### March 13 , 201 2

U.S. Environmental Protection Agency Region VIII 1595 Wynkoop Street Denver, CO 80202

- 1129 Attention: Vanessa Hinkle, 8P

- AR

Dear Ms. Hinkle:

This letter serves as a revision to the response to the Clean Air Act Section 114(a) request issued by the U.S. Environmental Protection Agency (EPA) Region 8 towards the fulfillment of the Reasonable Progress (RP) goals and strategies under EPA’s Regional Haze Rule, per Title 40 of the Code of Federal Regulations (40 CFR) 51.308(d)(1) and 40 CFR 51.308(d)(3) (herein referred to as “114 request letter”). 1 

### Th e response submitted on February 28, 2011 contained further analysis of control technologies for the Plum Creek Manufacturing (Plum Creek) Columbia Falls Operations’ Riley Stoker Boiler and med ium density fiberboard (MDF) Fiber Dryers and the Plum Creek Evergreen Division’s Riley Stoker Boiler, per EPA’s November 5, 2010 request. In November 2011, EPA Region 8 requested further information from Plum Creek . I n particular
, a more detailed discu ssion of the economic feasibility analysis with cost estimates was requested . As such, this letter retains the information submitted in the February 28, 2011 submittal, and includes the supplementary details r equested by EPA.

The 114 request letter issu ed by the EPA is included as Attachment A to this response. In the letter, EPA requests a control technology analysis for the emission units listed above in order to develop strategies towards achieving RP goals for Montana. In the letter, EPA specifies that the analysis must address the factors included in 40 CFR 51.308(d)(i)(A): the costs of compliance, time necessary for compliance, the energy and non

- air quality environmental im p acts of compliance
, and the remaining useful life of the affected sources . The 114 request letter states that further analysis is warranted for the emission units listed above, based on the information submitted by Plum Creek in March 2009 in response to a previously issued Section 114(a) request regarding a more expansive lis t of emission units at the facilities. 2



### The Regional Haze Rule covers emissions of p articulate m atter (PM), sulfur dioxide (SO 2 

### ), and nitrogen oxides (NO x 

### ). However, detailed control evaluations for emissions of PM and SO 2 

### are not included in this respo nse for the following reasons:

 

### PM emissions are already well

- controlled from all the emission units identified in the 114 request letter.

1 Letter dated November 5, 2010 from Mr. Stephen S. Tuber, EPA Region 8, to Mr. Thomas Ray, Plum Creek Manufacturing, received November 29, 2010, included as Attachment A. 2 The first 114 request regarding RP was issued by EPA Region 8 on January 29, 2009.

### Plum Creek Manufacturing

- Page 2 March 1 3 , 2012

• The Riley Stoker Boilers at the Columbia Falls Operations and at the Evergreen Division are equipped with dry Electrostatic Precipitators (ESPs).

• The Columbia Falls Operations Line 1 MDF Fiber Dryers exhaust through a Wet ESP.

• The Columbia Falls Operations Line 2 MDF Fiber Dryers are equipped with a Venturi Scrubber.

 

### SO 2 

### emissions are minimal from all emission uni ts identified in the 114 request letter.

• The SO 2 

### emissions from the boilers and dryers are expected to be minimal as the units combust wood residue with only trace amounts of sulfur.

• Any residual sulfur in the fuel will be oxidized during the combustion process and would be expected to be captured by the alkaline wood ash, with minimal amounts of SO x 

### exhausting

. 3



### • Commercial

- grade natural gas is used in the Columbia Falls Operations boiler during startup. The natural gas also contains only trace amounts of sulfur.

The control technology evaluation presented in this letter report follows the guidelines for a Best Achievable Retrofit Technology (BART) analysis, per 40 CFR 51, Appendix Y. The report is organized as follows:

 

### Section 1: BART Determination Methodology

 

### Section 2: NO x 

### C ontrol T echnolog y Descriptions

 

### Section 3 : Control Technology Analysis for NO x 

### from the Riley Stoker Boilers

 

### Section 4: Control Technology Analysis for NO x 

### from the Line 2 MDF Fiber Dryers

 

### Section 5: Control Technology Analy sis for NO x 

### from the Line 1 MDF Fiber Dryers

 

### Section 6: Conc l usion

 

### Attachment A: Copy of 114 request letter

 

### Attachment B: Supplemental material for the control technology evaluations

 

### Attachment C: Cost Evaluation of Control Technologies for Boilers and Dryers

 

### Attachment D: Process Flow Diagram of Line 1 and Line 2 Dryers



## S ECTION 

## 1. BART D ETERMINATION 

## M ETHODOLOGY

In the July 6, 2005, final BART Regulations and Guidelines, the EPA established guidelines for performing a BART Determination. 4 

### Essentially, the goal of the BART analysis is to determine

3 NCASI Technical Bulletin No. 884, Compilation of Criteria Air Pollutant Emissions Data for Sources at Pulp and Paper Mills Including Boilers, August 2004. Section 9.5.1 states: “...a significant amount of the fuel sulfur can be capt ured within the boiler itself by the alkaline wood ash.”

### Plum Creek Manufacturing

- Page 3 March 1 3 , 2012

the BART for each unit identified as a BART

- eligible source. In this analysis, there are no BART

- eligible sources. However, the BART determination approach is followed to conduct a control techn ology evaluation for the fulfillment of reasonable progress goals under 40 CFR 51.308(d) (1) and (3). This analysis must take into account several factors:

 

### The availability and feasibility of retrofit control options

 

### Pollution control equipment currently utilized

 

### Costs of compliance for each control option

 

### Remaining useful life of the facility

 

### Energy and environmental impacts of the control options

Note that a visibility impacts analysis was not requested by EPA Region 8, and, thus, it is not included in this report

To guide selection of appropriate case

- by

- case BART limits, EPA noted that the BART Determination evaluation must include the following specific steps (excluding the visibility impacts analysis):

1. Identify all available retrofit control optio ns
2. Eliminate technically infeasible options

3. Evaluate control effectiveness of remaining control technologies

4. Evaluate impacts and document results

Each of these steps is described in the following sections.



### S TEP 

### 1: I DENTIFY 

### A LL 

### A VAILABLE 

### R ETROFIT 

### C ONTROL 

### O PTIONS



### The first step in the BART Determination is the identification of all retrofit control options, which: 5



### ...are those air pollution control technologies with a practical potential for application to the emissions unit and the regulated pollutant under evaluation...Technologies required as [Best Available Control Technology] BACT or [Lowest Achievable Emission Rate] LAER are available for BART purposes and must be included as control alternatives...We do not expect the source owner to purchase or con struct a process or control device that has not already been demonstrated in practice.

4 40 CFR Part 51, Appendix Y, Section IV.A 5 40 CFR Part 51, Appendix Y, Section IV.D.1

### Plum Creek Manufacturing

- Page 4 March 1 3 , 2012

The guidelines also note that New Source Performance Standards (NSPS) level controls should be considered, as should pollution prevention options and usage (or improvem ent to existing units) of add

- on controls.



### S TEP 

### 2: E LIMINATE 

### T ECHNICALLY 

### I NFEASIBLE 

### O PTIONS



### After the identification of control options, the next step in the analysis is to eliminate technically infeasible options. A control option is considered techni cally infeasible if technical difficulties (based on physical, chemical, or engineering principles) would not allow the option to be utilized successfully. A control is eliminated from consideration if there are process

- specific conditions that prohibit t he implementation of control or if the highest control efficiency for that option would result in an emission level that is higher than any applicable regulatory limits.

Specifically, an option is considered technically feasible if it “has been installe d and operated successfully for the type of source under review under similar conditions, or the technology could be applied to the source under review.” 6 

### According to EPA’s Guidelines for BART Determinations under the Regional Haze Rules , technologies wh ich have not yet been applied to (or permitted for) full scale operations need not be considered as available. Therefore, control options that have not been successfully demonstrated for a particular emission unit are considered technically infeasible and removed from further consideration in this step. 7



### To demonstrate that an option is not technically feasible, the source must evaluate and document that either (1) the characteristics of the exhaust stream and/or the capabilities of the technology that wo uld not allow the option to be used, or (2) the option is not commercially available.



### S TEP 

### 3: E VALUATE 

### C ONTROL 

### E FFECTIVENESS OF 

### R EMAINING 

### C ONTROL 

### T ECHNOLOGIES



### The third step in the BART Determination is the evaluation of control effectiveness of any
contr ol options considered technically feasible. The control effectiveness should include comparing options on the same basis (e.g., lb/MMBtu). Varying control effectiveness levels for the same control option can be considered (e.g., 50% control versus 75% co ntrol). The effectiveness evaluation should also consider ways to improve the control associated with any existing control options already employed, especially when existing control devices are not achieving as great of reduction as the same control devic e on a similar source. 8



### S TEP 

### 4: E VALUATE 

### I MPACTS AND 

### D OCUMENT 

### R ESULTS



### The fourth step in the BART Determination is to analyze the costs of compliance using the control option, the energy impacts of the control option, the non

- air quality environmental imp acts of the control option, and the remaining useful life of the equipment.

6 40 CFR Part 51, Appendix Y, Section IV.D.2 7 40 CFR Part 51, Appendix Y 8 40 CFR Part 51, Appendix Y, Section IV.D.3

### Plum Creek Manufacturing

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The first factor evaluated is the cost of compliance. Evaluation of this factor includes development of cost calculations necessary to determine the average cost effectiveness, w hich is defined as “the total annualized costs of control divided by the annual emissions reductions.” 9 

### The incremental cost effectiveness can also be evaluated in situations where a number of control options are being evaluated in order to compare those options to one another. Costs of compliance can be determined using EPA’s OAQPS Control Cost Manual as guidance. 10 

### Note that the emissions reductions included in the cost of compliance calculations should “represent a realistic depiction of anticipated an nual emissions for the source...based upon actual emissions from a baseline period.” 11 

### Therefore, emission units with limited operation during the baseline period can consider similar limited operation (and limited emissions) in the cost effectiveness calcul ations.

The second factor evaluated is the energy impact. Energy impacts will result in additional costs or income to a source. Typically, these impacts are determined as part of the cost impact calculations, considering only the direct energy consumpti on.

The third factor evaluated is the non

- air quality environmental impact. Environmental impacts include generation of additional solid or liquid waste and the disposal of such waste.

The fourth factor evaluated is the remaining useful life of the sour ce. If the remaining useful life of the equipment is less than the time period recommended by EPA’s OAQPS Control Cost Manual , the shortened life should be utilized in the cost evaluations for the purposes of amortizing costs of the retrofit.



## S ECTION 

## 2. NO X 

## C ONTROL 

## T ECHNOLOG Y 

## D ESCRIPTIONS

This section contains a detailed description of each NO x 

### control technology discussed in later sections of the report. While the working mechanism of these technologies in NO x 

### removal is highlighted, the unit

- specific a pplications of these options are discussed in Sections 3 through 5. The control technologies are classified based on whether they are post

- combustion controls or combustion modifications that are pollution

- preventive by design.



### B ACKGROUND ON 

### P OLLUTANT 

### F ORMATION



### In industrial boiler and furnace combustion processes, NO x 

### is formed by two fundamentally different mechanisms: fuel NO x 

### and thermal NO x 

### . Technical literature suggests that NO x 

### formation from wood combustion is primarily fuel NO x 

### . 12

9 40 CFR Part 51, Appendix Y, Section IV.D.4.b 10 EPA, OAQPS Control Cost Manual, Sixth Edition , January 2002. EPA

- 452/B

- 02

- 001. 11 40 CFR Part 51, Appendix Y, Section IV.D.4.d 12 Webster, T.S. and S. Drennan. Low NO X Combustion of Biomass Fuels. Coen Company, Inc. http://www.coen.com/i_html/white_lownoxbiom.html

.

### Plum Creek Manufacturing

- Page 6 March 1 3 , 2012

“Fuel NO x 

### ” forms when the fuel bound nitrogen compounds are converted into nitrogen oxides. The amount of fuel bound nitrogen converted to fuel NO x 

### depends largely upon the fuel type, nitrogen content of the fuel, air supply, and boiler design (including combusti on temperature). The reaction between elemental nitrogen and oxygen to form nitrogen oxides happens very rapidly. Therefore, the primary mechanisms for reducing fuel NO x 

### involve creating a minimum amount of excess oxygen available to react with the fuel bound nitrogen throughout the combustion process. 13



### NO x 

### formed in the high

- temperature, post

- flame region of the combustion equipment is “thermal NO x 

### .” Temperature is the most important factor, and at flame temperatures above 2,200°F, thermal NO x 

### formatio n increases exponentially. 14



### NO formation is inherent in all high temperature combustion processes. Nitrogen dioxide (NO 2 

### ) can then be formed in a reaction between the NO and oxygen in the combustion gases. In stationary source combustion, little of th e NO is converted to NO 2 

### before being emitted. However, the NO continues to oxidize in the atmosphere. For this reason, all NO x 

### emissions from boilers are usually reported as NO 2 

### .


### C OMBUSTION 

### M ODIFICATION 

### T ECHNOLOGIES



### The combustion modification control t echnologies described below decrease NO x 

### emissions by preventing the formation of NO x 

### during the combustion process, rather than by reducing NO x 

### concentration s in the exhaust.



### Flue Gas Recirculation (FGR)
Flue gas recirculation (FGR) involves recycling a portion of the flue gas back into the combustion zone where inert combustion products in the recycled gas stream adsorb some of the heat generated by the combustion process, thus lowering peak flame temperature. The reduction of the peak flame temperatur e reduces the formation of thermal NO x 

### (conversion of N 2 

### in the combustion air to NO x 

### due to high temperatures and the presence of oxygen).



### Fuel Staging
Also known as “reburning” or “off

- stoichiometric combustion,” fuel staging is a technique where 10 to 2 0 percent of the total fuel input is diverted to a second combustion zone downstream of the primary zone. The fuel in the secondary zone serves as a reducing agent, and NO formed in the primary combustion zone is reduced to N 2 

### . This technique usually employs natural gas or distillate oil as the fuel in the secondary combustion zone.

13 Kraft, D.L. Bubbling Fluid Bed Boiler Emissions Firing Bark & Sludge. Barberton, OH: Babcock & Wilcox. September 199 8. http://www.babcock.com/library/pdf/BR

- 1661.pdf

. 14 Kraft, D.L. Bubbling Fluid Bed Boiler Emissions Firing Bark & Sludge. Barberton, OH: Babcock & Wilcox. September 1998. http://www.babcock.com/library/pdf/BR

- 1661.pdf

.

