(NOx) and sulfur dioxide (SO2). 

1.1 Applicable Emission Sources, 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 continuous 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 final 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 

sanderdust-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 other 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 currently made any 

project commitments, but is considering a replacement of the burner to improve performance and reduce 

emissions. A low NOx burner for the boiler has been considered in the RP analysis as one possible 

emission reduction option. 

The ROEMMC burner 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 

to 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 exhaust 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-clones1for 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, which 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 dryers. The SolaGen burner is equipped with a 

low NOx burner and flue gas reinjection to reduce NOx 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 source 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 Roseburg Missoula facility are different from multiclones 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 used as references. 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 control 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 situations, 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 and sorbent upstream of the dryers for NOx and SO2 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 technically 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 impacts 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 determination. 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 engineering 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 
February 2011 4 Project No.103-99731

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reasonable progress goals for each Class 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 modeling was not 

expected as part of this submittal.
February 2011 5 Project No.103-99731

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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 multiclones (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 multiclones based on actual hours of operation. For 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 complex 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 analyses. 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 Retrofit 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 technologies 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 multi-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 single, 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 exhaust. 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) cyclones 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 combustion 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 (of 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 are 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 condensable 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 can 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 Fabric Filters (Baghouses)

Fabric filters are used extensively as PM control devices 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 efficient 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 from 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 characteristics, fabric 

characteristics, and cleaning mechanism. In general, collection efficiency increases with decreasing

filtration velocity and increasing particle size. Fabric filters are generally less expensive than electrostatic 

precipitators and they 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 content 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 maintenance 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 equipment. 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 constricted 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 with 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 been 

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 Technically 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 the 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 feasible 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 plugging 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 (including 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 

resources 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 provides 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 effectiveness 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$/Δtons). 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, the 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 increasing 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 electricity. 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 

Missoula, 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 landfill. 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 are 

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 only 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 all 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 NOX RP ANALYSIS

NOx emissions result from the combustion of resonated sanderdust due to the nitrogen content of the 

wood and resin (fuel NOx) as well as from atmospheric nitrogen in the combustion air (thermal NOx). 

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.

NOx emission controls have been analyzed for the boiler, ROEMMC, and SolaGen sanderdust 

combustion devices. Currently there are no NOx add-on emission controls on these devices. However, 

the SolaGen burner was installed in 2006 with a low-NOx burner and flue gas recirculation. The 

controlled NOx emission rate from the SolaGen low-NOx 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 for 

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 NOx 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 

temperatures 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 

combustion 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 combustion 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 gases 

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 NOx control efficiency. However, ammonia is also a contributor to 

atmospheric formation of particulate that can contribute to regional haze. Therefore, the need to reduce 

NOx emissions must be balanced with the need to keep ammonia 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 NOx emissions with ammonia in 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 

combustion 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 NOx emissions, followed by a catalytic (SCR) section that further 

enhances the reduction of NOx 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 

irreversible.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, which 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 reduction of NOx in the presence of the catalyst. In situations where NOx

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 Selective 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 NOx, 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 catalytic reduction (600°F to 800°F) prior to entering an SCR unit. These systems 

have been proven to reduce NOx 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 NOx Burner

Low NOx 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 NOx formation. The SolaGen burner at the Missoula facility already utilizes a low-NOx burner. 

The ROEMMC burner still has a number of years of remaining useful life. However, as part of the 

performance upgrade evaluation of the boiler, low-NOx 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 relies 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 

combined 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 ammonia 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 instances 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 sanderdust 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, there 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 unit 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 these 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 downstream 

of the wood particle dryers.

3.2.4 Low-NOx Burners

A low-NOx burner technology is already in use for the SolaGen sanderdust burner. A low-NOx 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-NOx burner (≈20%)

3.4 Step 4 - Evaluate Impacts and Document Results

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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NOx 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 the 

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 exhaust 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 included 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 

greenhouse gases and other pollutant emissions. In Missoula, the electricity is most likely generated by a 

coal-fired electrical generator.

Low-NOx 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 

is a trade-off between maximizing NOx emission reductions and minimizing ammonia slip.

Low-NOx burners typically result in increased carbon monoxide emissions as thermal NOx 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 NOx emissions and increasing in carbon 

monoxide emissions.
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3.4.4 Useful 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-NOx 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 SO2 RP ANALYSIS

SO2 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 technologies must be considered 

downstream of the dryers where additives would not affect the wood furnish.

