# Appendix 9A

DNRE Best Available Retrofit Technology (BART) Rules

## R 336.1970 Best available retrofit techno logy; adoption by reference.

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

Determ inations 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 t echnology or BART program.

Rule 971. (1) The department shall determ ine applicability of be st available retrofit technology based on the provision s referenced in R 336.1970.

(2) The owner or operator of a unit subject to BART shall perfor m 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 da ys of the effectiv e 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 subr ule (2) of this rule shall be submitted to the departm ent and shall be subject to review and approva l by the department. If the department determines additional information is required, th e department shall provide to the owner or operator additional information requests and co mments 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 anal ysis 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 in to a permit to install or consent order with the department to make th e BART provisions legall y enforceable within 90 days of the department’s approval of th e 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 ru le shall m easure 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 ac ceptable to the department.

(c) A method currently in use or a future m ethod developed for use and acceptable to the department, including methods cont ained in existing permit conditions.

## 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 m onitoring system shall do either of the following:

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

com ply 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 departm ent.

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

system to demonstrate complian ce with this rule and who has already installed a continuous emission monitoring system for oxides of nitr ogen or sulfur dioxide pursuant to other applicable federal, state, or local rules shall meet the instal lation, testing, operation, quality assurance, and reporting requirement s specified by the department.

(10) An owner or operator of an emission unit that is subje ct 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 fo r the reporting period January 1 to June 30 of each calendar year. The reports shall in clude all of the following information:

(a) The date, time, magnitude of emissions , and em ission rates where applicable, of the specified emission unit or utility system.

(b) If emissions or emission rates exceed th e emissions or emi ssion rates allowed by the applicable emission limit, the cause, if known, and any corre ctive action taken.

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

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

shall includ e the date and time of each peri od 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 informati on shall be stated in the report.

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

shall be sub mitted 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.

# 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 Clea n 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

emissi on 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 e missions from each source in relationship to the distance from known Class 1 areas, i.e. Q/d

values. It was assumed that facilit ies 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 deci view threshold value, and using the CALP UFF model on the six fac ilities that met the Q/d criteria. This final step confirme d 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 t he Smurfit/Stone Container facility closed, resulting in removal of the two facilities from the BART-subject list.

### Table 1: BART-eligible Sources in Michigan

Source Name Unit Description SIC

Spreader Stroker Boiler 2899 Cargill Salt

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

Boiler #1 8221 Eastern Michigan University

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

Boiler 166-77 3714 Ford - Saline

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

Boiler # 3-2 3321 Gm - Saginaw Metal

Boiler # 4-2 3321

202 Boiler 3711 Gm - Technical Ctr R

Boiler #1 3711
Kalsec Inc Mfg Plant Cleaver-Brooks 2087

Kilns 19 3241 Lafarge Midwest Inc.

Kilns 20 3241Source 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

Boiler 8 2611 New Page Paper Co

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

Boiler #3 8221 University Of Michigan

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

### 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 tw o facilities are no longer BART-subject

# 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 IN FORMATION .........................................................................2-1 2.1 Facility Location ................................................................................................2-1 2.2 Description of Operati ons.................................................................................2-1
2.3 Class I Area Evaluated.....................................................................................2-3

3.0 BART SELECTION PROCES S...........................................................................3-1
3.1 SO 2 

## BART Anal ysis..........................................................................................3-1 Step 1 – Identify Potentially Applicable SO 2 

## Control Op tions .................................3-1 Step 2 – Eliminate Technically In feasible Contro l Options .....................................3-7 Step 3 – Rank Feasible SO 2 

## Control Op tions......................................................... 3-8 Step 4 – Evaluate Feasible Control Op tions........................................................... 3-9
3.2 NOx BART Analysis .........................................................................................3-9 Step 1 – Identify Potentially App licable NOx Contro l Options ................................3-9 Step 2 - Eliminate Technically In feasible Contro l Options ....................................3-16 Step 3 - Rank Feasible NOx Control Options .......................................................3-16 Step 4 – Evaluate Feasible Control Op tions......................................................... 3-16
3.3 SO 2 

## and NOx Control Cost Comparis ion........................................................3-17 3.4 Proposed BART .............................................................................................3-18

4.0 BART MODEL PR OCEDURE .............................................................................4-1
4.1 Modeled Emissions and Stack Parame ters......................................................4-1 4.2 Modeling Me thodology .....................................................................................4-3
4.3 CALM ET........................................................................................................... 4-5 Meteorological Domain...........................................................................................4-5 Meteorological Data ...............................................................................................4-5 Geophysical Data...................................................................................................4-7 CALMET Preproc essing.........................................................................................4-8
CALMET Anal ysis ..................................................................................................4-9
4.4 CALPUF F.......................................................................................................4-10 Modeling Do main .................................................................................................4-10
Class I Area Rec eptors ........................................................................................4-10
Control File Settings .............................................................................................4-11 Ozone and Ammonia Backg round Val ues............................................................ 4-11
4.5 CALPOS T ......................................................................................................4-11

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

## ii List of Tables

Table 1-1. Proposed BART for Lafarge Al pena...........................................................1-3 Table 3-1. Comparison of Cost s for Feasible BAR T Contro ls ...................................3-17
Table 4-1. Modeled Sta ck 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 Backgr ound)............................................................... 5-2

List of Figures

Figure 2-1. Location of the Lafarge Alpena Facility .....................................................2-2 Figure 2-2. Location of the Lafarge Alpen a Facility and the S eney Class I Area.........2-4 Figure 4-1. Lafarge Meteorologica l 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 st ationary sources that emit vi sibility impairing pollutants

must install and operate the Be st Available Retrofit Te chnology (BART). BART is

required for sources that fit specific cr iteria, as discussed bel ow, 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 source s 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 Guid elines 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 uni ts fall within the 15-year time frame

established by the BART Guidelines. Ther efore, 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 em ission sources is determining whether the

source meets a 250 ton per year emission thre shold. 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 cat egory and operational date tests must be in

excess of 250 tons per year for any single visibility impairing pol lutant. Visibilityimpairing pollutants include sulfur dioxide (SO 2 

## ), nitrogen oxides (NOx), and particulate

matter (PM).

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

Michigan. Portland cement m anufacturing is one of the spec ific 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 Laf arge 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 emissi ons from Lafarge change the 24- hour background visibility at

Seney by more than 0.5 deciviews (the deciv iew 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 pollut ant emitted. The BART review mu st identify the best system of

continuous emission reduction co nsidering the following five statutory fact ors: 1) the

cost of compliance, 2) energy and non-air quality environment al 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 implem enting BART.