### Plum Creek Manufacturing

- Page 7 March 1 3 , 2012



### Low NOx Burners (LNB)
Traditional burner design introduces both the fuel and air into one combustion zone. To obtain optimal flames, large amounts of excess air must be co mbined with the fuel. This relatively “uncontrolled” combustion creates high flame temperatures and therefore higher NO x 

### emissions.

To control the generation of thermal NO x 

### , LNB technology stages combustion in the high temperature zone of the flame. The first stage is a fuel

- rich, oxygen

- lean atmosphere where little oxygen is available for NO x 

### formation, which reduces peak flame temperatures by delaying the completion of the combustion process. Combustion is then completed downstream in the second stage where excess air is available but temperatures are lower than the hottest portion of the primary flame core . LNB technology is most suitable for oil and gas combustion.



### Low Excess Air (LEA)
LEA involves reducing the amount of excess combustion air to nea r

- stoichiometric levels, reducing flame temperature, and decreasing thermal NO x 

### formation.



### Staged Combustion
Staged combustion technologies such as Overfire Air (OFA) reduce NO x 

### emissions by creating a “fuel

- rich” zone via air staging (i.e., diverting a portion of the total amount of air required through separate ports so that partial combustion is carried out initially in the first stage with a lower air to fuel ratio than that of normal combustion, while secondary air is supplied to complete the combustion reaction in a subsequent combustion stage). Fuel

- rich conditions in the first stage reduce fuel NO x 

### formation b y limiting the amount of oxygen available to react with the fue l bound nitrogen. Conditions in the secondary combustion zone result in lower peak temperatures and thus, lower NO x 

### emissions.



### P OST


### - C OMBUSTION 

### C ONTROLS



### The post

- combustion control technologies described in detail below include Selective Catalytic Reductio n (SCR) and Selective Non

- Catalytic Reduction (SNCR), which both reduce NO x 

### in the flue gas by converting the NO x 

### to N 2 

### and H 2 

### O.


### Selective Catalytic Reduction (SCR)
The SCR technique involves injecting ammonia or urea into a flue gas with a temperature of about 480 to 800°F, then passing the gas through a catalyst bed where NO x 

### is converted to N 2 

### and H 2 

### O. The function of the catalyst is to lower the activation energy of the NO decomposition reaction, therefore, lowering the temperature necessary to carry o ut the reaction. Depending on the location of the SCR system in the combustion flue gas path, SCR technologies can be Tail

end (Cold

- side) or High

- dust (Hot

- side). A High

- dust SCR system is placed between the economizer and air heater, while the Tail

- end SCR is located downstream of the particulate control and air heater.

### Plum Creek Manufacturing

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Babcock Power’s patented Regenerative SCR (RSCR) systems are “Tail

- end” SCR systems on the cold side, after the particulate control device. In the RSCR configuration, the reagent is first introduced upstream of the RSCR unit. The flue gas/reagent mixture (previously cleaned of particulate matter) then enters one end of the system, where the flue gas mixture travels up through the (hot) ceramic heat retention canister to be reheated. The flue gas mixture then flows through the catalyst section, where the ammonia reacts with the NO x 

### to form nitrogen and water. After the catalyst, the flue gas flows through a “retention” chamber, where a burner reheats the flue gas slightly. From this chamber, the flue gas then flows through the (cold) second canister and is used to heat this canister’s ceramic heat retention block. Once this cycle is complete, the air flow is diverted, so that the second canister is the inlet for the “cold” flue gas, and the first canister is the outlet for the cleaned flue gas. 15 

### The RSCR approach minimizes the supplemental fuel required to reheat the cold exhaust gas.



### Selective Non

- Catalytic Reduction (SNCR)
SNCR is an exhaust gas treatment process in which urea or ammonia is injected into the exhaust gas. High temperatures, normally between 1,600 and 2,100°F, promote the reaction between urea or ammonia and NO x 

### to form N 2 

### and water. 16 

### The effectiveness of SNCR systems depends on the inlet NO x 

### concentration, tempera ture, mixing, residence time, reagent

- to

- NO x 

### ratio, and fuel sulfur content. The temperature of the system must fall within the appropriate range to avoid excess ammonia slip or the oxidation of NH 3 

### to NO x 

### . Proper mixing of the reagent and the flue gas i s necessary to ensure reduction of NO x 

### . The residence time must be of an appropriate duration to allow completion of the reaction. If the reagent

- to

- NO x 

### ratio is too high, excess NH 3 

### will become present in the exhaust

.


### Outside of the design temperature window, the emissions are adversely affected. If the temperatures are too high, then the reagent may be oxidized, causing additional NO x 

### emissions. If the temperatures are too low, then the reaction between the reagent and NO x 

### is slowed, and emissions of the reagent will be present.



## S ECTION 

## 3. C ONTROL 

## T ECHNOLOGY 

## A NALYSIS FOR 

## NO X 

### FROM THE 

## R ILEY 

## S TOKER 

## B OILERS 

## (C OLUMBIA 

## F ALLS AND 

## E VERGREEN 

## )

The Riley Stoker Boiler at Columbia Falls Operations was installed in 1973. It supplies steam to the dry kilns, plywood press, log vats, and MDF platen press. The boiler is rated at 292 MMBtu/hr and 170,000 pounds per hour (pph) steam. The boiler’s average firing rate from 2007 to 2009 was 177 MMBtu/hr.

The Riley Stoker Boiler at the Evergreen Division facility w as installed in 1971. The boiler is rated at 196 MMBtu/hr and 140,000 pph steam. It supplies steam for process operations such as

15 Abrams, Richard F. (Babcock Power Environmental, Inc.) and Kevin Toupin (Riley Power, Inc.). Efficient and Low Emission Stoker Fired Biomass Boiler Technology in T oday’s Marketplace. Worcester, MA: Babcock Power Environmental, Inc. March 2007. http://www.babcockpower.com/pdf/t

- 200.pdf 16 EPA, Air Pollution Control Technology Fact Sheet, EPA

- 452/F

- 03

- 031, Select ive Non

- Catalytic Reduction (SNCR), dated July 15, 2003.

### Plum Creek Manufacturing

- Page 9 March 1 3 , 2012

the dry kilns, the veneer dryers, plywood presses, and the medium density overlay (MDO) press. The boiler’s average firing rate from 2007 to 2009 was 84 MMBtu/hr.

The Riley Stoker Boilers at the Columbia Falls Operations and Evergreen Division facility are similar in design. Both are spreader

- stoker boilers that combust wood residue, primarily as bark from each facility’s lo g debarking process, and both are load

- following boilers used to meet the steam demand of various process operations. Sanderdust burners supplement the hog fuel firing downstream of the spreader

- stoker grate in both boilers. The sanderdust burners are al so capable of firing natural gas, with a design capacity of approximately 10 percent of the total boiler capacity. Natural gas firing only occurs during startup and rare events of sanderdust shortage. For reasons of similarity in design and operation, th e control technology evaluations for both units are addressed in this section.

The firing rate varies for the Riley Stoker Boilers at the Columbia Falls Operations and at the Evergreen Division facility in order to meet the steam demand at the respectiv e facilities. The load of the Columbia Falls Operations Riley Stoker Boiler fluctuates between 50,000 pph steam and 150,000 pph steam, and the Evergreen Division Riley Stoker Boiler’s load varies between 30,000 pph steam and 70,000 pph steam. These wide load changes often occur rapidly, sometimes swinging from the minimum load to the maximum load within thirty minutes. The average low

- end temperature of the flue gas from the boilers is 350o F. 17



### S TEP 

### 1: I DENTIFY 

### A LL 

### A VAILABLE 

### R ETROFIT 

### C ONTROL 

### O PTIONS



### P otentially applicable NO x 

### control technologies are identified based on a review of relevant information published in literature, determinations for similar units identified from a search of the EPA RACT/BACT/LAER Clearinghouse ( RBLC) and from a review of r ecently issued permits for similar biomass boilers ( a summary of relevant RBLC and permit search results is presented in Attachment B) , and experience in conducting control technology reviews for similar types of equipment.

After accounting for the phys ical and operational characteristics of the Riley Stoker Boilers , the post

- combustion and combustion modification control technologies and strategies considered in this analysis for controlling NO x 

### emissions include the following:

Combustion Modification Improvements  Staged Combustion (OFA)  Good Operating Practices (base case)

Post

- Combustion Controls  Selective Catalytic Reduction (SCR)  Selective Non

- Catalytic Reduction (SNCR)

17 Per call with Mitchell Leu and Anna Henolson (Trinity) on 12/07/2011.

### Plum Creek Manufacturing

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Each of the technologies listed above are described in Section 2 of this lette r report, with the exception of good operating practices for the Riley Stoker Boilers.



### Discussion of Current Combustion Design and Available Combustion Modification Improvements
The Riley Stoker Boilers inherently use a process similar to fuel staging by design. The sanderdust burners, which typically supply approximately 10 percent of the heat to the boiler, are located downstream of the primary wood

- fired flame. This configuration helps reduce thermal NO x 

### by breaking the combustion event into multiple stages. The formation of NO x 

### can be controlled using good combustion and boiler operation practices. Plum Creek adheres to a robust maintenance program to maintain the boilers’ burners, hog fuel feed system, fans, and other equipment in optimal conditio n. The boilers are also equipped with a computer control system used to maintain optimum air to fuel ratios and fuel feed rates. These good operating practices allow the facilities to meet the NO x 

### permit limits for the Riley Stoker Boilers at the Columbi a Falls Operations (134.50 lb/hr) and Evergreen Division facility (104 lb/hr).

M inimal thermal NO x 

### is formed in wood fired spreader stoker boilers due to the high moisture content of the wood, and the spread stoker firing configuration. Therefore, combus tion modification technologies that are aimed at reducing thermal NO x 

### formation, such as FGR, are not considered. Additionally, combustion modification technologies used with traditional gas and oil burners, such as LNB, are not available for wood fired b oilers boilers. 18 

### Similarly, s ince the boil ers are of spreader stoker design, they need h igh excess air levels for proper fuel burning. 19 

### As such, combustion modifications like LEA are not practical to employ on spreader stoker boilers

.
Many wood fired spreader stoker boilers include overfire air systems by design. The overfire air combustion configuration reduces NO x 

### through staged combustion technology. Because overfire air systems are commonly employed in spreader stoker boilers, ret rofitting an overfire air system on Plum Creek’s Riley Stoker boilers has been identified as a combustion modification improvement option.



### S TEP 

### 2: E LIMINATE 

### T ECHNICALLY 

### I NFEASIBLE 

### O PTIONS



### The technical feasibility of each identified technology for control of NO x 

### emissions from the Riley Stoker Boilers is discussed in the following sections.



### Selective Catalytic Reduction (SCR)
Implementing SCR on industrial hog fuel boilers poses several technical challenges. Size constraints often make retrofitting an SCR system near the boiler impossible. Further, most hog

18 In wood

- fired spreader stoker boilers such as those in the Plum Creek facilities, the hog fuel is not fed using traditional b urners. The majority of the wood residue fuel is fed on grates, and specialized sanderdust burners are used for up to 10 percent of the heat input capacity. 19 Washington State Department of Ecology Publication No. 03

- 02

- 009, Hog Fuel Boiler RACT Determina tion , April 2003, http://www.ecy.wa.gov/biblio/0302009.html.

### Plum Creek Manufacturing

- Page 11 March 1 3 , 2012

fuel boilers’ temperature profiles are not appropriate for SCR, and the SCR system pressure drop requirements result in sizing concerns related to existing boiler fans. The National Council for Air an d Stream Improvement (NCASI) notes that the high PM concentrations upstream of the PM control equipment (Hot

- side/High

- dust) would impede catalyst effectiveness and could result in deactivation or poisoning of the catalyst (requiring downtime to clean and/ or replace the catalyst), while the installation of SCR downstream of the PM control equipment (Cold

side/Tail

- end SCR) would render the gas stream too cold for effective reaction with the catalyst to reduce NO x 

### . 20 

### In biomass boilers, plugging and fouling of the catalyst can occur due to large amounts of fly ash generated by the biomass.