SO2 emission controls have been analyzed for the boiler, ROEMMC, and SolaGen sanderdust 

combustion devices. Currently there are no SO2 add-on emission controls 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 SO2 Retrofit Technologies

4.1.1 Wet Scrubber

Wet flue gas desulfurization (FGD) systems (wet scrubbers) remove SO2 from the flue gases by using an 

alkaline reagent to form sulfite and sulfate salts. Wet FGD systems typically utilize a spray absorber 

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 liquid 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 H2SO4 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 the 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 technology, 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 additional 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 

heat 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 removal. 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 SO2.

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 affect 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 predryer. Due to space limitations, neither the boiler or the ROEMMC burner have 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 predryer.
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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 sorbent 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 the 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 effectiveness and 

incremental cost effectiveness. Average cost effectiveness is the annualized cost of control (capital and 

operating expenses) divided by the total tons of SO2 emissions eliminated ($/ton). The incremental cost 

effectiveness is difference in cost between a control option and the next most effective control option 

divided by the additional amount of pollutant material collected (Δ$/Δtons). Individual cost analysis 

spreadsheets are located in Appendix A.

It should be noted that while there are technically feasible solutions, the relatively low emission rate of 

SO2 from all of the sanderdust combustion devices results in an extremely high average cost 

effectiveness. As a result, the benefit of installing controls for SO2 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 fuels 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 energy 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 systems 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 Missoula 

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 activities 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 location 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 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 scrubbers, Roseburg does not currently have a method to dispose of 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 CONTROLS

Based on the analysis above, the utilization of the existing controls constitutes the appropriate 

requirements 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 envelope for RP controls. In developing the 

presumptive BART requirements for large coal fired combustion units, EPA determined that controls 

constituted BART for SO2 emissions when the cost effectiveness values were between $400 and $2,000 

per ton of SO2 removed. Similarly, EPA determined controls for NOx emissions constituted BART when 

the cost was less than $1,500 per ton of NOx removed. The Roseburg control option with the lowest cost 

effectiveness is the low-NOx 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 NOx

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 each 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 regarding 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 the 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 for 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 logistics 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, The McIlvaine Company Hot 

Topic Hour presentation November 6, 2008.

Kurz, Max, Calculations for Engineering Economic Analysis, 1993. McGraw-Hill.

Perry, R.H. and C.H. Chilton, editors. 1973. Chemical Engineers Handbook. 5th Edition. McGraw-Hill.

PPC 2011. 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. Part 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 PM10 emissions PM2.5 emissions SO2

 emissions NOX 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 NOX 

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. PM10 and PM2.5 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 NOX, SO2

, and CO from Wood Residue Combustion, dry wood, September 2003.

(5) Source test conducted April 3, 2007. ROEMMC NOX emission rates based on the average of 2 high-fire test runs. Boiler NOX 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 NOX burner, RTO, and FGR.

(13) Source test of Line 1 and Line 2 dryers conducted September 30, 2004.

(14) Assumes PM2.5 is 75% of PM10 based on a conservative engineering estimate. Condensible PM emissions would be expected to be primarily PM2.5 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 PM10 emissions would be PM2.5. 

(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

SO2

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

NOX

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 NOX 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

NOx 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 NOX. Since only the boiler is subject to Low NOX 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

SO2 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 A
January, 2011 103-99731

Page 1 of 2

REGENERATIVE SELECTIVE CATALYTIC REDUCTION COST DATA 

LINE 1 CONTROL EQUIPMENT ANALYSIS

Roseburg Forest Products, Missoula, Montana

NOX 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 (CC) $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 CC) $169,400 Calculation

ADJUSTED CAPITAL INVESTMENT (ATCI) = (TCI) - (CC) $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 Associates
January, 2011 103-99731

Page 2 of 2

REGENERATIVE SELECTIVE CATALYTIC REDUCTION COST DATA 

LINE 1 CONTROL EQUIPMENT ANALYSIS

Roseburg Forest Products, Missoula, Montana

NOX 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 Associates
January, 2011 103-99731

Page 1 of 2

REGENERATIVE SELECTIVE CATALYTIC REDUCTION COST DATA 

LINE 2 CONTROL EQUIPMENT ANALYSIS

Roseburg Forest Products, Missoula, Montana

NOX 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 (CC) $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 CC) $82,700 Calculation