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

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

emissions of SO 2 

## and NOx and did not consider emissions of PM 10 

## as PM 10 

## 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 PM 10 emissions were included in the evaluation of visibility impacts. However, PM 10 control options were not evaluated as the MDEQ has agreed t hat the Alpena facility’s compliance with the MACT standards for particulates satisfies the BART requirements.

## 1-3 The results presented herein demonstrate th at wet scrubbers on the two large kilns

(K22 and 23) represent BART for control of SO 2 

## and that selective non-catalytic

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

demonstrates that the addition of SO 2 

## 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 98 th



### 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, SO 2 

## See note See note Seney

Kiln 23 SNCR, Wet scrubbing NOx, SO 2 

## See note See note Seney

Kilns 19-23 See above

control for

each kiln NOx, SO 2 

## 29.4 TPD
NOx 53.8
TPD SO 2 

## -0.83 a 

## Seney

Note: Lafarge is proposing facility-wide BART limits. The pr oposed 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 “averag e” 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 reductio ns that would be obtained by simply controlling each of the BART-eligible units t hat 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 wester n shore of Lake Huron in northeastern

Michigan in Alpena County. The approx imate 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 l oading operations. Kiln Nos. 19-21 are collectively referred

to as Kiln Group 5 (KG5) while the larger kiln s (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 Deteriorat ion regulation of 40 CF R 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 materi als before entering the kilns). Limestone

is quarried on site. Other primary raw mate rial 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 materi als 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 ma terials in a countercurrent manner. The

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

## 2-2 ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !

! ! !

! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !!!!! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !!!! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !!!!! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !!! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !!!!! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !



# ®

0 550 1,100 1,650 2,200 275 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 temperat ure. 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) le ave 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 fu rther processing. The final step in the

manufacture of portland cement at Alpena in volves a sequence of blending and grinding

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

are added as needed to impart spec ific 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. T he 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 Ac t than any other areas in the United

States. Class I areas that are located wit hin 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 Wildernes s 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 revisi ons January 23 and March 9, 2006).

## 2-4 ! ! ! ! ! !!! ! ! ! ! ! !! 

## [ _ Lafarge Alpena Seney Wilderness Area



# ®

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



## Figure 2-2. Location of the Lafarge Al pena Facility and th e Seney Class I Area

## 3-1 3.0 BART SELECTION PROCESS

Five basic steps were taken in sele cting BART for the Laf arge Alpena kilns:

• All available retrofit contro l 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 c ontrol 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 analys is for the Alpena plant focused on SO 2 

## and

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

basically unrelated, each pollutant is addr essed individually. However, because the

impacts of SO 2 

## and NOx on visibility are similar, t he proposed BART limits are based on

a combined SO 2 

## and NOx control strat egy (see Section 3.3). 3



## 3.1 SO 2 

## BART Analysis

Step 1 – Identify Potentially Applicable SO 2



## Control Options

Lafarge has identified SO 2 

## 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 cons idering the potential

for technology transfer, the SO 2 

## control technologies potentially available 4 

## for retrofit to

the Alpena kilns include:

3 Model results indicate that SO 2 and NOx emissions contributed equally to visibility reduction at Seney. Lafarge

therefore concl uded that both SO 2 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 eval uation70 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 t he Alpena kilns.

Duct Sorbent Injection Systems. In general, sorbent inje ction 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 (typic ally hydrated lime) are injected.

Examples of alkaline reagent s used in sorbent injection systems include magnesium

hydroxide, hydrated lime, and sodium car bonate. The injected reagent reacts with SO 2 

## in the gas stream. Once dry, the byproduct of this reacti on consists of fine sulfate and

sulfite particles along wit h unreacted reagent. These particles are collected in a

downstream particulate control device and ei ther disposed of or reintroduced into the

process.

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

have been applied on cement kilns in recent years to reduce SO 2 

## emissions. With

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

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

reduce SO 2 

## 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 in jected reagent. The Alpe na 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 du ring 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 t he 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 pluggi ng and erosion of the

boilers by injected sorbent.

The effectiveness of sorbent injection is a f unction 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 mini mum. This factor limits the effectiveness

of sorbent injection technologies for the Alpena kilns to an estimated 25% SO 2 

## control

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

estimates that the overall SO 2 

## control efficiency is 20% for this technology.

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

guidance shows that one of the most e ffective add-on control technologies for SO 2


## 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 SO 2 

## control technology because it uses

water to enhance the reactions between SO 2 

## and the alkaline reagent used. It has the

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

on the application. The following subsection s provide additional information on wet and

semi-dry FGD systems and their potential a pplicability to the Laf arge 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 ar e 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 (CaSO 3 

## ) solids.

The LSFO process produces a scrubber byproduct with very little CaSO 3


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

calcium sulfate dihydrate (CaSO 4 

## ·2H 2 

## O or gypsum) content in excess of

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

the solids easier to dewater, improv es the reliability of the scrubbing

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

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

conventional, unoxidized limestone scrubbing process.

In the LSFO process, hot flue gas ex iting the particulate control device

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

into the flue gas. 5 

## The SO 2 

## in the flue gas is absorbed into the slurry

which is alkaline relative to the absorbed SO 2 

## . The flue gas exits the

absorption tower through a mist elimi nator to remove entrained droplets.

The absorbed SO 2 

## (now mostly dissolved sulfite) contained in the slurry

drains into a recirculation tank locat ed 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 calc ium sulfate dihydrate.

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

the slurry to force the oxidat ion of sulfite to sulfate. A portion of the slurry

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

slightly from the system described here. However the basic principals of SO 2 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 SO 2 

## removal efficiency of 81% is

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

90% SO 2 

## 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 wit h wet FGD systems in the cement

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

FGD system. An overall 81% contro l efficiency is consistent with

Lafarge’s experience on a ce ment kiln in Europe t hat has been retrofitted

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

control efficiency data on other re trofitted FGD systems on long dry

cement kilns.