The desired temperature range for SCR application is 450 ° F, and the maximum exhaust temperature of the Riley Stoker Boiler at Columbia Falls Operations is 500 ° F and the exhaust temperature for the boiler at the Evergreen Division facility is 430 ° F. 21 

### While the exhaust temperatures of the two boilers are close to the range of operation of the SCR system, higher temperatures would likely be needed for optimum control effici ency for Tail

- end SCR application.

In an RCSR system, the regenerative heating reduces the required heat input; however, this reheating of the flue gas still represents a significant amount of auxiliary fuel that would be necessary for successful operat ion. Moreover, it is not considered available as RSCR has not been previously demonstrated on load

- following industrial boilers. 22 

### As noted above, locating the SCR in a higher temperature region (Hot

- side/High

- Dust SCR) to avoid the issue with use of auxi liary fuel would result in exposure to high particulate emissions from hog fuel combustion that could significantly damage the catalyst.

The technical difficulties described above apply generally to biomass boilers, and recent applications indicate that these difficulties may be overcome by advanced technologies and auxiliary heating of the Tail

- end flue gas. However, the wide swings experienced by the Plum Creek boilers result in unstable exhaust temperatures and would make it particularly difficult to control the reagent injection rate needed to ensure appropriate NO x 

### reductions while avoiding excessive ammonia slip. For these reasons, SCR technology has not been successfully demonstrated for a load

- following spreader

- stoker boiler with load swings co mparable to the Riley Stoker Boilers at the Columbia Falls Operations and Evergreen Division Facility. 23 , 24

20 NCASI Special Report 03

- 04, NO x Control in Forest Products Industry Boilers: A Review of Technologies, Costs, and Industry Experience , August 2003. 21 OAQPS Section 4.2 states the optimum temperature for operation of SCR is between 480 to 800 ° F

. Vendor information provided from Fuel Tech, Inc. to Anna Henolson (Trinity) via email on 1/13/2012 stated an optimum temperature of 450 ° F

. 22 A review of the RBLC database indicates that RSCR technology has previously been used only on a base

- loaded utility boiler. 23 NCASI Corporate Correspondent Memorandum No. 06

- 014, Information on Retrofit Control Measures for Kraft Pulp Mill Sources and Bo ilers for NO x , SO 2 and PM Emissions
, June 2006. 24 A review of the RBLC database and of recently issued biomass boiler permits, performed in 2011, indicates that SCR technology has not been previously demonstrated on similar load

- following boilers. Refer to Attachment B of the letter for a list of RBLC search results for biomass boilers.

### Plum Creek Manufacturing

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BART guidelines state that technologies which have not yet been applied to (or permitted for) full scale operations need not be considered available ; thus, technologies that have not been successfully implemented o n a comparable emission unit, such as SCR on a load

- following spread

- stoker boiler, are considered to be technically infeasible

. However, EPA Region 8 requested that an economic analysis be conducted on the boilers at the Plum Creek facilities to further demonstrate the infeasibility of the tail

- end SCR application on the boilers. A s such, demonstration of the economic infeasibility of the SCR technology is included under Step 3.



### Selective N on - Catalytic Reduction (SNCR)
Implementing SNCR on industrial load

- following hog fuel boilers also poses several technical challenges for many of the same reasons that SCR technology is considered technically infeasible. In an SNCR system, the injection o f the reagent must be applied in a narrow temperature window in order for the reduction reaction to successfully complete. In a load

following boiler, the region of the boiler where this temperature occurs varies depending on the firing rate, making it ne arly impossible to control the SNCR reaction temperature. Another factor preventing proper implementation of SNCR technology in load

- following biomass boilers is inadequate reagent dispersion in the injection region, which can lead to significant amounts of unreacted ammonia exhausted to the atmosphere (i.e., large ammonia slip). At least one pulp mill wood

- fired boiler had to abandon their SNCR system due to problems caused by poor dispersion of the reagent within the boiler. 25



### While there have been re cent advancements in SNCR technology that may aide in overcoming these technical hurdles, such as setting up multiple injection grids and the addition of sophisticated Continuous Emissions Monitoring Systems (CEMS)

- based feedback loops, SNCR has yet to be successfully demonstrated for a hog fuel boiler with swing loads comparable to the Riley Stoker Boilers at the Columbia Falls Operations and Evergreen Division facility. 26 , 27 

### Therefore, SNCR is considered to be technically infeasible. However, EPA Region 8 requested that an economic analysis be conducted on the boilers at the Plum Creek facilities to further demonstrate the infeasibility of the tail

- end SCR application on the boilers. As such, demonstration of the economic infeasibility of the SCR technolog y is included under Step 3.



### Staged Combustion
Implementing staged combustion technology would require installation of OFA injection ports, which poses several site

- specific technical obstacles for Plum Creek’s Riley Stoker Boilers. The ports would need to be installed at the exact location where the current sanderdust burners are

25 NCASI Corporate Correspondent Memorandum No. 06

- 014, Information on Retrofit Control Measures for Kraft Pulp Mill Sources and Boilers for NO x , SO 2 and PM Emissions
, June 2 006. 26 NCASI Corporate Correspondent Memorandum No. 06

- 014, Information on Retrofit Control Measures for Kraft Pulp Mill Sources and Boilers for NOx , SO 2 and PM Emissions
, June 2006. 27 A review of the RBLC database and of recently issued biomass boil er permits, performed in February 2011, indicates that SNCR technology has not been previously demonstrated on similar load

- following boilers. SNCR installations were identified for several industrial biomass boilers. However, each of the boilers with SN CR does not operate under load

- following conditions comparable to the Plum Creek Riley Stoker Boilers. Further detail for each SNCR application is provided in Attachment B.

### Plum Creek Manufacturing

- Page 13 March 1 3 , 2012

located, and installing OFA in the boilers’ small combustion chambers would likely result in flame impingement on boiler walls , leading to tube wall overheating and mechanical fai lure. Flame impingement can also result in premature flame quenching and increased soot and CO emissions. 28 

### Staged combustion generally lengthens the flame configuration so the applicability is limited to installations large enough to avoid flame impingement on internal surfaces. 29 

### Other issues related to general OFA retrofit installations include penetration of the boiler walls, which may affect the structural integrity of the unit, and which would require re

- routing of the steam tubes. The reduc ing atmosphere created in the fuel

- rich primary combustion zone may also result in accelerated corrosion of the furnace. Additionally, grate corrosion and overheating may occur in stokers as primary air flow is diverted to overfire air ports. 30



### Retrof itting the Riley Stoker Boilers with OFA injection ports is not technically feasible due to the numerous technical issues described above. Therefore, OFA technology is considered to be technically infeasible and is not considered further in the analysis.



### S TEP 

### 3: E VALUATE 

### C ONTROL 

### E FFECTIVENESS OF 

### R EMAINING 

### C ONTROL 

### T ECHNOLOGIES


### Selective Catalytic Reduction (SCR)

As requested by EPA Region 8, an economic analysis is conducted on the boilers at the Plum Creek facilities to further demonstrate the infeasibi lity of the tail

- end SCR application on the boilers. For the Columbia Falls Boilers, reheating the flue gas for use in a tail

- end SCR system alone would cost over $ 263 ,000 per year. Based on vendor quotes, the total cost per ton of NO x 

### removed for the ins tallation of an SCR system with 90% control efficiency is estimated at $ 5
, 652

. 31 

### For the Evergreen Boiler, the cost to reheat the flue gas for a tail

- end SCR system is over $ 161 ,000 per year. Based on vendor quotes, the total cost per ton of NO x 

### removed f or the installation of an SCR system with 90% control efficiency is estimated at $ 40,733 . For detailed cost calculations, please refer to Attachment C of this letter. At the request of EPA Region 8, cost estimates at two alternate control efficiencies (7 0% and 80%) are also included in Attachment C

. 32



### As discussed in Step 2 in previous paragraphs, the installation of an RSCR would pose significant design challenges in load following boilers. A vendor quote based evaluation

28 NCASI Special Report 03

- 04, NO x Control in Forest Products Industry Boilers: A Review of Technologies, Costs, and Industry Experience , August 2003. 29 Sloss, Leslie L. Nitrogen oxides technology fact book. 1992. 30 Controlling Nitrogen Dioxides under the Clean Air Act, A Menu of Options: Industrial and Commercial Boilers, http://www.p2pays.org/ref/02/01245/3017103.pdf 31 SCR quote prepared by Fuel Tech, Inc. for Trinity Consultants on 12/19/2012. 32 Note that multiple control efficiencies were requested from the vendo r, but costs for only the 90% control efficiency case were provided. The cost estimates for 70% and 80% control provided in Attachment D are based on applying general assumptions regarding the capital cost break

- down (50% fixed, 50% linearly proportional to control efficiency) for the 90% control efficiency case.

### Plum Creek Manufacturing

- Page 14 March 1 3 , 2012

specific to an RSCR system is not available at this time. 33 

### For the purpose of an economic analysis, the cost to install an RSCR system is expected to be similar to that for a tail

- end SCR system. From the cost evaluation, it can be concluded that there are economic constraints associ ated with installing a SCR control system . As such, RSCR and SCR are economically infeasible and are not considered further.



### Selective Non

- Catalytic Reduction (SNCR)

A n economic analysis is conducted on the boilers at the Plum Creek facilities to further demonstrate the infeasibility of the SNCR application on the boilers. The control cost evaluation of the SNCR system
, based on a vendor budgetary estimate , results in a cost of $1, 882 per ton of NO x 

### removed for the installation of an SNCR system with 50% control efficiency at the Columbia Falls facility. For the Evergreen boiler, the total cost per ton of NO x 

### removed for with 50% control efficiency is estimated at $ 4,994

. For cost estimate calculations, refer to Attachment C of this letter. At the request of EPA Region 8, cost estimates at an alternate control efficiency (35%) are also included in Attachment C

. 34



### As discussed in Step 3, SNCR technology has not been implemented on a load following biomass boiler comparable to the Plum Creek boilers, and is thus considered technically infeasible. The physical design of the boilers results in a very small area where the proper temperatures for reaction exist. Residence times may be too short for both proper mixing and reaction time. Due to the nature of swing loads this zone of proper temperature will also move around. Because of the technical challenges outlined in Section 3, actual costs may be significantly higher than provided in the vendor budgetary estimate, and the control efficiency of 50% may no t be achievable on a continuous basis. Based on the se considerations
, SNCR technology is considered technically and economically infeasible and is not considered further.



### S TEP 

### 4: E VALUATE 

### I MPACTS



### Good combustion and boiler operation practices constitute the most suitable control option for the Riley Stoker Boilers.

A ll control technology options are considered technically and economically infeasible for these boilers. T he remaining useful life of the equipment is used for evaluating economic feasibility and may need to be considered in establishing RP goals for the region. The remaining useful life of each Riley Stoker Boiler is 8 years. 35

33 A quote for an RSCR system from Babcock Power Environmental Inc. was requested by Anna Henolson (Trinity) on 12/06/2011. 34 No te that multiple control efficie ncies were requested from the vendor, but costs for only the 50% control efficiency case were provided. The cost estimates for 35% control provided in Attachment C are based on applying general assumptions regarding the capital cost break

- down (50% fixed, 50% linearly proportional to control efficiency) for the 50% control efficiency case. EPA also mentioned evaluating a higher control efficiency (75%); however, 50% is the maximum efficiency expected from the SNCR technology. 35 The remai ni ng economic life for each boiler is 8 years, as deter mined by Plum Creek, emailed to Trinity Consultants by Mitchell Leu, December 8, 2011.

### Plum Creek Manufacturing

- Page 15 March 1 3 , 2012



## S ECTION 

## 4. C ONTROL 

## T ECHNOLOGY 

## A NALYSIS FOR 

## NO X 

### FROM THE 

## L INE 

## 2 MDF F IBER 

## D RYERS 

## (C OLUMBIA 

## F ALLS 

## )

The Line 2 MDF Dryers at Columbia Falls Operations are direct

- contact dryers. The flue gas from the combustion chamber, rated at 85 MMBtu/hr, feeds a two stage flash tube dryer (the first stage dryer and the second stage dryer). The Line 2 Dryers are equipped with ven turi scrubbers, followed by biofilters for particulate and VOC control. The burner that supplies the heat to the dryers is fired with sanderdust from the process and employs staged combustion to limit NOx formation

. A copy of the Process Flow Diagram for the Dryers in included in Attachment D.



### S TEP 

### 1: I DENTIFY 

### A LL 

### A VAILABLE 

### R ETROFIT 

### C ONTROL 

### O PTIONS


### Potentially applicable NO x 

### control technologies are identified based on a review of determinations for similar units id entified from the RBLC search (A ttachment B presents a summary of the RBLC search results for the NO x 

### control technologies for MDF dryers) . After accounting for the physical and operational characteristics of the Line 2 MDF Fiber Dryers, the control techn ologies and strategies considered in this analysis for controlling NO x 

### emissions include the following:

 Selective Catalytic Reduction (SCR)  Sele cti ve Non

- Catalytic Reduction (SNCR)

The Line 2 MDF Fiber Dryers are currently equipped with staged combustion , and hence this control is treated as a baseline scenario against which additional control options are considered. Please refer to Section 2 of this report for a description of the control technologies listed above.



