Appendix 9A 

DNRE Best Available Retrofit Technology (BART) Rules 
R 336.1970 Best available retrofit technology; adoption by reference. 

 Rule 970. (1) The provisions of 40 C.F.R., part 51, appendix Y, “Guidelines for BART 

Determinations Under the Regional Haze Rule,” and 40 C.F.R. §51.301, “Definitions,” are 

adopted by reference in R 336.1902. 

History: 2008 MR 4, Eff. Sep. 11, 2008. 

R 336.1971 Best available retrofit technology or BART program. 

 Rule 971. (1) The department shall determine applicability of best available retrofit 

technology based on the provisions referenced in R 336.1970. 

 (2) The owner or operator of a unit subject to BART shall perform an engineering analysis 

as described in the provisions referenced in R 336.1970 and shall provide the results of the 

analysis to the department within 60 days of the effective date of R 336.1970 and 

R 336.1971. 

 (3) If an electric generating unit (EGU) subject to BART is subject to the trading programs 

of the Clean Air Interstate Rule under 40 C.F.R. part 97, the owner or operator of the EGU is 

not required to conduct a BART analysis for sulfur dioxide and oxides of nitrogen emissions 

under this rule. 

 (4) An engineering analysis required by subrule (2) of this rule shall be submitted to the 

department and shall be subject to review and approval by the department. If the department 

determines additional information is required, the department shall provide to the owner or 

operator additional information requests and comments in writing. The owner or operator 

shall provide the requested information within 60 days from receipt of written requests and 

comments from the department. The department may determine that more than 60 days will 

be allowed. 

 (5) The department shall determine the BART level of control for each unit subject to 

BART based on the engineering analysis referenced in subrule (2) of this rule, the provisions 

referenced in R 336.1970, and other information which the department determines to be 

relevant. 

 (6) The owner or operator of a unit subject to BART shall enter into a permit to install or 

consent order with the department to make the BART provisions legally enforceable within 

90 days of the department’s approval of the engineering analysis, unless the department 

determines that more than 90 days will be allowed. BART controls shall be in place and 

operating not later than December 31, 2012. 

 (7) An owner or operator subject to this rule shall measure oxides of nitrogen and sulfur 

dioxide emissions with 1 or more of the following: 

 (a) A continuous emission monitoring system. 

 (b) An alternate method as described in 40 C.F.R. part 60 or 75, adopted by reference

in R 336.1802a, as applicable and acceptable to the department. 

 (c) A method currently in use or a future method developed for use and acceptable to 

the department, including methods contained in existing permit conditions. 

1
R 336.1971 9-3 As Amended 9/11/2008 

 (8) An owner or operator of an emission unit that measures oxides of nitrogen or sulfur 

dioxide emissions by a continuous emission monitoring system shall do either of the 

following: 

 (a) Use procedures set forth in 40 C.F.R., part 60, subpart A and appendix B, and 

comply with the quality assurance procedures in appendix F, adopted by reference in 

R 336.1802a as applicable and acceptable to the department. 

 (b) Use procedures set forth in 40 C.F.R., part 75, and associated appendices, adopted 

by reference in R 336.1802a, as applicable and acceptable to the department. 

 (9) An owner or operator of an emission unit who uses a continuous emission monitoring 

system to demonstrate compliance with this rule and who has already installed a continuous 

emission monitoring system for oxides of nitrogen or sulfur dioxide pursuant to other 

applicable federal, state, or local rules shall meet the installation, testing, operation, quality 

assurance, and reporting requirements specified by the department. 

 (10) An owner or operator of an emission unit that is subject to this rule and has a permit 

or consent order issued under R 336.1971(4) shall submit at a minimum semiannual 

summary reports, in an acceptable format, to the department by March 15 for the reporting 

period July 1 to December 31 and September 15 for the reporting period January 1 to June 30 

of each calendar year. The reports shall include all of the following information: 

 (a) The date, time, magnitude of emissions, and emission rates where applicable, of the 

specified emission unit or utility system. 

 (b) If emissions or emission rates exceed the emissions or emission rates allowed by 

the applicable emission limit, the cause, if known, and any corrective action taken. 

 (c) The total operating time of the emission unit during the time period. 

 (d) For continuous emission monitoring systems, system performance information 

shall include the date and time of each period during which the continuous monitoring 

system was inoperative, except for zero and span checks, and the nature of the system 

repairs or adjustments. When the continuous monitoring system has not been inoperative, 

repaired, or adjusted, the information shall be stated in the report. 

 (11) Quarterly summary reports, if required by the department pursuant to R 336.1213, 

shall be submitted within 30 days following the end of the calendar quarter and may be used 

in place of the semi-annual reports required pursuant to subrule (9) of this rule. 

History: 2008 MR 4, Eff. Sep. 11, 2008. 

2
Appendix 9B 

Determining BART-Eligible and BART-Subject Facilities 
Description of BART-eligible and BART-subject Facilities 

The DNRE determined that the electric generating units (EGUs) subject to BART are included in 

the Clean Air Interstate Rule (CAIR) program and therefore do not have to conduct BART control 

analyses at this time. The remainder of this appendix deals with the Non-EGU sources in 

Michigan that may be subject to BART requirements, using the federal BART guidelines. 

To identify BART-subject sources, DNRE identified 35 non-EGU facilities with a total of 84 

emission units within the state that were potentially subject to BART (i.e. BART-eligible) based on 

dates of installation and commencement of operations. (See Table 1) 

Next, using emission inventory data from the years 2002 and 2004, DNRE evaluated the quantity 

of emissions from each source in relationship to the distance from known Class 1 areas, i.e. Q/d 

values. It was assumed that facilities with higher Q/d values have more than a 0.5 dV impact on 

more days over a relatively large area, and that a Q/d value of 10 TPY/km is a reasonable 

threshold. (i.e., facilities with Q/d values less than 10 TPY/km generally have few days over a 

relatively small area with more than a 0.5 dV impact). This resulted in six BART-eligible sources 

to be modeled in the next step of the evaluation. (See Table 2) 

The next step involved the individual source attribution approach (dispersion modeling) using the 

0.5 deciview threshold value, and using the CALPUFF model on the six facilities that met the Q/d 

criteria. This final step confirmed the six facilities as being non-EGU BART-subject sources (See 

Table 3). However, in the process of doing BART reviews, DNRE determined that an Empire mine 

furnace had shut down and that the Smurfit/Stone Container facility closed, resulting in removal of 

the two facilities from the BART-subject list. 

1
Table 1: BART-eligible Sources in Michigan 

Source Name Unit Description SIC 

Cargill Salt Spreader Stroker Boiler 2899 

Pulverized Coal Boiler 2899 

Chrysler - Trenton Engine Boiler #5 3714 

Boiler #5 3714 

Boiler #6 3714 

Delphi Saginaw Steering 

Boiler #4 3714 

Detroit Diesel Corp B & W 3519 

Boiler # 8, 72 mmbtu/hr 2899 

Boiler # 6, 84 mmbtu/hr 2899 

Dow Corning Corp 

Boiler #9, 72 2899 

Eastern Michigan University Boiler #1 8221 

Boiler #2 8221 

Unit 1 Boilers (1-3) 1011 

Unit 2 Boilers (4-5) 1011 

Pit Boilers (6-7) 1011 

primary ore processing 1011 

Furnace Unit #1 1011 

Unit #1 scrubbers 1011 

Furnace Unit #2 1011 

Unit #2 scrubbers 1011 

furnace unit #3 1011 

Empire Iron Mining 

Unit #3 scrubbers 1011 

Boiler #1 3714 

Boiler #3 3714 

Ford - Livonia Transmission 

Boiler #4 3714 

Boiler #1 3714 

Boiler #2 3714 

Ford - Rawsonville 

Boiler #5 3714 

Ford - Saline Boiler 166-77 3714 

Boiler 403-74 3714 

Ford - Utica Trim GRD Stor Boiler 3714 

Boiler #6 3714 

Boiler #7 3714 

Boiler #8 3714 

Gm - Pontiac Site Ope 

Boiler #9 3714 

Boiler #6 3714 

Boiler #4 3714 

Boiler #5 3714 

Gm - Powertrain Div 

Pouring/casting 33xx 

Gm - Saginaw Metal Boiler # 3-2 3321 

Boiler # 4-2 3321 

Gm - Technical Ctr R 202 Boiler 3711 

Boiler #1 3711 

Kalsec Inc Mfg Plant Cleaver-Brooks 2087 

Lafarge Midwest Inc. Kilns 19 3241 

Kilns 20 3241 

2
Source Name Unit Description SIC 

Kilns 21 3241 

Kilns 22 3241 

Kilns 23 3241 

Louisiana Pacific Corp Boiler #3 2493 

Marathon Ashland Petro Crude Oil heater 2911 

Marblehead Lime Co Kiln 3274 

Merillat Industries Inc Wood Boiler 2434 

Boiler #2 8221 

Boiler #3 8221 

Michigan State University 

Boiler #1 8221 

Michigan Sugar Co Caro Pkg. Boiler#3 2063 

Michigan Sugar Co Carrollton Riley Boiler 2063 

Michigan Sugar Co Sebewaing Pkg. boiler 2063 

Coke ovens & operations 3312 

O2 furnaces & operations 3312 

Boiler #9, 10-100 MMBTU/HR 3312 

National Steel Corp Gld 

Boiler #8, 10-100 MMBTU/HR 3312 

New Page Paper Co Boiler 8 2611 

Boiler 9 2611 

Reheat furnace & heater 3312 

Reheat furnace & heater 3312 

Rouge Steel Company 

Blast Furnaces & operations 3312 

Calciner 2621 

Boiler #3 2621 

Sappi 

Rec. Boiler 2621 

St. Mary’s Cement Lime kiln with pre-calciner 3241 

Smurfit-Stone Container Boiler 2611 

University Of Michigan Boiler #3 8221 

Boiler #4 8221 

Boiler #1(Pelletizing line #1) 1011 

primary crusher 1011 

cooler 1011 

dryer 1011 

Tilden Mining Co 

Kiln 1011 

Western Michigan University Boiler #6 8221 

Boiler #1 8062 

Boiler #4 8062 

William Beaumont Hospital 

Boiler #5 8062 

3
Table 2: Facilities with a Q/d >10 TPY/km 

Facility County Sox* NOx* Q/d 

Empire Iron Mining Marquette 369 2,708 22 

Lafarge Midwest Inc.(All 

Units) 

Alpena 20,623 10,953 127.3 

New Page Paper Company Escanaba 193 1,726.6 22 

St. Mary’s Cement Charlevoix 817 4,209 35 

Smurfit-Stone Container Ontonagon 1,949 1,128 23.5 

Tilden Mining Co Marquette 590 5,314 22 

* In Tons per Year 

Table 3: Final List of BART-subject Sources in Michigan 

BART-subject Facility Name City 

Empire Iron Mining* Marquette 

Lafarge Midwest Inc. Alpena 

New Page Paper Company Escanaba 

St. Mary’s Cement Charlevoix 

Smurfit-Stone Container * Ontonagon 

Tilden Mining Co Marquette 

*Due to permanent shut downs, a furnace at Empire and the Smurfit facility, the two facilities are no longer 

BART-subject 

4
Appendix 9C 

Lafarge BART Technical 

Analysis 
 

PROPOSED BEST AVAILABLE RETROFIT 

TECHNOLOGY (BART) FOR THE 

LAFARGE FACILITY IN 

ALPENA, MICHIGAN 

Prepared for: 

Lafarge 

1435 Ford Avenue 

Alpena, MI 49707 

Prepared by: 

RTP Environmental Associates 

304A West Millbrook Road 

Raleigh, North Carolina 27609 

April 2007
i 

Table of Contents

1.0 EXECUTIVE SUMMARY.....................................................................................1-1

2.0 BACKGROUND INFORMATION.........................................................................2-1 

2.1 Facility Location................................................................................................2-1 

2.2 Description of Operations.................................................................................2-1 

2.3 Class I Area Evaluated.....................................................................................2-3

3.0 BART SELECTION PROCESS...........................................................................3-1 

3.1 SO2 BART Analysis..........................................................................................3-1 

Step 1 – Identify Potentially Applicable SO2 Control Options .................................3-1 

Step 2 – Eliminate Technically Infeasible Control Options .....................................3-7 

Step 3 – Rank Feasible SO2 Control Options.........................................................3-8 

Step 4 – Evaluate Feasible Control Options...........................................................3-9 

3.2 NOx BART Analysis .........................................................................................3-9 

Step 1 – Identify Potentially Applicable NOx Control Options ................................3-9 

Step 2 - Eliminate Technically Infeasible Control Options ....................................3-16 

Step 3 - Rank Feasible NOx Control Options.......................................................3-16 

Step 4 – Evaluate Feasible Control Options.........................................................3-16 

3.3 SO2 and NOx Control Cost Comparision........................................................3-17 

3.4 Proposed BART .............................................................................................3-18

4.0 BART MODEL PROCEDURE .............................................................................4-1 

4.1 Modeled Emissions and Stack Parameters......................................................4-1 

4.2 Modeling Methodology .....................................................................................4-3 

4.3 CALMET...........................................................................................................4-5 

Meteorological Domain...........................................................................................4-5 

Meteorological Data ...............................................................................................4-5 

Geophysical Data...................................................................................................4-7 

CALMET Preprocessing.........................................................................................4-8 

CALMET Analysis ..................................................................................................4-9 

4.4 CALPUFF.......................................................................................................4-10 

Modeling Domain .................................................................................................4-10 

Class I Area Receptors ........................................................................................4-10 

Control File Settings .............................................................................................4-11 

Ozone and Ammonia Background Values............................................................4-11 

4.5 CALPOST ......................................................................................................4-11

5.0 BART MODEL RESULTS ...................................................................................5-1 
ii 

List of Tables

Table 1-1. Proposed BART for Lafarge Alpena...........................................................1-3 

Table 3-1. Comparison of Costs for Feasible BART Controls ...................................3-17 

Table 4-1. Modeled Stack Parameter Data .................................................................4-2 

Table 4-2. Baseline Modeled Emission Rates (lb/day)................................................4-2 

Table 4-3. Post-Control Modeled Emission Rates (lb/day)..........................................4-4 

Table 5-1. Delta Deciview Visibility Impact Rankings (4km CALMET Grid, Annual 

Average Concentrations as Background)...............................................................5-2 

List of Figures

Figure 2-1. Location of the Lafarge Alpena Facility .....................................................2-2 

Figure 2-2. Location of the Lafarge Alpena Facility and the Seney Class I Area.........2-4 

Figure 4-1. Lafarge Meteorological and Computational Domain .................................4-6 
1-1 

1.0 EXECUTIVE SUMMARY 

The U.S. Environmental Protection Agency (EPA) published final amendments and 

guidelines to its 1999 regional haze rule on July 6, 2005 (70 FR 39104). Under this 

regulation, certain existing stationary sources that emit visibility impairing pollutants 

must install and operate the Best Available Retrofit Technology (BART). BART is 

required for sources that fit specific criteria, as discussed below, and that “may 

reasonably be anticipated to cause or contribute” to visibility impairment in any Class I 

area. The determination of what constitutes BART is made on a case-by-case basis 

considering technical feasibility, costs of compliance, energy impacts, and the modeled 

reduction in visibility impacts. 

The BART requirement only applies to sources included in the specific source 

categories listed in CAA Section 169A(g)(7) that also meet the time frame and emission 

level thresholds specified in the BART Guidelines found at 40 CFR Part 51, Appendix Y. 

Once the emission units in the applicable source categories have been identified, the 

second step is to determine whether the units fall within the 15-year time frame 

established by the BART Guidelines. Therefore, BART applicability focuses on sources 

that were “in existence” on August 7, 1977 and not “in operation” before August 7, 1962. 

The third step of identifying BART-eligible emission sources is determining whether the 

source meets a 250 ton per year emission threshold. The 250 ton per year threshold is 

applied facility-wide. To be BART-eligible, the combined potential to emit of the 

emission units meeting the source category and operational date tests must be in 

excess of 250 tons per year for any single visibility impairing pollutant. Visibilityimpairing pollutants include sulfur dioxide (SO2), nitrogen oxides (NOx), and particulate 

matter (PM). 

Lafarge owns and operates a portland cement manufacturing facility in Alpena, 

Michigan. Portland cement manufacturing is one of the specific source categories listed 

in Section 169A. In addition, Lafarge operates five cement kilns that were constructed 

and, based upon available information, became operational between August 7, 1962 
1-2 

and August 7, 1977. Since the potential to emit of the five kilns is in excess of 250 tons 

per year for one or more visibility impairing pollutants, the kilns are considered to be 

BART-eligible. 

 

Based upon source-specific modeling of the Lafarge facility, the Michigan Department of 

Environmental Quality (MDEQ) has determined that the five BART-eligible emission 

units at Lafarge “may reasonably be anticipated to cause or contribute” to a visibility 

impairment at the Seney Wilderness Class I area. This source-specific modeling 

indicates that the emissions from Lafarge change the 24-hour background visibility at 

Seney by more than 0.5 deciviews (the deciview is the accepted metric for expressing 

visibility and changes in visibility). The five kilns at Lafarge are therefore subject to 

BART. 

Once a source is determined to be subject to BART, a BART review is required for each 

visibility-impairing pollutant emitted. The BART review must identify the best system of 

continuous emission reduction considering the following five statutory factors: 1) the 

cost of compliance, 2) energy and non-air quality environmental impacts, 3) any existing 

pollution control in use at the source, 4) the remaining useful life of the source, and 5) 

the degree of visibility improvement reasonably anticipated from implementing BART. 

This document presents the procedures and results of the BART review conducted for 

the five cement kilns at the Lafarge Alpena facility. The BART review focused on 

emissions of SO2 and NOx and did not consider emissions of PM10 as PM10 emissions 

are subject to the Maximum Achievable Control Technology (MACT) standard for 

portland cement (40 CFR 63.1340). The states may assume that the level of control 

required by a MACT standard meets BART (see 70 FR 39164).1

 

1

 PM10 emissions were included in the evaluation of visibility impacts. However, PM10 control options were not 

evaluated as the MDEQ has agreed that the Alpena facility’s compliance with the MACT standards for particulates 

satisfies the BART requirements. 
1-3 

The results presented herein demonstrate that wet scrubbers on the two large kilns 

(K22 and 23) represent BART for control of SO2 and that selective non-catalytic 

reduction (SNCR) on all five kilns represent BART for control of NOx. The analysis 

demonstrates that the addition of SO2 controls on the three smaller kilns would result in 

minimal improvement in visibility at a very high cost. Table 1-1 presents the proposed 

BART for the Lafarge Alpena facility. 

Table 1-1. Proposed BART for Lafarge Alpena 

Emission Unit 

Proposed 

BART 

Pollutant(s) 

Controlled 

Proposed 

BART 

Emission 

Limit 

Visibility 

Improvement 

on 98th 

Percentile 

Day (delta 

deciview) 

Class I 

Area 

Impacted 

Kiln 19 SNCR NOx See note See note Seney 

Kiln 20 SNCR NOx See note See note Seney 

Kiln 21 SNCR NOx See note See note Seney 

Kiln 22 

SNCR, Wet 

scrubbing NOx, SO2 See note See note Seney 

Kiln 23 

SNCR, Wet 

scrubbing NOx, SO2 See note See note Seney 

Kilns 19-23 

See above 

control for 

each kiln NOx, SO2

29.4 TPD 

NOx 53.8 

TPD SO2 -0.83a

 Seney 

Note: Lafarge is proposing facility-wide BART limits. The proposed BART limits are listed once, for all five kilns. The 

facility-wide limits were developed in reliance upon the MDEQ’s recognition that Appendix Y, 40 CFR Part 51 

provides: 

You should consider allowing sources to “average” emissions across any set of BART eligible 

emission units within a fenceline, so long as the emission reductions from each pollutant being 

controlled for BART would be equal to those reductions that would be obtained by simply controlling 

each of the BART-eligible units that constitute BART-eligible source. 

TPD = tons per day. 

a

2003 meteorology.
2-1 

2.0 BACKGROUND INFORMATION

2.1 Facility Location

The Lafarge facility is located on the western shore of Lake Huron in northeastern 

Michigan in Alpena County. The approximate Lambert Conformal Conic (LCC) 

coordinates of the facility are 1,066.778 kilometers east and 641.461 kilometers north. 

Figure 2-1 shows the location of the facility on the Alpena 7.5 minute USGS quadrangle. 

2.2 Description of Operations

The plant includes five dry process kilns, a quarry, raw material grinding and storage, 

finish grinding, and cement loading operations. Kiln Nos. 19-21 are collectively referred 

to as Kiln Group 5 (KG5) while the larger kilns (Kiln Nos. 22 & 23) are referred to as Kiln 

Group 6 (KG6). The facility is defined as a major source of air pollution per Rule 

336.1211 of the Michigan Administrative Rules for Air Pollution Control and under the 

Federal Prevention of Significant Deterioration regulation of 40 CFR 52.21. The facility 

operates under Renewable Operating Permit (ROP) No. MI-ROP-B1477-2006b. 

The production of portland cement at Alpena is a long-dry process (i.e., the facility does 

not have pre-heaters to pre-calcine raw materials before entering the kilns). Limestone 

is quarried on site. Other primary raw material components (aluminum, silica, and iron) 

are transported to the facility via barge, truck, and rail. The raw materials are conveyed 

by belt to one of two dryers prior to being processed in the raw grind operation. Once 

dried and ground, the raw materials are stored in silos. When needed for production, 

the raw materials are withdrawn from the blending silos and fed to the kilns. 

The Alpena facility uses a combination of coal and petroleum coke to provide heat to 

the kilns. Natural gas is also used as a “start-up” fuel. The heat from the hot 

combustion gases is transferred to the raw materials in a countercurrent manner. The 

materials are slowly moved to the lower end by rotation of the kilns. As they move 
2-2 

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0 275 550 1,100 1,650 2,200 ® Meters

Figure 2-1. Location of the Lafarge Alpena Facility 
2-3 

down the kilns, the materials are changed to cementitious or hydraulic minerals 

because of the increasing temperature. The exhaust gases exit the kilns at the elevated 

end. The exhaust gases are controlled with baghouses prior to release to the 

atmosphere. 

Once the cementitious materials (clinker) leave the kilns, the last component of the 

pyroprocessing system is the clinker cooler. In this step, the clinker is rapidly cooled 

using air to lock in desirable product qualities by freezing mineralogy. The clinker cooler 

also enables the material to be cooled for further processing. The final step in the 

manufacture of portland cement at Alpena involves a sequence of blending and grinding 

that transform the clinker into finished portland cement. Gypsum and other materials 

are added as needed to impart specific product properties. These materials and the 

clinker are mixed and milled in the finish mill. The final product is then stored in either 

land or marine silos prior to shipment. The cement is shipped off-site via trucks, 

railcars, and barges. 

2.3 Class I Area Evaluated

Class I areas are national parks and wilderness areas in which visibility is more 

stringently protected under the Clean Air Act than any other areas in the United 

States. Class I areas that are located within 300 km of a BART-eligible source are 

typically evaluated for visibility impacts.2 

There is one Class I area located within 300 km of the Lafarge site that required 

evaluation: the Seney Wilderness Area. Seney is located 250 km to the northwest of 

the Lafarge facility. Figure 2-2 shows the location of this Class I area with respect to the 

Lafarge facility. There is no other Class I area located within 500 km of the Lafarge 

facility. The next closest Class I area is Isle Royale National Park which is located 520 

km northwest of Lafarge Alpena. 

 

2

 Visibility Improvement State and Tribal Association of the Southeast (VISTAS) Regional Planning Organization 

(RPO), “Protocol for the Appication of the CALPUFF Model for Analysis of Best Available Retrofit Technology 

(BART), December 22, 2005 (with revisions January 23 and March 9, 2006). 
2-4 

!!!! [_!!!!!!!!!!!

Lafarge Alpena

Seney Wilderness Area

0 50,000 100,000 200,000 300,000 400,000 ® Meters

Figure 2-2. Location of the Lafarge Alpena Facility and the Seney Class I Area 
3-1 

3.0 BART SELECTION PROCESS

Five basic steps were taken in selecting BART for the Lafarge Alpena kilns: 

• All available retrofit control technologies were identified; 

• Technically infeasible options were eliminated; 

• The technically feasible options were ranked in order of control effectiveness: 

• The energy, environmental, and economic impacts of each control were 

evaluated; and 

• The visibility impact of each control alternative was determined (see 

70 FR 39164). 

Based on this process, Lafarge has proposed BART limits for the Alpena kilns as shown 

in Table 1-1 of this report. 

As discussed previously, the BART analysis for the Alpena plant focused on SO2 and 

NOx controls for the cement kilns. Since the control options for these pollutants are 

basically unrelated, each pollutant is addressed individually. However, because the 

impacts of SO2 and NOx on visibility are similar, the proposed BART limits are based on 

a combined SO2 and NOx control strategy (see Section 3.3).3

3.1 SO2 BART Analysis

Step 1 – Identify Potentially Applicable SO2 Control Options 

Lafarge has identified SO2 control options for retrofit to the Alpena kilns. Based on 

review of U.S. EPA’s RBLC (RACT, BACT, and LAER Clearinghouse) database, 

industry practice, recently issued permits for cement kilns, and considering the potential 

for technology transfer, the SO2 control technologies potentially available4

 for retrofit to 

the Alpena kilns include: 

 

3

 Model results indicate that SO2 and NOx emissions contributed equally to visibility reduction at Seney. Lafarge 

therefore concluded that both SO2 and NOx control strategies would need to be implemented to yield appreciable 

modeled visibility improvement. Modeling output data supporting this conclusion are provided in Appendix E. 

4

 Available retrofit control options are those air pollution control technologies with a practical potential for application 

to the emissions unit and the regulated pollutant under evaluation70 FR 39614]. A source owner is not required to 

purchase or construct a process or control device that has not already been demonstrated in practice. The term 

“demonstrated in practice” is not specifically defined in the BART rule, but EPA proposed to define this term to 
3-2 

• Duct Sorbent Injection; and 

• Flue Gas Desulfurization. 

The following subsections describe each of these technologies and their potential 

applicability to the Alpena kilns. 

Duct Sorbent Injection Systems. In general, sorbent injection systems consist of 

atomizing a reagent slurry or solution into fine droplets into the exhaust gas duct 

upstream of a particulate control device. In situations where there is limited ability to dry 

injected reagent, moist reagent powders (typically hydrated lime) are injected. 

Examples of alkaline reagents used in sorbent injection systems include magnesium 

hydroxide, hydrated lime, and sodium carbonate. The injected reagent reacts with SO2

in the gas stream. Once dry, the byproduct of this reaction consists of fine sulfate and 

sulfite particles along with unreacted reagent. These particles are collected in a 

downstream particulate control device and either disposed of or reintroduced into the 

process. 

Sorbent injection systems, such as Envirocare International’s Micro-Fine Lime system, 

have been applied on cement kilns in recent years to reduce SO2 emissions. With 

respect to the kilns at Alpena, a sorbent injection system could be installed upstream of 

the existing baghouse on each kiln. However, such systems could only be expected to 

reduce SO2 emissions by an estimated 25 percent. This efficiency is a function of the 

relatively low baghouse inlet temperatures at Alpena coupled with the limited duct 

residence time available for drying of injected reagent. The Alpena kilns are equipped 

with waste heat boilers designed to recover energy from the kiln exhaust gas. The 

resultant low temperature at the waste heat boiler exit affects the effectiveness of 

sorbent injection technologies as discussed below. Sorbent injection upstream of the 

 

include any technology that meets the following criteria: (1) it has been installed and operating continually for at least 

6 months on an emissions unit(s) which has been operating at least at 50 percent of design capacity during that 

period of time; and (2) its performance has been verified during that 6 month period with a performance test or 

performance data while operating under a load that coincides with either the operation of the emissions units served 

by the control technology at their PTE, or 90 percent of the control technology's design specifications [61 FR 38249]. 

This definition is assumed to be relevant for purposes of this BART analysis. 
3-3 

waste heat boilers is not feasible due to the potential for plugging and erosion of the 

boilers by injected sorbent. 

The effectiveness of sorbent injection is a function of the moisture content and drying 

time of injected reagent. Because of the gas temperatures downstream of the waste 

heat boilers and the limited duct residence time, a reagent slurry cannot be injected into 

these ducts at Alpena. The moisture in a slurry cannot be evaporated quickly enough to 

prevent either plugging of the baghouses or the formation of significant deposits of 

injected reagent on the duct walls. With limited ability to dry slurry, the moisture content 

of any injected reagent must be kept to a minimum. This factor limits the effectiveness 

of sorbent injection technologies for the Alpena kilns to an estimated 25% SO2 control 

efficiency on a short-term basis. Coupled with an on-stream factor of 80%, Lafarge 

estimates that the overall SO2 control efficiency is 20% for this technology. 

Flue Gas Desulfurization (FGD). A review of technical publications and USEPA 

guidance shows that one of the most effective add-on control technologies for SO2

control involves scrubbing with an aqueous alkaline slurry or solution. This type of addon control technology is commonly referred to as wet flue gas desulfurization. 

Another type of widely-used flue gas desulfurization technology is known as dry or 

semi-dry scrubbing. This is also an effective SO2 control technology because it uses 

water to enhance the reactions between SO2 and the alkaline reagent used. It has the 

advantage of producing a dry byproduct which is may be easier to manage depending 

on the application. The following subsections provide additional information on wet and 

semi-dry FGD systems and their potential applicability to the Lafarge Alpena cement 

kilns. 

Wet Flue Gas Desulfurization. Wet flue gas desulfurization (FGD) systems are 

characterized by low flue gas outlet temperatures and saturated flue gas 

conditions, and a wet sludge reaction product which is dewatered before reuse or 

disposal. Wet FGD systems typically are installed with a particulate matter 
3-4 

control device upstream of the scrubber so that the fly ash and scrubber reaction 

products are collected separately. The following discussion reviews wet 

scrubbing technologies that are potentially applicable to the Alpena kilns. 

Wet Limestone with Forced Oxidation (LSFO) – Limestone with forced 

oxidation (LSFO) is the type of wet limestone FGD process that is most 

commonly used today. A conventional wet limestone FGD system forms a 

scrubber byproduct composed mostly of calcium sulfite (CaSO3) solids. 

The LSFO process produces a scrubber byproduct with very little CaSO3

in the byproduct. Instead, the byproduct from an LSFO FGD system has a 

calcium sulfate dihydrate (CaSO4·2H2O or gypsum) content in excess of 

90 percent. The high gypsum content of the scrubber byproduct makes 

the solids easier to dewater, improves the reliability of the scrubbing 

process, and provides the potential for byproduct reuse. For most 

applications, these factors result in lower overall costs of control than a 

conventional, unoxidized limestone scrubbing process. 

In the LSFO process, hot flue gas exiting the particulate control device 

enters an absorber where a slurry of limestone and gypsum is sprayed 

into the flue gas.5

 The SO2 in the flue gas is absorbed into the slurry 

which is alkaline relative to the absorbed SO2. The flue gas exits the 

absorption tower through a mist eliminator to remove entrained droplets. 

The absorbed SO2 (now mostly dissolved sulfite) contained in the slurry 

drains into a recirculation tank located at the bottom of the spray tower. 

The sulfite is subsequently oxidized to sulfate in the recirculation tank, and 

following the oxidation step, it precipitates as calcium sulfate dihydrate. 

This process is called “forced oxidation,” and involves bubbling air through 

the slurry to force the oxidation of sulfite to sulfate. A portion of the slurry 

 

5

 There are a number of variations on the design of a limestone forced oxidation scrubbing system that may differ 

slightly from the system described here. However the basic principals of SO2 control and byproduct formation are 
3-5 

in the recirculation tank is pumped back into the spray tower, and a portion 

is removed. The removed slurry is dewatered, typically using 

hydrocyclones followed by a horizontal belt filter. The final gypsum 

product may be used in a number of applications. In the case of Alpena, 

depending on process chemistry and gypsum quality, it may be possible to 

reuse the byproduct gypsum by adding it to final cement product. 

For this BART analysis, an overall SO2 removal efficiency of 81% is 

assumed for the LSFO process. This efficiency represents a short-term 

90% SO2 control efficiency coupled with an estimated system on-stream 

factor of 90%. The control efficiency is typical of control efficiencies for 

wet scrubbers applied in this industry. The estimated on-stream factor 

reflects both limited experience with wet FGD systems in the cement 

industry along with the expected impacts on reliability of a single-module 

FGD system. An overall 81% control efficiency is consistent with 

Lafarge’s experience on a cement kiln in Europe that has been retrofitted 

with an FDG system. Lafarge has not be able to identify reliable published 

control efficiency data on other retrofitted FGD systems on long dry 

cement kilns. 

 

Wet Lime FGD Process – In the wet lime FGD process, flue gas leaving 

the particulate control device enters an absorber tower. The SO2 is 

removed from the flue gas when the gas comes into contact with an 

alkaline slurry of hydrated lime and calcium sulfite. The scrubbed flue gas 

exits the absorption tower through a mist eliminator to remove entrained 

droplets prior to gas exiting the system. The reaction products (i.e., 

scrubber slurry composed primarily of calcium sulfite) are withdrawn from 

the absorber and then sent for dewatering and further processing. This 

includes thickening the sulfite sludge and fixating the sludge or filter cake 

 

the same. The differences are principally due to alternative designs that have different features and benefits and 

the choice of technology is often a function of site-specific considerations and individual company preferences. 
3-6 

with lime and/or fly ash. The blend of fly ash, lime, and filter cake is then 

conveyed to a truck loading facility for disposal. 

A significant disadvantage of the wet lime FGD system as compared to 

the LSFO system is the higher operating costs, primarily due to the high 

lime reagent costs and higher byproduct disposal costs. The production of 

lime for this process also has important secondary environmental impacts 

as compared to the LSFO process, including the consumption of natural 

gas or other fuels for calcining raw limestone. 

The wet lime FGD process, like the LSFO process, can be designed for 

short-term SO2 removal efficiencies of 90%. However, due to the nature 

of the byproduct produced by this system, it is not considered a good 

choice for use at Alpena. The production of byproduct gypsum using the 

LSFO is much better match and it also provides cost advantages. For 

these reasons, wet lime scrubbing is not considered further in this BART 

assessment. Because LSFO is the best option from technical and 

environmental perspective, and because it provides equivalent levels of 

performance, this is the only wet scrubbing technology that is evaluated in 

this BART analysis.6

Dry or Semi-Dry Flue Gas Desulfurization. Spray dryers (also referred to as 

“semi-dry” FGD systems) are characterized by flue gas temperatures above the 

saturation point (i.e., the gas exiting the scrubber is at less than 100% relative 

humidity). Dry and semi-dry FGD systems typically use a particulate control 

system downstream of the FGD system to collect both scrubber byproduct and 

fly ash such that the fly ash and the FGD reaction products are commingled into 

a single byproduct stream. 

 

6

 This approach is consistent with the BART rule which states:”It is not necessary to list all permutations of available 

control levels that exist for a given technology - the list is complete if it includes the maximum level of control each 

technology is capable of achieving.” [70 FR 39164] 
3-7 

In the spray drying process, hot flue gases enters a spray dryer vessel. Within 

the spray dryer, a finely atomized slurry of lime and recycled ash is sprayed into 

the flue gas stream. The SO2 in the flue gas reacts with the lime and any alkali 

present in the fly ash to form sulfur salts (mostly CaSO3). As the SO2 reacts with 

the slurry, the water in the droplets evaporates forming solid particles, raising the 

flue gas moisture content, and lowering the flue gas temperature. A baghouse 

downstream of the spray dryer removes the dry solid reaction products and fly 

ash before the scrubbed gas is released to the atmosphere. A portion of the 

collected reaction products and fly ash solids is recycled to the spray dryer 

reagent feed system. The remaining solids are removed for reuse or disposal. 

Other semi-dry technologies involve the use of separate humidification and 

reagent injection steps in a fluidized bed reactor. In this reactor, the elevated 

humidity promotes the reaction between gas-phase SO2 and the semi-dry 

alkaline reagent. Possible reagents used in this type of system include lime and 

soda ash. Soda ash is less desirable because the sodium-sulfur byproducts (i.e., 

sodium sulfate and sodium sulfite) have a high level of solubility and thus, are 

more difficult to dispose of in an environmentally sound manner. 

Like spray drying, the reaction byproducts from the semi-dry technologies are 

typically collected in a fabric filter downstream of the reactor vessel. Some of the 

collected material is recycled to the reactor and a portion is sent to disposal. In 

the case of the Alpena plant, this reactor would have to be located upstream of 

the existing baghouse or a new second baghouse would need to be constructed. 

 

Step 2 – Eliminate Technically Infeasible Control Options 

Of the SO2 control options identified in this BART analysis, duct sorbent injection and 

wet scrubbing are technically feasible for retrofit application to the cement kilns at the 

Lafarge Alpena plant. The various dry scrubbing options are a poor choice for Alpena 
3-8 

and they are deemed infeasible for several reasons. First, there is insufficient space in 

the flue gas path for installation of a dry scrubber. While it may be theoretically possible 

to install dry scrubbers on the Alpena kilns, it is practically infeasible. Construction 

would involve large, complex duct runs, the need for additional gas fans, and complex 

duct/control system configurations. The cost of such a system would result in a dry 

FGD system that costs as much or more as a wet FGD system while providing less 

effective SO2 removal. 

Second, the presence of the waste heat boilers in the gas path makes dry scrubbing a 

poor choice for application to the kilns at Alpena. The reduction in gas temperature by 

the waste heat boilers limits the applicability of dry scrubber systems because less 

water can be used in the scrubbing process. When less water is used, dry scrubbing 

tends to be less effective. 

Finally, the effect of collecting removed SO2 in the kiln baghouses on the overall sulfur 

balance in the kilns presents a problem. Because much of the cement kiln dust (CKD) 

collected in the baghouses is recycled to the kiln, capturing and returning large amounts 

of sulfur to the process will result in reduced control effectiveness for these 

technologies. Alternatively, control efficiencies can be maintained at design levels at 

the expense of increased rates of CKD disposal to remove sulfur from the kiln system. 

Wet scrubbing is a better option because the gypsum byproduct can be added to the 

final product from the plant, thus eliminating the production of additional waste material 

as a result of installing an SO2 control system. 

Step 3 – Rank Feasible SO2 Control Options 

The most effective, technically feasible SO2 control option for the Alpena kilns is wet 

FGD at 81% overall SO2 control efficiency (90% control and 90% on-stream factor). 

The least effective option SO2 control option identified for the Alpena kilns is the use of 

duct sorbent injection at an overall SO2 control efficiency of 20% (25% control and 80% 

on-stream factor). 
3-9 

Step 4 – Evaluate Feasible Control Options 

The results of the visibility impact analysis performed for the Lafarge Alpena kilns show 

that both SO2 and NOx impacts on visibility are similar when compared on a mass 

emissions basis (i.e., SO2 and NOx reductions both result in similar visibility 

improvements per ton of emissions reduction). For this reason, Lafarge has evaluated 

the effectiveness, costs, and energy and environmental impacts of the technically 

feasible SO2 and NOx control technologies identified in this BART analysis together and 

used this assessment to select BART based on a combination of SO2 and NOx controls. 

The results of this combined SO2 and NOx assessment are contained in Section 3.4. 

3.2 NOx BART Analysis

Step 1 – Identify Potentially Applicable NOx Control Options 

Lafarge has identified possible NOx control options for retrofit to the Alpena kilns. 

Based on review of U.S. EPA’s RBLC (RACT, BACT, and LAER Clearinghouse) 

database, industry practice, recently issued permits for cement kilns, and considering 

the potential for technology transfer, the available NOx control technologies that are 

potentially applicable for retrofit to the Alpena kilns include: 

• Process Optimization 

• Low NOx Burners; 

• Selective non-catalytic NOx reduction (SNCR);and 

• Selective catalytic NOx reduction (SCR). 

The following subsections describe each of these technologies and their potential 

applicability to the Alpena kilns. 

Process Optimization. Any effort that is related to reducing the amount of fuel fired in 

a cement kiln can be characterized as process optimization since reduced fuel 

consumption (e.g., improved fuel efficiency) generally results in reduced NOx 

emissions. The Lafarge kilns have been upgraded over the years to incorporate 

enhanced process monitoring systems, advanced computer controls, and necessary 

instrumentation to improve overall kiln operation. The baseline and projected NOx 
3-10 

emission rates from the Alpena kilns reflect the impact that process optimization has 

had on reducing NOx emissions. Since process optimization is a technically feasible 

NOx control technique that is currently being used by the facility, it is not considered 

further in this analysis (i.e., this technology cannot be retrofit to the Alpena kilns and its 

effects are already included in the baseline NOx emissions from the facility). 

Low NOx Burners. Low NOx burner designs limit NOx formation by lowering the 

burner flame temperature, minimizing residence time at peak temperatures, and 

reducing the flame aggressiveness within the combustion zone. These burner designs 

typically introduce fuel in a sub-stoichiometric (lean) air-to-fuel ratio (generally 6 to 10 

percent) at the primary burner inlet to reduce the combustion zone temperature and 

create an air-starved flame. Secondary air inlets introduce more supplemental air 

beyond the primary flame to complete combustion. The goal of low NOx burner 

technology is to create an ignition of the fuel in an oxygen deficient environment, 

thereby creating less NOx. 

In many industries using conventional steam boilers, the implementation of low NOx 

burners has been very successful. However, in cement manufacturing, the success of 

low NOx burners is limited because much higher burning zone temperatures (as 

compared to the combustion temperature range found in industrial and utility boilers) 

are essential to achieve acceptable product quality. Lafarge is currently in the process 

of installing low-NOx burners on the Alpena kilns. Thus far, two of the five kilns have 

been fitted with low-NOx burner systems, and the installation of these low-NOx burner 

systems influence the NOx reductions that are achievable relative to baseline emissions 

for BART purposes. 

Selective Non-Catalytic Reduction (SNCR). SNCR is an add-on control technology 

that involves injection of aqueous or anhydrous ammonia (NH3), or urea (urea is 

composed of two attached ammonia molecules) into the gas stream. The injected 

ammonia is converted by OH* free radicals to ammonia free radicals (i.e., NH2*), which 

react with NOx to form N2 and H2O. The optimum temperature range for this reaction is 
3-11 

1,600oF to 1,900oF. Above 1,900oF, the amount of NH3 that oxidizes to NOx increases, 

and, in turn, the NOx reduction performance deteriorates. Both laboratory work and 

field data show NH3 slip7 to be a strong function of temperature. At temperatures at or 

above 1,900oF, unreacted NH3 emissions decrease due to the NH3 oxidation to NOx. At 

temperatures at or below 1,600oF, unreacted NH3 emissions may rapidly increase. At 

Alpena, NH3 can be injected into the kiln in a region that operates between 1,600oF and 

1900oF. This temperature window is appropriate for SNCR application. 

The following factors influence the control effectiveness of SNCR: 

• Temperature and oxygen availability (i.e., the NH3 injection location); 

• The baseline, or uncontrolled NOx concentration; 

• Mixing; 

• Reagent Ratio (i.e., the NH3 to NOx molar ratio at the injection point); 

• NH3 accumulation; 

• Excess ammonia emissions; and 

• Ammonium salt formation. 

Based on the current state of knowledge, these technical differences usually do not 

result in an SNCR system's "inability to perform" but instead present a "level of 

performance" question (i.e., generally, the central issue is the exact level of NOx 

reduction that can be achieved when SNCR is applied). 

For SNCR to work effectively, the gas stream being treated must have a relatively high 

concentration of NOx as opposed to other potential reactants with which NOx would 

compete with to react with NH3. The presence of competing reactants in the gas stream 

may result in less NH3 to convert NOx to its non-polluting forms. This would reduce the 

effectiveness of the SNCR process. 

Second, the desirable SNCR chemical reactions are most effective in a temperature 

range between 1,600°F and 1,900°F. Above the high end of the SNCR temperature 

range, the NOx reduction efficiency degrades dramatically; in fact, at higher 

 

7

 “Slip” is a term used to refer to emissions of unreacted ammonia from SNCR and SCR processes. 
3-12 

temperatures, the injected reagent can oxidize and actually increase NOx emissions. 

Below the low end of the temperature range, the reaction rates are not rapid enough for 

the injected reagent to react completely. Therefore, selection of the proper temperature 

range for ammonia or urea injection is critical to achieving optimum performance of 

SNCR. 

Finally, SNCR requires an oxidizing, or fuel-lean atmosphere to effectively reduce NOx 

emissions. In a fuel-rich, or reducing environment, partially oxidized fuel (e.g., CO) 

competes with NH3 for OH* radicals, thus reducing NOx control effectiveness. In 

addition, ammonia interferes with the complete oxidation of organic compounds in the 

fuel, potentially causing a rise in CO emissions. These three conditions must be met for 

SNCR to be most effective in NOx reduction. 

The successful application of SNCR also depends on the accurate injection of the 

optimum quantity of reagent NH3. Insufficient reagent will not result in effective control, 

while excess reagent will result in excessive ammonia slip. Ammonia is typically 

injected in approximately equal molar quantities relative to the NOx present in the gas 

stream. While this injection ratio can theoretically result in conversion of 50% or more 

of the NOx with an ammonia slip of 10 ppm or less, there is a strong potential for the 

formation of a detached plume resulting from the presence of chlorides and sulfates in 

the exhaust gas stream. These compounds are present in the raw materials and are 

released in the kiln system. 

In recent years, SNCR has been applied to a number of cement kilns in both the U.S. 

and internationally. However, nearly all of these applications have been on modern 

preheater/precalciner kilns and only limited testing has been conducted on long dry kilns 

similar to those at the Alpena plant. The key reason for this is the location within the 

kiln system where reagent injection occurs. In a preheater/precalciner kiln, reagent 

injection occurs at the exit of the kiln in the lower part of the preheater tower. This 

injection location is readily accessible using conventional injection technology. In a 

long-dry kiln, injection must occur mid-kiln because this is where the gas temperature is 
3-13 

in the proper range for the NOx reduction reactions to occur. Specialized injection 

systems are required to allow reagent injection in a mid-kiln location. 

Lafarge has completed an engineering assessment and determined that SNCR can be 

applied to the Alpena kilns. Based on this assessment, Lafarge estimates that SNCR, 

in combination with the low-NOx burners now being installed on the Alpena kilns, can 

achieve 35% NOx reductions on Kiln Group 5 and 40% NOx reductions on Kiln Group 6 

(relative to current baseline NOx emissions). These reduction efficiencies are 

consistent with the reduction efficiencies that have been observed on the limited SNCR 

testing and operation for other long-dry kilns. 

Selective Catalytic Reduction (SCR). Like SNCR, SCR systems use NH3 to 

chemically convert NOx to molecular N2 (i.e., the same form of nitrogen that comprises 

79% of the air we breathe). However, as the name indicates, SCR uses a catalyst to 

promote the selective reaction of NOx and ammonia. Ammonia injected into the gas 

stream reacts with NOx and the SCR catalyst enables these reactions to occur at lower 

temperatures than are possible with SNCR. While catalysts can operate over a range 

of temperatures, the optimal temperature range for SCR applications is between 570o to 

750oF, well below the 1,600oF to 1,900oF temperature range for SNCR reactions 

discussed previously. 

The SCR catalytic reactions occur on the surface of the catalyst structure. However, 

the catalyst structures are not composed of simple, flat surfaces. The catalyst is 

designed to have a series of large openings termed “macropores” and small openings 

termed “micropores.” These macropores and micropores maximize the surface area of 

the catalyst available for reaction with NOx and NH3. 

A set of SCR catalyst beds is placed in series in a large vessel located in a part of the 

process where the gas temperatures are in the appropriate range during routine 
3-14 

operation. The NH3

8

 is injected at a controlled rate upstream of the catalyst using an 

injection grid designed to ensure relatively even NH3 distribution, good mixing, and 

minimum NH3 slip. The injected NH3 reacts with NOx compounds (i.e., NO and NO2) on 

the surface of the catalyst in equal molar amounts (i.e., one molecule of NH3 reacts with 

one molecule of NOx) to form N2 and water. 

There is only one large scale installation of SCR on a cement plant in the world with any 

significant operating experience.9 This installation is at the Solnhofen Cement Works in 

Germany. This is a preheater kiln with the SCR system located at the exit of the 

preheater tower. In this location, the kiln exhaust gas temperature is in excess of 610oF 

which is in the correct range for SCR to function.10 There is no equivalent location for 

installing an SCR system in Alpena’s long dry kilns. The raw materials used in the 

Solnhofen plant differ significantly from those at Alpena. The Solnhofen kiln raw 

materials contain minimal amounts of sulfur and alkali while the Alpena kiln raw 

materials contain appreciable amounts of both. These compounds are significant 

because they contribute to SCR problems such as catalyst deactivation and fouling. In 

addition, the presence of sulfur compounds can lead to downstream problems such as 

increased particulate emissions and plugging and corrosion of heat exchangers and 

particulate control equipment. 

Lafarge has assessed the publicly available information regarding the Solnhofen SCR 

application and has determined that the long-term demonstrated performance of the 

SCR system at Solnhofen shows a demonstrated NOx reduction efficiency that is 

 

8

 The NH3 reagent can be in the form of an aqueous solution (typically 25 wt. % NH3), anhydrous NH3, or as a 

product of urea decomposition. 

9

 A second commercial-scale SCR system has been installed in Europe on a cement kiln at Cementeria di 

Monselice. This unit began operation in mid-2006. Very little data are available on this application, but what data 

are available show that it differs significantly from the Alpena kilns. The Monselice SCR system is installed on a 

pre-heater, pre-calciner kiln system. There is no equivalent location in the Alpena kilns that would allow 

installation of such a system. 

10 When it was operational, the SCR system at the Solnhofen Cement Works would be bypassed if the flue gas 

temperature dropped below 320oC or about 610oF. 
3-15 

similar to the reduction efficiencies expected to be achieved using SNCR.11 These data 

are consistent with the fact that this system is currently not operational and SNCR is 

being used to meet the NOx limit for this facility. In other words, over the long-term, the 

Solnhofen SCR system has not preformed better than the SNCR system and, as of this 

writing, it has been shutdown. 

The Solnhofen SCR system did operate over a period of several years, but as described 

above, its long-term, demonstrated control effectiveness was not measurably different 

than the expected control effectiveness of SNCR (on the order of 30 to 40% based on 

publicly available data). In addition, there are a number of significant differences 

between the Solnhofen application and the Alpena kilns including: 

• Kiln design; 

• Flue gas sulfur levels; and 

• Particulate mass loadings and compositions. 

For the above reasons, the European cement plant experience with SCR systems does 

not meet the test of being “demonstrated in practice”. 

There are a number of issues that must be considered in evaluating the potential 

application of SCR to the kilns at Alpena. First, as with SNCR, temperature is a critical 

variable in application of SCR technology to any source. In the case of the Alpena kilns, 

there is no location in the gas path where SCR could be applied. Second is the longterm viability of SCR technology in cement kiln applications. There are no known 

applications of SCR to long dry cement kilns like those at Alpena. 

It has been theorized that an SCR system could be installed downstream of the dust 

collection equipment on long dry kilns. Such an application would involve additional fuel 

combustion to reheat the gas and then the use of heat recovery equipment to limit the 

additional fuel used. This type of SCR installation has not been tested or demonstrated 

on a cement kiln (i.e., it has not been “demonstrated in practice”) and it presents a 

 

11 See for example: “Response to Comments, Permit No. 2000-05-077”; Submitted to Missouri Department 
3-16 

number of potential problems including the issue of fine particulate emissions generated 

by the SCR system itself, the potential for significant production of sulfuric acid mist in 

SCR system, and the potential for rapid catalyst deactivation due to the fine particulate 

in the effluent gas. The only U.S. applications of SCR in a low-dust environment using 

heat recovery of the SCR effluent to preheat the SCR inlet stream are on very low sulfur 

applications (i.e., less than 10 ppm SO2). Any attempt to apply this type of system to 

the Alpena kilns would be experimental in nature and such experimental technologies 

are not considered “available” when it comes to determining BART (as this term is 

described in the BART rule). 

Step 2 - Eliminate Technically Infeasible Control Options 

Of the NOx control options identified in this BART analysis, low-NOx burners and SNCR 

are feasible options for application to the Alpena kilns. 

The application of SCR to the Alpena kilns represents a technology experiment that 

would require significant time, resources, and risk. The BART process is intended to 

apply “available” technologies to existing facilities. Thus, SCR is not considered 

“available” as its application would require significant development and testing before 

the suitability for application to the Alpena kilns could even be determined. 

Step 3 - Rank Feasible NOx Control Options 

The most effective, technically feasible NOx control option for the Alpena kilns is the 

application of low-NOx burners and SNCR in combination. Lafarge estimates that this 

combination of technologies can achieve 35% NOx reduction on KG5 and 40% 

reduction on KG6. 

Step 4 – Evaluate Feasible Control Options 

The results of the visibility impact analysis performed for the Lafarge Alpena kilns show 

that both SO2 and NOx impacts on visibility are similar when compared on a mass 

 

of Natural Resources by: Holcim (US) Inc.; April 8, 2004. 
3-17 

emissions basis (i.e., SO2 and NOx reductions both result in similar visibility 

improvements per ton of emissions reduction). For this reason, Lafarge has evaluated 

the effectiveness, costs, and energy and environmental impacts of the technically 

feasible SO2 and NOx control technologies identified in this BART analysis together and 

used this assessment to select BART based on a combination of SO2 and NOx controls. 

3.3 SO2 and NOx Control Cost Comparision

Table 3-1 summarizes the results of Lafarge’s evaluation of the costs of SO2 and NOx 

control technologies determined to be technically feasible for retrofit to the Alpena kilns. 

Note that the energy impacts and secondary environmental impacts of these 

technologies are judged to be modest. Wet FGD will increase demand for electrical 

energy to operate pumps and fans in the FGD system. The FGD system will generally 

be closed loop with respect to water, so wastewater production will be minimal. Fresh 

water demand for this system can be readily met using existing plant water systems. 

Duct injection may result in a small increase in power demand and a small increase in 

the amount of CKD that must be disposed of. SNCR will result in an increase in NH3

emissions which can cause formation of fine particulates through reaction with SO3

and/or HCl in the exhaust gases from the kiln. None of these impacts are judged to be 

significant relative to the benefits of the control technologies evaluated. 

Table 3-1. Comparison of Costs for Feasible BART Controls 

Control Costs ($/ton)* 

Control Option KG5 KG6

Wet FGD $7,952 $1,087 

Duct Injection $3,367 $754 

SNCR $713 $498 

* See Appendix B for details of how these costs were estimated. 
3-18 

As shown in Table 3-1, certain of the estimated control costs appear reasonable and 

certain costs are excessive. In particular, the costs of both duct injection and wet FGD 

applied to KG5 at approximately $3,400 and $8,000 per ton, are excessive. This 

determination is made relative to the costs of the other control options listed in 

Table 3-1, relative to the costs/value of incremental SO2 control under the acid rain 

program, and relative to past SO2 BACT determinations in the Midwest. For example, 

the current value of SO2 allowances available for purchase (and potential retirement) 

under U.S. EPA’s acid rain program (i.e., Title IV of the 1990 Clean Air Act 

amendments) is less than $500/ton.12 The reason SO2 control costs for KG5 are 

excessive is because of the low SO2 emissions rate from these kilns relative to the 

volume of exhaust gases produced. KG6 represents a much more cost-effective 

location to achieve significant SO2 reductions at the Alpena plant. 

In addition, as discussed in Section 5, addition of SO2 controls on KG5 result in minimal 

improvement in visibility. The addition of SO2 controls on KG5 results in only two fewer 

days in a three year period with a visibility impact at Seney in excess of the 0.5 dv 

criterion. 

Based on this assessment, Lafarge concludes that the BART limit for the Alpena plant 

should based on the implementation of the SNCR on KG5 and KG6 and the 

implementation of wet FGD on KG6. Implementation of additional controls results in 

substantial added costs with only limited visibility improvement (as measured by the 

total emissions reductions achieved). The specific visibility impacts of the proposed 

BART controls are evaluated and discussed in Section 5. 

 

3.4 Proposed BART

Lafarge proposes to install SNCR on all kilns (KG5 and KG6) and wet scrubbers on the 

kilns in KG6. Consistent with this control plan, Lafarge is proposing a facility-wide 

BART limit on all five kilns of 29.4 tons of NOx per day and 53.1 tons of SO2 per day. 

 

12 CantorCO2e Real Time Market Data; Spot SO2 Market Summary; March 13, 2007. 
3-19 

Lafarge proposes that these limits be expressed as a 30-day rolling average. These 

proposed limits are based on applying the BART technology control efficiencies outlined 

in Sections 3.1 and 3.2 to the maximum daily emission rates measured during the 2002-

2004 period for each kiln. Specifically, the baseline, actual maximum emissions from 

the two kiln groups were determined to be: 

Baseline Maximum Emissions 

Compound (tons/day) 

KG5 KG6 

SO2 38.1 78.7 

NOx 18.9 28.5 

Table 1-1 summarizes the proposed BART technologies and emission limits in more 

detail. Lafarge is proposing mass emission limits for NOx and SO2 that apply to the 

total emissions from the BART-affected emission units (i.e., Kilns 19-23). Lafarge will 

employ continuous emission monitors to record mass emissions on a daily basis to 

insure compliance. 
4-1 

4.0 BART MODEL PROCEDURE

4.1 Modeled Emissions and Stack Parameters

Maximum, 24-hour actual emission rates during normal operation for 2002-2004 were 

determined and modeled in CALPUFF to calculate baseline visibility impacts at Seney. 

Baseline NOx and SO2 emissions from the kilns were obtained from continuous 

emission monitors (CEMS) during the 2002-2004 period. Particulate emissions were 

based upon stack test data. All PM10 emission were assumed to be filterable and were 

speciated, using VISTAS provided speciation profiles for dry process cement kilns, into 

PM10 (PMC or PM Coarse), PM2.5 (PMF or PM Fine), and elemental carbon (EC). As 

recommended by VISTAS, the condensable PM10 fraction was assumed to be 85.6% of 

the total PM10 emissions rate. The total PM10 rate was calculated from the filterable 

fraction assuming that the filterable fraction is 14.4% of the total. The condensable 

fraction was then speciated (again using the VISTAS recommended speciation profiles) 

into sulfates and secondary organic aerosols (SOA). The PM speciation calculations 

are presented in Appendix A. 

Based upon guidance from the Michigan Department of Environmental Quality (MDEQ), 

Lafarge modeled emissions of PM10, NOx and SO2 in calculating baseline visibility 

impacts at Seney. Lafarge did not model emissions of volatile organic compounds 

(VOCs) or ammonia as these pollutants are not believed to contribute significantly to 

visibility degradation at Seney. Only emissions of NOx and SO2 were varied in 

evaluating the affects of the various control technologies on visibility improvement. 

Lafarge did not evaluate PM control alternatives because the kilns are subject to a 

MACT standard which limits emissions of PM and, according to the final BART 

Guidelines, states may assume that the level of control required by a MACT standard 

meets BART (see 70 FR 39164). The stack parameters and emission rates that were 

modeled are provided in Tables 4-1 and 4-2, respectively. 
4-2 

Table 4-1. Modeled Stack Parameter Data 

Model 

Source 

ID 

Source 

Description 

LCC E 

(km)a

LCC N 

(km)a

Stack 

Height 

(m) 

Base 

Elevation 

(m) 

Stack 

Diameter 

(m) 

Exit 

Velocity 

(m/sec) 

Temp. 

(K) 

Sigma 

Y (m) 

S

Z 

SV00031 K19 Exhaust 1066.746 641.668 67.06 182.0 3.96 3.91 439.26 0 SV00032 K20 Exhaust 1066.762 641.671 67.06 182.0 3.96 3.91 439.26 0 SV00033 K21 Exhaust 1066.780 641.675 67.06 182.0 3.96 6.03 439.26 0 SV00047 

K22-23 Exhaust 1066.867 641.697 89.00 182.0 7.32 6.73 469.82 0 

KILNS 

Worst –Case Combined 1066.789 641.678 81.37 182.00 6.15 5.97 459.19 0 

aLambert Conformal Conic (LCC) coordinates are based upon an origin of 40.0N and 97.0W with Standard Parallels of 33.0N and 45.0N 

Table 4-2. Baseline Modeled Emission Rates (lb/day) 

Model 

Source 

ID 

Source 

Description SO2 SO4 NOx HNO3 NO3 PMC PMF EC 

SV00031 K19 Exhaust 34,760 577 13,116 0 0 51 54 6 SV00032 K20 Exhaust 19,656 577 12,712 0 0 51 54 6 SV00033 K21 Exhaust 21,796 577 11,942 0 0 51 54 6 SV00047 

K22-23 Exhaust 157,398 2,768 56,956 0 0 245 257 26 

KILNS 

Worst –Case Combined 233,610 4,498 94,726 0 0 399 417 43 

Notes: PMFine (PMF) or "soil" = PM < 2.5 um in diameter. PMCoarse (PMC) = PM between 2.5 and 10 um in diameter. SOA = 

aerosols. EC = elemental carbon. Kiln PM speciation based upon VISTAS guidance. 
4-3 

To simplify the modeling analysis, Lafarge modeled a single, worst-case stack. The 

emissions from each kiln were summed and assumed to be emitted from the worst-case 

stack. The parameters for the worst-case stack were calculated as a weighed sum with 

total emissions as the basis for the weighting. Appendix A provides the values used in 

calculating the worst-case parameters. The worst-case stack parameters were 

assumed not to be affected by the controls employed. That is, only stack gas emissions 

were varied in evaluating BART control alternatives. Stack gas exit temperature and 

flow as well as the physical parameters (i.e., diameter and height) were held constant in 

the control technology evaluation. 

The post-control emission rates for each of the BART control scenarios evaluated were 

based upon the anticipated reduction from each control device (expressed as a 

percentage) and the baseline rates. The post-control emission rates for each modeled 

BART scenario are presented in Table 4-3. 

4.2 Modeling Methodology

The modeling followed EPA’s Interagency Workgroup on Air Quality Modeling 

(IWAQM), Phase 2 recommendations, for long-range transport13 and the Lake Michigan 

Air Director’s Consortium (LADCO) Single Source Modeling Guidance.14 The IWAQM 

guidance was developed to address air quality impacts—as assessed through the 

Prevention of Significant Deterioration permitting program. The LADCO guidance was 

developed specifically for BART modeling. 

 

13 Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary Report and Recommendations for 

Modeling Long_Range Transport Impacts, EPA-454/R-98-019, U.S. Environmental Protection Agency, Air Quality 

Modeling Group, Research Triangle Park, North Carolina. December, 1998. 14 Single Source Modeling to Support Regional Haze BART Modeling Protocol, Lake Michigan Air Directors 

Consortium, Des Plaines, IL. March 21, 2006. 
4-4 

Table 4-3. Post-Control Modeled Emission Rates (lb/day) 

Source 

Description SO2 SO4 NOx HNO3 NO3 PMC PMF EC 

Control Scenario 1: SNCR KG5 & 6, Wet Scrubbing KG6 (Proposed BART) KG5 76,212 1,730 24,551 0 0 153 161 17 KG6 31,480 1,384 34,174 0 0 245 257 26 Total 107,692 3,114 58,724 0 0 399 417 43 Reduction from Baseline (%) 54 31 38 0 0 0 0 0 Control Scenario 2: SNCR KG5 & 6, Wet Scrubbing KG6, Duct Injection KG5 KG5 60,970 1,557 24,551 0 0 153 161 17 KG6 31,480 1,384 34,174 0 0 245 257 26 Total 92,449 2,941 58,724 0 0 399 417 43 Reduction from Baseline (%) 60 35 38 0 0 0 0 0 Control Scenario 3: SNCR KG5 & 6, Wet Scrubbing KG5 & 6KG5 15,242 865 24,551 0 0 153 161 17 KG6 31,480 1,384 34,174 0 0 245 257 26 Total 46,722 2,249 58,724 0 0 399 417 43 Reduction from Baseline (%) 80 50 38 0 0 0 0 0 

Note: KG5 = Kiln Group 5 which consists of Kilns 19-21. KG6 = Kiln Group 6 which consists of Kilns 22 & 23.
4-5 

4.3 CALMET

Meteorological Domain 

The Meteorological Domain was set to one hundred kilometers beyond all sources and 

receptors (see Figure 4-1). This Domain was cast on a Lambert Conformal Conic 

(LCC) coordinate system. The projection parameters and Meteorological Domain 

coordinates are as follows: 

LCC Projection Parameters 

Projection Origin – RLAT0 = 40N, RLON0 = 97W 

False Easting – FEAST = 0 

False Northing – FNORTH = 0 

Matching Parallels - XLAT1 =33N, XLAT2 = 45N 

Meteorological Domain 

Datum - WGS-84 

Southwest corner (km) - XORIGKM = 725.1340, YORIGKM = 541.6970 

Number of Grid Cells - NX = 110, NY = 78 

Horizontal Grid Spacing (km) - DGRIDKM = 4 

Vertical Grid Spacing (km) – 20, 40, 80, 160, 320, 1000, 1500, 2200, 3000 

(top of each cell) 

Meteorological Data 

Prognostic data for 2002, 2003 and 2004 was used for developing the Initial Guess 

Wind Fields in the CALMET model. The prognostic data was supplied by LADCO. 

These data cover an area from the eastern seaboard to the Rocky Mountains and from 

the Gulf of Mexico to well into Canada. 

Surface data for 2002, 2003 and 2004 was used as observations in developing the Step 

2 Wind Fields in the CALMET model. The surface data were purchased from BEE-Line 

Software, Asheville, NC. BEE-Line Software obtained these data from the National 

Climatic Data Center, Asheville, NC. The data includes all stations, with sufficient data 

for modeling, within or near the meteorological modeling domain. A total of eleven 

stations were used. 
4-6 

!!!!!! [_

!!!!!!!!

!!!!!!

!!!!

Lafarge Alpena

Seney NWR

0 37,500 75,000 150,000 225,000 300,000 ® Meters

MET Domain

Computational Domain

Figure 4-1. Lafarge Meteorological and Computational Domain 
4-7 

Upper air data for 2002, 2003 and 2004 were used as observations in developing the 

Step 2 Wind Fields in the CALMET model. The upper air data were purchased from 

BEE-Line Software, Asheville, NC. BEE-Line Software obtained these data from the 

NOAA Forecast Systems Laboratory web site. Two upper air stations, Gaylord and 

Green Bay, were found to be located near or in the meteorological modeling domain. 

Precipitation data for 2002, 2003 and 2004 were used as observations in developing the 

Step 2 Wind Fields in the CALMET model. The precipitation data were purchased from 

BEE-Line Software, Asheville, NC. BEE-Line Software obtained these data from the 

National Climatic Data Center, Asheville, NC. The dataset includes all stations, with 

sufficient data for modeling, within or near the meteorological modeling domain. A total 

of 19 stations were used for 2002 and 21 stations were used for 2003 and 2004. 

A list of all the surface, upper air, and precipitation stations that were used in the 

analysis are presented in Appendix C. 

Geophysical Data 

Land Use data were used to develop the surface characteristic for input to the CALMET 

model. For the US portion of the modeling domain, the best large-scale land use data 

sets are the USGS National Land Cover Dataset (NLCD 92) which have a 30 meter 

resolution. These data were used for the US portion of the modeling domain. The 

NLCD data is not available outside of the US. For the Canadian portion of the modeling 

domain, the USGS EROS Global Land Cover Characterization (GLCC Version 2) were 

used. 

Terrain data is used by the CALMET model to modify the Initial Guess Wind Fields in 

developing the Step 1 Wind Fields. For the US portion of the modeling domain, USGS 

1:250,000 scale Digital Elevation Model (DEM) data were used. For the Canadian 

portion of the modeling domain, the USGS GTOPO30 data were used.
4-8 

CALMET Preprocessing 

The SMERGE program reads multiple surface data files that may be in several different 

formats and makes any needed units conversion and writes the combined data to a 

single file (surf.dat). The surf.dat file is read by CALMET as observations and is used in 

the modification of the Step 1 Wind Fields in developing the Step 2 Wind Fields. 

The READ62 program reads an upper air data file and extracts soundings, makes any 

needed units conversion and writes the data to a processed data file. READ62 is 

repeated for each upper air file. Most upper air data files contain missing data and 

other errors. These missing data are filled and the errors are corrected. These 

changes are documented in the upper air list (.lst) files. The processed data files are 

read by CALMET as observations and are used in the modification of the Step 1 Wind 

Fields in developing the Step 2 Wind Fields. 

PXTRACT and PMERGE extract data for specific stations and combine the data into a 

single processed data file. The processed data file is read by CALMET as observations 

and are used in the modification of the Step 1 Wind Fields in developing the Step 2 

Wind Fields. 

CTGPROC reads land use data and calculates weighted land use for each grid cell in 

the modeling domain and writes a processed data file. 

TERREL reads terrain data and calculates the elevation of the center of each grid cell in 

the modeling domain and writes a processed data file. 

MAKEGEO reads the processed data files from CTGPROC and TERREL. MAKEGEO 

calculates weighted surface characteristics and writes these along with the terrain 

elevations to a processed data file. The processed data file is used by the CALMET 

model to modify the Initial Guess Wind Fields in developing the Step 1 Wind Fields. 
4-9 

CALMET Analysis 

The CALMET analysis followed guidance of IWAQM15 and FLAG16. Version 6.211 of 

the CALMET model was used to develop the parameters for the three-dimensional 

Meteorological Grid. The Meteorological Grid includes meteorological parameters, 

surface parameters and terrain elevations for each hour. This three-dimensional 

Meteorological Grid was calculated by CALMET in three steps as follows. 

Initial Guess Wind Fields. The 36 km prognostic data for 2002, 2003 and 2004 was 

used for developing the Initial Guess Wind Fields of the 4 km three-dimensional 

Meteorological Grid. 

Step 1 Wind Fields. The terrain and surface parameters are used to modify the Initial 

Guess Wind Fields to develop the Step 1 Wind Fields of the 4 km three-dimensional 

Meteorological Grid. The area that most influences the transport and dispersion of puffs 

from the source to the Class I Area is the area near a line from the source to the Class I 

Area. This area is generally gently sloping or overwater. Just to the south of this line in 

the north-central part of the lower part of Michigan are two higher areas with a shallow 

valley between. The higher terrain to the south is a little over 400 meters AMS, the 

valley floor is about 200 meters AMS, and north of the valley the terrain raises to an 

elevation of about 320 meters AMS. The distance from high terrain to high terrain is 

about 50 kilometers. Therefore, the radius of influence of terrain features (TERRAD) 

was set to 25 km to account for this terrain. The slope of the intervening terrain is 

gentle and the value of TERRAD should have very little influence on the calculated 

impacts. 

Step 2 Wind Fields. Meteorological observations (surface data, upper air data and 

precipitation data) are used to modify the Step 1 Wind Fields to develop the Step 2 

 

15 Interagency Workgroup on Air Quality Modeling Phase 2 Summary Report and Recommendations for Modeling 

Long Range Transport Impacts (EPA-454/R-98-019) (IWAQM) 

16 Federal Land Managers Air Quality Related Values Work Group Phase I report (USFS, NPS, USFWS, 2000) 

(FLAG) 
4-10 

Wind Fields of the 4 km three-dimensional Meteorological Grid. The terrain is gently 

rolling in the area that most influences the transport and dispersion of puffs from the 

source to the Class I Area. Therefore, the radius of influence of the observations should 

be relatively large. The maximum distances and relative weightings of observations 

were set as follows. 

Maximum Over Land Surface (KM) – RMAX1 = 100 

Maximum Over Land Aloft (KM) - RMAX2 = 200 

Maximum Over Water (KM) - RMAX3 = 100 

Relative Weighting Surface (KM) - R1 = 30 

Relative Weighting Aloft (KM) - R2 = 60

4.4 CALPUFF

Output from the CALMET model was input to the CALPUFF model, which simulates the 

effects of the meteorological conditions on the transport and dispersion of pollutants 

from an individual source. Version 6.112 of CALPUFF was used in the analysis. 

Modeling Domain 

The CALPUFF modeling domain was designed to include the Lafarge facility and the 

Seney Class I area (this is the only Class I Area within 500 km of Lafarge). A 50 km 

buffer zone in each direction was included in establishing the computational modeling 

domain. The domain dimensions are therefore 440 km east-west by 312 km northsouth. The modeling (computational) domain is shown in Figure 3. Ninety eight grid 

cells were employed in the east-west axis and 65 in the north-south axis. 

Class I Area Receptors 

Lafarge used the FLM Class I receptors for Seney, with elevations, as obtained from the 

National Parks Service. The receptor coordinates and elevations are provided in 

Appendix D. 

 
4-11 

Control File Settings 

In general, Lafarge used the default options in the CALPUFF model.17 The deviations 

from the default values are discussed below. 