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

the particulate control device ent ers an absorber tower. The SO 2 

## is

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

alkaline slurry of hydrated lime and calc ium 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 dewateri ng and further processing. This

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

the same. The differences are principally due to alternat ive designs that have different features and benefits and the choice of technology is often a function of site-spec ific 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 we t lime FGD system as compared to

the LSFO system is the higher operating costs, pr imarily due to the high

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

lime for this process also has impor tant secondary environmental impacts

as compared to the LSFO process, in cluding 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 SO 2 

## removal efficiencies of 90%. However, due to the nature

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

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

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

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

assessment. Because LSFO is th e best option from technical and

environmental perspective, and because it provides equivalent levels of

performance, this is the only wet scrubbi ng 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 characteri zed by flue gas temperatures above the

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

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

system downstream of t he FGD system to collect both scrubber byproduct and

fly ash such that the fly ash and the FG D 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 SO 2 

## in the flue gas reacts with the lime and any alkali

present in the fly ash to form sulfur salts (mostly CaSO 3 

## ). As the SO 2 

## reacts with

the slurry, the water in the droplets evapor ates forming solid particles, raising the

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

downstream of the spray dr yer 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 reac tor. In this reac tor, the elevated

humidity promotes the r eaction between gas-phase SO 2 

## 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 reacto r would have to be located upstream of

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

Step 2 – Eliminate Technically Infeasible Control Options

Of the SO 2 

## control options identified in this BART analysis, duct sorbent injection and

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

Lafarge Alpena plant. The various dry scrub bing options are a poor choice for Alpena

## 3-8 and they are deemed infeasible for several reas ons. 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 SO 2 

## 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 Al pena. The reduction in gas temperature by

the waste heat boilers limits the applicab ility 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 SO 2 

## in the kiln baghouses on the overall sulfur

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

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

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

technologies. Alternatively, control effici encies 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 t he gypsum byproduct can be added to the

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

as a result of installing an SO 2 

## control system.

Step 3 – Rank Feasible SO 2



## Control Options

The most effective, technically feasible SO 2 

## control option for the Alpena kilns is wet

FGD at 81% overall SO 2 

## control efficiency (90% contro l and 90% on-stream factor).

The least effective option SO 2 

## control option identified for the Alpena kilns is the use of

duct sorbent injection at an overall SO 2 

## 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 SO 2 

## and NOx impacts on visibility are similar when compared on a mass

emissions basis (i.e., SO 2 

## and NOx reductions both result in similar visibility

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

the effectiveness, costs, and energy and env ironmental impacts of the technically

feasible SO 2 

## and NOx control technologies identifie d in this BART analysis together and

used this assessment to select BART based on a combination of SO 2 

## and NOx controls.

The results of this combined SO 2 

## 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 NO x control options for retrof it 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 av ailable NOx control technologies that are

potentially applicable for retrofit to the Alpena kilns include:

• Process Optimization

• Low NOx Burners;

• Selective non-catalyti c NOx reduction (SNCR);and

• Selective catalytic NOx reduction (SCR).

The following subsections describe each of these technologies and their potential

applicability to t he Alpena kilns.

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

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

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

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

enhanced process monitoring systems, adv anced computer controls, and necessary

instrumentation to improve overall kiln operation. The baseli ne and projected NOx

## 3-10 emission rates from the Alpen a 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 fac ility, 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 base line 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 aggressiv eness within the combustion z one. These burner designs

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

percent) at the prim ary 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 co mbustion. 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 manufactu ring, 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 qua lity. 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 t he installation of t hese 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 (NH 3 

## ), or urea (urea is

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

ammonia is converted by OH* free radica ls to ammonia free radicals (i.e., NH 2 

## *), which

react with NOx to form N 2 

## and H 2 

## O. The optimum temperature range for this reaction is

## 3-11 1,600oF to 1,900oF. Above 1,900oF, the amount of NH 3 

## that oxidizes to NOx increases,

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

field data show NH 3 

## slip 7 

## to be a strong function of temperat ure. At temperatures at or

above 1,900oF, unreacted NH 3 

## emissions decrease due to the NH 3 

## oxidation to NOx. At

temperatures at or below 1,600oF, unreacted NH 3 

## emissions may rapidly increase. At

Alpena, NH 3 

## 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 av ailability (i.e., the NH 3 

## injection location);

• The baseline, or uncont rolled NOx concentration;

• Mixing;

• Reagent Ratio (i.e., the NH 3 

## to NOx molar ratio at the injection point);

• NH 3 

## 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 per form" but instead present a "level of

performance" question (i.e., generally, the c entral 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 NH 3 

## . The presence of competing reactants in the gas stream

may result in less NH 3 

## to convert NOx to its non-polluti ng 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 e fficiency degrades dramatica lly; 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 r eagent can oxidize and actually increase NOx emissions.

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

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

range for ammonia or urea inject ion is critical to achiev ing optimum performance of

SNCR.

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

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

competes with NH 3 

## for OH* radicals, thus reducing NOx control effectiveness. In

addition, ammonia interferes with the comple te oxidation of organic compounds in the

fuel, potentially causing a rise in CO emissi ons. 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 NH 3 

## . Insufficient reagent will not re sult 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 theoret ically result in conversion of 50% or more

of the NOx with an amm onia slip of 10 ppm or less, ther e 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 ar e 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 a ll of these applications have been on modern

preheater/precalciner kilns and only limited te sting 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 us ing conventional injection technology. In a

long-dry kiln, injection must occur mid-kiln be cause 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 in jection 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 t he Alpena kilns, can

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

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

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

testing and operation for ot her long-dry kilns.

Selective Catalytic Reduction (SCR). Like SNCR, SCR systems use NH 3 

## to

chemically convert NOx to molecular N 2 

## (i.e., the same form of nitrogen that comprises

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

promote the selective reacti on of NOx and ammonia. Amm onia injected into the gas

stream reacts with NO x 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 surfac e of the catalyst st ructure. However,

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

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

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

the catalyst available fo r reaction with NOx and NH 3



## .

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 NH 3 8 

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

injection grid designed to ensure relatively even NH 3 

## distribution, good mixing, and

minimum NH 3 

## slip. The injected NH 3 

## reacts with NOx compounds (i.e., NO and NO 2 

## ) on

the surface of the catal yst in equal molar amounts (i.e., one molecule of NH 3 

## reacts with

one molecule of NOx) to form N 2 

## 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 t he Solnhofen Cement Works in

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

preheater tower. In this locati on, 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 dr y kilns. The raw materials used in the

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

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

materials contain appreciable amounts of bot h. 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 pluggi ng and corrosion of heat exchangers and

particulate control equipment.

