March 13, 2012

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 The 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 medium 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. In particular, a more detailed discussion 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 requested by EPA. 

The 114 request letter issued 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 impacts 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 list of emission units at the facilities.2

The Regional Haze Rule covers emissions of particulate matter (PM), sulfur dioxide (SO2), and 

nitrogen oxides (NOx). However, detailed control evaluations for emissions of PM and SO2 are 

not included in this response 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.
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• 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.

 SO2 emissions are minimal from all emission units identified in the 114 request letter.

• The SO2 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 SOx 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: NOx Control Technology Descriptions

 Section 3: Control Technology Analysis for NOx from the Riley Stoker Boilers

 Section 4: Control Technology Analysis for NOx from the Line 2 MDF Fiber Dryers

 Section 5: Control Technology Analysis for NOx from the Line 1 MDF Fiber Dryers

 Section 6: Conclusion

 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

SECTION 1. BART DETERMINATION METHODOLOGY

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 captured within the boiler itself by the alkaline wood ash.”
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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 technology 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 options

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.

STEP 1: IDENTIFY ALL AVAILABLE RETROFIT CONTROL OPTIONS

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 construct 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
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The guidelines also note that New Source Performance Standards (NSPS) level controls should 

be considered, as should pollution prevention options and usage (or improvement to existing 

units) of add-on controls. 

STEP 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

After the identification of control options, the next step in the analysis is to eliminate technically 

infeasible options. A control option is considered technically 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 the 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 installed 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 which 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 would not allow the option to be used, or (2) the option is not commercially available.

STEP 3: EVALUATE CONTROL EFFECTIVENESS OF REMAINING CONTROL 

TECHNOLOGIES

The third step in the BART Determination is the evaluation of control effectiveness of any 

control 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% control). 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 device on a similar source.8

STEP 4: EVALUATE IMPACTS AND DOCUMENT RESULTS

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 

impacts 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
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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, which 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 annual 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 

calculations.

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 consumption.

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 source. 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.

SECTION 2. NOX CONTROL TECHNOLOGY DESCRIPTIONS

This section contains a detailed description of each NOx control technology discussed in later 

sections of the report. While the working mechanism of these technologies in NOx removal is 

highlighted, the unit-specific applications 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.

BACKGROUND ON POLLUTANT FORMATION

In industrial boiler and furnace combustion processes, NOx is formed by two fundamentally 

different mechanisms: fuel NOx and thermal NOx. Technical literature suggests that NOx

formation from wood combustion is primarily fuel NOx.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 NOX Combustion of Biomass Fuels. Coen Company, Inc. 

http://www.coen.com/i_html/white_lownoxbiom.html.
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“Fuel NOx” forms when the fuel bound nitrogen compounds are converted into nitrogen oxides. 

The amount of fuel bound nitrogen converted to fuel NOx depends largely upon the fuel type, 

nitrogen content of the fuel, air supply, and boiler design (including combustion temperature). 

The reaction between elemental nitrogen and oxygen to form nitrogen oxides happens very 

rapidly. Therefore, the primary mechanisms for reducing fuel NOx involve creating a minimum 

amount of excess oxygen available to react with the fuel bound nitrogen throughout the 

combustion process.13

NOx formed in the high-temperature, post-flame region of the combustion equipment is “thermal 

NOx.” Temperature is the most important factor, and at flame temperatures above 2,200°F, 

thermal NOx formation increases exponentially.14 

NO formation is inherent in all high temperature combustion processes. Nitrogen dioxide (NO2) 

can then be formed in a reaction between the NO and oxygen in the combustion gases. In 

stationary source combustion, little of the NO is converted to NO2 before being emitted. 

However, the NO continues to oxidize in the atmosphere. For this reason, all NOx emissions 

from boilers are usually reported as NO2.