• The MESOPUFF II module was used for chemical transformation (MCHEM=1)

• Number of vertical layers (NZ) was set to 10 and cell face heights (ZFACE) of 0, 

20, 40, 80, 160, 320, 1000, 1500, 2200, and 3000 meters were used (to be 

consistent with CALMET runs).

• The integrated puff sampling methodology was used for puff recognition.

• Building downwash was ignored because the Class Area is located greater than 

50 km from the source and downwash should not influence concentration 

estimates.

Ozone and Ammonia Background Values 

CALPUFF uses background ozone (O3) and ammonia (NH3) values in its chemistry 

module. Per LADCO Guidance, Lafarge used the domain seasonal average ozone and 

ammonia concentration values provided in the LADCO BART Guidance document. 

4.5 CALPOST

Calculation Methods for Background Light Extinction 

Input required by CALPOST includes an input control file and the hourly concentration 

output file from CALPUFF. The primary settings for the CALPOST control file are 

associated with the method for calculation of light extinction. The CALPOST control file 

was set such that the background light extinction calculation Visibility Method 6 

(MVISBK=6) was used. This is the default value as described in LADCO’s protocol 

document. As required by Method 6, The EPA Class I area-specific (centroid) monthly 

relative humidity values for the Seney Class I area were used. These values were 

obtained from Table A-3 of the EPA’s “Guidance for Estimating Natural Visibility 

Conditions Under the Regional Haze Rule”.18 

 

17 As defined by pages B-2 through B-8 of the IWAQM Phase 2 Summary Report. 18 “Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule”, EPA-450/B-03-005, 

September 2003. 
4-12 

In Visibility Method 6, CALPOST also requires monthly background concentrations of 

ammonium sulfate, ammonium nitrate, coarse particulate mass, organic carbon, soil, 

and elemental carbon. Annual averages reflective of natural background conditions for 

these species were obtained from the EPA’s “Guidance for Natural Visibility” document. 

Light Extinction Efficiencies and Rayleigh Scattering Value 

The other values required to execute CALPOST include the light extinction efficiencies 

for the pollutant species identified above (i.e., ammonium sulfate, ammonium nitrate, 

etc.) and the extinction due to Rayleigh scattering (BEXTRAY). Dry extinction 

efficiencies for the pollutant species were set equal to the Table 2-1 values of the EPA 

Visibility Guidance Document. The value for Rayleigh scattering was set to 10 Mm-1. 
5-1 

5.0 BART MODEL RESULTS

The CALPUFF modeling system was executed with input data and settings as 

described in Section 4. Delta-deciview results were obtained from the “24HR 

VISIBILITY (deciview)” table in the CALPOST output files. The regional haze regulation 

and BART guideline stipulate that the States have flexibility in determining the degree of 

visibility improvement that should be considered acceptable in assessing appropriate 

BART controls (see 70 FR 39170). The States may consider the frequency, magnitude, 

and duration components of visibility impairment. EPA suggests that the States use a 

comparison threshold, as is done for determining if BART-eligible emission units are 

subject to BART. Alternatively, States may compare the 98th percent days for the preand post-control runs. The MDEQ has requested that Lafarge provide the 98th

percentile values as well as the number of days with delta deciview values in excess of 

the 0.5 BART-eligibility criterion for both the pre- and post-control scenarios. These 

results are presented in Table 5-1 as well as Appendix E. 

 

As shown in Table 5-1, both the 98th percentile deciview value and the number of days 

in excess of 0.5 deciviews decrease with each of the control scenarios evaluated. 

However, the majority of the reduction is realized between the baseline and the control 

scenario no. 1 (SNCR on all kilns and wet scrubbing on KG6). The next highest level of 

control (adding duct injection to KG5) results in some degree of visibility improvement. 

However, the costs of the additional level of control outweighs the small additional 

improvement in modeled visibility impacts. The addition of duct injection on KG5 would 

only improve the combined, three year 98% dv value by 0.05 dv (0.746-0.697 dv) at a 

cost of over $3,300/ton or approximately $2,800,000/dv [$1,702,833/1.301-0.6967 dv]. 

The next level of control (addition of wet scrubbers to KG5) is even more expensive at 

$7,952/ton or approximately $21,000,000/dv [$16,287,149/(1.301-.509)]. 

The CALPUFF and CALPOST input and output files are provided on the enclosed CD. 
5-2 

Table 5-1. Delta Deciview Visibility Impact Rankings (4km CALMET Grid, Annual Average Co

Background) 

2002 2003 2004 200

Scenario 

98th

Percentile 

Value 

No. Days 

98% > 0.5 

deciview 

98th

Percentile 

Value 

No. Days 

98% > 0.5 

deciview 

98th

Percentile 

Value 

No. Days 

98% > 0.5 

deciview 

9

Perc

Va

Baseline 0.711 3 1.852 15 1.089 7 1.Control Scenario 1: SNCR KG5&6, Wet Scrubbing KG6 (Proposed BART) 

0.371 0 1.022 10 0.641 3 0.

Control Scenario 2: SNCR KG5&6, Wet Scrubbing KG6, Duct Injection KG5 

0.340 0 0.908 10 0.614 3 0.

Control Scenario 3: SNCR KG5&6, Wet Scrubbing KG5&6 

0.242 0 0.644 6 0.474 0 0.
 

APPENDIX A 

PM10 Speciation, Emission Calculations, 

And Worst Case-Stack Parameter Determination 
Source Equipment 

Number

New MAERS 

Activity ID 

No.

Model 

Source ID Source Description Material

Maximum 

Feed Rate 

(ton/hr)

Potential

Emission 

Factor 

(lb/ton 

feed) Emission Factor Reference

PM 

(l

25-253 KILN 19 SV00031 K19 Exhaust Kilns (CKD) 90 0.06 MAERS, Test 25-265 KILN 20 SV00032 K20 Exhaust Kilns (CKD) 90 0.06 MAERS, Test 25-266 KILN 21 SV00033 K21 Exhaust Kilns (CKD) 90 0.06 MAERS, Test 26-256 KILN 22 SV00047 K22-23 Exhaust Kilns (CKD) 144 0.11 MAERS, Test 126-256 KILN 23 SV00047 K22-23 Exhaust Kilns (CKD) 144 0.07 MAERS, Test 1Maximum hourly feed rates based upon a clinker factor of 1.8 and the following maximum clinker rates: K19-K21:50 ton/hr each, K22-K23-80 ton/hr each.

PM10 Emissions from Lafarge Alpena Kilns

PM Speciation 

Uncontrolled PM10 Emissions (Bold Value is Input by user.)

Kiln Total PM10 Filterable Coarse - PMC Ext. Fine Fine Soil - PMF Ext. Fine EC Ext. Condensible CPM IOR -SO4 Particle 

Lafarge Kiln (lb/hr) (lb/hr) (lb/hr) Coef. (lb/hr) (lb/hr) Coef. (lb/hr) Coef. (lb/hr) (lb/hr) Type Ext.Coef. 

KILN 19 31.9 4.6 2.1 0.6 2.5 2.2 1 0.2 10 27.3 24.0 SO4 3 

KILN 20 31.9 4.6 2.1 0.6 2.5 2.2 1 0.2 10 27.3 24.0 SO4 3 

KILN 21 31.9 4.6 2.1 0.6 2.5 2.2 1 0.2 10 27.3 24.0 SO4 3 

KILN 22 93.6 13.5 6.3 0.6 7.2 6.5 1 0.7 10 80.1 70.5 SO4 3 KILN 22 59.5 8.6 4.0 0.6 4.6 4.2 1 0.4 10 51.0 44.9 SO4 3 

Model Source 

Description

Model 

Source ID

Sum of 

Emissions 

(lb/hr)

Weighting 

Factor 

Based on 

Emissions

Weighted 

Stack 

Height (m)

Weighted 

Base 

Elevation 

(m)

Weighted 

Stack 

Diameter 

(m)

Weighted 

Exit 

Velocity 

(m/sec)

W

T

K19 Exhaust SV00031 2027 0.15 9.76 26.48 0.58 0.57 K20 Exhaust SV00032 1381 0.10 6.65 18.04 0.39 0.39 K21 Exhaust SV00033 1438 0.10 6.92 18.78 0.41 0.62 K22-23 Exhaust SV00047 9085 0.65 58.05 118.70 4.77 4.39 

Combined KILNS 13929 1 81.37 182.00 6.15 5.97 

Worst-Case Stack Parameter Determination - Weighting Based Upon Emissions
 

APPENDIX B 

Control Costing Calculations 

and Supporting Documentation 
KG5 Wet Scrubber Cost Estimate 

Item Basis Value Comments

Purchased equipment Costs

Scrubber System Cost (SSC) Vendor Quote + Plant Estimates 43,200,000

Includes scrubber, reagent prep, piping, tacompressors, gypsum handling, fans, and 

Instrumentation = 0.05*SSC 2,160,000

USEPA Control Cost Manual, Sec. 5.2, C1value to account for instrumentation in scr

Sales taxes = 0.03*SSC 1,296,000 USEPA Control Cost Manual, Sec. 5.2, C1Freight = 0.05*SSC 2,160,000 USEPA Control Cost Manual, Sec. 5.2, C1

Purchased equipment cost (PEC) PEC = 1.13*SSC 48,816,000

= Scrubber System Cost (SSC) + InstrumFreight

Direct installation costs

Foundations & supports Included in PEC - Included in SSCHandling & erection Included in PEC - Included in SSCElectrical Included in PEC - Included in SSC

Piping Included in PEC - Included in SSC

Insulation Included in PEC - Included in SSCPainting Included in PEC - Included in SSC

Direct installation costs Included in PEC - Included in SSCSite preparation & Buildings (SP + BLD.) As required 9,000,000 Lafarage Estimate: includes roads, electri

Total Direct Costs (DC) = PEC + SP +BLD. 57,816,000

= Site preparation & Buildings (SP + BLD.(PEC)

Indirect Costs (installation)

Engineering = 0.10*PEC 4,881,600 USEPA Control Cost Manual, Sec. 5.2, C1

Construction and field expenses = 0.10*PEC 4,881,600 USEPA Control Cost Manual, Sec. 5.2, C1Contractor fees = 0.10*PEC 4,881,600 USEPA Control Cost Manual, Sec. 5.2, C1

Start-up = 0.01*PEC 488,160 USEPA Control Cost Manual, Sec. 5.2, C1

Performance test = 0.01*PEC 488,160 USEPA Control Cost Manual, Sec. 5.2, C1Contingencies = 0.25*PEC 9,763,200 Conservative estimate of contingency basLost Production During Retrofit 30 days of downtime/kiln 4,320,000 Based on lost production of $40/ton and a 

Total Indirect Costs (IC) = 0.35*PEC 29,704,320 = SUM of Indirect Cost Elements

Total Capital Investment $ (TCI) = IC+ DC 91,840,320 = Total Direct Costs (DC) + Total Indirect 

Capital Cost Estimate
Annual Cost Inputs

Reagent Ratio (moles limestone/mole SO2 removed) Estimate. 1.1 1.05 Reagent Ratio & 95% CaCO3 in limestoneOperating Labor Cost ($/hr) Lafarge Data; unburdened cost. 23.78 Lafarge Data

Supervisory Labor Cost ($/hr) Lafarge Data; unburdened cost. 31.58 Lafarge DataMaintenance Labor Cost ($/hr) Lafarge Data; unburdened cost. 24.78 Lafarge DataPower Cost ($/kW) Lafarge Data 0.063 Lafarge Data

Limestone Cost ($/ton) Lafarge Data 1.25 Lafarge DataWater Cost ($/1000 gal) Lafarge Data 4.9 Lafarge DataSO2 to Scrubber (tpy) Based on 2004/2005 Average Emissions. 2,529

SO2 Removal Efficiency (%) Design Estimate. 90%

FGD On-stream Time (%) Design Estimate. 90%SO2 Removed by Scrubber (tpy) Calculated from above values. 2,048

= SO2 to Scrubber (tpy) * SO2 Removal EfficienTime (%)

Gypsum MW (lb/lb-mole) Constant 172CaCO3 MW (lb/lb-mole) Constant 100SO2 MW (lb/lb-mole) Constant 64

Gypsum Production Rate (tpy -dry basis) CaSO4*2H2O (dry basis) 5,504

= SO2 Removed by Scrubber (tpy) * Gypsum MMW (lb/lb-mole)

Gypsum Value ($/ton - dry basis) Lafarge Data 16 Lafarge Data

Water Evaporation Rate (gpm) Estimate. 100Direct Annual Costs (DAC)

Operating labor • Operator ($/yr) 3.0 operators per shift 624,938 Estimate of staffing based on scrubber complex • Supervisor ($/yr) 15% of operator labor 124,488 USEPA Control Cost Manual, Sec. 5.2, C1, TabOperating materials • Water ($/yr) 10 wt. % free moisture in Gypsum + evap. 233,790 Based on evaporation, and water lost w/ gypsum • Limestone ($/yr) Based on Reagent Ratio of 1.1. 4,400 Calculated based on Reagent Ratio & SO2 rem • Wastewater disposal ($/yr) None (FGD is assumed zero discharge) 0 Zero discharge.Maintenance • Labor ($/yr) 1.0 person per shift 217,073 Estimate of staffing based on scrubber complex • Material ($/yr) 100% of maintenance labor 217,073 USEPA Control Cost Manual, Sec. 5.2, C1, TabElectricity • Fans ($/yr) 400 kW for scrubber fans. 198,677 Design estimate. • Pumps ($/yr) 120 kW for scrubber pumps. 59,603 Design estimate. • Air Compressors ($/yr) 20 kW for oxidation air compressor. 9,934 Design estimate. • Limestone Grinding System ($/yr) 150 kW for limestone grinding circuit. 74,504 Design estimate.Gypsum Credit ($/yr) Gypsum value as cement additive. -88,069

= -Gypsum Production Rate (tpy -dry basis) * G

basis)

DAC Subtotal Direct Annual Costs (DAC) 1,676,411 = SUM of Direct Annual Cost Items

Indirect Annual Costs (IAC)

Overhead ($/yr) 60% of total labor and material costs 853,058 USEPA Control Cost Manual, Sec. 5.2, C1, Tab

Administrative charges ($/yr) 2% of Total Capital Investment 1,836,806 USEPA Control Cost Manual, Sec. 5.2, C1, Tab

Property tax ($/yr) 1% of Total Capital Investment 918,403 USEPA Control Cost Manual, Sec. 5.2, C1, TabInsurance ($/yr) 1% of Total Capital Investment 918,403 USEPA Control Cost Manual, Sec. 5.2, C1, TabCapital recovery ($/yr) 10.98% x Total Capital Investment 10,084,067 USEPA Control Cost Manual, Sec. 5.2, C1, Tab

IAC Subtotal Indirect Annual Costs (IAC) 14,610,738 = SUM of Indirect Annual Cost Items

Annualized Costs

Total Annual Cost ($/yr) DAC + IAC 16,287,149 = IAC Subtotal + DAC Subtotal

Control Cost Effectiveness ($/ton) TAC / Tons SO2 Removed 7,952 = Total Annual Cost ($/yr) / SO2 Removed by S

Annualized Cost Estimate
KG6 Wet Scrubber Cost Estimate 

Item Basis Value Comments

Purchased equipment Costs

Scrubber System Cost (SSC) Vendor Quote + Plant Estimates 30,000,000

Includes scrubber, reagent prep, piping, tacompressors, gypsum handling, fans, and 

Instrumentation = 0.05*SSC 1,500,000

USEPA Control Cost Manual, Sec. 5.2, Cvalue to account for instrumentation in scr

Sales taxes = 0.03*SSC 900,000 USEPA Control Cost Manual, Sec. 5.2, C

Freight = 0.05*SSC 1,500,000 USEPA Control Cost Manual, Sec. 5.2, C

Purchased equipment cost (PEC) PEC = 1.13*SSC 33,900,000

= Scrubber System Cost (SSC) + InstrumFreight

Direct installation costs

Foundations & supports Included in PEC - Included in SSCHandling & erection Included in PEC - Included in SSC

Electrical Included in PEC - Included in SSCPiping Included in PEC - Included in SSC

Insulation Included in PEC - Included in SSCPainting Included in PEC - Included in SSCDirect installation costs Included in PEC - Included in SSC

Site preparation & Buildings (SP + BLD.) As required 7,000,000 Lafarage Estimate: includes roads, electri

Total Direct Costs (DC) = PEC + SP +BLD. 40,900,000

= Site preparation & Buildings (SP + BLD.(PEC)

Indirect Costs (installation)

Engineering = 0.10*PEC 3,390,000 USEPA Control Cost Manual, Sec. 5.2, C

Construction and field expenses = 0.10*PEC 3,390,000 USEPA Control Cost Manual, Sec. 5.2, CContractor fees = 0.10*PEC 3,390,000 USEPA Control Cost Manual, Sec. 5.2, C

Start-up = 0.01*PEC 339,000 USEPA Control Cost Manual, Sec. 5.2, C

Performance test = 0.01*PEC 339,000 USEPA Control Cost Manual, Sec. 5.2, CContingencies = 0.25*PEC 6,780,000 Conservative estimate of contingency basLost Production During Retrofit 30 days of downtime/kiln 4,608,000 Based on lost production of $40/ton and a 

Total Indirect Costs (IC) = 0.35*PEC 22,236,000 = SUM of Indirect Cost Elements

Total Capital Investment $ (TCI) = IC+ DC 63,136,000 = Total Direct Costs (DC) + Total Indirect 

Capital Cost Estimate
Annual Cost Inputs

Reagent Ratio (moles limestone/mole SO2 removed) Estimate. 1.1 1.05 Reagent Ratio & 95% CaCO3 in limestoneOperating Labor Cost ($/hr) Lafarge Data; unburdened cost. 23.78 Lafarge Data

Supervisory Labor Cost ($/hr) Lafarge Data; unburdened cost. 31.58 Lafarge Data

Maintenance Labor Cost ($/hr) Lafarge Data; unburdened cost. 24.78 Lafarge Data

Power Cost ($/kW) Lafarge Data 0.063 Lafarge Data

Limestone Cost ($/ton) Lafarge Data 1.25 Lafarge Data

Water Cost ($/1000 gal) Lafarge Data 4.9 Lafarge Data

SO2 to Scrubber (tpy) Based on 2004/2005 Average Emissions. 13,433SO2 Removal Efficiency (%) Design Estimate. 90%FGD On-stream Time (%) Design Estimate. 90%

SO2 Removed by Scrubber (tpy) Calculated from above values. 10,880

= SO2 to Scrubber (tpy) * SO2 Removal EfficienTime (%)

Gypsum MW (lb/lb-mole) Constant 172

CaCO3 MW (lb/lb-mole) Constant 100

SO2 MW (lb/lb-mole) Constant 64Gypsum Production Rate (tpy -dry basis) CaSO4*2H2O (dry basis) 29,241

= SO2 Removed by Scrubber (tpy) * Gypsum MMW (lb/lb-mole)

Gypsum Value ($/ton - dry basis) Lafarge Data 16 Lafarge DataWater Evaporation Rate (gpm) Estimate. 100

Direct Annual Costs (DAC)

Operating labor • Operator ($/yr) 3.0 operators per shift 624,938 Estimate of staffing based on scrubber complex • Supervisor ($/yr) 15% of operator labor 124,488 USEPA Control Cost Manual, Sec. 5.2, C1, TabOperating materials • Water ($/yr) 10 wt. % free moisture in Gypsum + evap. 242,417 Based on evaporation, and water lost w/ gypsum • Limestone ($/yr) Based on Reagent Ratio of 1.1. 23,376 Calculated based on Reagent Ratio & SO2 rem • Wastewater disposal ($/yr) None (FGD is assumed zero discharge) 0 Zero discharge.Maintenance • Labor ($/yr) 1.0 person per shift 217,073 Estimate of staffing based on scrubber complex • Material ($/yr) 100% of maintenance labor 217,073 USEPA Control Cost Manual, Sec. 5.2, C1, TabElectricity • Fans ($/yr) 500 kW for scrubber fans. 248,346 Design estimate. • Pumps ($/yr) 300 kW for scrubber pumps. 149,008 Design estimate. • Air Compressors ($/yr) 50 kW for oxidation air compressor. 24,835 Design estimate. • Limestone Grinding System ($/yr) 200 kW for limestone grinding circuit. 99,338 Design estimate.Gypsum Credit ($/yr) Gypsum value as cement additive. -467,858

= -Gypsum Production Rate (tpy -dry basis) * Gy

basis)

DAC Subtotal Direct Annual Costs (DAC) 1,503,034 = SUM of Direct Annual Cost Items

Indirect Annual Costs (IAC)

Overhead ($/yr) 60% of total labor and material costs 869,619 USEPA Control Cost Manual, Sec. 5.2, C1, TabAdministrative charges ($/yr) 2% of Total Capital Investment 1,262,720 USEPA Control Cost Manual, Sec. 5.2, C1, TabProperty tax ($/yr) 1% of Total Capital Investment 631,360 USEPA Control Cost Manual, Sec. 5.2, C1, Tab

Insurance ($/yr) 1% of Total Capital Investment 631,360 USEPA Control Cost Manual, Sec. 5.2, C1, Tab

Capital recovery ($/yr) 10.98% x Total Capital Investment 6,932,333 USEPA Control Cost Manual, Sec. 5.2, C1, Tab

IAC Subtotal Indirect Annual Costs (IAC) 10,327,392 = SUM of Indirect Annual Cost Items

Annualized Costs

Total Annual Cost ($/yr) DAC + IAC 11,830,426 = IAC Subtotal + DAC Subtotal

Control Cost Effectiveness ($/ton) TAC / Tons SO2 Removed 1,087 = Total Annual Cost ($/yr) / SO2 Removed by S

Annualized Cost Estimate
KG5 Duct Injection Cost Estimate 

Item Basis Value Comments

Purchased equipment Costs

Duct Injection System Cost (DISC) Vendor Quote + Plant Estimates 1,455,600

Includes injection system, reagent prep, pand duct work.

Instrumentation = 0.10*DISC 145,560 USEPA Control Cost Manual, Sec. 5.2, C

Sales taxes = 0.03*DISC 43,668 USEPA Control Cost Manual, Sec. 5.2, C

Freight = 0.05*DISC 72,780 USEPA Control Cost Manual, Sec. 5.2, C

Purchased equipment cost (PEC) PEC = 1.18*DISC 1,717,608

= Duct Injection System Cost (DISC) + InsFreight

Direct installation costs

Foundations & supports Included in PEC - Included in DISCHandling & erection Included in PEC - Included in DISCElectrical Included in PEC - Included in DISC

Piping Included in PEC - Included in DISCInsulation Included in PEC - Included in DISC

Painting Included in PEC - Included in DISC

Direct installation costs Included in PEC - Included in DISC

Site preparation & Buildings (SP + BLD.) As required 500,000 Order of magnitude estimate.

Total Direct Costs (DC) = PEC + SP +BLD. 2,217,608

= Site preparation & Buildings (SP + BLD.(PEC)

Indirect Costs (installation)

Engineering = 0.10*PEC 171,761 USEPA Control Cost Manual, Sec. 5.2, CConstruction and field expenses = 0.10*PEC 171,761 USEPA Control Cost Manual, Sec. 5.2, C

Contractor fees = 0.10*PEC 171,761 USEPA Control Cost Manual, Sec. 5.2, C

Start-up = 0.01*PEC 17,176 USEPA Control Cost Manual, Sec. 5.2, CPerformance test = 0.01*PEC 17,176 USEPA Control Cost Manual, Sec. 5.2, CContingencies = 0.25*PEC 343,522 Conservative estimate of contingency basLost Production During Retrofit 10 days of downtime/kiln 1,440,000 Based on lost production of $40/ton and a 

Total Indirect Costs (IC) = 0.35*PEC 2,333,156 = SUM of Indirect Cost ElementsTotal Capital Investment $ (TCI) = IC+ DC 4,550,764 = Total Direct Costs (DC) + Total Indirect 

Capital Cost Estimate
Annual Cost Inputs

Reagent Ratio (moles limes/mole SO2 removed) Estimate. 1.0 1.0 reagent ration estiamted to achieve 20Operating Labor Cost ($/hr) Lafarge Data; unburdened cost. 23.78 Lafarge DataSupervisory Labor Cost ($/hr) Lafarge Data; unburdened cost. 31.58 Lafarge Data

Maintenance Labor Cost ($/hr) Lafarge Data; unburdened cost. 24.78 Lafarge DataPower Cost ($/kW) Lafarge Data 0.063 Lafarge DataLime Cost ($/ton) Lafarge Data 80 EstimateWater Cost ($/1000 gal) Lafarge Data 4.9 Lafarge DataCKD disposal cost ($/ton) Lafarge Data 3.5 Lafarge DataSO2 to Scrubber (tpy) Based on 2004/2005 Average Emissions. 2,529SO2 Removal Efficiency (%) Design Estimate. 25%FGD On-stream Time (%) Design Estimate. 80%SO2 Removed by System (tpy) Calculated from above values. 506

= SO2 to Scrubber (tpy) * SO2 Removal ETime (%)

Ca(OH)2 MW (lb/lb-mole) Constant 74SO2 MW (lb/lb-mole) Constant 64Water Evaporation Rate (gpm) Estimate. 50Direct Annual Costs (DAC)

Operating labor • Operator ($/yr) 1.0 operators per shift 208,313 Estimate of staffing based on scrubber co • Supervisor ($/yr) 15% of operator labor 41,496 USEPA Control Cost Manual, Sec. 5.2, COperating materials • Water ($/yr) Based on evaporation rate. 103,018 Based on evaporation. • Lime ($/yr) Based on Reagent Ratio of 1.0. 46,778 Calculated based on Reagent Ratio & SO • Wastewater disposal ($/yr) None (FGD is assumed zero discharge) 0 Zero discharge. • CKD disposal ($/yr) Assumes 2 tons CKD/ton SO2 removed. 3,540 Need to purge sulfur from system.Maintenance • Labor ($/yr) 0.5 person per shift 108,536 Estimate of staffing based on scrubber co

 • Material ($/yr) 100% of maintenance labor 108,536 USEPA Control Cost Manual, Sec. 5.2, CElectricity • Fans ($/yr) 50 kW for scrubber fans. 22,075 Design estimate.

 • Pumps ($/yr) 20 kW for scrubber pumps. 8,830 Design estimate.

DAC Subtotal Direct Annual Costs (DAC) 651,123 = SUM of Direct Annual Cost Items

Indirect Annual Costs (IAC)

Overhead ($/yr) 60% of total labor and material costs 370,006 USEPA Control Cost Manual, Sec. 5.2, C

Administrative charges ($/yr) 2% of Total Capital Investment 91,015 USEPA Control Cost Manual, Sec. 5.2, C

Property tax ($/yr) 1% of Total Capital Investment 45,508 USEPA Control Cost Manual, Sec. 5.2, C

Insurance ($/yr) 1% of Total Capital Investment 45,508 USEPA Control Cost Manual, Sec. 5.2, C

Capital recovery ($/yr) 10.98% x Total Capital Investment 499,674 USEPA Control Cost Manual, Sec. 5.2, C

IAC Subtotal Indirect Annual Costs (IAC) 1,051,711 = SUM of Indirect Annual Cost Items

Annualized Costs

Total Annual Cost ($/yr) DAC + IAC 1,702,833 = IAC Subtotal + DAC SubtotalControl Cost Effectiveness ($/ton) TAC / Tons SO2 Removed 3,367 = Total Annual Cost ($/yr) / SO2 Removed 

Annualized Cost Estimate
KG6 Duct Injection Cost Estimate 

Item Basis Value Comments

Purchased equipment Costs

Duct Injection System Cost (DISC) Vendor Quote + Plant Estimates 1,344,000

Includes injection system, reagent prep, pand duct work.

Instrumentation = 0.10*DISC 134,400 USEPA Control Cost Manual, Sec. 5.2, C

Sales taxes = 0.03*DISC 40,320 USEPA Control Cost Manual, Sec. 5.2, C

Freight = 0.05*DISC 67,200 USEPA Control Cost Manual, Sec. 5.2, C

Purchased equipment cost (PEC) PEC = 1.18*DISC 1,585,920

= Duct Injection System Cost (DISC) + InsFreight

Direct installation costs

Foundations & supports Included in PEC - Included in DISCHandling & erection Included in PEC - Included in DISCElectrical Included in PEC - Included in DISC

Piping Included in PEC - Included in DISCInsulation Included in PEC - Included in DISC

Painting Included in PEC - Included in DISC

Direct installation costs Included in PEC - Included in DISC

Site preparation & Buildings (SP + BLD.) As required 500,000 Order of magnitude estimate.

Total Direct Costs (DC) = PEC + SP +BLD. 2,085,920

= Site preparation & Buildings (SP + BLD.(PEC)

Indirect Costs (installation)

Engineering = 0.10*PEC 158,592 USEPA Control Cost Manual, Sec. 5.2, CConstruction and field expenses = 0.10*PEC 158,592 USEPA Control Cost Manual, Sec. 5.2, C

Contractor fees = 0.10*PEC 158,592 USEPA Control Cost Manual, Sec. 5.2, C

Start-up = 0.01*PEC 15,859 USEPA Control Cost Manual, Sec. 5.2, CPerformance test = 0.01*PEC 15,859 USEPA Control Cost Manual, Sec. 5.2, CContingencies = 0.25*PEC 317,184 Conservative estimate of contingency basLost Production During Retrofit 10 days of downtime/kiln 1,536,000 Based on lost production of $40/ton and a 

Total Indirect Costs (IC) = 0.35*PEC 2,360,678 = SUM of Indirect Cost ElementsTotal Capital Investment $ (TCI) = IC+ DC 4,446,598 = Total Direct Costs (DC) + Total Indirect 

Capital Cost Estimate
Annual Cost Inputs

Reagent Ratio (moles lime/mole SO2 removed) Estimate. 1.0 1.0 reagent ration estiamted to achieve 20Operating Labor Cost ($/hr) Lafarge Data; unburdened cost. 23.78 Lafarge DataSupervisory Labor Cost ($/hr) Lafarge Data; unburdened cost. 31.58 Lafarge Data

Maintenance Labor Cost ($/hr) Lafarge Data; unburdened cost. 24.78 Lafarge DataPower Cost ($/kW) Lafarge Data 0.063 Lafarge DataLime Cost ($/ton) Lafarge Data 80 EstimateWater Cost ($/1000 gal) Lafarge Data 4.9 Lafarge DataCKD disposal cost ($/ton) Lafarge Data 3.5 Lafarge DataSO2 to Scrubber (tpy) Based on 2004/2005 Average Emissions. 13,433SO2 Removal Efficiency (%) Design Estimate. 25%FGD On-stream Time (%) Design Estimate. 80%SO2 Removed by System (tpy) Calculated from above values. 2,687

= SO2 to Scrubber (tpy) * SO2 Removal E

Time (%)

Ca(OH)2 MW (lb/lb-mole) Constant 74SO2 MW (lb/lb-mole) Constant 64Water Evaporation Rate (gpm) Estimate. 50Direct Annual Costs (DAC)

Operating labor • Operator ($/yr) 1.0 operators per shift 208,313 Estimate of staffing based on scrubber co • Supervisor ($/yr) 15% of operator labor 41,496 USEPA Control Cost Manual, Sec. 5.2, COperating materials • Water ($/yr) Based on evaporation rate. 103,018 Based on evaporation. • Lime ($/yr) Based on Reagent Ratio of 1.0. 248,504 Calculated based on Reagent Ratio & SO • Wastewater disposal ($/yr) None (FGD is assumed zero discharge) 0 Zero discharge. • CKD disposal ($/yr) Assumes 2 tons CKD/ton SO2 removed. 18,806 Need to purge sulfur from system.Maintenance • Labor ($/yr) 0.5 person per shift 108,536 Estimate of staffing based on scrubber co • Material ($/yr) 100% of maintenance labor 108,536 USEPA Control Cost Manual, Sec. 5.2, CElectricity • Fans ($/yr) 50 kW for scrubber fans. 22,075 Design estimate. • Pumps ($/yr) 20 kW for scrubber pumps. 8,830 Design estimate.

DAC Subtotal Direct Annual Costs (DAC) 868,114 = SUM of Direct Annual Cost Items

Indirect Annual Costs (IAC)Overhead ($/yr) 60% of total labor and material costs 491,042 USEPA Control Cost Manual, Sec. 5.2, C

Administrative charges ($/yr) 2% of Total Capital Investment 88,932 USEPA Control Cost Manual, Sec. 5.2, C

Property tax ($/yr) 1% of Total Capital Investment 44,466 USEPA Control Cost Manual, Sec. 5.2, C

Insurance ($/yr) 1% of Total Capital Investment 44,466 USEPA Control Cost Manual, Sec. 5.2, C

Capital recovery ($/yr) 10.98% x Total Capital Investment 488,237 USEPA Control Cost Manual, Sec. 5.2, C

IAC Subtotal Indirect Annual Costs (IAC) 1,157,142 = SUM of Indirect Annual Cost Items

Annualized Costs

Total Annual Cost ($/yr) DAC + IAC 2,025,256 = IAC Subtotal + DAC SubtotalControl Cost Effectiveness ($/ton) TAC / Tons SO2 Removed 754 = Total Annual Cost ($/yr) / SO2 Removed 

Annualized Cost Estimate
KG5 SNCR Cost Estimate 

Item Basis Value Comments

Purchased equipment Costs

SNCR System Cost (SNCRSC) Vendor Quote + Plant Estimates 975,000

Includes injection system, reagent prep, pand duct work.

Instrumentation = 0.10*SNCRSC 97,500 USEPA Control Cost Manual, Sec. 5.2, CSales taxes = 0.03*SNCRSC 29,250 USEPA Control Cost Manual, Sec. 5.2, C

Freight = 0.05*SNCRSC 48,750 USEPA Control Cost Manual, Sec. 5.2, CPurchased equipment cost (PEC) PEC = 1.18*SNCRSC 1,150,500

= SNCR System Cost (SNCRSC) + InstruFreight

Direct installation costs

Foundations & supports Included in PEC - Included in SNCRSC

Handling & erection Included in PEC - Included in SNCRSC

Electrical Included in PEC - Included in SNCRSC

Piping Included in PEC - Included in SNCRSCInsulation Included in PEC - Included in SNCRSC

Painting Included in PEC - Included in SNCRSCDirect installation costs Included in PEC - Included in SNCRSCGeneral Facilities (GF) = 0.05*PEC 57,525 USEPA Control Cost Manual, Sec. 4.2, C

Total Direct Costs (DC) = PEC + GF 1,208,025 = General Facilities (GF) + Purchased equ

Indirect Costs (installation)

Engineering = 0.10*PEC 115,050 USEPA Control Cost Manual, Sec. 5.2, CConstruction and field expenses = 0.10*PEC 115,050 USEPA Control Cost Manual, Sec. 5.2, C

Contractor fees = 0.10*PEC 115,050 USEPA Control Cost Manual, Sec. 5.2, C

Start-up = 0.01*PEC 11,505 USEPA Control Cost Manual, Sec. 5.2, CPerformance test = 0.01*PEC 11,505 USEPA Control Cost Manual, Sec. 5.2, CContingencies = 0.25*PEC 230,100 Conservative estimate of contingency basLost Production During Retrofit 5 days of downtime/kiln 720,000 Based on lost production of $40/ton and a 

Total Indirect Costs (IC) = 0.35*PEC 1,318,260 = SUM of Indirect Cost ElementsTotal Capital Investment $ (TCI) = IC+ DC 2,526,285 = Total Direct Costs (DC) + Total Indirect 

Capital Cost Estimate
Annual Cost Inputs

Reagent Ratio (moles limestone/mole SO2 removed) Estimate. 1.0 1.0 reagent ration estiamted to achieve 40Operating Labor Cost ($/hr) Lafarge Data; unburdened cost. 23.78 Lafarge DataSupervisory Labor Cost ($/hr) Lafarge Data; unburdened cost. 31.58 Lafarge DataPower Cost ($/kW) Lafarge Data 0.063 Lafarge DataNH3 Cost ($/ton) Lafarge Data 650 Estimate.Water Cost ($/1000 gal) Lafarge Data 4.9 Lafarge DataNOx to SNCR (tpy) Based on 2004/2005 Average Emissions. 3,547NOx Removal Efficiency (%) Design Estimate. 44%SNCR On-stream Time (%) Design Estimate. 80%NOx Removed by System (tpy) Calculated from above values. 1,242

= NOx to SNCR (tpy) * NOx Removal EfficTime (%)

NH3 MW (lb/lb-mole) Constant 17NOx MW (lb/lb-mole) Constant 46Water Injection Rate (gpm) Based on 20% NH3/80% H2O by weight. 1.05 Calculated value.Direct Annual Costs (DAC)Operating labor • Operator ($/yr) 0.25 operators per shift 41,663 Estimate of staffing based on scrubber co • Supervisor ($/yr) 15% of operator labor 8,299 USEPA Control Cost Manual, Sec. 5.2, COperating materials • Water ($/yr) Based on evaporation rate. 2,157 Based on water used in injection system. • NH3 ($/yr) Based on Reagent Ratio of 1.0. 214,365 Calculated based on Reagent Ratio & SOMaintenance • Labor & Materials ($/yr) 1.5% of TCI 37,894 USEPA Control Cost Manual, Sec. 4.2, C1Electricity • Vaporization System & Pumps ($/yr) 44 kW 19,426 USEPA Control Cost Manual, Sec. 4.2, C1

DAC Subtotal Direct Annual Costs (DAC) 323,804 = SUM of Direct Annual Cost Items

Indirect Annual Costs (IAC)

Overhead ($/yr) 60% of total labor and material costs 182,626 USEPA Control Cost Manual, Sec. 5.2, C

Administrative charges ($/yr) 2% of Total Capital Investment 50,526 USEPA Control Cost Manual, Sec. 5.2, C

Property tax ($/yr) 1% of Total Capital Investment 25,263 USEPA Control Cost Manual, Sec. 5.2, C

Insurance ($/yr) 1% of Total Capital Investment 25,263 USEPA Control Cost Manual, Sec. 5.2, C

Capital recovery ($/yr) 10.98% x Total Capital Investment 277,386 USEPA Control Cost Manual, Sec. 5.2, C

IAC Subtotal Indirect Annual Costs (IAC) 561,064 = SUM of Indirect Annual Cost Items

Annualized Costs

Total Annual Cost ($/yr) DAC + IAC 884,867 = IAC Subtotal + DAC SubtotalControl Cost Effectiveness ($/ton) TAC / Tons NOx Removed 713 = Total Annual Cost ($/yr) / NOx Removed 

Annualized Cost Estimate
KG6 SNCR Cost Estimate 

Item Basis Value Comments

Purchased equipment Costs

SNCR System Cost (SNCRSC) Vendor Quote + Plant Estimates 800,000

Includes injection system, reagent prep, pand duct work.

Instrumentation = 0.10*SNCRSC 80,000 USEPA Control Cost Manual, Sec. 5.2, CSales taxes = 0.03*SNCRSC 24,000 USEPA Control Cost Manual, Sec. 5.2, C

Freight = 0.05*SNCRSC 40,000 USEPA Control Cost Manual, Sec. 5.2, CPurchased equipment cost (PEC) PEC = 1.18*SNCRSC 944,000

= SNCR System Cost (SNCRSC) + InstruFreight

Direct installation costs

Foundations & supports Included in PEC - Included in SNCRSC

Handling & erection Included in PEC - Included in SNCRSC

Electrical Included in PEC - Included in SNCRSC

Piping Included in PEC - Included in SNCRSCInsulation Included in PEC - Included in SNCRSC

Painting Included in PEC - Included in SNCRSCDirect installation costs Included in PEC - Included in SNCRSCGeneral Facilities (GF) = 0.05*PEC 47,200 USEPA Control Cost Manual, Sec. 4.2, C

Total Direct Costs (DC) = PEC + GF 991,200 = General Facilities (GF) + Purchased equ

Indirect Costs (installation)

Engineering = 0.10*PEC 94,400 USEPA Control Cost Manual, Sec. 5.2, CConstruction and field expenses = 0.10*PEC 94,400 USEPA Control Cost Manual, Sec. 5.2, C

Contractor fees = 0.10*PEC 94,400 USEPA Control Cost Manual, Sec. 5.2, C

Start-up = 0.01*PEC 9,440 USEPA Control Cost Manual, Sec. 5.2, CPerformance test = 0.01*PEC 9,440 USEPA Control Cost Manual, Sec. 5.2, CContingencies = 0.25*PEC 188,800 Conservative estimate of contingency basLost Production During Retrofit 5 days of downtime/kiln 768,000 Based on lost production of $40/ton and a 

Total Indirect Costs (IC) = 0.35*PEC 1,258,880 = SUM of Indirect Cost ElementsTotal Capital Investment $ (TCI) = IC+ DC 2,250,080 = Total Direct Costs (DC) + Total Indirect 

Capital Cost Estimate
Annual Cost Inputs

Reagent Ratio (moles limestone/mole SO2 removed) Estimate. 1.0 1.0 reagent ration estiamted to achieve 40Operating Labor Cost ($/hr) Lafarge Data; unburdened cost. 23.78 Lafarge DataSupervisory Labor Cost ($/hr) Lafarge Data; unburdened cost. 31.58 Lafarge DataPower Cost ($/kW) Lafarge Data 0.063 Lafarge DataNH3 Cost ($/ton) Lafarge Data 650 Estimate.Water Cost ($/1000 gal) Lafarge Data 4.9 Lafarge DataNOx to SNCR (tpy) Based on 2004/2005 Average Emissions. 5,748NOx Removal Efficiency (%) Design Estimate. 50%SNCR On-stream Time (%) Design Estimate. 80%NOx Removed by System (tpy) Calculated from above values. 2,299

= NOx to SNCR (tpy) * NOx Removal EfficTime (%)

NH3 MW (lb/lb-mole) Constant 17NOx MW (lb/lb-mole) Constant 46Water Injection Rate (gpm) Based on 20% NH3/80% H2O by weight. 1.94 Calculated value.Direct Annual Costs (DAC)Operating labor • Operator ($/yr) 0.25 operators per shift 41,663 Estimate of staffing based on scrubber co • Supervisor ($/yr) 15% of operator labor 8,299 USEPA Control Cost Manual, Sec. 5.2, COperating materials • Water ($/yr) Based on evaporation rate. 3,994 Based on water used in injection system. • NH3 ($/yr) Based on Reagent Ratio of 1.0. 396,957 Calculated based on Reagent Ratio & SOMaintenance • Labor & Materials ($/yr) 1.5% of TCI 33,751 USEPA Control Cost Manual, Sec. 4.2, C1Electricity • Vaporization System & Pumps ($/yr) 71 kW 31,347 USEPA Control Cost Manual, Sec. 4.2, C1

DAC Subtotal Direct Annual Costs (DAC) 516,011 = SUM of Direct Annual Cost Items

Indirect Annual Costs (IAC)

Overhead ($/yr) 60% of total labor and material costs 290,798 USEPA Control Cost Manual, Sec. 5.2, C

Administrative charges ($/yr) 2% of Total Capital Investment 45,002 USEPA Control Cost Manual, Sec. 5.2, C

Property tax ($/yr) 1% of Total Capital Investment 22,501 USEPA Control Cost Manual, Sec. 5.2, C

Insurance ($/yr) 1% of Total Capital Investment 22,501 USEPA Control Cost Manual, Sec. 5.2, C

Capital recovery ($/yr) 10.98% x Total Capital Investment 247,059 USEPA Control Cost Manual, Sec. 5.2, C

IAC Subtotal Indirect Annual Costs (IAC) 627,860 = SUM of Indirect Annual Cost Items

Annualized Costs

Total Annual Cost ($/yr) DAC + IAC 1,143,871 = IAC Subtotal + DAC SubtotalControl Cost Effectiveness ($/ton) TAC / Tons NOx Removed 498 = Total Annual Cost ($/yr) / NOx Removed 

Annualized Cost Estimate
 

APPENDIX C 

CALMET Meteorological Stations 
WBAN WMO Station 

Number Number Name Longitude Latitude Easterly Northerly Easterly North

(deg) (deg) (km) (km) (km) (km

4874 726394 Charlevoix - Newberry Luce Co MI 85.47 46.32 885.399 757.221 155.894 5139

14808 726395 Wurtsmith AFB MI 83.40 44.45 1074.281 573.444 309.041 492414841 727347 Pellston Emmet County AP MI 84.78 45.57 949.275 681.352 205.051 505314847 727340 SAULT STE MARIE/NWSO MI 84.35 46.47 968.599 784.893 242.800 515114850 726387 TRAVERSE CITY/FAA AIRPORT MI 85.58 44.73 898.900 580.888 137.112 496314898 726450 GREEN BAY/AUSTIN STRAUBEL FIE WI 88.13 44.48 701.564 530.828 -67.248 4950

86399* 726399 Seul Choix Pt AMOS - false WBAN MI 85.92 45.92 856.439 708.678 118.499 5096

94814 726380 Houghton Lake Roscommon MI 84.68 44.37 975.025 550.216 206.794 491994849 726390 ALPENA/PHELPS COLLINS AP MI 83.57 45.07 1051.088 639.300 297.917 499394853 726480 Escanaba AWOS MI 87.03 45.75 773.078 679.921 31.008 508394896 726487 Menominee AWOS MI 87.63 45.13 733.824 606.346 -21.357 5018

*Pseudo-WBAN number assigned for unknown WBAN number.

Surface Stations

2002, 2003 and 2004

State Geographic Location Lambert CC UTM

Station Station 

Number Name Longitude Latitude Easterly Northerly Easterly Northe

(deg) (deg) (km) (km) (km) (km)

4837 Gaylord MI 84.43 44.54 992.082 571.628 227.506 4937.5

14898 GREEN BAY/AUSTIN STRAUBEL FIE WI 88.13 44.48 701.564 530.828 -67.248 4950.3

Upper Air Stations

2002, 2003 and 2004

State Geographic Location Lambert CC UTM
Station Station 

Number Name Longitude Latitude Easterly Northerly Easterly Norther

(deg) (deg) (km) (km) (km) (km)

200164* ALPENA WB AIRPORT MI 83.57 45.07 1050.806 639.596 297.692 4993.9

200662 BELLAIRE MI 85.20 44.98 925.333 611.962 168.860 4989.3200766 BIG BAY 8 NW MI 87.87 46.88 695.537 798.422 -23.381 5214.7201486 CHATHAM EXP FARM 2 MI 86.92 46.33 774.419 745.086 44.371 5147.7202094 DETOUR VILLAGE MI 83.90 46.00 1010.299 738.259 275.450 5098.1202626 ESCANABA MI 87.03 45.75 773.078 679.921 31.008 5083.9

202788 FIFE LAKE 1 NNW MI 85.35 44.58 919.318 566.356 154.653 4945.5203199 GLENNIE ALCONA DAM MI 83.80 44.57 1040.981 581.974 277.671 4938.9203391 GRAYLING MI 84.70 44.65 969.256 580.820 206.611 4950.7203516 GWINN 1 W MI 87.45 46.28 734.439 735.145 3.134 5145.4

203936* HOUGHTON LAKE WSO AIRPORT MI 84.68 44.37 975.025 550.216 206.794 4919.5

204090 IRON MTN-KINGSFORD WWTP MI 88.08 45.78 691.610 674.781 -50.350 5094.0205073 MANISTIQUE MI 86.25 45.95 830.658 708.932 93.133 5101.9205816 NEWBERRY STATE HOSPITL MI 85.50 46.33 882.967 758.035 153.648 5140.5206438 PELLSTON REGIONAL AP MI 84.79 45.56 948.651 680.145 204.218 5052.1207366 SAULT STE MARIE WSO MI 84.35 46.47 968.552 785.224 242.814 5151.7208246 TRAVERSE CITY MI 85.57 44.77 899.402 585.097 138.373 4967.5208293 TROUT LAKE MI 85.02 46.20 921.517 748.429 189.856 5124.1208417 VANDERBILT 11 ENE MI 84.45 45.17 980.874 640.766 228.893 5007.6476510 PESHTIGO WI 87.73 45.03 727.152 594.481 -30.148 5008.3478267 STURGEON BAY EXP FARM WI 87.33 44.87 760.302 580.063 -0.032 4988.0

*Not used for 2002 (contained invalid characters)

Geographic Location Lambert CC UTM

Precipitation Stations

2002, 2003 and 2004

State
 

APPENDIX D 

Seney Receptor Locations and Elevations 
 

CALPUFF Receptor Locations (LCC) 

LCC Origin: 40.0N, 97.0W, Standard Parallels: 33.0N, 45.0N 

Receptor 

No. 

LCC East 

(km) 

LCC 

West 

(km) z (m) Description 

Distance 

to Lafarge 

(km) 

Source 1066.867 641.697 Lafarge 

1 827.834 740.858 225.000 Seney 258.785 

2 828.472 740.934 225.000 Seney 258.225 

3 829.110 741.010 225.000 Seney 257.666 

4 829.748 741.086 226.000 Seney 257.107 

5 830.386 741.163 226.000 Seney 256.548 

6 831.024 741.239 226.000 Seney 255.989 

7 831.662 741.315 226.000 Seney 255.432 

8 832.300 741.391 226.000 Seney 254.874 

9 832.938 741.468 226.000 Seney 254.317 

10 833.576 741.544 225.000 Seney 253.760 

11 834.214 741.621 224.000 Seney 253.204 

12 834.852 741.697 223.000 Seney 252.649 

13 835.490 741.774 223.000 Seney 252.093 

14 836.128 741.850 222.000 Seney 251.538 

15 836.765 741.927 221.000 Seney 250.984 

16 837.403 742.004 220.000 Seney 250.430 

17 838.041 742.081 220.000 Seney 249.877 

18 827.725 741.781 227.000 Seney 259.241 

19 828.362 741.857 226.000 Seney 258.682 

20 829.000 741.933 227.000 Seney 258.124 

21 829.638 742.009 227.000 Seney 257.566 

22 830.276 742.085 227.000 Seney 257.008 

23 830.914 742.161 228.000 Seney 256.451 

24 831.552 742.237 228.000 Seney 255.894 

25 832.190 742.314 228.000 Seney 255.338 

26 832.828 742.390 227.000 Seney 254.782 

27 833.465 742.466 226.000 Seney 254.226 

28 834.103 742.543 224.000 Seney 253.671 

29 834.741 742.619 223.000 Seney 253.117 

30 835.379 742.696 223.000 Seney 252.562 

31 836.017 742.773 221.000 Seney 252.009 

32 836.654 742.849 221.000 Seney 251.455 

33 826.977 742.627 227.000 Seney 260.258 

34 827.615 742.703 229.000 Seney 259.700 

35 828.253 742.779 229.000 Seney 259.142 

36 828.890 742.855 228.000 Seney 258.585 

37 829.528 742.931 228.000 Seney 258.028 

38 830.166 743.007 229.000 Seney 257.471 

39 830.804 743.083 229.000 Seney 256.915 

40 831.442 743.160 229.000 Seney 256.359 

41 832.079 743.236 228.000 Seney 255.804 

42 832.717 743.312 229.000 Seney 255.249 

43 833.355 743.389 228.000 Seney 254.695 
 

CALPUFF Receptor Locations (LCC) 

LCC Origin: 40.0N, 97.0W, Standard Parallels: 33.0N, 45.0N 

Receptor 

No. 

LCC East 

(km) 

LCC 

West 

(km) z (m) Description 

Distance 

to Lafarge 

(km) 

44 833.993 743.465 225.000 Seney 254.141 

45 834.630 743.542 226.000 Seney 253.587 

46 835.268 743.618 226.000 Seney 253.034 

47 835.906 743.695 226.000 Seney 252.481 

48 826.867 743.550 229.000 Seney 260.718 

49 827.505 743.626 231.000 Seney 260.161 

50 828.143 743.702 231.000 Seney 259.604 

51 828.780 743.778 231.000 Seney 259.048 

52 829.418 743.854 231.000 Seney 258.492 

53 830.056 743.930 230.000 Seney 257.936 

54 830.694 744.006 230.000 Seney 257.381 

55 831.331 744.082 230.000 Seney 256.827 

56 831.969 744.158 229.000 Seney 256.273 

57 832.607 744.235 229.000 Seney 255.719 

58 833.244 744.311 229.000 Seney 255.165 

59 833.882 744.387 227.000 Seney 254.613 

60 834.520 744.464 229.000 Seney 254.060 

61 835.157 744.541 229.000 Seney 253.508 

62 835.795 744.617 229.000 Seney 252.957 

63 826.120 744.397 229.000 Seney 261.738 

64 826.758 744.472 236.000 Seney 261.181 

65 827.395 744.548 235.000 Seney 260.625 

66 828.033 744.624 234.000 Seney 260.069 

67 828.671 744.700 234.000 Seney 259.514 

68 829.308 744.776 233.000 Seney 258.959 

69 829.946 744.852 232.000 Seney 258.404 

70 830.583 744.928 232.000 Seney 257.850 

71 831.221 745.004 232.000 Seney 257.297 

72 831.859 745.081 231.000 Seney 256.744 

73 832.496 745.157 230.000 Seney 256.191 

74 833.134 745.233 229.000 Seney 255.639 

75 833.771 745.310 229.000 Seney 255.087 

76 834.409 745.386 229.000 Seney 254.536 

77 835.047 745.463 229.000 Seney 253.985 

78 835.684 745.539 229.000 Seney 253.434 

79 826.010 745.319 229.000 Seney 262.202 

80 826.648 745.395 236.000 Seney 261.646 

81 827.286 745.471 237.000 Seney 261.091 

82 827.923 745.547 237.000 Seney 260.536 

83 828.561 745.622 236.000 Seney 259.982 

84 829.198 745.698 236.000 Seney 259.428 

85 829.836 745.775 234.000 Seney 258.875 

86 830.473 745.851 234.000 Seney 258.322 

87 831.111 745.927 235.000 Seney 257.769 

88 831.748 746.003 234.000 Seney 257.217 
 

CALPUFF Receptor Locations (LCC) 

LCC Origin: 40.0N, 97.0W, Standard Parallels: 33.0N, 45.0N 

Receptor 

No. 

LCC East 

(km) 

LCC 

West 

(km) z (m) Description 

Distance 

to Lafarge 

(km) 

89 832.386 746.079 232.000 Seney 256.666 

90 833.023 746.156 231.000 Seney 256.115 

91 833.661 746.232 230.000 Seney 255.564 

92 834.298 746.309 230.000 Seney 255.014 

93 834.936 746.385 229.000 Seney 254.464 

94 825.901 746.242 238.000 Seney 262.668 

95 826.538 746.317 239.000 Seney 262.114 

96 827.176 746.393 239.000 Seney 261.560 

97 827.813 746.469 238.000 Seney 261.006 

98 828.451 746.545 238.000 Seney 260.453 

99 829.088 746.621 237.000 Seney 259.900 

100 829.726 746.697 236.000 Seney 259.348 

101 830.363 746.773 236.000 Seney 258.796 

102 831.000 746.849 236.000 Seney 258.244 

103 831.638 746.926 236.000 Seney 257.694 

104 832.275 747.002 234.000 Seney 257.143 

105 832.913 747.078 233.000 Seney 256.593 

106 825.154 747.088 238.000 Seney 263.691 

107 825.791 747.164 242.000 Seney 263.137 

108 826.429 747.240 242.000 Seney 262.584 

109 827.066 747.316 242.000 Seney 262.031 

110 827.703 747.391 240.000 Seney 261.478 

111 828.341 747.467 240.000 Seney 260.926 

112 828.978 747.543 240.000 Seney 260.374 

113 829.615 747.619 239.000 Seney 259.823 

114 830.253 747.696 238.000 Seney 259.272 

115 830.890 747.772 238.000 Seney 258.722 

116 831.528 747.848 237.000 Seney 258.172 

117 832.165 747.924 236.000 Seney 257.623 

118 825.682 748.087 244.000 Seney 263.608 

119 826.319 748.162 244.000 Seney 263.056 

120 826.956 748.238 244.000 Seney 262.504 

121 827.594 748.314 243.000 Seney 261.953 

122 828.231 748.390 242.000 Seney 261.402 

123 828.868 748.466 242.000 Seney 260.851 

124 829.505 748.542 241.000 Seney 260.301 

125 830.143 748.618 240.000 Seney 259.751 

126 830.780 748.694 240.000 Seney 259.202 

127 831.417 748.770 238.000 Seney 258.653 

128 832.054 748.847 236.000 Seney 258.105 

129 825.572 749.009 244.000 Seney 264.082 

130 826.209 749.085 244.000 Seney 263.531 

131 826.846 749.161 244.000 Seney 262.980 

132 827.484 749.237 244.000 Seney 262.430 

133 828.121 749.312 244.000 Seney 261.880 
 

CALPUFF Receptor Locations (LCC) 

LCC Origin: 40.0N, 97.0W, Standard Parallels: 33.0N, 45.0N 

Receptor 

No. 

LCC East 

(km) 

LCC 

West 

(km) z (m) Description 

Distance 

to Lafarge 

(km) 

134 828.758 749.388 244.000 Seney 261.330 

135 829.395 749.464 243.000 Seney 260.781 

136 830.032 749.541 243.000 Seney 260.233 

137 830.670 749.617 240.000 Seney 259.684 

138 831.307 749.693 239.000 Seney 259.137 

139 831.944 749.769 238.000 Seney 258.590 

140 825.462 749.932 245.000 Seney 264.558 

141 826.100 750.007 245.000 Seney 264.008 

142 826.737 750.083 245.000 Seney 263.458 

143 827.374 750.159 244.000 Seney 262.909 

144 828.011 750.235 244.000 Seney 262.360 

145 828.648 750.311 244.000 Seney 261.812 

146 829.285 750.387 244.000 Seney 261.264 

147 829.922 750.463 243.000 Seney 260.716 

148 830.559 750.539 241.000 Seney 260.169 

149 831.196 750.615 240.000 Seney 259.623 

150 831.834 750.692 240.000 Seney 259.077 

151 825.353 750.854 247.000 Seney 265.037 

152 825.990 750.930 246.000 Seney 264.488 

153 826.627 751.006 245.000 Seney 263.939 

154 827.264 751.082 245.000 Seney 263.391 

155 827.901 751.158 244.000 Seney 262.843 

156 828.538 751.233 244.000 Seney 262.296 

157 829.175 751.309 244.000 Seney 261.749 

158 829.812 751.386 244.000 Seney 261.203 

159 830.449 751.462 242.000 Seney 260.657 

160 831.086 751.538 241.000 Seney 260.111 

161 831.723 751.614 241.000 Seney 259.566 

162 825.243 751.777 247.000 Seney 265.518 

163 825.880 751.853 246.000 Seney 264.970 

164 826.517 751.928 246.000 Seney 264.422 

165 827.154 752.004 245.000 Seney 263.875 

166 827.791 752.080 245.000 Seney 263.329 

167 828.428 752.156 244.000 Seney 262.782 

168 829.065 752.232 244.000 Seney 262.237 

169 829.702 752.308 244.000 Seney 261.691 

170 830.339 752.384 243.000 Seney 261.146 

171 830.976 752.460 242.000 Seney 260.602 

172 825.134 752.700 247.000 Seney 266.002 

173 825.770 752.775 247.000 Seney 265.455 
 

APPENDIX E 

Model Summary Results and 

Example CALPOST Output for Baseline 2002 Model 

All other model output and input files provided on enclosed CD 
 

Class I Area

Delta Deciview 

Rank Baseline

Scenario 1: 

SNCR 

KG5&6, Wet 

Scrub KG6

Scenario 2: 

SNCR 

KG5&6, Wet 

Scrub KG6, 

DAA KG5

Scenario 3: 

SNCR 

KG5&6, Wet 

Scrub 

KG5&6 Baseline

Scenario 1: 

SNCR 

KG5&6, Wet 

Scrub KG6

Scenario 2: 

SNCR 

KG5&6, Wet 

Scrub KG6, 

DAA KG5

Scenario 3: 

SNCR 

KG5&6, Wet 

Scrub 

KG5&6 Baseline

Scenario 1: 

SNCR 

KG5&6, Wet 

Scrub KG6

Scenario 2: 

SNCR KG5&6, 

Wet Scrub 

KG6, DAA 

KG5

Scenario 3: 

SNCR 

KG5&6, Wet 

Scrub 

KG5&6

Seney 1 2.949 1.637 1.498 1.058 3.866 2.098 1.883 1.364 2.178 1.228 1.141 0.869

2 2.324 1.357 1.281 1.039 3.38 1.932 1.795 1.275 1.777 0.956 0.874 0.678

3 1.735 0.896 0.798 0.494 2.945 1.61 1.488 1.198 1.616 0.912 0.855 0.619

4 1.277 0.702 0.642 0.452 2.579 1.555 1.462 0.996 1.315 0.765 0.729 0.613

5 1.104 0.561 0.496 0.399 2.346 1.221 1.081 0.774 1.305 0.746 0.701 0.557

6 1.029 0.53 0.477 0.313 2.054 1.058 0.981 0.702 1.3 0.719 0.661 0.526

7 0.807 0.484 0.464 0.294 1.983 1.047 0.947 0.656 1.285 0.699 0.641 0.509

8 0.711 0.371 0.34 0.242 1.852 1.022 0.908 0.644 1.089 0.641 0.614 0.474

9 0.609 0.314 0.29 0.216 1.747 0.974 0.903 0.639 0.96 0.591 0.572 0.461

10 0.589 0.306 0.274 0.215 1.733 0.957 0.884 0.625 0.935 0.534 0.505 0.414

11 0.478 0.273 0.26 0.197 1.438 0.82 0.773 0.603 0.777 0.417 0.384 0.283

12 0.432 0.244 0.233 0.177 1.437 0.778 0.746 0.564 0.653 0.358 0.332 0.252

13 0.42 0.214 0.191 0.153 1.385 0.772 0.722 0.527 0.608 0.332 0.302 0.206

14 0.352 0.197 0.186 0.124 1.301 0.769 0.697 0.471 0.529 0.274 0.249 0.194

15 0.346 0.184 0.169 0.12 1.096 0.597 0.555 0.422 0.435 0.236 0.222 0.173

16 0.281 0.151 0.141 0.118 1.073 0.586 0.533 0.41 0.428 0.233 0.219 0.171

17 0.269 0.149 0.14 0.104 1.02 0.566 0.528 0.364 0.414 0.233 0.218 0.171

18 0.212 0.117 0.11 0.085 0.889 0.481 0.443 0.326 0.389 0.231 0.215 0.165

19 0.182 0.104 0.097 0.076 0.81 0.423 0.383 0.264 0.338 0.197 0.191 0.161

20 0.162 0.094 0.09 0.075 0.68 0.362 0.334 0.257 0.324 0.169 0.15 0.119

21 0.157 0.089 0.083 0.067 0.581 0.335 0.318 0.25 0.262 0.15 0.142 0.104

22 0.15 0.074 0.066 0.046 0.524 0.264 0.237 0.155 0.249 0.138 0.13 0.096

No. Days > 0.5 dv --> 10 6 4 2 22 17 17 13 14 10 10 7

98% value (8th high) --> 0.711 0.371 0.340 0.242 1.852 1.022 0.908 0.644 1.089 0.641 0.614 0.474

No. Days 8th high > 0.5 dv --> 3 0 0 0 15 10 10 6 7 3 3 0

Largest delta dv --> 2.9 1.6 1.5 1.1 3.9 2.1 1.9 1.4 2.2 1.2 1.1 0.9

3-yrs Combined 98% value -> 1.301 0.746 0.697 0.509

3-yrs Comb. Days 98% > 0.5 dv -> 25 12 10 1

Annualized Control Costs $0 $11,470,682 $12,877,600 $21,949,728 $0 $11,470,682 $12,877,600 $21,949,728 $0 $11,470,682 $12,877,600 $21,949,728

Modeled Rates (lb/hr) All Kilns

NOx --> 3947 2447 2447 2447

SO2 --> 9734 4487 3852 1947

Modeled Rates (ton/day) All Kilns

NOx --> 47.4 29.4 29.4 29.4

SO2 --> 116.8 53.8 46.2 23.4

0.5 dv is critical value, allowed 7 exceedences per year.

Assumptions:

No ammonia limiting method.

CALMET in OBS mode, 12 surface, 2 upper air stations

Average background concentration (not 20% best days)

% Reductions Due to Control:

KG5 KG6

DAA 20 20

Wet Scrubbing 80 80

SNCR 35 40

Delta Deciview Ranking (4km CALMET Runs)

2002 2003 2004

Year of Meteorology
Appendix 9D 

Lafarge Global Settlement/Consent Decree - 

Alpena Facility 
 

 

 

 

_____________________________________ 

 

 

 

 

 

 

 

 

 

 

 

 

 

UNITED STATES DISTRICT COURT
 

FOR THE SOUTHERN DISTRICT OF ILLINOIS 

) 

UNITED STATES OF AMERICA, ) 

)

 Plaintiff, ) 

) 

and the STATE of ALABAMA, the STATE ) 

of ILLINOIS, the STATE of IOWA, ) 

the STATE of KANSAS, the STATE of ) 

MICHIGAN, the STATE of MISSOURI, ) 

the STATE of NEW YORK, the STATE ) 

OF OHIO, the STATE of PENNSYLVANIA, ) 

the STATE of SOUTH CAROLINA ) 

DEPARTMENT OF HEALTH AND ) 

ENVIRONMENTAL CONTROL, ) 

the WASHINGTON STATE ) 

DEPARTMENT OF ECOLOGY, ) 

the OKLAHOMA DEPARTMENT OF ) 

ENVIRONMENTAL QUALITY, and ) 

the PUGET SOUND CLEAN AIR AGENCY, ) 

) 

Plaintiff-Intervenors, ) 

) Civil Action No. 3:10-cv-0004-JPG-CJP

 v. ) 

) 

LAFARGE NORTH AMERICA, INC., ) 

LAFARGE MIDWEST, INC. , and ) 

LAFARGE BUILDING MATERIALS, INC., ) 

)

 Defendants. ) 

_____________________________________ ) 

CONSENT DECREE 

1
V. NOx CONTROL TECHNOLOGY, EMISSION LIMITS, TONNAGE LIMITS,
 

AND MONITORING REQUIREMENTS
 

A. NOx Control Technology, Emission Limits and Tonnage Limits. 

11. Subject to Section VII (Temporary Cessation of Kiln Operation), the Lafarge 

Companies shall install the NOx Control Technology and comply with the Emission Limits and 

Tonnage Limits for the specific Facilities and Kilns within their system according to Paragraphs 

11 through 44. The Lafarge Companies shall Continuously Operate each NOx Control 

Technology as applicable to each Kiln at all times of Kiln Operation, except for periods of 

Malfunction of the NOx Control Technology. Compliance with any requirement of this Section 

V (NOx Control Technology, Emission Limits, Tonnage Limits, and Monitoring Requirements) 

relating to any specific Facility or Kiln shall not be required if the Lafarge Companies Retire any 

such Facility or Kiln prior to any date for compliance. If one or more Kilns at a Facility is in 

Temporary Cessation, then the following provisions shall apply in addition to any other 

requirements in this Consent Decree: 

a.	 The Lafarge Companies shall comply with the applicable Demonstration Phase 

Facility-Wide 12-Month Rolling Average Emission Limit at all other Kilns not in 

Temporary Cessation at the Facility within 12 months of the Day on which the 

last Optimization Phase was concluded (as determined by U.S. EPA and the 

Affected State) at a Kiln not in Temporary Cessation at the Facility; and 

b.	 The Lafarge Companies shall comply with the applicable Facility-Wide 12-Month 

Rolling Average Emission Limit and Facility-Wide 12-Month Rolling Tonnage 

Limit at all other Kilns not in Temporary Cessation on the dates required in this 

Section V (NOx Control Technology, Emission Limits, Tonnage Limits and 

Monitoring Requirements). 

2
 

Alpena 

12. By January 1, 2011, the Lafarge Companies shall achieve and maintain 

compliance with an interim Facility-Wide 12-Month Rolling Tonnage Limit for NOx of 8,650 

tons. 

13. Control Technology Retrofit Option. 

a.	 Subject to Section VII (Temporary Cessation of Kiln Operation), the Lafarge 

Companies shall have installed and Commenced Continuous Operation of the 

SNCR technology specified in the table below on individual Kilns in the order 

selected by the Lafarge Companies within each specified Kiln Group (“KG”) at 

the Alpena Facility by the dates specified below: 

Kiln Control 

Technology 

Date of 

Installation and 

Commencement 

of Continuous 

Operation 

30-Day Rolling 

Average Emission 

Limits 

(lbs. NOx/Ton of 

clinker) 

Demonstration Phase 

Facility-Wide 12-Month 

Rolling Average 

Emission Limit 

(lbs. NOx/Ton of 

clinker) 

1st Kiln 

in KG5 

SNCR 10/1/2011 See Appendix 

4.89 

2nd Kiln 

in KG5 

SNCR 11/1/2011 See Appendix 

3rd Kiln 

in KG5 

SNCR 12/1/2011 See Appendix 

1st Kiln 

in KG6 

SNCR 1/1/2012 See Appendix 

2nd Kiln 

in KG6 

SNCR 3/1/2012 See Appendix 

3
b.	 Upon installation of the Control Technology, the Lafarge Companies shall 

Continuously Operate the SNCR technology during all times of Kiln Operation, 

except during periods of SNCR technology Malfunction. 

c.	 If the Lafarge Companies elect not to Retire and Replace any Alpena Kiln in 

accordance with Section VIII (Election to Retire and Replace Kilns), then: 

i.	 Within 12 months after the conclusion of the Optimization Phase as it 

applies to Kilns 19, 20, and 21 (KG5) identified in Paragraphs 13 and 

7.z(1), the Lafarge Companies shall achieve and maintain compliance with 

the Demonstration Phase Facility-Wide 12-Month Rolling Average 

Emission Limit for NOx of 4.89 lbs./Ton of clinker at Kilns 19, 20, and 21 

(KG5), or, alternatively, at those Kilns the Lafarge Companies have 

elected not to Retire and Replace; 

ii.	 Within 12 months after the conclusion of the Optimization Phase as it 

applies to Kilns 22 and 23 (KG6) identified in Paragraphs 13 and 7.z(1), 

the Lafarge Companies shall achieve and maintain compliance with the 

Demonstration Phase Facility-Wide 12-Month Rolling Average Emission 

Limit for NOx of 4.89 lbs./Ton of clinker at Kilns 19, 20, 21, 22, and 23 

(KG5 and KG6), or, alternatively, at those Kilns the Lafarge Companies 

have elected not to Retire and Replace. 

d.	 The Lafarge Companies shall comply with the Appendix (Control Technology 

Demonstration Requirements) in setting a 30-Day Rolling Average Emission 

Limit for NOx applicable to each Alpena Kiln that the Lafarge Companies have 

not otherwise elected to Retire and/or Replace pursuant to Section VIII (Election 

4
to Retire and Replace Kilns). Within 30 Days after the establishment of a 30-Day 

Rolling Average Emission Limit for NOx under the Appendix at any Alpena Kiln 

that the Lafarge Companies have not otherwise elected to Retire or Replace, the 

Lafarge Companies shall achieve and maintain compliance with the 30-Day 

Rolling Average Emission Limit for NOx at the respective Kiln. 

14. Kiln Replacement Option. If the Lafarge Companies elect to Retire and Replace 

any Alpena Kiln in accordance with Section VIII (Election to Retire and Replace Kilns), then 

Paragraph 13 (Control Technology Retrofit Option) shall not apply to that Kiln. Instead, the 

Lafarge Companies shall: 

a.	 Within 180 Days from the Date of Lodging of this Consent Decree, submit an 

application addressing all applicable requirements under the Clean Air Act and 

the Michigan SIP for a permit to install any Replacement Kiln(s) and thereafter 

take all other actions necessary to obtain such permits or approvals after filing the 

applications including, but not limited to, responding to reasonable requests for 

additional information by the permitting authority in a timely fashion, and 

conducting any environmental or other assessment lawfully required by the 

permitting authority; 

b.	 Submit written notice to U.S. EPA and the State of Michigan pursuant to Section 

XIX (Notices) within ten (10) Days after the date on which the Lafarge 

Companies have commenced construction of the Replacement Kiln(s), stating the 

date on which such construction commenced; 

c.	 Complete construction of the Replacement Kiln(s) within 42 months of the date 

on which the Lafarge Companies commence construction of the Replacement 

5
Kiln(s), provided that if the Lafarge Companies fail to commence construction of 

any Replacement Kilns by January 1, 2012 or within 12 months of permit 

issuance pursuant to Paragraph 14.a., whichever is earlier, then, in addition to any 

other remedies available to the United States or the State of Michigan under this 

Consent Decree or other applicable law, the Lafarge Companies shall either: 

i.	 Install and Commence Continuous Operation of the Control Technology 

by January 1, 2014 or within 36 months of permit issuance pursuant to 

Paragraph 14.a., whichever is earlier, and thereafter comply with the 

Control Technology and other applicable requirements of Paragraph 13 as 

to the existing Alpena Kilns; or 

ii.	 Retire the Kiln(s) by July 1, 2012 or within 18 months of a permit 

issuance pursuant to Paragraph 14.a, whichever is earlier. 

d.	 Commence Kiln Operation of any Replacement Kiln(s) within 42 months of the 

date on which the Lafarge Companies commence construction of the Replacement 

Kiln, or January 1, 2015, whichever is earlier; 

e.	 Retire the Replaced Kiln(s) within 180 Days of commencement of Kiln Operation 

of the Replacement Kiln(s); 

f.	 Install and Commence Continuous Operation of one SNCR at each Replacement 

Kiln within 42 months of the date on which the Lafarge Companies commence 

construction of the Replacement Kiln, or January 1, 2015, whichever is earlier; 

and 

g.	 Within 180 Days after the Lafarge Companies have commenced Kiln Operation 

of any Replacement Kiln at Alpena, achieve and maintain compliance with a 30-

6
Day Rolling Average Emission Limit for NOx of 2.1 lb/Ton of clinker, or the 

applicable New Source Performance Standard for NOx for Portland Cement 

Manufacturing Facilities promulgated pursuant to Section 111 of the Act, 

whichever is more stringent, at each Replacement Kiln. 