Lafarge has assessed the publicly availabl e information regarding the Solnhofen SCR

application and has determined that the long-term demonst rated performance of the

SCR system at Solnhofen shows a demonstr ated NOx reduction efficiency that is

8 The NH 3 reagent can be in the form of an aqueous solution (typically 25 wt. % NH 3 ), anhydrous NH 3 , or as a

product of urea decomposition.

9 A second commercial-scale SCR system has been install ed in Europe on a cement kiln at Cementeria di Monselice. This unit began operation in mid-2006. Very lit tle data are available on this application, but what data are available show that it differs significantly from t he Alpena kilns. The Monselice SCR system is installed on a pre-heater, pre-calciner kiln system. There is no equ ivalent 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 Wo rks would be bypassed if the flue gas temperature dropped below 320oC or about 610oF.

## 3-15 similar to the reduction efficiencie s 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 facilit y. In other words, over the long-term, the

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

writing, it has been shutdown.

The Solnhofen SCR system did oper ate over a period of severa l years, but as described

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

than the expected control effectiveness of S NCR (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 cem ent kilns like those at Alpena.

It has been theorized that an SCR system coul d 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 reco very 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, Permi t No. 2000-05-077”; Submitted to Missouri Department

## 3-16 number of potential probl ems including the issue of fine particulate emissions generated

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

SCR system, and the potential for rapid catal yst 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 effl uent to preheat the SCR inlet st ream are on very low sulfur

applications (i.e., less than 10 ppm SO 2 

## ). Any attempt to apply th is type of system to

the Alpena kilns would be experimental in nat ure and such experimental technologies

are not considered “available” when it come s 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 th is 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 fa cilities. 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, technica lly feasible NOx control optio n for the Alpena kilns is the

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

combination of technologies can ac hieve 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 SO 2 

## 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., SO 2 

## and NOx reductions both result in similar visibility

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

the effectiveness, costs, and energy and env ironmental impacts of the technically

feasible SO 2 

## and NOx control technologies identifie d in this BART analysis together and

used this assessment to select BART based on a combination of SO 2 

## and NOx controls.

3.3 SO 2 

## and NOx Control Cost Comparision

Table 3-1 summarizes the results of Lafarge’s evaluation of the costs of SO 2 

## 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. We t FGD will increase demand for electrical

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

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

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

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

the amount of CKD that must be disposed of. SNCR will result in an increase in NH 3



## emissions which can cause formation of fine particulates through reaction with SO 3 

## 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 Co sts 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 approximat ely $3,400 and $8,000 per ton, are excessive. This

determination is made relative to the cost s of the other contro l options listed in

Table 3-1, relative to the costs/value of incremental SO 2 

## control under the acid rain

program, and relative to past SO 2 

## BACT determinations in the Midwest. For example,

the current value of SO 2 

## allowances available for purchase (and potential retirement)

under U.S. EPA’s acid rain program (i.e ., Title IV of t he 1990 Clean Air Act

amendments) is less than $500/ton. 12 

## The reason SO 2 

## control costs for KG5 are

excessive is because of the low SO 2 

## emissions rate from these kilns relative to the

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

location to achieve significant SO 2 

## reductions at the Alpena plant.

In addition, as discussed in Section 5, addition of SO 2 

## controls on KG5 result in minimal

improvement in visibility. The addition of SO 2 

## 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 conclude s 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 KG 6. Implementation of addit ional controls results in

substantial added costs with onl y limited visibility improv ement (as measured by the

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

BART controls are evaluated an d discussed in Section 5.

3.4 Proposed BART

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

kilns in KG6. Consistent with this cont rol 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 SO 2 

## per day.

12 CantorCO2e Real Time Market Data; S pot 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 (tons/day) Compound

KG5 KG6

SO 2 

## 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 ma ss emission limits for NOx and SO 2 

## that apply to the

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

employ continuous emission monitors to re cord 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 rate s during normal operation for 2002-2004 were

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

Baseline NOx and SO 2 

## 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 PM 10 

## emission were assumed to be filterable and were

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

PM 10 

## (PMC or PM Coarse), PM 2.5 

## (PMF or PM Fine), and elem ental carbon (EC). As

recommended by VISTAS, the condensable PM 10 

## fraction was assumed to be 85.6% of

the total PM 10 

## emissions rate. The total PM 10 

## rate was calculated from the filterable

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

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

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

are presented in Appendix A.

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

Lafarge modeled emissions of PM 10 

## , NOx and SO 2 

## 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 SO 2 

## were varied in

evaluating the affects of t he various control technologi es 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 le vel of control required by a MACT standard

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

modeled are provided in Tables 4-1 and 4-2, respectively.4-2Table 4-1. ModeledStack Parameter DataModelSourceIDSourceDescriptionLCC E(km)aLCC N(km)aStackHeight(m)BaseElevation(m)StackDiameter(m)ExitVelocity(m/sec)Temp.(K)SigmaY (m)SigmaZ (m)MomentumFluxSV00031 K19 Exhaust 1066.746 641.66867.06 182.0 3.96 3.91 439.26 0 0 1SV00032 K20 Exhaust 1066.762 641.67167.06 182.0 3.96 3.91 439.26 0 0 1SV00033 K21 Exhaust 1066.780 641.67567.06 182.0 3.96 6.03 439.26 0 0 1SV00047K22-23Exhaust1066.867 641.697 89.00 182.0 7.32 6.73 469.82 0 0 1KILNSWorst –CaseCombined1066.789 641.678 81.37 182.00 6.15 5.97 459.19 0 0 1aLambert Conformal Conic (LCC) coordinates are based upon an originof 40.0N and 97.0W with Standard Parallels of 33.0N and 45.0N (WGS-84 Datum).Table 4-2. Baseline Modeled Emission Rates (lb/day)ModelSourceIDSourceDescriptionSO2SO4NOxHNO3NO3PMCPMFECSOASV00031 K19 Exhaust 34,760 577 13,116 0 0 51 54 6 79SV00032 K20 Exhaust 19,656 577 12,712 0 0 51 54 6 79SV00033 K21 Exhaust 21,796 577 11,942 0 0 51 54 6 79SV00047K22-23Exhaust157,398 2,768 56,956 0 0 245 257 26 377KILNSWorst –CaseCombined 233,610 4,498 94,726 0 0 399 417 43 613Notes: PMFine (PMF) or "soil" = PM < 2.5 um in diameter. PMCoarse (PMC) = PM between 2.5 and 10 um in diameter. SOA = secondary organicaerosols. EC = elemental carbon. Kiln PMspeciation based upon VISTAS guidance.