COMBUSTION MODIFICATION TECHNOLOGIES

The combustion modification control technologies described below decrease NOx emissions by 

preventing the formation of NOx during the combustion process, rather than by reducing NOx

concentrations 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 temperature reduces the formation of thermal NOx (conversion of N2 in the 

combustion air to NOx 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 20 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 N2. 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 1998. 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.
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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 combined with the fuel. This relatively 

“uncontrolled” combustion creates high flame temperatures and therefore higher NOx emissions.

To control the generation of thermal NOx, 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 NOx 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 near-stoichiometric levels, 

reducing flame temperature, and decreasing thermal NOx formation.

Staged Combustion 

Staged combustion technologies such as Overfire Air (OFA) reduce NOx 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 NOx formation by limiting the amount of oxygen available to react 

with the fuel bound nitrogen. Conditions in the secondary combustion zone result in lower peak 

temperatures and thus, lower NOx emissions.

POST-COMBUSTION CONTROLS

The post-combustion control technologies described in detail below include Selective Catalytic 

Reduction (SCR) and Selective Non-Catalytic Reduction (SNCR), which both reduce NOx in the 

flue gas by converting the NOx to N2 and H2O.

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 NOx is converted to N2

and H2O. The function of the catalyst is to lower the activation energy of the NO decomposition 

reaction, therefore, lowering the temperature necessary to carry out the reaction. Depending on 

the location of the SCR system in the combustion flue gas path, SCR technologies can be Tailend (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. 
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March 13, 2012

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 NOx 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 NOx to form N2 and water.16 The effectiveness of SNCR systems depends 

on the inlet NOx concentration, temperature, mixing, residence time, reagent-to-NOx 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 NH3 to NOx. Proper mixing of the reagent and 

the flue gas is necessary to ensure reduction of NOx. The residence time must be of an 

appropriate duration to allow completion of the reaction. If the reagent-to-NOx ratio is too high, 

excess NH3 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 NOx emissions. 

If the temperatures are too low, then the reaction between the reagent and NOx is slowed, and 

emissions of the reagent will be present. 

SECTION 3. CONTROL TECHNOLOGY ANALYSIS FOR NOX FROM THE 

RILEY STOKER BOILERS (COLUMBIA FALLS AND EVERGREEN)

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 was 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 Today’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, Selective Non-Catalytic 

Reduction (SNCR), dated July 15, 2003.
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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 log 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 also 

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, the 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 respective 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

STEP 1: IDENTIFY ALL AVAILABLE RETROFIT CONTROL OPTIONS

Potentially applicable NOx 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 recently 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 physical and operational characteristics of the Riley Stoker Boilers, the 

post-combustion and combustion modification control technologies and strategies considered in 

this analysis for controlling NOx 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.
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March 13, 2012

Each of the technologies listed above are described in Section 2 of this letter 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 NOx by breaking the combustion event into multiple stages. The formation of NOx 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 condition. 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 NOx permit limits for the Riley Stoker Boilers at the 

Columbia Falls Operations (134.50 lb/hr) and Evergreen Division facility (104 lb/hr).

Minimal thermal NOx is formed in wood fired spreader stoker boilers due to the high moisture 

content of the wood, and the spread stoker firing configuration. Therefore, combustion 

modification technologies that are aimed at reducing thermal NOx 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 boilers boilers.18 Similarly, since 

the boilers are of spreader stoker design, they need high 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 NOx through staged combustion technology. Because 

overfire air systems are commonly employed in spreader stoker boilers, retrofitting an overfire 

air system on Plum Creek’s Riley Stoker boilers has been identified as a combustion 

modification improvement option.