15. Subject to Paragraph 16 below, within 54 months of the date on which the 

Lafarge Companies commence construction of any Replacement Kiln(s), or January 1, 2016, 

whichever is earlier, the Lafarge Companies shall, at Alpena, achieve and maintain compliance 

with a Facility-Wide 12-Month Rolling Tonnage Limit for NOx of 7,160 Tons of NOx emitted per 

12-month period. 

16. Notification Regarding Alpena Replacement Compliance Dates. If a 

governmental entity's failure to act upon a timely-submitted or supplemented permit or approval 

application submitted pursuant to Paragraph 14.a., or the action of any third-party challenging 

the issuance of such permit operates to delay the issuance or effectiveness of a final valid permit 

or approval, thereby impairing the Lafarge Companies’ ability to timely satisfy the 

implementation schedule requirements of Paragraph 14, the Lafarge Companies shall notify, in 

writing, the U.S. EPA and the State of Michigan of any such delay as soon as the Lafarge 

Companies reasonably conclude that the delay could affect their ability to comply with the 

implementation schedule set forth in Paragraph 14. 

a.	 If the Lafarge Companies provide the notification required under this Paragraph 

16, the Lafarge Companies shall propose in such notification, for approval by the 

U.S. EPA and the State of Michigan pursuant to Section XXII (Modification), a 

modification to the applicable schedule of implementation setting out the time 

necessary to comply after the permit or approval has been finalized and becomes 

7
45. At each Kiln identified in Paragraph 7.z of this Decree (except for Joppa Kiln 3), 

the Lafarge Companies shall install and make operational within 12 months of the Effective Date 

a NOx continuous emissions monitoring system (CEMS) at each stack which collects emissions 

from such Kiln (or Kilns, in the case of Ravena) in accordance with the requirements of 40 C.F.R. 

Part 60. 

46. Except during CEMS breakdowns, repairs, calibration checks, and zero span 

adjustments, the CEMS required pursuant to Paragraph 45 shall be operated at all times during 

Kiln Operation. Each such CEMS shall be used at each Kiln to demonstrate compliance with the 

NOx Emission Limits established in Section V.A (NOx Control Technology, Emission Limits, 

and Tonnage Limits) and the Appendix (Control Technology Demonstration Requirements), as 

applicable, of this Consent Decree. 

47. Each NOx CEMS required pursuant to Paragraph 45 shall monitor and record the 

applicable NOx emission rate from each Kiln stack in units of lbs of NOx per Ton of clinker 

produced at such Kiln and shall be installed, certified, calibrated, maintained, and operated in 

accordance with the applicable requirements of 40 C.F.R. Part 60. 

48. For purposes of this Consent Decree, all emissions of NOx shall be measured by 

CEMS. During any time when CEMs are inoperable and otherwise not measuring emissions of 

NOx from any Kiln, the Lafarge Companies shall apply the missing data substitution procedures 

used by the Affected State or the missing data substitution procedures in 40 C.F.R. Part 75, 

Subpart D, whichever is deemed appropriate by the Affected State. 

VI. SO2 CONTROL TECHNOLOGY, EMISSION LIMITS, TONNAGE LIMITS, AND 

MONITORING REQUIREMENTS
 

A. SO2 Control Technology, Emission Limits, and Tonnage Limits. 

49. Subject to Section VII (Temporary Cessation of Kiln Operation), the Lafarge 

8
Companies shall install the SO2 Control Technology and comply with the Emission Limits for 

the specific Facilities and Kilns within their system according to Paragraphs 49 through 77. The 

Lafarge Companies shall Continuously Operate each SO2 Control Technology as applicable to 

each Kiln at all times of Kiln Operation, except for periods of Malfunction of the SO2 Control 

Technology. Compliance with any requirements of this Section VI relating to any specific 

Facility or Kiln shall not be required if the Lafarge Companies Retire any such Facility or Kiln 

prior to any date for compliance. If one or more Kilns at a Facility is in Temporary Cessation, 

then the following provisions shall apply in addition to any other requirements in this Consent 

Decree: 

a.	 The Lafarge Companies shall comply with the applicable Demonstration Phase 

Facility-Wide 12-Month Rolling Average Emission Limit at all other Kilns not in 

Temporary Cessation at the Facility within 12 months of the date on which the 

last Optimization Phase was concluded (as determined by U.S. EPA and the 

Affected State) at a Kiln not in Temporary Cessation at the Facility. 

b.	 The Lafarge Companies shall comply with the applicable Facility-Wide 12-Month 

Rolling Average Emission Limit and Facility-Wide 12-Month Rolling Tonnage 

Limit at all other Kilns not in Temporary Cessation on the dates required in this 

Section VI (SO2 Control Technology, Emission Limits, Tonnage Limits and 

Monitoring Requirements). 

9
Alpena 

50. By January 1, 2011, the Lafarge Companies shall achieve and maintain 

compliance with an interim Facility-Wide 12-Month Rolling Tonnage Limit for SO2 of 13,100 

tons per year. 

51. Control Technology Retrofit Option. 

a.	 Subject to Section VII (Temporary Cessation of Kiln Operation), the Lafarge 

Companies shall have installed and Commenced Continuous Operation of DAA 

or Wet FGD technology in the table specified below on individual Kilns in the 

order selected by the Lafarge Companies within each specified Kiln Group (“KG”) 

at the Alpena Facility by the dates specified below: 

Kiln Control 

Technology 

Date of 

Installation and 

Commencement 

of Continuous 

Operation 

30-Day Rolling 

Average Emission 

Limits 

Demonstration Phase 

Facility-Wide 12-Month 

Rolling Average 

Emission Limit 

(lbs. SO2 /Ton of 

clinker) 

1st Kiln 

in KG5 DAA 10/1/2011 See Appendix 

3.68 

2nd Kiln 

in KG5 DAA 11/1/2011 See Appendix 

3rd Kiln 

in KG5 DAA 12/1/2011 See Appendix 

1st Kiln 

in KG6 Wet FGD 1/1/2014 See Appendix 

2nd Kiln 

in KG6 Wet FGD 3/1/2014 See Appendix 

b. Upon installation of the SO2 Control Technology, the Lafarge Companies shall 

Continuously Operate the SO2 Control Technology during all times of Kiln 

Operation, except during periods of SO2 Control Technology Malfunction. 

10
c.	 Lafarge shall design each Wet FGD to be installed at Alpena Kilns 22 and 23 

(KG6) to achieve a removal efficiency for SO2 of no less than 90%. 

d.	 If the Lafarge Companies elect not to Retire and Replace any Alpena Kiln in 

accordance with Section VIII (Election to Retire and Replace Kilns), then: 

i.	 Within 12 months after the conclusion of the Optimization Phase as it 

applies to Kilns 19, 20, and 21 (KG5) identified in Paragraphs 51 and 

7.z(1), the Lafarge Companies shall achieve and maintain compliance with 

the Demonstration Phase Facility-Wide 12-Month Rolling Average 

Emission Limit for SO2 of 3.68 lbs./Ton of clinker at Kilns 19, 20, and 21 

(KG5), or, alternatively, at those Kilns the Lafarge Companies have 

elected not to Retire and Replace; 

ii.	 Within 12 months after the conclusion of the Optimization Phase as it 

applies to Kilns 22 and 23 (KG6) identified in Paragraphs 51 and 7.z(1), 

the Lafarge Companies shall achieve and maintain compliance with the 

Demonstration Phase Facility-Wide 12-Month Rolling Average Emission 

Limit for SO2 of 3.68 lbs./Ton of clinker at Kilns 19, 20, 21, 22, and 23 

(KG5 and KG6), or, alternatively, at those Kilns the Lafarge Companies 

have elected not to Retire and Replace. 

e.	 The Lafarge Companies shall comply with the Appendix (Control Technology 

Demonstration Requirements) in setting a 30-Day Rolling Average Emission 

Limit for SO2 applicable to each Alpena Kiln that the Lafarge Companies have 

not otherwise elected to Retire and/or Replace pursuant to Section VIII (Election 

to Retire and Replace Kilns). Within 30 Days after the establishment of a 30-Day 

11
Rolling Average Emission Limit for SO2 under the Appendix at any Alpena Kiln 

that the Lafarge Companies have not otherwise elected to Retire or Replace, the 

Lafarge Companies achieve and maintain compliance with the 30-Day Rolling 

Average Emission Limit for SO2 at the respective Kiln. 

52. Kiln Replacement Option. If the Lafarge Companies elect to Retire and Replace 

any Alpena Kiln in accordance with Section VIII (Election to Retire and Replace Kilns), then 

Paragraph 51 (Control Technology Retrofit Option) shall not apply to that Kiln. Instead, the 

Lafarge Companies shall: 

a.	 Within 180 Days following the Date of Lodging of this Consent Decree, submit 

an application addressing all applicable requirements under the Clean Air Act and 

the Michigan SIP for a permit to install any Replacement Kiln(s) at Alpena and 

thereafter take all other actions necessary to obtain such permits or approvals after 

filing the applications including, but not limited to, responding to reasonable 

requests for additional information by the permitting authority in a timely fashion, 

and conducting any environmental or other assessment lawfully required by the 

permitting authority; 

b.	 Submit written notice to U.S. EPA and the State of Michigan pursuant to Section 

XIX (Notices) within 10 Days after the date on which Lafarge has commenced 

construction of the Replacement Kiln(s), stating the date on which such 

construction commenced; 

c.	 Complete construction of the Replacement Kiln(s) within 42 months of the date 

on which the Lafarge Companies commence construction of the Replacement 

Kiln(s), provided that if the Lafarge Companies fail to commence construction of 


 

12
any Replacement Kilns by January 1, 2012 or within 12 months of permit 

issuance pursuant to Paragraph 52.a., whichever is earlier, then, in addition to any 

other remedies available to the United States or the State of Michigan under this 

Consent Decree or other applicable law, the Lafarge Companies shall either: 

i.	 Install and Commence Continuous Operation of the Control Technology 

by January 1, 2015 or within 48 months of permit issuance pursuant to 

Paragraph 52.a, whichever is earlier, and thereafter comply with the 

Control Technology and other applicable requirements of Paragraph 50 as 

to the existing Alpena Kilns; or 

ii.	 Retire the Kiln(s) by July 1, 2012 or within 18 months of permit issuance 

pursuant to Paragraph 52.a, whichever is earlier; 

d.	 Commence Kiln Operation of the Replacement Kiln(s) within 42 months of the 

date on which the Lafarge Companies commence construction of the Replacement 

Kiln, or January 1, 2015, whichever is earlier; 

e.	 Retire the Replaced Kiln(s) within 180 Days of commencement of Kiln Operation 

of the Replacement Kiln(s); 

f.	 Within 42 months of the date on which the Lafarge Companies commence 

construction of the Replacement Kiln, or January 1, 2015, whichever is earlier, 

install and Commence Continuous Operation of Wet FGD technology designed to 

achieve a Control Efficiency for SO2 of 95% at each Replacement Kiln, as 

compared to an identical Replacement Kiln without Wet FGD technology, at the 

Alpena Facility or, subject to review and approval by U.S. EPA and the Affected 

State pursuant to Section XI (Review and Approval of Submittals), equivalent 

13
alternative SO2 Control Technology that may include but shall not be limited to 

kiln system design, which is individually or collectively designed to achieve a 

Control Efficiency for SO2 equivalent to that of Wet FGD technology designed to 

achieve a Control Efficiency for SO2 of 95% at each Replacement Kiln(s) at the 

Alpena Facility; and 

g.	 Within 180 Days after the Lafarge Companies have commenced Kiln Operation 

of the applicable Replacement Kiln at Alpena, achieve and maintain compliance 

with a 30-Day Rolling Average Emission Limit for SO2 of 1.4 lb/Ton of clinker, 

or the New Source Performance Standard for SO2 for Portland Cement 

Manufacturing Facilities promulgated pursuant to Section 111 of the Act, 

whichever is more stringent, at each Replacement Kiln. 

53. Subject to Paragraph 54 below, within 54 months of the date on which the 

Lafarge Companies commence construction of any Replacement Kiln(s), or January 1, 2016, 

whichever is earlier, the Lafarge Companies shall, at Alpena, achieve and maintain compliance 

with a Facility-Wide 12-Month Rolling Tonnage Limit for SO2 of 5,762 Tons emitted per 12-

month period. 

54. Notification Regarding Alpena Replacement Kiln Compliance Date. If a 

governmental entity's failure to act upon a timely-submitted or supplemented permit or approval 

application submitted pursuant to Paragraph 52.a or the action of any third-party challenging the 

issuance of such permit operates to delay the issuance or effectiveness of a final valid permit or 

approval, thereby impairing the Lafarge Companies’ ability to timely satisfy the implementation 

schedule requirements of Paragraph 52, the Lafarge Companies shall notify, in writing, the U.S. 

EPA and the State of Michigan of any such delay as soon as the Lafarge Companies reasonably 


 

14
88. The limitations on the generation and use of netting credits or offsets set forth in 

Paragraphs 86 do not apply to emission reductions achieved by the Lafarge Companies that are 

surplus to those required under this Consent Decree (“surplus emission reductions”). For 

purposes of this Paragraph, surplus emission reductions are the reduction over and above those 

required under this Consent Decree that result from the Lafarge Companies’ compliance with 

federally enforceable emissions limits that are more stringent than limits imposed under this 

Consent Decree or from the Lafarge Companies’ compliance with emissions limits otherwise 

required under applicable provisions of the Clean Air Act or with an applicable SIP that contains 

more stringent limits than those imposed under this Consent Decree. 

89. Nothing in this Consent Decree is intended to preclude the emission reductions 

generated under this Consent Decree from being considered by U.S. EPA or a State as creditable 

contemporaneous emission decreases for the purpose of attainment demonstrations submitted 

pursuant to § 110 of the Act, 42 U.S.C. § 7410, or in determining impacts on NAAQS, PSD 

increments, or air quality-related values, including visibility in a Class I area. 

90. The Lafarge Companies shall, within 30 Days after the Effective Date, apply to 

the State of Georgia for and upon issuance retire fifty (50) NOx Emission Reduction Credits 

pursuant to Georgia's Emission Reduction Credit Rule Ga. Comp. R. & Regs. R., 391-3-1-.03(13) 

and the Clean Air Act. Lafarge shall thereafter provide notice to U.S. EPA of such retirement 

within 30 Days following receipt from the State of Georgia of confirmation of the retirement. 

X. PERMITS 

91. Where any compliance obligation under this Consent Decree requires the Lafarge 

Companies to obtain a federal, State, or local permit or approval the Lafarge Companies shall 

submit a timely and complete application for such permit or approval and take all other actions 


 

15
necessary to obtain all such permits or approvals, allowing for all legally required processing and 

review including requests for additional information by the permitting or approval authority. 

Except as provided for in Paragraphs 16, 21, 54, and 59, the Lafarge Companies may seek relief 

under the provisions of Section XIV of this Consent Decree (Force Majeure) for any delay in the 

performance of any obligation under this Consent Decree resulting from a failure to obtain, or a 

delay in obtaining, any permit or approval required to fulfill such obligation, if the Lafarge 

Companies have submitted timely and complete applications and have taken all other actions 

necessary to obtain all such permits or approvals and responses to requests for additional 

information. 

92. In addition to having first obtained any required preconstruction permits or other 

approvals pursuant to Paragraph 91, the Lafarge Companies, within 12 months after the 

Commencement of operation of each Control Technology required to be installed, upgraded, or 

operated on a Kiln under this Consent Decree, shall apply to the Affected State to include the 

requirements and limitations enumerated in this Consent Decree in a construction permit or other 

permit or approval (other than a Title V permit) which is federally enforceable, issued under the 

SIP of the Affected State, and issued under authority independent of the Affected State’s 

authority to issue Title V permits. The permit or approval shall require compliance with any 

applicable 30-Day Rolling Average Emission Limit, Facility-Wide 12-Month Rolling Average 

Emission Limit, and any applicable Facility-Wide 12-Month Rolling Tonnage Limit, and any 

monitoring requirements, including those in Sections V.B and VI.B. of this Decree. Following 

submission of the application for the permit or approval, the Lafarge Companies shall cooperate 

with the appropriate permitting authority by promptly submitting all information that such 

permitting authority seeks following its receipt of the application for the permit. 


 

16
 

 

 

CONSENT DECREE APPENDIX 

United States of America et al v. Lafarge North America, Inc., et al. 

Control Technology Demonstration Requirements 

I. Scope and Applicability 

1. The Lafarge Companies1 shall comply with this Appendix in proposing and establishing 30-

Day Rolling Average Emission Limits for Nitrogen Oxide (“NOx”) and Sulfur Dioxide 

(“SO2”) as applicable under Sections V and VI of the Consent Decree for individual kilns at 

Alpena, Sugar Creek, Fredonia, Joppa, Paulding, Ravena, Seattle and Tulsa (Affected Kilns). 

2. The Affected Kilns include kilns of varying type, age, design and operating capacities. Raw 

materials employed in the Affected Kilns vary substantially. Similarly, fuels permitted and 

employed in the Affected Kilns vary by location and can include fuel oil, natural gas, coal, 

petroleum coke, tire-derived fuel, hazardous waste derived fuels, used oils and other 

materials beneficially reused as fuel. The Lafarge Companies shall take the following steps 

to establish 30-Day Rolling Average Emission Limits as required under Sections V and VI 

of the Consent Decree for NOx and/or SO2 at individual Affected Kilns at Alpena, Sugar 

Creek, Fredonia, Joppa, Paulding, Ravena, Seattle and if necessary, Tulsa: 

a. Design Report: The Lafarge Companies shall prepare and submit to U.S. EPA and the 

Affected State a Design Report for each Control Technology required under the Consent 

Decree for each Affected Kiln, except Sugar Creek; 

b.aseline Data Collection:The Lafarge Companies shall collect baseline emission and 

operational data for each Affected Kiln for a 180-Day period prior to initiating operation 

of any Control Technology. The baseline data collection may run concurrently with other 

activities identified within this Appendix; 

c.ptimization Program: Following completion of installation of each Control 

Technology at each Affected Kiln, the Lafarge Companies shall, consistent with the 

requirements of Sections V or VI of the Consent Decree, undertake a startup and 

optimization program for each Control Technology; 

d.Demonstration Program: Upon completion of the startup and optimization program 

specified above, the Lafarge Companies shall operate the Control Technology in an 

optimized manner for a period of 12 months for the purpose of establishing a 30-Day 

Rolling Average Emission Limit for each Affected Kiln; 

e. Final Report: The Lafarge Companies shall prepare and submit to U.S. EPA and the 

Affected State for approval, a Final Report following completion of the 12-month period 

used to establish 30-Day Rolling Average Emission Limits for each Affected Kiln. 

1

 All terms in this Appendix shall be construed consistent with meanings specified in Section III, Definitions, of the 

Consent Decree into which this Appendix is incorporated. 

17
Appendix 9E 

St Mary’s Cement BART 

Technical Analysis 
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Appendix 9F 

St. Mary’s Cement BART Letter 
DRAFT 

BART Compliance Document 

SMC 

St. Mary’s would apply for a permit modification with the limits described below, which 

would be effective December 31, 2012, under two conditions, namely: 

1. DEQ can confirm in writing both that (i) the Emissions Limits below satisfy the 

Michigan BART rules, R 336.1970 and R 336.1971; and that (ii) the limits have 

been set in accordance with and satisfy the federal requirements for BART 

implementation, as detailed in 40 CFR 51.308 and 51.309, as well as 64 FR 35714 

and 70 FR 39104. 

2. The incorporation of these limits into the permit would be conditional on the 

resolution of those matters identified in the Notice of Violation dated September 

29, 2009 from EPA. 

FGKILNRAWMILLS 

Flexible Group Conditions 

I. Emission Limit(s) 

Pollutant Limit Time Period Monitoring 

Method 

NOx 6.5 lbs/Ton 

of clinker 

Effective January 1, 2013, Monthly 

average, as determined at the end of 

each calendar month. 

SC VI.2 SC 

VI.5 

NOx 4400 tons 

per year 

Effective January 1, 2013, 12 month 

rolling time period determined at the 

end of each calendar month 

SC VI.5 

SOx 7.6 lbs/Ton 

of clinker 

Effective January 1, 2013, Monthly 

average, as determined at the end of 

each calendar month. 

SC VI.2 SC 

VI.4 

SOx 3700 tons 

per year 

Effective January 1, 2013, 12 month 

rolling time period determined at the 

end of each calendar month 

SC VI.4 

1

AnnArbor_169566_1 
Appendix 9G 

Emission Limits – Excerpts from ROP for St Mary’s 

Cement Inc. 
FGKILNRAWMILLS 

FLEXIBLE GROUP CONDITIONS

DESCRIPTION: This Flexible Group deals with mixing and grinding, then heating the ingredients to 

make cement. Included are limestone, shale, bottom ash, fly ash, bauxite, mill scales, slags, various 

sands, numerous iron sources, clay, overburden that are ground and mixed in EURAWMILLS. These raw 

materials are then sent to the EUKILN where they are heated and become clinker. 

Emission Units: EURAWMILLS, EUKILN 

POLLUTION CONTROL EQUIPMENT: Baghouse, Electrostatic Precipitator, Selective Non-Catalytic 

Reduction (SNCR) 

I. EMISSION LIMIT(S)

Pollutant Limit Time Period/ Operating 

Scenario 

Equipment Monitoring/ 

Testing 

Method 

Underlying 

Applicable 

Requirements 

1. PM 0.30 lb/ton of 

dry feed2

FGKILNRAWMILLS SC V.1 40 CFR 

63.1343(b)(1) 

2. SO2 2800 lbs/hour2 Hourly, as the average of 

each calendar day’s 

emissions over the time of 

operation. 

FGKILNRAWMILLS SC VI.4, VI.10 R 336.1201(3) 

3. SO2 550 

tons/month2

Calendar month. FGKILNRAWMILLS SC VI.4, VI.10 R 336.1201(3) 

4. SO2 4404 tons/year2 12-month rolling time 

period, as determined at 

the end of each calendar 

month. 

FGKILNRAWMILLS SC VI.4, VI.10 R 336.1201(3) 

5. NOx 6.50 lbs/ton of 

clinker 

produced1

Monthly average, as 

determined at the end of 

each calendar month, from 

May 1 through September 

30. 

FGKILNRAWMILLS SC VI.2, VI.5, 

VI.11 

R 336.1801(4), 

Consent Order 

AQD No. 25-

2006 Paragraph 

10. A.1. 

6. NOx 7.67 lbs/ton of 

clinker 

produced2

Monthly average, as 

determined at the end of 

each calendar month, from 

October 1 through April 30.

FGKILNRAWMILLS SC VI.2, VI.5, 

VI.11 

R 336.1213, 

R 336.1910, 

Consent Order 

AQD No. 25-

2006 Paragraph 

10. A.1. 

7. D/F* 1.7 x 10-10

gr/dscf (TEQ) 

corrected to 7 

percent 

oxygen2#

FGKILNRAWMILLS SC III.4, V.2, 

VI.6, VI.17 

40 CFR 

63.1343(b)(3) 

8. Nickel 

when 

burning 

100% 

petroleum 

coke 

0.36 lb/hour1 FGKILNRAWMILLS SC V.3 R 336.1224, 

R 336.1225 

1
Appendix 9H 

 

Tilden Mining Company BART 

Technical Analysis 
1

West (Tilden) Analysis of Best Available Retrofit Technology (BART)

Table of Contents

1. Executive Summary , v

2. Introduction 1

2.A BART Eligibility 2

2.B BART Determinations :..3

3. Streamlined BART Analysis :..8

3.A Indurating Furnaces 8

3.B PM-Only Taconite MACT EmissionUnits 9

3.C Other CombustionUnits 9

4. Baseline Conditions andVisibility Impacts for BART Eligible Units 12

4.A MDEQ Subject-to-BART Modeling 12

4.B Facility Baseline Modeling 13

4.C Facility Baseline Modeling Results 15

5. BART Analysis for Indurating Furnaces :16

5.A Line 1 Indurating Furnace 16

5.A.i Sulfur Dioxide Controls 17

5.A.i.a STEP 1- Identify All Available Retrofit Control Technologies 17

5.A.i.b STEP 2 - Eliminate Teclmically Infeasible Options 17

5.A.i.c STEP 3 - Evaluate Control Effectiveness ofRemaining Control

Technologies 23

5.A.i.d STEP 4 - Evaluate Impacts and Document the Results 23

5.A.i.e STEP 5 - Evaluate Visibility Impacts 26

5.A.ii Nitrogen Oxide Controls : 33

5.A.ii.a STEP 1- Identify All Available Retrofit Control Technologies 33

5.A.ii.b STEP i-Eliminate Technically Infeasible Options ·33

5.A.ii.c STEP 3 - Evaluate Control Effectiveness ofRemaining Control

Technologies 46

5.A.ii.d STEP 4 - Evaluate Impacts and Document the Results .46

5.A.ii.e STEP 5 - Evaluate Visibility Impacts 49

5.B Process Boilers 1 and 2 .55

5.B.i Sulfur Dioxide Controls: 55

5.B.i.a STEP 1 - Identify All Available Retrofit Control Technologies 55

5.B.i.b STEP 2 - Eliminate Technically Infeasible Options 55

5.B.i.c STEP 3-Evaluate Control Effectiveness ofRemaining Control

Technologies 59

5.B.i.d STEP 4 - Evaluate Impacts and Document the Results 59

5.B.i.e STEP 5 - Evaluate Visibility Impacts 61

5.B.ii Nitrogen Oxide Controls 62

5.B.ii.a STEP 1 - Identify All Available Retrofit Control Technologies 62

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5.B.ii.b STEP 2 Eliminate TeclmicallyInfeasible Options ..; 62

5.B.ii.c STEP 3 - Evaluate Control Effectiveness ofRemaining Control

Teclmologies 70

5.B.ii.d STEP 4 - Evaluate Impacts and Document the Results 71

5.B.ii.e STEP 5 - Evaluate Visibility Impacts 73

5.C Line I Dryer 81

5.C.i Sulfur Dioxide Controls 81

5.C.i.a STEP 1-IdentifY All Available Retrofit ControI.Teclmologies 81

5.C.i.b STEP 2 - Eliminate Teclmically Infeasible Options 81

5.C.i.,,- STEP3 - Evaluate Control Effectiveness ofRemaining Control

Teclmologies 87

5.C.i.d STEP 4- Evaluate Impacts and Document the Results 87

5.A.ii.f STEP 5 - Evaluate Visibility Impacts 89

5.C.ii Nitrogen Oxide Controls 90

5.C.ii.a STEP 1 - IdentifY AllAvailable Retrofit Control Teclmologies 90

5.C.ii.b STEP 2 - Eliminate Teclmically Infeasible Options 90

5.C.ii.c STEP 3 - Evaluate Control Effectiveness ofRemaining Control

Teclmologies 98

5.C.ii.d STEP 4 - Evaluate Impacts and Document the Results 99

5.C.ii.e STEP 5 - Evaluate Visibility Impacts 101

6. Visibility Impacts 111

6.A Post-Control Modeling Scenarios 111

6.B Post-Control Modeling Results 111

7. Select BART 128

List of Tables

Table 3-1 Summary Table ofBART-Eligible Units Subject to a Streamlined BART Analysis 11

Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data 14

Table 4-2

Table 5-1

Table 5-2

Table 5-3

Table 5-4

Table 5-5

Table 5-6

Table 5-7

Table 5-8

Table 5-9

Baseline Visibility Modeling Results :: 15

Indurating Furnace S02 Control Teclmology - Availability, Applicability, and

Teclmical Feasibility 22

Indurating Furnace S02 Control Teclmology Effectiveness , 23

Indurating Furnace S02 Control Cost Summary 24

S02 Control Teclmology Impacts Assessment.. 25

Post-Control Modeling Scenarios 27

Post-Control S02 Modeling Scenarios - Modeling Input Data 29

Post-Control S02 Modeling Scenarios - Visibility Modeling Results 31

Post-Control S02 Modeling Scenarios - Visibility Improvements , 32

Indurating Furnace NOx Control Technology - Availability, Applicability, and

Teclmical Feasibility 45

11

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Table 5-30

Table 5-31

Table 5-32

. Table 5-18

Table 5-219

Table 5-20

Table 6-1

Table 6-2

Table 6-3

Table 6-4

Table 6-5

Table 5-21

Table 5-22

Table 5-23

Table 5-27

Table 5-28

Table 5-29

Table 5-30

Table 5-I0 Indurating Furnace NOx Control Technology Effectiveness --46

Table 5-I I Indurating Furnace NOx Control Cost Summary .....................................................•...47

Table 5-12 NOx Control Technology Impacts Assessment.. .48

Table 5-13 Post-Control NOx Modeling Scenarios...................................................................•...50

Control Scenario 50

Table 5-14 Post-Control NOx Modeling Scenarios - Modeling Input Data 52

Table 5-15 Post-Control NOx Modeling Scenarios - Visibility Modeling Results 53

Table 5-16 Post-Control NOx Modeling Scenarios - Visibility Improvements 54

Table 5-17 Process Boiler S02 Control Technology-Availability, Applicability, and Technical

Feasibility 59

Process Boiler S02 Control Technology Effectiveness .59

Process Boilers 1 and 2 S02 Control Cost Summary 60

Process Boilers 1 and 2 NO, Control Technology - Availability, Applicability and

Technical Feasibility 70

Backup Process Boiler NOx Control Technology Effectiveness 71

Process Boiler NOx Control Cost Summary , 72

Process Boiler NO, Control Technology - Other Impacts Assessment 73

Process Boiler Post-BART Modeling Scenarios 75

Process Boiler Post-BART NO, Modeling Scenarios - Modeling Input Data 78

Process Boiler Post-BART NO, Modeling Scenarios - Visibility Modeling Results 79

Process Boiler Post-BART NO, Modeling Scenarios - Comparison ofVisibility

Modeling Results to Baseline Modeling Results , 80

Table 5-29 Line 1 Dryer S02 Control Technology - Availability, Applicability, and Technical

Feasibility 87

Line I Dryer S02 Control Technology Effectiveness 87

Line I Dryer SO, Control Cost Summary 88

Line 1 Dryer NOx Control Technology - Availability, Applicability and Technical

Feasibility .......................................................................................................•..........98

Line 1 Dryer NOx Control Technology Effectiveness 99

Backup Process Boiler NO, Control Cost Summary 100

Line 1 Dryer NO, Control Technology - Other Impacts Assessment.. 101

Process Boiler Post-BART Modeling Scenarios 103

Process Boiler Post-BART NO, Modeling Scenarios - Modeling Input Data I08

Process Boiler Post-BART NO, Modeling Scenarios - Visibility Modeling Results .. 109

Process Boiler Post-BART NO, Modeling Scenarios - Comparison of Visibility

Modeling Results to Baseline Modeling Results 110

Post-Control Modeling Scenarios I 13

Post-Control NOx Modeling Scenarios - Modeling Input Data I 18

Post-Control Modeling Scenarios - Visibility Modeling Results I 19

Post-Control Modeling Scenarios - Visibility Modeling Results 120

Post-Control Modeling Results - Dollars per Deciview Improvement.. 121

Table 5-33

Table 5-34

Table 5-35

Table 5-36

Table 5-37

Table 5-38

Table 5-39

111

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Appendix A

AppendixB

Appendix C

AppendixD

AppendixE

AppendixF

List of Appendices

Control Cost Analysis Spreadsheets

Changes to MDEQ BART Modeling Protocol

Visibility Impacts Modeling Report

Applicable and Available Retrofit Teclrnologies

Clean Air Interstate Rule (CAIR), Cost-Effective Air Pollution Controls

BART Analysis Procedure and Streamlined BART Approach

IV

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v

1. Executive Summary 

DRAFT LANGUAGE 

Tilden Mining Company LC (Tilden) owns and operates an iron mining facility near Ishpeming, 

Michigan in Marquette County. This report describes the background and methods for the selection 

of the Best Available Retrofit Technology (BART) as proposed by Tilden for its taconite processing 

plant located near Ishpeming, MI. 

Michigan Department of Environmental Quality (MDEQ) identified the six pieces of equipment that 

were installed within the time window (1962-1977) that makes them subject to BART. The 

equipment includes Line 1 Kiln, Dryer, Cooler, Primary Crusher, and Process Boilers 1 and 2. Line 

1 Kiln is permitted for natural gas, coal and fuel oil and Line 1 Dryer, Process Boilers 1 and 2 are 

permitted for natural gas and fuel oil. Preliminary visibility modeling conducted by the MDEQ 

found that air emissions from Tilden’s facility “cause or contribute to visibility impairment” in a 

federally protected Class I area, therefore making the facility subject to BART. 

Guidelines included in 40 CFR §51 Appendix Y were used to propose BART for the subject units. 

The existing pollution control equipment includes wet scrubbers on the dryer, cooler, and primary 

crusher, which are designed to control particulate matter (PM). The wet scrubber on the dryer will, 

however, experience some collateral control of sulfur dioxide (SO2). The kiln PM is controlled with 

an electrostatic precipitator (dry). A dispersion modeling sequence of CALMET, CALPUFF, and 

CALPOST was used to assess the visibility impacts of the baseline emissions and after the 

application of candidate BART controls. Visibility impacts were evaluated in the selection of BART. 

Other criteria that the BART rules require to be considered include the availability of technology, 

costs of compliance, energy and environmental impacts of compliance, existing pollution control 

technology in use at the source, and the remaining useful life of the source. 

Based on consideration of all of the above criteria, Tilden proposes the following as BART: 

Line 1 Kiln 

• SO2 emissions of 28,000 lb per day for Line 1 when coal is burned 

• NOx limit as specified in Appendix 2 Schedule of Compliance in the Renewable Operating 

Permit 199600379 and with Rule 336.1801. 

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vi

• PM emissions will be controlled as prescribed by the taconite maximum achievable control 

technology (MACT) standard1. 

Line 1 Cooler 

• PM emissions will be controlled as prescribed by the taconite maximum achievable control 

technology (MACT) standard2. 

Boilers 1 and 2 

• SO2 emissions limit is regulated by limiting the sulfur content to 1.2% by weight, calculated 

on the basis on 18,000 BTU per pound when used oil is burned. 

• NOx is good combustion practices 

• PM emissions will be controlled as prescribed by the taconite maximum achievable control 

technology (MACT) standard3. 

Line 1 Dryer 

• SO2 emissions limit is regulated by limiting the sulfur content to 1.5% by weight, calculated 

on the basis on 18,000 BTU per pound when used oil is burned NOx emissions will be 

controlled 

• NOx is good combustion practices 

• PM emissions will be controlled as prescribed by the taconite maximum achievable control 

technology (MACT) standard4. 

Primary Crusher 

 

1

 40 CFR Subpart 63 RRRRR-NESHAPS: Taconite Iron Ore Processing 

2

 40 CFR Subpart 63 RRRRR-NESHAPS: Taconite Iron Ore Processing 

3

 40 CFR Subpart 63 RRRRR-NESHAPS: Taconite Iron Ore Processing 

4

 40 CFR Subpart 63 RRRRR-NESHAPS: Taconite Iron Ore Processing 

6
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vii

• PM emissions will be controlled as prescribed by the taconite maximum achievable control 

technology (MACT) standard5. 

CALPUFF model is conservative, resulting in an over prediction of impacts. This modeled high 

impact from the BART eligible sources is 0.72 dV, which is below perceptible levels of one to two 

dV. Real impacts to the Class I areas from Tilden are expected to be even less than these modeled 

impacts. 

 

5

 40 CFR Subpart 63 RRRRR-NESHAPS: Taconite Iron Ore Processing 

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1

2. Introduction 

Tilden Mining Company LC (Tilden) owns and operates an iron mining facility near Ishpeming, 

Michigan in Marquette County. This report describes the background and methods for the selection 

of the Best Available Retrofit Technology (BART) as proposed by Tilden for its taconite processing 

plant also located near Ishpeming, MI. 

To meet the Clean Air Act’s requirements, the U.S. Environmental Protection Agency (U.S. EPA) 

published regulations to address visibility impairment in our nation’s largest national parks and 

wilderness (“Class I”) areas in July 1999. This rule is commonly known as the “Regional Haze 

Rule” [64 Fed. Reg. 35714 (July, 1999) and 70 Fed. Reg. 39104 (July 6, 2005)] and is found in 40 

CFR part 51, in 51.300 through 51.309. 

Within its boundary, Michigan has two Class I areas – the Isle Royale National Park (IRNP) and 

Seney Wilderness Area. By December 2007, MDEQ must submit to U.S. EPA a Regional Haze 

State Implementation Plan (SIP) that identifies sources that cause or contribute to visibility 

impairment in these areas. The Regional Haze SIP must also include a demonstration of reasonable 

progress toward reaching the 2018 visibility goal for each of the state’s Class I areas. 

One of the provisions of the Regional Haze Rule is that certain large stationary sources that were put 

in place between 1962 and 1977 must conduct a Best Available Retrofit Technology (BART) 

analysis. The purpose of the BART analysis is to analyze available retrofit control technologies to 

determine if a technology should be installed to improve visibility in Class I areas. The chosen 

technology is referred to as the BART controls, or simply BART. The SIP must require BART on all 

BART-eligible sources and mandate a plan to achieve natural background visibility by 2064. The SIP 

must also include milestones for establishing reasonable progress towards the visibility improvement 

goals and plans for the first five-year period. Upon submission of the Regional Haze SIP, states must 

make the requirements for BART sources enforceable through rules, administrative orders or Title V 

permit amendments. 

By U.S. EPA’s definition, reasonable progress means that there is no degradation of the 20 bestvisibility days, and the 20 worst-visibility days must have no more visibility impairment than the 20 

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worst days under natural conditions by 2064.6 Assuming a uniform rate of progress, the default glide 

path would require 1 to 2 percent improvement per year in visibility on the 20 worst days. The state 

must submit progress reports every five years to establish their advancement toward the Class I area 

natural visibility backgrounds. If a state feels it may be unable to adopt the default glide path, a 

slower rate of improvement may be proposed on the basis of cost or time required for compliance and 

non-air quality impacts. 

Note that the improvements required under the Regional Haze regulations are different from the 

BART requirements. Facilities subject to BART are not required to make all of the reasonable 

progress towards improving regional haze in Class I areas. Rather, BART is but one of many 

measures which states may rely upon in making “reasonable progress” towards regional haze 

improvement goals. 

2.A BART Eligibility 

BART eligibility is established on the basis on three criteria. In order to be BART-eligible, sources 

must meet the following three conditions: 

1. Contain emission units in one or more of the 26 listed source categories under the PSD rules 

(e.g., taconite ore processing plants, fossil-fuel-fired steam electric plants larger than 250 

MMBtu/hr, fossil-fuel boilers larger than 250 MMBtu/hr, petroleum refineries, coal cleaning 

plants, sulfur recovery plants, etc.); 

2. Were in existence on August 7, 1977, but were not in operation before August 7, 1962; 

3. Have total potential emissions greater than 250 tons per year for at least one visibilityimpairing pollutant from the emission units meeting the two criteria above. 

Under the BART rules, large sources that have previously installed pollution-control equipment 

required under another standard (e.g., MACT, NSPS and BACT) will be required to conduct 

visibility analyses. Installation of additional controls may be required to further reduce emissions of 

visibility impairing pollutants such as PM, PM10, PM2.5, SO2, NOx, and possibly Volatile Organic 

Compounds (VOCs) and ammonia. Sources built before the implementation of the Clean Air Act 

(CAA), which had previously been grandfathered, may also have to conduct such analyses and 

 

6

 70 FR No. 178 pp. 39104 to 39172. 

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possibly install controls, even though they have been exempted to date from any other CAA 

requirements. 

Once BART eligibility is determined, a source must then determine if it is “subject to BART.” A 

source is subject to BART if emissions “cause or contribute” to visibility impairment at any Class I 

area. Visibility modeling conducted with CALPUFF or another U.S. EPA -approved visibility model 

is necessary to make a definitive visibility impairment determination (>0.5 deciviews). Sources that 

do not cause or contribute to visibility impairment are exempt from BART requirements, even if they 

are BART-eligible. 

2.B BART Determinations 

Each source that is subject to BART must determine BART on a case-by-case basis. Even if a source 

was previously part of a group BART determination, individual BART determinations must be made 

for each source. The BART analysis takes into account six criteria and is analyzed using five steps. 

The six criteria that comprise the engineering analysis include: the availability of the control 

technology, existing controls at a facility, the cost of compliance, the remaining useful life of a 

source, the energy and non-air quality environmental impacts of the technology, and the visibility 

impacts.7 The five steps of a BART analysis are: 

Step 1 - Identify all Available Retrofit Control Technologies 

The first step in the analysis is to identify all retrofit control technologies which are 

generally available for each applicable emission unit. Available retrofit control 

technologies are defined by U.S. EPA in Appendix Y to Part 51 (Guidelines for BART 

Determinations under the Regional Haze Rule) as follows: 

Available retrofit technologies are those air pollution control technologies 

with a practical potential for application to the emissions unit and the 

regulated pollutant under evaluation. Air pollution control technologies can 

include a wide variety of available methods, systems, and techniques for 

control of the affected pollutant. Technologies required as BACT or LAER 

are available for BART purposes and must be included as control 

alternatives. The control alternatives can include not only existing controls 

for the source category in question, but also take into account technology 

transfer of controls that have been applied to similar source categories or gas 

 

7

 40 CFR 51 Appendix Y 

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streams. Technologies which have not yet been applied to (or permitted for) 

full scale operations need not be considered as available; we do not expect 

the source owner to purchase or construct a process or control device that 

has not been demonstrated in practice.8

Step 2 - Eliminate Technically Infeasible Options 

In the second step, the source-specific technical feasibility of each control option 

identified in step one is evaluated by answering three specific questions: 

a. Is the control technology “available” to the specific source which is undergoing the 

BART analysis? 

The U.S. EPA states that a control technique is considered “available” to a specific 

source “if it has reached the stage of licensing and commercial availability.9” 

However, the U.S. EPA further states that they “do not expect a source owner to 

conduct extended trials to learn how to apply a technology on a totally new and 

dissimilar source type.10” 

b. Is the control technology an “applicable technology” for the specific source which 

is undergoing the BART analysis? 

In general, a commercially available control technology, as defined in question 1, 

“will be presumed applicable if it has been used on the same or a similar source 

type.11” If a control technology has not been demonstrated on a same or a similar 

source type, the technical feasibility is determined by “examining the physical and 

chemical characteristics of the pollutant-bearing stream and comparing them to the 

gas stream characteristics of the source types to which the technology has been 

applied previously.12” 

c. Are there source-specific issues/conditions that would make the control technology 

not technically feasible? 

 

8

 Federal Register 70, No. 128 (July 6, 2005): 39164 

9

 Federal Register 70, No. 128 (July 6, 2005): 39165 

10 IBID 

11 IBID 

12 IBID 

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This question addresses specific circumstances that “preclude its application to a 

particular emission unit.” This demonstration typically includes an “evaluation of 

the characteristics of the pollutant-bearing gas stream and the capabilities of the 

technology13.” This also involves the identification of “irresolvable technical 

difficulties.” However, when the technical difficulties are merely a matter of 

increased cost, the technology should be considered technically feasible and the 

technological difficulty evaluated as part of the economic analysis14. 

It is also important to note that vendor guarantees can provide an indication of 

technical feasibility but the U.S. EPA does not “consider a vendor guarantee alone 

to be sufficient justification that a control option will work.” Conversely, the U.S. 

EPA does not consider the absence of a vendor guarantee to be a “sufficient 

justification that a control option or emission limit is technically infeasible”. In 

general, the decisions on technical feasibility should be based on a combination of 

the evaluation of the chemical and engineering analysis and the information from 

vendor guarantees15. 

Step 3 - Evaluate Control Effectiveness 

In step three, the remaining controls are ranked based on the control efficiency at the 

expected emission rate (post-control) as compared to the emission rate before addition 

of controls (pre-BART) for the pollutant of concern. 

Step 4 - Evaluate Impacts and Document Results 

In the fourth step, an engineering analysis documents the impacts of each remaining 

control technology option. The economic analysis compares dollar per ton of pollutant 

removed for each technology. In addition it includes incremental dollar per ton cost 

analysis to illustrate the economic effectiveness of one technology in relation to the 

others. Finally, Step Four includes an assessment of energy impacts and other non-air 

quality environmental impacts. 

Economic impacts were analyzed using the procedures found in the U.S. EPA Air 

Pollution Control Cost Manual – Sixth Edition (EPA 452/B-02-001). Equipment cost 

estimates from the U.S. EPA Air Pollution Control Cost Manual or U.S. EPA’s Air 

 

13 IBID 

14 IBID 

15 IBID 

12
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6

Compliance Advisor (ACA) Air Pollution Control Technology Evaluation Model 

version 7.5 were used. Vendor cost estimates for this project were used when 

applicable. The source of the control equipment cost data are noted in each of the 

control cost analysis worksheets as found in Appendix A. 

Step 5 - Evaluate Visibility Impacts 

The fifth step requires a modeling analysis conducted with U.S. EPA -approved models 

such as CALPUFF. The modeling protocol16, including receptor grid, meteorological 

data, and other factors used for this part of the analysis were provided by the Michigan 

Department of Environmental Quality (MDEQ). The model outputs, including the 98th 

percentile dV value and the number of days the facility contributes more than a 0.5 

deciview (dV) of visibility impairment at each of the Class I areas, are used to establish 

the degree of improvement that can be reasonably attributed to each technology. 

The final step in the BART analysis is to select the “best” alternative using the results of steps 1 

through 5. In addition, the U.S. EPA guidance states that the “affordability” of the controls should 

be considered, and specifically states: 

1. Even if the control technology is cost effective, there may be cases where the installation 

of controls would affect the viability of plant operations. 

2. There may be unusual circumstances that justify taking into consideration the conditions 

of the plant and the economic effects requiring the use of a given control technology. 

These effects would include effects on product prices, the market share, and profitability 

of the source. Where there are such unusual circumstances that are judged to affect 

plant operations, you may take into consideration the conditions of the plant and the 

economic effects of requiring the use of a control technology. Where these effects are 

judged to have severe impacts on plant operations you may consider them in the selection 

process, but you may wish to provide an economic analysis that demonstrates, in 

sufficient detail for public review, the specific economic effects, parameters, and 

reasoning. (We recognize that this review process must preserve the confidentiality of 

sensitive business information). Any analysis may also consider whether competing 

 

16 Single Source Modeling to Support Regional Haze BART Modeling Protocol, March 21, 2006, Lake Michigan Air Directors 

Consortium. 

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plants in the same industry have been required to install BART controls if this 

information is available.17

To complete the BART process, the analysis must “establish enforceable emission limits that reflect 

the BART requirements and requires compliance within a reasonable period of time18.” Those limits 

must be developed for inclusion in the state implementation plan (SIP) that is due to U.S. EPA in 

December of 2007. In addition, the analysis must include requirements that the source “employ 

techniques that ensure compliance on a continuous basis19.” which could include the incorporation of 

other regulatory requirements for the source, including Compliance Assurance Monitoring (40 CFR 

64), Periodic Monitoring (40 CFR 70.6(a)(3)) and Sufficiency Monitoring (40 CFR 70(6)(c)(1)). If 

technological or economic limitations make measurement methodology for an emission unit 

infeasible, the BART limit can “instead prescribe a design, equipment, work practice, operation 

standard, or combination of these types of standards20.” 

Compliance with the BART emission limits will be required within 5 years of U.S. EPA approval of 

the Michigan SIP. 

 

17 40 CFR 51 Appendix Y. Page 361. 

18 40 CFR 51 Appendix Y. Page 368. 

19 40 CFR 51 Appendix Y. Page 369. 

20 40 CFR 51 Appendix Y. Page 368. 

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3. Streamlined BART Analysis 

Within the preamble to the final federal BART rule, U.S. EPA explicitly encouraged states to include 

a streamlined approach for BART analyses21. The streamlined approach will allow both states and the 

facilities to focus their resources on the main contributors to visibility impairment. This section of 

the report follows the MDEQ-approved streamlined BART analysis for taconite facilities and 

presents the results of the streamlined approach in Table 3-1. 

3.A Indurating Furnaces 

The indurating furnaces are sources of three visibility impairing pollutants: NOx, SO2, and PM. 

Relative to NOx and SO2, PM is not a major visibility impairing pollutant. Further, the indurating 

furnaces are subject to the taconite MACT standard22 for the PM emissions. MDEQ requested that 

Tilden submit a BART analysis approach August 31, 2006. Tilden submitted both the BART 

Analysis Procedures and Streamlined BART Approach on August 29, 2006. Tilden has performed the 

BART analysis as outlined in the August 29, 2006 submittals. The BART Analysis Procedures and 

Streamlined BART Approach dated August 29, 2006 is included in Appendix F for reference. 

The approach, as outlined in the August 29, 2006 Streamlined BART Approach, relies on MACT 

standards to represent BART level of control for those visibility impairing pollutants addressed by 

the MACT standard unless there are new technologies subsequent to the MACT standard, which 

would lead to cost-effective increases in the level of control. Specifically in 40 CFR Part 51 

Appendix Y paragraph IV.C., it states: 

For VOC and PM sources subject to MACT standards, States may streamline the analysis by 

including a discussion of the MACT controls and whether any major new technologies have 

been developed subsequent to the MACT standards. We believe that there are many VOC and 

PM sources that are well controlled because they are regulated by the MACT standards, 

which EPA developed under CAA section 112. For a few MACT standards, this may also be 

true for SO2. Any source subject to MACT standards must meet a level that is as stringent as 

the best-controlled 12 percent of sources in the industry. Examples of these hazardous air 

pollutant sources which effectively control VOC and PM emissions include (among others) 

secondary lead facilities, organic chemical plants subject to the hazardous organic NESHAP 

 

21 Federal Register 70, no. 128 (July 6, 2005): 39107 and 39116 

22 40 CFR Subpart 63 RRRRR-NESHAPS: Taconite Iron Ore Processing 

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(HON), pharmaceutical production facilities, and equipment leaks and wastewater 

operations at petroleum refineries. We believe that, in many cases, it will be unlikely that 

States will identify emission controls more stringent than the MACT standards without 

identifying control options that would cost many thousands of dollars per ton. Unless there 

are new technologies subsequent to the MACT standards which would lead to cost effective 

increases in the level of control, you may rely on the MACT standards for purposes of 

BART. (emphasis added)

It is clear from EPA’s guidance that they are encouraging states to develop a streamlined BART 

analysis approach for sources regulated under a MACT. Since the Taconite MACT standard was 

established very recently and becomes effective in 2006, the technology analysis is up-to-date. As a 

result, BART will be presumed to be equivalent to MACT for PM. 

A full BART analysis will be conducted for NOx and SO2 where applicable. 

3.B PM-Only Taconite MACT Emission Units 

In addition to the indurating furnaces, the taconite MACT standard also regulates PM emissions from 

Ore Crushing and Pellet Cooler operations. These sources operate near ambient temperature, only 

emit PM, and do not emit NOx or SO2. The Ore Crushing source operates with control equipment to 

meet the applicable MACT limits (0.008 gr/dscf for existing sources and 0.005 gr/dscf for new 

sources). The Pellet Cooler sources are excluded from additional control under the MACT standard 

due to the large size of the particles and the relatively low concentration of particle emissions [FR, 

December 18, 2002, page 77570]. Therefore, the emissions from the pellet coolers are considered to 

have a negligible impact on visibility impairment, and no control requirements under the MACT 

standard is consistent with the intention of the BART analysis. 

Since the MACT standard was established recently and became effective in October 31, 2006, the 

technology analysis is up-to-date. Again, for these units subject to a MACT standard, BART will be 

presumed to be equivalent to MACT according to Streamlined BART Procedures submitted to 

MDEQ August 29, 2006. 

No further analysis will be required to establish BART for these sources. 

3.C Other Combustion Units 

The combustion units are sources of three visibility impairing pollutants: NOx, SO2, and PM. 

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Tilden facility has two process boilers that are subject to the boiler MACT23. Since the boiler MACT 

standards were established recently and become effective in 2007, the technology analysis is up-todate. For the units subject to the boiler MACT standard, BART will be presumed to be equivalent to 

MACT for PM according to Streamlined BART Procedures submitted to MDEQ August 29, 2006 

Similar to the induration furnaces, the dryer is also subject to the Taconite MACT for PM. As a 

result, BART will be presumed to be equivalent to MACT for PM. 

A full BART analysis will be conducted for NOx and SO2 where applicable for the process boilers 

and dryer. 

 

23 40 CFR 63 Subpart DDDDD-NESHAPS: ICI Boilers and Process Heaters 

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Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysi

Emission 

Unit # 

Emission Unit 

Description 

NOx

Max 24-hr 

Actual 

Emissions 

(lbs/day) 

SO2

Max 24-hr 

Actual 

Emissions 

(lbs/day) 

PM10

Max 24-hr 

Actual 

Emissions 

(lbs/day) 

MACT 

PM Emission 

Limit 

(gr/dscf) 

Stack 

Number 

3.A Indurating Furnace 

EUKILN1 Line 1 Indurating Furnace 26208.0 6552.0 4948.5 0.01 magnetite 0.03 hematite 

SVP0051711 

(South) and 

SVP0051981 

(North) 

3.B PM-Only Taconite MACT Emission Units 

EUPRIMARY

CRUSHER Primary Crusher 1 -- -- 25.7 0.008 SVA0011570 

EUCOOLER1 Line 1 Pellet Cooler Exhaust -- -- 5.9 0.008 SVP0025490 

3.C Other Combustion Units 

EUDRYER1 Line 1 Dryer 

88.3 199.2 529.0 0.61 SVP0082951

EUBOILER1 Process Boiler #1 

463.3 1.5 300.0 0.61 SVBLR.STK. T1 

EUBOILER2 Process Boiler #2 

463.3 1.5 300.0 0.61 SVBLR.STK. T1 

1PM – Filterable PM only as measured by U.S. EPA Method 5 including the applicable averaging and grouping provisions, as pres

regulation, effective 10/30/2006.

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4. Baseline Conditions and Visibility Impacts for 

BART Eligible Units 

As indicated in U.S. EPA’s final BART guidance24, one of the factors to consider when determining 

BART for an individual source is the degree of visibility improvement resulting from the retrofit 

technology. The visibility impacts for this facility were estimated using CALPUFF, an U.S. EPA 

approved model recommended for comparing the visibility improvements of different retrofit control 

alternatives. However it is important to note that CALPUFF is a conservative model that over 

estimates real impacts. Therefore, although the CALPUFF baseline modeling results are important to 

comparing control alternatives on a relative basis they are do not accurately predict real impacts. 

The CALPUFF program models how a pollutant contributes to visibility impairment with 

consideration for the background atmospheric ammonia, ozone and meteorological data. 

Additionally, the interactions between the visibility impairing pollutants NOx, SO2, PM2.5, PM10, and 

background ammonia can play a large part in predicting impairment. It is therefore important to take 

a multi-pollutant approach when assessing visibility impacts. 

In order to estimate the visibility improvement resulting from the retrofit technology, the source must 

first be modeled at baseline conditions. Per U.S. EPA guidance, the baseline, or pre-BART 

conditions, shall represent the average emission rate in units of pounds per hour (lbs/hr) and reflect 

the maximum 24-hour actual emissions25. 

4.A MDEQ Subject-to-BART Modeling 

In order to determine which sources are “Subject-to-BART” in the state of Michigan, the MDEQ 

completed modeling of the BART-eligible emission units at various facilities in Michigan in 

accordance with the Regional Haze Rule. The modeling by MDEQ was conducted using CALPUFF, 

as detailed in the “Single Source Modeling to Support Regional Haze BART Modeling Protocol”, 

March 21, 2006, Lake Michigan Air Directors Consortium. The modeling by MDEQ was conducted 

using emission rate information submitted by the facility in the annual emissions reporting. The 

emissions were reported in units of pounds per year and divided by the annual hours per year of 

operation to calculate a pound per hour (lb/hr) emission rate. The lb/hr emission rate was then 

multiplied by 24 hours to calculate the pounds per day (lb/day) emission rate. The lb/day is to reflect 

 

24 Federal Register 70, no. 128 (July 6, 2005): 39106.

25 40 CFR Part 51 Appendix Y 

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13

the maximum actual emissions during a 24-hour period under steady-state operating conditions 

during periods of high capacity utilization. The modeling conducted by MDEQ demonstrated that 

this facility is subject-to-BART as stated in the letter from MDEQ on March 17, 2006 

4.B Facility Baseline Modeling 

Prior to re-creating the MDEQ visibility impairment model, the modeling method was re-revaluated. 

On behalf of Tilden and Empire, Barr Engineering proposed changes to the modeling. In discussions 

with MDEQ, it was indicated that most aspects of the modeling were flexible, so long as the changes 

were documented and appropriate files were included for their review with submittal of results. 

Details of the modifications to the model are included in Appendix B. 

In addition, the maximum 24-hour emission rates were re-evaluated internally within Tilden to verify 

that the emission rates represent the maximum steady-state operating conditions during periods of 

high capacity utilization. The maximum 24-hour emission rates were adjusted to reflect combustion 

of permitted fuels. 

The original baseline emissions were modeled for comparison to MDEQ results. This data is 

summarized in Table 4-1. The full modeling analysis is presented in Appendix C. 

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Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data 

Emissi

on 

Unit 

ID 

Emission 

Unit 

Description 

SO2 

Max. 

24-hr 

Actual 

Emissi

ons 

(lb/day) 

Basis 

for SO2 

24-hr 

Actual 

Emissi

ons 

NOx Max. 

24-hr 

Actual 

Emissions 

(lb/day) 

Basis for 

NOx 24-

hr 

Actual 

Emissio

ns 

PM2.5 

Max. 24-

hr Actual

Emission

s (lb/day) 

Basis 

for 

PM2.5 

24-hr 

Actual 

Emissio

ns 

PM10 

Max. 24-

hr Actual

Emission

s (lb/day) 

Basis 

for 

PM10 

24-hr 

Actual 

Emissio

ns 

Stack 

No. 

Latitud

e Longitude 

Height 

of 

openin

g 

from 

ground 

(ft) 

Ba

Elev

o

o

Gro

(f

3.A Indurating Furnaces 

EUKI

LN1 

Line 1 

Pellet 

Induration 

6552.0 COAL 26,208.0 Nat gas 3,610.1 MACT SVP00 51981 46.440 84994 -87.653 40738 240 14

 1,338.4 MACT SVP00 51711 46.440 75383 -87.651 32336 160 14

3.B PM-Only Taconite MACT Emission Units 

EUP

RIMA

RYCRUSHER 

PRIMARY 

CRUSHER 25.7 MACT SVA00 11570 46.439 33071 -87.651 52770 15 14

EUCOOL

ER 

Line 1 

Cooler 5.9 MACT SVP00 25490 46.439 79916 -87.648 27887 151 14

3.C PM-Only Other Combustion MACT Emission Units 

EUD

RYE

R1 

Line 1 

Dryer 199.2 COAL 88.3 NAT. GAS 529.0 MACT SVP00 82951 46.440 75383 -87.651 32336 119 14

EUB

OILE

R1 

Process 

Boiler #1 1.5 FUEL OIL 463.3 NAT. GAS 300.0 MACT SVBLR .STK.T 1 46.440 91784 -87.654 12418 130 14

EUB

OILE

R2 

Process 

Boiler #2 1.5 FUEL OIL 463.3 NAT. GAS 300.0 MACT SVBLR .STK.T 1 46.440 91784 -87.654 12418 130 14

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4.C Facility Baseline Modeling Results 

The Michigan BART modeling protocol26 describes the CALPUFF model inputs, including the 

meteorological data set and background atmospheric ammonia and ozone concentrations, along with 

the functions of the CALPOST post processing. The CALPOST output files provide the following 

two methods to assess the expected post-control visibility improvement: 

• 98th Percentile: As defined by federal guidance, a source "contributes to visibility 

impairment” if the 98th percentile of any year’s modeling results (i.e. 7th highest day) meets 

or exceeds the threshold of five-tenths (0.5) of a deciview (dV) at a Federally protected Class 

I area receptor. 

• Number of Days Exceeding 0.5 dV: The severity of the visibility impairment contribution, or 

reasonably attributed visibility impairment, can be gauged by assessing the number of days 

on which a source exceeds a visibility impairment threshold of 0.5 dV. 

A summary of the baseline visibility modeling is presented in Table 4-2. As illustrated in the table, 

this facility is considered to contribute to visibility impairment in Class I areas because the modeled 

98th percentile of the baseline conditions exceeds the threshold of 0.5 dV. The results of this 

modeling are also utilized in the post-control modeling analysis in section 6 of this document. The 

full modeling analysis is presented in Appendix C. 

Table 4-2 Baseline Visibility Modeling Results 

2002 2003 2004 

2002 – 2004 

Combined 

Class I Area 

with 

Greatest 

Impact 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of 

days 

exceeding 

0.5 

deciview 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of 

days 

exceeding 

0.5 

deciview 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of 

days 

exceeding 

0.5 

deciview 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of 

days 

exceeding 

0.5 

deciview 

IRNP 0.714 19 0.722 11 0.599 11 0.674 41 

 

26 Single Source Modeling to Support Regional Haze BART Modeling Protocol, March 21, 2006, Lake Michigan Air Directors 

Consortium. Page 3. 

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5. BART Analysis for Indurating Furnaces 

As presented in section 3 and Table 3-1, the following sources at Tilden require a full BART analysis 

for SO2 and NOx: 

 Line 1 Indurating Furnace; 

 Process Boilers 1 and 2; and 

 Line 1 Dryer. 

The BART analyses for these sources are presented in sections 5.A, 5.B, and 5.C, respectively. 

5.A Line 1 Indurating Furnace 

The primary function of taconite indurating furnaces is to convert magnetic or hematite iron 

concentrate to a more highly oxidized iron in the form of a pellet that is sold to metallic iron and 

steel production facilities. “Soft” or “green” pellets are oxidized and heat-hardened in the induration 

furnace. The induration process involves pellet pre-heating, drying, hardening, oxidation and cooling. 

The process requires large amounts of air for pellet oxidation and cooling. Process temperature 

control in all parts of the furnace is critical to minimize product breakage in the initial process stages, 

allow required oxidation reactions to occur, and adequately cool the product prior to subsequent 

handling steps. Directed air flow, heat recovery and fuel combustion are critical to controlling 

temperature and product quality in all parts of the furnace. 

The Line 1 Indurating Furnace is a grate/kiln furnace, in which the pellets are dried on a grate and 

then transferred to a rotary kiln for hardening and oxidation. The pellet hardening and oxidation 

section of the induration furnace is designed to operate at 2,400 oF and higher. This temperature is 

required to meet taconite pellet product specifications. Direct-fired fuel combustion in the induration 

furnace is carried out at 300% to 400% excess air to provide sufficient oxygen for pellet oxidation. 

Air is used for combustion, pellet cooling, and as a source of oxygen for pellet oxidation. Due to the 

high-energy demands of the induration process, induration furnaces have been designed to recover as 

much heat as possible using hot exhaust gases to heat up incoming pellets. Pellet drying and preheat 

zones are heated with the hot gases generated in the pellet hardening/oxidation section and the pellet 

cooler sections. Each of these sections is designed to maximize heat recovery within process 

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constraints. The pellet coolers are also used to preheat combustion air so more of the fuel’s energy is 

directed to the process instead of heating ambient air to combustion temperatures. 

Tilden has two grate/kiln furnaces, Line 1 and Line 2. Line 1 is subject-to-BART and Line 2 is not 

subject to BART because Line 2 was installed outside the BART applicability time window. Line 1 is 

permitted to burn natural gas, coal and fuel oil. Line 1 is controlled by an electrostatic precipitator 

(ESP). The ESP is designed to remove PM and would be considered a high efficiency PM ESP Kiln 

1 has a PM limit of 0.065 per 1000 pounds of exhaust gas and 200 pounds per hour. NOx is 

controlled through furnace design and type of fuel usage. During high ozone alert days, coal is 

burned to reduce the amount of NOx generation. The SO2 is controlled through furnace design and 

type of fuel usage. Kiln 1 has a SO2 limit of 28,000 lbs per day. 

5.A.i Sulfur Dioxide Controls 

There are two sources of SO2 emissions from the Line 1 Indurating Furnace: 

1. SO2 emissions from the trace amounts of sulfur in the iron concentrate and binding agents 

present in the green balls; and 

2. SO2 emission from the sulfur in distillate fuel oil and coal, which are the permitted fuels. 

5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies 

See Appendix D for a comprehensive list of all potential retrofit control technologies that were 

evaluated. Many emerging technologies have been identified that are not currently commercially 

available. A preliminary list of technologies was submitted to MDEQ on October 6, 2006 with the 

status of the technology as it was understood at that time. Appendix D presents the current status of 

the general availability of each technology. 

5.A.i.b STEP 2 – Eliminate Technically Infeasible Options 

Step 1 identified the available and applicable technologies for SO2 emission reduction. Within 

Step 1, the technical feasibility of the control option was also discussed and determined. The 

following describes retrofit SO2 control technologies that were identified as available and applicable 

in the original submittal and discusses aspects of those technologies that determine whether or not 

the technology is technically feasible for indurating furnaces. 

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Wet Walled Electrostatic Precipitator (WWESP) 

An ESP applies electrical forces to separate suspended particles from the flue gas stream. The 

suspended particles are given an electrical charge by passing through a high voltage DC corona 

region in which gaseous ions flow. The charged particles are attracted to and collected on oppositely 

charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers 

for collection and removal. 

A wet walled electrostatic precipitator (WWESP) operates on the same collection principles as a dry 

ESP and uses a water spray to remove particulate matter from the collection plates. For SO2 removal, 

caustic is added to the water spray system, allowing the WWESP spray system to function as an SO2

absorber. 

The SO2 control efficiency for a WWESP is dependent upon various process specific variables, such 

as SO2 flue gas concentration, fuel used, and ore composition. Tilden currently employs an ESP 

designed for removal of particulate matter. The existing ESP does not have the capacity to handle 

the additional loading of sulfate particulates. To add a WWESP to the process, it would be necessary 

to install it in series with the existing ESP. A control efficiency of a WWESP ranges from 30-80% 

dependent upon the process specific operating parameters. 

Based on the information contained within this report, a WWESP is considered a technically feasible 

technology for SO2 reduction for this BART analysis. 

Wet Scrubbing (High and Low Efficiency) 

Wet scrubbing, when applied to remove SO2, is generally termed flue-gas desulfurization (FGD). 

FGD utilizes gas absorption technology, the selective transfer of materials from a gas to a contacting 

liquid, to remove SO2 in the waste gas. Crushed limestone, lime, or caustic are used as scrubbing 

agents. Most wet scrubbers recirculate the scrubbing solution, which minimizes the wastewater 

discharge flow. However, higher concentrations of solids exist within the recirculated wastewater. 

For a wet scrubber to be considered a high efficiency SO2 wet scrubber, the scrubber would require 

designs for removal efficiency up to 95% SO2. Typical high efficiency SO2 wet scrubbers are packedbed spray towers using a caustic scrubbing solution. Whereas, a low efficiency SO2 wet scrubber 

could have a control efficiency of 30% or lower. A low efficiency SO2 scrubber could be a venturi 

rod scrubber design using water as a scrubbing solvent. Venturi rod scrubbers, which are frequently 

used for PM control at taconite facilities, will also remove some of the SO2 from the flue gas as 

collateral emission reduction. 

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Limestone scrubbing introduces limestone slurry with the water in the scrubber. The sulfur dioxide is 

absorbed, neutralized, and partially oxidized to calcium sulfite and calcium sulfate. The overall 

reactions are shown in the following equations: 

CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2

CaSO3 •1/2 H2O + 3H2O + O2 → 2 CaSO4 •2 H2O 

Lime scrubbing is similar to limestone scrubbing in equipment and process flow, except that lime is a 

more reactive reagent than limestone. The reactions for lime scrubbing are as follows: 

Ca(OH)2 +SO2 → CaSO3• 1/2 H2O + 1/2 H2O 

Ca(OH)2 + SO2 + 1/2 O2 + H2O → CaSO4•2 H2O 

When caustic (sodium hydroxide solution) is the scrubbing agent, the SO2 removal reactions are as 

follows: 

Na+ + OH- + SO2 + → Na2SO3

2Na+ + 2OH- + SO2 + → Na2SO3 + H2O 

Caustic scrubbing produces a liquid waste, and minimal equipment is needed as compared to lime or 

limestone scrubbers. If lime or limestone is used as the reagent for SO2 removal, additional 

equipment will be needed for preparing the lime/limestone slurry and collecting and concentrating 

the resultant sludge. Calcium sulfite sludge is watery; it is typically stabilized with fly ash for land 

filling. The calcium sulfate sludge is stable and easy to dewater. To produce calcium sulfate, an air 

injection blower is needed to supply the oxygen for the second reaction to occur. 

The normal SO2 control efficiency range for SO2 scrubbers on coal-fired utility boilers with oxygen

concentrations of 2-3% is 80% to 90% for low efficiency scrubbers and 90% to 95% for high 

efficiency scrubbers. The highest control efficiencies can be achieved when SO2 concentrations are 

the highest. The indurating furnace SO2 concentration would be considered low due to the high air 

flow rates required to assure product quality. Unlike coal-fired boilers, indurating furnaces operate 

with maximum excess air to enable proper oxidation of the pellet. The excess air dilutes the SO2

concentration as well as creates higher flow rates to control. Additionally, the varying sulfur 

concentration within the pellet causes fluctuations of the SO2 concentrations in the exhaust gas 

stream. This could also impact the SO2 control efficiency of the wet scrubber. 

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Based on the information contained within this report, a wet scrubber is considered a technically 

feasible technology for SO2 reduction for this BART analysis. 

Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection) 

Dry sorbent injection (DSI) of lime/limestone is a post-combustion SO2 control technology in which 

pulverized lime or limestone is directly injected into the duct upstream of the fabric filter. Dry 

sorption of SO2 onto the lime or limestone particle occurs and the solid particles are collected with a 

fabric filter. Further SO2 removal occurs as the flue gas flows through the filter cake on the bags. The 

normal SO2 control efficiency range for dry SO2 scrubbers is 70% to 90 % for coal fired utility 

boilers. Depending on the residence time and gas stream temperature, DSI control efficiency for an 

indurating furnace is estimated at 55%. 

Based on the information contained within this report, DSI is considered a technically feasible 

technology for SO2 reduction for this BART analysis. 

Spray Dryer Absorption (SDA) 

Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO2 is 

absorbed by the slurry, forming CaSO3/CaSO4. The liquid-to-gas ratio is such that the water 

evaporates before the droplets reach the bottom of the tower. The dry solids are carried out with the 

gas and collected with a fabric filter. When used to specifically control SO2, the term flue-gas 

desulfurization (FGD) may also be used. 

Based on the information contain with this report, SDA is considered a technically feasible 

technology for SO2 reduction for this BART analysis. 

Energy Efficiency Projects 

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption, 

which results in lower operating costs. Typically, reduced fuel usage translates into reduced 

pollution emissions. Due to the increased price of fuel, Tilden has already implemented energy 

efficiency projects. Each project carries its own fuel usage reductions and potentially emission 

reductions. Due to the uncertainty and generalization of this category, this will not be further 

evaluated in this report. However, it should be noted that Tilden will continue to evaluate and 

implement energy efficiency projects as they arise. 