ADJUSTED CAPITAL INVESTMENT (ATCI) = (TCI) - (CC) $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 Associates
January, 2011 103-99731

Page 2 of 2

REGENERATIVE SELECTIVE CATALYTIC REDUCTION COST DATA 

LINE 2 CONTROL EQUIPMENT ANALYSIS

Roseburg Forest Products, Missoula, Montana

NOX 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 Associates
January, 2011 103-99731

Page 1 of 2

REGENERATIVE SELECTIVE CATALYTIC REDUCTION COST DATA 

SOLAGEN Predryer CONTROL EQUIPMENT ANALYSIS

Roseburg Forest Products, Missoula, Montana

NOX 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 (CC) $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 CC) $48,700 Calculation

ADJUSTED CAPITAL INVESTMENT (ATCI) = (TCI) - (CC) $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 Associates
January, 2011 103-99731

Page 2 of 2

REGENERATIVE SELECTIVE CATALYTIC REDUCTION COST DATA 

SOLAGEN Predryer CONTROL EQUIPMENT ANALYSIS

Roseburg Forest Products, Missoula, Montana

NOX 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 Associates
January, 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) (CB) $19,140 638 bags @ $30 / bag

 (4) Bag Replacement Labor (CL = BPM/60 x BN X BL) $3,190 EPA APC Manual, baghouse

- Total Person Minutes Required to Change One Bag (BPM) 12

- Number of Bag to be Replaced (BN) 638 Calculation

- Hourly Labor Rate for Bag Replacement ($/hr) (BL) $25

 (5) Capital Recovery Factor (CRF) (0.576) EPA APC Manual, baghouse

 (6) Capital Recovery Cost (BCRC) = (CRF x (CB + CL)) $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 Associates
January, 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 Associates
January, 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) (CB) $13,920 EPA APC Manual, baghouse

 (4) Bag Replacement Labor (CL = BPM/60 x BN X BL) $2,320

- Total Person Minutes Required to Change One Bag (BPM) 12 Calculation

- Number of Bag to be Replaced (BN) 464

- Hourly Labor Rate for Bag Replacement ($/hr) (BL) $25 EPA APC Manual, baghouse

 (5) Capital Recovery Factor (CRF) (0.576) EPA APC Manual, baghouse

 (6) Capital Recovery Cost (BCRC) = (CRF x (CB + CL)) $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 Associates
January, 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 Associates
January, 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, ft2) 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 Associates
January, 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 Associates
January, 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, ft2) 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 Associates
January, 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

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

Page 1 of 2

VENTURI SCRUBBER COST DATA 

LINE 1 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) 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

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

Page 2 of 2

VENTURI SCRUBBER COST DATA 

LINE 1 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) = 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

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

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

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

Page 2 of 2

VENTURI SCRUBBER COST DATA 

LINE 2 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) = 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 Associates
January, 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

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

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

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

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

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

Page 2 of 2

WET IMPINGEMENT SCRUBBER 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 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 Associates
January, 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 Associates
January, 2011 103-99731

Page 2 of 2

WET IMPINGEMENT SCRUBBER 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 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 Associates
January, 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 Associates
January, 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 Associates
January, 2011 103-99731

Page 1 of 1

DRY SORBENT INJECTION SCRUBBER COST DATA 

LINE 1 CONTROL EQUIPMENT ANALYSIS

Roseburg Forest Products, Missoula, Montana

SO2 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 Associates
January, 2011 103-99731

Page 1 of 1

DRY SORBENT INJECTION SCRUBBER COST DATA 

LINE 2 CONTROL EQUIPMENT ANALYSIS

Roseburg Forest Products, Missoula, Montana

SO2 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 Associates
January, 2011 103-99731

Page 1 of 1

DRY SORBENT INJECTION SCRUBBER COST DATA 

SOLAGEN Predryer CONTROL EQUIPMENT ANALYSIS

Roseburg Forest Products, Missoula, Montana

SO2 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 Associates
Page 1 of 1

LOW NOX BURNER COST DATA 

BOILER BURNER REPLACEMENT CONTROL EQUIPMENT ANALYSIS

Roseburg Forest Products, Missoula, Montana

NOX 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 NOX 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

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

Golder Associates Inc.

9 Monroe Parkway, Suite 270

Lake Oswego, OR 97035 USA

Tel: (503) 607-1820

Fax: (503) 607-1825