STEP 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

The technical feasibility of each identified technology for control of NOx 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 burners. 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 

Determination, April 2003, http://www.ecy.wa.gov/biblio/0302009.html. 
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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 and 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 (Coldside/Tail-end SCR) would render the gas stream too cold for effective reaction with the catalyst 

to reduce NOx.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 efficiency 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 operation. 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 

auxiliary 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 NOx 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 comparable to the 

Riley Stoker Boilers at the Columbia Falls Operations and Evergreen Division Facility.23,24 

 20 NCASI Special Report 03-04, NOxControl 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 Boilers for NOx, SO2 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.
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March 13, 2012

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 on 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. As such,

demonstration of the economic infeasibility of the SCR technology is included under Step 3.

Selective Non-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 of the reagent must be applied in a narrow 

temperature window in order for the reduction reaction to successfully complete. In a loadfollowing boiler, the region of the boiler where this temperature occurs varies depending on the 

firing rate, making it nearly 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 recent 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 technology 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 NOx, SO2 and PM Emissions, June 2006. 

26 NCASI Corporate Correspondent Memorandum No. 06-014, Information on Retrofit Control Measures 

for Kraft Pulp Mill Sources and Boilers for NOx, SO2 and PM Emissions, June 2006. 

27 A review of the RBLC database and of recently issued biomass boiler 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 

SNCR 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 13, 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 failure. 

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 reducing 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 

Retrofitting 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. 

STEP 3: EVALUATE CONTROL EFFECTIVENESS OF REMAINING CONTROL 

TECHNOLOGIES

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 infeasibility 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 NOx

removed for the installation 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 NOx removed for 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 (70% 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, NOx 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 vendor, 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 13, 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 

associated with installing a SCR control system. As such, RSCR and SCR are economically 

infeasible and are not considered further.

Selective Non-Catalytic Reduction (SNCR)

An 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 NOx 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 NOx

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 not be achievable on a continuous basis. Based on these considerations, SNCR

technology is considered technically and economically infeasible and is not considered further.

STEP 4: EVALUATE IMPACTS

Good combustion and boiler operation practices constitute the most suitable control option for 

the Riley Stoker Boilers.

All control technology options are considered technically and economically infeasible for these 

boilers. The 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 Note that multiple control efficiencies 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 remaining economic life for each boiler is 8 years, as determined by Plum Creek, emailed to Trinity 

Consultants by Mitchell Leu, December 8, 2011.
Plum Creek Manufacturing - Page 15

March 13, 2012

SECTION 4. CONTROL TECHNOLOGY ANALYSIS FOR NOX FROM THE 

LINE 2 MDF FIBER DRYERS (COLUMBIA FALLS) 

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 venturi 

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.

STEP 1: IDENTIFY ALL AVAILABLE RETROFIT CONTROL OPTIONS

Potentially applicable NOx control technologies are identified based on a review of 

determinations for similar units identified from the RBLC search (Attachment B presents a 

summary of the RBLC search results for the NOx control technologies for MDF dryers). After 

accounting for the physical and operational characteristics of the Line 2 MDF Fiber Dryers, the 

control technologies and strategies considered in this analysis for controlling NOx emissions 

include the following:

 Selective Catalytic Reduction (SCR)

 Selective 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 Design 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 stage is "fuel rich," thereby limiting formation of fuel NOx. 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 NOx is also 

reduced. 

Most of the NOx emissions from wood-fired units arise from the fuel nitrogen. As such, 

combustion modification technologies that are aimed at reducing thermal NOx 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 staged combustion. The burners contribute to lower NOx

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 13, 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, fuel staging primarily reduces thermal NOx, not fuel NOx (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 

decomposition of wood furnish components in the drying process. Therefore, no combustion 

modification improvements are identified for the Line 2 Dryers.

STEP 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

The technical feasibility of each identified technology for the control of NOx 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 after 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, for a 

hot-side SCR, the SCR system is located prior to the particulate control processing. Such a 

design is technically difficult due to the small size of the combustion chamber. It also poses the 

risk of damage to the catalysts in the bed due to high particulates 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 can 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 considerably 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 

technically infeasible. However, a demonstration of the economic infeasibility of the SCR 

technology is included under Step 3.
Plum Creek Manufacturing - Page 17

March 13, 2012

Selective Non-Catalytic Reduction (SNCR)

As previously discussed, SNCR systems are installed where the temperature in the combustion 

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 reaches 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.