### Discussion of Current Combustion Desig n and Available Combustion Modification Improvements
The combustion stage for the Line 2 MDF Fiber Dryers employs a staged combustion design. 36 

### First, the burners fire sanderdust at less than stoichiometric oxygen to fuel ratio. The primary combustion sta ge is "fuel rich," thereby limiting formation of fuel NO x 

### . As the flame progresses in the firebox, additional air is added to complete the combustion process. Due to the lower temperature needed in the secondary combustion zone, formation of thermal NO x 

### is also reduced.

Most of the NO x 

### emissions from wood

- fired units arise from the fuel nitrogen. As such, combustion modification technologies that are aimed at reducing thermal NO x 

### formation, such as FGR, are not considered. Since the dryers burn wood residue in a small combustion chamber

36 It should be noted that the Columbia Falls Operations air permit specifies that the Line 2 Dryers employ LNB/FGR; however, the technology employed in practice is stage d combustion. The burners contribute to lower NO x formation by firing the sanderdust at sub

- stoichiometric conditions; however, the burners themselves do not support the secondary combustion stage needed to complete the combustion process. The unit does not employ any form of FGR.

### Plum Creek Manufacturing

- Page 16 March 1 3 , 2012

with no available footprint for a secondary combustion zone, fuel staging is not an available combustion modification option as the technology involves the diversion of fuel to a secondary combustion zone. Further, f uel staging primarily reduces thermal NO x 

### , not fuel NO x 

### (the primary component of the dryers’ exhaust). LEA is also not an available control alternative as high excess air levels are needed for proper fuel burning in MDF dryers due to limited thermal decom position of wood furnish components in the drying process. Therefore, no combustion modification improvements are identified for the Line 2 Dryers.



### S TEP 

### 2: E LIMINATE 

### T ECHNICALLY 

### I NFEASIBLE 

### O PTIONS



### The technical feasibility of each identified technology f or the control of NO x 

### from the Line 2 MDF Fiber Dryers is discussed in the following sections.



### Selective Catalytic Reduction (SCR)
SCR technology has not been previously demonstrated on a wood product dryer. This control option does not appear in the RBLC search results for similar units. SCR technology is not feasible for wood products dryers because of the direct contact of the combustion air with the wood product material. If the reagent were to be injected in the optimal temperature range directly af ter the burner (hot

- side SCR) , the ammonia in the flue gas would deposit on the wood fibers (due to the direct

- fired nature of the burners where the combustion gases come in contact with the material being dried), causing product damage. Specifically, the ammonia would tie up the formaldehyde in the urea

- formaldehyde resin, causing structural defects. Furthermore, f or a hot

- side SCR, the SCR system is located prior to the particulate control processing. Such a design is technically difficult due to the s mall size of the combustion chamber. It also poses the ris k of damage to the catalysts in the bed due to high particulate s in the gas.

An alternative to avoid product fouling issues is to place the SCR system post particulate control (tail

- end SCR) . As mentioned previously, the Line 2 Dryers are equipped with venturi scrubbers followed by biofilters. For a tail

- end SCR application, the flue gas from the dryers would need to be reheated to a temperature optimal for the injection of the ammonia reagent. The reheating cost alone is a significant hurdle in the application of this technology for these dryers.

The tail

- end SCR c an be located after the venturi scrubbers , prior to the biofilter. However, this system design would require a modification to the biofilters to accommodate increased flow and heat . A large volume of cooling air is added to the dryer exhaust stream prior to the biofilter in order to cool the flue gas to a biologically optimum temperature of 104F

. Hence , the temperature is considerab ly lower and the flow is considerably higher post

- biofilter. The size of the SCR system will also be significantly larger in such a scenario. For these reasons, SCR has not been successfully demonstrated on wood products dryers. Hence, it is considered
t echnically infeasible. However, a demonstration of the economic infeasibility of the SCR technology is included under Step 3.

### Plum Creek Manufacturing

- Page 17 March 1 3 , 2012



### Selective Non

- Catalytic Reduction (SNCR)
As previously discussed, SNCR systems are installed where the temperature in the combust ion zone of the unit reaches the optimum range for operation of the SNCR of 1600 to 2100 ° F. The combustion zone for the Line 2 Dryers reach es a maximum temperature of approximately 1500 ° F, lower than the minimum temperature needed for SNCR. Moreover, as for SCR, if the reagent were to be injected near the optimal temperature range within the combustion chamber, the reagent in the flue gas would deposit on the wood fibers, causing product damage. Specifically, the ammonia would tie up the formaldehyde in the urea

- formaldehyde resin, altering the resin curing chemistry and causing structural defects. Due to these reasons, SNCR has not been successfully demonstrated on wood products dryers. Therefore, SNCR is considered technically infeasible and is not considered further.



### S TEP 

### 3: E VALUATE 

### C ONTROL 

### E FFECTIVENESS OF 

### R EMAINING 

### C ONTROL 

### T ECHNOLOGIES


### Selective Catalytic Reduction (SCR)
For the purpose of an economic analysis, the cost to reheat the gas alone is evaluated for two tail

- end SCR system locatio ns

– pre

- biofil ter and post

- biofilter. Th e flue gas reheating cost for a SCR application placed post

- biofilter is estimated at over $ 54,4 00 per ton NO x 

### removed. For a scenario where the SCR system is placed prior to the biofilter, the flue gas reheating cost alone is estimated over $ 15,800 per ton NO x 

### removed. The biofilter would also then need to be modified and expanded adding additional capital and operating costs. For detailed calculations, refer to Attachment C of the letter. From the cost evaluation, it can be concluded that there are economic constraints associated with installing a SCR control system. As such, this technology is economically infeasible and is not considered further.



### Staged Combustion
Staged combustion te chnology, presently installed and operational, is an available NO x 

### control for the Line 2 Dryers. There are no other remaining control options which are technically and economically feasible.



### S TEP 

### 4: E VALUATE 

### I MPACTS



### S taged combustion constitutes the mos t suitable control option for the Line 2 MDF Fiber Dryers. Plum Creek employs a robust maintenance program that keeps this technology effective at reducing NO x 

### emissions. The burner itself is also strictly controlled using computer controls that monitor and control fuel feed and combustion air, monitor combustion zone temperatures as well as monitor fire brick temperatures.

The remaining useful life of the dryers is used for evaluating the economic feasibili ty of control options. A ll add

- on control tech nology options are considered technically and economically infeasible for this unit. T he remaining useful life of the equipment may need to be considered in

### Plum Creek Manufacturing

- Page 18 March 1 3 , 2012

establishing Reasonable Progress goals for the region. The remaining useful life of the Line 2 MD F Fiber Dryers is 7 years. 37



## S ECTION 

## 5. C ONTROL 

## T ECHNOLOGY 

## A NALYSIS FOR 

## NO X 

### FROM THE 

## L INE 

## 1 MDF F IBER 

## D RYERS 

## (C OLUMBIA 

## F ALLS 

## O PERATIONS 

## )

The Line 1 MDF Fiber Dryers at the Columbia Falls Operations include a core dryer and a face dryer, each installed wi th a sanderdust burner with a capacity of 50 MMBtu/hr for each unit

. The dryers can process up to 57 tons/hr of bone dry fiber. A copy of the Process Flow Diagram for the Dryers in included in Attachment D.



### S TEP 

### 1: I DENTIFY 

### A LL 

### A VAILABLE 

### R ETROFIT 

### C ONTROL 

### O PTIONS


### Potentially applicable NO x 

### control technologies are identified based on a review of determinations for similar units identified from the RBLC search ( a summary of relevant RBLC search results are presented in Attachment B) . After accountin g for the physical and operational characteristics of the Line 1 MDF Fiber Dryers, the control technologies and strategies considered in this analysis for controlling NO x 

### emissions include the following:

 Selective Catalytic Reduction (SCR)  Selective Non

- C atalytic Reduction (SNCR)  Staged Combustion / Low NO x 

### Burners (LNB)  Good Operating Practices (baseline)

Each of the technologies listed above are described in Section 2 of this letter report, with the exception of good operating practices for the Line 1 MDF Fiber Dryers.

The formation of NO x 

### can be controlled using good operation practices. Plum Creek adheres to a robust maintenance program for the Line 1 MDF Fiber Dryers. Maintaining the burners and other dryer equipment in good condition promotes p roper combustion and supports good operating practices, including computer controlled optimization of air to fuel ratios and firing rates. The burners are also computer monitored for combustion zone temperatures.



### Discussion of Current Combustion Design a nd Available Combustion Modification Improvements
The size of the combustion chambers in the Line 1 Dryers is approximately one

- fourth that of the combustion chamber for the Line 2 Dryers. This size difference is a direct result of the Line 2 Dryers includ ing a staged combustion design requirement from the permitting process of the second line. The staged combustion technology implemented when the Line 2 Dryers were constructed requires four times the space to complete the combustion process. FGR, fuel

37 Engineering estimate by Plum Creek, emailed to Trinity Consultants by Mitchell Leu, December 8, 2011.

### Plum Creek Manufacturing

- Page 19 March 1 3 , 2012

st aging, and LEA are not available combustion modification options for the Line 1 Dryers for the same reasons outlined previously under Section 3 for the Line 2 MDF Fiber Dryers.

Because staged combustion technology has been demonstrated as a technically fe asible combustion technology for the construction of the Line 2 dryers, retrofitting a staged combustion system on Plum Creek’s Line 1 Dryers has been identified as a combustion modification improvement option.



### S TEP 

### 2: E LIMINATE 

### T ECHNICALLY 

### I NFEASIBLE 

### O PT IONS



### The technical feasibility for applying staged combustion for the control of NO x 

### from the Line 1 MDF Fiber Dryers is discussed in the following section.



### Staged Combustion / Low NOx Burners (LNB)
The available technique for application of staged combust ion / LNB technology for the combustion of sanderdust involves the same staged combustion process described for the Line 2 MDF Fiber Dryers. This technique involves firing the sanderdust at sub

- stoichiometric levels at the burners, and adding air through s eparate air ports to complete the combustion process. The type of LNB technology that can be applied for natural gas or fuel oil combustion is not applicable for the combustion of sanderdust.

The application of staged combustion is limited by the longer and cooler flames produced as a consequence of improved air distribution control. The Line 1 MDF Fiber Dryers have a combustion chamber that is size

- restricted. The firebox is one

- fourth the s ize of that of the Line 2 MDF Fiber Dryers combustion chamber. The small size of the combustion chamber makes it impossible to retrofit the Line 1 MDF Fiber Dryers with a staged combustion technology without requiring replacement of the unit for the large r sized chamber. Where the current burners are located is footprint restricted for size so the larger combustion chambers would need to be relocated further away from the dryer also. This would add in sizable additional costs for ducting the combustion ga ses into the dryer. Therefore, staged combustion technology is considered technically infeasible for the retrofit of the Line 1 MDF Fiber Dryers.

It is possible (though cost prohibitive) to replace the existing Line 1 burners with an entirely

new , larger firebox, that would also involve adding significant ducting to accommodate the existing Line 1 D ryers footprint. See Step 3 for an economic evaluation of this option.



### Selective Catalytic Reduction (SCR)
As described for the Line 2 Dryers in Section 4, there are several technical challenges of installing an SCR system in the MDF dryers. See Step 3 for an economic evaluation of this option.

### Plum Creek Manufacturing

- Page 20 March 1 3 , 2012



### Selective Non

- Catalytic Reduction (SNCR)

As described in detail in Section 4 for the Line 2 Dryers , SNCR is tec hnically infeasible for application on the MDF dryers due to inadequate combustion chamber temperatures and product fouling.



### S TEP 

### 3: E VALUATE 

### C ONTROL 

### E FFECTIVENESS OF 

### R EMAINING 

### C ONTROL 

### T ECHNOLOGIES


### Staged Combustion / Low NOx Burners (LNB)
For the purpose of an economic analysis, the cost to install two new burners witha larger firebox for the Line 1 Dryers was evaluated. It was estimated that the cost of the equipment with ducting would be priced at approximately $ 4,000,000, resulting in a cost per ton of over $ 7
, 0 00 per ton of NO x 

### removed

. 38 

### As such, this technology is economically infeasible and is not considered further.



### Selective Catalytic Reduction (SCR)
As described for the Line 2 Dryers in Section 4, an economic evaluation of reheating flue gas in a tail end SCR system was conducted on the Line 1 Dryers, considering two different SCR locations. The flue gas reheating cost for an SCR application placed post

- biofilter is estimated at over $ 49,600 per ton NO x 

### removed. For a scenario where the SCR sy stem is placed prior to the biofilter, the flue gas reheating cost alone is estimated over $1 2,400 per ton NO x 

### removed. Additional cost for increasing the capacity of the biofilter due to increased heat and for the capital cost of the SCR equipment would r esult in a considerably higher cost per ton

. For detailed calculations, refer to Attachment D of the letter. Based on the cost evaluation, this technology is economically infeasible and is not considered further.



### S TEP 

### 4: E VALUATE 

### I MPACTS



### Good combustion practices constitute the most suitable control option for the Line 1 MDF Fiber Dryers.

The remaining useful life of the unit is not used for evaluating the economic feasibility of control options. However, the remaining useful life of t he equipment may need to be considered in establishing Reasonable Progress goals for the region. The remaining useful life of the face burner and core burner on the Line 1 MDF Fiber Dryers is 15 and 10 years , respectively

. 39



## S ECTION 

## 6. C ONCLUSION

38 Capital cost of new burners is estimated by Plum Creek based on the Line 2 cap i t al projects and bids. Cost per ton of NO x removed is calculated based on 2007

- 2009 firing data and 23 % control efficiency, based on the Line 2 Dryers design control efficiency (no source test data available). 39 Engineering estimate by Plum Creek, emailed to Trinity Consultants by Mitchell Leu, D ecember 8, 2011.