## 4-3 To simplify the modeling analysis, Lafarge model ed a single, worst-case stack. The

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

stack. The parameters for t he 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-ca se stack parameters were

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

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

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

the control technol ogy evaluation.

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

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

percentage) and the baseline rates. The pos t-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 recommendat ions, for long-range transport 13 

## 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 De terioration permitting program . The LADCO guidance was

developed specifically for BART modeling.

13 Interagency Workgroup on Air Quality Modeling (IWA QM) Phase 2 Summary Report and Recommendations for Modeling Long_Range Transport Impacts , EPA-454/R-98-019, U.S. Environmental Protection A gency, 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, 2006.4-4Table 4-3. Post-Control Modeled Emission Rates (lb/day)SourceDescriptionSO2SO4NOxHNO3NO3PMCPMFECSOAControl Scenario 1: SNCR KG5 & 6, Wet Scrubbing KG6 (Proposed BART)KG5 76,212 1,730 24,551 0 0 153 161 17 236KG6 31,480 1,384 34,174 0 0 245 257 26 377Total 107,692 3,114 58,724 0 0 399 417 43 613Reduction fromBaseline (%)54 31 38 0 0 0 0 0 0Control Scenario 2: SNCR KG5 & 6, Wet Scrubbing KG6, Duct Injection KG5KG5 60,970 1,557 24,551 0 0 153 161 17 236KG6 31,480 1,384 34,174 0 0 245 257 26 377Total 92,449 2,941 58,724 0 0 399 417 43 613Reduction fromBaseline (%)60 35 38 0 0 0 0 0 0Control Scenario 3: SNCR KG5 & 6, Wet Scrubbing KG5 & 6KG5 15,242 865 24,551 0 0 153 161 17 236KG6 31,480 1,384 34,174 0 0 245 257 26 377Total 46,722 2,249 58,724 0 0 399 417 43 613Reduction fromBaseline (%)80 50 38 0 0 0 0 0 0Note: 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) - XOR IGKM = 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. T he 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 thes e data from the National

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

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

stations were used.

## 4-6 ! ! ! ! ! ! ! !!! !!! ! ! ! ! ! ! ! ! ! !! 

## [ _ Lafarge Alpena Seney NWR



# ®

0 75,000 150,000 225,000 300,000 37,500 Meters MET Domain

Computational Domain



## Figure 4-1. Lafarge Meteorologi cal 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, wit hin 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 stati ons 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 po rtion of the modeling

domain, the USGS EROS Global Land Cover C haracterization (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 (DE M) data were used. For the Canadian

portion of the modeling domain, t he 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 conversi on and writes the combined data to a

single file (surf.dat). The sur f.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 fill ed and the errors are corrected. These

changes are documented in the upper air list (.ls t) files. The proc essed 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 dat a 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 calc ulates the elevation of the center of each grid cell in

the modeling domain and writes a processed data file.

MAKEGEO reads the proce ssed data files from CTGPROC and TERREL. MAKEGEO

calculates weighted surface characteristi cs 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 IWAQM 15 

## and FLAG 16 

## . Version 6.211 of

the CALMET model was used to develop t he 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 Wi nd Fields of the 4 km three-dimensional

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

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

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

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

valley between. The higher terrain to the s outh 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 dist ance 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 ve ry little influence on the calculated

impacts.

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

precipitation data) ar e 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 thr ee-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. T herefore, the radius of influenc e 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 Surf ace (KM) - R1 = 30 Relative Weighting Aloft (KM) - R2 = 60

4.4 CALPUFF

Output from the CALMET m odel 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 co mputational modeling

domain. The domain dimensio ns are therefore 440 km eas t-west by 312 km northsouth. The modeling (computat ional) 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 S eney, with elevations, as obtained from the

National Parks Service. The receptor c oordinates 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 se t 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 methodol ogy was used for puff recognition.

• 

## Building downwash was ignored because t he 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 (O 3 

## ) and ammonia (NH 3 

## ) values in its chemistry

module. Per LADCO Guidance, Lafarge us ed 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 inpu t control file and the hourly concentration

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

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

was set such that the backg round light extinction calcul ation 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 Cla ss I area were used. These values were

obtained from Table A-3 of t he 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, CALP OST also requires monthly ba ckground concentrations of

ammonium sulfate, ammonium nitrate, coarse particulate mass, organic carbon, soil,

and elemental carbon. Annual averages reflecti ve of natural background conditions for

these species were obtained from the EPA’s “Gui dance for Natural Visibi lity” document.

Light Extinction Efficiencies and Rayleigh Scattering Value

The other values required to execute CALPOS T 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 val ue for Rayleigh scattering was set to 10 Mm -1



## .

## 5-1 5.0 BART MODEL RESULTS

The CALPUFF modeling system was exec uted with input data and settings as

described in Section 4. Delta-decivie w results were obtained from the “24HR

VISIBILITY (deciview)” table in the CALPOST output files. The regional haze regulation

and BART guideline stipulat e that the States have flexibi lity in determining the degree of

visibility improvement that should be considered acceptable in assessing appropriate

BART controls (see 70 FR 39170). The Stat es may consider the frequency, magnitude,

and duration components of visibility impairm ent. EPA suggests that the States use a

comparison threshold, as is done for determi ning if BART-eligible emission units are

subject to BART. Alternativel y, States may compare the 98 th 

## percent days for the preand post-control runs. The MDEQ has requested that Laf arge provide the 98 th



## percentile values as well as the number of days with delta deciview values in excess of

the 0.5 BART-eligibility criterion for both t he pre- and post-contro l scenarios. These

results are presented in Table 5-1 as well as Appendix E.

As shown in Table 5-1, both the 98 th 

## 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 bas eline and the control

scenario no. 1 (SNCR on all kilns and wet scrubbi ng on KG6). The next highest level of

control (adding duct injection to KG5) result s in some degree of visibility improvement.