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Alternate Fuels 

As described within the energy efficiency description, increased price of fuel has moved companies 

to evaluate alternate fuel sources. These fuel sources come in all physical forms – solid, liquid and 

gas. To achieve reduction of SO2 emissions through alternative fuel usage, the source must be 

capable of burning fuels with lower sulfur content than the existing fuels. Switching fuels trades one 

visibility impairment pollutant (SO2) for another (NOx), as induration furnaces emit significantly less 

NOx when burning solid fuels. Therefore, if this option is pursued, the impact on emissions of all 

visibility pollutants must be quantified and the cumulative visibility impact modeled to determine the 

net benefit of a particular alternative fuel. 

It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as an 

option, not to direct the fuel choice.27 

Therefore, due to the uncertainty of alternative fuel costs, the potential of replacing one visibility 

impairment pollutant for another, and the fact that BART is not intended to mandate a fuel switch, 

alternative fuels as an SO2 air pollution control technology will not be further evaluated in this 

report. However, similar to energy efficiency, Tilden will continue to evaluate and implement 

alternate fuel usage as the feasibility arises. 

Coal Processing 

Pre-combustion coal processing techniques have been proposed as one strategy to reduce 

uncontrolled SO2 emissions. Coal processing technologies are being developed to remove moisture 

and potential contaminants from the coal prior to use. 

These processes typically employ both mechanical and thermal means to increase the quality of coal 

by removing moisture, sulfur, mercury, and heavy metals. In one process, raw coal from the mine 

enters a first stage separator where it is crushed and screened to remove large rock and rock 

material.28 The processed coal is then passed on to an intermediate storage facility prior to being sent 

to the next stage in the process, the thermal process. In this stage, coal passes through pressure locks 

into the thermal processors where steam is injected. Moisture in the coal is released under these 

conditions. Mineral inclusions are also fractured under thermal stress, removing both included rock 

 

27 Federal Register 70, no. 128 (July 6, 2005): 39164

28 The coal processing description provided herein is based on the K-Fuel®

 process under development by KFx, Inc. 

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and sulfur-forming pyrites. After treatment, the coal is discharged into a second pressurized lock. 

The second pressurized lock is vented into a water condenser to return the processor to atmospheric 

pressure and to flash cool the coal. Water, removed from the process at various points, and 

condensed process steam are reused within the process or treated prior to being discharged. 

To date, the use of processed fuels has only been demonstrated with test burns in a pulverized coalfired boiler. Using processed fuels at a taconite plant would require research, test burns, and 

extended trials to identify potential impacts on plant systems, including the furnaces, material 

handling, and emission control systems. Therefore, processed fuels are not considered commercially 

available, and will not be analyzed further in this BART analysis. 

Coal crushing and drying is currently employed by Tilden as an incidental option for SO2 reduction. 

In the process, raw coal is crushed and screened to remove rocks and other impurities. The crushed 

coal is then thermally processed to remove excess moisture. Coal crushing and drying is already in 

use, so further reductions from this control option are not possible. Therefore, it will not be further 

evaluated in this report. 

Step 2 Conclusion 

Based upon the determination within Step 2, the remaining SO2 control technologies that are 

available and applicable as secondary controls to the existing indurating furnace wet scrubbers are 

identified in Table 5-1. The technical feasibility as determined in Step 2 is also included in Table 5-1.

Table 5-1 Indurating Furnace SO2 Control Technology – Availability, Applicability, and 

Technical Feasibility 

SO2 Pollution Control Technology Available? Applicable? 

Technically 

Feasible? 

Wet Walled Electrostatic Precipitator 

(WWESP) Yes Yes Yes 

Wet Scrubbing Yes Yes Yes 

Dry sorbent injection (DSI) Yes Yes Yes 

Spray Dryer Absorption (SDA) Yes Yes Yes 

Energy Efficiency Projects Yes Yes Project Dependent 

Alternative Fuels Yes Yes Yes – Not 

Required by BART 

Coal Processing No No No 

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5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

Table 5-2 describes the expected control efficiency from each of the remaining feasible control 

options. 

Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness 

SO2 Pollution Control Technology Approximate Control Efficiency

SDA 90% 

Wet Scrubber 80% 

WWESP 80% 

DSI 55% 

5.A.i.d STEP 4 – Evaluate Impacts and Document the Results 

As illustrated in Table 5-2 above, the technically feasible control remaining provide varying levels of 

emission reduction. Therefore, it is necessary to consider the economic, energy, and environmental 

impacts to better differentiate as presented below. 

Economic Impacts 

Table 5-3 details the expected costs associated with installation of the above alternatives on each 

stack. Equipment design was based on the maximum 24-hour emissions, vendor estimates, and U.S. 

EPA cost models. Capital costs were based on a recent vendor quotation. The cost for that unit was 

scaled to each stack’s flow rate using the six-tenths-factor rule as shown in the following equation: 

 Cost of equipment A = Cost of equipment B * (capacity of A/capacity of B)0.6

Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S. 

EPA models and factors. Operating costs were based on 100% utilization and annual operating hours 

of 7680 hours. Operating costs of consumable materials, such as electricity, water, and chemicals 

were established based on the U.S. EPA control cost manual29 and engineering experience, and were 

adjusted for the specific flow rates and pollutant concentrations. 

Due to space considerations, 60%30 of the total capital investment was included in the costs to 

account for a retrofit installation. After a tour of the facility and discussions with facility staff, it was 

 

29 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition. 

30 U.S. EPA, CUE Cost Workbook Version 1.0. Page 2. 

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determined the space surrounding the furnaces is congested, and the area surrounding the building 

supports vehicle and rail traffic to transport materials to and from the building. Additionally, the 

structural design of the existing building would not support additional equipment on the roof. 

Therefore, the cost estimates provide for additional site-work and construction costs to accommodate 

the new equipment within the facility. A site-specific estimate for site work, foundations, and 

structural steel was added to arrive at the total retrofit installed cost of the control technology. The 

site specific estimate was based on Barr’s experience with similar retrofit projects. See Appendix C 

for an aerial photo of the facility. The detailed cost analysis is provided in Appendix A. 

Table 5-3 Indurating Furnace SO2 Control Cost Summary 

Control Technology 

Installed 

Capital Cost 

(MM$) 

Total Annual Cost 

(MM$/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

SDA $167,260,397 $23,254,882 $22,407 

Wet Scrubber $34,869,327 $6,048,540 $6,557 

WWESP $52,638,755 $13,922,184 $15,091 

DSI $42,082,032 $9,975,786 $15,729 

Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory 

bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective 

air pollution controls in the electric utility industry for large power plants are in the range $1,000 to 

$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an indirect 

measure of affordability for the electric utility industry used by USEPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost 

effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not 

afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the 

electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater 

business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for 

proposing BART in lieu of developing industry and site specific data. 

The annualized pollution control cost value was used to determine whether or not additional impacts 

analyses would be conducted for the technology. If the control cost was less than a screening 

threshold established by MDEQ, then visibility modeling impacts, and energy and other impacts are 

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evaluated. MDEQ set the screening level to eliminate technologies from requiring the additional 

impact analyses at an annualized cost of $12,000 per ton of controlled pollutant31. Therefore, all air 

pollution controls with annualized costs less than this screening threshold will be evaluated for 

visibility improvement, energy and other impacts. Based on the information presented in table 5-3, 

the wet scrubber is the only technology that requires analysis for visibility improvement, energy and 

other impacts. 

The BART guidance documents also present a calculation method for incremental control cost which 

is intended to present the incremental value of each technology as compared to the next most 

effective alternative. Since only one of the technologies is cost effective, the incremental control 

cost is not applicable and is not presented in this analysis. 

Energy and Environmental Impacts 

The energy and non-air quality impacts for wet scrubbers are presented in Table 5-4. 

Table 5-4 SO2 Control Technology Impacts Assessment 

Control 

Technology Energy Impacts Other Impacts 

Wet Scrubber Significant pressure drop results 

in higher electrical requirements 

• Additional water 

consumption and 

wastewater generation 

• Increased facility water 

balance and water quality 

issues 

• Ponding for scrubber 

discharge will be limited 

because of site space 

constraints 

• Additional solid 

waste/sludge generation 

• Process downtime/lost 

production during 

installation 

Table 5-4 notes that wet scrubbers would require additional water consumption. Michigan’s Upper 

Peninsula has experienced a drought in the past several years. Use of wet scrubbers would create 

additional demand for water, a resource that is already stressed due to the recent drought conditions. 

Because the cost of the remaining SO2 control technologies for Tilden Line 1 furnace is so high and 

 

31 Michigan Department of Environmental Quality May 12, 2006 meeting. 

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does not meet a reasonable definition of cost effective technology, these technologies are removed 

from further consideration in this analysis. 

5.A.i.e STEP 5 – Evaluate Visibility Impacts 

As previously stated in section 4 of this document, states are required to consider the degree of 

visibility improvement resulting from the retrofit technology, in combination with other factors such 

as economic, energy and other non-air quality impacts, when determining BART for an individual 

source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this 

document. This section of the report evaluates the visibility impacts of BART SO2 control for the 

Line 1 Indurating Furnace and the resulting degree of visibility improvement. 

Predicted 24-Hour Maximum Emission Rates 

Consistent with the use of the highest daily emissions for baseline, or pre-BART, visibility impacts, 

the post-control emissions to be used for the visibility impacts analysis should also reflect a 

maximum 24-hour average project emission rate. In the visibility impacts analysis for SO2, the 

emissions from the sources undergoing a full BART SO2 analysis were adjusted to reflect the 

projected 24-hour maximum SO2 emission rate when applying the control technologies that met the 

threshold requirements of steps 1 – 4. The emissions from all other Subject-to-BART sources were 

not changed. Table 5-5 provides a summary of the modeled 24-hour maximum emission rates and 

their computational basis for the evaluated SO2 control technologies. Table 5-6 provides a summary

of the modeling input data.

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Table 5-5 Post-Control Modeling Scenarios 

Scenario Control Technology SO2 

Control 

Scenario SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour lbs/hr % Reductio

Base SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% Base SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% Base SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

2 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

3 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

6 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

7 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

10 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

11 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

14 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

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Scenario Control Technology SO2 

Control 

Scenario SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour lbs/hr % Reductio

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

15 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

18 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

19 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

22 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

23 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

26 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

27 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

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Scenario Control Technology SO2 

Control 

Scenario SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour lbs/hr % Reductio

30 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

31 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

Table 5-6 Post-Control SO2 Modeling Scenarios - Modeling Input Data 

Control Scenario SV # Emission Unit Stack Latitude Stack Longitude 

Height of 

Opening from 

Ground 

(ft) 

Base Elevation 

of Ground 

(ft) 

Stack length, 

width, or 

Diameter 

(ft) 

Flow Rate 

(acfm

All Scenarios SVP0051981 SVP0051711 EUKILN1 46.44084994 

46.44075383 

-87.653 

40738 

-87.651 

32336 

240 160 

1474 

19.3 13.5 

842,0306,0

 SVP0082951 EUDRYER1 46.44075383 -87.651 32336 119 1474 6.3 57,13

SVBLR.STK.

T1 

EUBOILER1 EUBOILER2 46.44091784 -87.654 12418 130 1474 7.5 192,0

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Post-Control Visibility Impacts Modeling Results 

Results of the post-control visibility impacts modeling for SO2 are presented in Table 5-7. The 

results summarize the 98th percentile dV value and the number of days the facility contributes more 

than a 0.5 dV of visibility impairment at each of the Class I areas. The comparison of the postcontrol modeling scenarios to the baseline conditions is presented in Table 5-8. 

As illustrated in Tables 5-7 and 5-8, the highest facility baseline visibility contribution is 0.72 dV. A 

wet scrubber (Scenario 2) would potentially reduce the visibility contribution by 0.1 dV at a cost of 

over $34 million in installed capital cost and a total annual cost of over $6.0 million per year. This 

would result in a cost per deciview reduction of over $60 million per deciview. 

Visibility impacts with NOx controls are presented in Section 6. 

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Table 5-7 Post-Control SO2 Modeling Scenarios - Visibility Modeling Results 

2002 2003 2004 

2002 – 200

Combined 

Scenario # 

Class I 

Area with 

Greatest 

Impact 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of days 

exceeding 

0.5 

deciview 

Modeled 98th

Percentile 

Value 

(deciview) 

No. of days 

exceeding 0.5 

deciview 

Modeled 98th

Percentile 

Value 

(deciview) 

No. of days 

exceeding 0.5 

deciview 

Modeled 98th

Percentile 

Value 

(deciview) 

N

ex

Base IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 

2 IRNP 0.610 15.0 0.620 10.000 0.535 8.000 0.600 3 IRNP 0.183 0.0 0.177 0.000 0.154 0.000 0.173 6 IRNP 0.619 15.0 0.623 10.000 0.528 8.000 0.598 7 IRNP 0.182 0.0 0.177 0.000 0.155 0.000 0.169 

10 IRNP 0.618 15.0 0.607 10.000 0.527 8.000 0.590 11 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161 14 IRNP 0.627 15.0 0.608 9.000 0.544 8.000 0.585 15 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160 18 IRNP 0.626 15.0 0.605 9.000 0.542 8.000 0.596 19 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163 22 IRNP 0.625 15.0 0.602 9.000 0.291 3.000 0.588 23 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165 26 IRNP 0.623 15.0 0.605 9.000 0.550 8.000 0.597 27 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165 30 IRNP 0.613 14.0 0.614 9.000 0.542 8.000 0.588 31 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.164 

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Table 5-8 Post-Control SO2 Modeling Scenarios - Visibility Improvements 

Modeling Results 

0 2002 2003 2004 2002-2004 

Scenario 

Limiting 

Class I 

Area 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

Base IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 41 

2 IRNP 0.104 4 0.102 1 0.064 3 0.074 8 3 IRNP 0.531 19 0.545 11 0.445 11 0.501 41 6 IRNP 0.095 4 0.099 1 0.071 3 0.076 8 7 IRNP 0.532 19 0.545 11 0.444 11 0.505 41 

10 IRNP 0.096 4 0.115 1 0.072 3 0.084 8 11 IRNP 0.538 19 0.554 11 0.449 11 0.513 41 14 IRNP 0.087 4 0.114 2 0.055 3 0.089 9 15 IRNP 0.538 19 0.551 11 0.449 11 0.514 41 18 IRNP 0.088 4 0.117 2 0.057 3 0.078 9 19 IRNP 0.539 19 0.549 11 0.448 11 0.511 41 22 IRNP 0.089 4 0.12 2 0.308 8 0.086 14 23 IRNP 0.539 19 0.552 11 0.449 11 0.509 41 26 IRNP 0.091 4 0.117 2 0.049 3 0.077 9 27 IRNP 0.538 19 0.55 11 0.448 11 0.509 41 30 IRNP 0.101 5 0.108 2 0.057 3 0.086 10 31 IRNP 0.541 19 0.55 11 0.448 11 0.51 41 

.

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5.A.ii Nitrogen Oxide Controls 

To be able to control NOx it is important to understand how NOx is formed. There are three 

mechanisms by which NOx production occurs: thermal, fuel and prompt NOx. 

• Fuel bound NOx is formed from fuel combustion as nitrogen compounds in the fuel are 

oxidized. 

• Thermal NOx production arises from the thermal dissociation of nitrogen and oxygen 

molecules within the furnace. Combustion air is the primary source of nitrogen and oxygen. 

In taconite furnaces, thermal NOx production is a function of the residence time, free oxygen, 

and temperature, primarily in the flame area of the furnace. 

• Prompt NOx is a form of thermal NOx which is generated at the flame boundary. It is the 

result of reactions between nitrogen and carbon radicals generated during combustion. Only 

minor amounts of NOx are emitted as prompt NOx. 

The majority of NOx is emitted as NO. Minor amounts of NO2 are formed in the furnaces. 

5.A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies 

With the understanding of how NOx is formed, available and applicable control technologies were 

evaluated. See Appendix D for a comprehensive list of all potential retrofit control technologies that 

were evaluated. 

5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options 

Step 1 identified the available and applicable technologies for NOx emission reduction. Within 

Step 1, the technical feasibility of the control option was also discussed and determined. The 

following describes retrofit NOx control technologies that were identified as available and applicable 

in the original submittal and discusses aspects of those technologies that determine whether or not 

the technology is technically feasible for indurating furnaces. 

External Flue Gas Recirculation (EFGR) 

External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures 

thereby reducing thermal NOx formation. In an external flue gas recirculation system, flue gas is 

collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is 

mixed with the combustion air and this mixture is introduced into the burner. The addition of flue gas 

reduces the oxygen content of the “combustion air” (air + flue gas) in the burner. The lower oxygen 

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level in the combustion zone reduces flame temperatures; which in turn reduces NOx emissions. For 

this technology to be effective, the combustion conditions must have the ability to be controlled at 

the burner tip. 

The normal NOx control efficiency range for EFGR is 30% to 50%. 

Application of EFGR technology in taconite induration is problematic for three reasons: 

1. The exhaust gas in an induration furnace typically has an oxygen content that is close to 

ambient, or 18% oxygen, vs. a boiler which has 2% - 3% oxygen. In a boiler, the flue gas 

is relatively inert and oxygen starved so it can be used as a diluent for flame temperature 

reduction. Taconite waste gas has much higher oxygen level; thus use of taconite waste 

gas for EFGR would be equivalent to adding combustion air instead of an inert gas. 

2. The oxidation zone of induration furnaces needs to be above 2,400oF in order to meet 

product specifications. Existing burners are designed to meet these process conditions. 

Application of EFGR would reduce flame temperatures. Lower flame temperatures 

would reduce furnace temperatures to the point that product quality could be jeopardized. 

3. Application of EFGR technology increases flame length. Dilution of the combustion 

reactants increases the reaction time needed for fuel oxidation to occur; so, flame length 

increases. Therefore, application of EFGR could result in flame impingement on furnace 

components. That would subject those components to excessive temperatures and cause 

equipment failures. 

Although this may be an available and applicable control option, it is not technically feasible due to 

the high oxygen content of the flue gas and will not be further evaluated in this report. 

Low-NOx Burners 

Low-NOx burner (LNB) technology utilizes advanced burner design to reduce NOx formation through 

the restriction of oxygen, flame temperature, and/or residence time. LNB is typically a staged 

combustion process that is designed to split fuel combustion into two zones, primary combustion and 

secondary combustion. 

In the primary combustion zone of a staged fuel burner, NOx formation is limited by a rich (high 

fuel) condition. Oxygen levels and flame temperatures are low; this results in less NOx formation. In 

the secondary combustion zone, incomplete combustion products formed in the primary zone act as 

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reducing agents. In a reducing atmosphere, nitrogen compounds are preferentially converted to 

molecular nitrogen (N2) over nitric oxide (NO). The estimated NOx control efficiency for LNB in 

high temperature applications is 10%. Low NOx burners have been installed in the preheating section 

of a straight-grate furnace at another taconite plant; however, the Line 1 Indurating Furnace does not 

contain a pre-heat burner section. If LNB were to be applied in the indurating zone of the furnace, 

the reduced flame temperatures associated with LNB would adversely affect taconite pellet product 

quality. LNB has not been applied to the indurating or preheat zones of any grate-kiln taconite 

furnace. Therefore, this option is not technically feasible. 

It is also important to note that there are other methods being developed for LNB which are not yet 

commercially available. Some incorporate various fuel dilution techniques to reduce flame 

temperatures; such as mixing an inert gas like CO2 with natural gas. Water injection to cool the 

burner peak flame temperature is also being investigated. This technique has already been 

successfully used for reducing NOx emissions from gas turbines and a straight-grate taconite 

indurating furnace in the Netherlands. The water injection technique shows promise for high 

temperature applications, but will not be further investigated in this report as the technology is still in 

the development phase and is not yet commercially available. 

Induced Flue Gas Recirculation Burners 

Induced flue gas recirculation burners, also called ultra low-NOx burners, combine the benefits of 

flue gas recirculation and low-NOx burner control technologies. The burner is designed to draw flue 

gas to dilute the fuel in order to reduce the flame temperature. These burners also utilize staged fuel 

combustion to further reduce flame temperature. The estimated NOx control efficiency for IFGR 

burners in high temperature applications is 25-50%. 

As noted above, taconite furnaces are designed to operate with oxygen levels near 18%. At these 

oxygen levels, flue gas recirculation is ineffective at NOx reduction, and it would adversely affect 

combustion because excessive amounts of oxygen would be injected into the flame pattern. In 

addition, IFGR relies on convective flow of flue gas through the burner and requires burners to be 

up-fired; meaning that the burner is mounted in the furnace floor and the flame rises up. 

Furthermore, IFGR is not feasible because the reduced flame temperatures associated with IFGR 

would adversely affect taconite pellet product quality. 

Although this may be an available and applicable control option, it is not technically feasible due to 

the high oxygen content of the flue gas and will not be further evaluated in this report. 

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Energy Efficiency Projects 

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption, 

which results in lower operating costs. Typically, reduced fuel usage translates into reduced 

pollution emissions. Due to the increased price of fuel, Tilden has already implemented energy 

efficiency projects. Each project carries its own fuel usage reductions and potentially emission 

reductions. Due to the uncertainty and generalization for this category, this will not be further 

evaluated in this report. However, it should be noted that Tilden will continue to evaluate and 

implement energy efficiency projects as they arise. 

Ported Kilns 

Ported kilns are rotary kilns that have air ports installed at specified points along the length of the 

kiln for process improvement. The purpose of the ports is to allow air injection into the pellet bed as 

it travels down the kiln bed. Ports are installed about the circumference of the kiln. Each port is 

equipped with a closure device that opens when it is at the bottom position to inject air in the pellet 

bed, and closed when it rotates out of position. 

The purpose of air injection is to provide additional oxygen for pellet oxidation. The oxidation 

reaction produces enough heat to offset the heat loss associated with air injection. Air injection 

reduces the overall energy use of the kiln and produces a higher quality taconite pellet. Air injection 

also reduces the carry over of the oxidation reaction into the pellet coolers. 

Ported kilns are potentially applicable to grate-kilns. In the past, the technology was believed to 

reduce NOx formation. However, the technology vendor will not guarantee that ported kilns will 

reduce NOx emissions because controlling the oxygen in the firing zone is not possible due to the 

flow of air from the pellet cooler32. Any reduction in NOx would be minor and incidental to the 

process improvement and specific to the individual furnace. Therefore, although this may be an 

available and applicable technology, its NOx reduction potential is small and may be unsuccessful 

because of the design of the pellet cooler area. Ported kilns will not be further evaluated in this 

report. 

Alternate Fuels 

As described within the energy efficiency description, increased price of fuel has moved companies 

to evaluate alternate fuel sources. These fuel sources come in all physical forms – solid, liquid and 

 

32 Telephone conversation with Metso, July 18, 2006. 

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gas. Reduction of NOx emissions through alternative fuel usage has been achieved at taconite gratekilns through the use of solid fuel. In these cases the reduction resulted due to changes from 

pulverized solid fuel dispersal in the kiln that resulted in lower flame temperature compared to other 

fuels. Switching from natural gas or oil to solid fuel has a potential drawback in that it can exchange 

one visibility impairment pollutant (NOx) for another (SO2). Therefore, if this option is pursued, the 

impact on emissions of all visibility pollutants must be quantified and the cumulative visibility 

impact modeled to determine the net benefit of a particular alternative fuel. 

It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as an 

option, not to direct the fuel choice.33 

However, similar to energy efficiency, Tilden will continue to evaluate and implement alternate fuel 

usage as the feasibility arises. 

Coal Processing 

Pre-combustion coal processing techniques have been proposed as one strategy to reduce 

uncontrolled NOx emissions. Coal processing technologies are being developed to remove moisture 

and potential contaminants from the coal prior to use. 

These processes typically employ both mechanical and thermal means to increase the quality of coal 

by removing moisture, sulfur, mercury, and heavy metals. In one process, raw coal from the mine 

enters a first stage separator where it is crushed and screened to remove large rock and rock 

material.34 The processed coal is then passed on to an intermediate storage facility prior to being sent 

to the next stage in the process, the thermal process. In this stage, coal passes through pressure locks 

into the thermal processors where steam is injected. Moisture in the coal is released under these 

conditions. Mineral inclusions are also fractured under thermal stress, removing both included rock 

and sulfur-forming pyrites. After treatment, the coal is discharged into a second pressurized lock. 

The second pressurized lock is vented into a water condenser to return the processor to atmospheric 

pressure and to flash cool the coal. Water, removed from the process at various points, and 

condensed process steam are reused within the process or treated prior to being discharged. 

 

33 Federal Register 70, no. 128 (July 6, 2005): 39164

34 The coal processing description provided herein is based on the K-Fuel®

 process under development by KFx, Inc. 

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To date, the use of processed fuels has only been demonstrated with test burns in a pulverized coalfired boiler. Using processed fuels at a taconite plant would require research, test burns, and 

extended trials to identify potential impacts on plant systems, including the furnaces, material 

handling, and emission control systems. Therefore, processed fuels are not considered commercially 

available, and will not be analyzed further in this BART analysis. 

Coal crushing and drying is currently employed by Tilden as an incidental option for NOx reduction. 

In the process, raw coal is crushed and screened to remove rocks and other impurities. The crushed 

coal is then thermally processed to remove excess moisture. Coal crushing and drying is already in 

use, so further reductions from this control option are not possible. Therefore, it will not be further 

evaluated in this report. 

Process Optimization with Parametric Monitoring 

There are several concerns with utilizing process optimization as an available, applicable and 

technically feasible control option for the taconite industry: 

• Typical taconite furnaces are designed and operated to convert magnetite to hematite in the 

presence of excess oxygen and require heat input to initiate the reaction which is exothermic 

and releases heat once initiated. Fuel combustion is only part of the process and therefore 

this process is different from a boiler. 

• The quality of the process feed materials to the furnace is variable at some taconite 

operations and product quality may be compromised by attempting to fine tune heat input to 

minimize NOx formation. 

• At some operations, the operating parameters which generally influence the rate of NOx

generation such as flame temperature, fuel usage and excess air are relatively constant during 

operation of the furnace, independent of process operation variability. This indicates that NOx

formation may not be dependent upon controllable operating parameters. In the absence of 

controllable parameters, process optimization would not be effective at controlling NOx

emissions. 

Based upon this information, there is no indication that further emission reductions would be 

achieved through process optimization using parametric monitoring as a control technology. 

Therefore, process optimization as a control option will not be evaluated further in this report. 

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Post Combustion Controls 

NOx can be controlled using add-on systems located downstream of the combustion process. The 

two main techniques in commercial service include the selective non catalytic reduction (SNCR) 

process and the selective catalytic reduction (SCR) process. There are a number of different process 

systems in each of these categories of control techniques. 

In addition to these treatment systems, there are a large number of other processes being developed 

and tested on the market. These approaches involve innovative techniques of chemically reducing, 

absorbing, or adsorbing NOx downstream of the combustion chamber. Examples of these alternatives 

are nonselective catalytic reduction (NSCR) and Low Temperature Oxidation (LTO). Each of these 

alternatives is described below.

Non-Selective Catalytic Reduction (NSCR) 

A non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas 

treatment system. NSCR catalyst is very sensitive to poisoning; so; NSCR is usually applied 

primarily in natural gas combustion applications. 

NSCR is often referred to as “three-way conversion” catalyst because it simultaneously reduces NOx, 

unburdened hydrocarbons (UBH), and carbon monoxide (CO). Typically, NSCR can achieve NOx

emission reductions of 90 percent. In order to operate properly, the combustion process must be near 

stoichiometric conditions. Under this condition, in the presence of a catalyst, NOx is reduced by CO, 

resulting in nitrogen (N2) and carbon dioxide (CO2). The most important reactions for NOx removal 

are: 

2CO + 2NO → 2CO2 + N2 (1) 

[UBH] + NO → N2 + CO2 + H2O (2) 

NSCR catalyst has been applied primarily in clean combustion applications. This is due in large part 

to the catalyst being very sensitive to poisoning, making it infeasible to apply this technology to the 

indurating furnace. In addition, we are not aware of any NSCR installations on taconite induration 

furnaces or similar combustion equipment. Therefore, this technology is not considered to be 

available and applicable, and therefore will not be further evaluated in this report. 

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Selective Catalytic Reduction (SCR) and Regenerative Selective Catalytic Reduction 

(R-SCR) 

SCR is a post-combustion NOx control technology in which ammonia (NH3) is injected into the flue 

gas stream in the presence of a catalyst. NOx is removed through the following chemical reaction:

4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (1) 

2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O (2) 

A catalyst bed containing metals in the platinum family is used to lower the activation energy 

required for NOx decomposition. SCR requires a temperature range of about 570°F – 850°F for a 

normal catalyst. At temperature exceeding approximately 670oF, the oxidation of ammonia begins to 

become significant. At low temperatures, the formation of ammonium bisulfate causes scaling and 

corrosion problems. 

A high temperature zeolite catalyst is also available; it can operate in the 600 °F – 1000°F 

temperature range. However, these catalysts are very expensive. 

Ammonia slip from the SCR system is usually less than 3 to 5 ppm. The emission of ammonia 

increases during load changes due to the instability of the temperature in the catalyst bed as well as at 

low loads because of the low gas temperature. 

Regenerative Selective Catalytic Reduction (R-SCR) applies the Selective Catalytic Reduction (SCR) 

control process as described above with a preheat process step to reheat the flue gas stream up to 

SCR catalyst operating temperatures. The preheating process combines use of a thermal heat sink 

(packed bed) and a duct burner. The thermal sink recovers heat from the hot gas leaving the R-SCR 

and then transfers that heat to gas entering the R-SCR. The duct burner is used to complete the 

preheating process. R-SCR operates with several packed bed/SCR reactor vessels. Gas flow 

alternates between vessels. Each of the vessels alternates between preheating/treating and heat 

recovery. 

The benefits of R-SCR are: 

• Its high energy efficiency allows it to be used after SO2 and particulate controls. 

• R-SCR has a thermal efficiency of 70% vs. standard heat exchangers which have a thermal 

efficiency of 60% to 70%. 

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• Application of R-SCR after SO2 and PM controls significantly reduces the potential for 

problems associated with plugging and catalyst poisoning and deactivation. 

There are several concerns about the technical feasibility and applicability of R-SCR on an 

indurating furnace: 

• The composition of the indurating furnace flue gas is significantly different from the 

composition of the flue gas from the boilers that utilize R-SCR; 

• The taconite dust is highly erosive and can cause significantly equipment damage. R-SCR 

has a number of valves which must be opened and closed frequently to switch catalyst/heat 

recovery beds. These valves could be subject to excessive wear in a taconite application due 

to the erosive nature of the taconite dust; 

• R-SCR has not been applied downstream of a wet scrubber. Treating a stream saturated with 

water may present design problems in equipment sizing for proper heat transfer and in 

corrosion protection; 

• R-SCR catalyst had been shown to oxidize mercury. Oxidized mercury can be absorbed by 

the local environment and have adverse impact. The impact of RSCR on mercury emissions 

needs to be studied to determine whether or not mercury oxidation is a problem and to 

identify mitigation methods if needed. 

To date, R-SCR has been applied to wood-fired utility boilers. Application of this technology has 

not been applied to taconite induration furnaces, to airflows of the magnitude of taconite furnace 

exhausts, nor to exhaust streams with similar, high moisture content. Using R-SCR at a taconite plant 

would require research, test runs, and extended trials to identify potential issues related to catalyst 

selection, and impacts on plant systems, including the furnaces and emission control systems. It is 

not reasonable to assume that vendor guarantees of performance would be forthcoming in advance of 

a demonstration project. The timeline required to perform such a demonstration project would likely 

be two years to develop and agree on the test plan, obtain permits for the trial, commission the 

equipment for the test runs, perform the test runs for a reasonable study period, and evaluate and 

report on the results. The results would not be available within the time window for establishing 

emission limits to be incorporated in the state implementation plan (SIP) by December 2007. 

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Recalling U.S. EPA’s intention regarding “available” technologies to be considered for BART, as 

mentioned in Section 2.B, facility owners are not expected to undergo extended trials in order to 

learn how to apply a control technology to a completely new and significantly different source type. 

Therefore, R-SCR is not considered to be technically feasible, and will not be analyzed further in this 

BART analysis. 

SCR with reheat through a conventional duct burner (rather than using a regenerative heater) has 

been successfully implemented more widely and in higher airflow applications and will be carried 

forward in this analysis as available and applicable technology that is reasonably expected to be 

technically feasible. 

Low Temperature Oxidation (LTO) 

The LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including 

NOx. In the system, the NOx in the flue gas is oxidized to form nitrogen pentoxide (equations 1, 2, 

and 3). The nitrogen pentoxide forms nitric acid vapor as it contacts the water vapor in the flue gas 

(4). Then the nitric acid vapor is absorbed as dilute nitric acid and is neutralized by the sodium 

hydroxide or lime in the scrubbing solution forming sodium nitrate (5) or calcium nitrate. The 

nitrates are removed from the scrubbing system and discharged to an appropriate water treatment 

system. Commercially available LTO systems include Tri-NOx® and LoTOx®. 

NO + O3 → NO2 + O2 (1) 

NO2 + O3 → NO3 + O2 (2) 

NO3 + NO2 → N2O5 (3) 

N2O5 + H2O → 2HNO3 (4) 

HNO3 + NaOH → NaNO3 + H2O (5) 

Low Temperature Oxidation (Tri-NOx

®

) 

This technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO2 in a 

primary scrubbing stage. Then NO2 is removed through caustic scrubbing in a secondary stage. The 

reactions are as follows: 

O3 + NO → O2 + NO2

(1)

2NaOH + 2NO2 + 1⁄2 O2 → 2NaNO3 + H2O (2)

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Tri-NOx

®

 is a multi-staged wet scrubbing process in industrial use. Several process columns, each 

assigned a separate processing stage, are involved. In the first stage, the incoming material is 

quenched to reduce its temperature. The second, oxidizing stage, converts NO to NO2. Subsequent 

stages reduce NO2 to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NOx

®

 is 

typically applied at small to medium sized sources with high NOx concentration in the exhaust gas 

(1,000 ppm NOx). NOx concentrations in the exhaust at Tilden are typically less than 200 ppm. 

Therefore, Tri-NOx

®

 is not applicable to taconite processing and will not be analyzed further in this 

BART analysis. 

Low Temperature Oxidation (LoTOx®) 

BOC Gases’ Lo-TOx®

 is an example of a version of an LTO system. LoTOx® technology uses ozone 

to oxidize NO to NO2 and NO2 to N2O5 in a wet scrubber (absorber). This can be done in the same 

scrubber used for particulate or sulfur dioxide removal, The N2O5 is converted to HNO3 in a 

scrubber, and is removed with lime or caustic. Ozone for LoTOx® is generated on site with an 

electrically powered ozone generator. The ozone generation rate is controlled to match the amount 

needed for NOx control. Ozone is generated from pure oxygen. In order for LoTOx® to be 

economically feasible, a source of low cost oxygen must be available from a pipeline or on-site 

generation. 

The first component of the technical feasibility review includes determining if the technology would 

apply to the process being reviewed. This would include a review and comparison of the chemical 

and physical properties required. Although it appears that the chemistry involved in the LTO 

technology may apply to an indurating furnace, the furnace exhaust contains other ore components 

that may participate in side reactions. This technology has not been demonstrated on a taconite pellet 

indurating furnace or any process beyond coal or gas fired boilers. This raises uncertainties about 

how or whether the technology will transfer to a different type of process. 

The second component of the technical feasibility review includes determining if the technology is 

commercially available. Evaluations of LTO found that it has only been applied to small to medium 

sized coal or gas fired boiler applications, and has never been demonstrated on a large-scale facility. 

For example, the current installations of LoTOx® are on sources with flue gas flow rates from 150 – 

35,000 acfm, which is quite small, compared to the indurating furnace flue gas flow rates of over one 

million acfm. Therefore, the application of LTO would be more than two orders of magnitude larger 

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than the biggest current installation. This large scale-up is contrary to good engineering practices 

and could be problematic in maintaining the current removal efficiencies. 

In addition, only two of BOC’s LoTOx® installations are fully installed and operational applications. 

Therefore, although this is an emerging technology, the limited application means that it has not been 

demonstrated to be an effective technology in widespread application. 

There are several other concerns about the technical feasibility and applicability of LTO on an 

indurating furnace: 

• The composition of the indurating furnace flue gas is significantly different from the 

composition of the flue gas from the boilers and process heaters that utilize LTO; 

• The taconite dust in the flue gas is primarily magnetite (Fe3O4) which would react with the 

ozone to form hematite (Fe2O3); since the ozone injection point would be before the scrubber, 

there can be more than 185 pounds per hour of taconite dust in the flue gas which could 

consume a significant amount of the ozone being generated which may change the reaction 

kinetics; consequently, this would necessitate either an increase in the amount of ozone 

generated or a decrease in the estimated control efficiency; 

• The ozone that would be injected into the flue gas would react with the SO2, converting the 

material to SO3 which could result in the generation of sulfuric acid mist from the scrubber; 

• Since LTO has not been installed at a taconite plant, it is likely that the application of LTO to 

an indurating furnace waste gas could present technical problems which were not 

encountered, or even considered, in the existing LTO applications; 

• An LTO system at a taconite facility would also be a source of nitrate discharge to the 

tailings basin which would change the facility water chemistry which could cause operational 

problems and would likely cause additional problems with National Pollutant Discharge 

Elimination System (NPDES) discharge limits and requirements. 

Application of this technology has not been tried on taconite induration furnaces, on airflows of the 

magnitude of taconite furnace exhausts, nor on exhaust streams with similar, high moisture content. 

Using LTO at a taconite plant would require research, test runs, and extended trials to identify 

potential issues related to design for high airflows and impacts on plant systems, including the 

furnaces and emission control systems. It is not reasonable to assume that vendor guarantees of 

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performance would be forthcoming in advance of a demonstration project. The timeline required to 

perform such a demonstration project would likely be two years to develop and agree on the test 

plan, obtain permits for the trial, commission the equipment for the test runs, perform the test runs 

for a reasonable study period, and evaluate and report on the results. The results would not be 

available within the time window for establishing emission limits to be incorporated in the state 

implementation plan (SIP) by December 2007. 

Recalling U.S. EPA’s intention regarding “available” technologies to be considered for BART, as 

mentioned in Section 2.B, facility owners are not expected to undergo extended trials in order to 

learn how to apply a control technology to a completely new and significantly different source type. 

Consequently, LTO is technically infeasible on an indurating furnace and will not be evaluated 

further. 

Step 2 Conclusion 

Based upon the determination within Step 2, the remaining NOx control technologies that are 

available and applicable to the indurating furnace process are identified in Table 5-9. The technical 

feasibility as determined in Step 2 is also included in Table 5-9.

Table 5-9 Indurating Furnace NOx Control Technology – Availability, Applicability, and 

Technical Feasibility 

NOx Pollution Control 

Technology Available? Applicable?

Technically 

Feasible? 

External Flue Gas 

Recirculation (EFGR) Yes No No 

Low NOx Burners (LNB) Yes Yes No 

Induced Flue Gas 

Recirculation Burners (IFGR) Yes Yes No 

Energy Efficiency Projects Yes Yes Project 

Dependent 

Ported Kilns 

(Applies to Grate-Kilns Only) Yes Yes No 

Alternative Fuels Yes Yes 

Yes 

- Not Required 

by BART 

Process Optimization Yes No No 

Non-Selective Catalytic 

Reduction (NSCR) Yes No No 

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NOx Pollution Control 

Technology Available? Applicable?

Technically 

Feasible? 

Selective Catalytic 

Reduction (SCR) with 

conventional reheat 

Yes Yes Yes 

Regenerative SCR Yes No No 

Selective Non-Catalytic 

Reduction (SNCR) Yes No No 

Low Temperature Oxidation 

(LTO) Yes No No 

5.A.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

Table 5-10 describes the expected control efficiency from each of the remaining technically feasible 

control options as identified in Step 2. 

Table 5-10 Indurating Furnace NOx Control Technology Effectiveness 

NOx Pollution Control 

Technology 

Approximate Control 

Efficiency 

SCR 

With conventional reheat 80% 

5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results 

Table 5-11 summarizes the expected costs associated with installation of low NOx burners and SCR 

with conventional reheat. Capital costs were calculated based on the maximum 24-hour emissions, 

U.S. EPA cost models, and vendor estimates. Vendor estimates for capital costs based on a specific 

flow rate were scaled to each stack’s flow rate using the six-tenths-factor rule to account for the 

economy of scale. Operating costs were based on 93% utilization and annual operating hours of 

7680 hours for Line 1. Operating costs were proportionally adjusted to reflect site specific flow rates 

and pollutant concentrations. 

After a tour of the facility and discussions with facility staff, it was determined the space surrounding 

the furnaces is congested and the area surrounding the building supports vehicle and rail traffic to 

transport materials to and from the building. A site-specific estimate for site-work, foundations, and 

structural steel was added based upon the facility site to arrive at the total retrofit installed cost of the 

control technology. The site specific estimate was based on Barr’s experience with recent actual 

retrofit costs. See Appendix C for a site plan of the facility. Additionally, the structural design of the 

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existing building would not support additional equipment on the roof. The detailed cost analysis is 

provided in Appendix A. 

Table 5-11 Indurating Furnace NOx Control Cost Summary 

Control Technology 

Installed 

Capital Cost 

(MM$) 

Total Annual 

Cost 

(MM$/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

SCR 

With conventional reheat 

$65,492,092 $31,055,581 $8,416 

Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory 

bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective 

air pollution controls in the electric utility industry for large power plants are in the range $1,000 to 

$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an indirect 

measure of affordability for the electric utility industry used by USEPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost 

effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not 

afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the 

electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater 

business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for 

proposing BART in lieu of developing industry and site specific data. 

The annualized pollution control cost value was used to determine whether or not additional impacts 

analyses would be conducted for the technology. If the control cost was less than a screening 

threshold established by MDEQ, then visibility modeling impacts, and energy and other impacts are 

evaluated. MDEQ set the screening level to eliminate technologies from requiring the additional 

impact analyses at an annualized cost of $12,000 per ton of controlled pollutant35. Therefore, all air 

pollution controls with annualized costs less than this screening threshold will be evaluated for 

visibility improvement, energy and other impacts. Based on the information presented in table 5-11, 

SCR with conventional reheat is the only technology that requires analysis for visibility 

improvement, energy and other impacts. 

 

35 Michigan Department of Environmental Quality May 12, 2006 meeting. 

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The BART guidance documents also present a calculation method for incremental control cost which 

is intended to present the incremental value of each technology as compared to the next most 

effective alternative. Since only one of the technologies is cost effective, the incremental control 

cost is not applicable and is not presented in this analysis. 

The incremental control cost column in Table 5-11 is intended to present the incremental value of 

each technology as compared to the technology with the next most effective alternative. Since none 

of the NOx reduction technologies are cost effective, the incremental cost is not applicable. 

Energy and Environmental Impact 

The energy and non-air quality impacts for the remaining alternatives are presented in Table 5-12. 

Table 5-12 NOx Control Technology Impacts Assessment 

Control Technology Energy Impacts Other Impacts 

SCR with Reheat 

Reheat would require 

additional natural gas 

use. 

• Ammonia slip, which 

contributes to regional 

haze. Ammonia reacts 

with NOx to form 

ammonium nitrate and 

SO2 to form ammonium 

sulfate particles. 

Ammonium sulfate is 

hygroscopic and bonds 

with water in the air to 

grow large particles. The 

large particles formed by 

ammonium sulfate 

disproportionately 

contribute to visibility 

impairment. 

• Ammonia emissions will 

increase condensable PM 

emissions that will have 

possible PSD permitting 

implications. 

• Ammonia deposition onto 

nearby lakes and waters 

of the state and contribute 

nutrients and undesirable 

biological growth. 

• Additional safety and 

regulatory concerns 

associated with ammonia 

storage on site. 

• Possible oxidation of 

elemental mercury. 

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5.A.ii.e STEP 5 – Evaluate Visibility Impacts 

As previously stated in Section 4 of this document, states are required to consider the degree of 

visibility improvement resulting from the retrofit technology, in combination with other factors such 

as economic, energy and other non-air quality impacts, when determining BART for an individual 

source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this 

document. This section of the report evaluates the visibility impacts of BART NOx control and the 

resulting degree of visibility improvement. 

Predicted 24-Hour Maximum Emission Rates 

Consistent with the use of the highest daily emissions for baseline, or pre-BART, visibility impacts, 

the post-control emissions to be used for the visibility impacts analysis should also reflect a 

maximum 24-hour average project emission rate. In the visibility impacts analysis for NOx, the 

emissions from the sources undergoing a full BART NOx analysis were adjusted to reflect the 

projected 24-hour maximum NOx emission rate when applying the control technologies that met the 

threshold requirements of steps 1 – 4. The emissions from all other Subject-to-BART sources were 

not changed. Table 5-13 provides a summary of the modeled 24-hour maximum emission rates and 

their computational basis for the evaluated NOx control technologies. Table 5-14 provides a 

summary of the modeling input data.

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Table 5-13 Post-Control NOx Modeling Scenarios 

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

Base SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% Base SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% Base SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

1 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

3 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

5 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

7 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

9 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

11 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

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Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

13 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

15 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

17 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

19 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

21 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

23 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

25 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

27 SVP0051981 EUKILN1 Wet Scrubber SCR w/reheat 80% 40.0 80% 

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Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

SVP0051711 80% 14.6 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

29 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

31 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

Table 5-14 Post-Control NOX Modeling Scenarios - Modeling Input Data 

Control Scenario SV # Emission Unit Stack Easting 

(utm) 

Stack Northing 

(utm) 

Height of 

Opening from 

Ground 

(ft) 

Base Elevation 

of Ground 

(ft) 

Stack length, 

width, or 

Diameter 

(ft) 

Flow Rate 

(acfm

All Scenarios SVP0051981 SVP0051711 EUKILN1 46.44084994 

46.44075383 

-87.653 

40738 

-87.651 

32336 

240 160 

1474 

19.3 13.5 

842,0306,0

 SVP0082951 EUDRYER1 46.44075383 -87.651 32336 119 1474 6.3 57,13

SVBLR.STK.

T1 

EUBOILER1 EUBOILER2 46.44091784 -87.654 12418 130 1474 7.5 192,0

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Post-Control Visibility Impacts Modeling Results 

Results of the post-control visibility impacts modeling for NOX are presented in Table 5-15. The 

results summarize 98th percentile dV value and the number of days the facility contributes more than 

a 0.5 dV of visibility impairment at each of the Class I areas. The comparison of the post-control 

modeling scenarios to the baseline conditions is presented in Table 5-16. 

As illustrated in tables 5-15 and 5-16, the facility baseline visibility contribution is 0.72 dV. 

Installing SCR with conventional reheat on Line 1 when natural gas is burned could potentially 

reduce the visibility contribution by 0.45 from Scenario 1.. 

Visibility impacts with SO2 controls are presented in section 6. 

Table 5-15 Post-Control NOX Modeling Scenarios - Visibility Modeling Results 

Modeling Results 

 2002 2003 2004 

2002-2004 

Scenario 

Limiting 

Class I 

Area 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Base IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 41 

1 IRNP 0.323 2.0 0.275 1.000 0.228 1.000 0.248 2 

3 IRNP 0.183 0.0 0.177 0.000 0.154 0.000 0.173 0 

5 IRNP 0.322 2.0 0.256 0.000 0.219 1.000 0.254 2 

7 IRNP 0.182 0.0 0.177 0.000 0.155 0.000 0.169 0 

9 IRNP 0.314 2.0 0.252 0.000 0.213 1.000 0.248 2 

11 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161 0 

13 IRNP 0.315 2.0 0.246 0.000 0.218 1.000 0.243 2 

15 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160 0 

17 IRNP 0.326 2.0 0.243 0.000 0.218 1.000 0.243 2 

19 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163 0 

21 IRNP 0.324 2.0 0.241 0.000 0.215 1.000 0.241 2 

23 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165 0 

25 IRNP 0.326 2.0 0.245 0.000 0.207 1.000 0.241 2 

27 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165 0 

29 IRNP 0.325 2.0 0.239 0.000 0.198 1.000 0.240 2 

31 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.164 0 

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Table 5-16 Post-Control NOX Modeling Scenarios - Visibility Improvements 

Modeling Results 

2002 2003 2004 2002-2004 

Scenario 

Limiting 

Class I 

Area 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

1 IRNP 0.391 17 0.447 10 0.371 10 0.426 39 

3 IRNP 0.531 19 0.545 11 0.445 11 0.501 41 

5 IRNP 0.392 17 0.466 11 0.38 10 0.42 39 

7 IRNP 0.532 19 0.545 11 0.444 11 0.505 41 

9 IRNP 0.4 17 0.47 11 0.386 10 0.426 39 

11 IRNP 0.538 19 0.554 11 0.449 11 0.513 41 

13 IRNP 0.399 17 0.476 11 0.381 10 0.431 39 

15 IRNP 0.538 19 0.551 11 0.449 11 0.514 41 

17 IRNP 0.388 17 0.479 11 0.381 10 0.431 39 

19 IRNP 0.539 19 0.549 11 0.448 11 0.511 41 

21 IRNP 0.39 17 0.481 11 0.384 10 0.433 39 

23 IRNP 0.539 19 0.552 11 0.449 11 0.509 41 

25 IRNP 0.388 17 0.477 11 0.392 10 0.433 39 

27 IRNP 0.538 19 0.55 11 0.448 11 0.509 41 

29 IRNP 0.389 17 0.483 11 0.401 10 0.434 39 

31 IRNP 0.541 19 0.55 11 0.448 11 0.51 41 

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5.B Process Boilers 1 and 2 

Two natural gas and fuel oil fired process boilers require BART analysis. These boilers provide 

steam required to operate the taconite plant, as needed. The boilers are only permitted to burn 

natural gas and used oil. 

5.B.i Sulfur Dioxide Controls 

Sulfur in the fuel is the only source of SO2 emissions from these boilers. The boilers have low

emissions of SO2 due to the low sulfur content of the permitted fuels. 

5.B.i.a STEP 1 – Identify All Available Retrofit Control Technologies 

See Appendix F for a comprehensive list of all potential retrofit control technologies that were 

evaluated. Many emerging technologies have been identified that are not currently commercially 

available. A preliminary list of technologies was submitted to MDEQ on October 6, 2006 with the 

status of the technology as it was understood at that time. As work on this evaluation progressed, 

new information became apparent of the limited scope and scale of some of the technology 

applications. Appendix F presents the current status of the general availability of each technology. 

5.B.i.b STEP 2 – Eliminate Technically Infeasible Options 

Step 1 identified the available and applicable technologies for SO2 emission reduction. Within 

Step 1, the technical feasibility of the control option was also discussed and determined. The 

following describes retrofit SO2 control technologies that were identified as available and applicable 

in the original submittal and discusses aspects of those technologies that determine whether or not 

the technology is technically feasible for indurating furnaces. 

Wet Walled Electrostatic Precipitator (WWESP) 

An electrostatic precipitator (ESP) applies electrical forces to separate suspended particles from the 

flue gas stream. The suspended particles are given an electrical charge by passing through a high 

voltage DC corona region in which gaseous ions flow. The charged particles are attracted to and 

collected on oppositely charged collector plates. Particles on the collector plates are released by 

rapping and fall into hoppers for collection and removal. 

A wet walled electrostatic precipitator (WWESP) operates on the same collection principles as a dry 

ESP and uses a water spray to remove particulate matter from the collection plates. For SO2 removal, 

caustic is added to the water spray system, allowing the WWESP spray system to function as an SO2

absorber. 

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The SO2 control efficiency for a WWESP is dependent upon various process specific variables, such 

as SO2 flue gas concentration and fuel used. Based on the information contained within this report, a 

WWESP is considered a technically feasible technology for SO2 reduction for this BART analysis. 

Wet Scrubbing (High and Low Efficiency) 

Wet scrubbing, when applied to remove SO2, is generally termed flue-gas desulfurization (FGD). 

FGD utilizes gas absorption technology, the selective transfer of materials from a gas to a contacting 

liquid, to remove SO2 in the waste gas. Crushed limestone, lime or Caustic is used as scrubbing 

agents. 

Limestone scrubbing introduces limestone slurry with the flue gas in a spray tower. The sulfur 

dioxide is absorbed, neutralized, and partially oxidized to calcium sulfite and calcium sulfate. The 

overall reactions are shown in the following equations: 

CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2

CaSO3 •1/2 H2O + 3H2O + O2 → 2 CaSO4 •2 H2O 

Lime scrubbing is similar to limestone scrubbing in equipment and process flow, except that lime is a 

more reactive reagent than limestone. The reactions for lime scrubbing are as follows: 

Ca(OH)2 +SO2 → CaSO3• 1/2 H2O + 1/2 H2O 

Ca(OH)2 + SO2 + 1/2 O2 + H2O → CaSO4•2 H2O 

When that caustic (sodium hydroxide solution) is the scrubbing agent, the SO2 removal reactions are 

as follows: 

Na+ + OH- + SO2 + → Na2SO3

2Na+ + 2OH- + SO2 + → Na2SO3 + H2O 

Caustic scrubbing produces a liquid waste, and minimal equipment is needed as compared to lime or 

limestone scrubbers. If lime or limestone is used as the reagent for SO2 removal, additional 

equipment will be needed for preparing the lime/limestone slurry and collecting and concentrating 

the resultant sludge. Calcium sulfite sludge is watery; it is typically stabilized with fly ash for land 

filling. The calcium sulfate sludge is stable and easy to dewater. To produce calcium sulfate, an air 

injection blower is needed to supply the oxygen for the second reaction to occur. 

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The normal SO2 control efficiency range for SO2 scrubbers on coal fired utility boilers is 80% to 90% 

for low efficiency scrubbers and 90% and more for high efficiency scrubbers. The highest control 

efficiencies can be achieved when SO2 concentrations are the highest. The process boiler’s exhaust 

would not have a high SO2 concentration, so the low end of the efficiency range would be expected. 

Based on the information contained within this report, a wet scrubber is considered a technically 

feasible technology for SO2 reduction for this BART analysis. 

Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection) 

Dry sorbent injection (DSI) of lime/limestone is a post-combustion SO2 control technology in which 

pulverized lime or limestone is directly injected into the duct upstream of the fabric filter. Dry 

sorption of SO2 onto the lime or limestone particle occurs and the solid particles are collected with a 

fabric filter. Further SO2 removal occurs as the flue gas flows through the filter cake on the bags. The 

normal SO2 control efficiency range for dry SO2 scrubbers is 70% to 90 % for coal fired utility 

boilers. 

Based on the information contained within this report, DSI is considered a technically feasible 

technology for SO2 reduction for this BART analysis. 

Spray Dryer Absorption (SDA) 

Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO2 is 

absorbed by the slurry, forming CaSO3/CaSO4. The liquid-to-gas ratio is such that the water 

evaporates before the droplets reach the bottom of the tower. The dry solids are carried out with the 

gas and collected with a fabric filter. The normal SO2 control efficiency range for SDA is up to 90%. 

Based on the information contained with this report, SDA is considered a technically feasible 

technology for SO2 reduction for this BART analysis. 

Energy Efficiency Projects 

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption, 

which results in lower operating costs. Typically, reduced fuel usage translates into reduced 

pollution emissions. Due to the increased price of fuel, Tilden has already implemented energy 

efficiency projects. Each project carries its own fuel usage reductions and potentially emission 

reductions. Due to the uncertainty and generalization of this category, this will not be further 

evaluated in this report. However, it should be noted that Tilden will continue to evaluate and 

implement energy efficiency projects as they arise. 

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Alternate Fuels 

As described within the energy efficiency description, increased price of fuel has also pushed 

companies to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and 

gas. To achieve reduction of SO2 emissions through alternative fuel usage, the source must be 

capable of burning fuels with lower sulfur content than the existing fuels. The process boilers are 

only permitted to burn natural gas and used oil, which are both low in sulfur content. Therefore SO2

emission reductions through the use of alternate fuels are not an option and are not applicable to the 

process boilers. 

It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their 

option, not to direct the fuel choice.36 

Therefore, due to the limited fuel burning capabilities of the boilers and the fact that BART is not 

intended to mandate a fuel switch, alternative fuels as an air pollution control technology will not be 

further evaluated in this report. 

However, similar to energy efficiency, Tilden will continue to evaluate and implement alternate fuel 

usage as the feasibility arises. 

Coal Processing 

Since the process boilers are not capable of burning solid fuel, this option is not applicable for SO2

reductions. 

STEP 2 Conclusion 

Based upon the determination within Step 2, the remaining SO2 control technologies that are 

available and applicable to the process boilers are identified in Table 5-17. The technical feasibility 

as determined in Step 2 is also included in Table 5-17. 

 

36 Federal Register 70, no. 128 (July 6, 2005): 39164

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Table 5-17 Process Boiler SO2 Control Technology – Availability, Applicability, and Technical 

Feasibility 

SO2 Pollution Control 

Technology Available? Applicable? Technically Feasible? 

WWESP Yes Yes Yes 

Wet Scrubber Yes Yes Yes 

Spray Dry Absorption (SDA) Yes Yes Yes 

Dry Sorbent Injection (DSI) Yes Yes Yes 

Energy Efficiency Projects Yes Yes Project Dependent 

Alternative Fuels Yes Yes Yes - Not Required by 

BART 

5.B.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

Table 5-18 describes the expected control efficiency from each of the remaining feasible control 

options when burning liquid fuels. 

Table 5-18 Process Boiler SO2 Control Technology Effectiveness 

SO2 Pollution Control Technology Approximate Control Efficiency

SDA 90% 

Wet Scrubbing (High Efficiency) 80% 

WWESP 80% 

DSI 55% 

5.B.i.d STEP 4 – Evaluate Impacts and Document the Results 

As illustrated in Table 5-18 above, the technically feasible control remaining provide varying levels 

of emission reduction. Therefore, it is necessary to consider the economic, energy, and 

environmental impacts to better differentiate as presented below. 

Economic Impacts 

Table 5-19 details the expected costs associated with installation of the above alternatives on each 

stack. Equipment design was based on the maximum 24-hour emissions, vendor estimates, and U.S. 

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EPA cost models. Capital costs were based on a recent vendor quotation. The cost for that unit was 

scaled to each stack’s flow rate using the six-tenths-factor rule37 as shown in the following equation: 

Cost of equipment A = Cost of equipment B * (capacity of A/capacity of B)0.6

Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S. 

EPA models and factors. Operating costs were based on 93% utilization and 7650 operating hours 

per year, which is very conservative, considering these are backup boilers. Operating costs of 

consumable materials, such as electricity, water, and chemicals were established based on the U.S. 

EPA control cost manual38 and engineering experience, and were adjusted for the specific flow rates 

and pollutant concentrations. 

The detailed cost analysis is provided in Appendix A. 

Table 5-19 Process Boilers 1 and 2 SO2 Control Cost Summary 

Control Technology 

Installed 

Capital Cost 

($) 

Total 

Annual Cost

($/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

SDA $56,323,180 $8,640,697 $38,403,097 

Wet Scrubber $9,309,297 $1,489,576 $7,447,882 

WWESP $17,123,526 $3,146,592 $15,732,959 

DSI $32,010,048 $4,892,432 $35,581,325 

Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory 

bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective 

air pollution controls in the electric utility industry for large power plants are in the range $1,000 to 

$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an indirect 

measure of affordability for the electric utility industry used by USEPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost 

effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not 

afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the 

electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater 

 

37 M.S. Peters and K.D. Timmerhaus, December, 2002 Plant Design and Economics for Chemical Engineers, Fifth 

Edition. 

38 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition. 

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business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for 

proposing BART in lieu of developing industry and site specific data. 

The annualized pollution control cost value was used to determine whether or not additional impacts 

analyses would be conducted for the technology. If the control cost was less than a screening 

threshold established by MDEQ, then visibility modeling impacts, and energy and other impacts are 

evaluated. MDEQ set the screening level to eliminate technologies from requiring the additional 

impact analyses at an annualized cost of $12,000 per ton of controlled pollutant39. Therefore, all air 

pollution controls with annualized costs less than this screening threshold will be evaluated for 

visibility improvement, energy and other impacts. Based on the information presented in table 5-19, 

the annualized pollution control costs for all of the technologies are above the $12,000 threshold. 

Therefore, no additional analysis for visibility improvement, energy and other impacts is required. 

The BART guidance documents also present a calculation method for incremental control cost which 

is intended to present the incremental value of each technology as compared to the next most 

effective alternative. Since none of the technologies are cost effective, the incremental control cost 

is not applicable and is not presented in this analysis. 

Energy and Environmental Impacts 

Since none of the SO2 technologies are cost effective for the process boilers, the energy and non-air 

quality impacts were not assessed for the SO2 control equipment technologies for the process boilers. 

5.B.i.e STEP 5 – Evaluate Visibility Impacts 

As previously stated in section 4 of this document, states are required to consider the degree of 

visibility improvement resulting from the retrofit technology, in combination with other factors such 

as economic, energy and other non-air quality impacts, when determining BART for an individual 

source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this 

document. Since none of the SO2 technologies are cost effective for the process boilers, the visibility 

impacts were not evaluated. 

 

39 Michigan Department of Environmental Quality May 12, 2006 meeting. 

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5.B.ii Nitrogen Oxide Controls 

To be able to control NOx it is important to understand how NOx is formed. There are three 

mechanisms by which NOx production occurs: thermal, fuel and prompt NOx. 

• Fuel bound NOx is formed as nitrogen compounds in the fuel is oxidized in the combustion 

process. 

• Thermal NOx production arises from the thermal dissociation of nitrogen and oxygen 

molecules within the furnace. Combustion air is the primary source of nitrogen and oxygen. 

Thermal NOx production is a function of the residence time, free oxygen, and temperature. 

• Prompt NOx is a form of thermal NOx which is generated at the flame boundary. It is the 

result of reactions between nitrogen and carbon radicals generated during combustion. Only 

minor amounts of NOx are emitted as prompt NOx. 

The majority of NOx is emitted as NO. Minor amounts of NO2 are formed in the boiler. 

5.B.ii.a STEP 1 – Identify All Available Retrofit Control Technologies 

With the understanding of how NOx is formed, available and applicable control technologies were 

evaluated. See Appendix F for the current status of the availability and applicability of retrofit 

control technologies. Many emerging technologies have been identified that are not currently 

commercially available. A preliminary list of technologies was submitted to MDEQ on October 6, 

2006 with the status of the technology as it was understood at that time. As work on this evaluation 

progressed, new information became apparent of the limited scope and scale of some of the 

technology applications. Appendix F presents the current status of the general availability of each 

technology. 

5.B.ii.b STEP 2 – Eliminate Technically Infeasible Options 

Step 1 identified the available and applicable technologies for NOx emission reduction. Within 

Step 1, the technical feasibility of the control option was also discussed and determined. The 

following describes retrofit NOx control technologies that were identified as available and applicable 

in the original submittal and discusses aspects of those technologies that determine whether or not 

the technology is technically feasible for process boilers. 

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External Flue Gas Recirculation (EFGR) 

External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures 

thereby reducing thermal NOx formation. In an external flue gas recirculation system, flue gas is 

collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is 

mixed with the combustion air and this mixture is introduced into the burner. The addition of flue gas 

reduces the oxygen content of the “combustion air” (air + flue gas) in the burner. The lower oxygen 

level in the combustion zone reduces flame temperatures; which in turn reduces NOx emissions. For 

this technology to be effective, the combustion conditions must have the ability to be controlled at 

the burner tip. Due to the current configuration of the burners, Process boilers 1 and 2 do not have 

the capability of control at the burner tip. Therefore, this option is not technically feasible and will 

not be further evaluated in this report. 

Low NOx Burners (LNB) 

Low-NOx burner (LNB) technology utilizes advanced burner design to reduce NOx formation through 

the restriction of oxygen, flame temperature, and/or residence time. LNB is a staged combustion 

process that is designed to split fuel combustion into two zones. In the primary zone, NOx formation 

is limited by either one of two methods. Under staged air rich (high fuel) condition, low oxygen 

levels limit flame temperatures resulting in less NOx formation. The primary zone is then followed 

by a secondary zone in which the incomplete combustion products formed in the primary zone act as 

reducing agents. Alternatively, under staged fuel lean (low fuel) conditions, excess air will reduce 

flame temperature to reduce NOx formation. In the secondary zone, combustion products formed in 

the primary zone act to lower the local oxygen concentration, resulting in a decrease in NOx

formation. Low NOx burners typically achieve NOx emission reductions of 25% - 50% for process 

boilers. 

Based on the information contained within this report, LNB is considered a technically feasible 

technology for NOx reduction for this BART analysis. 

Overfire Air (OFA) 

Overfire air (OFA) diverts a portion of the total combustion air from the burners and injects it 

through separate air ports above the top level of burners. OFA is a NOx control technology typically 

used in boilers and is primarily geared to reduce thermal NOx. Staging of the combustion air creates 

an initial fuel-rich combustion zone for a cooler fuel-rich combustion zone. This reduces the 

production of thermal NOx by lowering peak combustion temperature and limiting the availability of 

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oxygen in the combustion zone where NOx is most likely to be formed. OFA is considered 

compatible with the LNB. The estimated NOx control efficiency for LNB with OFA is 50-67%. 

Based on the information contained within this report, OFA with LNB is considered a technically 

feasible technology for NOx reduction for this BART analysis. 

Induced Flue Gas Recirculation (IFGR) 

Induced flue gas recirculation burners, also called ultra low-NOx burners, combine the benefits of 

flue gas recirculation and low-NOx burner control technologies. The burner is designed to draw flue 

gas to dilute the fuel in order to reduce the flame temperature. These burners also utilize staged fuel 

combustion to further reduce flame temperature. The estimated NOx control efficiency for IFGR 

burners in high temperature applications is 50-75%. 

Based on the information contained within this report, IFGR is considered a technically feasible 

technology for NOx reduction for this BART analysis. 

Energy Efficiency Projects 

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption. 

Typically reduced fuel usage translates into reduced pollution emissions. An energy efficiency 

project could be preheat incoming make-up air or pellet feed. Each project is very dependent upon 

the fuel usage, process equipment, type of product and so many other variables. 

Due to the increased price of fuel, Tilden has already implemented energy efficiency projects. Each 

project carries its own fuel usage reductions and potential emission reductions. Due to the 

uncertainty and generalization of this category, this will not be further evaluated in this report. 

However, it should be noted that Tilden will continue to evaluate and implement energy efficiency 

projects as they arise. 

Alternate Fuels 

As described within the energy efficiency description, increased price of fuel has also pushed 

companies to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and 

gas. To achieve reduction of NOx emissions through alternative fuel usage, the source must be 

currently burning a high NOx emitting fuel relative to other fuels. The boilers are only capable of 

burning natural gas and distillate oil. Therefore the use of alternate fuels is not a viable option for 

the process boilers and will not be considered further in this analysis. 

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It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their 

option, not to direct the fuel choice.40 

Therefore, due to the limited boiler fuel capabilities and the fact that BART is not intended to 

mandate a fuel switch, alternative fuels as an air pollution control technology will not be further 

evaluated in this report 

However, similar to energy efficiency, Tilden will continue to evaluate and implement alternate fuel 

usage as the feasibility arises. 

Low Excess Air 

Operating a boiler with low excess air is a method to minimize peak flame temperature and excess 

oxygen which therefore minimizes the production of NOx. Operating a boiler with low excess air 

also optimizes the fuel efficiency as less air is heated up in the combustion chamber. 

As previously stated, the increased price of fuel has pushed companies to evaluate fuel usage. 

Therefore, the boilers at Tilden are operated with low excess air within the constraints of the boilers. 

Therefore, low excess air will not be further evaluated in this report. However, similar to energy 

efficiency and alternate fuels, the facility will continue to evaluate boiler optimization including 

operating at low excess air. 

Reburning 

Reburning is a technology used with solid fuels. Process boilers are not cable of burning solid fuel, 

therefore this technology will not be further evaluated. 

Post Combustion Controls 

NOx can be controlled using add-on systems located downstream of the combustion process. The 

two main techniques in commercial service include the selective non catalytic reduction (SNCR) 

process and the selective catalytic reduction (SCR) process. There are a number of different process 

systems in each of these categories of control techniques. 

In addition to these treatment systems, there are a large number of other processes being developed 

and tested on the market. These approaches involve innovative techniques of chemically reducing, 

 

40 Federal Register 70, no. 128 (July 6, 2005): 39164

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absorbing, or adsorbing NOx downstream of the combustion chamber. Examples of these alternatives 

are nonselective catalytic reduction (NSCR) and Low Temperature Oxidation (LTO). Each of these 

alternatives is described below. 

Non-Selective Catalytic Reduction (NSCR) 

A non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas 

treatment system. NSCR catalyst is very sensitive to poisoning; therefore, NSCR is applied primarily 

in natural gas combustion applications. 

NSCR is often referred to as “three-way conversion” catalyst because it simultaneously reduces NOx, 

unburdened hydrocarbons (UBH), and carbon monoxide (CO). Typically, NSCR can achieve NOx

emission reductions of 90 percent. In order to operate properly, the combustion process must be near 

stoichiometric conditions. Under this condition, in the presence of a catalyst, NOx is reduced by CO, 

resulting in nitrogen (N2) and carbon dioxide (CO2). The most important reactions for NOx removal 

are: 

2CO + 2NO → 2CO2 + N2 (1) 

[UBH] + NO → N2 + CO2 + H2O (2) 

NSCR catalyst has been applied primarily in clean combustion applications. This is due in large part 

to the catalyst being very sensitive to poisoning, making it infeasible to apply this technology to 

liquid fuels. Therefore, this technology will not be further evaluated in this report. 

Selective Catalytic Reduction (SCR) and Regenerative Selective Catalytic Reduction 

(R-SCR) 

SCR is a post-combustion NOx control technology in which ammonia (NH3) is injected into the flue 

gas stream in the presence of a catalyst. NOx is removed through the following chemical reaction:

4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (1) 

2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O (2) 

A catalyst bed containing metals in the platinum family is used to lower the activation energy 

required for NOx decomposition. SCR requires a temperature range of about 570°F – 850°F for a 

normal catalyst. At temperature exceeding approximately 670oF, the oxidation of ammonia begins to 

become significant. At low temperatures, the formation of ammonium bisulfate causes scaling and 

corrosion problems. 

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A high temperature zeolite catalyst is also available; it can operate in the 600 °F – 1000°F 

temperature range. However, these catalysts are very expensive. 

Ammonia slip from the SCR system is usually less than 3 to 5 ppm. The emission of ammonia 

increases during load changes due to the instability of the temperature in the catalyst bed as well as at 

low loads because of the low gas temperature. 

Regenerative Selective Catalytic Reduction (R-SCR) applies the Selective Catalytic Reduction (SCR) 

control process as described below with a preheat process step to reheat the flue gas stream up to 

SCR catalyst operating temperatures. The preheating process combines use of a thermal heat sink 

(packed bed) and a duct burner. The thermal sink recovers heat from the hot gas leaving the R-SCR 

and then transfers that heat to gas entering the R-SCR. The duct burner is used to complete the 

preheating process. R-SCR operates with several packed bed/SCR reactor vessels. Gas flow 

alternates between vessels. Each of the vessels alternates between preheating/treating and heat 

recovery. 

The benefits of R-SCR are: 

• Its high energy efficiency allows it to be used after SO2 and particulate controls. 

• R-SCR has a thermal efficiency of 90% - 95% vs. standard heat exchangers which have a 

thermal efficiency of 60% to 70%. 

• Application of R-SCR after SO2 and PM controls significantly reduces the potential for 

problems associated with plugging and catalyst poisoning and deactivation. 

To date, R-SCR has been applied to wood-fired utility boilers. Application of this technology has 

not been applied to liquid and natural gas fired boilers. Using RSCR would require research, test 

runs, and extended trials to identify potential issues related to catalyst selection, and impacts on plant 

systems. It is not reasonable to assume that vendor guarantees of performance would be forthcoming 

in advance of a demonstration project. The timeline required to perform such a demonstration project 

would likely be two years to develop and agree on the test plan, obtain permits for the trial, 

commission the equipment for the test runs, perform the test runs for a reasonable study period, and 

evaluate and report on the results. The results would not be available within the time window for 

establishing emission limits to be incorporated in the state implementation plan (SIP) by December 

2007. 

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Recalling U.S. EPA’s intention regarding “available” technologies to be considered for BART, as 

mentioned in Section 2.B, facility owners are not expected to undergo extended trials in order to 

learn how to apply a control technology to a completely new and significantly different source type. 

Therefore, R-SCR is not considered to be technically feasible, and will not be analyzed further in this 

BART analysis. 

SCR with reheat through a conventional duct burner (rather than using a regenerative heater) has 

been successfully implemented more widely and in higher airflow applications and will be carried 

forward in this analysis as available and applicable technology that is reasonably expected to be 

technically feasible. 