### Plum Creek Manufacturing

- Page 21 March 1 3 , 2012

Plum Cr eek conducted a control technology evaluation to address requirements under the Regional Haze Rule for Reasonable Progress goals and strategies. Based on the evaluation presented in this letter, the existing control measures are the most suitable for PM, SO 2 

### , and NO x 

### emissions from the Riley Stoker Boilers at the Columbia Falls Operations and at the Evergreen Division facility and the Line 1 and Line 2 MDF Fiber Dryers at the Columbia Falls Operations.

PM emissions are well control led for all four emissio n units, using a Venturi scrubber for the Line 2 MDF Fiber Dryers and ESP technology for the remaining units. Emissions of SO 2 

### are minimal , since all four units combust fuels with negligible amounts of sulfur ( hog fuel, sanderdust, and natural gas )

. NO x 

### emissions from the Riley Stoker Boilers are controlled using good operating practices, including employing a computerized control system to optimize the air and fuel feed rates. Additionally
, the firing of hog fuel with supplemental downstream sanderdust burners results in low thermal NO x 

### formation. NO x 

### emissions from the Line 1 MDF Fiber Dryers are controlled using good operating practices, and the Line 2 MDF Fiber Dryers employ staged combustion technology to reduce NO x 

### formation. All available NO x 

### con trol technologies were determined to be technically or economically infeasible.

Should EPA Region 8 have any questions or require further information regarding the emission units or control technologies addressed in this letter, Plum Creek looks forward t o working with EPA Region 8 to provide additional information to assist in establishing the Reasonable Progress goals and strategies for Montana.

Sincerely,

PLUM CREEK MANUFACTU RING

Thomas Ray Vice President Northwest Resources & Manufacturing

Attachments

cc: Mr. Mitchell Leu, Plum Creek Ms. Anna Henolson, Trinity Consultants Ms. Anupama Krishnan, Trinity Consultants

## A TTACHMENT 

## A

EPA 114 Request Letter

## A TTACHMENT 

## B

RBLC and Biomass Boiler Permit Search ResultsTable B-2. RBLC Search Results for NOxcontrol devices on Wood Products DryersFACILITY STATEPERMIT ISSUANCEDATEPROCESS NAME PRIMARY FUEL THROUGHPUT UNITCONTROL METHODDESCRIPTIONEMISSIONLIMITUNIT CASE-BY-CASE BASISPARAGON PANELS OF ALABAMA, L.L.C. AL 4/12/2006 WOOD FIBER PREP/DRYING 151 mmsf/yr LOW NOX BURNERS 80 LB/H BACT-PSDLOUISIANA PACIFIC CORPORATION AL 6/14/2006 BOARD PRESS BARK 85000 LB/H GOOD DESIGN/OPERATION 5.3 LB/H BACT-PSDLOUISIANA PACIFIC CORPORATION AL 6/14/2006 BARK BURNER/DRYER BARK 85000 lb/h 61.3 LB/H BACT-PSDGEORGIA-PACIFIC ORIENTED STRANDBOARD FACILITY AR 1/7/2003 ROTARY CHIP DRYER, (5) WOOD WASTES 600 MMSF/YR LOW NOX BURNER 14.66 LB/H BACT-PSDNORBORD GEORGIA GA 6/3/2005 WOOD FLAKE DRYERS WOOD 52 ODT/H 0.28 LB/MMBTU BACT-PSDOAKDALE OSB PLANT LA 6/13/2005 ROTARY DRYER NOS. 1-3 WOOD 300000MSF/YR 3/8inch basiLOW NOX BURNERS ANDWATER INJECTION69.77 LB/H BACT-PSDWEYERHAEUSER MI 6/11/2002 DRYERS AND BURNERS, WOOD CHIP WOOD 108000 LB/H LOW EXCESS-AIR FIRING 27.8 PPMDV BACT-PSDSAGOLA MILL MI 1/31/2008 FLAKE DRYERSLOW NOX BURNERS, GOODCOMBUSTION PRACTICES192.2 T/YR Other Case-by-CaseDIBOLL PARTICLEBOARD OPERATION TX 9/28/2001 PARTICLE BOARD PRESS, PB-53 NONE INDICATED 3.94 LB/H Other Case-by-CaseDIBOLL PARTICLEBOARD OPERATION TX 9/28/2001 (2) DRYERS NO 1 & 2, PB-47 NONE INDICATED 4.62 LB/H Other Case-by-CaseDIBOLL PARTICLEBOARD OPERATION TX 9/28/2001 DRYER NO 3, PB-49 NONE INDICATED 10.6 LB/H Other Case-by-CaseDIBOLL PARTICLEBOARD OPERATION TX 9/28/2001 DRYER NO 4, PB-50 NONE INDICATED 6.3 LB/H Other Case-by-CaseDIBOLL PARTICLEBOARD OPERATION TX 9/28/2001 SANDER DUST BOILER, PB-44 WOOD 40 MMBTU/H NONE INDICATED 57.2 LB/H Other Case-by-CaseJASPER ORIENTED STRANDBOARD MILL TX 2/9/2004 DRYERS 1-5 BYPASS4.12 LB/H BACT-PSDCARHAGE ORIENTED STRANDBOARD MILL TX 3/16/2004 DRYER BYPASS (2)4.2 LB/H BACT-PSDLOUISIANA-PACIFIC HAYWARD WI 6/17/2004 DRYER SYSTEM, LINE I, LINE II WOODGOOD COMBUSTIONPRACTICES, USE OF LOWNOX BURNERS IN OXIDATIONSYSTEM21.9 LB/H BACT-PSD1. Search Criteria for RBLC: Date range from January 1, 2000 through January, 2011; Process Information included Dryers firedby all fuel types. Dryers with all other fuel types other than hog fuel are removed from the search results. Wherefuel type is not provided in RBLC entries, assumptions regarding possible fuel types are made based on industry.Plum Creek ManufacturingRBLC Search MFD Dryer_v2.0.xlsx - 30.530Trinity ConsultantsFebruary 2011Table B-1. RBLC Search Results for NOxcontrol devices on Hog Fuel Boilers1FACILITY STATEPERMITISSUANCE DATE EQUIPMENT PRIMARY FUEL THROUGHPUT UNIT CONTROL METHOD DESCRIPTIONEMISSIONLIMIT UNITCASE-BY-CASEBASIS NOTESMEADWESTVACO KENTUCKY, INC/WICKLIFFE KY 2/27/2002 BOILER, BARK BARK 631 MMBTU/H 0.4 LB/MMBTU BACT-PSDBOGALUSA MILL LA 11/23/2004NO. 12 HOGGED FUELBOILER BARK 787.5 MMBTU/HEXISTING OVERFIRE AIR SYSTEM WITH LOWNOX BURNERS IN THE UNDER GRATE AIRHEATER SYSTEM, PLUS GOOD COMBUSTIONPRACTICES 351.38 LB/H BACT-PSDS.D. WARREN CO. - SKOWHEGAN, ME ME 11/27/2001 BOILER, #2 WOOD WASTE 1300 MMBTU/H SCNR 260 LB/H BACT-PSDThe boiler is a 1300 MMBtu/hr unit which canfire multiple fuels including fuel oil, TDF,biomass, bark, LVHC gases, solid oily waste andkraft condensates. Additionally, the facility has apackage boiler and an additional hog fuel boilerthat can meet the facility's changing steamdemands. Based on the large size of the unit andthe load demands of the boiler, the boiler is notconsidered a comparable emissions source.DISTRICT ENERGY ST. PAUL, INC MN 11/15/2001 BOILER WOOD 550 MMBTU/HSELECTIVE, NON-CATALYTIC REDUCTION,SNCR 0.15LB/MMBTU,BIOMASS BACT-PSDThe boiler is used to produce steam for electricitygeneration and is likely to be base-loaded. Basedon boiler utility, the unit is not considered acomparable source.KODA ENERGY MN 8/23/2007 BIOMASS BOILER 3SNCR 0.25 LB/MMBTU BACT-PSDThe boiler is used to produce steam for electricitygeneration and is likely to be base-loaded. Basedon boiler utility, the unit is not considered acomparable source.KODA ENERGY MN 8/23/2007 BIOMASS BOILER 4SNCR 0.18 LB/MMBTU BACT-PSDThe boiler is used to produce steam for electricitygeneration and is likely to be base-loaded. Basedon boiler utility, the unit is not considered acomparable source.NORTHERN SUN ND 5/1/2006 WOOD/HULL FIRED BOILER BIOMASS COMBUSTION CONTROLS 0.2 LB/MM BTU BACT-PSDSCHILLER STATION NH 10/25/2004BOILER, WOOD FIRED CFB,UNIT #5 BIOMASS 720 MMBTU/h SELECTIVE NON-CATALYTIC REDUCTION 0.075 LB/MMBTU OtherThe boiler is used to produce steam for electricitygeneration and is likely to be base-loaded. Basedon boiler utility, the unit is not considered acomparable source.CONCORD STEAM CORPORATION NH 2/27/2009 BOILER #1 BIOMASS 32.62 T/HSELECTIVE CATALYTIC REDUCTION (SCR)SYSTEM 0.065 LB/MMBTU LAERThe boiler is used to produce steam for electricitygeneration and is likely to be base-loaded. Basedon boiler utility, the unit is not considered acomparable source.CLEAN POWER BERLIN LLC NH 9/25/2009 BOILER 1 WOOD CHIPS 40.75 T/H WOODSELECTIVE CATALYTIC REDUCTION (SCR)WITH STAGED COMBUSTION 0.065 LB/MMBTU LAERThe boiler is used to produce steam for electricitygeneration and is likely to be base-loaded. Basedon boiler utility, the unit is not considered acomparable source.BERLIN BIOPOWER NH 7/26/2010 EU01 BOILER #1 WOOD 1013 MMBTU/HSCR (COLD SIDE OF BAGHOUSE) WITHAMMONIA INJECTION 0.06 LB/MMBRU LAERThe boiler is used to produce steam for electricitygeneration and is likely to be base-loaded. Basedon boiler utility, the unit is not considered acomparable source.BERLIN BIOPOWER NH 7/26/2010 EU01 BOILER #1 WOOD 1013 MMBTU/HSCR (COLD SIDE OF BAGHOUSE) WITHAMMONIA INJECTION 0.06 LB/MMBTU BACT-PSDThe boiler is used to produce steam for electricitygeneration and is likely to be base-loaded. Basedon boiler utility, the unit is not considered acomparable source.SOUTH POINT BIOMASS GENERATION OH 4/4/2006 WOOD FIRED BOILERS (7) WOOD 318 MMBTU/H SELECTIVE CATALYTIC REDUCTION 27.98 LB/H BACT-PSDFacility proposes to generate electricity fromwood. As of December 2010, project is movingforward. It is not expected to be a load-followingboiler, hence is not a comparable source based onboiler utility.Plum Creek ManufacturingRBLC Search Boiler_v2.0.xlsx - 11.120Trinity ConsultantsFebruary 2011LINDALE RENEWABLE ENERGY TX 1/8/2010 Wood fired boiler biomass 73 T/H Selective Non-catalytic Reduction 0.15 LB/MMBTU BACT-PSDThe wood fired boiler used to produce steam foran electricity generation facility. It is not expectedto be a load-following boiler, hence is not acomparable source based on boiler utility.LUFKIN GENERATING PLANT TX 10/26/2009 Wood-fired Boiler wood 693 MMBtu/hr Selective Catalytic Reduction 0.075 LB/MMBTU BACT-PSDThe boiler is used to produce steam for electricitygeneration and is likely to be base-loaded. Basedon boiler utility, the unit is not considered acomparable source.INTERNATIONAL BIOFUELS, INC VA 12/13/2005WOOD THERMAL OXIDERSFOR WOOD PELLENTPROCESS WOOD/WOOD PASTE 43 MMBTU/H THERMAL OXIDIZERS AND CEM SYSTEM 18.9 LB/H BACT-PSDABERDEEN DIVISION WA 10/17/2002 HOG FUEL BOILER WASTE WOOD 310 MMBTU/H SNCR, BOILER DESIGN 0.15 LB/MMBTU BACT-PSDThe wood-fired boiler is used to generate steamfor electricity generation. Boilers used forelectricity generation are not expected to haveswing loads. Therefore, this boiler is not acomparable source based on boiler utility.SKAGIT COUNTY LUMBER MILL WA 1/25/2006WOOD-FIREDCOGENERATION UNIT BARK & WASTE WOOD 430 mmBtu/HSELECTIVE NONCATALYTIC REDUCTION(SNCR) 56 LB/H BACT-PSDThe boiler is used to produce steam for electricitygeneration and is likely to be base-loaded. Basedon boiler utility, the unit is not considered acomparable source.DARRINGTON ENERGY COGENERATION POWERPLANT WA 2/11/2005WOOD WASTE-FIREDBOILER WOOD WASTE 403 MMBtTU/H SNCR 0.12 LB/MMBTU BACT-PSDThe boiler is used to produce steam for electricitygeneration and is likely to be base-loaded. Basedon boiler utility, the unit is not considered acomparable source.CLEWISTON SUGAR MILL AND REFINERY FL 2004 BOILER 8 BAGASSE 1030 MMBTU/H SNCR 0.14 LB/MMBTU BACT-PSDThe unit is a new 1030 MMBtu/hr bagasse-firedboiler. The bagasse-fired boiler is not expected tooperate as a load-following boiler, because thesteam is co-generated into electricity onsite.Hence, it is not considered a comparable sourcebased on boiler utility.DEL-TIN FIBER L.L.C AR 2/28/2003 HEAT ENERGY SYSTEM BIOMASS 291 MMBTU/H SNCR 0.3 LB/MMBTU BACT-PSDThe unit is a heat-energy system and hence, is notcomparable emission source.INLAND PAPERBOARD TX 10/5/2004 BOILER BARK 856 MMBTU/H SNCR 0.166 LB/MMBTU BACT-PSDThe unit is an 856 MMBtu/hr bark boiler, and thefacility has two natural gas fired boilers. Due tothe large size of the unit and the two boilersexpected to meet the facility's changing steamdemand, the bark boiler is not expected to be acomparable emissions source.WEYERHAEUSER RED RIVER MILLLA 5/24/2006NO. 2 HOGGED FUEL BOILERWOOD 940 MMBTU/HSNCR0.15 LB/MMBTU BACT-PSDThe unit is a 940 MMBtu/hr boiler, and thefacility has a natural gas fired power boiler. Dueto the large size of the unit as well as the powerboiler expected to meet the changing steamdemand, the unit is not expected to have wideswing loads and is not considered a comparableemissions source.1. Search Criteria for RBLC: Date range from January 1, 2000 through January, 2011; Process Information included Boilers firedby all fuel types. Boilers with all other fuel types other than hog fuel are removed from the search results. Where fuel typeis not provided in RBLC entries, assumptions regarding possible fuel types are made based on industry. Thelist also includes a search of facilities with recently permitted industrial biomass boilers having SNCR systems installed.Plum Creek ManufacturingRBLC Search Boiler_v2.0.xlsx - 11.120Trinity ConsultantsFebruary 2011