However, the costs of the addi tional level of control out weighs the small additional

improvement in modeled visib ility 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 (addi tion 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.5-2Table 5-1. Delta DeciviewVisibility Impact Rankings (4km CALMET Grid, Annual Average Concentrations asBackground)2002200320042002-2004 CombinedScenario98thPercentileValueNo. Days98% > 0.5deciview98thPercentileValueNo. Days98% > 0.5deciview98thPercentileValueNo. Days98% > 0.5deciview98thPercentileValueNo. Days98% > 0.5deciviewBaseline0.711 3 1.852 15 1.089 7 1.301 25Control Scenario 1: SNCRKG5&6, Wet ScrubbingKG6 (Proposed BART)0.371 0 1.022 10 0.641 3 0.746 12Control Scenario 2: SNCRKG5&6, Wet ScrubbingKG6, Duct Injection KG50.340 0 0.908 10 0.614 3 0.697 10Control Scenario 3: SNCRKG5&6, Wet ScrubbingKG5&60.242 0 0.644 6 0.474 0 0.509 1

## APPENDIX A

PM 10 

## Speciation, Emission Calculations,
And Worst Case-Stack Parameter DeterminationSource EquipmentNumberNew MAERSActivity IDNo.ModelSource ID Source DescriptionMaterialMaximumFeed Rate(ton/hr)PotentialEmissionFactor(lb/tonfeed) Emission Factor ReferencePM PTE(lbs/hr)PM10PTE(lbs/hr)PM10PTE(ton/yr)25-253 KILN 19 SV00031 K19 Exhaust Kilns (CKD) 90 0.06 MAERS, Test 5.40 4.59 20.125-265 KILN 20 SV00032 K20 Exhaust Kilns (CKD) 90 0.06 MAERS, Test 5.40 4.59 20.125-266 KILN 21 SV00033 K21 Exhaust Kilns (CKD) 90 0.06 MAERS, Test 5.40 4.59 20.126-256 KILN 22 SV00047 K22-23 Exhaust Kilns (CKD) 144 0.11 MAERS, Test 15.84 13.46 59.026-256 KILN 23 SV00047 K22-23 Exhaust Kilns (CKD) 144 0.07 MAERS, Test 10.08 8.57 37.5Maximum 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.PM10Emissions from Lafarge Alpena KilnsPM SpeciationUncontrolled PM10 Emissions(BoldValue isInputby user.)Kiln Total PM10 Filterable Coarse - PMC Ext. Fine Fine Soil - PMF Ext. Fine EC Ext. Condensible CPM IOR -SO4 Particle CPM OR - SOA ParticleLafarge Kiln(lb/hr) (lb/hr) (lb/hr) Coef. (lb/hr) (lb/hr) Coef. (lb/hr) Coef. (lb/hr) (lb/hr) Type Ext.Coef. (lb/hr) Type Ext.Coef.KILN 1931.94.62.1 0.6 2.5 2.2 1 0.2 10 27.3 24.0 SO4 3 3.3 SOA 4KILN 2031.94.62.1 0.6 2.5 2.2 1 0.2 10 27.3 24.0 SO4 3 3.3 SOA 4KILN 2131.94.62.1 0.6 2.5 2.2 1 0.2 10 27.3 24.0 SO4 3 3.3 SOA 4KILN 2293.613.56.3 0.6 7.2 6.5 1 0.7 10 80.1 70.5 SO4 3 9.6 SOA 4KILN 2259.58.64.0 0.6 4.6 4.2 1 0.4 10 51.0 44.9 SO4 3 6.1 SOA4Model SourceDescriptionModelSource IDSum ofEmissions(lb/hr)WeightingFactorBased onEmissionsWeightedStackHeight (m)WeightedBaseElevation(m)WeightedStackDiameter(m)WeightedExitVelocity(m/sec)WeightedTemp. (K)K19 Exhaust SV00031 2027 0.15 9.76 26.48 0.58 0.57 63.91K20 Exhaust SV00032 1381 0.10 6.65 18.04 0.39 0.39 43.54K21 Exhaust SV00033 1438 0.10 6.92 18.78 0.41 0.62 45.34K22-23 ExhaustSV00047 9085 0.65 58.05 118.70 4.77 4.39 306.41Combined KILNS 13929 181.37 182.00 6.15 5.97 459.19Worst-Case Stack Parameter Determination - Weighting Based Upon Emissions