STEP 3: EVALUATE CONTROL EFFECTIVENESS OF REMAINING CONTROL 

TECHNOLOGIES 

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 locations – pre-biofilter and post-biofilter. The flue gas reheating cost for a

SCR application placed post-biofilter is estimated at over $54,400 per ton NOx 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 NOx 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 technology, presently installed and operational, is an available NOx control 

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

economically feasible.

STEP 4: EVALUATE IMPACTS

Staged combustion constitutes the most suitable control option for the Line 2 MDF Fiber Dryers. 

Plum Creek employs a robust maintenance program that keeps this technology effective at 

reducing NOx 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 feasibility of control 

options. All add-on control technology options are considered technically and economically 

infeasible for this unit. The remaining useful life of the equipment may need to be considered in 
Plum Creek Manufacturing - Page 18

March 13, 2012

establishing Reasonable Progress goals for the region. The remaining useful life of the Line 2 

MDF Fiber Dryers is 7 years.37

SECTION 5. CONTROL TECHNOLOGY ANALYSIS FOR NOX FROM THE 

LINE 1 MDF FIBER DRYERS (COLUMBIA FALLS OPERATIONS) 

The Line 1 MDF Fiber Dryers at the Columbia Falls Operations include a core dryer and a face 

dryer, each installed with 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.

STEP 1: IDENTIFY ALL AVAILABLE RETROFIT CONTROL OPTIONS

Potentially applicable NOx 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 accounting for the physical and operational 

characteristics of the Line 1 MDF Fiber Dryers, the control technologies and strategies 

considered in this analysis for controlling NOx emissions include the following:

 Selective Catalytic Reduction (SCR)

 Selective Non-Catalytic Reduction (SNCR) 

 Staged Combustion / Low NOx 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 NOx 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 proper 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 and 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 including 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 13, 2012

staging, 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 feasible 

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.

STEP 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

The technical feasibility for applying staged combustion for the control of NOx 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 combustion / 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 separate 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 size 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 larger 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 gases 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 Dryers 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 13, 2012

Selective Non-Catalytic Reduction (SNCR)

As described in detail in Section 4 for the Line 2 Dryers, SNCR is technically infeasible for 

application on the MDF dryers due to inadequate combustion chamber temperatures and product 

fouling.

STEP 3: EVALUATE CONTROL EFFECTIVENESS OF REMAINING CONTROL 

TECHNOLOGIES

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 $7,000 

per ton of NOx 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 NOx removed. For a scenario where the SCR system is placed prior to 

the biofilter, the flue gas reheating cost alone is estimated over $12,400 per ton NOx removed. 

Additional cost for increasing the capacity of the biofilter due to increased heat and for the 

capital cost of the SCR equipment would result 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.

STEP 4: EVALUATE IMPACTS

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 the 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

SECTION 6. CONCLUSION

 38 Capital cost of new burners is estimated by Plum Creek based on the Line 2 capital projects and bids. 

Cost per ton of NOx 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, December 8, 

2011.
Plum Creek Manufacturing - Page 21

March 13, 2012

Plum Creek 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, SO2, and NOx

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 controlled for all four emission units, using a Venturi scrubber for the 

Line 2 MDF Fiber Dryers and ESP technology for the remaining units. Emissions of SO2 are 

minimal, since all four units combust fuels with negligible amounts of sulfur (hog fuel, 

sanderdust, and natural gas). NOx 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 NOx formation. NOx 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 NOx formation. All available NOx control 

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 to working with 

EPA Region 8 to provide additional information to assist in establishing the Reasonable 

Progress goals and strategies for Montana.