## A TTACHMENT 

## C

Cost Estimates for SCR, SNCR for Boilers Cost Estimates for SCR for DryersTrinity Consultants Plum Creek BACT Cost Calc_Boiler_v2.0 SCR Info Table C-1. Cost Analysis Supporting Information for Tail-end SCR

Parameter Units Note(s)
90% Control 80% Control 70% Control Boiler Firing Rate 177 177 177 MMBtu/hr 1 Potential NOx Emission Factor 0.578 0.578 0.578 lb/MMBtu 1 Potential NO x Emissions 448 448 448 tpy 1 Removal Efficiency 90 80 70 % 2 Pollutant Removed @ % control 403 359 314 tpy 3
SCR Inlet Airflow (before reheating) 151,000 151,000 151,000 acfm 4 SCR Inlet Temperature (before reheating) 350 350 350 ° F 4 SCR Inlet Temperature (after reheating) 450 450 450 ° F 4 SCR Inlet Flow Rate 393,500 393,500 393,500 lb/hr 6 Additional heat required 25.5 25.5 25.5 Btu/lb 7 10 10 10 MMBtu/hr 52,740 52,740 52,740 MMBtu/yr 8 Natural Gas Cost 5 5 5 $/MMBtu 4 Fuel Sulfur Content 0.01 0.01 0.01 % 5 Ammonia Slip Allowed 5 5 5 ppm 6 Volume of Catalyst 1,240 1,240 1,240 ft 3 6 Mass Flow Rate of Reagent 40.60 36.09 31.58 lb/hr 6 Concentration of Stored Reagent Solution 19 19 19 % Reagent 6 Pressure Drop Across the SCR and Ductwork 7.5 7.5 7.5 inches of H 2 O 6 Electricity Usage 79 78 77 kW 9

Catalyst Cost, Initial 331.91 331.91 331.91 $/ft 3 10 Catalyst Cost, Replacement 401.05 401.05 401.05 $/ft 3 10 19% Ammonia Solution Cost 0.14 0.14 0.14 $/lb 10 Electricity Cost 0.070 0.07 0.07 $/kW-hr 11

SCR Equipment Life 8 8 8 years 12 Interest Rate 6.25 6.25 6.25 % 12

December 1998 $ 163.9 163.9 163.9 n/a 13 2012 $ 226.7 226.7 226.7 n/a 13

3. Pollutant Removed (tpy) = (Removal Efficiency, %) × (Potential Emissions, tpy).

5. Sulfur content based on information provided by Mitchell Leu to Trinity Consultants via email on 1/11/2011.

9 . Electricity usage requirement based on equation 2.48 of OAQPS Manual, Section 4.2, Chapter 2, page 2-46.

11. Cost based on site-specific utility rate, provided by Mitchell Leu to Anna Henolson (Trinity) on 1/11/2011. 12. Assumed an average rate of interest of 6.25% based on current market rates (http://www.steelheadcapital.com/rates.asp, accessed 3/8/2012). 13. Values based on U.S. Historical Consumer Price Index: ftp://ftp.bls.gov/pub/special.requests/cpi/cpiai.txt. Columbia Falls Boiler

10. Catalyst costs based on example problem in OAQPS Manual, Section 4.2, Chapter 2, page 2-50. Costs converted from December 1998 $ to 2012 $. 8. The boiler's typical exhaust temperature during lower load operation is 350 F. These lower exhaust temperatures occur approximately 60% of the operating hours per year. 1. Inlet emissions based on 2007 through 2009 actual fuel usage and November 27, 2007 source test. Design emission factor is based 2007 source test results (test conducted on the boiler on 11/27/2007).

6. SCR design specifications based on vendor quote from Fuel Tech, Inc. to Anna Henolson (Trinity) on 12/19/2011. Pressure drop across the SCR system was provided in vendor quote as 5 inches in WC. It is assumed that the pressure drop across the ductwork is an additional 2.5 in WC. The mass flowrate of reagant for different control efficiencies was scales based on the mass of pollutant removed. 7. An average heat capacity of 0.255 Btu/lb-F is used to calculate the heat needed to raise the temperature of flue gas by 100 F. 4. Assuming the boiler exhaust temperature needs to be heated by 100 F to fall within the minimum acceptable temperature of 450 F, provided by the vendor. Cost of natural gas provided by Mitchell Leu to Anna Henolson (Trinity) on 1/11/2011. 2. Based on call with EPA Region 8 and Anna Henolson (Trinity) on November 30, 2011, EPA requested that SCR cost calculations be presented for three different case scenarios: for control efficiencies at 70, 80 and 90%.Trinity Consultants Plum Creek BACT Cost Calc_Boiler_v2.0 SCR Cost Table C-2. Cost Analysis for SCR

Capital Cost OAQPS Notation 1

90% Control 80% Control 70% Control Purchased Equipment Costs Total Equipment Cost 2 2,384,625 2,299,625 2,214,625 A
Instrumentation 3 238,463 229,963 221,463 0.10 × A
Sales Tax 3 0 0 0

-- Freight 3 0 0 0

-- Total Purchased Equipment Costs 2,623,088 2,529,588 2,436,088 B = 1.1 × A

Direct Installation Costs 4 Foundations and Supports 262,309 252,959 243,609 0.10 × B Handling and Erection 1,049,235 1,011,835 974,435 0.40 × B
Electrical 104,924 101,184 97,444 0.04 × B Piping 52,462 50,592 48,722 0.02 × B
Insulation 104,924 101,184 97,444 0.04 × B Painting 26,231 25,296 24,361 0.01 × B Site Preparation (Site Specific) 157,385 151,775 146,165 0.06 × B Total Direct Installation Costs 1,757,469 1,694,824 1,632,179 C = 0.67 x B

Indirect Installation Costs General Facilities 219,028 211,221 203,413 0.05 × (B + C) Engineering and Home Office Fees 438,056 422,441 406,827 0.10 × (B + C) Process Contingencies 219,028 211,221 203,413 0.05 × (B + C)

Total Indirect Installation Costs 876,111 844,882 813,653 D = 0.20 × (B + C)

Project Contingency 788,500 760,394 732,288 E = 0.15 × (B + C + D) Total Plant Cost 6,045,167 5,829,687 5,614,207 F = B + C + D + E Allowance for Funds During Construction 5 0 0 0 G Royalty Allowance 5 0 0 0 H Preproduction Costs 120,903 116,594 112,284 I = 0.02 × (F + G) Inventory Capital 6 1,905 J Initial Catalyst and Chemicals 5 0 K

Total Capital Investment 7 8,635,167 8,324,794 8,017,088 TCI = (F + G + H + I + J + K) × 1.4

Operating Cost OAQPS Notation

Direct Annual Costs Operating and Supervisory Labor 5 0 1 2 L
Maintenance 129,528 124,872 120,256 M = 0.015 × TCI Reagent Consumption 8 261,459 232,408 203,357 N
Utilities 9 312,371 311,712 311,054 O Catalyst Replacement 10 171,958 171,958 171,958 P
Total Direct Annual Costs 875,316 840,952 806,627 DAC = L + M + N + O + P

Indirect Annual Costs Overhead, Taxes, Insurance, Administration 5 0 0 0 Q Capital Recovery 11 1,404,363 1,353,886 1,303,843 R

Total Indirect Annual Costs 1,404,363 1,353,886 1,303,843 IDAC = Q + R

Total Annual Cost 2,279,679 2,194,838 2,110,470 TAC = DAC + IDAC

Pollutant Removed (tpy) @ % control 403 359 314 tpy Cost per ton of NO X Removed @ % control 5,652 6,122 6,727 $/ton = TAC / Pollutant Removed

1. U.S. EPA OAQPS, EPA Air Pollution Control Cost Manual (6th Edition) , January 2002, Section 4.2, Chapter 2.

5. Value is $0 for an SCR system, per OAQPS Manual, Section 4.2, Chapter 2, pages 2-44, 2-45, and 2-48. 6. Inventory capital is the cost to fill the reagent tank(s) for the first time, OAQPS Manual, Section 4.2, Chapter 2, page 2-44. 7. Assumed retrofit cost factor of 1.4 due to space constraints and other site-specific factors. 8. Reagent consumption cost calculated based on Equation 2.47 of OAQPS Manual, Section 4.2, Chapter 2, page 2-46. 9. Utilities cost calculated based on Equation 2.49 of OAQPS Manual, Section 4.2, Chapter 2, page 2-46. It includes the cost to reheat the flue gas for a tail-end SCR application.

11. Capital Recovery calculated based on Equations 2.54 and 2.55 of OAQPS Manual, Section 4.2, Chapter 2, pages 2-48 and 2-49. 2. Direct Capital Costs are based on a vendor budget estimate from Fuel Tech, Inc. to Anna Henolson (Trinity) on 12/19/2011 for a 90% SCR control efficiency. The capital costs for other control efficiency systems are calculated by assuming half the capital cost is linearly proportional to the mass of NOx tons removed. The direct capital cost includes the cost of a NOx analyzer of $29,625, obtained from CEMTEKS Instruments, Inc on 12/29/2011 to Anupama Krishnan (Trinity). It also includes the cost of an auxiliary burner ($700,000) and ammonia storage tank ($125,000) supplied by Fuel Tech, Inc. to Anna Henolson (Trinity) on 3/7/2011 and 3/6/2011 respectively. 3. The state of Montana does not have a generally applicable sales tax. As such, sales tax costs are not added to the cost estimate. Freight costs are included in vendor cost estimate. As such, no separate freight costs are added. 4. Direct capital cost estimates based on engineering knowledge and evaluation of costs for other equipment as specified in OAQPS Manual.

10. Catalyst replacement cost presumes one layer is replaced each year and is calculated based on Equations 2.51 and 2.52 of OAQPS Manual, Section 4.2, Chapter 2, page 2-47. Assumes 24,000 hours of operation for the life of a layer and 8760 hours per year of SCR operation. Columbia Falls Boiler

Columbia Falls BoilerTrinity Consultants Plum Creek BACT Cost Calc_Boiler_v2.0 SNCR Info Table C-3 . Cost Analysis Supporting Information for SNCR

Parameter Units Note(s) 50% Control 35% Control Maximum Boiler Capacity 177 177 MMBtu/hr 1 Potential NOx Emission Factor 0.58 0.58 lb/MMBtu 1 Controlled Outlet Emissions @ % control 0.29 0.38 lb/MMBtu 2 Removal Efficiency 50 35 % 2 Pollutant Removed @ % control 224 157 tpy 3
Reagant Cost 1.18 1.18 $/gal 4 Normalized Stoichiometric Ratio (Urea) 1.61 1.12 n/a 5 Reagent Consumption (Urea) 53.61 26.27 lb/hr 6 Reagant Solution Consumption (Urea) 30.96 21.68 gal/hr 1 Reagant Solution Storage Capacity (Urea) 10,404 7,283 gal 7 Concentration of Stored Reagent Solution 40 40 % Reagent 8 Concentration of Injected Reagent Solution 10 10 % Reagent 8

Water Cost 0.0006 0.0006 $/gal 9 Electricity Cost 0.070 0.070 $/kW-hr 10
SNCR Equipment Life 8 8 years 11 Interest Rate 6.3 6.3 % 12

December 1998 $ 163.9 163.9 n/a 13 2012 $ 226.7 226.7 n/a 13

8. Concentration based on example problem in OAQPS Manual, Section 4.2, Chapter 1, page 1-39. 9. Water consumption cost based on OAQPS Manual, Section 4.2, Sample problem. Scaled to 2012 dollars.