## APPENDIX B

Control Costing Calculations and Supporting DocumentationKG5 Wet Scrubber Cost EstimateItemBasisValueCommentsPurchased equipment CostsScrubber System Cost (SSC)Vendor Quote + Plant Estimates43,200,000Includes scrubber, reagent prep, piping, tanks, and pumps, aircompressors, gypsum handling, fans, and duct work.Instrumentation= 0.05*SSC2,160,000USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995) - use 1/2value to account for instrumentation in scrubber price.Sales taxes= 0.03*SSC1,296,000USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Freight= 0.05*SSC2,160,000USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Purchased equipment cost (PEC)PEC = 1.13*SSC48,816,000= Scrubber System Cost (SSC) + Instrumentation + Sales taxes +FreightDirect installation costsFoundations & supportsIncluded in PEC- Included in SSCHandling & erectionIncluded in PEC- Included in SSCElectricalIncluded in PEC- Included in SSCPipingIncluded in PEC- Included in SSCInsulationIncluded in PEC- Included in SSCPaintingIncluded in PEC- Included in SSCDirect installation costsIncluded in PEC- Included in SSCSite preparation & Buildings (SP + BLD.)As required9,000,000Lafarage Estimate: includes roads, electrical, water, etc.Total Direct Costs (DC)= PEC + SP +BLD.57,816,000= Site preparation & Buildings (SP + BLD.) + Purchased equipment cost(PEC)Indirect Costs (installation)Engineering= 0.10*PEC4,881,600USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Construction and field expenses= 0.10*PEC4,881,600USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Contractor fees= 0.10*PEC4,881,600USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Start-up= 0.01*PEC488,160USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Performance test= 0.01*PEC488,160USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Contingencies= 0.25*PEC9,763,200Conservative estimate of contingency based on level of engineering.Lost Production During Retrofit30 days of downtime/kiln4,320,000Based on lost production of$40/ton and a capacity of 150 tph.Total Indirect Costs (IC)= 0.35*PEC29,704,320= SUM of Indirect Cost ElementsTotal Capital Investment $ (TCI)= IC+ DC91,840,320= Total Direct Costs (DC) + Total Indirect Costs (IC)Capital Cost EstimateAnnual Cost InputsReagent Ratio (moles limestone/mole SO2 removed) Estimate.1.1 1.05 Reagent Ratio & 95% CaCO3 in limestone.Operating Labor Cost ($/hr)Lafarge Data; unburdened cost.23.78 Lafarge DataSupervisory Labor Cost ($/hr)Lafarge Data; unburdened cost.31.58 Lafarge DataMaintenance Labor Cost ($/hr)Lafarge Data; unburdened cost.24.78 Lafarge DataPower Cost ($/kW)Lafarge Data0.063 Lafarge DataLimestone Cost ($/ton)Lafarge Data1.25 Lafarge DataWater Cost ($/1000 gal)Lafarge Data4.9 Lafarge DataSO2 to Scrubber (tpy)Based on 2004/2005 Average Emissions.2,529SO2 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 Efficiency (%) * FGD On-streamTime (%)Gypsum MW (lb/lb-mole)Constant172CaCO3 MW (lb/lb-mole)Constant100SO2 MW (lb/lb-mole)Constant64Gypsum Production Rate (tpy -dry basis)CaSO4*2H2O (dry basis)5,504= SO2 Removed by Scrubber (tpy) * Gypsum MW (lb/lb-mole) / SO2MW (lb/lb-mole)Gypsum Value ($/ton - dry basis)Lafarge Data16 Lafarge DataWater Evaporation Rate (gpm)Estimate.100Direct Annual Costs (DAC)Operating labor• Operator ($/yr) 3.0 operators per shift 624,938 Estimate of staffing based on scrubber complexity.• Supervisor ($/yr) 15% of operator labor 124,488USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Operating materials• Water ($/yr) 10 wt. % free moisture in Gypsum + evap. 233,790 Based on evaporation, and water lost w/ gypsum.• Limestone ($/yr) Based on Reagent Ratio of 1.1. 4,400 Calculated based on Reagent Ratio & SO2 removal rate.• Wastewater disposal ($/yr) None (FGD is assumed zero discharge) 0 Zero discharge.Maintenance• Labor ($/yr) 1.0 person per shift 217,073 Estimate of staffing based on scrubber complexity.• Material ($/yr) 100% of maintenance labor 217,073USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Electricity• 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 ($/yr) Gypsum value as cement additive. -88,069= -Gypsum Production Rate (tpy -dry basis) * Gypsum Value ($/ton - drybasis)DAC SubtotalDirect Annual Costs (DAC) 1,676,411 = SUM of Direct Annual Cost ItemsIndirect Annual Costs (IAC)Overhead ($/yr)60% of total labor and material costs853,058USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Administrative charges ($/yr)2% of Total Capital Investment1,836,806USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Property tax ($/yr)1% of Total Capital Investment918,403USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Insurance ($/yr)1% of Total Capital Investment918,403USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Capital recovery ($/yr)10.98% x Total Capital Investment10,084,067USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).IAC SubtotalIndirect Annual Costs (IAC)14,610,738= SUM of Indirect Annual Cost ItemsAnnualized CostsTotal Annual Cost ($/yr)DAC + IAC16,287,149= IAC Subtotal + DAC SubtotalControl Cost Effectiveness ($/ton)TAC / Tons SO2 Removed7,952 = Total Annual Cost ($/yr) / SO2 Removed by Scrubber (tpy)Annualized Cost EstimateKG6 Wet Scrubber Cost EstimateItemBasisValueCommentsPurchased equipment CostsScrubber System Cost (SSC)Vendor Quote + Plant Estimates30,000,000Includes scrubber, reagent prep,piping, tanks, and pumps, aircompressors, gypsum handling, fans, and duct work.Instrumentation= 0.05*SSC1,500,000USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995) - use 1/2value to account for instrumentation in scrubber price.Sales taxes= 0.03*SSC900,000USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Freight= 0.05*SSC1,500,000USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Purchased equipment cost (PEC)PEC = 1.13*SSC33,900,000= Scrubber System Cost (SSC) + Instrumentation + Sales taxes +FreightDirect installation costsFoundations & supportsIncluded in PEC- Included in SSCHandling & erectionIncluded in PEC- Included in SSCElectricalIncluded in PEC- Included in SSCPipingIncluded in PEC- Included in SSCInsulationIncluded in PEC- Included in SSCPaintingIncluded in PEC- Included in SSCDirect installation costsIncluded in PEC- Included in SSCSite preparation & Buildings (SP + BLD.)As required7,000,000 Lafarage Estimate: includes roads, electrical, water, etc.Total Direct Costs (DC)= PEC + SP +BLD.40,900,000= Site preparation & Buildings (SP + BLD.) + Purchased equipment cost(PEC)Indirect Costs (installation)Engineering= 0.10*PEC3,390,000USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Construction and field expenses= 0.10*PEC3,390,000USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Contractor fees= 0.10*PEC3,390,000USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Start-up= 0.01*PEC339,000USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Performance test= 0.01*PEC339,000USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Contingencies= 0.25*PEC6,780,000Conservative estimate of contingency based on level of engineering.Lost Production During Retrofit30 days of downtime/kiln4,608,000Based on lost production of$40/ton and a