Sincerely,

PLUM CREEK MANUFACTURING 

Thomas Ray

Vice President Northwest Resources & Manufacturing

Attachments

cc: Mr. Mitchell Leu, Plum Creek

Ms. Anna Henolson, Trinity Consultants

Ms. Anupama Krishnan, Trinity Consultants
ATTACHMENT A

EPA 114 Request Letter 



ATTACHMENT B

RBLC and Biomass Boiler Permit Search Results
Table B-2. RBLC Search Results for NOx control devices on Wood Products Dryers

FACILITY STATE

PERMIT ISSUANCE 

DATE PROCESS NAME PRIMARY FUEL THROUGHPUT UN

PARAGON PANELS OF ALABAMA, L.L.C. AL 4/12/2006 WOOD FIBER PREP/DRYING 151 mm

LOUISIANA PACIFIC CORPORATION AL 6/14/2006 BOARD PRESS BARK 85000 LBLOUISIANA PACIFIC CORPORATION AL 6/14/2006 BARK BURNER/DRYER BARK 85000 lb

GEORGIA-PACIFIC ORIENTED STRANDBOARD FACILITY AR 1/7/2003 ROTARY CHIP DRYER, (5) WOOD WASTES 600 MMS

NORBORD GEORGIA GA 6/3/2005 WOOD FLAKE DRYERS WOOD 52 OD

OAKDALE OSB PLANT LA 6/13/2005 ROTARY DRYER NOS. 1-3 WOOD 300000

MSF/Y

inch 

WEYERHAEUSER MI 6/11/2002 DRYERS AND BURNERS, WOOD CHIP WOOD 108000 LB

SAGOLA MILL MI 1/31/2008 FLAKE DRYERS

DIBOLL PARTICLEBOARD OPERATION TX 9/28/2001 PARTICLE BOARD PRESS, PB-53 DIBOLL PARTICLEBOARD OPERATION TX 9/28/2001 (2) DRYERS NO 1 & 2, PB-47 DIBOLL PARTICLEBOARD OPERATION TX 9/28/2001 DRYER NO 3, PB-49 DIBOLL PARTICLEBOARD OPERATION TX 9/28/2001 DRYER NO 4, PB-50 DIBOLL PARTICLEBOARD OPERATION TX 9/28/2001 SANDER DUST BOILER, PB-44 WOOD 40 MMB

JASPER ORIENTED STRANDBOARD MILL TX 2/9/2004 DRYERS 1-5 BYPASS 

CARHAGE ORIENTED STRANDBOARD MILL TX 3/16/2004 DRYER BYPASS (2) 

LOUISIANA-PACIFIC HAYWARD WI 6/17/2004 DRYER SYSTEM, LINE I, LINE II WOOD

1. Search Criteria for RBLC: Date range from January 1, 2000 through January, 2011; Process Information included Dryers fired by all fuel types. Dryers with all other fuel types other than hog fuel fuel 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 - 30.530 
Table B-1. RBLC Search Results for NOx control devices on Hog Fuel Boilers 1