11. Based on OAQPS Manual, Section 4.2, Chapter 1, page 1-37. 12. Assumed an average rate of interest of 6.25% based on current market rates (http://www.steelheadcapital.com/rates.asp, accessed 3/8/2012). 13. Values based on U.S. Historical Consumer Price Index: ftp://ftp.bls.gov/pub/special.requests/cpi/cpiai.txt. Columbia Falls Boiler

1. Inlet emissions based on maximum boiler capacity. Design specifications are based on vendor quote from De-NOx Technologies, LLC to Anna Henolson (Trinity) on 12/18/2011. 2. Based on call with EPA Region 8 and Anna Henolson (Trinity) on November 30, 2011, EPA requested that SNCR cost calculations be presented for three different case scenarios: for control efficiencies at 35, 50 and 75%.

10. Cost based on site-specific utility rate, provided by Mitchell Leu to Anna Henolson (Trinity) on 1/11/2011. 3. Pollutant Removed (tpy) = (Uncontrolled Inlet Emissions - Controlled Outlet Emissions, lb/MMBtu) × (Maximum Unit Capacity, MMBtu/hr) × (8,760 hr/yr) / (2000 lb/ton). 4. Cost based on example problem in OAQPS Manual, Section 4.2, Chapter 1, page 1-39, converted from December 1998 $ to 2012 $.

7. Reagent storage capacity based on 14 days: Storage capacity (gal) = (Reagent Consumption, gal/hr) × (24 hr/day) × (14 days). 6. Reagent consumption calculated based on Equations 1.15 through 1.17 in OAQPS Manual, Section 4.2, Chapter 1, pages 1-26 and 1-27. The mass flowrate of reagant for different control efficiencies was scales based on the mass of pollutant removed. 5. Normalized Stoichiometric Ratio for Urea calculated based on Equation 1.14 of OAQPS Manual, Section 4.2, Chapter 1, page 1-25.Trinity Consultants Plum Creek BACT Cost Calc_Boiler_v2.0 SNCR Cost Table C-4. Cost Analysis for SNCR

Capital Cost OAQPS Notation 1

50% Control 35% Control Purchased Equipment Costs Total Equipment Cost 2 255,525 256,821 A
Instrumentation 3 25,553 25,682 0.10 × A
Sales Tax 3 0 0

-- Freight 3 0 0

-- Total Purchased Equipment Costs 281,078 282,503 B = 1.1 × A

Direct Installation Costs 4 Foundations and Supports 14,054 14,054 0.05 × B Handling and Erection 56,216 56,216 0.20 × B
Electrical 11,243 11,243 0.04 × B Piping 5,622 5,622 0.02 × B
Insulation 11,243 11,243 0.04 × B Painting 2,811 2,811 0.01 × B
Total Direct Installation Costs 101,188 101,188 C=0.36 × B

Indirect Installation Costs General Facilities 5 19,113 19,185 0.05 × (B + C) Engineering and Home Office Fees 5 38,227 38,369 0.10 × (B + C) Process Contingencies 19,113 19,185 0.05 × (B + C)

Total Indirect Installation Costs 76,453 76,738 D = 0.20 × (B + C)

Project Contingency 5 68,808 69,064 E = 0.15 × (B + C + D)
Total Plant Cost 527,526 529,494 F = B + C + D + E Allowance for Funds During Construction 0 0 G Royalty Allowance 0 0 H Preproduction Costs 5 10,551 10,590 I = 0.02 × (F + G) Inventory Capital 6 12,230 8,561 J Initial Chemicals 5 0 0 K
Total Capital Investment 550,307 617,709 TCI = F + G + H + I + J + K

Operating Cost OAQPS Notation
50% Control 35% Control

Direct Annual Costs Operating and Supervisory Labor 0 0 L
Maintenance 8,255 9,266 M = 0.015 × TCI Reagant Consumption 7 318,852 223,197 N Electricity 4,984 3,489 O Water Consumption 233 114 P
Total Direct Annual Costs 332,324 236,065 DAC = L + M + N + O + P

Indirect Annual Costs Overhead, Taxes, Insurance, Administration 5 0 0 Q Capital Recovery 8 89,498 100,460 R

Total Indirect Annual Costs 89,498 100,460 IDAC = Q + R

Total Annual Cost 421,822 336,525 TAC = DAC + IDAC

Pollutant Removed (tpy) @ % control 224 157 tpy Cost per ton of NO X Removed @ % control 1,882 2,689 $/ton = TAC / Pollutant Removed

6. Inventory capital is the cost to fill the reagent tank(s) for the first time, OAQPS Manual, Section 4.2, Chapter 1, page 1-32. 7. Based on ammonia and water consumption. 8. Capital Recovery calculated based on Equations 1.33 and 1.34 of OAQPS Manual, Section 4.2, Chapter 1, pages 1-37 and 1-38. 4. Estimates based on engineering knowledge and evaluation of costs for other equipment as specified in OAQPS Manual. 5. Costs were based on OAQPS default methodology, Table 1.4 of Section 4.2, Chapter 1, page 1.32. Columbia Falls Boiler

Columbia Falls Boiler

2. Direct Capital Costs are based on vendor quote from De-Nox Technologies, LLC to Anna Henolson (Trinity) on 1/6/2012 for an SNCR system of 50% control. It is assumed that 10 days of set up costs will be incurred, charged at the rate of $1000/day. The direct capital cost includes the cost of a NOx analyzer of $29,625, obtained from CEMTEKS Instruments, Inc on 12/29/2011 to Anupama Krishnan (Trinity). 1. U.S. EPA OAQPS, EPA Air Pollution Control Cost Manual (6th Edition) , January 2002, Section 4.2, Chapter 1. Adjustments to lettering made as PEC and direct installation costs were broken out for this analysis.

3. Instrumentation based on general OAQPS costs as presented on page 2-27 of Section 1, Chapter 2 of OAQPS Manual. The provided vendor estimate includes freight cost to site. The state of Montana does not have a generally applicable sales tax. As such, sales tax costs are not added to the cost estimate.Trinity Consultants Plum Creek BACT Cost Calc_Boiler_v2.0 SCR Info2 Table C-5. Cost Analysis Supporting Information for SCR

Parameter Units Note(s)
90% Control 80% Control 70% Control Maximum Boiler Capacity 84 84 84 MMBtu/hr 1 Potential NOx Emission Factor 0.128 0.128 0.128 lb/MMBtu 1 Potential NO x Emissions 47 47 47 tpy 1 Removal Efficiency 90 80 70 % 2 Pollutant Removed @ % control 42 38 33 tpy 3
SCR Inlet Airflow (before reheating) 55,500 55,500 55,500 acfm 4 SCR Inlet Temperature (before reheating) 350 350 350 ° F 4 SCR Inlet Temperature (after reheating) 450 450 450 ° F 4 SCR Inlet Flow Rate 240,300 240,300 240,300 lb/hr 6 Additional heat required 25.5 26 26 Btu/lb 7 6 6 6 MMBtu/hr 32,207 32,207 32,207 MMBtu/yr 8 Natural Gas Cost 5 5 5 $/MMBtu 4 Fuel Sulfur Content 0.01 0.01 0.01 % 5 Ammonia Slip Allowed 5 5 5 ppm 6 Volume of Catalyst 607 607 607 ft 3 6 Mass Flow Rate of Reagent 9.50 8.44 7.39 lb/hr 6 Concentration of Stored Reagent Solution 19 19 19 % Reagent 6 Pressure Drop Across the SCR and Ductwork 6.0 6.0 6.0 inches of H 2 O 6 Electricity Usage 27.5 27.4 27.3 kWhr 9

Catalyst Cost, Initial 331.91 331.91 331.91 $/ft 3 10 Catalyst Cost, Replacement 401.05 401.05 401.05 $/ft 3 10 19% Ammonia Solution Cost 0.14 0.14 0.14 $/lb 10 Electricity Cost 0.070 0.070 0.070 $/kW-hr 11
SCR Equipment Life 8 8 8 years 12 Interest Rate 6.3 6 6 % 12

December 1998 $ 163.9 163.9 163.9 n/a 13 2012 $ 226.7 226.7 226.7 n/a 13

3. Pollutant Removed (tpy) = (Removal Efficiency, %) × (Potential Emissions, tpy).

5. Sulfur content based on information provided by Mitchell Leu to Trinity Consultants via email on 1/11/2011.

9 . Electricity usage requirement based on equation 2.48 of OAQPS Manual, Section 4.2, Chapter 2, page 2-46.

11. Cost based on site-specific utility rate, provided by Mitchell Leu to Anna Henolson (Trinity) on 1/11/2011. 12. Assumed an average rate of interest of 6.25% based on current market rates (http://www.steelheadcapital.com/rates.asp, accessed 3/8/2012). 13. Values based on U.S. Historical Consumer Price Index: ftp://ftp.bls.gov/pub/special.requests/cpi/cpiai.txt. 6. SCR design specifications based on vendor quote from Fuel Tech, Inc. to Anna Henolson (Trinity) on 12/19/2011. Pressure drop across the SCR system was provided in vendor quote as 5 inches in WC. It is assumed that the pressure drop across the ductwork is an additional 2.5 in WC. The mass flowrate of reagant for different control efficiencies was scales based on the mass of pollutant removed. 7. An average heat capacity of 0.255 Btu/lb-F is used to calculate the heat needed to raise the temperature of flue gas by 100 F. 8. The boiler's typical exhaust temperature during lower load operation is 350 F. These lower exhaust temperatures occur approximately 60% of the operating hours per year.

10. Catalyst costs based on example problem in OAQPS Manual, Section 4.2, Chapter 2, page 2-50. Costs converted from December 1998 $ to 2012 $. Evergreen Boiler

1. Inlet emissions based on 2007 through 2009 actual fuel usage and November 27, 2007 source test. Design emission factor is based on 2009 source test results (test conducted on 10/15/2009). 2. Based on call with EPA Region 8 and Anna Henolson (Trinity) on November 30, 2011, EPA requested that SCR cost calculations be presented for three different case scenarios: for control efficiencies at 70, 80 and 90%.

4. Assuming the boiler exhaust temperature needs to be heated by 100 F to fall within the minimum acceptable temperature of 450 F, provided by the vendor. Cost of natural gas provided by Mitchell Leu to Anna Henolson (Trinity) on 1/11/2011.Trinity Consultants Plum Creek BACT Cost Calc_Boiler_v2.0 SCR Cost2 Table C-6. Cost Analysis for SCR

Capital Cost OAQPS Notation 1

90% Control 80% Control 70% Control Purchased Equipment Costs Total Equipment Cost 2 1,934,625 1,866,847 1,799,069 A
Instrumentation 3 193,463 186,685 179,907 0.10 × A
Sales Tax 3 0 0 0

-- Freight 3 0 0 0

-- Total Purchased Equipment Costs 2,128,088 2,053,532 1,978,976 B = 1.1 × A

Direct Installation Costs 4 Foundations and Supports 212,809 205,353 197,898 0.10 × B Handling and Erection 851,235 821,413 791,591 0.40 × B
Electrical 85,124 82,141 79,159 0.04 × B Piping 42,562 41,071 39,580 0.02 × B
Insulation 85,124 82,141 79,159 0.04 × B Painting 21,281 20,535 19,790 0.01 × B Site Preparation (Site Specific) 127,685 123,212 118,739 0.06 × B
Total Direct Installation Costs 1,425,819 1,375,866 1,325,914 C = 0.67 x B

Indirect Installation Costs General Facilities 177,695 171,470 165,245 0.05 × (B + C) Engineering and Home Office Fees 355,391 342,940 330,489 0.10 × (B + C) Process Contingencies 177,695 171,470 165,245 0.05 × (B + C)

Total Indirect Installation Costs 710,781 685,880 660,978 D = 0.20 × (B + C)

Project Contingency 639,703 617,292 594,880 E = 0.15 × (B + C + D)
Total Plant Cost 4,904,390 4,732,570 4,560,749 F = B + C + D + E Allowance for Funds During Construction 5 0 0 0 G Royalty Allowance 5 0 0 0 H Preproduction Costs 98,088 94,651 91,215 I = 0.02 × (F + G) Inventory Capital 6 3 3 3 J Initial Catalyst and Chemicals 5 0 0 0 K

Total Capital Investment 7 7,899,058 7,622,322 7,345,586 TCI = (F + G + H + I + J + K) × 1.4

Operating Cost OAQPS Notation
90% Control 80% Control 70% Control

Direct Annual Costs Operating and Supervisory Labor 5 0 0 0 L
Maintenance 118,486 114,335 110,184 M = 0.015 × TCI Reagent Consumption 8 61,179 54,381 47,584 N
Utilities 9 177,883 177,814 177,745 O Catalyst Replacement 10 84,265 84,265 84,265 P Total Direct Annual Costs 441,812 430,794 419,776 DAC = L + M + N + O + P +Q

Indirect Annual Costs Overhead, Taxes, Insurance, Administration 5 0 0 0 R Capital Recovery 11 1,284,647 1,239,641 1,194,634 S

Total Indirect Annual Costs 1,284,647 1,239,641 1,194,634 IDAC = R + S

Total Annual Cost 1,726,459 1,670,435 1,614,411 TAC = DAC + IDAC

Pollutant Removed (tpy) @ % control 42 38 33 tpy Cost per ton of NO X Removed @ % control 40,733 44,338 48,973 $/ton = TAC / Pollutant Removed

1. U.S. EPA OAQPS, EPA Air Pollution Control Cost Manual (6th Edition) , January 2002, Section 4.2, Chapter 2.

5. Value is $0 for an SCR system, per OAQPS Manual, Section 4.2, Chapter 2, pages 2-44, 2-45, and 2-48. 6. Inventory capital is the cost to fill the reagent tank(s) for the first time, OAQPS Manual, Section 4.2, Chapter 2, page 2-44. 7. Assumed retrofit cost factor of 1.4 due to space constraints and other site-specific factors. 8. Reagent consumption cost calculated based on Equation 2.47 of OAQPS Manual, Section 4.2, Chapter 2, page 2-46.