Selective Non-Catalytic Reduction (SNCR) 

In the SNCR process, urea or ammonia-based chemicals are injected into the flue gas stream to 

convert NO to molecular nitrogen, N2, and water. SNCR control efficiency is typically 25% - 60%. 

Without a catalyst, the reaction requires a high temperature range to obtain activation energy. The 

relevant reactions are as follows: 

NO + NH3 + 1⁄4O2 → N2 + 3/2H2O (1) 

NH3 + 1⁄4O2 → NO + 3/2H2O (2) 

At temperature ranges of 1470 to 1830°F reaction (1) dominates. At temperatures above 2000°F, 

reaction (2) will dominate. 

Based on the information contained within this report, a SNCR is considered a technically feasible 

technology for NOx reduction for this BART analysis. 

Low Temperature Oxidation (LTO) 

The LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including 

NOx. In the system, the NOx in the flue gas is oxidized to form nitrogen pentoxide (equations 1, 2, 

and 3). The nitrogen pentoxide forms nitric acid vapor as it contacts the water vapor in the flue gas 

(4). Then the nitric acid vapor is absorbed as dilute nitric acid and is neutralized by the sodium 

hydroxide or lime in the scrubbing solution forming sodium nitrate (5) or calcium nitrate. The 

nitrates are removed from the scrubbing system and discharged to an appropriate water treatment 

system. Commercially available LTO systems include Tri-NOx® and LoTOx®. 

NO + O3 → NO2 + O2 (1) 

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NO2 + O3 → NO3 + O2 (2) 

NO3 + NO2 → N2O5 (3) 

N2O5 + H2O → 2HNO3 (4) 

HNO3 + NaOH → NaNO3 + H2O (5) 

Low Temperature Oxidation (Tri-NOx

®

) 

This technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO2 in a 

primary scrubbing stage. Then NO2 is removed through caustic scrubbing in a secondary stage. The 

reactions are as follows: 

O3 + NO → O2 + NO2

(1)

2NaOH + 2NO2 + 1⁄2 O2 → 2NaNO3 + H2O (2)

Tri-NOx

®

 is a multi-staged wet scrubbing process in industrial use. Several process columns, each 

assigned a separate processing stage, are involved. In the first stage, the incoming material is 

quenched to reduce its temperature. The second, oxidizing stage, converts NO to NO2. Subsequent 

stages reduce NO2 to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NOx

®

 is 

typically applied at small to medium sized sources with high NOx concentration in the exhaust gas 

(1,000 ppm NOx). 

Low Temperature Oxidation (LoTOx®

) 

BOC Gases’ Lo-TOx® is an example of a version of an LTO system. LoTOx® technology uses ozone 

to oxidize NO to NO2 and NO2 to N2O5 in a wet scrubber (absorber). This can be done in the same 

scrubber used for particulate or sulfur dioxide removal, The N2O5 is converted to HNO3 in a 

scrubber, and is removed with lime or caustic. Ozone for LoTOx®

 is generated on site with an 

electrically powered ozone generator. The ozone generation rate is controlled to match the amount 

needed for NOx control. Ozone is generated from pure oxygen. In order for LoTOx® to be 

economically feasible, a source of low cost oxygen must be available from a pipeline or on site 

generation. 

In addition, only two of BOC’s LoTOx® installations are fully installed and operational applications. 

Therefore, although this is an emerging technology, the limited application means that it has not been 

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demonstrated to be an effective technology in widespread application. Consequently, the technical 

feasibility of LTO as technically infeasible for this application and will not be evaluated further. 

Step 2 Conclusion 

Based upon the determination within Step 2, the remaining NOx control technologies that are 

available and applicable to the process boilers are identified in Table 5-20. The technical feasibility 

as determined in Step 2 is also included in Table 5-20.

Table 5-20 Process Boilers 1 and 2 NOx Control Technology – Availability, Applicability and 

Technical Feasibility 

NOx Pollution Control Technology Available? Applicable?

Technically 

Feasible? 

External Flue Gas Recirculation (EFGR) Yes Yes No 

Low-NOx Burners (LNB) Yes Yes Yes 

Low NOx Burners with Overfired Air 

(LNB/OFA) Yes Yes Yes 

Induced Flue Gas Recirculation (IFGR) Yes Yes Yes 

Low Excess Air Yes Yes 

Yes 

(already 

implemented) 

Reburning Yes Yes No 

Energy Efficiency Projects Yes Yes Project 

Dependent 

Alternative Fuels Yes Yes 

Yes 

- Not Required 

by BART 

Non-Selective Catalytic Reduction (NSCR) Yes Yes Yes 

Selective Catalytic Reduction (SCR) Yes Yes Yes 

Regenerative SCR Yes Yes No 

Selective Non-Catalytic Reduction (SNCR) Yes Yes Yes 

Low Temperature Oxidation (LTO) Yes No No 

5.B.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

Table 5-21 describes the expected control efficiency from the remaining technically feasible control 

option as identified in Step 2. 

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Table 5-21 Process Boiler NOx Control Technology Effectiveness 

NOx Pollution Control Technology 

Approximate Control 

Efficiency 

Selective Catalytic Reduction (SCR) with 

Reheat 80% 

Low NOX Burner / Flue Gas Recirculation 

(LNB/FGR) 75% 

Regenerative Selective Catalytic Reduction 

(R-SCR) 70% 

Low NOX Burner / Overfire Air (LNB/OFA) 67% 

Low NOX Burner (LNB) 50% 

Selective Non-Catalytic Reduction (SNCR) 50% 

5.B.ii.d STEP 4 – Evaluate Impacts and Document the Results 

Table 5-22 details the expected costs associated with installation of NOx controls. Capital costs were 

calculated based on the maximum 24-hour emissions, U.S. EPA cost models, and vendor estimates. 

Vendor estimates for capital costs based on a specific flow rate were scaled to each stack’s flow rate 

using the 6/10 power law to account for the economy of scale. Operating costs were based on 93% 

utilization and 7650 operating hours per year, which is extremely conservative, since they are backup 

boilers. Operating costs were proportionally adjusted to reflect site specific flow rates and pollutant 

concentrations. 

After a tour of the facility and discussions with facility management, it was determined the space 

surrounding the boilers is congested and the area surrounding the building supports vehicle and rail 

traffic to transport materials to and from the building. A site-specific estimate for site-work, 

foundations, and structural steel was added based upon the facility site to arrive at the total retrofit 

installed cost of the control technology. See Appendix C for a site plan of the facility. Additionally, 

the structural design of the existing building would not support additional equipment on the roof. The 

detailed cost analysis is provided in Appendix A. 

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Table 5-22 Process Boiler NOx Control Cost Summary 

Control 

Technology 

Installed 

Capital Cost 

($) 

Total Annual 

Cost 

($/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

Incremental 

Control Cost 

($/ton) 

SCR with Reheat** $6,317,686 $2,528,225 $39,888 NA 

LNB/FGR $2,190,300 $270,904 $4,559 Lowest 

R-SCR** $16,117,290 $3,303,391 $59,563 NA 

LNB/OFA $3,031,714 $390,751 $7,361 NA 

LNB $1,320,909 $286,968 $7,244 NA 

SNCR $1,501,420 $426,135 $10,760 NA* 

* Control efficiency is equal to the option with the lowest cost per ton, LNB at 50%. 

** SCR and R-SCR were eliminated from further consideration due to high cost per ton.

Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory 

bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective 

air pollution controls in the electric utility industry for large power plants are in the range $1,000 to 

$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an indirect 

measure of affordability for the electric utility industry used by USEPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost 

effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not 

afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the 

electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater 

business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for 

proposing BART in lieu of developing industry and site specific data. 

The annualized pollution control cost value was used to determine whether or not additional impacts 

analyses would be conducted for the technology. If the control cost was less than a screening 

threshold established by MDEQ, then visibility modeling impacts, and energy and other impacts are 

evaluated. MDEQ set the screening level to eliminate technologies from requiring the additional 

impact analyses at an annualized cost of $12,000 per ton of controlled pollutant41. Therefore, all air 

pollution controls with annualized costs less than this screening threshold will be evaluated for 

visibility improvement, energy and other impacts. 

 

41 Michigan Department of Environmental Quality May 12, 2006 meeting. 

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The incremental control cost listed in Table 5-22 represents the incremental value of each technology 

as compared to the technology with the next highest level of control. The cost of control and 

incremental cost of SCR with reheat, R-SCR and SNCR are not reasonable. The magnitude of the 

capital and operating costs of remaining alternatives is also significant and may impact the viability 

of continued operation. 

Energy and Environmental Impacts 

The energy and non-air quality impacts for LNB and LNB with IFGR are presented in Table 5-23. 

Because the cost of the remaining NOx control technologies for the process boilers is so high and 

does not meet a reasonable definition of cost effective technology, these technologies are removed 

from further consideration in this analysis. 

Table 5-23 Process Boiler NOx Control Technology – Other Impacts Assessment 

Control 

Option Energy Impacts Other Impacts 

LNB - Minimal energy impacts - Increase in CO emissions 

- Potential for steam tube wastage due to 

longer combustion flame 

LNB/OFA - Minimal energy impacts - Increase in CO emissions 

- Potential for steam tube wastage due to 

longer combustion flame 

LNB/FGR - Minimal energy impacts. - Increase in CO emissions 

- Potential for steam tube wastage due to 

longer combustion flame. 

5.B.ii.e STEP 5 – Evaluate Visibility Impacts 

As previously stated in section 4 of this document, states are required to consider the degree of 

visibility improvement resulting from the retrofit technology, in combination with other factors such 

as economic, energy and other non-air quality impacts, when determining BART for an individual 

source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this 

document. This section of the report evaluates the visibility impacts of BART NOX control and the 

resulting degree of visibility improvement. 

Predicted 24-Hour Maximum Emission Rates 

Consistent with the use of the highest daily emissions for baseline, or pre-BART, visibility impacts, 

the post-BART emissions to be used for the visibility impacts analysis should also reflect a 

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maximum 24-hour average project emission rate. In the visibility impacts NOX modeling analysis, 

the emissions from the sources undergoing a full BART NOx analysis were adjusted to reflect the 

projected 24-hour maximum NOx emission rate when applying the control technologies that met the 

threshold requirements of steps 1 – 4. The emissions from all other Subject-to-BART sources were 

not changed. Table 5-24 provides a summary of the modeled 24-hour maximum emission rates and 

their computational basis for the evaluated NOx control technologies. Table 5-25 provides a 

summary of the modeling input data. 

Post-BART Visibility Impacts Modeling Results 

Results of the post-BART visibility impacts modeling for NOX for the process boilers are presented 

in Table 5-26. The results summarize 98th percentile dV value and the number of days the facility 

contributes more than a 0.5 dV of visibility impairment at each of the Class I areas. The comparison 

of the post-BART modeling scenarios to the baseline conditions is presented in Table 5-27. 

Visibility impacts with SO2 controls are presented in section 6. 

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Table 5-27 Process Boiler Post-BART Modeling Scenarios 

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

Base SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% Base SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% Base SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

8 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

9 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

10 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

11 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

12 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

13 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

14 SVP0051981 EUKILN1 Wet Scrubber Good Combustion 80% 40.0 0.0% 

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Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

SVP0051711 Practice 80% 14.6 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

15 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

16 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

17 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

18 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

19 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

20 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

21 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

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Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

22 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

23 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

24 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

25 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

26 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

27 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

28 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

29 SVP0051981 EUKILN1 Low Sulfur Coal SCR w/reheat 0.0% 200.2 80% 

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Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

SVP0051711 Natural Gas 72.8 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

30 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

31 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

Table 5-28 Process Boiler Post-BART NOx Modeling Scenarios - Modeling Input Data 

Control Scenario SV # Emission Unit Stack Easting 

(utm) 

Stack Northing 

(utm) 

Height of 

Opening from 

Ground 

(ft) 

Base Elevation 

of Ground 

(ft) 

Stack length, 

width, or 

Diameter 

(ft) 

Flow Rate at exit 

(acfm) 

All Scenarios SVP0051981 SVP0051711 EUKILN1 46.44084994 

46.44075383 

-87.653 

40738 

-87.651 

32336 

240 160 

1474 

19.3 13.5 

842,000 306,000 

 SVP0082951 EUDRYER1 46.44075383 -87.651 32336 119 1474 6.3 57,135 

SVBLR.STK.

T1 

EUBOILER1 EUBOILER2 46.44091784 -87.654 12418 130 1474 7.5 192,000 

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Table 5-29 Process Boiler Post-BART NOx Modeling Scenarios - Visibility Modeling Result

Modeling Results 

2002 2003 2004 

2002-2004 

Scenario 

Limiting 

Class I 

Area 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Base IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 41 

8 IRNP 0.714 19.0 0.711 11.000 0.583 11.000 0.653 41 9 IRNP 0.314 2.0 0.252 0.000 0.213 1.000 0.248 2 

10 IRNP 0.618 15.0 0.607 10.000 0.527 8.000 0.590 33 11 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161 0 12 IRNP 0.719 19.0 0.693 10.000 0.592 9.000 0.654 38 13 IRNP 0.315 2.0 0.246 0.000 0.218 1.000 0.243 2 14 IRNP 0.627 15.0 0.608 9.000 0.544 8.000 0.585 32 15 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160 0 16 IRNP 0.722 19.0 0.673 10.000 0.605 9.000 0.656 38 17 IRNP 0.326 2.0 0.243 0.000 0.218 1.000 0.243 2 18 IRNP 0.626 15.0 0.605 9.000 0.542 8.000 0.596 32 19 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163 0 20 IRNP 0.734 19.0 0.692 10.000 0.605 10.000 0.654 39 21 IRNP 0.324 2.0 0.241 0.000 0.215 1.000 0.241 2 22 IRNP 0.625 15.0 0.602 9.000 0.291 3.000 0.588 27 23 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165 0 24 IRNP 0.727 19.0 0.689 10.000 0.603 10.000 0.656 39 25 IRNP 0.326 2.0 0.245 0.000 0.207 1.000 0.241 2 26 IRNP 0.623 15.0 0.605 9.000 0.550 8.000 0.597 32 27 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165 0 28 IRNP 0.704 19.0 0.672 10.000 0.606 9.000 0.657 38 29 IRNP 0.325 2.0 0.239 0.000 0.198 1.000 0.240 2 30 IRNP 0.613 14.0 0.614 9.000 0.542 8.000 0.588 31 31 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.164 0 

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Table 5-30 Process Boiler Post-BART NOx Modeling Scenarios – Comparison of Visibility Modeling Results t

Results 

Modeling Results 

2002 2003 2004 2002-2004 

Scenario 

Limiting 

Class I 

Area 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

8 IRNP 0 0 0.011 0 0.016 0 0.021 0 9 IRNP 0.4 17 0.47 11 0.386 10 0.426 39 

10 IRNP 0.096 4 0.115 1 0.072 3 0.084 8 11 IRNP 0.538 19 0.554 11 0.449 11 0.513 41 12 IRNP -0.005 0 0.029 1 0.007 2 0.02 3 13 IRNP 0.399 17 0.476 11 0.381 10 0.431 39 14 IRNP 0.087 4 0.114 2 0.055 3 0.089 9 15 IRNP 0.538 19 0.551 11 0.449 11 0.514 41 16 IRNP -0.008 0 0.049 1 -0.006 2 0.018 3 17 IRNP 0.388 17 0.479 11 0.381 10 0.431 39 18 IRNP 0.088 4 0.117 2 0.057 3 0.078 9 19 IRNP 0.539 19 0.549 11 0.448 11 0.511 41 20 IRNP -0.02 0 0.03 1 -0.006 1 0.02 2 21 IRNP 0.39 17 0.481 11 0.384 10 0.433 39 22 IRNP 0.089 4 0.12 2 0.308 8 0.086 14 23 IRNP 0.539 19 0.552 11 0.449 11 0.509 41 24 IRNP -0.013 0 0.033 1 -0.004 1 0.018 2 25 IRNP 0.388 17 0.477 11 0.392 10 0.433 39 26 IRNP 0.091 4 0.117 2 0.049 3 0.077 9 27 IRNP 0.538 19 0.55 11 0.448 11 0.509 41 28 IRNP 0.01 0 0.05 1 -0.007 2 0.017 3 29 IRNP 0.389 17 0.483 11 0.401 10 0.434 39 30 IRNP 0.101 5 0.108 2 0.057 3 0.086 10 31 IRNP 0.541 19 0.55 11 0.448 11 0.51 41 

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5.C Line 1 Dryer 

The Line 1 Dryer requires a BART analysis. This Line 1 Dryer includes a combustion box in which 

natural gas and used oil is burned as fuel. The flue gas from the combustion box flows into a rotary 

dryer that repeatedly tumbles wet taconite ore concentrate through the flue gas stream to reduce the 

amount of entrained moisture in the taconite ore concentrated. The particulate emissions from the 

dryer are controlled by cyclones and impingement scrubbers in series. The dryer is only permitted to 

use natural gas and used oil for fuel. 

5.C.i Sulfur Dioxide Controls 

Sulfur in the fuel is the only source of SO2 emissions from the dryer. The Line 1 Dryer has low

emissions of SO2 due to the low sulfur content of the permitted fuels. In addition, collateral SO2

reductions occur within the existing impingment scrubbers, and therefore the existing scrubber is 

considered a low-efficiency SO2 scrubber. 

5.C.i.a STEP 1 – Identify All Available Retrofit Control Technologies 

See Appendix F for a comprehensive list of all potential retrofit control technologies that were 

evaluated. Many emerging technologies have been identified that are not currently commercially 

available. A preliminary list of technologies was submitted to MDEQ on October 6, 2006 with the 

status of the technology as it was understood at that time. As work on this evaluation progressed, 

new information became apparent of the limited scope and scale of some of the technology 

applications. Appendix F presents the current status of the general availability of each technology. 

5.C.i.b STEP 2 – Eliminate Technically Infeasible Options 

Step 1 identified the available and applicable technologies for SO2 emission reduction. Within 

Step 1, the technical feasibility of the control option was also discussed and determined. The 

following describes retrofit SO2 control technologies that were identified as available and applicable 

in the original submittal and discusses aspects of those technologies that determine whether or not 

the technology is technically feasible for indurating furnaces. 

Wet Walled Electrostatic Precipitator (WWESP) 

An electrostatic precipitator (ESP) applies electrical forces to separate suspended particles from the 

flue gas stream. The suspended particles are given an electrical charge by passing through a high 

voltage DC corona region in which gaseous ions flow. The charged particles are attracted to and 

collected on oppositely charged collector plates. Particles on the collector plates are released by 

rapping and fall into hoppers for collection and removal. 

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A wet walled electrostatic precipitator (WWESP) operates on the same collection principles as a dry 

ESP and uses a water spray to remove particulate matter from the collection plates. For SO2 removal, 

caustic is added to the water spray system, allowing the WWESP spray system to function as an SO2

absorber. 

The SO2 control efficiency for a WWESP is dependent upon various process specific variables, such 

as SO2 flue gas concentration and fuel used. Since Line 1 Dryer currently employs a wet scrubber 

designed for removal of particulate matter, the scrubber also performs as a low efficiency SO2 wet 

scrubber. The addition of a WWESP would act as a polishing SO2 control device and would 

experience reduced control efficiency due to lower SO2 inlet concentrations. 

Based on the information contained within this report, a WWESP is considered a technically feasible 

technology for SO2 reduction for this BART analysis. 

Wet Scrubbing (High and Low Efficiency) 

Wet scrubbing, when applied to remove SO2, is generally termed flue-gas desulfurization (FGD). 

FGD utilizes gas absorption technology, the selective transfer of materials from a gas to a contacting 

liquid, to remove SO2 in the waste gas. Crushed limestone, lime or Caustic is used as scrubbing 

agents. 

Limestone scrubbing introduces limestone slurry with the flue gas in a spray tower. The sulfur 

dioxide is absorbed, neutralized, and partially oxidized to calcium sulfite and calcium sulfate. The 

overall reactions are shown in the following equations: 

CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2

CaSO3 •1/2 H2O + 3H2O + O2 → 2 CaSO4 •2 H2O 

Lime scrubbing is similar to limestone scrubbing in equipment and process flow, except that lime is a 

more reactive reagent than limestone. The reactions for lime scrubbing are as follows: 

Ca(OH)2 +SO2 → CaSO3• 1/2 H2O + 1/2 H2O 

Ca(OH)2 + SO2 + 1/2 O2 + H2O → CaSO4•2 H2O 

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When that caustic (sodium hydroxide solution) is the scrubbing agent, the SO2 removal reactions are 

as follows: 

Na+ + OH- + SO2 + → Na2SO3

2Na+ + 2OH- + SO2 + → Na2SO3 + H2O 

Caustic scrubbing produces a liquid waste, and minimal equipment is needed as compared to lime or 

limestone scrubbers. If lime or limestone is used as the reagent for SO2 removal, additional 

equipment will be needed for preparing the lime/limestone slurry and collecting and concentrating 

the resultant sludge. Calcium sulfite sludge is watery; it is typically stabilized with fly ash for land 

filling. The calcium sulfate sludge is stable and easy to dewater. To produce calcium sulfate, an air 

injection blower is needed to supply the oxygen for the second reaction to occur. 

The normal SO2 control efficiency range for SO2 scrubbers on coal fired utility boilers is 80% to 90% 

for low efficiency scrubbers and 90% and more for high efficiency scrubbers. The highest control 

efficiencies can be achieved when SO2 concentrations are the highest. The dryer and process boiler’s 

exhaust would not have a high SO2 concentration, so the low end of the efficiency range would be 

expected. 

As stated in the beginning of this section, a wet scrubber is currently in place on the Line 1 Dryer and 

is believed to remove approximately 30% of the SO2 in the exhaust. The addition of an additional 

SO2 scrubber would act as a polishing SO2 control device and would experience reduced control

efficiency due to lower SO2 inlet concentrations. 

A Minnesota taconite facility has evaluated modifying the exiting scrubber on the kiln exhaust, 

which is similar to the dryer exhaust stream, to determine if improvements to SO2 removal could be 

accomplished. The concentration of caustic in the scrubbing water was increased to a pH of 8 for 

several hours and stack sampling was performed to evaluate the change in SO2 emissions. The SO2

emissions were not reduced. The materials of construction of the existing scrubbers would not 

withstand a higher pH than 7 or 8. An engineering study would be required to evaluate more 

extensive redesign of the existing scrubbers, such as modifying the spray, increasing the contact 

time, recirculating the scrubber water, and retrofitting to allow use of a much higher pH. 

Quantifying the likelihood and magnitude of potential improvements to SO2 control would not be 

possible without a study, so this option could not be selected as BART. 

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Based on the information contained within this report, a wet scrubber is considered a technically 

feasible technology for SO2 reduction for this BART analysis. 

Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection) 

Dry sorbent injection (DSI) of lime/limestone is a post-combustion SO2 control technology in which 

pulverized lime or limestone is directly injected into the duct upstream of the fabric filter. Dry 

sorption of SO2 onto the lime or limestone particle occurs and the solid particles are collected with a 

fabric filter. Further SO2 removal occurs as the flue gas flows through the filter cake on the bags. The 

normal SO2 control efficiency range for dry SO2 scrubbers is 70% to 90 % for coal fired utility 

boilers. 

The Line 1 Dryer flue gas stream is high in water content and is exhausted at or near their dew 

points. Exhaust gases leaving the Line 1 Dryer is currently treated for removal of particulate matter 

using a wet scrubber. Due to the high water content in the dryer flue gas, the baghouse filter cake 

would become saturated with moisture and plug both the filters and the dust removal system. 

Although this may be an available and applicable control option, it is not technically feasible due to 

the high moisture content and will not be further evaluated in this report for the Line 1 Dryer. 

Spray Dryer Absorption (SDA) 

Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO2 is 

absorbed by the slurry, forming CaSO3/CaSO4. The liquid-to-gas ratio is such that the water 

evaporates before the droplets reach the bottom of the tower. The dry solids are carried out with the 

gas and collected with a fabric filter. The normal SO2 control efficiency range for SDA is up to 90%. 

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The Line 1 Dryer flue gas stream is high in water content and is exhausted at or near their dew 

points. Gases leaving the dryer are currently treated for removal of particulate matter using a wet 

scrubber. The exhaust temperature is typically in the range of 100 oF to 150 oF and is saturated with 

water. For comparison, a utility boiler exhaust operates at 350 o

F or higher and is not saturated with 

water. Under dryer conditions, the baghouse filter cake would become saturated with moisture and 

plug both the filters and the dust removal system. Although this may be an available and applicable 

control option, it is not technically feasible due to the high moisture content and will not be further 

evaluated in this report. 

Energy Efficiency Projects 

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption, 

which results in lower operating costs. Typically, reduced fuel usage translates into reduced 

pollution emissions. Due to the increased price of fuel, Tilden has already implemented energy 

efficiency projects. Each project carries its own fuel usage reductions and potentially emission 

reductions. Due to the uncertainty and generalization of this category, this will not be further 

evaluated in this report. However, it should be noted that Tilden will continue to evaluate and 

implement energy efficiency projects as they arise. 

Alternate Fuels 

As described within the energy efficiency description, increased price of fuel has also pushed 

companies to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and 

gas. To achieve reduction of SO2 emissions through alternative fuel usage, the source must be 

capable of burning fuels with lower sulfur content than the existing fuels. The Line 1 Dryer is only 

permitted to burn natural gas and used oil, which are both low in sulfur content. Therefore SO2

emission reductions through the use of alternate fuels are not an option and are not applicable to the 

Line 1 Dryer. 

It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their 

option, not to direct the fuel choice.42 

 

42 Federal Register 70, no. 128 (July 6, 2005): 39164

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Therefore, due to the limited fuel burning capabilities of the Line 1 Dryer and the fact that BART is 

not intended to mandate a fuel switch, alternative fuels as an air pollution control technology will not 

be further evaluated in this report. 

However, similar to energy efficiency, Tilden will continue to evaluate and implement alternate fuel 

usage as the feasibility arises. 

Coal Processing 

Since the Line 1 Dryer is not permitted to burn solid fuel, this option is not applicable for SO2

reductions. 

STEP 2 Conclusion 

Based upon the determination within Step 2, the remaining SO2 control technologies that are 

available and applicable to the Line 1 Dryer are identified in Table 5-29. The technical feasibility as 

determined in Step 2 is also included in Table 5-29. 

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Table 5-29 Line 1 Dryer SO2 Control Technology – Availability, Applicability, and Technical 

Feasibility 

SO2 Pollution Control 

Technology Available? Applicable? Technically Feasible? 

WWESP Yes Yes Yes 

Wet Scrubber Yes Yes Yes 

Spray Dry Absorption (SDA) Yes Yes No 

Dry Sorbent Injection (DSI) Yes Yes No 

Energy Efficiency Projects Yes Yes Project Dependent 

Alternative Fuels Yes Yes Yes – Not required by 

BART 

5.C.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

Table 5-30 describes the expected control efficiency from each of the remaining feasible control 

options for the Line 1 Dryer. 

Table 5-30 Line 1 Dryer SO2 Control Technology Effectiveness 

SO2 Pollution Control Technology Approximate Control Efficiency

Wet Scrubbing (High Efficiency) 80% 

Wet Walled Electrostatic Precipitator (WWESP) 80% 

5.C.i.d STEP 4 – Evaluate Impacts and Document the Results 

As illustrated in Table 5-30 above, the technically feasible control remaining provide varying levels 

of emission reduction. Therefore, it is necessary to consider the economic, energy, and 

environmental impacts to better differentiate as presented below. 

Economic Impacts 

Table 5-31 details the expected costs associated with installation of a WWESP and wet scrubber. 

Equipment design was based on the maximum 24-hour emissions, vendor estimates, and U.S. EPA 

cost models. Capital costs were based on a recent vendor quotation. The cost for that unit was 

scaled to each stack’s flow rate using the six-tenths-factor rule as shown in the following equation: 

 Cost of equipment A = Cost of equipment B * (capacity of A/capacity of B)0.6

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Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S. 

EPA models and factors. Operating costs were based on 100% utilization and 7650 operating hours 

per year, which is very conservative based on historic operating data. Operating costs of consumable 

materials, such as electricity, water, and chemicals were established based on the U.S. EPA control 

cost manual43 and engineering experience, and were adjusted for the specific flow rates and pollutant 

concentrations. 

See Appendix C for an aerial photo of the facility. The detailed cost analysis is provided in Appendix 

A. 

Table 5-31 Line 1 Dryer SO2 Control Cost Summary 

Control Technology 

Installed 

Capital Cost 

($) 

Total 

Annual Cost

($/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

Wet Scrubber $3,898,490 $684,207 $25,103 

Wet ESP (WWESP) $7,674,618 $1,429,065 $52,432 

Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory 

bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective 

air pollution controls in the electric utility industry for large power plants are in the range $1,000 to 

$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an indirect 

measure of affordability for the electric utility industry used by USEPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost 

effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not 

afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the 

electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater 

business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for 

proposing BART in lieu of developing industry and site specific data. 

The annualized pollution control cost value was used to determine whether or not additional impacts 

analyses would be conducted for the technology. If the control cost was less than a screening 

threshold established by MDEQ, then visibility modeling impacts, and energy and other impacts are 

evaluated. MDEQ set the screening level to eliminate technologies from requiring the additional 

 

43 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition. 

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impact analyses at an annualized cost of $12,000 per ton of controlled pollutant44. Therefore, all air 

pollution controls with annualized costs less than this screening threshold will be evaluated for 

visibility improvement, energy and other impacts. However, as presented in table 5-31, all of the 

available and applicable technologies for SO2 control for the Line 1 Dryer have annualized control 

costs greater than $12,000 per ton of controlled pollutant. Therefore, no additional impacts analysis 

is required. 

The BART guidance documents also present a calculation method for incremental control cost which 

is intended to present the incremental value of each technology as compared to the next most 

effective alternative. Since none of the technologies are cost effective, the incremental control cost 

is not applicable and is not presented in this analysis. 

Energy and Environmental Impacts 

As presented in table 5-31, all of the available and applicable technologies for SO2 control for the 

Line 1 Dryer have annualized control costs greater than $12,000 per ton of controlled pollutant. 

Therefore, no energy and environmental impacts analysis was required. 

5.C.i.e STEP 5 – Evaluate Visibility Impacts 

As previously stated in section 4 of this document, states are required to consider the degree of 

visibility improvement resulting from the retrofit technology, in combination with other factors such 

as economic, energy and other non-air quality impacts, when determining BART for an individual 

source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this 

document. Since none of the SO2 technologies are cost effective for the process boilers, the visibility 

impacts were not evaluated. 

 

44 Michigan Department of Environmental Quality May 12, 2006 meeting. 

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5.C.ii Nitrogen Oxide Controls 

To be able to control NOx it is important to understand how NOx is formed. There are three 

mechanisms by which NOx production occurs: thermal, fuel and prompt NOx. 

• Fuel bound NOx is formed as nitrogen compounds in the fuel is oxidized in the combustion 

process. 

• Thermal NOx production arises from the thermal dissociation of nitrogen and oxygen 

molecules within the furnace. Combustion air is the primary source of nitrogen and oxygen. 

Thermal NOx production is a function of the residence time, free oxygen, and temperature. 

• Prompt NOx is a form of thermal NOx which is generated at the flame boundary. It is the 

result of reactions between nitrogen and carbon radicals generated during combustion. Only 

minor amounts of NOx are emitted as prompt NOx. 

The majority of NOx is emitted as NO. Minor amounts of NO2 are formed in the dryer. 

5.C.ii.a STEP 1 – Identify All Available Retrofit Control Technologies 

With the understanding of how NOx is formed, available and applicable control technologies were 

evaluated. See Appendix F for the current status of the availability and applicability of retrofit 

control technologies. Many emerging technologies have been identified that are not currently 

commercially available. A preliminary list of technologies was submitted to MDEQ on October 6, 

2006 with the status of the technology as it was understood at that time. As work on this evaluation 

progressed, new information became apparent of the limited scope and scale of some of the 

technology applications. Appendix F presents the current status of the general availability of each 

technology. 

5.C.ii.b STEP 2 – Eliminate Technically Infeasible Options 

Step 1 identified the available and applicable technologies for NOx emission reduction. Within 

Step 1, the technical feasibility of the control option was also discussed and determined. The 

following describes retrofit NOx control technologies that were identified as available and applicable 

in the original submittal and discusses aspects of those technologies that determine whether or not 

the technology is technically feasible for the Line 1 Dryer. 

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External Flue Gas Recirculation (EFGR) 

External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures 

thereby reducing thermal NOx formation. In an external flue gas recirculation system, flue gas is 

collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is 

mixed with the combustion air and this mixture is introduced into the burner. The addition of flue gas 

reduces the oxygen content of the “combustion air” (air + flue gas) in the burner. The lower oxygen 

level in the combustion zone reduces flame temperatures; which in turn reduces NOx emissions. For 

this technology to be effective, the combustion conditions must have the ability to be controlled at 

the burner tip. Due to the current configuration of the burners, the Line 1 Dryer does not have the 

capability of control at the burner tip. Therefore, this option is not technically feasible and will not be 

further evaluated in this report. 

Low NOx Burners (LNB) 

Low-NOx burner (LNB) technology utilizes advanced burner design to reduce NOx formation through 

the restriction of oxygen, flame temperature, and/or residence time. LNB is a staged combustion 

process that is designed to split fuel combustion into two zones. In the primary zone, NOx formation 

is limited by either one of two methods. Under staged air rich (high fuel) condition, low oxygen 

levels limit flame temperatures resulting in less NOx formation. The primary zone is then followed 

by a secondary zone in which the incomplete combustion products formed in the primary zone act as 

reducing agents. Alternatively, under staged fuel lean (low fuel) conditions, excess air will reduce 

flame temperature to reduce NOx formation. In the secondary zone, combustion products formed in 

the primary zone act to lower the local oxygen concentration, resulting in a decrease in NOx

formation. Low NOx burners typically achieve NOx emission reductions of 25% - 50% for process 

boilers. 

Based on the information contained within this report, LNB is considered a technically feasible 

technology for NOx reduction for this BART analysis. 

Overfire Air (OFA) 

Overfire air (OFA) diverts a portion of the total combustion air from the burners and injects it 

through separate air ports above the top level of burners. OFA is a NOx control technology typically 

used in boilers and is primarily geared to reduce thermal NOx. Staging of the combustion air creates 

an initial fuel-rich combustion zone for a cooler fuel-rich combustion zone. This reduces the 

production of thermal NOx by lowering peak combustion temperature and limiting the availability of 

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oxygen in the combustion zone where NOx is most likely to be formed. OFA is considered 

compatible with the LNB. The estimated NOx control efficiency for LNB with OFA is 50-67%. 

Based on the information contained within this report, OFA with LNB is considered a technically 

feasible technology for NOx reduction for this BART analysis. 

Induced Flue Gas Recirculation (IFGR) 

Induced flue gas recirculation burners, also called ultra low-NOx burners, combine the benefits of 

flue gas recirculation and low-NOx burner control technologies. The burner is designed to draw flue 

gas to dilute the fuel in order to reduce the flame temperature. These burners also utilize staged fuel 

combustion to further reduce flame temperature. The estimated NOx control efficiency for IFGR 

burners in high temperature applications is 50-75%. 

Based on the information contained within this report, IFGR is considered a technically feasible 

technology for NOx reduction for this BART analysis. 

Energy Efficiency Projects 

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption. 

Typically reduced fuel usage translates into reduced pollution emissions. An energy efficiency 

project could be preheat incoming make-up air or pellet feed. Each project is very dependent upon 

the fuel usage, process equipment, type of product and so many other variables. 

Due to the increased price of fuel, Tilden has already implemented energy efficiency projects. Each 

project carries its own fuel usage reductions and potential emission reductions. Due to the 

uncertainty and generalization of this category, this will not be further evaluated in this report. 

However, it should be noted that Tilden will continue to evaluate and implement energy efficiency 

projects as they arise. 

Alternate Fuels 

As described within the energy efficiency description, increased price of fuel has also pushed 

companies to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and 

gas. To achieve reduction of NOx emissions through alternative fuel usage, the source must be 

currently burning a high NOx emitting fuel relative to other fuels. The Line 1 Dryer is only capable 

of burning natural gas and distillate oil. Therefore the use of alternate fuels is not a viable option for 

the Line 1 Dryer and will not be considered further in this analysis. 

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It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their 

option, not to direct the fuel choice.45 

Therefore, due to the limited Line 1 Dryer fuel capabilities and the fact that BART is not intended to 

mandate a fuel switch, alternative fuels as an air pollution control technology will not be further 

evaluated in this report. 

However, similar to energy efficiency, Tilden will continue to evaluate and implement alternate fuel 

usage as the feasibility arises. 

Low Excess Air 

Operating a burner with low excess air is a method to minimize peak flame temperature and excess 

oxygen which therefore minimizes the production of NOx. Operating a burner with low excess air 

also optimizes the fuel efficiency as less air is heated up in the combustion chamber. 

As previously stated, the increased price of fuel has pushed companies to evaluate fuel usage. 

Therefore, the Line 1 Dryer at Tilden is operated with low excess air within the constraints of the 

combustion chamber. Therefore, low excess air will not be further evaluated in this report. 

However, similar to energy efficiency and alternate fuels, the facility will continue to evaluate boiler 

optimization including operating at low excess air. 

Reburning 

Reburning is a technology used with solid fuels. The Line 1 Dryer is not cable of burning solid fuel; 

therefore this technology will not be further evaluated. 

Post Combustion Controls 

NOx can be controlled using add-on systems located downstream of the combustion process. The 

two main techniques in commercial service include the selective non catalytic reduction (SNCR) 

process and the selective catalytic reduction (SCR) process. There are a number of different process 

systems in each of these categories of control techniques. 

In addition to these treatment systems, there are a large number of other processes being developed 

and tested on the market. These approaches involve innovative techniques of chemically reducing, 

 

45 Federal Register 70, no. 128 (July 6, 2005): 39164

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absorbing, or adsorbing NOx downstream of the combustion chamber. Examples of these alternatives 

are nonselective catalytic reduction (NSCR) and Low Temperature Oxidation (LTO). Each of these 

alternatives is described below. 

Non-Selective Catalytic Reduction (NSCR) 

A non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas 

treatment system. NSCR catalyst is very sensitive to poisoning; therefore, NSCR is applied primarily 

in natural gas combustion applications. 

NSCR is often referred to as “three-way conversion” catalyst because it simultaneously reduces NOx, 

unburdened hydrocarbons (UBH), and carbon monoxide (CO). Typically, NSCR can achieve NOx

emission reductions of 90 percent. In order to operate properly, the combustion process must be near 

stoichiometric conditions. Under this condition, in the presence of a catalyst, NOx is reduced by CO, 

resulting in nitrogen (N2) and carbon dioxide (CO2). The most important reactions for NOx removal 

are: 

2CO + 2NO → 2CO2 + N2 (1) 

[UBH] + NO → N2 + CO2 + H2O (2) 

NSCR catalyst has been applied primarily in clean combustion applications. This is due in large part 

to the catalyst being very sensitive to poisoning, making it infeasible to apply this technology to 

liquid fuels. Therefore, this technology will not be further evaluated in this report. 

Selective Catalytic Reduction (SCR) and Regenerative Selective Catalytic Reduction 

(R-SCR) 

SCR is a post-combustion NOx control technology in which ammonia (NH3) is injected into the flue 

gas stream in the presence of a catalyst. NOx is removed through the following chemical reaction:

4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (1) 

2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O (2) 

A catalyst bed containing metals in the platinum family is used to lower the activation energy 

required for NOx decomposition. SCR requires a temperature range of about 570°F – 850°F for a 

normal catalyst. At temperature exceeding approximately 670oF, the oxidation of ammonia begins to 

become significant. At low temperatures, the formation of ammonium bisulfate causes scaling and 

corrosion problems. 

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A high temperature zeolite catalyst is also available; it can operate in the 600 °F – 1000°F 

temperature range. However, these catalysts are very expensive. 

Ammonia slip from the SCR system is usually less than 3 to 5 ppm. The emission of ammonia 

increases during load changes due to the instability of the temperature in the catalyst bed as well as at 

low loads because of the low gas temperature. 

Regenerative Selective Catalytic Reduction (R-SCR) applies the Selective Catalytic Reduction (SCR) 

control process as described below with a preheat process step to reheat the flue gas stream up to 

SCR catalyst operating temperatures. The preheating process combines use of a thermal heat sink 

(packed bed) and a duct burner. The thermal sink recovers heat from the hot gas leaving the R-SCR 

and then transfers that heat to gas entering the R-SCR. The duct burner is used to complete the 

preheating process. R-SCR operates with several packed bed/SCR reactor vessels. Gas flow 

alternates between vessels. Each of the vessels alternates between preheating/treating and heat 

recovery. 

The benefits of R-SCR are: 

• Its high energy efficiency allows it to be used after SO2 and particulate controls. 

• R-SCR has a thermal efficiency of 90% - 95% vs. standard heat exchangers which have a 

thermal efficiency of 60% to 70%. 

• Application of R-SCR after SO2 and PM controls significantly reduces the potential for 

problems associated with plugging and catalyst poisoning and deactivation. 

To date, R-SCR has been applied to wood-fired utility boilers. Application of this technology has 

not been applied to liquid and natural gas fired taconite dryers. Using R-SCR would require research, 

test runs, and extended trials to identify potential issues related to catalyst selection, and impacts on 

plant systems. It is not reasonable to assume that vendor guarantees of performance would be 

forthcoming in advance of a demonstration project. The timeline required to perform such a 

demonstration project would likely be two years to develop and agree on the test plan, obtain permits 

for the trial, commission the equipment for the test runs, perform the test runs for a reasonable study 

period, and evaluate and report on the results. The results would not be available within the time 

window for establishing emission limits to be incorporated in the state implementation plan (SIP) by 

December 2007. 

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Recalling U.S. EPA’s intention regarding “available” technologies to be considered for BART, as 

mentioned in Section 2.B, facility owners are not expected to undergo extended trials in order to 

learn how to apply a control technology to a completely new and significantly different source type. 

Therefore, R-SCR is not considered to be technically feasible, and will not be analyzed further in this 

BART analysis. 

SCR with reheat through a conventional duct burner (rather than using a regenerative heater) has 

been successfully implemented more widely and in higher airflow applications and will be carried 

forward in this analysis as available and applicable technology that is reasonably expected to be 

technically feasible. 

Selective Non-Catalytic Reduction (SNCR) 

In the SNCR process, urea or ammonia-based chemicals are injected into the flue gas stream to 

convert NO to molecular nitrogen, N2, and water. SNCR control efficiency is typically 25% - 60%. 

Without a catalyst, the reaction requires a high temperature range to obtain activation energy. The 

relevant reactions are as follows: 

NO + NH3 + 1⁄4O2 → N2 + 3/2H2O (1) 

NH3 + 1⁄4O2 → NO + 3/2H2O (2) 

At temperature ranges of 1470 to 1830°F reaction (1) dominates. At temperatures above 2000°F, 

reaction (2) will dominate. 

Based on the information contained within this report, a SNCR is considered a technically feasible 

technology for NOx reduction for this BART analysis. 

Low Temperature Oxidation (LTO) 

The LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including 

NOx. In the system, the NOx in the flue gas is oxidized to form nitrogen pentoxide (equations 1, 2, 

and 3). The nitrogen pentoxide forms nitric acid vapor as it contacts the water vapor in the flue gas 

(4). Then the nitric acid vapor is absorbed as dilute nitric acid and is neutralized by the sodium 

hydroxide or lime in the scrubbing solution forming sodium nitrate (5) or calcium nitrate. The 

nitrates are removed from the scrubbing system and discharged to an appropriate water treatment 

system. Commercially available LTO systems include Tri-NOx® and LoTOx®. 

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NO + O3 → NO2 + O2 (1) 

NO2 + O3 → NO3 + O2 (2) 

NO3 + NO2 → N2O5 (3) 

N2O5 + H2O → 2HNO3 (4) 

HNO3 + NaOH → NaNO3 + H2O (5) 

Low Temperature Oxidation (Tri-NOx

®

) 

This technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO2 in a 

primary scrubbing stage. Then NO2 is removed through caustic scrubbing in a secondary stage. The 

reactions are as follows: 

O3 + NO → O2 + NO2

(1)

2NaOH + 2NO2 + 1⁄2 O2 → 2NaNO3 + H2O (2)

Tri-NOx

®

 is a multi-staged wet scrubbing process in industrial use. Several process columns, each 

assigned a separate processing stage, are involved. In the first stage, the incoming material is 

quenched to reduce its temperature. The second, oxidizing stage, converts NO to NO2. Subsequent 

stages reduce NO2 to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NOx

®

 is 

typically applied at small to medium sized sources with high NOx concentration in the exhaust gas 

(1,000 ppm NOx). 

Low Temperature Oxidation (LoTOx®

) 

BOC Gases’ Lo-TOx®

 is an example of a version of an LTO system. LoTOx® technology uses ozone 

to oxidize NO to NO2 and NO2 to N2O5 in a wet scrubber (absorber). This can be done in the same 

scrubber used for particulate or sulfur dioxide removal, The N2O5 is converted to HNO3 in a 

scrubber, and is removed with lime or caustic. Ozone for LoTOx® is generated on site with an 

electrically powered ozone generator. The ozone generation rate is controlled to match the amount 

needed for NOx control. Ozone is generated from pure oxygen. In order for LoTOx®

 to be 

economically feasible, a source of low cost oxygen must be available from a pipeline or on site 

generation. 

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In addition, only two of BOC’s LoTOx® installations are fully installed and operational applications. 

Therefore, although this is an emerging technology, the limited application means that it has not been 

demonstrated to be an effective technology in widespread application. In addition, LoTOx has not 

been applied on a taconite dryer or similar process. Consequently, the technical feasibility of LTO as 

technically infeasible for this application and will not be evaluated further. 

Step 2 Conclusion 

Based upon the determination within Step 2, the remaining NOx control technologies that are 

available and applicable to the process boilers are identified in Table 5-32. The technical feasibility 

as determined in Step 2 is also included in Table 5-32.

Table 5-32 Line 1 Dryer NOx Control Technology – Availability, Applicability and Technical 

Feasibility 

NOx Pollution Control Technology Available? Applicable?

Technically 

Feasible? 

External Flue Gas Recirculation (EFGR) Yes Yes No 

Low-NOx Burners Yes Yes Yes 

Overfired Air Yes Yes No 

Induced Flue Gas Recirculation (IFGR) Yes Yes Yes 

Energy Efficiency Projects Yes Yes Project 

Dependent 

Alternative Fuels Yes Yes 

Yes – Not 

required by 

BART 

Non-Selective Catalytic Reduction (NSCR) Yes Yes No 

Selective Catalytic Reduction (SCR) Yes Yes Yes 

Regenerative SCR Yes Yes No 

Selective Non-Catalytic Reduction (SNCR) Yes Yes Yes 

Low Temperature Oxidation (LTO) Yes No No 

5.C.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

Table 5-33 describes the expected control efficiency from each of the remaining technically feasible 

control options as identified in Step 2. 

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Table 5-33 Line 1 Dryer NOx Control Technology Effectiveness 

NOx Pollution Control Technology 

Approximate Control 

Efficiency 

Selective Catalytic Reduction (SCR) with 

Reheat 80% 

Low NOX Burner / Flue Gas Recirculation 

(LNB/FGR) 75% 

Regenerative Selective Catalytic Reduction 

(R-SCR) 70% 

Low NOX Burner / Overfire Air (LNB/OFA) 67% 

Low NOX Burner (LNB) 50% 

Selective Non-Catalytic Reduction (SNCR) 50% 

5.C.ii.d STEP 4 – Evaluate Impacts and Document the Results 

Table 5-34 details the expected costs associated with installation of NOx controls. Capital costs were 

calculated based on the maximum 24-hour emissions, U.S. EPA cost models, and vendor estimates. 

Vendor estimates for capital costs based on a specific flow rate were scaled to each stack’s flow rate 

using the six-tenths-factor rule to account for the economy of scale. Operating costs were based on 

100% utilization and 7650 operating hours per year, which is extremely conservative. Operating 

costs were proportionally adjusted to reflect site specific flow rates and pollutant concentrations. 

After a tour of the facility and discussions with facility management, it was determined the space 

surrounding the boilers is congested and the area surrounding the building supports vehicle and rail 

traffic to transport materials to and from the building. A site-specific estimate for site-work, 

foundations, and structural steel was added based upon the facility site to arrive at the total retrofit 

installed cost of the control technology. See Appendix C for a site plan of the facility. Additionally, 

the structural design of the existing building would not support additional equipment on the roof. The 

detailed cost analysis is provided in Appendix A. 

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Table 5-34 Line 1 Dryer NOx Control Cost Summary 

Control 

Technology 

Installed 

Capital Cost 

($) 

Total Annual 

Cost 

($/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

Incremental 

Control Cost 

($/ton) 

SCR with Reheat $6,439,029 $1,008,211 $83,472 NA 

LNB/FGR $1,087,058 $134,645 $11,891 $19,493 

R-SCR $5,445,064 $1,024,459 $96,934 NA 

LNB/OFA $888,317 $116,686 $11,535 $21,669 

LNB $432,579 $61,070 $8,090 Lowest 

SNCR $915,968 $278,929 $36,949 NA 

Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory 

bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective 

air pollution controls in the electric utility industry for large power plants are in the range $1,000 to 

$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an indirect 

measure of affordability for the electric utility industry used by USEPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost 

effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not 

afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the 

electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater 

business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for 

proposing BART in lieu of developing industry and site specific data. 

The annualized pollution control cost value was used to determine whether or not additional impacts 

analyses would be conducted for the technology. If the control cost was less than a screening 

threshold established by MDEQ, then visibility modeling impacts, and energy and other impacts are 

evaluated. MDEQ set the screening level to eliminate technologies from requiring the additional 

impact analyses at an annualized cost of $12,000 per ton of controlled pollutant46. Therefore, all air 

pollution controls with annualized costs less than this screening threshold will be evaluated for 

visibility improvement, energy and other impacts. 

The incremental control cost listed in Table 5-34 represents the incremental value of each technology 

as compared to the technology with the next highest level of control. The cost of control and 

 

46 Michigan Department of Environmental Quality May 12, 2006 meeting. 

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incremental cost of SCR with reheat, R-SCR and SNCR are not reasonable. The magnitude of the 

capital and operating costs of remaining alternatives is also significant and may impact the viability 

of continued operation. 

Energy and Environmental Impacts 

The energy and non-air quality impacts for LNB and LNB with IFGR are presented in Table 5-35. 

Because the cost of the remaining NOx control technologies for the Line 1 Dryer is so high and does 

not meet a reasonable definition of cost effective technology, these technologies are removed from 

further consideration in this analysis. 

Table 5-35 Line 1 Dryer NOx Control Technology – Other Impacts Assessment 

Control 

Option Energy Impacts Other Impacts 

LNB - Minimal energy impacts - Increase in CO emissions 

- Potential for steam tube wastage due to 

longer combustion flame 

LNB/FGR - Minimal energy impacts. - Increase in CO emissions 

- Potential for steam tube wastage due to 

longer combustion flame. 

5.C.ii.e STEP 5 – Evaluate Visibility Impacts 

As previously stated in section 4 of this document, states are required to consider the degree of 

visibility improvement resulting from the retrofit technology, in combination with other factors such 

as economic, energy and other non-air quality impacts, when determining BART for an individual 

source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this 

document. This section of the report evaluates the visibility impacts of BART NOX control and the 

resulting degree of visibility improvement. 

Predicted 24-Hour Maximum Emission Rates 

Consistent with the use of the highest daily emissions for baseline, or pre-BART, visibility impacts, 

the post-BART emissions to be used for the visibility impacts analysis should also reflect a 

maximum 24-hour average project emission rate. In the visibility impacts NOX modeling analysis, 

the emissions from the sources undergoing a full BART NOx analysis were adjusted to reflect the 

projected 24-hour maximum NOx emission rate when applying the control technologies that met the 

threshold requirements of steps 1 – 4. The emissions from all other Subject-to-BART sources were 

not changed. Table 5-36 provides a summary of the modeled 24-hour maximum emission rates and 

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their computational basis for the evaluated NOx control technologies. Table 5-37 provides a 

summary of the modeling input data. 

Post-BART Visibility Impacts Modeling Results 

Results of the post-BART visibility impacts modeling for NOX for the process boilers are presented 

in Table 5-38. The results summarize 98th percentile dV value and the number of days the facility 

contributes more than a 0.5 dV of visibility impairment at each of the Class I areas. The comparison 

of the post-BART modeling scenarios to the baseline conditions is presented in Table 5-39. 

Visibility impacts with SO2 controls are presented in section 6. 

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Table 5-36 Line 1 Dryer Post-BART Modeling Scenarios 

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

Base SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% Base SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

Base SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

1 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

3 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

4 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

5 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

6 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil LNB 0.0% 8.3 50.0% 

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Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

Natural Gas 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

7 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

8 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

9 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

10 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

11 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

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Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

12 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

13 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

14 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

15 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

16 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

17 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 Low Sulfur Fuel LNB w/OFA 0.0% 0.1 67.0% 

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106

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

EUBOILER2 Oil 

Natural Gas 

18 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

19 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

20 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

21 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

22 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

23 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil LNB 0.0% 8.3 50.0% 

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107

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

Natural Gas 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

24 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

25 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

26 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

27 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

28 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

29 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

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108

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

30 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

31 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

Table 5-37 Line 1 Dryer Post-BART NOx Modeling Scenarios - Modeling Input Data 

Control Scenario SV # Emission Unit Stack Easting 

(utm) 

Stack Northing 

(utm) 

Height of 

Opening from 

Ground 

(ft) 

Base Elevation 

of Ground 

(ft) 

Stack length, 

width, or 

Diameter 

(ft) 

Flow Rate 

(acfm

All Scenarios SVP0051981 SVP0051711 EUKILN1 46.44084994 

46.44075383 

-87.653 

40738 

-87.651 

32336 

240 160 

1474 

19.3 13.5 

842,0306,0

 SVP0082951 EUDRYER1 46.44075383 -87.651 32336 119 1474 6.3 57,13

SVBLR.STK.

T1 

EUBOILER1 EUBOILER2 46.44091784 -87.654 12418 130 1474 7.5 192,0

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109

Table 5-38 Line 1 Dryer Post-BART NOx Modeling Scenarios - Visibility Modeling Results 

Modeling Results 

 2002 2003 2004 

2002-2004 

Scenario 

Limiting 

Class I 

Area 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Base IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 41 

1 IRNP 0.323 2.0 0.275 1.000 0.228 1.000 0.248 2 

2 IRNP 0.610 15.0 0.620 10.000 0.535 8.000 0.600 33 

3 IRNP 0.183 0.0 0.177 0.000 0.154 0.000 0.173 0 

4 IRNP 0.717 19.0 0.717 11.000 0.589 12.000 0.668 42 

5 IRNP 0.322 2.0 0.256 0.000 0.219 1.000 0.254 2 

6 IRNP 0.619 15.0 0.623 10.000 0.528 8.000 0.598 33 

7 IRNP 0.182 0.0 0.177 0.000 0.155 0.000 0.169 0 

8 IRNP 0.714 19.0 0.711 11.000 0.583 11.000 0.653 41 

9 IRNP 0.314 2.0 0.252 0.000 0.213 1.000 0.248 2 

10 IRNP 0.618 15.0 0.607 10.000 0.527 8.000 0.590 33 

11 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161 0 

12 IRNP 0.719 19.0 0.693 10.000 0.592 9.000 0.654 38 

13 IRNP 0.315 2.0 0.246 0.000 0.218 1.000 0.243 2 

14 IRNP 0.627 15.0 0.608 9.000 0.544 8.000 0.585 32 

15 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160 0 

16 IRNP 0.722 19.0 0.673 10.000 0.605 9.000 0.656 38 

17 IRNP 0.326 2.0 0.243 0.000 0.218 1.000 0.243 2 

18 IRNP 0.626 15.0 0.605 9.000 0.542 8.000 0.596 32 

19 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163 0 

20 IRNP 0.734 19.0 0.692 10.000 0.605 10.000 0.654 39 

21 IRNP 0.324 2.0 0.241 0.000 0.215 1.000 0.241 2 

22 IRNP 0.625 15.0 0.602 9.000 0.291 3.000 0.588 27 

23 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165 0 

24 IRNP 0.727 19.0 0.689 10.000 0.603 10.000 0.656 39 

25 IRNP 0.326 2.0 0.245 0.000 0.207 1.000 0.241 2 

26 IRNP 0.623 15.0 0.605 9.000 0.550 8.000 0.597 32 

27 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165 0 

28 IRNP 0.704 19.0 0.672 10.000 0.606 9.000 0.657 38 

29 IRNP 0.325 2.0 0.239 0.000 0.198 1.000 0.240 2 

30 IRNP 0.613 14.0 0.614 9.000 0.542 8.000 0.588 31 

31 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.164 0 

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110

Table 5-39 Line 1 Dryer Post-BART NOx Modeling Scenarios – Comparison of Visibility 

Modeling Results to Baseline Modeling Results 

Modeling Results 

2002 2003 2004 2002-2004 

Scenario 

Limiting 

Class I 

Area 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

1 IRNP 0.391 17 0.447 10 0.371 10 0.426 39 

2 IRNP 0.104 4 0.102 1 0.064 3 0.074 8 

3 IRNP 0.531 19 0.545 11 0.445 11 0.501 41 

4 IRNP -0.003 0 0.005 0 0.01 -1 0.006 -1 

5 IRNP 0.392 17 0.466 11 0.38 10 0.42 39 

6 IRNP 0.095 4 0.099 1 0.071 3 0.076 8 

7 IRNP 0.532 19 0.545 11 0.444 11 0.505 41 

8 IRNP 0 0 0.011 0 0.016 0 0.021 0 

9 IRNP 0.4 17 0.47 11 0.386 10 0.426 39 

10 IRNP 0.096 4 0.115 1 0.072 3 0.084 8 

11 IRNP 0.538 19 0.554 11 0.449 11 0.513 41 

12 IRNP -0.005 0 0.029 1 0.007 2 0.02 3 

13 IRNP 0.399 17 0.476 11 0.381 10 0.431 39 

14 IRNP 0.087 4 0.114 2 0.055 3 0.089 9 

15 IRNP 0.538 19 0.551 11 0.449 11 0.514 41 

16 IRNP -0.008 0 0.049 1 -0.006 2 0.018 3 

17 IRNP 0.388 17 0.479 11 0.381 10 0.431 39 

18 IRNP 0.088 4 0.117 2 0.057 3 0.078 9 

19 IRNP 0.539 19 0.549 11 0.448 11 0.511 41 

20 IRNP -0.02 0 0.03 1 -0.006 1 0.02 2 

21 IRNP 0.39 17 0.481 11 0.384 10 0.433 39 

22 IRNP 0.089 4 0.12 2 0.308 8 0.086 14 

23 IRNP 0.539 19 0.552 11 0.449 11 0.509 41 

24 IRNP -0.013 0 0.033 1 -0.004 1 0.018 2 

25 IRNP 0.388 17 0.477 11 0.392 10 0.433 39 

26 IRNP 0.091 4 0.117 2 0.049 3 0.077 9 

27 IRNP 0.538 19 0.55 11 0.448 11 0.509 41 

28 IRNP 0.01 0 0.05 1 -0.007 2 0.017 3 

29 IRNP 0.389 17 0.483 11 0.401 10 0.434 39 

30 IRNP 0.101 5 0.108 2 0.057 3 0.086 10 

31 IRNP 0.541 19 0.55 11 0.448 11 0.51 41 

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6. Visibility Impacts 

As previously stated in section 4 of this document, states are required to consider the degree of 

visibility improvement resulting from the retrofit technology, in combination with other factors such 

as economic, energy and other non-air quality, when determining BART for an individual source. 

The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this document. 

The visibility impacts of individual control technologies were presented in Step 5 of section 5 of this 

document. This section of the report evaluates the various BART control scenarios utilizing both 

SO2 and NOx controls, and estimates the resulting degree of visibility improvement. 

6.A Post-Control Modeling Scenarios 

Steps 1-4 of the BART analysis identified the control technologies that were: 

• Available and applicable; 

• Technically feasible; and 

• Below the screening cost threshold for further BART analysis. 

Step 5 of the BART analysis evaluated the visibility impacts of each of the control technologies that 

met the requirements of the screening analysis of steps 1-4. 

The interactions between the visibility impairing pollutants NOx, SO2 and PM10 can play a large part 

in predicting impairment. It is therefore important to take a multi-pollutant approach when assessing 

visibility impacts. Accordingly, this visibility improvement analysis evaluates several operating 

control scenarios that account for the various combinations of available NOx controls. In addition, 

two site-specific scenarios were developed so that the evaluation includes other operating scenarios 

and conditions that would improve visibility impairment. The post-control modeling scenarios, 

including those presented in Step 5 of section 5, are presented in Table 6-1. The modeling scenario 

stack parameters are presented in Table 6-2. 

6.B Post-Control Modeling Results 

Results of the post-control modeling scenarios are presented in Table 6-3. The results summarize 

98th percentile dV value and the number of days the facility contributes more than a 0.5 dV of 

visibility impairment at each of the Class I areas. The comparison of the post-control modeling 

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112

scenarios to the baseline conditions is presented in Table 6-4. Notably, none of the post-control 

scenarios produces a visibility improvement that exceeds the perceptible threshold of 1-2 dV. 

Additionally, Table 6-5 illustrates the scenarios on a $/dV basis. The dollar per deciview ranges 

from $6.1 million to more than $79 million per dV of improvement. 

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Table 6-1 Post-Control Modeling Scenarios 

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

Base SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% Base SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

Base SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

1 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

2 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

3 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

4 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

5 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil LNB 0.0% 8.3 50.0% 

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114

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

Natural Gas 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

6 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

7 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

8 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

9 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

10 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

11 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

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115

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

12 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

13 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

14 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

15 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

16 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

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116

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

17 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

18 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

19 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

20 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

21 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

22 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 Low Sulfur Fuel LNB w/OFA 0.0% 0.1 67.0% 

123
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117

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

EUBOILER2 Oil 

Natural Gas 

23 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

24 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

25 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

26 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

27 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

28 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil LNB 0.0% 8.3 50.0% 

124
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118

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

Natural Gas 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

29 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

30 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

31 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

Table 6-2 Post-Control NOX Modeling Scenarios - Modeling Input Data 

Control Scenario SV # Emission Unit Stack Easting 

(utm) 

Stack Northing 

(utm) 

Height of 

Opening from 

Ground 

(ft) 

Base Elevation 

of Ground 

(ft) 

Stack length, 

width, or 

Diameter 

(ft) 

Flow Rate 

(acfm

All Scenarios SVP0051981 SVP0051711 EUKILN1 46.44084994 

46.44075383 

-87.653 

40738 

-87.651 

32336 

240 160 

1474 

19.3 13.5 

842,0306,0

 SVP0082951 EUDRYER1 46.44075383 -87.651 32336 119 1474 6.3 57,13

SVBLR.STK.

T1 

EUBOILER1 EUBOILER2 46.44091784 -87.654 12418 130 1474 7.5 192,0

125
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119

Table 6-3 Post-Control Modeling Scenarios - Visibility Modeling Results 

Modeling Results 

 2002 2003 2004 

2002-2004 

Scenario 

Limiting 

Class I 

Area 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Base IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 41 

1 IRNP 0.323 2.0 0.275 1.000 0.228 1.000 0.248 2 

2 IRNP 0.610 15.0 0.620 10.000 0.535 8.000 0.600 33 

3 IRNP 0.183 0.0 0.177 0.000 0.154 0.000 0.173 0 

4 IRNP 0.717 19.0 0.717 11.000 0.589 12.000 0.668 42 

5 IRNP 0.322 2.0 0.256 0.000 0.219 1.000 0.254 2 

6 IRNP 0.619 15.0 0.623 10.000 0.528 8.000 0.598 33 

7 IRNP 0.182 0.0 0.177 0.000 0.155 0.000 0.169 0 

8 IRNP 0.714 19.0 0.711 11.000 0.583 11.000 0.653 41 

9 IRNP 0.314 2.0 0.252 0.000 0.213 1.000 0.248 2 

10 IRNP 0.618 15.0 0.607 10.000 0.527 8.000 0.590 33 

11 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161 0 

12 IRNP 0.719 19.0 0.693 10.000 0.592 9.000 0.654 38 

13 IRNP 0.315 2.0 0.246 0.000 0.218 1.000 0.243 2 

14 IRNP 0.627 15.0 0.608 9.000 0.544 8.000 0.585 32 

15 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160 0 

16 IRNP 0.722 19.0 0.673 10.000 0.605 9.000 0.656 38 

17 IRNP 0.326 2.0 0.243 0.000 0.218 1.000 0.243 2 

18 IRNP 0.626 15.0 0.605 9.000 0.542 8.000 0.596 32 

19 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163 0 

20 IRNP 0.734 19.0 0.692 10.000 0.605 10.000 0.654 39 

21 IRNP 0.324 2.0 0.241 0.000 0.215 1.000 0.241 2 

22 IRNP 0.625 15.0 0.602 9.000 0.291 3.000 0.588 27 

23 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165 0 

24 IRNP 0.727 19.0 0.689 10.000 0.603 10.000 0.656 39 

25 IRNP 0.326 2.0 0.245 0.000 0.207 1.000 0.241 2 

26 IRNP 0.623 15.0 0.605 9.000 0.550 8.000 0.597 32 

27 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165 0 

28 IRNP 0.704 19.0 0.672 10.000 0.606 9.000 0.657 38 

29 IRNP 0.325 2.0 0.239 0.000 0.198 1.000 0.240 2 

30 IRNP 0.613 14.0 0.614 9.000 0.542 8.000 0.588 31 

31 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.164 0 

126
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120

Table 6-4 Post-Control Modeling Scenarios – Improved Visibility Modeling Results 

Modeling Results 

2002 2003 2004 2002-2004 

Scenario 

Limiting 

Class I 

Area 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

1 IRNP 0.391 17 0.447 10 0.371 10 0.426 39 

2 IRNP 0.104 4 0.102 1 0.064 3 0.074 8 

3 IRNP 0.531 19 0.545 11 0.445 11 0.501 41 

4 IRNP -0.003 0 0.005 0 0.01 -1 0.006 -1 

5 IRNP 0.392 17 0.466 11 0.38 10 0.42 39 

6 IRNP 0.095 4 0.099 1 0.071 3 0.076 8 

7 IRNP 0.532 19 0.545 11 0.444 11 0.505 41 

8 IRNP 0 0 0.011 0 0.016 0 0.021 0 

9 IRNP 0.4 17 0.47 11 0.386 10 0.426 39 

10 IRNP 0.096 4 0.115 1 0.072 3 0.084 8 

11 IRNP 0.538 19 0.554 11 0.449 11 0.513 41 

12 IRNP -0.005 0 0.029 1 0.007 2 0.02 3 

13 IRNP 0.399 17 0.476 11 0.381 10 0.431 39 

14 IRNP 0.087 4 0.114 2 0.055 3 0.089 9 

15 IRNP 0.538 19 0.551 11 0.449 11 0.514 41 

16 IRNP -0.008 0 0.049 1 -0.006 2 0.018 3 

17 IRNP 0.388 17 0.479 11 0.381 10 0.431 39 

18 IRNP 0.088 4 0.117 2 0.057 3 0.078 9 

19 IRNP 0.539 19 0.549 11 0.448 11 0.511 41 

20 IRNP -0.02 0 0.03 1 -0.006 1 0.02 2 

21 IRNP 0.39 17 0.481 11 0.384 10 0.433 39 

22 IRNP 0.089 4 0.12 2 0.308 8 0.086 14 

23 IRNP 0.539 19 0.552 11 0.449 11 0.509 41 

24 IRNP -0.013 0 0.033 1 -0.004 1 0.018 2 

25 IRNP 0.388 17 0.477 11 0.392 10 0.433 39 

26 IRNP 0.091 4 0.117 2 0.049 3 0.077 9 

27 IRNP 0.538 19 0.55 11 0.448 11 0.509 41 

28 IRNP 0.01 0 0.05 1 -0.007 2 0.017 3 

29 IRNP 0.389 17 0.483 11 0.401 10 0.434 39 

30 IRNP 0.101 5 0.108 2 0.057 3 0.086 10 

31 IRNP 0.541 19 0.55 11 0.448 11 0.51 41 

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121

Table 6-5 Post-Control Modeling Results – Dollars per Deciview Improvement 

Scenario Control Technology 

Control Scenario SV # Emission Unit SO2

NOx

Annualized Cost 

($/yr) 

Improved 

Modeled 98th

Percentile 

Value (∆-dV) 

$/dV 

Base SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice Base SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

Base SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 

1 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat $31,055,581 0.447 $69,475,573

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 

2 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice $6,048,540 0.104 $58,159,038

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 

3 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,104,122 0.545 $68,080,958

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 

4 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Good Combustion Practice $61,070 0.01 $6,107,000

128
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122

Scenario Control Technology 

Control Scenario SV # Emission Unit SO2

NOx

Annualized Cost 

($/yr) 

Improved 

Modeled 98th

Percentile 

Value (∆-dV) 

$/dV 

Natural Gas 

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 

5 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,165,192 0.466 $79,753,630

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 

6 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice $6,048,540 0.099 $61,493,020

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 

7 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,104,121 0.545 $68,153,011

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 

8 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice $303,758 0.016 $18,984,875

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 

9 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat $31,055,581 0.47 $66,652,096

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

129
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123

Scenario Control Technology 

Control Scenario SV # Emission Unit SO2

NOx

Annualized Cost 

($/yr) 

Improved 

Modeled 98th

Percentile 

Value (∆-dV) 

$/dV 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 

10 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice $6,352,298 0.115 $55,237,373

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 

11 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,407,880 0.554 $67,523,250

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 

12 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice $364,828 0.029 $12,580,275

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 

13 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat $31,420,409 0.476 $66,009,262

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 

14 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice $6,413,368 0.114 $56,257,614

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 

15 SVP0051981 EUKILN1 Wet Scrubber SCR w/reheat $37,165,192 0.551 $67,450,439

130
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124

Scenario Control Technology 

Control Scenario SV # Emission Unit SO2

NOx

Annualized Cost 

($/yr) 

Improved 

Modeled 98th

Percentile 

Value (∆-dV) 

$/dV 

SVP0051711 

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 

16 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice $390,751 0.049 $7,974,510

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 

17 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat $31,446,333 0.479 $65,649,965

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 

18 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice $6,439,291 0.117 $55,036,675

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 

19 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,494,873 0.549 $68,296,672

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 

20 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice $451,821 0.03 $15,060,700

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil LNB 

131
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125

Scenario Control Technology 

Control Scenario SV # Emission Unit SO2

NOx

Annualized Cost 

($/yr) 

Improved 

Modeled 98th

Percentile 

Value (∆-dV) 

$/dV 

Natural Gas 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 

21 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat $31,507,403 0.481 $65,503,956

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 

22 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice $6,500,362 0.12 $54,169,683

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 

23 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,555,942 0.552 $68,036,127

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 

24 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice $286,968 0.033 $8,696,000

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 

25 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,391,089 0.477 $78,388,027

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 

132
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126

Scenario Control Technology 

Control Scenario SV # Emission Unit SO2

NOx

Annualized Cost 

($/yr) 

Improved 

Modeled 98th

Percentile 

Value (∆-dV) 

$/dV 

26 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice $6,335,508 0.117 $54,149,641

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 

27 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,391,089 0.55 $67,983,798

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 

28 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice $348,038 0.05 $6,960,760

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 

29 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat $31,403,619 0.483 $65,017,845

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 

30 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice $6,396,578 0.108 $59,227,574

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 

31 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,452,159 0.55 $68,094,834

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil LNB 

133
Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc 

127

Scenario Control Technology 

Control Scenario SV # Emission Unit SO2

NOx

Annualized Cost 

($/yr) 

Improved 

Modeled 98th

Percentile 

Value (∆-dV) 

$/dV 

Natural Gas 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 

134
Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc 

128

7. Select BART 

DRAFT LANGUAGE 

BART for Tilden is determined to be as described below. 

Line 1 Indurating Furnace 

For SO2, add-on controls are not cost effective. Therefore, BART is determined to be existing 

controls. The corresponding SO2 emissions limit is 28,000 lb per day for Line 1 when coal is burned. 

For NOx, the reduction due to good combustion practices on Line 1 is selected as BART. Other addon controls for NOx are not cost effective. The corresponding NOx limit is specified in Appendix 2 

Schedule of Compliance in the Renewable Operating Permit 199600379 and with Rule 336.1801. 