FACILITY STATE

PERMIT 

ISSUANCE DATE EQUIPMENT PRIMARY FUEL THROUGHPUT UNIT CONTROL METHOD DESCRIP

MEADWESTVACO KENTUCKY, INC/WICKLIFFE KY 2/27/2002 BOILER, BARK BARK 631 MMBTU/H 

BOGALUSA MILL LA 11/23/2004

NO. 12 HOGGED FUEL 

BOILER BARK 787.5 MMBTU/H

EXISTING OVERFIRE AIR SYSTEM 

NOX BURNERS IN THE UNDER G

HEATER SYSTEM, PLUS GOOD CO

PRACTICES 

S.D. WARREN CO. - SKOWHEGAN, ME ME 11/27/2001 BOILER, #2 WOOD WASTE 1300 MMBTU/H SCNR 

DISTRICT ENERGY ST. PAUL, INC MN 11/15/2001 BOILER WOOD 550 MMBTU/H

SELECTIVE, NON-CATALYTIC RE

SNCR 

KODA ENERGY MN 8/23/2007 BIOMASS BOILER 3 SNCR KODA ENERGY MN 8/23/2007 BIOMASS BOILER 4 SNCR 

NORTHERN SUN ND 5/1/2006 WOOD/HULL FIRED BOILER BIOMASS COMBUSTION CONTROL

SCHILLER STATION NH 10/25/2004

BOILER, WOOD FIRED CFB, 

UNIT #5 BIOMASS 720 MMBTU/h SELECTIVE NON-CATALYTIC RE

CONCORD STEAM CORPORATION NH 2/27/2009 BOILER #1 BIOMASS 32.62 T/H

SELECTIVE CATALYTIC REDUCT

SYSTEM 

CLEAN POWER BERLIN LLC NH 9/25/2009 BOILER 1 WOOD CHIPS 40.75 T/H WOOD

SELECTIVE CATALYTIC REDUCT

WITH STAGED COMBUSTI

BERLIN BIOPOWER NH 7/26/2010 EU01 BOILER #1 WOOD 1013 MMBTU/H

SCR (COLD SIDE OF BAGHOUSE

AMMONIA INJECTION 

BERLIN BIOPOWER NH 7/26/2010 EU01 BOILER #1 WOOD 1013 MMBTU/H

SCR (COLD SIDE OF BAGHOUSE

AMMONIA INJECTION 

SOUTH POINT BIOMASS GENERATION OH 4/4/2006 WOOD FIRED BOILERS (7) WOOD 318 MMBTU/H SELECTIVE CATALYTIC REDU

Plum Creek ManufacturingRBLC Search Boiler_v2.0.xlsx - 11.120
LINDALE RENEWABLE ENERGY TX 1/8/2010 Wood fired boiler biomass 73 T/H Selective Non-catalytic Reduc

LUFKIN GENERATING PLANT TX 10/26/2009 Wood-fired Boiler wood 693 MMBtu/hr Selective Catalytic Reductio

INTERNATIONAL BIOFUELS, INC VA 12/13/2005

WOOD THERMAL OXIDERS 

FOR WOOD PELLENT 

PROCESS WOOD/WOOD PASTE 43 MMBTU/H THERMAL OXIDIZERS AND CEM 

ABERDEEN DIVISION WA 10/17/2002 HOG FUEL BOILER WASTE WOOD 310 MMBTU/H SNCR, BOILER DESIGN 

SKAGIT COUNTY LUMBER MILL WA 1/25/2006

WOOD-FIRED 

COGENERATION UNIT BARK & WASTE WOOD 430 mmBtu/H

SELECTIVE NONCATALYTIC RED

(SNCR) 

DARRINGTON ENERGY COGENERATION POWER 

PLANT WA 2/11/2005

WOOD WASTE-FIRED 

BOILER WOOD WASTE 403 MMBtTU/H SNCR 

CLEWISTON SUGAR MILL AND REFINERY FL 2004 BOILER 8 BAGASSE 1030 MMBTU/H SNCR 

DEL-TIN FIBER L.L.C AR 2/28/2003 HEAT ENERGY SYSTEM BIOMASS 291 MMBTU/H SNCR 

INLAND PAPERBOARD TX 10/5/2004 BOILER BARK 856 MMBTU/H SNCR 

WEYERHAEUSER RED RIVER MILL LA 5/24/2006 NO. 2 HOGGED FUEL BOILER WOOD 940 MMBTU/H SNCR 

1. Search Criteria for RBLC: Date range from January 1, 2000 through January, 2011; Process Information included Boilers fired by all fuel types. Boilers with all other fuel types other than hog fuel are removed from the search results. W

list also includes a search of facilities with recently permitted industrial biomass boilers having SNCR systems installed.