11. Capital Recovery calculated based on Equations 2.54 and 2.55 of OAQPS Manual, Section 4.2, Chapter 2, pages 2-48 and 2-49. 10. Catalyst replacement cost presumes one layer is replaced each year and is calculated based on Equations 2.51 and 2.52 of OAQPS Manual, Section 4.2, Chapter 2, page 2-47. Assumes 24,000 hours of operation for the life of a layer and 8760 hours per year of SCR operation. 9. Utilities cost calculated based on Equation 2.49 of OAQPS Manual, Section 4.2, Chapter 2, page 2-46. It includes the cost to reheat the flue gas for a tail-end SCR application. Evergreen Boiler

Evergreen Boiler

2. Direct Capital Costs are based on vendor quote from Fuel Tech, Inc. to Anna Henolson (Trinity) on 12/19/2011 for a 90% SCR control efficiency. The capital costs for other control efficiency systems are calculated by assuming half the capital cost is linearly proportional to the mass of NOx tons removed. The direct capital cost includes the cost of a NOx analyzer of $29,625, obtained from CEMTEKS Instruments, Inc on 12/29/2011 to Anupama Krishnan (Trinity). It also includes the cost of an auxiliary burner ($560,000) and ammonia storage tank ($125,000) supplied by Fuel Tech, Inc. to Anna Henolson (Trinity) on 3/7/2011 and 3/6/2011 respectively. 3. The state of Montana does not have a generally applicable sales tax. As such, sales tax costs are not added to the cost estimate. Freight costs are included in vendor cost estimate. As such, no separate freight costs are added. 4. Direct capital cost estimates based on engineering knowledge and evaluation of costs for other equipment as specified in OAQPS Manual.Trinity Consultants Plum Creek BACT Cost Calc_Boiler_v2.0 SNCR Info2 Table C-7 . Cost Analysis Supporting Information for SNCR

Parameter Units Note(s) 50% Control 35% Control Maximum Boiler Capacity 84 84 MMBtu/hr 1 Potential NOx Emission Factor 0.13 0.13 lb/MMBtu 1 Controlled Outlet Emissions @ 35% control 0.06 0.08 lb/MMBtu 2 Removal Efficiency 50 35 % 2 Pollutant Removed @ 35% control 24 16 tpy 3
Reagant Cost 1.18 1.18 $/gal 4 Normalized Stoichiometric Ratio (Urea) 3.73 2.61 n/a 5 Reagent Consumption (Urea) 13.10 6.42 lb/hr 6 Reagant Solution Consumption (Urea) 2.00 1.40 gal/hr 1 Reagant Solution Storage Capacity (Urea) 672 470 gal 7 Concentration of Stored Reagent Solution 50 50.00 % Reagent 8 Concentration of Injected Reagent Solution 10 10.00 % Reagent 8

Water Cost 0.0006 0.0006 $/gal 9 Electricity Cost 0.070 0.070 $/kW-hr 10
SNCR Equipment Life 8 8 years 11 Interest Rate 6.3 6.3 % 12

December 1998 $ 163.9 163.9 n/a 13 2012 $ 226.7 226.7 n/a 13

8. Concentration based on example problem in OAQPS Manual, Section 4.2, Chapter 1, page 1-39. 9. Water consumption cost based on OAQPS Manual, Section 4.2, Sample problem. Scaled to 2010 dollars.

11. Based on OAQPS Manual, Section 4.2, Chapter 1, page 1-37. 12. Assumed an average rate of interest of 6.25% based on current market rates (http://www.steelheadcapital.com/rates.asp, accessed 3/8/2012). 13. Values based on U.S. Historical Consumer Price Index: ftp://ftp.bls.gov/pub/special.requests/cpi/cpiai.txt. Evergreen Boiler

2. Based on call with EPA Region 8 and Anna Henolson (Trinity) on November 30, 2011, EPA requested that SNCR cost calculations be presented for three different case scenarios: for control efficiencies at 35, 50 and 75%. 1. Inlet emissions based on maximum boiler capacity. Emissions and design specifications are based on vendor quote from De-NOx Technologies, LLC to Anna Henolson (Trinity) on 12/18/2011.

10. Cost based on site-specific utility rate, provided by Mitchell Leu to Anna Henolson (Trinity) on 1/11/2011. 3. Pollutant Removed (tpy) = (Uncontrolled Inlet Emissions - Controlled Outlet Emissions, lb/MMBtu) × (Maximum Unit Capacity, MMBtu/hr) × (8,760 hr/yr) / (2000 lb/ton). 4. Cost based on example problem in OAQPS Manual, Section 4.2, Chapter 1, page 1-39, converted from December 1998 $ to 2010 $. 5. Normalized Stoichiometric Ratio for Urea calculated based on Equation 1.14 of OAQPS Manual, Section 4.2, Chapter 1, page 1-25. 6. Reagent consumption calculated based on Equations 1.15 through 1.17 in OAQPS Manual, Section 4.2, Chapter 1, pages 1-26 and 1-27. The mass flowrate of reagant for different control efficiencies was scales based on the mass of pollutant removed. 7. Reagent storage capacity based on 14 days: Storage capacity (gal) = (Reagent Consumption, gal/hr) × (24 hr/day) × (14 days).Trinity Consultants Plum Creek BACT Cost Calc_Boiler_v2.0 SNCR Cost2 Table C-8. Cost Analysis for SNCR

Capital Cost OAQPS Notation 1

50% Control 35% Control Purchased Equipment Costs Total Equipment Cost 2 255,525 246,821 A
Instrumentation 3 25,553 24,682 0.10 × A
Sales Tax 3 0 0

-- Freight 3 0 0

-- Total Purchased Equipment Costs 281,078 271,503 B = 1.1 × A

Direct Installation Costs 4 Foundations and Supports 14,054 13,575 0.05 × B Handling and Erection 56,216 54,301 0.20 × B
Electrical 11,243 10,860 0.04 × B Piping 5,622 5,430 0.02 × B
Insulation 11,243 2,715 0.04 × B Painting 2,811 2,715 0.01 × B
Total Direct Installation Costs 101,188 89,596 C=0.36 × B

Indirect Installation Costs General Facilities 5 19,113 18,055 0.05 × (B + C) Engineering and Home Office Fees 5 38,227 36,110 0.10 × (B + C) Process Contingencies 19,113 18,055 0.05 × (B + C)

Total Indirect Installation Costs 76,453 72,220 D = 0.20 × (B + C)

Project Contingency 5 68,808 64,998 E = 0.15 × (B + C + D)
Total Plant Cost 527,526 498,317 F = B + C + D + E Allowance for Funds During Construction 0 0 G Royalty Allowance 0 0 H Preproduction Costs 5 10,551 9,966 I = 0.02 × (F + G) Inventory Capital 6 790 553 J Initial Catalyst and Chemicals 5 0 0 K
Total Capital Investment 538,867 573,835 TCI = F + G + H + I + J + K

Operating Cost OAQPS Notation

Direct Annual Costs Operating and Supervisory Labor 0 0 L
Maintenance 8,083 8,608 M = 0.015 × TCI Reagant Consumption 7 20,595 14,416 N Electricity 1,218 853 O Water Consumption 61 30 P
Total Direct Annual Costs 29,957 23,906 DAC = L + M + N + O + P

Indirect Annual Costs Overhead, Taxes, Insurance, Administration 5 0 0 Q Capital Recovery 8 87,637 93,324 R

Total Indirect Annual Costs 87,637 93,324 IDAC = Q + R

Total Annual Cost 117,594 117,231 TAC = DAC + IDAC

Pollutant Removed (tpy) @ % control 24 16 tpy Cost per ton of NO X Removed @ % control 4,994 7,134 $/ton = TAC / Pollutant Removed

6. Inventory capital is the cost to fill the reagent tank(s) for the first time, OAQPS Manual, Section 4.2, Chapter 1, page 1-32. 7. Based on ammonia and water consumption. 8. Capital Recovery calculated based on Equations 1.33 and 1.34 of OAQPS Manual, Section 4.2, Chapter 1, pages 1-37 and 1-38. 4. Estimates based on engineering knowledge and evaluation of costs for other equipment as specified in OAQPS Manual. 5. Costs were based on OAQPS default methodology, Table 1.4 of Section 4.2, Chapter 1, page 1.32. Evergreen Boiler

Evergreen Boiler

1. U.S. EPA OAQPS, EPA Air Pollution Control Cost Manual (6th Edition) , January 2002, Section 4.2, Chapter 1. Adjustments to lettering made as PEC and direct installation costs were broken out for this analysis. 2. Direct Capital Costs are based on vendor quote from De-Nox Technologies, LLC to Anna Henolson (Trinity) on 1/6/2012 for an SNCR system of 50% control. It is assumed that 10 days of set up costs will be incurred, charged at the rate of $1000/day. The direct capital cost includes the cost of a NOx analyzer of $29,625, obtained from CEMTEKS Instruments, Inc on 12/29/2011 to Anupama Krishnan (Trinity). 3. Instrumentation Tax based on general OAQPS costs as presented on page 2-27 of Section 1, Chapter 2 of OAQPS Manual. The provided vendor estimate includes freight cost to site. The state of Montana does not have a generally applicable sales tax. As such, sales tax costs are not added to the cost estimate.Trinity Consultants Plum Creek BACT Cost Calc_Dryers_v2.0 Reheat cost Table C-9. Cost Estimation to Reheat Flue Gas Post Bio-Filter in Dryers

Parameters Line 1 Dryer Line 2 Dryer Unit

Maximum Dryer Capacity 100 85 MMBtu/hr Potential NOx Emission Factor 0.75 0.54 lb/MMBtu Potential Emissions 329 200 tpy Maximum Removal Efficiency 90 90 % Pollutant Removed 296 180 tpy SCR Inlet Airflow (before reheating) 900,000 600,000 acfm SCR Inlet Temperature (before reheating) 104 104 ° F SCR Inlet Airflow (after reheating) 1,452,128 968,085 acfm SCR Inlet Temperature (after reheating) 450 450 ° F Mass Flow Rate 3,801,337 2,534,225 lb/hr Additional heat required 88.23 88.23 Btu/lb 335.39 223.59 MMBtu/hr 2,938,034 1,958,689 MMBtu/yr Natural gas cost (site-specific) 5 5 $/MMBtu Total Reheating Cost 14,690,169 9,793,446 $ Reheat Cost per ton NOx removed 49,688 54,482 $/ton

Footnotes: Molecular weight of dry air 28.95 lb/lbmol Volume of 1 lbmol air @ 68F 385 ft3/lbmol Average heat capacity of air 0.255 Btu/lb*F

Table C-10. Cost Estimation to Reheat Flue Gas Pre Bio-Filter in Dryers

Parameters Line 1 Dryer Line 2 Dryer Unit

Maximum Dryer Capacity 100 85 MMBtu/hr Potential NOx Emission Factor 0.75 0.54 lb/MMBtu Potential Emissions 329 200 tpy Maximum Removal Efficiency 90 90 % Pollutant Removed 296 180 tpy SCR Inlet Airflow (before reheating) 268,000 198,000 acfm SCR Inlet Temperature (before reheating) 140 130 ° F SCR Inlet Airflow (after reheating) 406,467 305,390 acfm SCR Inlet Temperature (after reheating) 450 450 ° F Mass Flow Rate (before reheating) 1,064,037 799,441 lb/hr Additional heat required 79.05 81.6 Btu/lb 84.11 65.23 MMBtu/hr 736,822 571,453 MMBtu/yr Natural gas cost (site-specific) 5 5 $/MMBtu Total Reheating Cost 3,684,110 2,857,265 $ Reheat Cost per ton NOx removed 12,461 15,895 $/ton

Footnotes: Molecular weight of dry air 28.95 lb/lbmol Vol ume of 1 lbmol air @ 68F 385 ft3/lbmol Average heat capacity of air 0.255 Btu/lb*FTrinity Consultants Plum Creek BACT Cost Calc_L1 Dryers_burner v2.0 L1 burner cost Table C-11. Cost Estimation to install a new firebox in Line 1 Dryers

Parameters Line 1 Dryer Unit

Dryer Fuel Usage a 64 MMBtu/hr Potential NOx Emission Factor 0.75 lb/MMBtu Potential Emissions 210 tpy Maximum Removal Efficiency 23.0 % Pollutant Removed 48 tpy Capital Cost of Burner 4,000,000 $ Equipment Life 20 years Interest Rate 6.25 % Capital Recovery Factor 0.089 Annualized Burner Cost 355,849 $ Cost per ton NOx removed 7,382 $/ton

a Annual average fuel usage, 2007-2009. Assuming a fuel high heating value (HHV) of 8,000 Btu/lb.

## A TTACHMENT 

## D

Process Flow Diagram for Line 1 and Line 2 Dryers