For PM, requirements compelled by the October 30, 2006 MACT standard constitute BART. The 

corresponding emissions limits are equivalent to the limits identified in Table 3-1. 

Process Boilers 1 and 2 

For SO2, add-on controls are not cost effective. Therefore, BART is determined to be existing 

controls. The corresponding SO2 emissions limit is regulated by limiting the sulfur content to 1.2% 

by weight, calculated on the basis on 18,000 BTU per pound when used oil is burned. 

For NOx, the reduction due to good combustion practices is selected as BART. Other add-on controls 

for NOx are not cost effective. 

For PM, requirements compelled by the September 13, 2007 MACT standard constitute BART. The 

corresponding emissions limits are equivalent to the limits identified in Table 3-1. 

Line 1 Dryer 

For SO2, add-on controls are not cost effective. Therefore, BART is determined to be existing 

controls. The corresponding SO2 emissions limit is regulated by limiting the sulfur content to 1.5% 

by weight, calculated on the basis on 18,000 BTU per pound when used oil is burned. 

For NOx, the reduction due to good combustion practices is selected as BART. Other add-on controls 

for NOx are not cost effective. 

135
Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc 

129

For PM, requirements compelled by the October 30, 2006 MACT standard constitute BART. The 

corresponding emissions limits are equivalent to the limits identified in Table 3-1. 

The schedule for implementation of controls is by October 30, 2006, well in advance of the 5-year 

time-frame required for BART implementation. 

136
Michigan Operations - West (Tilden) 12/

BART Report - Attachment A: Emission Control Cost AnalysisTable A.1: Grate Kiln Cost Summary

NOx Control Cost Summary 

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Annualized Cost $/yr Pollution 

Cost $

Selective Catalytic 

Reduction with Reheat 80% 923 3690 $65,492,092 $31,055,581 $8,4

SO2 Control Cost Summary 

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Annualized Cost $/yr Pollution 

Cost $

Spray Dry Baghouse 90% 115.3 1037.8 $167,260,397 $23,254,882 $22,4Wet Scrubber (Absorber)(after existing ESP) 80% 230.6 922.5 $34,869,327 $6,048,540 $6,5

Secondary Wet Walled Electrostatic Precipitator (WWESP)(after existing ESP)

80% 230.6 922.5 $52,638,755 $13,922,184 $15,

DSI Baghouse 55% 518.9 634.2 $42,082,032 $9,975,786 $15,7

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix A Tilden Furnace Control Costs.xlsCost Summary

137
Michigan Operations - West (Tilden) 12/27/2006

BART Report - Attachment A: Emission Control Cost AnalysisTable A.1: Process Boilers 1 and 2 and Line 1 Dryer Cost Summary

NOx Control Cost Summary 

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Annualized Cost $/yr Pollution Control Cost $/ton Incremental Cost

Selective Catalytic Reduction (SCR) with ReheatProcess Boilers #1 and #2 80% 15.85 63.38 $6,317,686 $2,528,225 $39,888 n/a

Line 1 Dryer 80% 3.02 12.08 $6,439,029 $1,008,211 $83,472 n/aLow NOX Burner / Flue Gas Recirculation

Process Boilers #1 and #2 75% 19.81 59.42 $2,190,300 $303,758 $5,112 n/a

Line 1 Dryer 75% 3.77 11.32 $1,087,058 $134,645 $11,891 $19,493Regenerative Selective Catalytic Reduction (R-SCR)Process Boilers #1 and #2 70% 23.77 55.46 $16,117,290 $3,303,391 $59,563 n/aLine 1 Dryer 70% 4.53 10.57 $5,445,064 $1,024,459 $96,934 n/aLow NOX Burner / Overfire Air (OFA)

Process Boilers #1 and #2 67% 26.15 53.08 $3,031,714 $390,751 $7,361 na

Line 1 Dryer 67% 4.98 10.12 $888,317 $116,686 $11,535 $21,669Low NOX Burner

Process Boilers #1 and #2 50% 39.61 39.61 $1,320,909 $286,968 $7,244 n/a

Line 1 Dryer 50% 7.55 7.55 $432,579 $61,070 $8,090 n/aSelective Non-Catalytic Reduction (SNCR)Process Boilers #1 and #2 50% 39.61 39.61 $1,501,420 $468,772 $11,833 n/aLine 1 Dryer 50% 7.55 7.55 $915,968 $278,929 $36,949 n/a

SO2 Control Cost Summary 

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Annualized Cost $/yr Pollution Control Cost $/ton Incremental Cost

Spray Dry BaghouseProcess Boilers #1 and #2 90% 0.03 0.23 $56,323,180 $8,640,697 $38,403,097 n/a

Line 1 Dryer 90% 0.03 0.23 $26,617,360 $4,025,029 $17,889,019 n/aWet ScrubberProcess Boilers #1 and #2 80% 0.05 0.20 $9,309,297 $1,489,576 $7,447,882 n/aLine 1 Dryer 80% 6.81 27.26 $3,898,490 $684,207 $25,103 n/aWet ESP (WWESP)Process Boilers #1 and #2 80% 0.05 0.20 $17,123,526 $3,146,592 $15,732,959 n/aLine 1 Dryer 80% 6.81 27.26 $7,674,618 $1,429,065 $52,432 n/aDSI BaghouseProcess Boilers #1 and #2 55% 0.11 0.14 $32,010,048 $4,892,432 $35,581,325 n/aLine 1 Dryer 55% 0.04 0.14 $26,023,184 $4,079,117 $29,666,302 n/a

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix A Tilden Process Boilers Control Costs.xlsCost Summary

138
Michigan Operations - West (Tilden)

BART Report - Changes to MDEQ BART Modeling ProtocolAppendix B

CALMET

Variable Description Value Default Comments

NX Number of X grid cells 66 n/a

NY Number of Y grid cells 39 n/a

XORIGKM Reference point coordinates for grid 180 n/a

YORIGKM Reference point coordinates for grid 612 n/a

NOOBS No Observation Mode 0 Y Include Surface, Upper Air and 

NSSTA Number of Surface Stations 88 n/a 88 surface weather stationsNPSTA Number of Precipitation Stations 99 n/a 99 precipitation stations

Input Group 5

BIAS Surface/upper-air weighting factors -1, 11*0 12*0 Surface Layer is set to -1 since 

ITPROG 3D temperature from observations or from prognostic data? 0 Y Inclusion of Surface and Upper 

CALPUFF

Variable Description Value Default Comments

NX Number of X grid cells in met grid 66 n/a

NY Number of Y grid cells in met grid 39 n/a

XORIGKM Reference point coordinates for met grid 180 n/a

YORIGKM Reference point coordinates for met grid 612 n/a

IBCOMP X index of LL corner 1 n/a

JBCOMP Y index of LL corner 1 n/a

IECOMP X index of UR corner 66 n/a

JECOMP Y index of UR corner 39 n/a

Input Group 2Input Group 4Input Group 6Input Group 4

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix B Changes to MDEQ BART Modeling Protocol (WEST).xls

Sheet1

139
Cleveland Cliffs Michigan Operations - Taconite BART Analysis

SO2 Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2

This table is part of the CCMO not be distributed without the fuinformation is not taken out of c

Reference No.

1

SO2 Pollution Control 

Technology 2 

Is this a generally available 

control technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible for 

this source? Approximate Control Efficiency

Comments Bas

1 Wet Scrubbing (High Efficiency) Y Y Y Y 90-95% Absorption and reaction using an alka

2 Wet Scrubbing (Low Efficiency) Y Y Y Y <50% Absorption and reaction using an alka

3 Wet Walled Electrostatic Precipitator (WWESP) Y Y Y Y 80% Suspended particles are separated from 

collected in hoppers

4 Dry sorbent injection Y Y Y Y <55%

Pulverized lime or limestone is directlfabric filter. Dry sorption of SO2 onto 

solid particles are collected with a fab

5 Spray Dryer Absorption (SDA) Y Y Y Y <90% Lime slurry is sprayed into an absorpt

slurry, forming CaSO3/CaSO4

6 Alternative Fuels Y Y

Y

(for furnaces 

capable of 

multiple fuels)

Y

(not required 

by BART)

Site-specific Natural gas is base case Use a fuel with lower sulfur content.

7 Load Reduction N --- --- --- --- Power plant technology This is a strategy to reduce load on a p

demand throught efficiency projects.

8 Energy Efficiency Projects Y Y

Y 

(for large 

projects like 

heat-recoup)

Y 

(for large 

projects like 

heat-recoup)

Site-specific decrease amount of fuel required to m

9 Coal Processing Y N --- --- --- Applies only to facilities that burn coal Dry coal will increase the as-burned B

to be burned. Specific energy efficien

10 Bio Filters N --- --- --- --- Research level

Gas stream passes through a packed bsupports the growth of active bacteriaare biodegraded or biotransformed intdioxide, water, chlor

11 CANSOLV Regenerable SO2 N --- --- --- --- Research level

An aqueous solution of proprietary di

countercurrent absorption tower. The 

stripping, giving a byproduct of pure, 

recycling to the a

12 Pahlman Process N --- --- --- --- Research level

Gas stream is passed through a filter b

particle, high-surface area metal oxide removed from the gases by adsorption

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Furnaces.xls

140
Cleveland Cliffs Michigan Operations - Taconite BART Analysis

SO2 Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2

This table is part of the CCMO not be distributed without the fuinformation is not taken out of c

Reference No.

1

SO2 Pollution Control 

Technology 2 

Is this a generally available 

control technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible for 

this source? Approximate Control Efficiency

Comments Bas

13 SOx-NOx-Rox-Box N --- --- --- --- Technology has not been demonstrated

Dry sorbent injection upstream of the injection upstream of a zeolitic selectiincorporated in the baghouse to reduc

14 Electron (E-Beam) Process N --- --- --- --- No operating commercial applications on coal Electron beam irradiation in the prese

conversion of sulfur and nitrogen oxidcollected by conventional methods su

15 Electrocatalytic Oxidation N --- --- --- --- Similar to cold plasma. Will keep watch for availability of this technology

Utilizes a reactor in which SO2, NOx, 

dioxide (NO2), sulfuric acid, and merc

plasma.On recent project, the vender was doin

16 NOXSO N --- --- --- --- Commercial version of adsorption. Limited experience (proof-of-concept tests).

Uses a regenerable sorbent to simultan

from coal-fired utility and industrial b

to a saleable sulfur by-product (liquid 

the NOx

17 Copper-Oxide N --- --- --- --- Absorption and SCR. Experience limited to pilot scale.

SO2 in the flue gas reacts with copper 

alumina, to form copper sulfate. Ammabsorption reactor and a selective catareduces the nitr

18 SNOX N --- --- --- --- Early commercial development stage

Catalytic reduction of NOx in the pres

catalytic oxidation of SO2 to SO3. The 

through a novel glass-tube condenser 

and then condensed to a

19 Cold Plasma N --- --- --- --- Research level

1) This number is for reference only. It does not in any way rank the control technologies.2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART Reports

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Furnaces.xls

141
Cleveland Cliffs Michigan Operations BART Analysis

SO2 Control

Process Boilers

Available and Applicable Review 

Step 1 Step 2

This table is part of the CCMO Process Boiler BART 

without the full text of the report so that the inform

Reference No.

1

SO2 Pollution Control 

Technology 2 

Is this a 

generally 

available 

control 

technology?

Is the control 

technology 

available to 

power boilers?

Is the control 

technology 

applicable to 

this specific 

source?

Is it technically 

feasible for this 

source?

Comments Basic Principle

1 Wet Scrubbing (High Efficiency) Yes Yes Yes Yes Absorption and reaction using an alkaline reagent to produ

2 Wet Scrubbing (Low Efficiency) Yes Yes Yes Yes Absorption and reaction using an alkaline reagent to produ

3 Wet Walled Electrostatic Precipitator (WWESP) Yes Yes Yes Yes Existing fabric filter control Suspended particles are separated from the flue gas stream

hoppers

4 Dry sorbent injection Yes Yes Yes Yes

Pulverized lime or limestone is directly injected into the dsorption of SO2 onto the lime or limestone particle occurs 

a fabric filter

5 Spray Dryer Absorption (SDA) Yes Yes Yes Yes Lime slurry is sprayed into an absorption tower where SO2 

CaSO3/CaSO4

6 Alternative Fuels Yes Yes Yes

Yes (not 

required by 

BART)

Not permitted for other fuels. Use a fuel with lower sulfur content.

7 Load Reduction Yes Yes No --- Could reduce production This is a strategy to reduce load on a power plant by reduc

efficiency projects.

8 Energy Efficiency Projects Yes Yes Yes Yes Decrease amount of fuel required to make an acceptable p9 Coal Drying Yes Yes No --- Requires available excess heat source Dry coal will increase the as-burned BTU value, and there

Specific energy efficiency project

10 Bio Filters No --- --- --- Research level

Gas stream passes through a packed bed of specially engingrowth of active bacterial species. The pollutants in the gabiotransformed into innocuous products, such as carbon disulfate or nitrate ions in water.

11 CANSOLV Regenerable SO2 No --- --- --- Research level

An aqueous solution of proprietary diamine captures SO2 f

absorption tower. The rich solvent is regenerated by steam 

water saturated SO2 gas and lean solvent for recycling to th

12 Pahlman Process No --- --- --- Research level

Gas stream is passed through a filter baghouse in which spsurface area metal oxide sorbent have been deployed. Polladsorption.

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Process Boilers.xls

SOx Process Boilers

142
Cleveland Cliffs Michigan Operations BART Analysis

SO2 Control

Process Boilers

Available and Applicable Review 

Step 1 Step 2

This table is part of the CCMO Process Boiler BART 

without the full text of the report so that the inform

Reference No.

1

SO2 Pollution Control 

Technology 2 

Is this a 

generally 

available 

control 

technology?

Is the control 

technology 

available to 

power boilers?

Is the control 

technology 

applicable to 

this specific 

source?

Is it technically 

feasible for this 

source?

Comments Basic Principle

13 SOx-NOx-Rox-Box No --- --- --- Technology has not been demonstrated Dry sorbent injection upstream of the baghouse for remov

upstream of a zeolitic selective catalytic reduction (SCR) creduce NOx emissions.

14 Electron (E-Beam) Process No --- --- --- No operating commercial 

applications on coal

Electron beam irradiation in the presence of ammonia to innitrogen oxides into components which can be easily collean ESP or baghouse.

15 Electrocatalytic Oxidation No --- --- --- Similar to cold plasma. Will keep watch for availability 

of this technology

Utilizes a reactor in which SO2, NOx, and mercury are oxi

acid, and mercuric oxide respectively using non-thermal pOn recent project, the vender was doing final trials on full

16 NOXSO No --- --- --- Commercial version of adsorption. Limited experience 

(proof-of-concept tests).

Uses a regenerable sorbent to simultaneously adsorb SO2 a

utility and industrial boilers. In the process, the SO2 is con

(liquid SO2, elemental sulfur, or sulfuric acid) and the NO

17 Copper-Oxide No --- --- --- Absorption and SCR. Experience limited to 

pilot scale.

SO2 in the flue gas reacts with copper oxide, supported on 

copper sulfate. Ammonia is injected into the flue gas beforcatalytic reduction-type reaction occurs that reduces the niregeneration step, the copper sulfate is reduced in a regenenatural gas, producing a concentrated stream of SO2.

18 SNOX No --- --- --- Early commercial development stage

Catalytic reduction of NOx in the presence of ammonia (N

SO2 to SO3. The exit gas from the SO3 converter passes th

which the SO3 is hydrated to H2SO4 vapor and then conde

acid (H2SO4).

19 Cold Plasma No --- --- --- Research level

1) This number is for reference only. It does not in any way rank the control technologies.

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Process Boilers.xls

SOx Process Boilers

143
Cleveland Cliffs Michigan Operations BART Analysis

SO2 Control

Process Boilers

Available and Applicable Review 

Step 1 Step 2

This table is part of the CCMO Process Boiler BART 

without the full text of the report so that the inform

Reference No.

1

SO2 Pollution Control 

Technology 2 

Is this a 

generally 

available 

control 

technology?

Is the control 

technology 

available to 

power boilers?

Is the control 

technology 

applicable to 

this specific 

source?

Is it technically 

feasible for this 

source?

Comments Basic Principle

2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc. b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm c) New and Emerging Environmental Technologies, http://neet.rti.org/ d) ND BART Reports

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Process Boilers.xls

SOx Process Boilers

144
145

Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Dryer

Available and Applicable Review

Revised: December 1, 2006

Yes Yes Yes Yes Combustion air is separated into primary and secondary flow sections to achieve complete burnout and to encourage the formation ofN2 rather than NOx

Yes Yes Yes No Mixes flue gas with combustion air which reduces oxygen content and therefore 

reduces flame temperature

Yes Yes Yes Yes Burners are designed to reduce NOx formation through restriction ofoxygen, flame temperature, and/or residence time

Need to be upfired. Need 

Yes Yes Yes Yes convective loop to get gas Draws flue gas to dilute the fuel in order to reduce the flame temperature recirculated

Yes Yes Yes Yes Reduces roduction Reduces ox en content in flue as and reduces flame tern erature

Need capacity of all Shut offthe fuel flow fi·om one burner or more to create fuel rich and fuel lean 

Yes Yes Yes No burners for worst case 

scenario zones

Yes Yes Yes No Combustion is staged by diverting fuel from the upper level burners to the lower ones or from the center to the side burners to create and fucl·lcan zones

Part of the total fuel heat input is injected into the furnace in a region above the

Yes Yes Yes No primary (main burners) flames to create a reducing atmosphere zone),

where hydrocarbon radicals rcact with NOx to producc clemental nitrogen

Yes Yes No This is a strategy to reduce load on a power plant by reducing the elcctrical demand through efficiency rojects,

s Yes Yes Yes Yes Decrease amount offuel re uircd to make an acce table roduct

Yes Yes No Requires available excess Dry coal will increase the as-burned BTU value, and therefore less fuel is required heat. to be burned, Specific energy efficiency project

g Yes Yes No Could reduce load Cooling ofthe primary flame zone by heat transfer to surrounding surfaces capabilities

eport\Appendix\Appendix 0 Michigan Operations Control Technologies Dryer.xls

1 of 4

12/21/2006
146

Cleveland Cliffs Michigan Operations BART Analysis

NOxControl

Oryer

Available and Applicable Review

Requires case by case

Yes (not analysis. Typically, Lower combustion temps with solid fuels vs gas. 

15 Alternate Fuels Yes Yes Yes required by facilities experience lower

BART) NOx when burning solid using a fuel with less nitrogen.

fuels.

16 Oxygen Enhanced No Research level A small fraction ofthe combustion air is replaced 

Combustion

Pulverized coal preheated and volatiles and 

17 Preheat Combustion No Research level released in a controlled reducing atmosphere wh

reduced to Nz.

This is addressed through Combination nfGFA and SCR. Wall-fired or 

18 ROFA-ROTAMIX Yes Yes Yes 'Yes the scenario that combines utilizes high velocity overflre air. Additional NO

OFAand SCR anunonia injection (Rotamix)

Current equipment cannot

19 NOxCEMS Yes Yes Yes "'-'-No---""---·'" be tuned to'impact NOx Optimization of combustion

emissions

CUrrent e,quipment cannot

20 Parametric Monitoring Yes Yes Yes No be tuned to impact NOx Optimization of combustion

emissions

Catalyst Injection

A combustion catalyst is directly injected into the 

38 No Research Level to the combustion site, initiating chemical reactio

(EPS Technologies) the flame.

21 Non-Selective Catalytic Yes Yes Yes Yes Not ,efficient as other Under near stoichiometric conditions, in the pres

Reduction (NSCR) reduced by CO, resulting in nitrogen (N2) and ca

22 Low Temperature Oxidation Yes Yes No Requires ozone generation Utilizes an oxidizing agent such as ozone to oxid

(LTD) Tri-NOx® NOx

Y:\22\52\OBO Tilden BART\BART report\Appendix\Appendix 0 Michigan Operations Control Technologies M Dryer.xls

NOx Dryer
147

Cleveland Cliffs Michigan Operations BART Analysis

NOx COl")trol

Dryer.

Available and Applicable Review

Revised: December 1, 2006

n Yes 

on Yes 

No

Yes Yes Yes

Has been included as an

"innovative" technology in

recent BACT analyses

from multiple facilities.

Need to inject at

appropriate temperature.

Applicable to clean

services.

Utilizes an oxidizing agent such as ozone to oxidize various pollutants including

NOx

Ammonia (NH)) is injected into the flue gas stream in the presence ofa catalyst to

convert NOx into Nz and water

Yes

Yes

No

Yes

Yes

No

Yes

Yes

Yes

YesYes

Yes

Yes

Yes

Yes

•.. j .",

For clean services. Too

much debris in flue gas

would poison catalyst

Still in research sta es.

Similar to TriNOx

Redundant to regenerative

. ...,r;

Urea or ammonia·based chemicals are injected into the flue gas stream to COnvert

NO to molecular nitrogen, N2, and water

Use of char activated carbon to adsorb oxides ofnitro en

Use of water, hydroxide and carbonate solutions, sulfuric acid, organic solutions,

molten alkali carbonates, or hydroxides to absorb oxides ofnitrogen.

Gas stream is sent through the regenerative, recuperative, catalytic or direct fired

oxidizer where pollutants are heated to a combustion point and destroyed.

No

No

Early'col1li:nercial

development stage

Technology has not been

demonstrated

Catalytic reduction ofNOx in the presence of ammonia (NH]), followed by

catalytic oxidation ofS02 to SO]. The exit gas from the SO) converter passes

through a novel glass-tube condenser in which the SO] is hydrated to H2S04

vapor and then condensed to a concentrated liquid sulfuric acid (H2S04),

Dry sorbent injection upstream ofthe baghouse for removal of SOx and ammonia

injection upstream ofa zeolitic selective catalytic reduction (SCR) catalyst

incorporated in the baghouse to reduce NOx emissions.

eport\Appendix\Appendix D Michigan Operations Control Technologies 7 Dl)Ier.xls

.

30f4

1212112006
148

Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Dryer

Available and Applicable Review

No operating commercial Electron beam irradiation in the presence of ammo

32 Electron (E-Beam) Process No applications on coal conversion ofsulfur and nitrogen oxides into com

collected by conventional methods such as an ESP 

Similar to cold plasma.

Utilizes a reactor in which S02' NOx, and mercur

Will keep watch for dioxide (N02), sulfuric acid, and mercuric oxide r

33 Electrocatalytic Oxidation No availability ofthis plasma.

technology On recent project, the vender was doing final trial

Commercial version of Uses a regenerable sorbent to simultaneously adso

34 NOXSO No adsorption. Limited from utility and industrial boilers. In the 

experience to a saleable sulfur by-product (liquid SOz, elemen

concept tests). the NOx is converted to nitrogen and oxygen.

S02 in the flue gas reacts with copper oxide, supp

Absorption and SCR. alumina, to fonn copper sulfate. Ammonia is injec

absorption reactor and a selective catalytic 

35 No e,·. ExperitmceJimited to pilot reduces the nitric oxides in the flue gas. In the reg

scale. sulfate is reduced in a regenerator with a reducing 

producing a concentrated stream ofS02.

36 Cold Plasma No Research Level

Gas stream is passed through a filter medium ofs

37 Biofilters No Research level adsorbed and degraded by microbial metabolism 

dioxide and water.

Gas stream is passed through a filter baghouse in 

38 Pahlman Process No Research Level area metal oxide sorb

Pollutants are removed from the gases by adsor ti

I) This number is for reference only. It does not in any way rank the control technologies.

2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.

b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogaptil/inodule6/index.htm

c) New and Emerging Environmental Technologies, http://neet.rti.orgl

d) ND BART Reports

Y:\22\52\080 Tilden BART\8ART report\Appendix\Appendix 0 Michigan Operations Control Technologies,. Dryer,xis

NOx Dryer
149

Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Process Boilers

Available and Applicable Review DRAFT

Revised: December 1, 2006

Yes Yes Yes Yes Combustion air is separated into primary and secondary flow sections to achieve complete burnout and to encourage the fonnation ofN1 rather than NOx

Yes Yes Yes No Mixes flue gas with combustion air which reduces oxygen content and therefore 

reduces flame temperature

Yes Yes Yes Yes Burners are designed to reduce NOx fonnation through restriction ofoxygen, flame temperature, and/or residence time

Need to be upfired. Need 

Yes Yes Yes Yes convective loop to get gas Draws flue gas to dilute the fuel in order to reduce the flame temperature

recirculated

Yes Yes Yes Yes Reduces roduction Reduces ox en content in flue as and reduces flame tem erature

Need capacity of all Shut offthe fuel flow from one burner or more to create fuel rich and fuel lean 

Yes Yes Yes No bU111ers for worst case 

scenario zones

Yes Yes Yes No Combustion is staged by diverting fuel from the upper level burners to the lower ones or from the center to the side burners to create fuel-rich and fuel-leal). zones

Palt ofthe total fuel heat input is injected into the furnace in a region above the

Yes Yes Yes Yes primary (main burners) flames to create a reducing atmosphere (re-bum zone),

where hydrocarbon radicals react with NOx to produce elemental nitrogen

Yes Yes No This is a strategy to reduce load on a power plant by reducing the electrical demand through efficiency projects,

Yes Yes Yes Yes Decrease amount offuel re uired to make an acce table roduet

Yes Yes No Requires available excess Dry coal will increase the as-burned BTU value, and therefore less fuel is required heat. to be burned. Specific energy efficiency project

Yes Yes No Could reduce load Cooling ofthe primary flame zone by heat transfer to surrounding surfaces capabilities

port\Appendix\Appendix 0 -Michigan Operations Control Technologies - Process Boilers.xls

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NOx Control

Process Boilers

Available and Applicable Review 

Requires case by case

Yes (not analysis. Typically, Lower combustion temps with solid fuels vs gas. 

15 Altemate Fuels Yes Yes Yes required by facilities experience lower using a fuel with less nitrogen. BART) NOx when burning solid

fuels.

16 Oxygen Enhanced No Research level A small fraction ofthe combustion air is replaced 

Combustion

Pulverized coal preheated and volatiles and fuel-

17 Preheat Combustion No Research level released in a controlled reducing atmosphere wh

reduced to Nz.

This is addressed through Combination afCFA and SCR. Wall-fired or tan

18 ROFA-ROTAMIX Yes Yes Yes Yes the scenario that combines utilizes high velocity overfire air. Additional NO

OFA and SCR ammonia injection (Rotamix)

Current equipment cannot

19 NOxCEMS Yes Yes Yes No be tuned to impact NOx Optimization of combustion

emissionsCurrent equipment cannot

20 Parametric Monitoring Yes Yes Yes No he tuned to impact NOx Optimization of combustion

emissions

Catalyst Injection

A combustion catalyst is directly injected into th

38 No Research Level to the combustion site, initiating chemical reacti

(EPS Technologies) the flame.

Catalytic For clean services. Too Under near stoichiometric conditions, in the pre

21 Reduction (NSCR) Yes Yes Yes Yes much debris in flue gas reduced by CO, resulting in nitrogen (N2) and ca

would poison catalyst

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix 0 - Michigan Operations Conlrol Technologies Process Boilers.xls

NOx Process Boilers
151

Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Process Boilers

Available and Applicable Review DRAFT

Revised: December 1, 2006

Yes Yes No Requires ozone generation Utilizes an oxidizing agent such as ozone to oxidize various pollutants including 

NOx

Has been included as an

Yes No "innovative" technology in Utilizes an oxidizing agent such as ozone to oxidize various pollutants including 

recent BACT analyses NOx

from multiple facilities.

Need to inject at

Yes Yes Yes Yes appropriate temperature. Ammonia (NH3) is injected into the flue gas stream in the presence of a catalyst to 

Applicable to clean convert NOx into N2 and water

services.

For clean services. Too

Yes No much debris in flue gas

would poison catalyst

Yes Yes Yes Yes Urea or ammonia-based chemicals are injected into the flue gas stream to convert 

NO to molecular nitrogen, N2, and water

No Still in research stages. Usc of char activated carbon to adsorb oxides ofnitro en

Yes Yes No Similar to TriNOx Use of water, hydroxide and carbonate solutions, sulfuric acid, organic solutions, molten alkali carbonates, or hydroxides to absorb oxides ofnitrogen.

Yes Yes Yes Yes Redundant to regenerative Gas stream is sent through the regenerative, recuperative, catalytic or direct fired SCR oxidizer where pollutants are heated to a combustion point and destroyed.

port\Appendix\Appendix 0 - Michigan Operations Control Technologies Process Boilers.xls

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Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Process Boilers

Available and Applicable Review 

30

31

32

33

34

3S

36

SNOX

SOx-NOx-Rox-Box

Electron (E-Beam) Process

Electrocatalytic Oxidation

NOXSO

Copper-Oxide

Cold Plasma

No

NoNo

NoNo

NoNo

Early commercial

stage

Technology has not been

demonstrated

No operating commercial

applications on coal

Similar to cold plasma.

Will keep watch for

availability ofthi5

Commercial version of

adsorption. Limitedexperience

concept tests).

Absorption and SCR.

Experience limited to pilot

scale.

Research Level

Catalytic reduction ofNOx in the presence of am

catalytic oxidation of S02 to S03' The exit gas fr

through a novel glass-tube condenser in which th

vapor and then condensed to a concentrated liqu

Dry sorbent injection upstream ofthe baghouse f

injection upstream of a zeolitic selective catalytic 

incorporated in the baghouse to reduce NOx emi

Electron beam irradiation in the presence of amm

conversion ofsulfur and nitrogen oxides into com

collected by conventional methods such as an ES

Utilizes a reactor in which S02' NOx, and mercu

dioxide (N0z), sulfuric acid, and mercuric oxide 

plasma.

On recent project, the vender was doing final tri

Uses a regenerable sorbent to simultaneously ad

fi'om utility and industrial boilers. In th

to a saleable sulfur by-product (liquid S02, elem

the NOx is converted to nitrogen and oxygen.

S02 in the flue gas reacts with copper oxide, sup

alumina, to fonn copper sulfate. Ammonia is injabsorption reactor and a selective catalytic reduc

reduces the nitric oxides in the flue gas. In the re

sulfate is reduced in a regenerator with a reducin

producing a concentrated stream of S02'

Y:\22\52\OBO Tilden BART\BART report:\Appendlx\Appendix 0 Michigan Operations Control Technologies Process Boilers.xis

NOx Process Boilers
153

Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Process Boilers

Available and Applicable Review DRAFT

Revised: December 1, 2006

NoNo

Research level

Research Level

Gas stream is passed through a filter medium ofsoil and microbes. Pollutants are

adsorbed and degraded by microbial metabolism forming the products carbon

dioxide and water.

Gas stream is passed through a filter baghouse in which specially-developed,

small-particle, high-surface area metal oxide sorbent have been deployed.

Pollutants are removed from the gases b adsor tion.

nly. It does not in any way rank the control technologies.

d Control. Wark, Kenneth; Wamer, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.

Environmental Science, Module 6, http://www.epa.gov/eogaptillmodule6/index.htm

mental Technologies, http://neet.rti.org!

eport\Appendix\Appendix 0 - Michigan Operations Control Technologies Process Boilers.xls

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Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Process Boilers

Available and Applicable Review DRAFT

Revised: December 1, 2006

Yes Yes Yes Yes Combustion air is separated into primary and secondary flow sections to achieve complete burnout and to encourage the fonnation ofN1 rather than NOx

Yes Yes Yes No Mixes flue gas with combustion air which reduces oxygen content and therefore 

reduces flame temperature

Yes Yes Yes Yes Burners are designed to reduce NOx fonnation through restriction ofoxygen, flame temperature, and/or residence time

Need to be upfired. Need 

Yes Yes Yes Yes convective loop to get gas Draws flue gas to dilute the fuel in order to reduce the flame temperature

recirculated

Yes Yes Yes Yes Reduces roduction Reduces ox en content in flue as and reduces flame tem erature

Need capacity of all Shut offthe fuel flow from one burner or more to create fuel rich and fuel lean 

Yes Yes Yes No bU111ers for worst case 

scenario zones

Yes Yes Yes No Combustion is staged by diverting fuel from the upper level burners to the lower ones or from the center to the side burners to create fuel-rich and fuel-leal). zones

Palt ofthe total fuel heat input is injected into the furnace in a region above the

Yes Yes Yes Yes primary (main burners) flames to create a reducing atmosphere (re-bum zone),

where hydrocarbon radicals react with NOx to produce elemental nitrogen

Yes Yes No This is a strategy to reduce load on a power plant by reducing the electrical demand through efficiency projects,

Yes Yes Yes Yes Decrease amount offuel re uired to make an acce table roduet

Yes Yes No Requires available excess Dry coal will increase the as-burned BTU value, and therefore less fuel is required heat. to be burned. Specific energy efficiency project

Yes Yes No Could reduce load Cooling ofthe primary flame zone by heat transfer to surrounding surfaces capabilities

port\Appendix\Appendix 0 -Michigan Operations Control Technologies - Process Boilers.xls

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Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Process Boilers

Available and Applicable Review 

Requires case by case

Yes (not analysis. Typically, Lower combustion temps with solid fuels vs gas. 

15 Altemate Fuels Yes Yes Yes required by facilities experience lower using a fuel with less nitrogen. BART) NOx when burning solid

fuels.

16 Oxygen Enhanced No Research level A small fraction ofthe combustion air is replaced 

Combustion

Pulverized coal preheated and volatiles and fuel-

17 Preheat Combustion No Research level released in a controlled reducing atmosphere wh

reduced to Nz.

This is addressed through Combination afCFA and SCR. Wall-fired or tan

18 ROFA-ROTAMIX Yes Yes Yes Yes the scenario that combines utilizes high velocity overfire air. Additional NO

OFA and SCR ammonia injection (Rotamix)

Current equipment cannot

19 NOxCEMS Yes Yes Yes No be tuned to impact NOx Optimization of combustion

emissionsCurrent equipment cannot

20 Parametric Monitoring Yes Yes Yes No he tuned to impact NOx Optimization of combustion

emissions

Catalyst Injection

A combustion catalyst is directly injected into th

38 No Research Level to the combustion site, initiating chemical reacti

(EPS Technologies) the flame.

Catalytic For clean services. Too Under near stoichiometric conditions, in the pre

21 Reduction (NSCR) Yes Yes Yes Yes much debris in flue gas reduced by CO, resulting in nitrogen (N2) and ca

would poison catalyst

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix 0 - Michigan Operations Conlrol Technologies Process Boilers.xls

NOx Process Boilers
156

Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Process Boilers

Available and Applicable Review DRAFT

Revised: December 1, 2006

Yes Yes No Requires ozone generation Utilizes an oxidizing agent such as ozone to oxidize various pollutants including 

NOx

Has been included as an

Yes No "innovative" technology in Utilizes an oxidizing agent such as ozone to oxidize various pollutants including 

recent BACT analyses NOx

from multiple facilities.

Need to inject at

Yes Yes Yes Yes appropriate temperature. Ammonia (NH3) is injected into the flue gas stream in the presence of a catalyst to 

Applicable to clean convert NOx into N2 and water

services.

For clean services. Too

Yes No much debris in flue gas

would poison catalyst

Yes Yes Yes Yes Urea or ammonia-based chemicals are injected into the flue gas stream to convert 

NO to molecular nitrogen, N2, and water

No Still in research stages. Usc of char activated carbon to adsorb oxides ofnitro en

Yes Yes No Similar to TriNOx Use of water, hydroxide and carbonate solutions, sulfuric acid, organic solutions, molten alkali carbonates, or hydroxides to absorb oxides ofnitrogen.

Yes Yes Yes Yes Redundant to regenerative Gas stream is sent through the regenerative, recuperative, catalytic or direct fired SCR oxidizer where pollutants are heated to a combustion point and destroyed.

port\Appendix\Appendix 0 - Michigan Operations Control Technologies Process Boilers.xls

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Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Process Boilers

Available and Applicable Review 

30

31

32

33

34

3S

36

SNOX

SOx-NOx-Rox-Box

Electron (E-Beam) Process

Electrocatalytic Oxidation

NOXSO

Copper-Oxide

Cold Plasma

No

NoNo

NoNo

NoNo

Early commercial

stage

Technology has not been

demonstrated

No operating commercial

applications on coal

Similar to cold plasma.

Will keep watch for

availability ofthi5

Commercial version of

adsorption. Limitedexperience

concept tests).

Absorption and SCR.

Experience limited to pilot

scale.

Research Level

Catalytic reduction ofNOx in the presence of am

catalytic oxidation of S02 to S03' The exit gas fr

through a novel glass-tube condenser in which th

vapor and then condensed to a concentrated liqu

Dry sorbent injection upstream ofthe baghouse f

injection upstream of a zeolitic selective catalytic 

incorporated in the baghouse to reduce NOx emi

Electron beam irradiation in the presence of amm

conversion ofsulfur and nitrogen oxides into com

collected by conventional methods such as an ES

Utilizes a reactor in which S02' NOx, and mercu

dioxide (N0z), sulfuric acid, and mercuric oxide 

plasma.

On recent project, the vender was doing final tri

Uses a regenerable sorbent to simultaneously ad

fi'om utility and industrial boilers. In th

to a saleable sulfur by-product (liquid S02, elem

the NOx is converted to nitrogen and oxygen.

S02 in the flue gas reacts with copper oxide, sup

alumina, to fonn copper sulfate. Ammonia is injabsorption reactor and a selective catalytic reduc

reduces the nitric oxides in the flue gas. In the re

sulfate is reduced in a regenerator with a reducin

producing a concentrated stream of S02'

Y:\22\52\OBO Tilden BART\BART report:\Appendlx\Appendix 0 Michigan Operations Control Technologies Process Boilers.xis

NOx Process Boilers
158

Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Process Boilers

Available and Applicable Review DRAFT

Revised: December 1, 2006

NoNo

Research level

Research Level

Gas stream is passed through a filter medium ofsoil and microbes. Pollutants are

adsorbed and degraded by microbial metabolism forming the products carbon

dioxide and water.

Gas stream is passed through a filter baghouse in which specially-developed,

small-particle, high-surface area metal oxide sorbent have been deployed.

Pollutants are removed from the gases b adsor tion.

nly. It does not in any way rank the control technologies.

d Control. Wark, Kenneth; Wamer, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.

Environmental Science, Module 6, http://www.epa.gov/eogaptillmodule6/index.htm

mental Technologies, http://neet.rti.org!

eport\Appendix\Appendix 0 - Michigan Operations Control Technologies Process Boilers.xls

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Cleveland Cliffs Michigan Operations· Taconite BART Analysis

502 Control

Indurating Furnaces

Available and Applicable Review

2 y y y y <50% Absorption aud reaction using all a

Wet Scrubbing (High

__

-1f + -/- If-

__

---11---------------f------------

Wet Scrubbing (Low

Efficiency)

Wet Walled Electrostatic

Preci itator (WWESP) y y y y 80% Suspcnded particles are scparated 

collected in ho ers

4 Dry sorbent injection y y y y <55%

Pulverized lime or limestone is dir

fabric filter, Dry sorption of S02 o

solid particles arc collectedwitlt a 

5 Spray Dryer Absorption

6 Allemative Fuels

7 Load Reduction

8 Energy Efficiency Projects

9 Coal Processing

10 Bio Filters

y

y

N

y

y

N

y

yy

N

y

y

(for furnaces

capable of

multiple fLlels)

y

(for large

projects

heat-recou

y

y

(not required

by BART)

y

(for large

prqjects.llke

<90%

Site-specific Natural gas is base case

Powcr plant technology

Site-specific

Applies only to facilities tllat burn coal

level

Use a fuel with lower sulfur conte

Tbis is a strategy to rcduce load al

demand thrall htcfficienc ro·ccdecrease amount offuel required 

Dry coal will increase the as-bunte

to be bunted, 8 ecific ener effi

Gas stream passes through a pack

supports tlte growth of active bact

are biodegraded or biotransfonned 

dioxide, water, clilor

II CANSOLV Regenerable S02 N Research level

All aqueous solution ofproprietar

countercurreut absorption tower. T

stripping, giving a byproduct of pu

recycling to the a

12 Pahlman Process N Rcsearch level

Gas stream is passed through a fil

particlc, high·surface area metal o

removed from the gascs by adso 

13 SOx-NOx-Rox-Box N Teclmology has not been demonstrated

Dry sorbcnt injection npstream of

injection upstream of a zeolitic se

incorporated in tlte bagltouse to re

Y:\22\52\080 Tilden BART\BART repor1\Appendix\Appendix D· Michigan Operations Control Technologies _Furnaces.xls

502 Tables - Furnace
160

Cleveland Cliffs Michigan Operations· Taconite BART Analysis

502 Control

Indurating Furnaces

Available and Applicable Review

Revised: December 1, 2006

No operating commercial applications all

coal

Similar to cold plasma. Will keep watch fa

availability Ofl11is technology

Commercial version of adsorption. Limited

experience (proof-of-concept tests).

Absorption and SCR. Experience limited to

pilot scale.

arly commercial development stage

Electron beam irradiation in the presence of ammonia to initiate chemical

conversion ofsulfur and nitrogen oxides into components wl\ic1\ can be easily

collected by conventional methods such as an ESP or baghouse.

Utilizes a reactor in whic1\ S02' NOll, and mercury are oxidized to nitrogen

dioxide (N02), sulfuric acid, and mercuric oxide respectively using lloll-thenllal

plasma.

On recent project, the vender was doing fInal trials all full-scale applications.

Uses a regenerable sorbent to simultaneously adsorb S02 and NOx from flue gas

from coal-fired utility and industrial boilers. In the process, die S02 is converted t

a saleable sulfilr by-product (liquid S02, elemental sulfur, or sulfuric acid) and the

NO,

S02 in the flue gas reacts witll copper oxide, supported on small spheres of

alumina, to fonn copper snlfate. Ammonia is injected into the flue gas before the

absorption reactor and a selective catalytic reduction-type reaction occurs that

reduces the nitr

Catalytic reduction ofNOx in the presence of ammonia (NHl ), followed by

catalytic oxidation ofS02 to SOl' The exit gas from the S03 converter passes

through a novel glass-tube condenser in which the S03 is hydrated to H2S04 vapor

and then condensed to a

h level

es not in any way rank the control tcclmologies.

Wark, Kennetll; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Tuc.

mental Science, Module 6, http://www.epa.gov/eogaptillmodllle6/index.1Jtm

echnologies, llttp:llncet..rti.orgl

Appendix o· Michigan Operations Control Technologies - Furnaces.xls

20f2

12/20/2006
Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Dryer

Available and Applicable Review

Step 1 Step 2

This table is part of the CCMO Process 

be distributed without the full text of t

not taken out 

Reference No.

1

NOx Pollution Control 

Technology 2 

Is this a 

generally 

available 

control 

technology?

Is the control 

technology 

available to 

power boilers?

Is the control 

technology 

applicable to 

this specific 

source?

Is it technically 

feasible for this 

source?

Comments Basic Pri

Combustion Controls

1 Overfire Air (OFA) Yes Yes Yes Yes Combustion air is separated into primary an

complete burnout and to encourage the form

2 External Flue Gas Recirculation (EFGR) Yes Yes Yes No Mixes flue gas with combustion air which 

reduces flame temperature

3 Low-NOx Burners Yes Yes Yes Yes Burners are designed to reduce NOx forma

flame temperature, and/or residence time

4 Induced Flue Gas Recirculation Burners Yes Yes Yes Yes Need to be upfired. Need convective loop to get gas recirculated Draws flue gas to dilute the fuel in order to 

5 Low Excess Air Yes Yes Yes Yes Reduces production Reduces oxygen content in flue gas and red6 Burners out of Service (BOOS) Yes Yes Yes No Need capacity of all burners for worst case scenario Shut off the fuel flow from one burner or m

zones

7 Fuel Biasing Yes Yes Yes No Combustion is staged by diverting fuel from 

ones or from the center to the side burners 

8 Reburning Yes Yes Yes No

Part of the total fuel heat input is injected iprimary (main burners) flames to create a rwhere hydrocarbon radicals react with NOx 

9 Load Reduction Yes Yes No --- This is a strategy to reduce load on a power 

demand through efficiency projects.

10 Energy Efficiency Projects Yes Yes Yes Yes Decrease amount of fuel required to make 

11 Coal Drying Yes Yes No --- Requires available excess heat. Dry coal will increase the as-burned BTU v

required to be burned. Specific energy effi

14 Combustion Zone Cooling Yes Yes No --- Could reduce load capabilities Cooling of the primary flame zone by heat 

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D Michigan Operations Control Technologies - Dryer.xlsNOx Dryer

161
Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Dryer

Available and Applicable Review

Step 1 Step 2

This table is part of the CCMO Process 

be distributed without the full text of t

not taken out 

Reference No.

1

NOx Pollution Control 

Technology 2 

Is this a 

generally 

available 

control 

technology?

Is the control 

technology 

available to 

power boilers?

Is the control 

technology 

applicable to 

this specific 

source?

Is it technically 

feasible for this 

source?

Comments Basic Pri

15 Alternate Fuels Yes Yes Yes

Yes (not 

required by 

BART)

Requires case by case analysis. Typically, facilities experience lower NOx when burning solid fuels.

Lower combustion temps with solid fuels vusing a fuel with less nitrogen.

16 Oxygen Enhanced Combustion No --- --- --- Research level A small fraction of the combustion air is re17 Preheat Combustion No --- --- --- Research level

Pulverized coal preheated and volatiles and released in a controlled reducing atmospherreduced to N2.

18 ROFA-ROTAMIX Yes Yes Yes Yes

This is addressed through the scenario that combines OFA and SCR

Combination of OFA and SCR. Wall-fired utilizes high velocity overfire air. Additionaammonia injection (Rotamix)

19 NOx CEMS Yes Yes Yes No

Current equipment cannot be tuned to impact NOx emissions

Optimization of combustion

20 Parametric Monitoring Yes Yes Yes No

Current equipment cannot be tuned to impact NOx emissions

Optimization of combustion

38 Catalyst Injection (EPS Technologies) No --- --- --- Research Level A combustion catalyst is directly injected in

to the combustion site, initiating chemical rthe flame.

Post Combustion Controls

21 Non-Selective Catalytic Reduction (NSCR) Yes Yes Yes Yes Not as efficient as other control technologies Under near stoichiometric conditions, in th

reduced by CO, resulting in nitrogen (N2) a

22 Low Temperature Oxidation (LTO) - Tri-NOx® Yes Yes No --- Requires ozone generation Utilizes an oxidizing agent such as ozone to 

NOx

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D Michigan Operations Control Technologies - Dryer.xlsNOx Dryer

162
Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Dryer

Available and Applicable Review

Step 1 Step 2

This table is part of the CCMO Process 

be distributed without the full text of t

not taken out 

Reference No.

1

NOx Pollution Control 

Technology 2 

Is this a 

generally 

available 

control 

technology?

Is the control 

technology 

available to 

power boilers?

Is the control 

technology 

applicable to 

this specific 

source?

Is it technically 

feasible for this 

source?

Comments Basic Pri

23 Low Temperature Oxidation (LTO) - LoTOx Yes No --- --- Has been included as an "innovative" technology in recent BACT analyses 

from multiple facilities.

Utilizes an oxidizing agent such as ozone to NOx

24 Selective Catalytic Reduction (SCR) Yes Yes Yes Yes

Need to inject at appropriate temperature. Applicable to clean services.

Ammonia (NH3) is injected into the flue ga

to convert NOx into N2 and water

25 Regenerative SCR Yes No --- --- For clean services. Too much debris in flue gas 

would poison catalyst

26 Selective Non-Catalytic Reduction (SNCR) Yes Yes Yes Yes Urea or ammonia-based chemicals are inje

NO to molecular nitrogen, N2, and water

27 Adsorption No --- --- --- Still in research stages. Use of char (activated carbon) to adsorb ox28 Absorption Yes Yes Yes Yes Similar to TriNOx Use of water, hydroxide and carbonate solu

molten alkali carbonates, or hydroxides to a

29 Oxidizer Yes Yes Yes Yes Redundant to regenerative SCR Gas stream is sent through the regenerative

oxidizer where pollutants are heated to a co

30 SNOX No --- --- --- Early commercial development stage

Catalytic reduction of NOx in the presence 

catalytic oxidation of SO2 to SO3. The exit 

through a novel glass-tube condenser in wh

vapor and then condensed to a concentrated 

31 SOx-NOx-Rox-Box No --- --- --- Technology has not been demonstrated Dry sorbent injection upstream of the bagh

injection upstream of a zeolitic selective caincorporated in the baghouse to reduce NO

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D Michigan Operations Control Technologies - Dryer.xlsNOx Dryer

163
Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Dryer

Available and Applicable Review

Step 1 Step 2

This table is part of the CCMO Process 

be distributed without the full text of t

not taken out 

Reference No.

1

NOx Pollution Control 

Technology 2 

Is this a 

generally 

available 

control 

technology?

Is the control 

technology 

available to 

power boilers?

Is the control 

technology 

applicable to 

this specific 

source?

Is it technically 

feasible for this 

source?

Comments Basic Pri

2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc. b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm c) New and Emerging Environmental Technologies, http://neet.rti.org/ d) ND BART Reports

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D Michigan Operations Control Technologies - Dryer.xls

NOx Dryer

164
Appendix E Summary of Relevant Economic Feasility ($/ton) Control Costs 

Appendix E Clean Air Interstate Rule (CAIR), Cost-Effecti

Comments

Reference Regulatory Body/Rule SO2 NOx SO2 NOx

BART 100 to 1000 100 to 1000 70 FR 39135BART 281 to 1296 70 FR 39135 Table BART 919 70 FR 39133BART Guidelines dispara

dollars per ton" in cexceed MACT and 

70_FR_25210_CAIR.pdf CAIR 1300 Estimated Margina

BART(proposed rule) 200-1000

BART proposed lis

SO2 control, which lb/MMBtu. Droppeflexibility to require bypasses aren't BABART.

BART(proposed rule)

0.2 lb/MMBtu for N

Recognizes that so

get this level. For t

cost vs. visibility va

CAIR(using IPM) 1000 1500CAIR ( 2009 in 1999$) 900 2400CAIR ( 2015 in 1999$) 1800 3000CAIR (depending on Nat'l emissions) 1200 - 3000 1400- 2100

This was modeled 

Retrofitting Updatinmarginal values.

Kammer_EPA_Decision.doc Kammer Decision over 1000 over 1000

LADCO_MidwestRPO_Boiler Analysis.pdf LADCO/Midwest RPO 1240 to 3822 607 to 4493MANE-VU_BART_Control_Assessment.pdf MANE-VU 200-500 200-1500Bowers_vs_SWAPCA.txt Bowers vs SWAPCA 300 300 1000 1000

954-1134 was rule

for SO2. This did cSections XVII to XI

WRAP 3000EPA - Referenced by Wrap

References EPA-6

<$500/ton, Moderaover $3000/ton

WRAP_Trading_program_methodology.pdf

Avg. Expected Values ($/ton) Limiting/Marginal values ($/ton)

MidwestRPO_rept_referencing_CAIR.pdfFR_Notice_5MAY04_Proposed_Rule.pdfFR_Notice_6JULY05_Final_Rule.pdf

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix E - Table of Costs_per_ton.xls

165
DRAFT – BART Analysis Procedures 8/29/2006 

P:\22-52\CCMO BART\BART General Documents\BART Analysis Procedures.doc 

1

1. BART Eligibility 

BART eligibility is established on the basis on three criteria. In order to be BART-eligible, 

sources must meet the following three conditions: 

1. Contain emission units in one or more of the 26 listed source categories under the 

PSD rules (e.g., taconite ore processing plants, fossil-fuel-fired steam electric plants 

larger than 250 mmBtu/hr, fossil-fuel boilers larger than 250 mmBtu/hr, petroleum 

refineries, coal cleaning plants, sulfur recovery plants, etc.); 

2. Were in existence on August 7, 1977, but were not in operation before August 7, 

1962; 

3. Have total potential emissions greater than 250 tons per year for at least one 

visibility-impairing pollutant from the emission units meeting the two criteria above. 

Under the BART rules, large sources that have previously installed pollution control 

equipment required under another standard (e.g., MACT, NSPS and BACT) will be required 

to conduct visibility analyses. Installation of additional controls may be required to further 

reduce emissions of visibility impairing pollutants such as particulate matter (PM), PM10, 

PM2.5, sulfur dioxide (SO2), nitrous oxide (NOx), and possibly Volatile Organic Compounds 

(VOCs) and ammonia. Sources built before the implementation of the Clean Air Act (CAA), 

which had previously been grandfathered, may also have to conduct such analyses and 

possibly install controls, even though they have been exempted to date from any other CAA 

requirements. 

Once BART eligibility is determined, a source must then determine if it is ‘subject to BART.’ 

A source is subject to BART if emissions “cause or contribute” to visibility impairment at 

any Class I area. Visibility modeling conducted with CALPUFF or another U.S. EPAapproved visibility model is necessary to make a definitive visibility impairment 

determination (>0.5 deciviews). Sources that do not cause or contribute to visibility 

impairment are exempt from BART requirements, even if they are BART-eligible. 

2. BART Determinations 

Each source that is subject to BART must determine BART on a case-by-case basis. Even if a 

source was previously part of a group BART determination, individual BART determinations 

must be made for each source. The BART analysis takes into account six criteria and is 

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2

analyzed using five steps. The six criteria that comprise the engineering analysis include: the 

availability of the control technology, existing controls at a facility, the cost of compliance, 

the remaining useful life of a source, the energy and non-air quality environmental impacts of 

the technology, and the visibility impacts.1 The five steps of a BART analysis are: 

Step 1 - Identify all Available Retrofit Control Technologies 

The first step in the analysis is to identify all retrofit control technologies which 

are generally available for each applicable emission unit. Available retrofit 

control technologies are defined by U.S. EPA in Appendix Y to Part 51 

(Guidelines for BART Determinations under the Regional Haze Rule) as 

follows: 

Available retrofit technologies are those air pollution control 

technologies with a practical potential for application to the 

emissions unit and the regulated pollutant under evaluation. Air 

pollution control technologies can include a wide variety of available 

methods, systems, and techniques for control of the affected pollutant. 

Technologies required as BACT or LAER are available for BART 

purposes and must be included as control alternatives. The control 

alternatives can include not only existing controls for the source 

category in question, but also take into account technology transfer of 

controls that have been applied to similar source categories or gas 

streams. Technologies which have not yet been applied to (or 

permitted for) full scale operations need not be considered as 

available; we do not expect the source owner to purchase or construct 

a process or control device that has not been demonstrated in 

practice.2

Step 2 - Eliminate Technically Infeasible Options 

In the second step, the source-specific technical feasibility of each control 

option identified in step one is evaluated by answering three specific questions: 

 

1

 40 CFR 51 Appendix Y 

2

 Federal Register 70, No. 128 (July 6, 2005): 39164 

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3

a. Is the control technology “available” to the specific source which is 

undergoing the BART analysis? 

The U.S. EPA states that a control technique is considered “available” to a 

specific source “if it has reached the stage of licensing and commercial 

availability.3” However, the U.S. EPA further states that they “do not 

expect a source owner to conduct extended trials to learn how to apply a 

technology on a totally new and dissimilar source type.4” 

b. Is the control technology an “applicable technology” for the specific source 

which is undergoing the BART analysis? 

In general, a commercially available control technology, as defined in 

question 1, “will be presumed applicable if it has been used on the same or 

a similar source type.5” If a control technology has not been demonstrated

on a same or a similar source type, the technical feasibility is determined by 

“examining the physical and chemical characteristics of the pollutantbearing stream and comparing them to the gas stream characteristics of the 

source types to which the technology has been applied previously.6” 

c. Are there source-specific issues/conditions that would make the control 

technology not technically feasible? 

This question addresses specific circumstances that “preclude its 

application to a particular emission unit.” This demonstration typically 

includes an “evaluation of the characteristics of the pollutant-bearing gas 

stream and the capabilities of the technology7.” This also involves the 

identification of “un-resolvable technical difficulties.” However, when the 

technical difficulties are merely a matter of increased cost, the technology 

 

3

 Federal Register 70, No. 128 (July 6, 2005): 39165 

4

 IBID 

5

 IBID 

6

 IBID 

7

 IBID 

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4

should be considered technically feasible and the technological difficulty 

evaluated as part of the economic analysis8. 

It is also important to note that vendor guarantees can provide an indication 

of technical feasibility but the U.S. EPA does not “consider a vendor 

guarantee alone to be sufficient justification that a control option will 

work.” Conversely, the U.S. EPA does not consider as “sufficient 

justification that a control option or emission limit is technically infeasible. 

In general, the decisions on technical feasibility should be based on a 

combination of the evaluation of the chemical and engineering analysis and 

the information from vendor guarantees9. 

Step 3 - Evaluate Control Effectiveness 

In step three, the remaining controls are ranked based on the control efficiency 

at the expected emission rate (post-control) as compared to the emission rate 

before addition of controls (pre-BART) for the pollutant of concern. 

Step 4 - Evaluate Impacts and Document Results 

In the fourth step, an engineering analysis documents the impacts of each 

remaining control technology option. The economic analysis compares dollar 

per ton of pollutant removed for each technology. In addition, it includes 

incremental dollar per ton cost analysis to illustrate the economic effectiveness 

of one technology in relation to the others. Finally, step four includes an 

assessment of energy impacts and other non-air quality environmental impacts. 

Step 5 - Evaluate Visibility Impacts 

The fifth step requires a modeling analysis conducted with U.S. EPA-approved 

models such as CALPUFF. The modeling protocol10, including receptor grid, 

meteorological data, and other factors used for this part of the analysis were 

provided by the MDEQ. The model outputs, including the 98th percentile 

deciview (dV) value and the number of days the facility contributes more than a 

0.5 dV of visibility impairment at each of the Class I areas, are used to establish 

the degree of improvement that can be reasonably attributed to each technology. 

 

8

 IBID 

9

 IBID 

10 LADCO. March 21, 2006. Single Source Modeling to Support Regional Haze BART Modeling Protocol. 

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The final step in the BART analysis is to select the “best” alternative using the results of 

steps 1 through 5. In addition, the U.S. EPA guidance states that the “affordability” of the 

controls should be considered, and specifically states: 

1. Even if the control technology is cost effective, there may be cases where the 

installation of controls would affect the viability of plant operations. 

2. There may be unusual circumstances that justify taking into consideration the 

conditions of the plant and the economic effects requiring the use of a given 

control technology. These effects would include effects on product prices, the 

market share, and profitability of the source. Where there are such unusual 

circumstances that are judged to affect plant operations, you may take into 

consideration the conditions of the plant and the economic effects of requiring the 

use of a control technology. Where these effects are judged to have severe 

impacts on plant operations you may consider them in the selection process, but 

you may wish to provide an economic analysis that demonstrates, in sufficient 

detail for public review, the specific economic effects, parameters, and reasoning. 

(We recognize that this review process must preserve the confidentiality of 

sensitive business information). Any analysis may also consider whether 

competing plants in the same industry have been required to install BART 

controls if this information is available.11

To complete the BART process, the analysis must “establish enforceable emission limits that 

reflect the BART requirements and requires compliance within a reasonable period of 

time12.” Those limits must be developed for inclusion in the state implementation plan (SIP) 

that is due to U.S. EPA in December of 2007. In addition, the analysis must include 

requirements that the source “employ techniques that ensure compliance on a continuous 

basis13;” which could include the incorporation of other regulatory requirements for the 

source, including Compliance Assurance Monitoring (40 CFR 64), Periodic Monitoring (40 

CFR 70.6(a)(3)) and Sufficiency Monitoring (40 CFR 70(6)(c)(1)). If technological or 

economic limitations make measurement methodology for an emission unit infeasible, the 

 

11 Federal Register 70, No. 128 (July 6, 2005): 39171.

12 Federal Register 70, No. 128 (July 6, 2005): 39172.

13 IBID. 

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BART limit can “instead prescribe a design, equipment, work practice, operation standard, or 

combination of these types of standards14.” 

Compliance with the BART emission limits will be required within 5 years of U.S. EPA 

approval of the Michigan SIP. 

 

14 IBID. 

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DRAFT BART Eligible Emission Units Subject to a Streamlined BART Analysis 

1.0 Indurating Furnaces (PM Only) 

The indurating furnaces are sources of three visibility impairing pollutants: NOx, SO2, and PM. 

Relative to NOx and SO2, PM is not a major visibility impairing pollutant. Further, the 

indurating furnaces are subject to the taconite Maximum Achievable Control Technologies 

(MACT) standard [40 CFR Subpart RRRRR-NESHAPS: Taconite Iron Ore Processing] for the 

PM emissions. In 40 CFR Part 51 Appendix Y paragraph IV.C., it states: 

For VOC and PM sources subject to MACT standards, States may streamline the analysis 

by including a discussion of the MACT controls and whether any major new technologies 

have been developed subsequent to the MACT standards. We believe that there are many 

VOC and PM sources that are well controlled because they are regulated by the MACT 

standards, which EPA developed under CAA section 112. For a few MACT standards, 

this may also be true for SO2. Any source subject to MACT standards must meet a level 

that is as stringent as the best-controlled 12 percent of sources in the industry. Examples 

of these hazardous air pollutant sources which effectively control VOC and PM emissions 

include (among others) secondary lead facilities, organic chemical plants subject to the 

hazardous organic NESHAP (HON), pharmaceutical production facilities, and 

equipment leaks and wastewater operations at petroleum refineries. We believe that, in 

many cases, it will be unlikely that States will identify emission controls more stringent 

than the MACT standards without identifying control options that would cost many 

thousands of dollars per ton. Unless there are new technologies subsequent to the 

MACT standards which would lead to cost effective increases in the level of control, 

you may rely on the MACT standards for purposes of BART.(emphasis added)

It is clear from EPA’s guidance that they are encouraging states to develop a streamlined BART 

analysis approach for sources regulated under a MACT. Since the Taconite MACT standard was 

established very recently and becomes effective in 2006, the technology analysis is up-to-date. 

As a result, BART will be presumed to be equivalent to MACT for PM. 

A full BART analysis will be conducted for NOx and SO2 where applicable. 

2.0 Taconite MACT Emission Units (PM-Only) 

In addition to the indurating furnaces, the taconite MACT standard also regulates PM emissions 

from Ore Crushing and Handling operations, Pellet Coolers, and Finished Pellet Handling 

operations. These sources operate near ambient temperature, only emit PM, and do not emit NOx

or SO2. The Ore Crushing and Handling sources and the Finished Pellet Handling sources 

operate with control equipment to meet the applicable MACT limits (0.008 gr/dscf for existing 

sources and 0.005 gr/dscf for new sources). The Pellet Cooler sources are excluded from 

additional control under the MACT standard due to the large size of the particles and the 

relatively low concentration of particle emissions [FR, December 18, 2002, page 77570]. 

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Since the MACT standard was established recently and will become effective in 2006, the 

technology analysis is up-to-date. Again, for these units subject to a MACT standard, BART 

will be presumed to be equivalent to MACT according to U.S. EPA guidance. 

No further analysis will be required to establish BART for these sources. 

3.0 Process Boiler MACT Emission Units (PM-Only) 

Similarly to sources subject to the Taconite MACT, a taconite processing facility has many 

process boilers subject to the Boiler MACT. Since the MACT standard was established recently 

and will become effective in 2007, the technology analysis is up-to-date. Again, for these units 

subject to a MACT standard, BART will be presumed to be equivalent to MACT according to 

U.S. EPA guidance. 

No further analysis will be required to establish BART for these sources. 

4.0 Process Boiler Emission Units (NOx and SO2) 

It is important to note that the emissions from the indurating furnaces represent the vast majority 

of emissions of all visibility impairing pollutants, with the process boiler emission units typically 

contributing less than 1% of the total emissions of each pollutant from sources that are subject to 

BART. The emissions from all the remaining sources are small relative to the total emissions 

that are subject to the BART standard. Additional control of these sources can be presumed to 

have minimal impact on visibility improvement in Class I areas. Each facility will conduct an 

analysis for the remaining sources to demonstrate that the impact on visibility is negligible. The 

procedure for the analysis is detailed in section 5 of this document. Assuming that the modeling 

demonstrates that the sources have a negligible impact on visibility in Class I areas, no further 

analysis will be required to establish BART for these sources. 

5.0 Visibility Impact Modeling for Negligible Impacts 

As described in sections 3 and 4 of this document, each facility contains several process boilers 

that are assumed to have a negligible impact on visibility in Class I areas. In order to confirm 

this assumption, each facility will conduct a modeling analysis to determine the impact of the 

emissions from these sources on visibility in Class I areas. The analysis will consist of the 

following: 

A. Conduct air dispersion modeling for uncontrolled BART-eligible emission unit, as 

described in sections 3 and 4 above. The modeling will be conducted based on the 

guidance document Single Source Modeling to Support Regional Haze BART 

Modeling Protocol dated March 21, 2006 as prepared by Lake Michigan Air 

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Directors Consortium (LADCO). One modeling analysis will be conducted for each 

facility. 

B. Count the days with a 98th percentile (21 over 3-yrs, 7 each year) change in visibility 

greater than or equal to 0.05 deciviews (based on 10% of the facility threshold of 0.5 

deciviews) at the modeled receptors with in the boundaries of each Class I area 

assessed over the 3-year period 2002-2004. 

C. If the modeled emission sources result in a 98th percentile change in visibility less 

than or equal to 0.05 deciviews, the point sources will be considered to not cause or 

contribute to visibility impairment in Class I areas. Therefore, the existing operations 

will be considered BART. No further analysis will be required to establish BART for 

these sources. 

D. If the modeled emissions result in a 98th percentile change in visibility greater than or 

equal to 0.05 deciviews, a full BART analysis will be conducted on the emission 

sources. 

174
Appendix 9I 

 

 

 

 

 

 

 Tilden Mining Company BART Letter 
Y:\Mpls\22 MI\52\2252080 Tilden BART\WorkFiles\_MovedFromMpls_P\MDEQ BART Followup\Tilden Unit 1 BART Recommendations 2-2010.doc 

Barr Engineering Company 

450 South Wagner Road • Ann Arbor, MI 48103 

Phone: 734-922-4400 • Fax: 734-922-4401 • www.barr.com An EEO Employer

Minneapolis, MN • Hibbing, MN • Duluth, MN • Ann Arbor, MI • Jefferson City, MO ● Bismarck, ND 

Technical Memorandum

To: Asad Khan 

From: Teresa Kinder, Barr Engineering 

Subject: Tilden Unit 1 BART Recommendation 

Date: February 19, 2010 

Project: 22/52-0080

c: Brent Ketzenberger, Tom O’Brien, John Flegel, Dave Cartella – Cliffs Natural Resources, Inc. 

 George Pruchnofski, Barr Engineering 

Summary

Michigan Department of Natural Resources and Environment – Air Quality Division (MDNRE) is 

requesting Cliffs Natural Resources, Inc. (Cliffs) to propose oxides of nitrogen (NOx) and sulfur dioxide 

(SO2) limits for Tilden Unit 1 grate/kiln to satisfy Best Available Retrofit Technology (BART) 

requirements. 

As requested by MDNRE, Cliffs proposes the following as BART emission limits for Tilden Unit 1 

grate/kiln: 

• SO2 – 28,800 lb SO2 per calendar day, and 

• NOx – Similar to the Minnesota Regional Haze State Implementation Plan, the new NOx limits will 

be set after testing to determine appropriate limits based on “good combustion practices.” 

Background

The State of Michigan is required to submit to U.S. EPA a Regional Haze State Implementation Plan (SIP) 

to make “reasonable progress” to reduce visibility impairment to federal Class I areas. Part of the initial 

SIP is to include BART determinations to establish emission limits for sources constructed within the time 

window of 1962 to 1977. BART is only one of many programs that states may rely upon in making 

“reasonable progress” towards regional haze improvement goals. 

MDNRE determined that Tilden Unit 1 is considered BART-eligible. Once a unit is considered BARTeligible, Cliffs is then required to determine if the unit is subject to BART at pre-BART conditions. 

1
Technical Memorandum 

To: Asad Khan

From: Teresa Kinder

Subject: Tilden Unit 1 BART Recommendations 

Date: February 26, 2010 

Page: 2 

Per U.S. EPA guidance, the baseline (or pre-BART conditions), represents the average emission rate in 

units of pounds per hour (lbs/hr) and reflects the maximum 24-hour actual emissions for each visibility 

impairing pollutant emitted from the indurating furnace, which in this case are particulate matter (PM), 

nitrous of oxides (NOx) and sulfur dioxide (SO2). These emission rates are then modeled to evaluate the 

potential visibility impact to Class I areas. In order to evaluate the maximum rate for each pollutant as 

mandated by BART, it required the assumption of 100% natural gas usage for NOx emissions and 100% 

coal usage for SO2 emissions. The modeling results show SO2 emissions do not cause visibility impairment 

to the Class I areas. Therefore, the BART proposal will primarily focus on NOx emissions. 

Proposed BART

The visibility impairment pollutants from indurating furnaces are PM, NOx and SO2. BART allows 

application of other standards to regulate a pollutant, such as maximum achievable control technology 

(MACT). Since the Taconite MACT regulates PM as a surrogate to hazardous air pollutants and Tilden Unit 

1grate/kiln is subject to the Taconite MACT, BART applies the applicable PM limits in the Taconite 

MACT. The PM limit for magnetite is of 0.01 grains per dry standard cubic foot (gr/dscf) and 0.03 gr/dscf 

for hematite. Therefore, the Taconite PM emission limit is BART. 

MDNRE has requested Cliffs to propose an appropriate SO2 emission limit for the Tilden Unit 1 grate/kiln. 

As the modeling results from 100% coal usage scenario showed, the SO2 emissions are not causing or 

contributing to visibility impairment. Therefore, the current Tilden’s Title V permit limits for SO2 emissions 

of 28,800 lbs per calendar day are sufficient. Cliffs proposes to continue to limit the SO2 emissions for 

Tilden Unit 1 grate/kiln as established in the Tilden Title V permit. 

MDNRE has also requested Cliffs to propose an emission limit for NOx. Due to the lack of sufficient 

emissions data representing good combustion practices and the range of operating conditions that influence 

emissions, Cliffs is unable at this time to propose an emission limit that corresponds to BART for Tilden 

Unit 1 grate/kiln. Cliffs proposes to develop a NOx emission factor in pounds of NOx per million BTU of 

heat input by collecting sufficient emissions data through stack testing to determine appropriate limits based 

on “good combustion practices.” The establishment of the NOx emission factor through stack testing is 

similar to the requirements in the Minnesota Regional Haze State Implementation Plan for taconite 

facilities. The established NOx emission factor can then be incorporated into Tilden’s Title V renewable 

operating permit, pursuant to 40 CFR Part 51 Appendix Y. 

2
Appendix 9J 

Emission Limits – Excerpts from ROP 

for Tilden Mining Company 
EU-KILN1 

EMISSION UNIT CONDITIONS

PROCESS AND CONTROL EQUIPMENT

EU-KILN1 Unit 1 Grate Kiln Indurating Furnace receives pellets from the balling section, dries and 

preheats them on a traveling grate which discharges them into a rotary kiln for final induration. Unit 1 

main burners are rated at 590 million BTU per hour heat input. The Tilden facility produces hematite 

pellets and magnetite pellets. Unit 1 is fired with coal, coal/petroleum coke blend, natural gas, or used oil 

supplied from the 1.5 million gallon storage tank. 

Also, blending coke breeze into the green pellets to provide additional heat input for the induration 

process was authorized in 2002 under Permit to Install #70-02. The unit is controlled with electrostatic 

precipitators. 

{Permits to Install #511-87C, #70-02}

I. EMISSION LIMITS

Pollutant Limit Time Period/ 

Operating 

Scenario 

Equipment Monitoring/ 

 Testing Method

Underlying 

Applicable 

Requirements 

1. Arsenic 

 

1. Arsenic emissions, from firing 

used oil, shall not exceed 0.0058 

tons per rolling 12-calendar month 

period.1

Rolling 12-

calendar month 

period 

Unit 1 

Indurating 

Furnace

Appendix 7 R336.1224 

2. Cadmium 

 

2. Cadmium emissions, from firing

used oil, shall not exceed 0.0058 

tons per rolling 12-calendar month 

period.1

Rolling 12-

calendar month 

period 

Unit 1 

Indurating 

Furnace

Appendix 7 R336.1224 

3. Chromium 

(total) 

 

3. Chromium (total) emissions, 

from firing used oil, shall not 

exceed 0.0058 tons per rolling 12-

calendar month period.1

Rolling 12-

calendar month 

period 

Unit 1 

Indurating 

Furnace

Appendix 7 R336.1224 

4. Particulate 4. Particulate 

a. Particulate emissions shall not 

exceed 0.01 grains per dry 

standard cubic foot (gr/dscf) for 

existing grate kiln indurating 

furnaces processing magnetite. 

b. Particulate emissions shall not 

exceed 0.03 grains per dry 

standard cubic foot (gr/dscf) for 

existing grate kiln indurating 

furnaces processing hematite. 