Plum Creek ManufacturingRBLC Search Boiler_v2.0.xlsx - 11.120
ATTACHMENT C

Cost Estimates for SCR, SNCR for Boilers

Cost Estimates for SCR for Dryers
Trinity 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 NOx 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 ft3 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 H2O 6

Electricity Usage 79 78 77 kW 9

Catalyst Cost, Initial 331.91 331.91 331.91 $/ft3 10

Catalyst Cost, Replacement 401.05 401.05 401.05 $/ft3 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 Notation1

90% Control 80% Control 70% Control

Purchased Equipment Costs

Total Equipment Cost2 2,384,625 2,299,625 2,214,625 A

Instrumentation3 238,463 229,963 221,463 0.10 × A

Sales Tax3 0 0 0 --

Freight3 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 Construction5 0 0 0 G

Royalty Allowance5 0 0 0 H

Preproduction Costs 120,903 116,594 112,284 I = 0.02 × (F + G)

Inventory Capital6 1,905 J

Initial Catalyst and Chemicals5 0 K

Total Capital Investment7 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 Labor5 0 1 2 L

Maintenance 129,528 124,872 120,256 M = 0.015 × TCI

Reagent Consumption8 261,459 232,408 203,357 N

Utilities9 312,371 311,712 311,054 O

Catalyst Replacement10 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, Administration5 0 0 0 Q

Capital Recovery11 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 NOX 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 Boiler

 
Trinity 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 Notation1

50% Control 35% Control

Purchased Equipment Costs

Total Equipment Cost2 255,525 256,821 A

Instrumentation3 25,553 25,682 0.10 × A

Sales Tax3 0 0 --

Freight3 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 Facilities5 19,113 19,185 0.05 × (B + C)

Engineering and Home Office Fees5 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 Contingency5 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 Costs5 10,551 10,590 I = 0.02 × (F + G)

Inventory Capital6 12,230 8,561 J

Initial Chemicals5 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 Consumption7 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, Administration5 0 0 Q

Capital Recovery8 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 NOX 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 NOx 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 ft3 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 H2O 6

Electricity Usage 27.5 27.4 27.3 kWhr 9

Catalyst Cost, Initial 331.91 331.91 331.91 $/ft3 10

Catalyst Cost, Replacement 401.05 401.05 401.05 $/ft3 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 Notation1

90% Control 80% Control 70% Control

Purchased Equipment Costs

Total Equipment Cost2 1,934,625 1,866,847 1,799,069 A

Instrumentation3 193,463 186,685 179,907 0.10 × A

Sales Tax3 0 0 0 --

Freight3 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 Construction5 0 0 0 G

Royalty Allowance5 0 0 0 H

Preproduction Costs 98,088 94,651 91,215 I = 0.02 × (F + G)

Inventory Capital6 3 3 3 J

Initial Catalyst and Chemicals5 0 0 0 K

Total Capital Investment7 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 Labor5 0 0 0 L

Maintenance 118,486 114,335 110,184 M = 0.015 × TCI

Reagent Consumption8 61,179 54,381 47,584 N

Utilities9 177,883 177,814 177,745 O

Catalyst Replacement10 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, Administration5 0 0 0 R

Capital Recovery11 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 NOX 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 Notation1

50% Control 35% Control

Purchased Equipment Costs

Total Equipment Cost2 255,525 246,821 A

Instrumentation3 25,553 24,682 0.10 × A

Sales Tax3 0 0 --

Freight3 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 Facilities5 19,113 18,055 0.05 × (B + C)

Engineering and Home Office Fees5 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 Contingency5 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 Costs5 10,551 9,966 I = 0.02 × (F + G)

Inventory Capital6 790 553 J

Initial Catalyst and Chemicals5 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 Consumption7 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, Administration5 0 0 Q

Capital Recovery8 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 NOX 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*F
Trinity 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.
ATTACHMENT D

Process Flow Diagram for Line 1 and Line 2 Dryers