Test Protocol Unit 1 

Indurating 

Furnace

40 CFR 63 Subparts 

RRRRR and A

40 CFR Part 63 

Subparts RRRRR 

and A 

(see TACONITE 

MACT 

REQUIREMENTS 

below)

1
Pollutant Limit Time Period/ 

Operating 

Scenario 

Equipment Monitoring/ 

 Testing Method

Underlying 

Applicable 

Requirements 

5. Lead 

 

5. Lead emissions, from firing 

used oil, shall not exceed 0.017 

tons per rolling 12-calendar month 

period.1

Rolling 12-

calendar month 

period 

Unit 1 

Indurating 

Furnace

Appendix 7 R336.1224 

6. Particulate 6. Particulate emissions shall not 

exceed 0.065 pounds per 1000 

pounds of exhaust gases, nor 200 

pounds per hour.2

Test Protocol Unit 1 

Indurating 

Furnace

GC 13, 14, 15 R336.1331 

7. Sulfur 

 Dioxide 

7. Sulfur dioxide emissions shall 

not exceed 28,800 pounds per 

calendar day.2

Calendar Day Unit 1 

Indurating 

Furnace 

VI. 1 

VI. 2 

R336.1402 

II. MATERIAL LIMITS

1. The halogen content of the used oil burned in Unit 1 Indurating Furnace shall not exceed 1000 parts 

per million, by weight.

1

 [R336.1224] 

2. The maximum feedrate of coke breeze shall not exceed 5 tons per hour.

1

 [R336.1224] 

III. PROCESS OR OPERATIONAL RESTRICTIONS 

1. The permittee shall not operate Unit 1 Indurating Furnace unless the electrostatic precipitators are 

operating properly.2

 [R336.1910] 

2. The oil burned in Unit 1 Indurating Furnace shall be supplied only from the 1.5 million gallon used oil 

tank. 

[R336.1201(3)] 

3. See TACONITE MACT REQUIREMENTS below. [40 CFR 63 Subparts RRRRR and A] 

IV. DESIGN OR EQUIPMENT PARAMETERS

NA 

2
EU-OREDRYER1 

EMISSION UNIT CONDITIONS

PROCESS AND CONTROL EQUIPMENT

EU-OREDRYER1 – Ore Concentrate Dryer #1 is rated at 400 tons per hour throughput and 70 million 

BTU per hour heat input. The Dryer is fired with natural gas and used oil supplied from the 1.5 million 

gallon storage tank. Dryer #1 is controlled with a cyclone precleaner and a wet scrubber. 

{Permit to Install #511-87C}

I. EMISSION LIMITS

Pollutant Limit Time Period/ 

Operating 

Scenario 

Equipment Monitoring/ 

 Testing Method

Underlying 

Applicable 

Requirements 

1. Arsenic 

 

1. Arsenic emissions, when firing 

used oil, shall not exceed 0.0009 

tons per rolling 12-calendar month 

period.1

Rolling 12-

calendar month 

period 

Ore Dryer #1 Appendix 7 R336.1224 

2. Cadmium 

 

2. Cadmium emissions, when 

firing used oil, shall not exceed 

0.0009 tons per rolling 12-

calendar month period.1

Rolling 12-

calendar month 

period 

Ore Dryer #1 Appendix 7 R336.1224 

3. Chromium 

(total) 

 

3. Chromium (total) emissions, 

when firing used oil, shall not 

exceed 0.0009 tons per rolling 12-

calendar month period.1

Rolling 12-

calendar month 

period 

Ore Dryer #1 Appendix 7 R336.1224 

4. Particulate 4. Particulate emissions shall not 

exceed 0.052 grains per dry 

standard cubic foot (gr/dscf) for 

existing Ore Dryers. 

Test Protocol Ore Dryer #1 40 CFR 63 Subparts 

RRRRR and A

40 CFR Part 63 

Subparts RRRRR 

and A 

(see TACONITE 

MACT 

REQUIREMENTS 

below)

5. Lead 

 

5. Lead emissions, when firing 

used oil, shall not exceed 0.00265 

tons per rolling 12-calendar month 

period.1

Rolling 12-

calendar month 

period 

Ore Dryer #1 Appendix 7 R336.1224 

6. Particulate 6. Particulate emissions shall not 

exceed 0.10 pounds per 1000 

pounds of exhaust gases, 

calculated on a dry gas basis.2

Test Protocol Ore Dryer #1 GC 13, 14, 15 R336.1331 

3
EU-BOILERS1-2 

EMISSION UNIT CONDITIONS

PROCESS AND CONTROL EQUIPMENT

EU-BOILERS1-2 - Boilers #1 and #2 are each rated at 225 million BTU per hour heat input capacity and 

are fired with natural gas and used oil supplied from the 1.5 million gallon storage tank. Boilers #1 and 

#2 exhaust from a common stack. 

{Permit to Install #511-87C}

I. EMISSION LIMITS

Pollutant Limit Time Period/ 

Operating 

Scenario 

Equipment Monitoring/ 

 Testing Method

Underlying 

Applicable 

Requirements 

1. Arsenic 

 

1. Arsenic emissions, when firing 

used oil, shall not exceed 0.12 

tons per rolling 12-calendar month 

period.2

Rolling 12-

calendar month 

period 

Boilers #1 

and #2 

Appendix 7 R336.1224 

2. Cadmium 

 

2. Cadmium emissions, when 

firing used oil, shall not exceed 

0.12 tons per rolling 12-calendar 

month period.2

Rolling 12-

calendar month 

period 

Boilers #1 

and #2 

Appendix 7 R336.1224 

3. Chromium 

(total) 

 

3. Chromium (total) emissions, 

when firing used oil, shall not 

exceed 0.12 tons per rolling 12-

calendar month period.2

Rolling 12-

calendar month 

period 

Boilers #1 

and #2 

Appendix 7 R336.1224 

4. Lead 5. Lead emissions, when firing 

used oil, shall not exceed 0.37 

tons per rolling 12-calendar month 

period.2

Rolling 12-

calendar month 

period 

Boilers #1 

and #2 

Appendix 7 R336.1224 

II. MATERIAL LIMITS

1. The used oil burned in Boilers #1 and #2 shall not exceed a sulfur content of 1.2%, calculated on the 

basis of 18,000 BTU per pound. [R336.1401] 

2. The halogen content of the used oil burned in Boilers #1 and #2 shall not exceed 1000 parts per 

million, by weight.

1

 [R336.1224] 

4
Appendix 9K 

 

New Page Paper Company BART 

Technical Analysis 
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BEST AVAILABLE 

RETROFIT 

TECHNOLOGY{BART) 

ANALYSIS 

CASE•BY~CASE "BART ANALYSIS 

ESCANABA PAPER COMPANY 

Prepared in accordance with: 

40 CFR Part 51, Subpart P and Appendix Y 

Submitted By: 

Escanaba Paper Company 

7100 County Road 426 

P.O. Box 1062 

Escanaba, Michigan 49829 

Delta County 

Prepared 

By: 

ALL4 

2393 Kimberton Road 

PO Box299 

Kimberton, PA 

19442-0299 

Submitted To: 

Michigan DEQ 

. Air Quality Division 

Constitution Hall, 3rd Floor North 

525 W. Allegan St. 

P.O. Box ·30260 

Lansing, Ml 48909 

SUBMnTED:JANUARY,2007 

VERSION 1.0 
r. -· ·-------·--·---- - . . 

I (. , _" _ .--j ,., 

! \\ ... I •.. TABLE OF CONTENTS 

! 

Section ....................................................................................................................... Page Number 

1. BART DETERMINATION ANALYSIS ..................................................................... 1-1 

1.1 EXECUTIVE SUMMARY ......................................................................................... 1-1 

1.2 BACKGROUND ......................................................................................................... 1-2 

1.3 CASE-BY-CASE BART ANALYSIS ........................................................................ 1-4 

1.4 DOCUMENT ORGANIZATION ...... ; ........................................................................ 1-7 

2. VISffiiLITY MODELING ANALYSIS ...................................................................... 2-1 

2.1 MODELING METHODOLOGY ................................................................................ 2-1 

2.2 · DECIVIEW THRESHOLD .......................................................................................... 2-3 

2.3 EXEMPTION MODELING ANALYSIS ................................................. , ................. 2-3 

2.4 BART CONTROL MODELING ANALYSIS .......................................................... :.2-4 

3. SUMMARY OFB.AR.T ANALYSIS RESULTS ......................................................... J-1 

·4. NO. 8 BOILER (EUSB13) ......................................................................................... ~ ... 4-1 

4.1 NO.8 BOILER DESCRIPTION ............................................................. · .................... 4-1 

4.2 NOx BART ANALYSIS ............................................................................................. 4-1 

4.2.1 Identification of All Available Retrofit Control Teclmologies (Step 1) .......... 4-2 

4.2.2 Discussion of Technical Feasibility (Step 2) ................................................... 4-2 

4.2.3 . Evaluate Control Effectiveness of Remaining Technically Feasible Control 

Technologies (Step 3) .......................................... : .................................................... · ....... 4-5 

4.2.4 Evaluate Impacts and Document Results (Step 4) ........................................... 4-6 

4.2.5 Evaluate Visibility Impacts (Step 5) ................................................................ 4-9 

4.2.6 Identify BART ............................................................................................... 4-10 

4.3 S02 BART ANALYSIS .............................................................................................. 4-10 

4.3.1 Identification of All Available Retrofit Control Technologies (Step 1) ........ 4-10 

4.3.2 Discussion of Technical Feasibility (Step 2) ................................................. 4-10 

4.3.3 Evaluate Control Effectiveness ofRemaining Technically Feasible Control 

Technologies (Step 3) .................................................................................................... 4-13 

4.3.4 Evaluate Impacts and Document Results (Step 4) ......................................... 4-14 

4.3.5 Evaluate Visibility Impacts (Step 5) .............................................................. 4-16 

4.3.6 Identify BART ............................................................................................... 4-17 

4.4 PMwBART ANALYSIS~ .......................................................................................... 4-18 

4.4.1 Identification ofMACT Applicability and Identification ofBART .............. 4-18 

5. NO. 9 BOILER (EU9B03) ............................................................................................. 5-1 

5.1 NO.9 BOILER DESCRIPTION ................................................................................. 5-1 

5.2 NOx BART ANALYSIS ............................................................................................. 5-2. 

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Final EPC 1 26 07.doc 112612007 

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__,---------........ ....... , ............... ..,..,.,.. ........ 

/ __,, ,, '•1J'ie NP '-, ' 

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Scale In Kilometers 

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Figure 2-1 

Location of Class I Areas 

Within 300 km of the EPC Mill 
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3. SUMMARY OF BART ANALYSIS RESULTS 

Escanaba Paper Company 

Case-by-Case BART analysis 

The results of the BART analysis are provided in full detail in subsequent sections of this 

document. EPC has included this section as a brief summary to discuss the results ofthe BART 

analysis. 

Summaries ofthe BART results for each of the facility's BART eligible sources (No.8 Boiler, 

No. 9 Boiler, Recovery Furnace, Smelt Dissolving Tank, and Lime Kiln) are provided in Tables 

3-1, 3-2, 3-3,3-4, and 3-5 respectively. The tables include the following information: 

• YIPs identified for each source; 

• Identification of control technologies for each sourceNIP scenario; 

• Control effectiveness of each technically feasible control technology; 

• Calculated Cost Effectiveness; 

• Energy and non-air quality envirorunental impacts; 

• Visibility impacts of control technology; and 

• Identificatiqn of BART control. 

• The tables identify "N/A" in places where the previous step in the BART analysis 

indicated that the evaluation of the next BART evaluation step was not warranted. 

For example, if a control technology evaluation was determined to be unnecessary 

due to existing Maximum Available Control Technology (MACT), then the 

subsequent BART evaluation steps were determined to be "N/A". Additionally, if a 

potential control technology was considered not to be cost effective, then energy and 

visibility impacts were determined to be "N/ A" as well. 

As indicated in Section 2, only the Seney Wilderness Area is predicted to have any visibility 

impacts due to the BART-eligible sources at the Mill. A summary comparison of the visibility 

~pacts on the Seney Wilderness Area considering the pre-control and post-control scenarios is 

provided in Table 3-6. EPC used the 98th Percentile deciview values for the pre-control and 

Anal EPC 1 26 07 .doc 

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Escanaba Paper Company 

Case-by-Case BART analysis 

( -,., \. 1 4.2.2.3 Selective Non-Catalytic Reduction (SNCR) 

The SNCR process involves the injection of a nitrogen-containing chemical, typically either 

ammonia or urea into a turbulent region of the boiler where the gas temperature is in the range of 

approximately 1600° to 2100°F with a corresponding residence time of at least 1 second. In this 

temperature range or "window," the injected chemical reacts selectively with NOx in the 

presence of oxygen to form molecular nitrogen, carbon dioxide and water without a catalytic 

converter. 

The primary SNCR process by-products are NH3, C02, and N20 emissions. N20 and C02 are 

both greenhouse gases. IfN20 and C~ emissions need to be abated, this will affect the choice 

of SNCR chemical, but not necessarily the NOx reduction performance of the SNCR system. 

However, with either SNCR chemical, by-product NH3 (i.e., ammonia slip) can lead to adverse 

impacts downstream of the SNCR system, including air heater fouling, and plume formation. 

When assessing SNCR feasibility, these impacts must be considered, along with any regulatory 

requirements to limit NH3 emissions. 

EPC spoke with one vendor that indicated SNCR can be applied to an oil/gas-fired boiler that 

swings load. On a swing boiler, like the No. 8 Boiler, the application of SNCR will depend on 

how fast the boiler swings and how fast the temperature zone moves. Conventional SNCR 

dictates that urea be applied at varying boiler loads in three different zones. Newer SNCR 

technology can be designed with nozzles that tilt up and down to inject the urea. 

NOx reductions range from 20 to 50% at full load,. depending on a variety of interdependent, 

unit-specific boiler and process parameters. These include: 

• Physical locations of the temperature window, which moves as a function of boiler 

operating variables; 

• Residence time of injected chemical in the temperature window; 

• Initial NOx level; 

• SNCR chemical type; 

• Injection-system de$ign; and 

4-4 

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• SNCR- 0.1 deciview 

• FGR- 0.1 deciview 

4.2.6 Identify BART 

Escanaba Paper Company 

Case-by-Case BART analysis 

Based on the information developed in the hnpacts Analysis, BART for NOx from the No. 8 

Boiler is identified as use of the existing FGR system during the ozone. control season only. 

4.3 S02 BART ANALYSIS 

Sulfur dioxide (S02) emissions from the No. 8 Boiler are largely the result of the combustion of 

No. 6 fuel oil due to the oxidation of sulfur in the fuel to S02• Natural gas combustion 

contributes negligible quantities of so2. 

4.3.1 Identification of All Available Retrofit Control Technologies (Step 1) 

Based on the data review process· described previously, a list of potential technologies for 

controlling S02 emissions from No. 8 Boiler was formulated. EPC identified . the following 

potential control technologies: 

• Low Sulfur Fuels; 

• Wet Scrubbing; 

• Dry Scrubbing; and 

• Semi-Dry Scrubbing. 

4.3.2 Discussion of Technical Feasibility (Step 2) 

The next step in the top-down BART analysis is an evaluation of the technical feasibility of each 

of the identified control options. Each of the potential control teclmologies considered is 

described below along with a discussion of the teclmical feasibility with respect to the No. 8 

Boiler. 

4.3.2.1 Low Sulfur Fuels 

In addition to natural gas, the No. 8 Boiler is p'ermitted to burn No. 6 fuel oil with a sulfur 

) content of 1.0%. Baseline S02 emissions are approximately 115 tpy, which are driven by the 

4-10 

Final EPC 1 26 07.doc 1/W2007 

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·---................ ·-·--· .... -· ~·- ---·--- ... ---- · ·-·-- ·-· .. ·-----··- -·~··- · ... -- --

Escanaba Paper Company 

Case-by-Case BART analysis 

teclmology on fuel oil and natural gas fired boilers such as the No. 8 Boiler were identified in our 

research of potential control technologies; therefore. EPC does not consider this to be technically 

feasible. In order to be conservative, EPC considers this technology to potentially be 

transferable to the No. 8 Boiler and evaluated it anyway. 

4.3.2.4 Semi-dry Scrubbing 

The conceptual design of a semi-dry scrubbing system is based on atomizing a reagent slurry 

stream containing lime and contacting the flue gases in a spray dryer vessel. The dry material 

consisting of un-reacted lime, reaction products, and fly ash must be collected downstream by an 

ESP or a fabric filter. 

In · conventional applications, the flue gas would be directed to a Semi-Dry Absorber (SDA) 

which is a vertical-downflow chamber designed to provide optimal gas and liquid spray 

interactions and retention time for evaporative cooling an~ lime slurry spray-dry absorption of 

acid gases. All of the sprayed liquid would evaporate as it travels in the tower, leaving only dry 

) reagent products at the discharge. The partially reacted lime powder and ash would then be 

transported from the SDA vessel into the flue gas to ESP or fabric filter for final treatment. The 

reagent used would be calcium hydroxide, which is hydrated lime. 

A vendor for this control option was able to guarantee no more than 25% potential control 

efficiency due to the low inlet concentration. No applications of this technology on fuel oil and 

natural gas fired boilers such as the No. 8 Boiler were identified in our research of potential 

control technologies; therefore, EPC does not consider this teclmology to be technically feasible. 

In order to be conservative, EPC considers this technology to potentially be transferable to the 

No. 8 Boiler and evaluated it anyway. 

4.3.3 Evaluate Control Effectiveness of Remaining Technically Feasible Control 

Technologies (Step 3) 

Based on the reasons outlined in the above discussion, EPC has identified the following control 

technologies as teclmically feasible, ranked in order of most effective to least effective: 

) • Lower Sulfur Fuels - 99% control switching to natural gas only; 

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(j 8.4 PM10 BART ANALYSIS 

Escanaba Paper Company 

Case-by-Case BART analysis 

Particulate emissions from the Lime Kiln consists primarily of dust entrained from the 

combustion section of the kiln. This dust consists of sodium salts, calcium carbonate and 

calcium oxide. The sodium salt emissions result primarily from sodium compounds that are 

retained in the lime mud due to inefficient washing, while the calcium particulates result 

principally from entrainment. Thus, the particulate emissions are affected by the efficiency of 

the mud washing system and the gas velocity and turbulence in the kiln (EPA 1976a). 

The typical first step in the BART analysis is the identification of all available retrofit control 

options. However, 40 CFR Part 51, Appendix Y (IV, C) identifies an exception to the BART 

analysis for VOC and PM sources subject to Maximum Achievable Control Technology 

(MACT) standards under Section 112 of the Clean Air Act. Specifically, Appendix Y states that: 

"We believe that, in many cases, it will be unlikely that States will identify emission 

controls more stringent than the MACT standards without identifying control options that 

would cost many thousands of dollars per ton. Unless there are new technologies 

subsequent to the MA CT standards which would lead to cost-effective increases in the 

) level of control, you may rely on the MACT standards for the purposes of BART" 

The Lime Kiln is subject to 40 CFR Part 63, Subpart MM - "MACT II" with a compliance date 

of March 13, 2004. The Lime Kiln is in compliance with the PM standard that was established 

under MACT IT. EPC has reviewed the RBLC database and believes that there are two control 

technologies that represent the most stringent PM control: (1) ESP and (2) venturi scrubber. 

Both ESPs and venturi scrubbers have been used to control particulate emissions .from lime kilns. 

While both are capable of a high degree of particulate removal, the .issue of which device 

represents the best system of emission reduction is clouded due to the presence of so2 in the 

lime kiln flue gas due to the incineration of NCGs. The incineration of NCGs in the Lime Kiln 

places a greater S02 load on the kiln. Unlike an ESP, the venturi scrubber reduces emissions of 

S02 as well as particulate as described in the S02 BART analysis section above. 

EPC has concluded that the existing venturi scrubber represents BART for PM control based on 

the following key issues: 

8-9 

Final EPC 1 26 07 .doc 1126/2007 

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) 

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

RESEARCH TRIANGLE PARK, NC 27711 

JUL 1 9 2006 

OFFICE OF 

AIR QUALITY ?LANNING 

AND STANDARDS 

MEMORANDUM 

SUBJECT: 

FROM: 

TO: 

Regional Haze Regulations and Guidelines for Best Available Retrofit 

Technology (BART) Determinations 

~~ · Joseph w. Paisie, Group Lead~ . J

1 -[~ ' 

Geographic Strategies Group (hlc~&r-2) ~ 

Kay Prince, Branch Chief 

EPA, Region 4 

In July 2005, EPA issued BART Guidelines thai provide guidance to the States in making BART 

determinations for large power plants and other BART sources. In the BART Guidelines, we 

described several approaches that States could use to detennine whether a source should be 

subject to review for BART, or whether it should be exempt from the BART requirements. As 

you know, BART applies to existing sources of a certain type, age, and size that 11emit any air 

pollutant which may reasonably be anticipated to cause or contribute to any impainnent of 

visibility in any [Class I] area." CAA §169A(b)(2)(A). One approach discussed in the 

Guidelines for determining that a source does not meet the threshold test for BART is to use the 

air quality model CALPUFF. 

We understand that many States and Regional Planning Organizations (RPOs) are currently 

considering the use ofCALPUFF for making BART determinations. We have received a 

question asking whether States can, or should, allow sources to use CALPUFF to estimate 

visibility impacts on a pollutaJ.1t specific basis, or whether EPA intended CALPUFF to be used to 

model a source's visibility impacts based on its total emissions of visibility-impairing pollutants. 

We have also received a question regarding the process for estimating natural background 

conditions, one of the factors used to estimate a source's impact on visibility. This memo 

addresses these two questions. 

Pollutant-Specific CALPUFF Analvses 

Because of the complexity and nonlinear nature of atmospheric chemistry and chemical 

transformation among pollutants, EPA does not generally recommend that CALPUFF be used on 

a pollutant specific basis to determine whether a source meets the threshold test for BART. In 

lntemet Address (URL) .g~ttp:J/www.ep gov 

Rocyclod/Recyclablo • Ptlnreo wkh Vegolabto Oil BtiSild lnl<s on Recycled Paper (MinJmum 25% Poslconsumer) 
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Appendix 9L 

 

New Page- Paper Company BART Letter 
1

=:J NewPageFebruary 2,2010

RECEIVED

FEB I) 5 2010

AIR QUALITY Of\/.

Delivering on the Promise of Paper'~

Mr. Bob Irvine

Michigan Department ofNatural Resources and Environment

525 West Allegan Street

P.O. Box 30260

Lansing, Michigan 48909-0260

Re: Escanaba Paper Company (EPe) Best Available Retrofit Technology

(BART) Response

Dear Mr. Irvine:

NewPage Corporation Escanaba Paper Company (EPe) has prepared the following

response to address outstanding issues related to the Best Available Retrofit Technology

(BART) analyses. EPC has prepared this response to reaffirm the conclusions of the

original BART analysis and to reiterate that EPC believes that the original BART

analysis is consistent with the intent ofthe BART guidance contained in 40 CFR Part 51

Appendix Y as well as the current U.S. EPA interpretation ofBART requirements.

Background

There are five (5) emission units at the EPC mill that have start-up dates between August

7, 1962 and August 7, 1977. EPC conducted a visibility modeling analysis using 24-hour

worst-case actual emissions for each VIP for the BART-eligible source (i.e., each ofthe

five emission units) at the mill. The results ofthe baseline visibility modeling indicated

the BART-eligible source could contribute to visibility impairment under worst-case

meteorological conditions and when all of the BART-eligible sources at the mill were

emitting at their maximum 24-hour actual emission rates. Therefore the emission units

(i.e. the BART-eligible source) are subject to BART. EPC then conducted a case-by-case

five-step. BART analysis for each emission unit comprising the BART-eligible source.

The conclusions of the five-step BART analysis were provided to Michigan DEQ in a

January 2007 report. Supplemental information has been submitted to Michigan DEQ to

clarifY and expand on the original BART report. The most recent information related

directly to the BART report was submitted to Michigan DEQ in May 2008 and reflected

the use of the 20% best days background data and the use of U.S. EPA's refined

Interagency Monitoring ofProtected Visual Environments (IMPROVE) equation.

EPC's BART Analysis

The BART report that EPe prepared and submitted to Michigan DEQ in January 2007

outlined the potential control options for each of the five (5) emission units at the EPe

mill. Using vendor quotes for control equipment and U.S. EPA's 2003 Air Pollution

Control Cost Manual, EPe provided costs for installing and operating the control options

where it was technically feasible to install control equipment. The control costs for all

emission units were generally greater than $10,000 per ton ofVIP removed except for the

No. 8 Power Boiler where select control costs for sulfur dioxide (SOz) and oxides of

NewPage Corporation, Coated Paper

7100 County 426 M.5 Road, P. O. Box 7$7, Escanaba MI 49829·0757 T 9067861660
2

Mr. Bob Irvine

Escanaba Paper Company (EPC) BART Analysis

20f2

nitrogen (NOx) were approximately $4,000 per ton of VIP removed. EPC believes that

the S02 and NOx control costs for the No.8 Power Boiler are at the high range of cost

~ffectiveness. However, the consideration of a control cost by itself is an incomplete

review under the Five Step case-by-case BART analysis. The five step evaluation of

visibility impacts must be included in the case-by-case BART analysis.

The visibility modeling performed by EPC included pre-control and post control

visibility impacts for each of the five emission units where control options were

technically feasible. The visibility modeling demonstrated that the application of a

control technology did not result in a meaningful improvement in visibility. For

example, the addition oflow NOx burners on the No.8 Power Boiler would result in 0.12

deciview change in the 98th percentile visibility value. It is important to note that the

procedures identified in 40 CFR Part 51 Appendix Y state the evaluation of visibility

modeling is just a portion ofthe overall BART process and that even ifmodeled visibility

impacts above 0.5 deciviews are predicted, the visibility impacts can be judged on a

relative basis not an absolute basis. This meanS that 98th percentile results above 0.5

deciview can be judged to be acceptable.

Considering all ofthe factors in the five step case-by-case BART analysis, EPC believes

there is no best available retrofit technology that would apply to any of the five (5)

emission units at the mill. Therefore, since there is no BART, there are no control

requirements and no enforceable emission limits that need to be established. As

described in 40 CFR Part 51 Appendix Y enforceable emission limits are necessary when

there are BART requirements (i.e., emission controls).

If Michigan DNRE has questions concerning this letter or the information that was

presented in the January 2007 BART report, please do not hesitate to contact me at 906-

233-2929.

Sincerely

9-~ Todd Schmidt

Environmental Manager

File: 8.19.2 21212010
Appendix 9M

Emission Limits – Excerpts from ROP 

for New Page Paper Company
EU #8 Boiler System

EMISSION UNIT CONDITIONS

DESCRIPTION: The #8 Boiler (EG8B13) is a Combustion Engineering boiler rated for 450,000 pounds 

of steam per hour (approximately 594 million BTU per hour heat input) that provides steam for mill 

processes and steam turbine-generator sets for producing electricity. A Flu Gas Recirculation system was 

installed on the # 8 Boiler. The #8 Boiler burns natural gas and fuel oil 

POLLUTION CONTROL EQUIPMENT NA 

I. EMISSION LIMIT(S)

Pollutant Limit Underlying 

Applicable 

Requirements 

1. NOx The Permittee shall comply with the appropriate NOx emission limitations 

averaged over the ozone control season. 

 a. The emission limitation when firing gas is 0.20 lbs/MMBtu. 

 b. The emission limitation when firing residual oil is 0.40 lbs/MMBtu. 

 

The ozone control period is May 1 through September 30. 

 (R336.1801)1

 (R336.1801(13)1

 (R336.1801(13)1

 (R336.1801(1)(f))1

II. MATERIAL LIMIT(S)

Material Limit Underlying 

Applicable 

Requirements 

1. Fuel Oil The fuel oil burned in #8 Boiler shall not exceed a maximum sulfur content of 

1.0 percent by weight, calculated on the basis of 18,000 BTU per pound. 

(R336.1201, 

R336.1401) 

III. PROCESS/OPERATIONAL RESTRICTION(S) : NA

IV. DESIGN/EQUIPMENT PARAMETER(S): NA

V. TESTING/SAMPLING 

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. The permittee shall measure NOx emissions using a NOX CEMS during the ozone control period in 

 accordance with the provisions of R336.1801(11). (R336.1801(8))1

VI. MONITORING/RECORDKEEPING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

1. The permittee shall obtain and keep records of the sulfur and BTU content of the fuel oil burned 

in #8 Boiler. For each shipment received, the permittee shall obtain from the supplier a laboratory 

analysis of the fuel oil sulfur and BTU content. The permittee shall also record the date received, 

fuel oil grade, source of fuel oil and 

1
EU #9 Boiler System

EMISSION UNIT CONDITIONS

DESCRIPTION: The # 9 Boiler (EU9B03) is a Babcock & Wilcox boiler rated for 250,000 pounds of 

steam per hour (approximately 360 million BTU per hour heat input) that provides steam for mill 

processes and steam turbine-generators for producing electricity. The # 9 boiler burns primarily wood 

residue, but may also burn natural gas, and paper cores. The boiler system has two emission units, the 

#9 Boiler and Wood Residue Surge Bin. 

POLLUTION CONTROL EQUIPMENT: Multiclone and two wet scrubbers on the # 9 boiler exhaust; 

Cyclone dust collector on Wood Residue Surge Bin. 

Flexible Grouping ID: FGRMPMOD 

I. EMISSION LIMIT(S)

Pollutant Limit Underlying 

Applicable 

Requirements

1. NOx The permittee shall comply with applicable oxides of nitrogen emission limits for 

the # 9 boiler, as specified in Table 81 of Rule 801, during years when the boiler 

meets the definition of a fossil fuel fired emission unit per the definition in 

R336.1801(1)(b).

 (R336.1801)1

2. Particulate If the wood residue heat input to # 9 boiler is greater than 75 percent of the 

total heat input to the boiler, the particulate emission from# 9 boiler shall not 

exceed 0.50 pounds per 1000 pounds of exhaust gases, measured at operating 

conditions, corrected to 50 percent excess air. 

(R336.1201, 

R336.1331) 

3. Particulate If the wood residue heat input to the # 9 boiler is less than or equal to 75 

percent of the total heat input to the boiler, the particulate emission from # 9 

boiler shall not exceed the fraction of total heat input from the wood residue 

times 0.67 pounds per 1000 pounds of exhaust gases, measured at operating 

conditions, corrected to 50 percent excess air. 

(R336.1201, 

R336.1331) 

4. Particulate The particulate emission from the cyclone dust collector serving the wood 

residue surge bin shall not exceed 0.10 pounds per 1000 pounds of exhaust 

gases, measured at operating conditions. 

(R336.1331) 

II. MATERIAL LIMIT(S): NA 

III. PROCESS/OPERATIONAL RESTRICTION(S)

1. The permittee shall not operate EU9B03 while burning wood residue and/or paper cores unless the 

multiclone dust collector and two wet scrubbers are operating properly. (R336.1201, R336.1910) 

2. The permittee shall immediately cease wood residue input feed to EU9B03, consistent with safe 

operating procedures, upon initiation of scrubber bypass. During a scrubber bypass, the permittee shall 

burn only natural gas in EU9B03. Wood residue fuel input shall not be restarted until the scrubber is 

back on line and functioning properly. (R336.1201, R336.1331, R336.1910) 

2
EU Chemical Recovery Furnace System

EMISSION UNIT CONDITIONS

DESCRIPTION: The Chemical Recovery Furnace System is used to regenerate chemicals used in 

the kraft process. The #10 Recovery Furnace is rated for 565,000 pounds of steam per hour 

(approximately 950 million BTU per hour heat input), and burns black liquor, natural gas, #6 fuel oil, and 

used oil. Also, the #10 Recovery Furnace receives and incinerates HVLC noncondensible gases from 

the Digester System, Brownstock System, Evaporator System, and Chemical Recovery Furnace System. 

The Chemical Recovery Furnace System has one emitting units: #10 Recovery Furnace (EURF15). 

POLLUTION CONTROL EQUIPMENT: Electrostatic precipitator on #10 Recovery Furnace. 

I. EMISSION LIMIT(S)

Pollutant Limit Monitoring/ 

Testing 

Method 

Underlying 

Applicable 

Requirements

1. Arsenic The arsenic emission from EURF15 while burning used oil 

and/or # 6 fuel oil shall not exceed 0.004 milligrams per cubic 

meter, corrected to 70 degrees Fahrenheit and 29.92 inches 

Hg. 

(R336.1901)1

2. Cadmium The cadmium emission from EURF15 while burning used oil 

and/or #6 fuel oil shall not exceed 0.038 milligrams per cubic 

meter, corrected to 70 degrees Fahrenheit and 29.92 inches 

Hg. 

(R336.1901)1

3. Carbon Monoxide The carbon monoxide emission from EURF15 shall not exceed 

2000 parts per million by volume nor 1424 pounds per hour, 

based upon a one-hour average. 

(R336.1201, 40 

CFR 52.21)

4. Carbon Monoxide The carbon monoxide emission from EURF15 shall not exceed 

800 parts per million by volume nor 570 pounds per hour, 

based upon an eight-hour average. 

(R336.1201, 40 

CFR 52.21) 

5.Chromium The chromium emission from EURF15 while burning used oil 

and/or #6 fuel oil shall not exceed 0.016 milligrams per cubic 

meter, corrected to 70 degrees Fahrenheit and 29.92 inches 

Hg. 

(R336.1901)1

3
Pollutant Limit Monitoring/ 

Testing 

Method 

Underlying 

Applicable 

Requirements

6. HAP Metals 

measured as 

Particulate Matter 

(PM) 

The permittee shall comply with the emission limits specified in 

one of the following options as provided in 40 CFR 63 Subpart 

MM: 

 a. The Particulate Matter (PM) concentration in the # 10 

 Recovery Furnace exhaust gases shall not exceed 

 0.044 grain per dry standard cubic foot corrected to 8 

 percent oxygen; 

 OR 

 b. Alternative Particulate Matter (PM) emission limits 

 established for each existing recovery furnace, smelt 

 dissolving tank, and lime kiln that operates 6,300 hours 

 per year or more as provided under 40 CFR 

 63.862(a)(1)(ii), subject to the limitations specified. 

 

(40 CFR 63.861)

(40 CFR 63.862 

(a)(1)(i)(A), 40 

CFR 63.865(b)) 

(40 CFR 63.862 

(a)(1)(ii), 40 

CFR 63.865(a), 

40 CFR 63.865 

(b)) 

7. Nitrogen Oxides The nitrogen oxides emission from EURF15 shall not exceed 

400 parts per million by volume, nor 468 pounds per hour. 

(R336.1201, 40 

CFR 52.21) 

8. Particulate The particulate emission from EURF15 shall not exceed 

0.033grains per dry standard cubic foot corrected to 8 percent 

oxygen, nor 60.5 pounds per hour. The permittee may 

petition the Department for an alternate particulate limit up to, 

but not exceeding, 0.044 grains per dry standard cubic foot of 

exhaust gases corrected to 8 percent oxygen. Such alternate 

particulate emission limit shall not be established by the 

Department unless the Department is reasonably convinced of 

all the following: 

 a. All reasonable measures to reduce particulate 

 emissions have been implemented or will be 

 implemented in accordance with a schedule 

 approved by the Department. 

 b. Compliance with the original particulate emission limit 

 is either technically or economically unreasonable. 

 c. The requested alternate particulate limit is the limit that 

 reflects the level of emission that can be reasonably 

 achieved on a consistent basis. 

(R336.1201, 

R336.1331, 40 

CFR 52.21)

9. Polychlorinated 

Biphenyls 

The polychlorinated biphenyls emission from EURF15 while 

burning used oil and/or #6 fuel oil shall not exceed 0.014 

milligrams per cubic meter, corrected to 70 degrees Fahrenheit

and 29.92 inches Hg. 

(R336.1901)1

10. Sulfur Dioxide The sulfur dioxide emission from EURF15 shall not exceed 

250 parts per million by volume, nor 407 pounds per hour. 

R336.1201, 40 

CFR 52.21) 

11. Total Reduced 

Sulfur 

The total reduced sulfur emission from EURF15 shall not 

exceed 5 parts per million based upon a 12-hour average, 

corrected to 8 percent oxygen, nor 5.6 pounds per hour. 

(R336.1201, 40 

CFR 52.21, 40 

CFR 60.283) 

4
EU Smelt Dissolving Tank System

EMISSION UNIT CONDITIONS

DESCRIPTION: The Smelt Dissolving Tank System is used to regenerate chemicals used in the 

kraft process. The Smelt Dissolving Tank receives smelt from the # 10 Recovery Furnace, 

which it mixes with weak wash to generate green liquor that is transported to the Recausticizing 

System. The Smelt Dissolving Tank System has one emitting unit: The Smelt Dissolving Tank 

(EUST15). 

POLLUTION CONTROL EQUIPMENT: Wet scrubber and mist eliminator on Smelt Dissolving 

Tank. 

I. EMISSION LIMIT(S)

Pollutant Limit Monitoring/ 

Testing 

Method 

Underlying 

Applicable 

Requirements 

1.Particulate a. The Particulate Matter (PM) concentration in the Smelt 

 Dissolving Tank exhaust gases shall not exceed 0.20 

 pounds per ton of black liquor solids fired. 

b. Alternate Particulate Matter (PM) emission limits may be 

 established for each existing smelt dissolving tank 

 that operates 6,300 hours per year or more as provided 

 under 40 CFR 63.862(a)(1)(ii), subject to limitations 

 specified. 

c. The Particulate emission from the Smelt Dissolving Tank 

 shall not exceed 0.15 lbs/1000 lbs of exhaust gases, 

 calculated on a dry gas basis. 

a. (40 CFR 

63.862(a)(i)(B), 40 

CFR 63.865(b)) 

b. (40 CFR 

63.862(a)(1)(ii), 40 

CFR 63.865(a), 40 

CFR 63.865(b) 

c. (R336.1201, 

R336.1331, 40 CFR 

52.21)

2. Total Reduced 

Sulfur (TRS) 

The total reduced sulfur emission from the Smelt Dissolving 

Tank shall not exceed 0.0084 grams per kilogram of black 

liquor solids based upon a 12 hour average. 

(R336.1201, 40 

CFR 52.21) 

II. MATERIAL LIMIT(S): NA

III. PROCESS/OPERATIONAL RESTRICTION(S): NA

IV. DESIGN/EQUIPMENT PARAMETER(S): NA

V. TESTING/SAMPLING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. The permittee shall test for particulate and total reduced sulfur emissions from the Smelt Dissolving 

Tank once every three years from the date of issuance of this permit. Test results shall be submitted in an 

acceptable manner with in 60 days of completion of the test. (R336.1201, R336.1213(3))

5
2. Performance tests shall be conducted according to procedures and test methods specified or 

approved by the Air Quality Division. Not less than 30 days prior to testing, a test plan shall be submitted 

to the AQD for review and approval. (R336.2001, R336.2003) 

See Appendix 5 

6
EU Lime Kiln System

EMISSION UNIT CONDITIONS

DESCRIPTION: The Lime Kiln System (EULK29) includes the Lime Kiln and two Lime Storage Bins, 

one for hot lime storage, one for purchased lime storage. The Lime Kiln is fired with natural gas and/or 

fuel oil. Also, the Lime Kiln is a backup incineration device for the Thermal Oxidizer System

POLLUTION CONTROL EQUIPMENT: Venturi scrubber and mist eliminator on EULK29. A 

common baghouse dust collector serves the two Lime Storage Bins. 

I. EMISSION LIMIT(S)

Pollutant Limit Monitoring/ 

Testing 

Method 

Underlying 

Applicable 

Requirements 

1. HAP Metals 

measured as 

Particulate Matter (PM)

Pursuant to 40 CFR 63 Subpart MM, the permittee shall 

comply with the emission limits specified in one of the 

following options: 

 a. The Particulate Matter (PM) concentration for 

 EULK29 exhaust gases shall not exceed (0.064 

 grains per dry standard cubic foot) corrected to 10 

 percent oxygen based on a 3 hour averaging time at 

 all times except during a SSM and as specified in 40 

 CFR 63.443(e), 40 CFR 36.446(g) and 40 CFR 

 63.864(k)(2). 

 or 

 b. Alternative Particulate Matter (PM) emission limits 

 established for each existing recovery furnace, 

 EUST15, and EULK29 that operates 6,300 hours per 

 year or more as provided under 40 CFR 

 63.862(a)(1)(ii), subject to the limitations specified. 

 

 (40 CFR 63.861) 

(40 CFR 63.6(f), 

63.862(a)(1)(i)(c))

(40 CFR 

63.862(a)(1)(ii), 

40 CFR 63.865(a), 

40 CFR 63.865(b))

2. Particulate The particulate emission from EULK29 shall not exceed 

0.20 pounds per 1000 pounds of exhaust gases measured 

at operating conditions. 

(R336.1201, 

R336.1331) 

3. Particulate The particulate emission from the two Lime Storage Bins 

shall not exceed 0.10 pounds per 1000 pounds of exhaust 

gas, measured at operating conditions. 

(R336.1331)

4. Sulfur Dioxide The sulfur dioxide emission from EULK29 shall not exceed 

9 pounds per hour. 

(R336.1201)

5. Total Reduced 

Sulfur 

The TRS concentration from EULK29 exhaust gases shall 

not exceed 20 parts per million by volume, based on a 

twelve hour average, corrected to 10 percent oxygen. 

(R336.1201)

7
Appendix 9N 

 

Smurfit-Stone Container Company BART 

Technical Analysis 
Table of Contents 

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Sebesta Blomberg Project No. 556500.20 March 31, 2007 

Section Page 

1.0 Introduction to The Regional Haze Rule........................................................................ 2

2.0 Existing Equipment .......................................................................................................... 4

2.1 Riley Boiler .................................................................................................................................4

2.2 Electrostatic Precipitator..............................................................................................................4

2.3 Low NOx Burners .......................................................................................................................4

2.4 Flame Stabilization Rings............................................................................................................5

2.5 Boiler MACT Compliance ..........................................................................................................5

3.0 BART Applicability Determination ................................................................................ 7

3.1 BART ‘Eligible’ Sources.............................................................................................................7

3.2 Determine ‘Reasonable Cause or Contribution to Visibility Impairment’..................................8

3.3 State/RPO BART Applicability Determinations.........................................................................9

3.4 Updating the Baseline..................................................................................................................9

3.5 Impacting Isle Royale? ..............................................................................................................10

4.0 Summary.......................................................................................................................... 12

Appendices 

Appendix A: CALPUFF Protocol 

Appendix B: 2005-2006 Baseline Case Model Output Files 
Section 1 

Introduction to the Regional Haze Rule 

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Sebesta Blomberg Project No. 556500.20 March 31, 2007 

1.0 Introduction to The Regional Haze Rule 

On July 1, 1999, the Environmental Protection Agency (EPA) finalized a rules package known as the 

“Regional Haze Regulations. The purpose of the regulation is to limit visibility-impairing emissions of 

particulate matter, sulfur and nitrogen compounds that impact federal Class I areas. These Class I areas 

include national parks, wilderness areas, and select areas of the country for which scenic views are 

considered an important attribute. As required by Section 169B of the Clean Air Act, the Regional Haze 

Regulations include Best Available Retrofit Technology (BART) provisions for certain sources that may 

reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I area. More 

specifically, BART applied to sources within 26 specific source categories that were constructed between 

1962 and 1977 and that have the potential to emit 250 tons per year of visibility impairing pollutants. The 

rule requires states to submit implementation plans for visibility improvement to EPA no later than 

December 31, 2007. The state must revise the implementation plan and submit the revision by July 31, 

2018 and every ten years thereafter. 

On July 6, 2005, EPA issued another final rule, titled “Regional Haze Regulations and Guidelines for 

Best Available Retrofit Technology.” This rule lays out the procedural requirements for determination of 

Best Available Retrofit Technology (BART) for control of visibility-impairing pollutants for sources that 

may reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I area. The 

EPA defines BART as follows: 

“Best Available Retrofit Technology (BART) means an emission limitation based on the 

degree of reduction achievable through the application of the best system of continuous 

emission reduction for each pollutant which is emitted by a BART-eligible source. The 

emission limitation must be established, on a case-by-case basis, taking into 

consideration the technology available, the costs of compliance, the energy and non-air 

quality environmental impacts of compliance, any pollution control equipment in use or 

in existence at the source, and the degree of improvement in visibility which may 

reasonably be anticipated to result from the use of such technology.” 

The BART analysis identifies the best system of continuous emission reduction taking into 

account: 

1. The available retrofit control options 

2. Any pollution control equipment in use at the source (which affects the 

availability of options and their impacts). 

3. The costs of compliance with control options 
Section 1 

Introduction to the Regional Haze Rule 

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Sebesta Blomberg Project No. 556500.20 March 31, 2007 

4. The remaining useful life of the facility 

5. The energy and non-air quality environmental impacts of control options 

6. The visibility impacts analysis 

Only one source at the Smurfit-Stone facility in Ontonagon, Michigan, the Riley Boiler #1, meets the 

BART eligibility requirements. This report documents the BART applicability determination process for 

that boiler. The report includes a review of the state/regional planning organization efforts at determining 

BART eligibility, updating the baseline conditions to 2005-2006 emission averages so as to reflect 

emission reductions already implemented at the source. Based on the information presented in the 

following sections, Smurfit Stone does not believe that BART requirements apply to the Ontonagon 

facility. 
Section 2 

Existing Equipment 

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Sebesta Blomberg Project No. 556500.20 March 31, 2007 

2.0 Existing Equipment

2.1 Riley Boiler 

The Riley Boiler #1, installed in 1966, was designed to burn pulverized coal, wood waste, natural gas, and 

oil. When the mill installed emission control equipment for the Pulp and Paper MACT, the boiler was 

modified to also burn non-condensable gases (NCG). Wood waste is no longer fired and natural gas and 

oil are seldom fired. 

Rated heat input is 375 MMBtu/hr. Flue gas emissions are controlled with multiclones and a Belco 

electrostatic precipitator which was installed in 1983. The design flue gas flow at the boiler outlet is 

160,000 ACFM at a temperature of 475oF. 

2.2 Electrostatic Precipitator 

A weighted-wire electrostatic precipitator (ESP) has been in place at the facility since 1983. The ESP 

removes particulates in the flue gas via electric forces. The particulates are given an electrical charge as 

they pass through the ESP and an electrical field forces the particulates to the collector plates. The 

collector plates are rapped to remove particulates from the collector which are then collected in a hopper 

at the bottom of the ESP. The ESP was designed for a gas flow rate of 160,000 ACFM at a temperature of 

475oF. Recent stack test reports have shown the ESP to be in excellent working condition with particulate 

removal efficiencies exceeding 99.9%. 

2.3 Low NOx Burners 

Riley Boiler #1 was retrofitted in 1995 with four low-NOx burners designed to burn pulverized coal. 

Low-NOx burners (LNBs) are designed to "stage" combustion. In this technology, a fuel-rich combustion 

zone is created by forcing additional air to the outside of the firing zone and by delaying the combustion 

of coal. 

The burners are DB Riley model 3A Controlled Combustion Venturi (CCV). The design of these burners 

incorporates a venturi coal nozzle and spreader to reduce NOx emissions. The venturi nozzle concentrates 

the pulverized coal and primary air into a fuel-rich mixture. The fuel/air mixture passes over spreader 

blades that divide the mixture into distinct streams. Devolatilization of the coal in the fuel-rich mixture 

occurs at the burner exit in an oxygen-lean primary combustion zone, resulting in lower fuel NOx 

conversion. The streams enter the furnace in a helical pattern, resulting in gradual mixing of the coal and 

secondary air. Secondary air is introduced outside the primary combustion zone to further burn the fuel. 

Peak flame temperature is thus reduced and thermal NOx formation is suppressed. 
Section 2 

Existing Equipment 

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Sebesta Blomberg Project No. 556500.20 March 31, 2007 

Following installation of the LNBs, the NOx emission from Boiler #1 was approximately 0.75 

lbs/MMBtu (2004). 

2.4 Flame Stabilization Rings 

To improve combustion and lower the NOx emissions after installation of the LNBs, flame stabilizer 

rings were installed during the fall of 2004. The most recent stack test resulted in a NOx emission rate of 

0.403 pounds NOx per MMBtu. 

2.5 Boiler MACT Compliance 

SSCC has been required to address emissions of mercury and hydrogen chloride from the Riley Boiler 

under the NESHAP for Industrial/Commercial/Institutional Boilers and Process Heaters, commonly 

referred to as the Boiler MACT. To meet these requirements SSCC has begun installation of a multipollutant control system from Mobotec USA. 

Mobotec System 

The design and construction of a pollution control system from MobotecUSA is currently 

underway in an effort to ensure compliance with Boiler MACT. The Mobotec system was chosen 

to meet Boiler MACT requirements in large part due to their system’s inherent reduction in NOx 

and because the system provides the potential for incorporating pollutant control upgrades for 

other pollutants. 

The Mobotec control package is based on a Rotating Opposed Fired Air (ROFA) fan system. The 

ROFA fan system will supply high velocity air to multiple ROFA boxes installed at key locations 

inside the furnace of the boiler. This allows the boiler to achieve higher combustion efficiencies 

and lower pollutant emissions. The design and locations of the ROFA boxes are determined 

through computational fluid dynamics (CFD). 

Below is Mobotec’s description of their ROFA system taken from their website: 

The volume of the furnace is set in rotation via special asymmetrically placed air 

nozzles. The combustion gases mix well with the added air, making a combustion 

gas swirl. This generates turbulence and rotation in the entire furnace. Rotation 

prevents laminated flow and the whole volume of the furnace can be used more 

effectively for the combustion process. The ROFA® swirl reduces the maximum 

temperature of the flames and increases heat absorption, which in turn improves 

the boilers overall efficiency. With the ROFA® technique surplus air can be 

reduced without increasing CO or other unwanted substances. The combustion 
Section 2 

Existing Equipment 

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Sebesta Blomberg Project No. 556500.20 March 31, 2007 

air is mixed more effectively. The result is less cooling of the furnace due to 

unused combustion air, thereby increasing efficiency. 

Some of the documented advantages of the ROFA techniques are: 

• Less temperature variation in the cross section of the furnace. 

• A more even distribution of combustion products in the cross-section of the 

furnace (e.g., CO, NOx, SOx etc.) 

• Rotary mixing dramatically reduces fly ash (i.e. unburnt content in the flue 

gas). 

• Lower CO levels mean less surplus air. Less surplus air (O2) means less 

NOx and higher overall efficiency. 

• Increased heat absorption from the furnace itself results in lower outgoing 

furnace temperature and potential increased energy output. 

• Less temperature variation of superheated steam. 

To meet Boiler MACT requirements, Smurfit Stone is installing the ROFA system and a sorbent 

injection system (MinPlus) for control of mercury emissions. Smurfit-Stone expects that this 

system will also provide further NOx reductions from the Riley Boiler.
Section 3 

BART Applicability Determination 

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Sebesta Blomberg Project No. 556500.20 March 31, 2007 

3.0 BART Applicability Determination 

The regional haze rules established a multi-step process for determining which existing sources must 

apply BART. 

3.1 BART ‘Eligible’ Sources 

In the first step of the process, the state, on its own or through its Regional Planning Organization (RPO) 

develops a list of sources that; were installed between August 1962 and August 1977, belong to one of the 

26 named source categories listed in Table 1., and have aggregated potential emissions within a single 

category exceeding 250 tons per year for any one of the BART pollutants; sulfur dioxide, nitrogen oxides, 

particulate matter, VOC. 

Table 1. 26 Named Source Categories Where BART-Eligible Source May be Found 

(1) Fossil-fuel fired steam electric plants of more than 250 million British thermal units per 

hour heat input 

(2) Coal cleaning plants (thermal dryers) 

(3) Kraft pulp mills 

(4) Portland cement plants 

(5) Primary zinc smelters 

(6) Iron and steel mill plants 

(7) Primary aluminum ore reduction plants 

(8) Primary copper smelters 

(9) Municipal incinerators capable of charging more than 250 tons of refuse per day 

(10) Hydrofluoric, sulfuric, and nitric acid plants 

(11) Petroleum refineries 

(12) Lime plants 

(13) Phosphate rock processing plants 

(14) Coke oven batteries 

(15) Sulfur recovery plants 

(16) Carbon black plants (furnace process) 

(17) Primary lead smelters 

(18) Fuel conversion plants 

(19) Sintering plants 

(20) Secondary metal production facilities 

(21) Chemical process plants 

(22) Fossil-fuel boilers of more than 250 million British thermal units per hour heat input 

(23) Petroleum storage and transfer facilities with a capacity exceeding 300,000 barrels 

(24) Taconite ore processing facilities 

(25) Glass fiber processing plants 

(26) Charcoal production facilities. 
Section 3 

BART Applicability Determination 

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Sebesta Blomberg Project No. 556500.20 March 31, 2007 

The Riley Boiler at the Ontonagon facility is subject to BART under source category 22, Fossil-fuel 

boilers of more than 250 million British thermal units per hour heat input. 

3.2 Determine ‘Reasonable Cause or Contribution to 

Visibility Impairment’ 

Following identification of BART-eligible sources, the states were to determine whether the sources 

collectively impaired visibility at a Class I area, and whether a specific source could cause or contribute to 

impairment. In general terms, this involved determining whether the amount of pollutant emitted and the 

distance of the source from the Class I area allowed emissions from the source to impact visibility in the 

Class I area. In the Guidelines for BART Determinations Under the Regional Haze Rules (Appendix Y to 

40 CFR Part 51), EPA defined ‘causing impairment’ as demonstrating a modeled impact on visibility 

exceeding 1.0 deciviews. A source was said to ‘contribute to impairment’ if its modeled visibility impact 

exceeded 0.5 deciviews. Further, EPA specified that those thresholds be evaluated based on the 98th

percentile modeled impact, which means that the impacts must be indicated for more than seven days per 

year. 

What is a deciview? A deciview is defined as an atmospheric haze metric that 

expresses uniform changes in visibility regardless of the background. A one deciview 

change in visibility is thought to be the level of perceptible change that can be noted 

with the human eye. The measure is related mathematically to the common visibility 

parameters of light extinction coefficients and visual range; however, it remains a 

somewhat subjective measure. 

The states were given a variety of options for determining whether the BART-eligible source could 

reasonably cause or contribute to impairment. 

• Decide that all BART-eligible sources in the state do cause or contribute to visibility impairment. 

• Demonstrate that all of the BART-eligible sources do NOT cause or contribute to visibility 

impairment. 

• Evaluate BART-eligible sources individually to determine whether they contribute to visibility 

impairment. This could be accomplished by using an emission rate-to-distance (Q/D) from the 

Class I area metric, or via regional modeling. 

• Use a conservative ‘model facility’ approach that establishes very conservative parameters for a 

facility, then modeling the impacts of that facility to estimate which BART eligible sources may 

cause or contribute to visibility impairment. 

Michigan has chosen to use the individual source evaluation method. 
Section 3 

BART Applicability Determination 

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Sebesta Blomberg Project No. 556500.20 March 31, 2007 

3.3 State/RPO BART Applicability Determinations 

The Michigan Department of Environmental Quality (MDEQ), through the regional planning 

organization, Lake Michigan Air Directors Consortium (LADCO), conducted modeling of all sources to 

determine impacts to visibility in Class I areas. The model was developed by LADCO using 2004 

MAERS inventory data for the Riley Boiler at the Smurfit-Stone facility (although PM emissions were 

omitted). The model evaluated visibility impacts from the Riley Boiler upon four Class I areas that fall 

within the 500 kilometer radius of the facility. Of the four Class I areas evaluated, Voyageur’s National 

Park and Boundary Water Canoe Area in Minnesota, and Seney Wilderness and Isle Royale in Michigan, 

impacts were indicated only at Isle Royale. 

The LADCO model indicated visibility impacts exceeding 0.5 deciviews for more than seven days for the 

years 2002, 2003 and 2004 meteorological data sets. We have rerun the original LADCO model using 

their selected model settings and background concentration assumptions, but with two exceptions: 

LADCO had originally modeled using background values for ammonium sulfate and organic carbon that 

were established for the Western U.S. – we have changed those background values to reflect the more 

appropriate Eastern U.S. values. Secondly, we have included the PM emissions that were mistakenly 

omitted from the original LADCO analysis. 

Table 2. LADCO Model Results Using 2004 MAERS Data 

Met Year Days > 0.5 dv 

2002 22 

2003 21 

2004 11 

The results of the LADCO model run using the 2004 MAERS emission data, predicts that the Riley 

Boiler contributes to visibility impairment at Isle Royale. 

3.4 Updating the Baseline 

Since the baseline emissions were established in 2004, SSCC has implemented additional controls that 

have reduced the emission of visibility impairing pollutants. As a result, the visibility impact of the Riley 

Boiler has also been reduced from that indicated by the LADCO baseline model results. In the preamble 

to the July 20, 2001 Proposed BART Determination Guidelines, EPA says “For purposes of estimating 

actual emissions, these guidelines take a similar approach to the current definition of actual emissions in 

NSR programs. That is, the baseline emissions are the average annual emissions from the two most recent 

years...” This approach was unchanged in the July 6, 2005 final rule. Table 3 presents the MAERS 

emission inventory information for years 2005 and 2006 and the average of emissions during those two 

years. 
Section 3 

BART Applicability Determination 

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Sebesta Blomberg Project No. 556500.20 March 31, 2007 

Table 3. 2005, 2006 and Average MAERS Data for Smurfit Stone 

Pollutant 2005 (TPY) 2006 (TPY) Two-Year Average 

SO2 2914 2846 2880 

NOx 715 628 671.5 

PM10 37 38 37.5 

Modeling of visibility impacts at Isle Royale was then completed using the updated baseline condition. 

Table 4 lists the number of days each modeled year with visibility impacts exceeding the 0.5 dv change 

threshold. Use of the updated baseline period shows that reductions already made by SSCC have 

significantly reduced the predicted impacts. 

Table 4. Model-Predicted Visibility Impacts Using the Updated 2005-2006 Emissions Data 

Met Year Days > 0.5 dv 

2002 17 

2003 15 

2004 7 

3.5 Impacting Isle Royale? 

As stated on the official Isle Royale Park Service website, Isle Royale “is one of the few national parks to 

close during the winter.” The Park is closed from November 1 through April 16 and operates under 

reduced hours during May, June and September. Due to harsh conditions, even park management leaves 

the island during the winter months, relocating to Houghton, Michigan. Not only is the park ‘closed’ 

during the winter months, the Park Services states on their website that it is not possible to reach the park 

during these months: 

“A National Atmospheric Deposition Program/National Trends Network (NADP/NTN) 

wet deposition monitor has been operating at Wallace Lake in Isle Royale NP (site 

#MI97) since 1985. Because the site can’t be accessed for winter sampling, data don’t 

meet the completeness criteria required by NADP/NTN for a trend analysis.” 

(From http://www2.nature.nps.gov/air/Permits/ARIS/isro/ (accessed March 21, 2007)) 

Isle Royale differs from the majority of Class I areas because there is no physical way for the park to be 

observed by visitors, day or night, for nearly half of the year. This brings into question whether it is 

appropriate to calculate visibility impact values in the same manner for Isle Royale as for other Class I 

areas which are staffed and open to visitors on a year-round basis. Considering that the park is closed for 

5.5 months, or 46 percent of the year, SSCC proposes that the updated baseline case could be represented 

as shown in Table 5 below, where the number of days with predicted impact exceeding 0.5 dv is 

multiplied by the 54 percent of the year that the park is operating. It should also be noted that no 
Section 3 

BART Applicability Determination 

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Sebesta Blomberg Project No. 556500.20 March 31, 2007 

additional adjustment was made for the significant amount of time that the park is open, but operating 

under reduced hours. 

Table 5. Updated Baseline Model Results Scaled for Park Closure Period 

Met Year Days > 0.5 dv 

2002 9.18 

2003 8.10 

2004 3.78 

Taking the average of the values shown in Table 5 leads to an average of 7.02 days with predicted 

visibility impact greater than 0.5 dv. This is less than the 98th percentile value for number of days per 

year : (365 * (1-0.98) = 7.3 days with deciview changes greater than 0.5 dv) , which indicates that the 

Riley Boiler does not contribute to visibility impairment at Isle Royale. Per the Regional Haze 

Regulations, BART requirements apply only to sources that may reasonably be anticipated to cause or 

contribute to impairment of visibility in a Class I area. 

SSCC urges that MDEQ determine that the Riley Boiler can not be found to reasonably cause or 

contribute to appreciable visibility degradation at Isle Royale, and therefore BART does not apply to the 

Riley Boiler. 
Section 4 

Summary 

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Sebesta Blomberg Project No. 556500.20 March 31, 2007 

4.0 Summary 

Smurfit Stone Container Corporation (SSCC) believes that the Riley Boiler at the Ontonagon, Michigan 

facility does not sufficiently impact visibility at Isle Royale to require installation of BART controls. The 

continuous improvement in boiler operation and control over recent years, and the current installation of 

controls to meet requirements of the Boiler MACT have or will reduce potential visibility impacts from 

the boiler. This claim is further strengthened by the fact that Isle Royale is unique among Class I areas in 

that there is virtually no access to the park for nearly half of the year. By discounting the modeled 

visibility impacts to reflect this lack of access, it appears that the Riley Boiler may produce visibility 

impacts of greater than 0.5 deciviews on an average of only 7.02 days per year, which is below the 7.3 

day threshold that is the 98th percentile value as specified in the BART regulations. SSCC therefore 

concludes that the Riley Boiler does not cause or contribute to visibility impairment in a Class I areas and 

therefore, is not subject to the requirement to install BART controls. 
Appendix A: 

CALPUFF Protocol 

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Appendix A 

CALPUFF Protocol 
Appendix A: 

CALPUFF Protocol 

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Sebesta Blomberg Project No. 556500.20 March 31, 2007 

CALPUFF Protocol 

The following model settings were employed in all modeling described in this report. In an effort to 

facilitate the MDEQ review process, SSCC chose to use the regional modeling approach conducted by 

LADCO with only minor modifications or corrections. Model output files from CALPUFF and the 

CALPOST utility are included in the appendices to this report. 

CALPUFF Modeling Protocol for SSCC BART Impacts 

Analysis 

Model Selection 

Regional visibility modeling was performed for the Smurfit Stone Container Corporation (SSCC) 

in Ontonagon, Michigan, using Bee-Line Software’s Professional CALPUFF Version 2.34.0, a 

Graphical User Interface (GUI) which interfaces with the EPA CALPUFF 2004 Version. This 

program implements CALPUFF version 5.756 and CALPOST version 5.6393. 

Modeling Protocol 

The modeling protocols supplied by the Midwest Regional Planning Organization (MRPO) and 

LADCO were consulted during the development of the SSCC facility model. Recommended 

default model values were taken from the LADCO protocol. The Interagency Workgroup on Air 

Quality Modeling (IWAQM) Phase 2 Report and Recommendations for Modeling Long Range 

Transport Impacts was also consulted during the development of the model and served as the 

starting point for the SSCC modeling effort. 

Modeling Domain 

The CALPUFF modeling domain is the RPO grid used by LADCO, a Lambert conformal grid 

projection centered at 97W, 40N with true latitudes at 33N and 45N and origin at -900 km, -1620 

km. There are 97 36-km grid cells in the east-west direction and 90 36-km grid cells in the north 

–south direction to make up the horizontal domain. The vertical domain contains 16 layers up to 

15 km in the atmosphere with higher resolution in the boundary layer. 

Meteorological Data 

Meteorological data were supplied by LADCO. The CALMET data files were created using 

MM5 output files. All meteorological data are in 36 km resolution. Each met file contains the 

data for one day. To retain consistency with the LADCO model, no observation data were added 

to the MM5-generated CALMET files. The LADCO data set includes calendar years 2002, 2003 

and 2004. 
Appendix A: 

CALPUFF Protocol 

Smurfit-Stone Corporation - BART Applicability Determination Page 15 of 21 

Sebesta Blomberg Project No. 556500.20 March 31, 2007 

Terrain 

Terrain effects were incorporated by LADCO in the development of the MM5 data and 36-km 

grid development. 

Receptors 

Pre-defined receptors established by the Federal Land Managers were added to the Federal Class 

I Area of Isle Royale. A total of 966 receptors at ground level are included in the Class I area. 

Species Modeled 

Sulfur dioxide, sulfate, nitrogen oxides, nitric acid, nitrates and particulate matter less than 10 

micrometers in diameter (PM10) are the species modeled for the SSCC facility. Sulfur dioxide, 

nitrogen oxides and PM10 are modeled as emitted and all species are modeled as deposited. The 

CALPUFF chemical transformation algorithms general sulfate and nitrate concentrations. 

Model Settings 

The model was set to output for concentrations and visibility in 24-hour averages. Visibility 

settings identified sulfate, nitrate, and coarse particles (PM10) to be included in computing total 

light extinction. Rayleigh scattering was set equal to 10. The particle growth curve for 

hygroscopic species was set to the FLAG (2000) f(RH) tabulation. The method used for 

background light extinction is Method 6; FLAG RH adjustment factor applied to observed and 

modeled sulfates and nitrates computed using monthly relative humidity factors. The relative 

humidity factors used for each month are listed in Table 6 below. Table 7 shows the monthly 

background concentrations used. In both cases, values are taken directly from LADCO. 

Table 6. Assumed Background Relative Humidity Values 

Month 

Relative 

Humidity Month 

Relative 

Humidity 

January 3.1 July 3.0 

February 2.5 August 3.2 

March 2.7 September 3.8 

April 2.4 October 2.7 

May 2.2 November 3.3 

June 2.6 December 3.3 

Table 7. Assumed Monthly Background Concentrations 

Component 

Background 

Concentration (μg/m3) 

Ammonium sulfate 0.2 

Ammonium nitrate 0.1 
Appendix A: 

CALPUFF Protocol 

Smurfit-Stone Corporation - BART Applicability Determination Page 16 of 21 

Sebesta Blomberg Project No. 556500.20 March 31, 2007 

Component 

Background 

Concentration (μg/m3) 

Coarse particles 3.0 

Organic carbon 1.5 

Soil 0.5 

Elemental carbon 0.02 

Model Settings Compared to Default Values 

Both IWAQM and LADCO recommend default model settings in their modeling protocols. These default 

settings have been used for most variables in the model. The CALPUFF variables, the IWAQM default 

value, the LADCO default value and the value used in the SSCC model are shown in Table 8 below. Any 

differences are highlighted in gray and are explained below. Where IWAQM and LADCO guidance 

differed, the SSCC model generally follows the LADCO methodology. CALPOST defaults are shown in 

Table 9. 

Table 8. CALPUFF Settings and Default Values 

Input 

Group Variable Description IWAQM Default LADCO Default 

SSCC Model 

Value 

1 AVET Minutes 60 60 60 

1 PGTIME Minutes 60 60 

2 MGAUSS 1=Gaussian 1 1 1 

2 MCTADJ 3=partial plume path 

adjustment 3 3 3 

2 MCTSG Subgrid-scale complex 

terrain flag modeled? No No No 

2 MSLUG Near-field puffs 

modeled as elongated? No No No 

2 MTRANS Transitional plume rise 

modeled? Yes Yes Yes 

2 MTIP Stack Tip Downwash 

Used? Yes Yes Yes 

2 MSHEAR Vertical wind shear 

modeled? No No No 

2 MSPLIT Puff splitting allowed? No No No 

2 MAQCHEM 

Aqueous phase 

transformation 

modeled? 

No No 

2 MWET Wet removal modeled? Yes Yes Yes 

2 MDRY Dry deposition 

modeled? Yes Yes Yes 

2 MDISP 

Dispersion Coefficients 

used 

3 PG dispersion 

coefficients for 

RURAL areas 

(computed using 

ISCST multi-segment 

approximation) and 

MP coefficients in 

3 PG dispersion 

coefficients for 

RURAL areas 

(computed using 

ISCST multi-segment 

approximation) and 

MP coefficients in 

3 PG dispersion 

coefficients for 

RURAL areas 

(computed using 

ISCST multisegment 

approximation) 
Appendix A: 

CALPUFF Protocol 

Smurfit-Stone Corporation - BART Applicability Determination Page 17 of 21 

Sebesta Blomberg Project No. 556500.20 March 31, 2007 

Input 

Group Variable Description IWAQM Default LADCO Default 

SSCC Model 

Value 

urban areas urban areas and MP 

coefficients in 

urban areas 

2 MROUGH PG sigma-y,z adjusted 

for roughness? No No No 

2 MPARTL Model partial plume 

penetration? Yes Yes Yes 

2 MPDF Use PDF for convective 

dispersion No No No 

2 MSGTIBL Use TIBL module? No No No 

4 MESHDN Nesting factor for 

sampling grid? Yes Yes Yes 

9 RCUTR Reference cuticle 

resistance (s/cm) 30 30 30 

9 RGR Reference ground 

resistance (s/cm) 10 10 10 

9 REACTR Reference reactivity 8 8 8 

9 NINT Number of particle-size 

intervals 9 9 9 

9 IVEG 

Vegetation state in 

unirrigated areas active 

and unstressed? 

Yes Yes Yes 

11 BCKO3 

Background Ozone 

concentrations (ppb per 

month) 

80, 80, 80, 80, 80, 80, 

80, 80, 80, 80, 80, 80 

31, 31, 31, 37, 37, 37, 

33, 33, 33, 27, 27, 27 

31, 31, 31, 37, 37, 

37, 33, 33, 33, 27, 

27, 27 

11 BCKNH3 

Background ammonia 

concentrations (ppb per 

month) 

10, 10, 10, 10, 10, 10, 

10, 10, 10, 10, 10, 10 

0.3, 0.3, 0.3, 0.5, 0.5, 

0.5, 0.5, 0.5, 0.5, 0.5, 

0.5, 0.5 

0.3, 0.3, 0.3, 0.5, 

0.5, 0.5, 0.5, 0.5, 

0.5, 0.5, 0.5, 0.5 

11 RNITE1 Nighttime SO2 loss rate 

(%/hr) 0.2 0.2 0.2 

11 RNITE2 Nighttime NOx loss rate 

(%/hr) 2.0 2.0 2.0 

11 RNITE3 Nighttime HNO3 loss 

rate (%/hr) 2.0 2.0 2.0 

12 SYTDEP 

Horizontal size (m) to 

switch to time 

dependence 

550 550 550 

12 MHFTSZ Use Heffter for vertical 

dispersion? No No No 

12 JSUP PG Stability class above 

mixed layer 5 5 5 

12 CONK1 Stable dispersion 

constant 0.01 0.01 0.01 

12 CONK2 Neutral dispersion 

constant 0.1 0.1 0.1 

12 TBD Transition for 

downwash algorithms 

0.5 ISC Transitionpoint 0.5 ISC Transitionpoint 0.5 ISC 

Transition-point 

12 IURB1 Beginning urban 

landuse type 10 10 10 

12 IURB2 Ending urban landuse 

type 19 19 19 

12 XMXLEN Maximum slug length 

in units of DGRIDKM 1.0 1.0 1.0 
Appendix A: 

CALPUFF Protocol 

Smurfit-Stone Corporation - BART Applicability Determination Page 18 of 21 

Sebesta Blomberg Project No. 556500.20 March 31, 2007 

Input 

Group Variable Description IWAQM Default LADCO Default 

SSCC Model 

Value 

12 XSAMLEN 

Maximum puff travel 

distance per sampling 

step (units of 

DGRIDKM) 

1.0 1.0 1.0 

12 MXNEW Maximum number of 

puffs per hour 99 99 99 

12 MXSAM Maximum sampling 

steps per hour 99 99 99 

12 NCOUNT 

Number of iterations 

used when computing 

the transport wind for a 

sampling step that 

includes gradual rise 

2 2 

12 SYMIN 

Minimum lateral 

dispersion of new purr 

(m) 

1.0 1.0 1.0 

12 SZMIN 

Minimum vertical 

dispersion of new puff 

(m) 

1.0 1.0 1.0 

12 SVMIN 

Array of minimum 

lateral turbulence (m/s) 0.5, 0.5, 0.5, 0.5, 0.5, 

0.5 for land 

0.37, 0.37, 0.37, 0.37, 

0.37, 0.37 for water 

0.5, 0.5, 0.5, 0.5, 0.5, 

0.5 for land 

0.37, 0.37, 0.37, 0.37, 

0.37, 0.37 for water 

0.5, 0.5, 0.5, 0.5, 

0.5, 0.5 for land 

0.37, 0.37, 0.37, 

0.37, 0.37, 0.37 for 

water 

12 SWMIN Array of minimum 

vertical turbulence (m/s) 

0.20, 0.12, 0.08, 0.06, 

0.03, 0.016 

0.20, 0.12, 0.08, 0.06, 

0.03, 0.016 

0.20, 0.12, 0.08, 

0.06, 0.03, 0.016 

12 CDIV 

Divergence criterion for 

dw/dz across puff used 

to initiate adjustment 

for horizontal 

convergence (1/s) 

0.01 0.00, 0.00 0.00, 0.00 

12 WSCALM 

Minimum wind speed 

(m/s) allowed for noncalm conditions 0.5 0.5 0.5 

12 XMAXZI Maximum mixing 

height (m) 3000 3000 3000 

12 XMINZI Minimum mixing height 

(m) 50 50 50 

12 WSCAT Default wind speed 

classes 

1.54, 3.09, 5.14, 8.23, 

10.8 

1.54, 3.09, 5.14, 

8.23, 10.8 

12 PLX0 

Default wind speed 

profile power-law 

exponents for stabilities 

1-6 

0.07, 0.07, 0.10, 0.15, 

0.35, 0.55 

0.07, 0.07, 0.10, 

0.15, 0.35, 0.55 

12 PTG0 

Default potential 

temperature gradient for 

stable classes E, F (deg 

K/m) 

0.020, 0.035 0.020, 0.035 0.020, 0.035 

12 PPC 

Default plume path 

coefficients for each 

stability class 

0.50, 0.50, 0.50, 0.50, 

0.35, 0.35 

0.50, 0.50, 0.50, 0.50, 

0.35, 0.35 

0.50, 0.50, 0.50, 

0.50, 0.35, 0.35 

12 SL2PF 

Slug-to-puff transition 

criterion factor equal to 

sigma-y/length of slug 

10 10 
Appendix A: 

CALPUFF Protocol 

Smurfit-Stone Corporation - BART Applicability Determination Page 19 of 21 

Sebesta Blomberg Project No. 556500.20 March 31, 2007 

Input 

Group Variable Description IWAQM Default LADCO Default 

SSCC Model 

Value 

12 NSPLIT 

Number of puffs that 

result every time a puff 

is split vertically 

3 3 3 

12 IRESPLIT 

Time of day when split 

puffs are eligible to be 

split once again; 

typically set once per 

day around sunset 

before nocturnal shear 

develops 

User Defined 17 17 

12 ZISPLIT Previous hour’s mixing 

height (minimum) (m) 100 100 100 

12 ROLDMAX 

Previous maximum 

mixing height / current 

mixing height ratio, 

must be less than this 

value to allow puff split 

0.25 0.25 0.25 

12 NSPLITH 

Number of puffs that 

result every time a puff 

is split horizontally 

5 5 

12 SYSPLITH 

Minimum sigma-y (grid 

cell units) of puff before 

it may be split 

1.0 1.0 

12 SHSPLITH 

Minimum puff 

elongation rate 

(SYSPLIT/hr) due to 

wind shear before it 

may be split 

2.0 2.0 

12 CNSPLITH 

Minimum concentration 

(g/m3) of each species 

in puff before it may be 

split 

1.0E-07 1.0E-07 

12 EPSSLUG 

Fractional convergence 

criterion for numerical 

SLUG sampling 

integration 

1.0E-04 1.0E-04 1.0E-04 

12 EPSAREA 

Fractional convergence 

criterion for numerical 

AREA source 

integration 

1.0E-06 1.0E-06 1.0E-06 

12 DSRISE 

Trajectory step-length 

(m) used for numerical 

rise integration 

1.0 1.0 

The SSCC model uses the same defaults as employed by LADCO for CALPOST. IWAQM did not 

provide default CALPOST values in the Phase 2 report. 

Table 9. CALPOST Settings and Default Values for Extinction Efficiency 

Variable LADCO Default SSCC Model Value 

EEPMC 0.6 Modeled PM Coarse 0.6 Modeled PM Coarse 

EEPMF 1.0 Modeled PM Fine 1.0 Modeled PM Fine 

EEPMCBK 0.6 Background PM Coarse 0.6 Background PM Coarse 

EESO4 3.0 Ammonium Sulfate 3.0 Ammonium Sulfate 
Appendix A: 

CALPUFF Protocol 

Smurfit-Stone Corporation - BART Applicability Determination Page 20 of 21 

Sebesta Blomberg Project No. 556500.20 March 31, 2007 

Variable LADCO Default SSCC Model Value 

EENO3 3.0 Ammonium Nitrate 3.0 Ammonium Nitrate 

EEOC 4.0 Organic Carbon 4.0 Organic Carbon 

EESOIL 1.0 Soil 1.0 Soil 

EEEC 10.0 Elemental Carbon 10.0 Elemental Carbon 

Variables Adjusted from IWAQM and/or LADCO Defaults 

CDIV 

The LADCO default and the value used for the SSCC model for CDIV, the divergence criterion 

for dw/dz across the puff used to initiate adjustment for horizontal convergence (1/s) was set at 

0.0, 0.0. This differs from the IWAQM recommended setting value equal to 0.01. 

BCK03 

The IWAQM recommended default for background ozone concentrations is 80 ppb for all 

months. This value should only be used for missing data. SSCC employed the LADCO defaults 

for background ozone concentration of 31 ppb for January, February and March; 37 ppb for 

April, May and June; 33 ppb for July, August, September, and 27 ppb for October, November and 

December. 

BCKNH3 

The background ammonia concentration recommended by IWAQM is 10 ppb for all months. 

The LADCO background concentrations for ammonia are 0.3 ppb in January, February and 

March and 0.5 ppb for the rest of the year. The LADCO default values were used in the SSCC 

model. 

Source Parameters 

The source parameters for the Riley Boiler as entered into the CALPUFF model in Input Group 

13 are shown in Table 10 below. 

Table 10. Source Parameters Modeled for the Riley Boiler 

Variable Parameter 

Source ID 1 

UTM X (km) 780.0257 

UTM Y (km) 5197.3649 

Zone 15 

Stack Height (m) 61.1400 

Base Elevation (m) 198.0000 

Stack Diameter (m) 2.2900 

Exit Velocity (m/s) 17.6200 

Exit Temperature (K) 445.3700 
Appendix B: 

2005 – 2006 Baseline Model Output Files 

Smurfit-Stone Corporation - BART Applicability Determination Page 21 of 21 

Sebesta Blomberg Project No. 556500.20 March 31, 2007 

Appendix B 

2005-2006 

Baseline Model Output Files 
Appendix 9O 

Emission Limits – Excerpts from ROP for Smurfit- Stone 

Container Company 
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 2 of 32 

Michigan Department of Environmental Quality 

Air Quality Division 

EFFECTIVE DATE: January 1, 2007 

REVISION DATES: June 13, 2007; November 13, 2007; 

June 29, 2009 

ISSUED TO: 

Smurfit-Stone Container Enterprises, Inc. 

d/b/a Smurfit-Stone Container Corporation 

State Registration Number (SRN): A5754 

LOCATED AT: 

One Superior Way, Ontonagon, Michigan 49953 

RENEWABLE OPERATING PERMIT 

Permit Number: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

Administratively Complete ROP Renewal Application Due Between July 1, 2010 and July 1, 2011 

This Renewable Operating Permit (ROP) is issued in accordance with and subject to Section 5506(3) of 

Part 55, Air Pollution Control, of the Natural Resources and Environmental Protection Act, 1994 PA 451, 

as amended (Act 451). Pursuant to Michigan Air Pollution Control Rule 210(1), this ROP constitutes the 

permittee’s authority to operate the stationary source identified above in accordance with the general 

conditions, special conditions and attachments contained herein. Operation of the stationary source and 

all emission units listed in the permit are subject to all applicable future or amended rules and regulations 

pursuant to Act 451 and the federal Clean Air Act. 

SOURCE-WIDE PERMIT TO INSTALL 

Permit Number: MI-PTI-A5754-2007c 

This Permit to Install (PTI) is issued in accordance with and subject to Section 5505(5) of Act 451. 

Pursuant to Michigan Air Pollution Control Rule 214a, the terms and conditions herein, identified by the 

underlying applicable requirement citation of Rule 201(1)(a), constitute a federally enforceable PTI. The 

PTl terms and conditions do not expire and remain in effect unless the criteria of Rule 201(6) are met.

Operation of all emission units identified in the PTI is subject to all applicable future or amended rules

and regulations pursuant to Act 451 and the federal Clean Air Act. 

Michigan Department of Environmental Quality 
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 3 of 32 

______________________________________ 

William A. Presson, Acting Permit Section Supervisor
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 4 of 32 

TABLE OF CONTENTS

AUTHORITY AND ENFORCEABILITY......................................................................................................5

A. GENERAL CONDITIONS .....................................................................................................................6

Permit Enforceability ...................................................................................................................................6

General Provisions......................................................................................................................................6

Equipment & Design ...................................................................................................................................7

Emission Limits ...........................................................................................................................................7

Testing/Sampling ........................................................................................................................................7

Monitoring/Recordkeeping ..........................................................................................................................8

Certification & Reporting .............................................................................................................................8

Permit Shield...............................................................................................................................................9

Revisions ..................................................................................................................................................10

Reopenings...............................................................................................................................................10

Renewals ..................................................................................................................................................11

Stratospheric Ozone Protection ................................................................................................................11

Risk Management Plan.............................................................................................................................11

Emission Trading ......................................................................................................................................11

Permit To Install (PTI) ...............................................................................................................................12

B. SOURCE-WIDE CONDITIONS...........................................................................................................12

C. EMISSION UNIT CONDITIONS..........................................................................................................13

EMISSION UNIT SUMMARY TABLE .......................................................................................................13

EUCOPE...................................................................................................................................................14

EURB1 ......................................................................................................................................................17

EUFA1 ......................................................................................................................................................20

EUPB2A....................................................................................................................................................22

EUPB3 ......................................................................................................................................................25

EUPB4 ......................................................................................................................................................27

D. FLEXIBLE GROUP CONDITIONS .....................................................................................................29

E. NON-APPLICABLE REQUIREMENTS...............................................................................................29

APPENDICES...........................................................................................................................................30

Appendix 1: Abbreviations and Acronyms ...............................................................................................30

Appendix 2. Schedule of Compliance ......................................................................................................31

Appendix 3. Monitoring Requirements.....................................................................................................31

Appendix 4. Recordkeeping.....................................................................................................................31

Appendix 5. Testing Procedures..............................................................................................................31

Appendix 6. Permits to Install ..................................................................................................................31

Appendix 7. Emission Calculations..........................................................................................................32

Appendix 8. Reporting .............................................................................................................................32
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 5 of 32 

AUTHORITY AND ENFORCEABILITY 

For the purpose of this permit, the permittee is defined as any person who owns or operates an 

emission unit at a stationary source for which this permit has been issued. The department is defined in 

Rule 104(d) as the Director of the Michigan Department of Environmental Quality (MDEQ) or his or her 

designee. 

The permittee shall comply with all specific details in the permit terms and conditions and the cited 

underlying applicable requirements. All terms and conditions in this ROP are both federally enforceable 

and state enforceable unless otherwise footnoted. Certain terms and conditions are applicable to most 

stationary sources for which an ROP has been issued. These general conditions are included in Part A 

of this ROP. Other terms and conditions may apply to a specific emission unit, several emission units 

which are represented as a flexible group, or the entire stationary source which is represented as a 

source-wide group. Special conditions are identified in Parts B, C, D and/or the appendices. 

In accordance with Rule 213(2)(a), all underlying applicable requirements will be identified for each ROP 

term or condition. All terms and conditions that are included in a PTI, are streamlined or subsumed, or 

are state-only enforceable will be noted as such. 

In accordance with Section 5507 of Act 451, the permittee has included in the ROP application a 

compliance certification, a schedule of compliance, and a compliance plan. For applicable requirements 

with which the source is in compliance, the source will continue to comply with these requirements. For 

applicable requirements with which the source is not in compliance, the source will comply with the 

detailed schedule of compliance requirements that are incorporated as an appendix in this ROP. 

Furthermore, for any applicable requirements effective after the date of issuance of this ROP, the 

stationary source will meet the requirements on a timely basis, unless the underlying applicable 

requirement requires a more detailed schedule of compliance. 

Issuance of this permit does not obviate the necessity of obtaining such permits or approvals from other 

units of government as required by law. 
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 6 of 32 

A. GENERAL CONDITIONS 

Permit Enforceability 

• All conditions in this permit are both federally enforceable and state enforceable unless otherwise noted. 

(R 336.1213(5))

• Those conditions that are hereby incorporated in a state only enforceable Source-wide PTI pursuant to Rule 

201(2)(d) are designated by footnote one. (R 336.1213(5)(a), R 336.1214a(5))

• Those conditions that are hereby incorporated in federally enforceable Source-wide PTI No. MI-PTI-A5754-2007c 

pursuant to Rule 201(2)(c) are designated by footnote two. (R 336.1213(5)(b), R 336.1214a(3))

General Provisions 

1. The permittee shall comply with all conditions of this ROP. Any ROP noncompliance constitutes a violation of 

Act 451, and is grounds for enforcement action, for ROP revocation or revision, or for denial of the renewal of 

the ROP. All terms and conditions of this ROP that are designated as federally enforceable are enforceable by 

the Administrator of the United States Environmental Protection Agency (USEPA) and by citizens under the 

provisions of the federal Clean Air Act (CAA). Any terms and conditions based on applicable requirements 

which are designated as “state only” are not enforceable by the USEPA or citizens pursuant to the CAA. 

(R 336.1213(1)(a))

2. It shall not be a defense for the permittee in an enforcement action that it would have been necessary to halt or 

reduce the permitted activity in order to maintain compliance with the conditions of this ROP. 

(R 336.1213(1)(b))

3. This ROP may be modified, revised, or revoked for cause. The filing of a request by the permittee for a permit 

modification, revision, or termination, or a notification of planned changes or anticipated noncompliance does 

not stay any ROP term or condition. This does not supersede or affect the ability of the permittee to make 

changes, at the permittee’s own risk, pursuant to Rule 215 and Rule 216. (R 336.1213(1)(c))

4. The permittee shall allow the department, or an authorized representative of the department, upon presentation 

of credentials and other documents as may be required by law and upon stating the authority for and purpose 

of the investigation, to perform any of the following activities (R 336.1213(1)(d)): 

a. Enter, at reasonable times, a stationary source or other premises where emissions-related activity is 

conducted or where records must be kept under the conditions of the ROP. 

b. Have access to and copy, at reasonable times, any records that must be kept under the conditions of the 

ROP. 

c. Inspect, at reasonable times, any of the following: 

i. Any stationary source. 

ii. Any emission unit. 

iii. Any equipment, including monitoring and air pollution control equipment. 

iv. Any work practices or operations regulated or required under the ROP. 

d. As authorized by Section 5526 of Act 451, sample or monitor at reasonable times substances or 

parameters for the purpose of assuring compliance with the ROP or applicable requirements. 

5. The permittee shall furnish to the department, within a reasonable time, any information the department may 

request, in writing, to determine whether cause exists for modifying, revising, or revoking the ROP or to 

determine compliance with this ROP. Upon request, the permittee shall also furnish to the department copies 

of any records that are required to be kept as a term or condition of this ROP. For information which is claimed 

by the permittee to be confidential, consistent with the requirements of the 1976 PA 442, MCL §15.231 et seq., 
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 7 of 32 

and known as the Freedom of Information Act, the person may also be required to furnish the records directly 

to the USEPA together with a claim of confidentiality. (R 336.1213(1)(e))

6. A challenge by any person, the Administrator of the USEPA, or the department to a particular condition or a 

part of this ROP shall not set aside, delay, stay, or in any way affect the applicability or enforceability of any 

other condition or part of this ROP. (R 336.1213(1)(f))

7. The permittee shall pay fees consistent with the fee schedule and requirements pursuant to Section 5522 of 

Act 451. (R 336.1213(1)(g))

8. This ROP does not convey any property rights or any exclusive privilege. (R 336.1213(1)(h))

Equipment & Design 

9. Any collected air contaminants shall be removed as necessary to maintain the equipment at the required 

operating efficiency. The collection and disposal of air contaminants shall be performed in a manner so as to 

minimize the introduction of contaminants to the outer air. Transport of collected air contaminants in Priority I 

and II areas requires the use of material handling methods specified in Rule 370(2). (R 336.1370)

10. Any air cleaning device shall be installed, maintained, and operated in a satisfactory manner and in accordance 

with the Michigan Air Pollution Control rules and existing law. (R 336.1910)

Emission Limits 

11. Except as provided in Subrules 2, 3, and 4 of Rule 301, states in part; “a person shall not cause or permit to be 

discharged into the outer air from a process or process equipment a visible emission of a density greater than 

the most stringent of Rule 301(1)(a) or (b) unless otherwise specified in this ROP.” The grading of visible 

emissions shall be determined in accordance with Rule 303. (R 336.1301(1) in pertinent part): 

a. A 6-minute average of 20 percent opacity, except for one 6-minute average per hour of not more than 27 

percent opacity. 

b. A limit specified by an applicable federal new source performance standard. 

12. The permittee shall not cause or permit the emission of an air contaminant or water vapor in quantities that cause, 

alone or in reaction with other air contaminants, either of the following: 

a. Injurious effects to human health or safety, animal life, plant life of significant economic value, or property. 1

(R 336.1901(a)) 

b. Unreasonable interference with the comfortable enjoyment of life and property. 1(R 336.1901(b)) 

Testing/Sampling 

13. The department may require the owner or operator of any source of an air contaminant to conduct acceptable 

performance tests, at the owner’s or operator’s expense, in accordance with Rule 1001 and Rule 1003, under 

any of the conditions listed in Rule 1001(1). (R 336.2001)

14. Any required performance testing shall be conducted in accordance with Rule 1001(2), Rule 1001(3) and 

Rule 1003. (R 336.2001(2), R 336.2001(3), R 336.2003(1))

15. Any required test results shall be submitted to the Air Quality Division (AQD) in the format prescribed by the 

applicable reference test method within 60 days following the last date of the test. (R 336.2001(4))
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Monitoring/Recordkeeping 

16. Records of any periodic emission or parametric monitoring required in this ROP shall include the following 

information specified in Rule 213(3)(b)(i), where appropriate (R 336.1213(3)(b)): 

a. The date, location, time, and method of sampling or measurements. 

b. The dates the analyses of the samples were performed. 

c. The company or entity that performed the analyses of the samples. 

d. The analytical techniques or methods used. 

e. The results of the analyses. 

f. The related process operating conditions or parameters that existed at the time of sampling or 

measurement. 

17. All required monitoring data, support information and all reports, including reports of all instances of deviation 

from permit requirements, shall be kept and furnished to the department upon request for a period of not less 

than five years from the date of the monitoring sample, measurement, report or application. Support 

information includes all calibration and maintenance records and all original strip-chart recordings, or other 

original data records, for continuous monitoring instrumentation and copies of all reports required by the ROP. 

(R 336.1213(1)(e), R 336.1213(3)(b)(ii))

Certification & Reporting 

18. Except for the alternate certification schedule provided in Rule 213(3)(c)(iii)(B), any document required to be 

submitted to the department as a term or condition of this ROP shall contain an original certification by a 

responsible official which states that, based on information and belief formed after reasonable inquiry, the 

statements and information in the document are true, accurate, and complete. (R 336.1213(3)(c))

19. A responsible official shall certify to the appropriate AQD District Office and to the USEPA that the stationary 

source is and has been in compliance with all terms and conditions contained in the ROP except for deviations 

that have been or are being reported to the appropriate AQD District Office pursuant to Rule 213(3)(c). This 

certification shall include all the information specified in Rule 213(4)(c)(i) through (v) and shall state that, based 

on information and belief formed after reasonable inquiry, the statements and information in the certification are 

true, accurate, and complete. The USEPA address is: USEPA, Air Compliance Data - Michigan, Air and 

Radiation Division, 77 West Jackson Boulevard, Chicago, Illinois 60604. (R 336.1213(4)(c))

20. The certification of compliance shall be submitted annually for the term of this ROP as detailed in the special 

conditions, or more frequently if specified in an applicable requirement or in this ROP. (R 336.1213(4)(c))

21. The permittee shall promptly report any deviations from ROP requirements and certify the reports. The prompt 

reporting of deviations from ROP requirements is defined in Rule 213(3)(c)(ii) as follows, unless otherwise 

described in this ROP. (R 336.1213(3)(c))

a. For deviations that exceed the emissions allowed under the ROP, prompt reporting means reporting 

consistent with the requirements of Rule 912 as detailed in Condition 25. All reports submitted pursuant to 

this paragraph shall be promptly certified as specified in Rule 213(3)(c)(iii). 

b. For deviations which exceed the emissions allowed under the ROP and which are not reported pursuant to 

Rule 912 due to the duration of the deviation, prompt reporting means the reporting of all deviations in the 

semiannual reports required by Rule 213(3)(c)(i). The report shall describe reasons for each deviation and 

the actions taken to minimize or correct each deviation. 

c. For deviations that do not exceed the emissions allowed under the ROP, prompt reporting means the 

reporting of all deviations in the semiannual reports required by Rule 213(3)(c)(i). The report shall describe 

the reasons for each deviation and the actions taken to minimize or correct each deviation. 

22. For reports required pursuant to Rule 213(3)(c)(ii), prompt certification of the reports is described in 

Rule 213(3)(c)(iii) as either of the following (R 336.1213(3)(c)): 
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a. Submitting a certification by a responsible official with each report which states that, based on information 

and belief formed after reasonable inquiry, the statements and information in the report are true, accurate, 

and complete. 

b. Submitting, within 30 days following the end of a calendar month during which one or more prompt reports 

of deviations from the emissions allowed under the ROP were submitted to the department pursuant to 

Rule 213(3)(c)(ii), a certification by a responsible official which states that, “based on information and belief 

formed after reasonable inquiry, the statements and information contained in each of the reports submitted 

during the previous month were true, accurate, and complete”. The certification shall include a listing of the 

reports that are being certified. Any report submitted pursuant to Rule 213(3)(c)(ii) that will be certified on a 

monthly basis pursuant to this paragraph shall include a statement that certification of the report will be 

provided within 30 days following the end of the calendar month. 

23. Semiannually for the term of the ROP as detailed in the special conditions, or more frequently if specified, the 

permittee shall submit certified reports of any required monitoring to the appropriate AQD District Office. All 

instances of deviations from ROP requirements during the reporting period shall be clearly identified in the 

reports. (R 336.1213(3)(c)(i))

24. On an annual basis, the permittee shall report the actual emissions, or the information necessary to determine 

the actual emissions, of each regulated air pollutant as defined in Rule 212(6) for each emission unit utilizing 

the emissions inventory forms provided by the department. (R 336.1212(6))

25. The permittee shall provide notice of an abnormal condition, start-up, shutdown, or malfunction that results in 

emissions of a hazardous or toxic air pollutant which continue for more than one hour in excess of any applicable 

standard or limitation, or emissions of any air contaminant continuing for more than two hours in excess of an 

applicable standard or limitation, as required in Rule 912, to the appropriate AQD District Office. The notice shall 

be provided not later than two business days after the start-up, shutdown, or discovery of the abnormal conditions 

or malfunction. Notice shall be by any reasonable means, including electronic, telephonic, or oral communication. 

Written reports, if required under Rule 912, must be submitted to the appropriate AQD District Supervisor within 10 

days after the start-up or shutdown occurred, within 10 days after the abnormal conditions or malfunction has been 

corrected, or within 30 days of discovery of the abnormal conditions or malfunction, whichever is first. The written 

reports shall include all of the information required in Rule 912(5) and shall be certified by a responsible official in a 

manner consistent with the CAA. (R 336.1912)

Permit Shield 

26. Compliance with the conditions of the ROP shall be considered compliance with any applicable requirements 

as of the date of ROP issuance, if either of the following provisions is satisfied. (R 336.1213(6)(a)(i), 

R 336.1213(6)(a)(ii))

a. The applicable requirements are included and are specifically identified in the ROP. 

b. The permit includes a determination or concise summary of the determination by the department that other 

specifically identified requirements are not applicable to the stationary source. 

Any requirements identified in Part E of this ROP have been identified as non-applicable to this ROP and are 

included in the permit shield. 

27. Nothing in this ROP shall alter or affect any of the following: 

a. The provisions of Section 303 of the CAA, emergency orders, including the authority of the USEPA under 

Section 303 of the CAA. (R 336.1213(6)(b)(i))

b. The liability of the owner or operator of this source for any violation of applicable requirements prior to or at 

the time of this ROP issuance. (R 336.1213(6)(b)(ii))

c. The applicable requirements of the acid rain program, consistent with Section 408(a) of the CAA. 

(R 336.1213(6)(b)(iii)) 

d. The ability of the USEPA to obtain information from a source pursuant to Section 114 of the CAA. 

(R 336.1213(6)(b)(iv))
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28. The permit shield shall not apply to provisions incorporated into this ROP through procedures for any of the 

following: 

a. Operational flexibility changes made pursuant to Rule 215. (R 336.1215(5))

b. Administrative Amendments made pursuant to Rule 216(1)(a)(i)-(iv). (R 336.1216(1)(b)(iii))

c. Administrative Amendments made pursuant to Rule 216(1)(a)(v) until the amendment has been approved 

by the department. (R 336.1216(1)(c)(iii))

d. Minor Permit Modifications made pursuant to Rule 216(2). (R 336.1216(2)(f))

e. State-Only Modifications made pursuant to Rule 216(4) until the changes have been approved by the 

department. (R 336.1216(4)(e))

29. Expiration of this ROP results in the loss of the permit shield. If a timely and administratively complete 

application for renewal is submitted not more than 18 months, but not less than 6 months, before the expiration 

date of the ROP, but the department fails to take final action before the end of the ROP term, the existing ROP 

does not expire until the renewal is issued or denied, and the permit shield shall extend beyond the original 

ROP term until the department takes final action. (R 336.1217(1)(c), R 336.1217(1)(a))

Revisions 

30. For changes to any process or process equipment covered by this ROP that do not require a revision of the 

ROP pursuant to Rule 216, the permittee must comply with Rule 215. (R 336.1215, R 336.1216)

31. A change in ownership or operational control of a stationary source covered by this ROP shall be made pursuant to 

Rule 216(1). (R 336.1219(2))

32. For revisions to this ROP, an administratively complete application shall be considered timely if it is received by 

the department in accordance with the time frames specified in Rule 216. (R 336.1210(9))

33. Pursuant to Rule 216(1)(b)(iii), Rule 216(2)(d) and Rule 216(4)(d), after a change has been made, and until the 

department takes final action, the permittee shall comply with both the applicable requirements governing the 

change and the ROP terms and conditions proposed in the application for the modification. During this time 

period, the permittee may choose to not comply with the existing ROP terms and conditions that the application 

seeks to change. However, if the permittee fails to comply with the ROP terms and conditions proposed in the 

application during this time period, the terms and conditions in the ROP are enforceable. (R 336.1216(1)(c)(iii), 

R 336.1216(2)(d), R 336.1216(4)(d))

Reopenings 

34. A ROP shall be reopened by the department prior to the expiration date and revised by the department under 

any of the following circumstances: 

a. If additional requirements become applicable to this stationary source with three or more years remaining in 

the term of the ROP, but not if the effective date of the new applicable requirement is later than the ROP 

expiration date. (R 336.1217(2)(a)(i))

b. If additional requirements pursuant to Title IV of the CAA become applicable to this stationary source. 

(R 336.1217(2)(a)(ii))

c. If the department determines that the ROP contains a material mistake, information required by any 

applicable requirement was omitted, or inaccurate statements were made in establishing emission limits or 

the terms or conditions of the ROP. (R 336.1217(2)(a)(iii))

d. If the department determines that the ROP must be revised to ensure compliance with the applicable 

requirements. (R 336.1217(2)(a)(iv))
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Renewals 

35. For renewal of this ROP, an administratively complete application shall be considered timely if it is received by 

the department not more than 18 months, but not less than 6 months, before the expiration date of the ROP. 

(R 336.1210(7))

Stratospheric Ozone Protection 

36. If the permittee is subject to Title 40 of the Code of Federal Regulations (CFR), Part 82 and services, 

maintains, or repairs appliances except for motor vehicle air conditioners (MVAC), or disposes of appliances 

containing refrigerant, including MVAC and small appliances, or if the permittee is a refrigerant reclaimer, 

appliance owner or a manufacturer of appliances or recycling and recovery equipment, the permittee shall 

comply with all applicable standards for recycling and emissions reduction pursuant to 40 CFR, Part 82, 

Subpart F. 

37. If the permittee is subject to 40 CFR, Part 82, and performs a service on motor (fleet) vehicles when this 

service involves refrigerant in the MVAC, the permittee is subject to all the applicable requirements as specified 

in 40 CFR, Part 82, Subpart B, Servicing of Motor Vehicle Air Conditioners. The term “motor vehicle” as used 

in Subpart B does not include a vehicle in which final assembly of the vehicle has not been completed by the 

original equipment manufacturer. The term MVAC as used in Subpart B does not include the air-tight sealed 

refrigeration system used for refrigerated cargo or an air conditioning system on passenger buses using 

Hydrochlorofluorocarbon-22 refrigerant. 

Risk Management Plan 

38. If subject to Section 112(r) of the CAA and 40 CFR, Part 68, the permittee shall register and submit to the 

USEPA the required data related to the risk management plan for reducing the probability of accidental 

releases of any regulated substances listed pursuant to Section 112(r)(3) of the CAA as amended in 40 CFR, 

Part 68.130. The list of substances, threshold quantities, and accident prevention regulations promulgated 

under 40 CFR, Part 68, do not limit in any way the general duty provisions under Section 112(r)(1). 

39. If subject to Section 112(r) of the CAA and 40 CFR, Part 68, the permittee shall comply with the requirements 

of 40 CFR, Part 68, no later than the latest of the following dates as provided in 40 CFR, Part 68.10(a): 

a. June 21, 1999, 

b. Three years after the date on which a regulated substance is first listed under 40 CFR, Part 68.130, or 

c. The date on which a regulated substance is first present above a threshold quantity in a process. 

40. If subject to Section 112(r) of the CAA and 40 CFR, Part 68, the permittee shall submit any additional relevant 

information requested by any regulatory agency necessary to ensure compliance with the requirements of 

40 CFR, Part 68. 

41. If subject to Section 112(r) of the CAA and 40 CFR, Part 68, the permittee shall annually certify compliance with 

all applicable requirements of Section 112(r) as detailed in Rule 213(4)(c)). (40 CFR, Part 68)

Emission Trading 

42. Emission averaging and emission reduction credit trading are allowed pursuant to any applicable interstate or 

regional emission trading program that has been approved by the Administrator of the USEPA as a part of 

Michigan’s State Implementation Plan. Such activities must comply with Rule 215 and Rule 216. 

(R 336.1213(12))
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Permit To Install (PTI) 

43. The process or process equipment included in this permit shall not be reconstructed, relocated, or modified 

unless a PTI authorizing such action is issued by the department, except to the extent such action is exempt 

from the PTI requirements by any applicable rule.2

 (R 336.1201(1)) 

44. The department may, after notice and opportunity for a hearing, revoke PTI terms or conditions if evidence 

indicates the process or process equipment is not performing in accordance with the terms and conditions of 

the PTI or is violating the department’s rules or the CAA.2

 (R 336.1201(8), Section 5510 of Act 451) 

45. The terms and conditions of a PTI shall apply to any person or legal entity that now or hereafter owns or 

operates the process or process equipment at the location authorized by the PTI. If a new owner or operator 

submits a written request to the department pursuant to Rule 219 and the department approves the request, 

this PTI will be amended to reflect the change of ownership or operational control. The request must include all 

of the information required by Subrules (1)(a), (b) and (c) of Rule 219. The written request shall be sent to the 

appropriate AQD District Supervisor, MDEQ.2

 (R 336.1219) 

46. If the installation, reconstruction, relocation, or modification of the equipment for which PTI terms and 

conditions have been approved has not commenced within 18 months, or has been interrupted for 18 months, 

the applicable terms and conditions from that PTI shall become void unless otherwise authorized by the 

department. Furthermore, the person to whom that PTI was issued, or the designated authorized agent, shall 

notify the department via the Supervisor, Permit Section, MDEQ, AQD, P. O. Box 30260, Lansing, Michigan 

48909, if it is decided not to pursue the installation, reconstruction, relocation, or modification of the equipment 

allowed by the terms and conditions from that PTI.2

 (R 336.1201(4)) 

Footnotes: 

1

This condition is state only enforceable and was established pursuant to Rule 201(1)(b). 2

This condition is federally enforceable and was established pursuant to Rule 201(1)(a). 

B. SOURCE-WIDE CONDITIONS 

Part B outlines the Source-Wide Terms and Conditions that apply to this stationary source. The permittee is 

subject to these special conditions for the stationary source in addition to the general conditions in Part A and any 

other terms and conditions contained in this ROP. 

The permittee shall comply with all specific details in the special conditions and the underlying applicable 

requirements cited. If a specific condition type does not apply to this source, N/A (not applicable) has been used in 

the table. If there are no Source-Wide Conditions, this section will be left blank. 
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C. EMISSION UNIT CONDITIONS 

Part C outlines terms and conditions that are specific to individual emission units listed in the Emission Unit 

Summary Table. The permittee is subject to the special conditions for each emission unit in addition to the General 

Conditions in Part A and any other terms and conditions contained in this ROP. 

The permittee shall comply with all specific details in the special conditions and the underlying applicable 

requirements cited. If a specific condition type does not apply, N/A (not applicable) has been used in the table. If 

there are no conditions specific to individual emission units, this section will be left blank. 

EMISSION UNIT SUMMARY TABLE 

The descriptions provided below are for informational purposes and do not constitute enforceable conditions.

Emission 

Unit ID 

Emission Unit Description 

(Including Process Equipment & Control 

Device(s)) 

Control Device 

Installation 

Date/ 

Modification 

Date 

Flexible 

Group ID 

EUCOPE The Copeland Reactor is a chemical 

recovery furnace rated at 131 million 

BTU/hour; the Emission Unit includes a 

Chemical Recovery Storage Tank and a 

dissolving tank. 

Cyclone, Venturi Scrubber, 

Packed Column Scrubber, 

Dissolving Tank Baghouse, 

Regenerative Thermal 

Oxidizer. 

12/01/1989 

01/01/1990 

6/2009 

N/A 

EURB1 The No. 1 Riley Boiler is rated for 375 

million BTU/hour and is capable of firing 

coal, wood, natural gas, No. 2 thru No. 6 

fuel oil and noncondensible gases (NCGs) 

in compliance with 40 CFR 63 Subpart S. 

Electro Static Precipitator, 

Cyclone. 

01/01/1965 

01/01/1983 

N/A 

EUFA1 An Ash Silo used to collect ash from the 

burning of coal or wood in the No. 1 Riley 

boiler. 

Baghouse. 01/01/1965 

01/01/1983 

N/A 

EUPB2A The No. 2A package boiler is rated for 136 

million BTUs/hour and is fired by natural 

gas with backup by No. 2 thru No. 6 fuel 

oil. It is also capable of incinerating NCGs 

in compliance with 40 CFR 63 Subpart S. 

 06/30/1986 N/A 

EUPB3 The No. 3 package boiler is rated at 136 

million BTU/hour and is fired by natural gas 

with backup by No. 2 thru No. 6 fuel oil. It 

is also capable of incinerating NCGs in 

compliance with 40 CFR 63 Subpart S. 

 06/01/1978 N/A 

EUPB4 The No. 4 package boiler, rated for 65 

million BTU/hour, is fired by natural gas. It 

is also capable of incinerating NCGs in 

compliance with 40 CFR 63 Subpart S. 

 06/01/1989 N/A 
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EUCOPE 

EMISSION UNIT CONDITIONS

DESCRIPTION: The Copeland Reactor is a chemical recovery furnace rated at 131 million BTUs per 

hour heat input. Emission controls are by a cyclone, venturi scrubber, packed tower scrubber and a 

Regenerative Thermal Oxidizer (RTO).

POLLUTION CONTROL EQUIPMENT: Cyclone, venturi scrubber, packed tower scrubber and a 

regenerative thermal oxidizer. 

I. EMISSION LIMIT(S)

Pollutant Limit 

Time Period/ 

Operating 

Scenario 

Equipment Monitoring/ 

Testing Method 

Underlying 

Applicable 

Requirements

1. Particulate 

matter (PM) 

16 lbs/hour2 Per hour limit based 

on 3 hour average.

EUCOPE V.1 R 336.1331, 

40 CFR 52.21 

2. Sulfur Dioxide 

(SO2) 

a. 2.62 lbs/hour2

 EUCOPE V.1 R 336.1402(2), 

40 CFR 52.21 

b. Less than 0.02 lbs 

per MM BTUs heat 

input2

24 hour average. EUCOPE V.1 R 336.1201(3), 

40 CFR 52.21 

3. Nitrogen 

Oxides (NOx) 

a. Less than 2.62 lbs 

per hour when 

controlled by the 

cyclone, venturi 

scrubber and packed 

tower scrubber2

Per hour. EUCOPE V.1 R366.1201(3), 

40 CFR 52.21 

b. Less than 0.02 lbs 

per million BTUs heat 

input when controlled 

by the cyclone, 

venturi scrubber and 

packed tower 

scrubber2

24 hour average EUCOPE V.1 R 336.1201(3), 

40 CFR 52.21 

c. Less than 63.0 lbs 

per hour when 

controlled by the 

cyclone, venturi 

scrubber, packed 

tower scrubber 

followed by the RTO2

24 hour average EUCOPE V.1 R 336.1201(3), 

40 CFR 52.21 

4. Carbon 

Monoxide (CO) 

Less than 157.0 lbs per 

hour when controlled by 

the cyclone, venturi 

scrubber, packed tower 

scrubber followed by 

the RTO2

24 hour average EUCOPE V.1 R 336.1201(3), 

40 CFR 52.21 
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II. MATERIAL LIMIT(S) N/A 

III. PROCESS/OPERATIONAL RESTRICTION(S) 

1. Permittee shall operate the Copeland reactor in accordance with a malfunction abatement plan to prevent, 

detect, and correct malfunctions or equipment failures resulting in emissions exceeding any applicable 

emission limitations. (R 336.1911)1

IV. DESIGN/EQUIPMENT PARAMETER(S)

1. Permittee shall equip and maintain each scrubber with a liquid flow indicator. (R 336.1201(3), R 336.1910)1

2. Permittee shall not operate the Copeland reactor unless the cyclone, venture scrubber, and packed tower 

scrubber, are installed and operating properly. (R 336.1201(3), R 336.1910, 40 CFR 52.21, 40 CFR 63 

Subpart MM)2

V. TESTING/SAMPLING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. The permittee shall conduct stack testing of the Copeland/RTO, at the owner’s expense, to verify compliance 

with the CO, PM, NOx, SO2, RTO (VOC/HAP) destruction efficiency, and Gaseous organic HAPs. Testing shall 

be within the five year life of this permit and in accordance with Department requirements. A complete and 

acceptable test plan must be submitted 30 days prior to the test and approved prior to testing. See IX 5. 

(R 336.1201(3)) 

2. Acceptable performance testing shall be conducted by the permittee in accordance with R 336.2003. 

(R 336.2003, R 336.2004) 

VI. MONITORING/RECORDKEEPING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))]

1. Permittee shall maintain records of the emission rates of PM, SO2, and NOx from the Copeland reactor to 

demonstrate compliance with the pounds per hour and tons per year emission rates. (R 336.1201(3))

VII. REPORTING

1. Prompt reporting of deviations pursuant to General Conditions 21 and 22 of Part A. (R 336.1213(3)(c)(ii))

2. Semiannual reporting of monitoring and deviations pursuant to General Condition 23 of Part A. The report shall 

be postmarked or received by the appropriate AQD District Office by March 15 for reporting period July 1 to 

December 31 and September 15 for reporting period January 1 to June 30. (R 336.1213(3)(c)(i))

3. Annual certification of compliance pursuant to General Conditions 19 and 20 of Part A. The report shall be 

postmarked or received by the appropriate AQD District Office by March 15 for the previous calendar year. 

(R 336.1213(4)(c))

See Appendix 8 
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VIII. STACK/VENT RESTRICTION(S)

The exhaust gases from the stacks listed in the table below shall be discharged unobstructed vertically upwards to 

the ambient air unless otherwise noted: 

Stack & Vent ID Maximum Exhaust 

Dimensions (inches) 

Minimum Height 

Above Ground (feet) 

Underlying Applicable 

Requirements 

1.SVCR-9S 60 144 R 336.1201(3)1

2.SVPSG-10S 76 144 R 336.1201(3)1

IX. OTHER REQUIREMENT(S)

1. Permittee shall ensure that the HAP emissions from the RTO as measured by total hydrocarbons reported as 

carbon, are reduced by at least 90 percent prior to discharge. (R 336.1201(3), 40 CFR 63.862(c)(2)(ii)) 

2. Permittee shall established an RTO operating temperature range as specified in 40 CFR 63.864(j) and operate 

the RTO within that range per 40 CFR 63.864(k). Permittee shall monitor and record the RTO operating 

temperature in a continuous basis and with instrumentation acceptable to the AQD. (R 336.1201(3), 

R 336.1910, 40 CFR 63.864(j) & (k)) 

3. The permittee shall comply with the general monitoring requirements under 40 CFR Section 63.864(a); and the 

on-going compliance provisions of 40 CFR Section 63.864 (k)(1)(iii). (R 336.1910, 40 CFR 63.864(a)) 

4. The permittee shall comply with the applicable recordkeeping requirements specified in 40 CFR Section 

63.866(a)-(c)(1) and (c)(3)-(5) and the reporting requirements under 40 CFR Section 63.867(a), (b)(3)(i), 

(b)(3)(iii) and (c). (R 336.1201(3), 40 CFR 63.866(a)-(c)(1), (c)(3)-(5), 40 CFR 63.867(a)(b)(3)(i) & (iii) and (c)) 

5. The RTO efficiency test methods and procedures shall use Method 25A in appendix A of 40 CFR Part 60 as 

well as paragraphs (b)(5)(i)-(iv) of 40 CFR Part 63 Subpart MM Section 63.865. (R 336.1201(3), 40 CFR 60 

Appendix A, 40 CFR 63.865) 

6. The permittee shall not use any fuel other than natural gas or charcoal for start up of the Copeland reactor. 

(R 336.1201(3), 40 CFR 52.21) 

7. The permittee shall not use any fuel other than natural gas and ultra low sulfur diesel oil as an auxiliary fuel in 

the Copeland reactor. (R 336.1201(3), 40 CFR 52.21) 

Footnotes: 

1

This condition is state only enforceable and was established pursuant to Rule 201(1)(b). 2

This condition is federally enforceable and was established pursuant to Rule 201(1)(a). 
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EURB1

EMISSION UNIT CONDITIONS

DESCRIPTION: The number 1 Riley Boiler, rated at 375 million BTU per hour, is capable of firing coal, 

wood, natural gas, and No. 2 through No. 6 fuel oil. The boiler is also capable of incinerating 

noncondensible gases (NCGs) in compliance with 40 CFR 63 Subpart S. 

POLLUTION CONTROL EQUIPMENT: Particulate matter is controlled by a cyclone and an electrostatic 

precipitator. 

I. EMISSION LIMIT(S)

Pollutant Limit 

Time Period/ 

Operating 

Scenario 

Equipment Monitoring/ 

Testing Method 

Underlying 

Applicable 

Requirements

1. SO2 a. The SO2 emission rate while 

firing coal in the Riley Boiler 

shall not exceed 2.50 

pounds per million BTUs 

heat input.2

24 hours Riley Boiler V.1 R 336.1402 

b. The SO2 emission rate while 

firing coal in the Riley Boiler 

may be measured as usage 

of coal with a sulfur content 

not exceeding 1.5 % at a 

heat value of 12,000 BTUs 

per pound of coal2

N/A Riley Boiler V.1 R 336.1402 

c. The maximum sulfur content 

of fuel oil fired in the Riley 

Boiler shall not exceed 1.5% 

based on a heat value of 

18,000 BTUs per pound of 

oil.2

N/A Riley Boiler V.1 R 336.1201(3) 

2. NOx Nitrogen oxides emissions 

shall not exceed 0.95 pounds 

per million BTU heat input 

averaged over the ozone 

control period. Total NOx 

emissions shall not exceed 350 

pounds per hour.1

Ozone control 

period average 

(May 1 through 

September 30) 

Riley Boiler V.2 R 336.1801(8) 

3. PM The particulate emission from 

the Riley Boiler shall not 

exceed 0.25 pounds per 1,000 

pounds of exhaust gases, 

corrected to 50% excess air.2

N/A Riley Boiler V.1 R 336.1330, 

R 336.1331 

II. MATERIAL LIMIT(S) N/A 
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 18 of 32 

III. PROCESS/OPERATIONAL RESTRICTION(S) 

1. Upon initiation of collector bypass, the input feed (excluding natural gas) to the Riley boiler shall cease 

immediately, consistent with safe operating procedures. Coal, oil, and or wood feed to the Riley boiler shall not 

restart until the collector is back on line and functioning properly. (R 336.1301, R 336.1331)2

2. The blow tank and evaporator systems shall be enclosed and vented into a closed vent system and routed to 

the No. 1 Riley boiler, or other onsite boiler capable of incinerating NCGs, and the permittee shall comply with 

the compliance date under 40 CFR 63.440(d) and the applicable requirements under 40 CFR 63.443 (d) and 

(e)(1). The enclosures and closed vent system shall meet the applicable requirements specified in 40 CFR 

63.450. (40 CFR 63, Subpart S)2

IV. DESIGN/EQUIPMENT PARAMETER(S) N/A 

V. TESTING/SAMPLING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. Permittee shall conduct a performance stack testing of the boiler to verify PM emission rates from the Riley 

boiler during the five year life of this ROP. Test method as specified in 40 CFR 63, Subpart S. (R 336.1201(3), 

R 336.2001; 40 CFR 63, Subpart S; 40 CFR 60 Appendix A)2

2. Permittee shall measure nitrogen oxides emissions from Riley Boiler by any of the following. (R 336.1801(8))

a. Performance tests described in Rule 801(9). 

b. Through the use of continuous emission monitoring in accordance with the provisions of Rule 801(11). 

c. According to a schedule and method acceptable to the department. 

3. The permittee shall obtain and keep records of the sulfur, ash, and BTU content of the coal burned in No. 1 

Riley Boiler, as detailed in Appendix 4. (R 336.1201(3))2 

See Appendix 4 

VI. MONITORING/RECORDKEEPING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. The permittee shall operate the continuous opacity monitoring system on the duct serving No. 1 Riley Boiler. 

The permittee shall keep records of the opacity on a continuous basis and with instrumentation acceptable to 

the Air Quality Division. (R 336.1201(3))

2. The continuous opacity monitoring system shall comply with 40 CFR Part 60 Appendix B, Performance 

Specification 1. (R 336.2150)

3. The continuous opacity monitoring system shall comply with the cycling time requirements specified in Rule 

1152. (R 336.2152)

4. The continuous opacity monitoring system shall comply with the zero and drift requirements specified in Rule 

1153. (R 336.2153)

5. The continuous opacity monitoring system shall comply with the instrument span requirements specified in Rule 

1154. (R 336.2154)

6. The continuous opacity monitoring system shall comply with the monitor location requirements specified in Rule 

1155. (R 336.2155)
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 19 of 32 

VII. REPORTING

1. Prompt reporting of deviations pursuant to General Conditions 21 and 22 of Part A. (R 336.1213(3)(c)(ii)) 

2. Within 60 days after the end of the ozone control period, the permittee shall submit a summary report in an 

acceptable format to the Air Quality Division to include all of the information specified in rule 801(12).1

 

(R 336.1801(12)) 

3. Semiannual reporting of monitoring and deviations pursuant to General Condition 23 of Part A. The report shall 

be postmarked or received by the appropriate AQD District Office by March 15 for reporting period July 1 to 

December 31 and September 15 for reporting period January 1 to June 30. (R 336.1213(3)(c)(i)) 

4. Annual certification of compliance pursuant to General Conditions 19 and 20 of Part A. The report shall be 

postmarked or received by the appropriate AQD District Office by March 15 for the previous calendar year. 

(R 336.1213(4)(c)) 

See Appendix 8 

VIII. STACK/VENT RESTRICTION(S)

The exhaust gases from the stacks listed in the table below shall be discharged unobstructed vertically upwards to 

the ambient air unless otherwise noted: 

Stack & Vent ID Maximum Exhaust 

Dimensions (inches) 

Minimum Height 

Above Ground (feet) 

Underlying Applicable 

Requirements 

1.SVPSG-7S 120 195 R 336.1201(3)1

IX. OTHER REQUIREMENT(S) N/A

Footnotes: 

1

This condition is state only enforceable and was established pursuant to Rule 201(1)(b). 2

This condition is federally enforceable and was established pursuant to Rule 201(1)(a). 
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 20 of 32 

EUFA1

EMISSION UNIT CONDITIONS

DESCRIPTION: Ash silo, used to collect ash from the burning of coal and/or wood in the No. 1 Riley 

boiler. 

POLLUTION CONTROL EQUIPMENT

I. EMISSION LIMIT(S)

Pollutant Limit 

Time Period/ 

Operating 

Scenario 

Equipment Monitoring/ 

Testing Method 

Underlying 

Applicable 

Requirements

1. PM Emission from the fly 

ash silo shall not 

exceed 0.10 pounds 

per 1,000 lbs. of 

exhaust gases, 

calculated on a dry 

gas basis2

Test Protocol Ash Silo N/A R 336.1331 

II. MATERIAL LIMIT(S) N/A

III. PROCESS/OPERATIONAL RESTRICTION(S: N/A 

IV. DESIGN/EQUIPMENT PARAMETER(S) N/A 

V. TESTING/SAMPLING N/A 

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

VI. MONITORING/RECORDKEEPING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. Permittee shall keep records of Fugitive Dust Control Program specified in IX below. (R 336.1213(3))

VII. REPORTING

1. Prompt reporting of deviations pursuant to General Conditions 21 and 22 of Part A. (R 336.1213(3)(c)(ii)) 

2. Semiannual reporting of monitoring and deviations pursuant to General Condition 23 of Part A. The report shall 

be postmarked or received by the appropriate AQD District Office by March 15 for reporting period July 1 to 

December 31 and September 15 for reporting period January 1 to June 30. (R 336.1213(3)(c)(i)) 

3. Annual certification of compliance pursuant to General Conditions 19 and 20 of Part A. The report shall be 

postmarked or received by the appropriate AQD District Office by March 15 for the previous calendar year. 

(R 336.1213(4)(c))

See Appendix 8 
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 21 of 32 

VIII. STACK/VENT RESTRICTION(S)

The exhaust gases from the stacks listed in the table below shall be discharged unobstructed vertically upwards to 

the ambient air unless otherwise noted: 

Stack & Vent ID Maximum Exhaust 

Dimensions (inches) 

Minimum Height 

Above Ground (feet) 

Underlying Applicable 

Requirements 

1.SVPSG-8S N/A N/A N/A 

IX. OTHER REQUIREMENT(S)

1. The permittee shall establish and implement a Fugitive Dust Control Program, which will include keeping a log 

for recording inspections, problems identified, repairs and/or corrective actions taken, and scheduled and 

completed maintenance to enclosures or other dust control or suppression mechanisms. The log shall also 

include observations of the Ash Handling and Storage activities and other actions taken to control fugitive dust. 

(R 336.1213(3), R 336.1370)

Footnotes: 

1

This condition is state only enforceable and was established pursuant to Rule 201(1)(b). 2

This condition is federally enforceable and was established pursuant to Rule 201(1)(a). 
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 22 of 32 

EUPB2A

EMISSION UNIT CONDITIONS

DESCRIPTION: The No. 2A package boiler is rated at 136 million BTUs per hour and is fired by natural 

gas with No. 2 through No. 6 fuel oils as back up. The boiler is capable of incinerating noncondensible 

gases in compliance with 40 CFR 63, Subpart S. 

Flexible Group ID: N/A 

POLLUTION CONTROL EQUIPMENT N/A 

I. EMISSION LIMIT(S)

Pollutant Limit Time Period/ 

Operating Scenario Equipment 

Monitoring/ 

Testing 

Method 

Underlying 

Applicable 

Requirements 

1. SO2 a. SO2 emissions shall 

not exceed 1.67 lbs. 

per billion BTUs heat 

input2

Per 24 hour 

period. 

# 2A Package 

Boiler 

Test Protocol R 336.1401, 

Table 42 

 b. SO2 emissions shall 

not exceed117 tons2

Per year # 2A Package 

Boiler 

Test Protocol R 336.1201(3) 

c. The maximum sulfur 

content of oil fired in 

the No. 2A boiler shall 

not exceed 1.5 

percent2

Percent sulfur 

based on heat 

value of 18,000 

BTUs per lb. of oil. 

# 2A Package 

Boiler 

Test Protocol R 336.1201(3) 

2. NOx a. NOx emissions shall 

not exceed 74.8 lbs 

per hour # 2A Package 

Boiler 

Test Protocol R 336.1201(3) 

AP-42 

b. NOx emissions shall 

not exceed 150 tons 

per year # 2A Package 

Boiler 

Test Protocol R 336.1201(3) 

AP-42 

3. PM Visible emissions from 

the boiler shall not 

exceed a 6 minute 

average of 20% opacity 

while burning No. 2 

through No. 6 fuel oil, 

except as specified in 

Rule 336.1301(1)(a)2

 # 2A Package 

Boiler 

R 336.1301(1)(a),

R 336.1303 

II. MATERIAL LIMIT(S)

Material Limit Equipment 

Underlying 

Applicable 

Requirements 

1. Fuel Oil Permittee shall not burn more than 990,000 gallons

of No. 6 fuel oil per year. 

# 2A Package Boiler R 336.1201(3), 

40 CFR 52.21 
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 23 of 32 

Material Limit Equipment 

Underlying 

Applicable 

Requirements 

2. Natural Gas Permittee shall not burn more than 545.4 million

cubic feet of natural gas per year, except when No.

6 fuel oil is used in the 2A package boiler, the

maximum allowed natural gas usage shall be 

reduced by applying the following equation:

(545.4 – 0.122G) million cubic feet of natural gas

per year, where G is No. 6 fuel oil usage in

thousands of gallons. 

# 2A Package Boiler R 336.1201(3), 

40 CFR 52.21 

III. PROCESS/OPERATIONAL RESTRICTION(S) N/A 

IV. DESIGN/EQUIPMENT PARAMETER(S) N/A 

V. TESTING/SAMPLING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. Permittee shall conduct performance stack testing of one package boiler (Package Boiler # 2A, #3, or #4) to 

determine compliance with the NOx emission limitations within five years of issuance of this ROP. The 

package boiler tested and the test method shall be approved by the Department. (R 336.1213(3), R 336.2001) 

2. Visible observation of the boiler emissions shall be conducted as specified in the Inspection and Maintenance 

Program. (R 336.1301, R 336.1303)

See Appendix 5 

VI. MONITORING/RECORDKEEPING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. Records shall be kept in accordance with the Inspection and Maintenance Program, specified in IX. The 

records shall include but not be limited to, records of inspections, problems identified, repairs and or corrective 

action taken, scheduled and completed maintenance, and records of visual observations to assure compliance 

with Rule 336.1301 and Rule 336.1901. (R 336.1213(3), R 336.1301(1)(a), R 336.1303)

VII. REPORTING

1. Prompt reporting of deviations pursuant to General Conditions 21 and 22 of Part A. (R 336.1213(3)(c)(ii)) 

2. Semiannual reporting of monitoring and deviations pursuant to General Condition 23 of Part A. The report shall 

be postmarked or received by the appropriate AQD District Office by March 15 for reporting period July 1 to 

December 31 and September 15 for reporting period January 1 to June 30. (R 336.1213(3)(c)(i)) 

3. The Permittee shall submit quarterly reports of fuel usage pursuant to Condition 23 of Part A. The report shall 

be postmarked or received by the appropriate AQD District Office by June 15 for the January 1 to March 31 

reporting period, and by September 15 for the April 1 to June 30 reporting period, December 15 for the July 1 to 

September 30 reporting period, and March 15 for the October 1 to December 31 reporting period. 

(R 336.1213(3)(c)(i)) 
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Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 24 of 32 

4. Annual certification of compliance pursuant to General Conditions 19 and 20 of Part A. The report shall be 

postmarked or received by the appropriate AQD District Office by March 15 for the previous calendar year. 

(R 336.1213(4)(c)) 

See Appendix 8 

VIII. STACK/VENT RESTRICTION(S)

The exhaust gases from the stacks listed in the table below shall be discharged unobstructed vertically upwards to 

the ambient air unless otherwise noted: 

Stack & Vent ID Maximum Exhaust 

Dimensions (inches) 

Minimum Height 

Above Ground (feet)

Underlying Applicable 

Requirements 

1.SVPSG-91011S 55 195 R 336.1201(3)1

IX. OTHER REQUIREMENT(S)

1. The permittee shall carry out an Inspection and Maintenance Program for the No. 2A Package boiler, including 

keeping a log, to assure that the process equipment is maintained and operated in a satisfactory manner and in 

accordance with the Michigan Air Pollution Control Rules and existing law. (R 336.1301, R 336.1331) 

Footnotes: 

1

This condition is state only enforceable and was established pursuant to Rule 201(1)(b). 2

This condition is federally enforceable and was established pursuant to Rule 201(1)(a). 
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 25 of 32 

EUPB3

EMISSION UNIT CONDITIONS

DESCRIPTION: The number 3 package boiler, rated at 136 million BTUs per hour, is fired by natural gas 

with No. 2 through No. 6 fuel oil back up. The boiler is also capable of incinerating noncondensible 

gases (NCGs) in compliance with 40 CFR 63 Subpart S. 

POLLUTION CONTROL EQUIPMENT

I. EMISSION LIMIT(S)

Pollutant Limit Time Period/ 

Operating Scenario Equipment Monitoring/ Testing Method 

Underlying 

Applicable 

Requirements

1. SO2 SO2 emissions shall not 

exceed 1.67 pounds per 

million BTUs heat input2

Per 24 hour period No. 3 boiler Test Protocol R 336.1401 

II. MATERIAL LIMIT(S)

Material Limit Time Period/ 

Operating Scenario Equipment Monitoring/ Testing Method 

Underlying 

Applicable 

Requirements

1. No. 2 through 

No. 6 fuel oil 

The maximum sulfur 

content of oil fired in the 

No. 3 boiler shall not 

exceed 1.5 %, based on 

a heating value of 

18,000 BTUs per pound 

of oil2

N/A No. 3 boiler Test protocol R 336.1201(3) 

III. PROCESS/OPERATIONAL RESTRICTION(S) N/A 

IV. DESIGN/EQUIPMENT PARAMETER(S) N/A 

V. TESTING/SAMPLING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

1. Permittee shall conduct performance stack testing of one package boiler (Package Boiler # 2A, #3, or #4) to 

determine compliance with the NOx emission limitations within five years of issuance of this ROP. The 

package boiler tested and the test method shall be approved by the Department. (R 336.1213(3), R 336.2001) 

2. Visible observations of the boiler emissions shall be conducted as specified in the Inspection and Maintenance 

Program. (R 336.1301, R 336.1303)

VI. MONITORING/RECORDKEEPING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 26 of 32 

1. On a monthly basis permittee shall record fuel usage rates and total SO2 emissions. The SO2 emissions may 

be calculated from the fuel usage. (R 336.1201(3)) 

2. Records shall be kept in accordance with the Inspection and Maintenance Program, specified in IX. The 

records shall include but not be limited to, records of inspections, problems identified, repairs and or corrective 

action taken, scheduled and completed maintenance, and records of visual observations to assure compliance 

with Rule 336.1301 and R 336.1901. (R 336.1213(3), R 336.1301(1)(a), R 336.1303) 

VII. REPORTING

1. Prompt reporting of deviations pursuant to General Conditions 21 and 22 of Part A. (R 336.1213(3)(c)(ii)) 

2. Semiannual reporting of monitoring and deviations pursuant to General Condition 23 of Part A. The report shall 

be postmarked or received by the appropriate AQD District Office by March 15 for reporting period July 1 to 

December 31 and September 15 for reporting period January 1 to June 30. (R 336.1213(3)(c)(i)) 

3. The Permittee shall submit quarterly reports of fuel usage pursuant to Condition 23 of Part A. The report shall 

be postmarked or received by the appropriate AQD District Office by June 15 for the January 1 to March 31 

reporting period, and by September 15 for the April 1 to June 30 reporting period, December 15 for the July 1 to 

September 30 reporting period, and March 15 for the October 1 to December 31 reporting period. 

(R 336.1213(3)(c)(i)) 

4. Annual certification of compliance pursuant to General Conditions 19 and 20 of Part A. The report shall be 

postmarked or received by the appropriate AQD District Office by March 15 for the previous calendar year. 

(R 336.1213(4)(c)) 

See Appendix 8 

VIII. STACK/VENT RESTRICTION(S)

The exhaust gases from the stacks listed in the table below shall be discharged unobstructed vertically upwards to 

the ambient air unless otherwise noted: 

Stack & Vent ID 

Maximum Exhaust 

Dimensions 

(inches) 

Minimum Height 

Above Ground 

(feet) 

Underlying Applicable 

Requirements 

1.SVPSG-91011S 55 195 R 336.1201(3)1

IX. OTHER REQUIREMENT(S)

1. The permittee shall carry out an Inspection and Maintenance Program for the No. 3 Package boiler, including 

keeping a log, to assure that the process equipment is maintained and operated in a satisfactory manner and in 

accordance with the Michigan Air Pollution Control Rules and existing law. (R 336.1301, R 336.1331) 

Footnotes: 

1

This condition is state only enforceable and was established pursuant to Rule 201(1)(b). 2

This condition is federally enforceable and was established pursuant to Rule 201(1)(a). 
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 27 of 32 

EUPB4

EMISSION UNIT CONDITIONS

DESCRIPTION: The number 4 package boiler, rated at 65 million BTUs per hour and 50,000 pounds of 

steam (at 250 psi.) per hour, is fired by natural gas. This boiler is also capable of incinerating 

noncondensible gases (NCGs) in compliance with 40 CFR 63 Subpart S. 

POLLUTION CONTROL EQUIPMENT N/A 

I. EMISSION LIMIT(S)

Pollutant Limit Time Period/ 

Operating Scenario Equipment Monitoring/ Testing Method 

Underlying 

Applicable 

Requirements

1. NOx a. NOx emissions when 

firing natural gas shall 

not exceed 0.14 lbs 

per million BTUs heat 

input 

Per 24 hour 

average 

No. 4 boiler Approved method 

per R 336.2004, 

may be 

calculated based 

on fuel use 

R 336.1201(3) 

b. Emissions shall not 

exceed 9.09 pounds 

Per hour No. 4 boiler Approved method 

per R 336.2004, 

may be 

calculated based 

on fuel use 

R 336.1201(3) 

II. MATERIAL LIMIT(S) N/A 

III. PROCESS/OPERATIONAL RESTRICTION(S)

1. Permittee shall not fire any fuel in the boiler other than sweet natural gas. R 336.1201(1) 

IV. DESIGN/EQUIPMENT PARAMETER(S) N/A 

V. TESTING/SAMPLING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. Permittee shall conduct performance stack testing of one package boiler (Package Boiler # 2A, #3, or #4) to 

determine compliance with the NOx emission limitations within five years of issuance of this ROP. The 

package boiler tested and the test method shall be approved by the Department. (R 336.1213(3), R 336.2001) 

2. Visible observation of the boiler emissions shall be conducted as specified in the Inspection and Maintenance 

Program. (R 336.1301, R 336.1303)

VI. MONITORING/RECORDKEEPING 

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

N/A 
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 28 of 32 

VII. REPORTING

1. Prompt reporting of deviations pursuant to General Conditions 21 and 22 of Part A. (R 336.1213(3)(c)(ii)) 

2. Semiannual reporting of monitoring and deviations pursuant to General Condition 23 of Part A. The report shall 

be postmarked or received by the appropriate AQD District Office by March 15 for reporting period July 1 to 

December 31 and September 15 for reporting period January 1 to June 30. (R 336.1213(3)(c)(i)) 

3. Annual certification of compliance pursuant to General Conditions 19 and 20 of Part A. The report shall be 

postmarked or received by the appropriate AQD District Office by March 15 for the previous calendar year. 

(R 336.1213(4)(c)) 

4. The Permittee shall submit quarterly reports of fuel usage pursuant to Condition 23 of Part A. The report shall 

be postmarked or received by the appropriate AQD District Office by June 15 for the January 1 to March 31 

reporting period, and by September 15 for the April 1 to June 30 reporting period, December 15 for the July 1 to 

September 30 reporting period, and March 15 for the October 1 to December 31 reporting period. 

(R 336.1213(3)(c)(i)) 

See Appendix 8 

VIII. STACK/VENT RESTRICTION(S)

The exhaust gases from the stacks listed in the table below shall be discharged unobstructed vertically upwards to 

the ambient air unless otherwise noted: 

Stack & Vent ID Maximum Exhaust 

Dimensions (inches) 

Minimum Height 

Above Ground (feet) 

Underlying Applicable 

Requirements 

1.SVPSG-91011S 55 195 R 336.1201(3)1

IX. OTHER REQUIREMENT(S)

1. The permittee shall carry out an Inspection and Maintenance Program for the No.4 Package boiler, including 

keeping a log, to assure that the process equipment is maintained and operated in a satisfactory manner and in 

accordance with the Michigan Air Pollution Control Rules and existing law. (R 336.1301, R 336.1331) 

Footnotes: 

1

This condition is state only enforceable and was established pursuant to Rule 201(1)(b). 2

This condition is federally enforceable and was established pursuant to Rule 201(1)(a). 
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 29 of 32 

D. FLEXIBLE GROUP CONDITIONS 

Part D outlines terms and conditions that apply to more than one emission unit. The permittee is subject to the 

special conditions for each flexible group in addition to the General Conditions in Part A and any other terms and 

conditions contained in this ROP. 

The permittee shall comply with all specific details in the special conditions and the underlying applicable 

requirements cited. If a specific condition type does not apply, N/A (not applicable) has been used in the table. If 

there are no special conditions that apply to more than one emission unit, this section will be left blank. 

E. NON-APPLICABLE REQUIREMENTS 

At the time of the ROP issuance, the AQD has determined that no non-applicable requirements have been 

identified for incorporation into the permit shield provision set forth in the General Conditions in Part A pursuant to 

Rule 213(6)(a)(ii). 
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 30 of 32 

APPENDICES

Appendix 1: Abbreviations and Acronyms 

The following is an alphabetical listing of abbreviations/acronyms that may be used in this permit. 

AQD Air Quality Division MM Million 

acfm Actual cubic feet per minute MSDS Material Safety Data Sheet 

BACT Best Available Control Technology MW Megawatts 

BTU British Thermal Unit N/A Not Applicable 

°C Degrees Celsius NAAQS National Ambient Air Quality Standards 

CAA Federal Clean Air Act NESHAP National Emission Standard for Hazardous Air 

Pollutants 

CAM Compliance Assurance Monitoring NMOC Non-methane Organic Compounds 

CEM Continuous Emission Monitoring NOx Oxides of Nitrogen 

CFR Code of Federal Regulations NSPS New Source Performance Standards 

CO Carbon Monoxide NSR New Source Review 

COM Continuous Opacity Monitoring PM Particulate Matter 

department Michigan Department of Environmental Quality PM-10 Particulate Matter less than 10 microns in 

diameter 

dscf Dry standard cubic foot pph Pound per hour 

dscm Dry standard cubic meter ppm Parts per million 

EPA United States Environmental Protection Agency ppmv Parts per million by volume 

EU Emission Unit ppmw Parts per million by weight 

°F Degrees Fahrenheit PS Performance Specification 

FG Flexible Group PSD Prevention of Significant Deterioration 

GACS Gallon of Applied Coating Solids psia Pounds per square inch absolute 

gr Grains psig Pounds per square inch gauge 

HAP Hazardous Air Pollutant PeTE Permanent Total Enclosure 

Hg Mercury PTI Permit to Install 

hr Hour RACT Reasonable Available Control Technology 

HP Horsepower ROP Renewable Operating Permit 

H2S Hydrogen Sulfide SC Special Condition 

HVLP High Volume Low Pressure * scf Standard cubic feet 

ID Identification (Number) sec Seconds 

IRSL Initial Risk Screening Level SCR Selective Catalytic Reduction 

ITSL Initial Threshold Screening Level SO2 Sulfur Dioxide 

LAER Lowest Achievable Emission Rate SRN State Registration Number 

lb Pound TAC Toxic Air Contaminant 

m Meter Temp Temperature 

MACT Maximum Achievable Control Technology THC Total Hydrocarbons 

MAERS Michigan Air Emissions Reporting System tpy Tons per year 

MAP Malfunction Abatement Plan μg Microgram 

MDEQ Michigan Department of Environmental Quality VE Visible Emissions 

mg Milligram VOC Volatile Organic Compounds 

mm Millimeter yr Year 

*For HVLP applicators, the pressure measured at the gun air cap shall not exceed 10 pounds per square inch gauge (psig). 
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 31 of 32 

Appendix 2. Schedule of Compliance 

The permittee certified in the ROP application that this stationary source is in compliance with all applicable 

requirements and the permittee shall continue to comply with all terms and conditions of this ROP. A Schedule of 

Compliance is not required. (R 336.1213(4)(a), R 336.1119(a)(ii))

Appendix 3. Monitoring Requirements 

Specific monitoring requirement procedures, methods or specifications are detailed in Part A or the appropriate 

Source-Wide, Emission Unit and/or Flexible Group Special Conditions. Therefore, this appendix is not applicable. 

Appendix 4. Recordkeeping 

The permittee shall use the following approved formats and procedures for the recordkeeping requirements 

referenced in EURB1Number 1 Riley Boiler. Alternative formats must be approved by the AQD District Supervisor. 

1. Coal Analysis 

 

a) For each coal shipment received, the permittee shall obtain from the coal supplier a laboratory analysis of the 

ash content, sulfur content, and the BTU content. The determination of sulfur content shall be carried out in 

accordance with one of the following procedures: ASTM Method 3177-75 or ASTM Method 4239-85 or an 

alternative method approved by the AQD District Supervisor. For each coal shipment received, the permittee 

shall record the date received, source of coal and shipper, and tons received. These records shall be retained 

by the permittee for a minimum of five years, and made available to the Air Quality Division upon request. 

b) At least once per calendar year, the permittee shall have an analysis performed of the coal ash content, sulfur 

content, and BTU content for one sample each of eastern coal and western coal. These analyses shall be 

independent of the analyses received from the coal supplier with each shipment. The determination of coal 

sulfur content shall be carried out in accordance with one of the following procedures: ASTM Method 3177-75 

or ASTM Method 4239-85 or an alternative method approved by the AQD District Supervisor. These records 

shall be retained by the permittee for a minimum of five years, and made available to the Air Quality Division 

upon request. 

Specific recordkeeping requirements, formats and procedures for the remaining emission units are detailed in Part 

A or the appropriate source-wide emission unit and/or flexible group special conditions. 

Appendix 5. Testing Procedures 

Specific testing requirement plans, procedures, and averaging times are detailed in the appropriate Source-Wide, 

Emission Unit and/or Flexible Group Special Conditions. Therefore, this appendix is not applicable. 

Appendix 6. Permits to Install 

The following table lists any PTIs issued since the effective date of previously issued ROP No 199600350. 

Permit to Install 

Number Description of Equipment 

Corresponding 

Emission Unit(s) or 

Flexible Group(s) 

N/A 
Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c 

Expiration Date: December 31, 2011 

PTI No: MI-PTI-A5754-2007c 

Page 32 of 32 

Appendix 7. Emission Calculations 

Specific emission calculations to be used with monitoring, testing or recordkeeping data are detailed in the 

appropriate Source-Wide, Emission Unit and/or Flexible group Special Conditions. Therefore, this appendix is not 

applicable. 

Appendix 8. Reporting 

A. Annual, Semiannual, and Deviation Certification Reporting 

The permittee shall use the MDEQ Report Certification form (EQP 5736) and MDEQ Deviation Report form 

(EQP 5737) for the annual, semiannual and deviation certification reporting referenced in the Reporting Section of 

the Source-Wide, Emission Unit and/or Flexible Group Special Conditions. Alternative formats must meet the 

provisions of Rule 213(4)(c) and Rule 213(3)(c)(i), respectively, and be approved by the AQD District Supervisor. 

B. Other Reporting 

Specific reporting requirement formats and procedures are detailed in Part A or the appropriate Source-Wide, 

Emission Unit and/or Flexible Group Special Conditions. Therefore, Part B of this appendix is not applicable.