capacity of 160 tph.Total Indirect Costs (IC)= 0.35*PEC22,236,000= SUM of Indirect Cost ElementsTotal Capital Investment $ (TCI)= IC+ DC63,136,000= Total Direct Costs (DC) + Total Indirect Costs (IC)Capital Cost EstimateAnnual Cost InputsReagent Ratio (moles limestone/mole SO2 removed) Estimate.1.1 1.05 Reagent Ratio & 95% CaCO3 in limestone.Operating Labor Cost ($/hr)Lafarge Data; unburdened cost.23.78 Lafarge DataSupervisory Labor Cost ($/hr)Lafarge Data; unburdened cost.31.58 Lafarge DataMaintenance Labor Cost ($/hr)Lafarge Data; unburdened cost.24.78 Lafarge DataPower Cost ($/kW)Lafarge Data0.063 Lafarge DataLimestone Cost ($/ton)Lafarge Data1.25 Lafarge DataWater Cost ($/1000 gal)Lafarge Data4.9 Lafarge DataSO2 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 Efficiency (%) * FGD On-streamTime (%)Gypsum MW (lb/lb-mole)Constant172CaCO3 MW (lb/lb-mole)Constant100SO2 MW (lb/lb-mole)Constant64Gypsum Production Rate (tpy -drybasis)CaSO4*2H2O (dry basis)29,241= SO2 Removed by Scrubber (tpy) * Gypsum MW (lb/lb-mole) / SO2MW (lb/lb-mole)Gypsum Value ($/ton - dry basis)Lafarge Data16 Lafarge DataWater Evaporation Rate (gpm)Estimate.100Direct Annual Costs (DAC)Operating labor• Operator ($/yr) 3.0 operators per shift 624,938 Estimate of staffing based on scrubber complexity.• Supervisor ($/yr) 15% of operator labor 124,488USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Operating materials• Water ($/yr) 10 wt. % free moisture in Gypsum + evap. 242,417 Based on evaporation, and water lost w/ gypsum.• Limestone ($/yr) Based on Reagent Ratio of 1.1. 23,376 Calculated based on Reagent Ratio & SO2 removal rate.• Wastewater disposal ($/yr) None (FGD is assumed zero discharge) 0 Zero discharge.Maintenance• Labor ($/yr) 1.0 person per shift 217,073 Estimate of staffing based on scrubber complexity.• Material ($/yr) 100% of maintenance labor 217,073USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Electricity• 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 ($/yr) Gypsum value as cement additive. -467,858= -Gypsum Production Rate (tpy -dry basis) * Gypsum Value ($/ton - drybasis)DAC SubtotalDirect Annual Costs (DAC) 1,503,034 = SUM of Direct Annual Cost ItemsIndirect Annual Costs (IAC)Overhead ($/yr)60% of total labor and material costs869,619USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Administrative charges ($/yr)2% of Total Capital Investment1,262,720USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Property tax ($/yr)1% of Total Capital Investment631,360USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Insurance ($/yr)1% of Total Capital Investment631,360USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Capital recovery ($/yr)10.98% x Total Capital Investment6,932,333USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).IAC SubtotalIndirect Annual Costs (IAC)10,327,392= SUM of Indirect Annual Cost ItemsAnnualized CostsTotal Annual Cost ($/yr)DAC + IAC11,830,426= IAC Subtotal + DAC SubtotalControl Cost Effectiveness ($/ton)TAC / Tons SO2 Removed1,087 = Total Annual Cost ($/yr) / SO2 Removed by Scrubber (tpy)Annualized Cost EstimateKG5 Duct Injection Cost EstimateItemBasisValueCommentsPurchased equipment CostsDuct Injection System Cost (DISC)Vendor Quote + Plant Estimates1,455,600Includes injection system, reagent prep, piping, tanks, silos, and pumpsand duct work.Instrumentation= 0.10*DISC145,560USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Sales taxes= 0.03*DISC43,668USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Freight= 0.05*DISC72,780USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Purchased equipment cost (PEC)PEC = 1.18*DISC1,717,608= Duct Injection System Cost (DISC) + Instrumentation + Sales taxes +FreightDirect installation costsFoundations & supportsIncluded in PEC- Included in DISCHandling & erectionIncluded in PEC- Included in DISCElectricalIncluded in PEC- Included in DISCPipingIncluded in PEC- Included in DISCInsulationIncluded in PEC- Included in DISCPaintingIncluded in PEC- Included in DISCDirect installation costsIncluded in PEC- Included in DISCSite preparation & Buildings (SP + BLD.)As required500,000 Order of magnitude estimate.Total Direct Costs (DC)= PEC + SP +BLD.2,217,608= Site preparation & Buildings (SP + BLD.) + Purchased equipment cost(PEC)Indirect Costs (installation)Engineering= 0.10*PEC171,761USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Construction and field expenses= 0.10*PEC171,761USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Contractor fees= 0.10*PEC171,761USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Start-up= 0.01*PEC17,176USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Performance test= 0.01*PEC17,176USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Contingencies= 0.25*PEC343,522Conservative estimate of contingency based on level of engineering.Lost Production During Retrofit10 days of downtime/kiln1,440,000Based on lost production of$40/ton and a capacity of 150 tph.Total Indirect Costs (IC)= 0.35*PEC2,333,156= SUM of Indirect Cost ElementsTotal Capital Investment $ (TCI)= IC+ DC4,550,764= Total Direct Costs (DC) + Total Indirect Costs (IC)Capital Cost EstimateAnnual Cost InputsReagent Ratio (moles limes/mole SO2 removed) Estimate.1.0 1.0 reagent ration estiamted to achieve 20% reduction.Operating Labor Cost ($/hr)Lafarge Data; unburdened cost.23.78 Lafarge DataSupervisory Labor Cost ($/hr)Lafarge Data; unburdened cost.31.58 Lafarge DataMaintenance Labor Cost ($/hr)Lafarge Data; unburdened cost.24.78 Lafarge DataPower Cost ($/kW)Lafarge Data0.063 Lafarge DataLime Cost ($/ton)Lafarge Data80 EstimateWater Cost ($/1000 gal)Lafarge Data4.9 Lafarge DataCKD disposal cost ($/ton)Lafarge Data3.5 Lafarge DataSO2 to Scrubber (tpy)Based on 2004/2005 Average Emissions.2,529SO2 Removal Efficiency (%)Design Estimate.25%FGD On-stream Time (%)Design Estimate.80%SO2 Removed by System (tpy)Calculated from above values.506= SO2 to Scrubber (tpy) * SO2 Removal Efficiency (%) * FGD On-streamTime (%)Ca(OH)2 MW (lb/lb-mole)Constant74SO2 MW (lb/lb-mole)Constant64Water Evaporation Rate (gpm)Estimate.50Direct Annual Costs (DAC)Operating labor• Operator ($/yr) 1.0 operators per shift 208,313 Estimate of staffing based on scrubber complexity.• Supervisor ($/yr) 15% of operator labor 41,496USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Operating materials• Water ($/yr) Based on evaporation rate. 103,018 Based on evaporation.• Lime ($/yr) Based on Reagent Ratio of 1.0. 46,778 Calculated based on Reagent Ratio & SO2 removal rate.• Wastewater disposal ($/yr) None (FGDis 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 shift108,536 Estimate of staffing based on scrubber complexity.• Material ($/yr)100% of maintenance labor108,536USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Electricity• Fans ($/yr)50 kW for scrubber fans.22,075 Design estimate.• Pumps ($/yr)20 kW for scrubber pumps.8,830 Design estimate.DAC SubtotalDirect Annual Costs (DAC)651,123 = SUM of Direct Annual Cost ItemsIndirect Annual Costs (IAC)Overhead ($/yr)60% of total labor and material costs370,006USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Administrative charges ($/yr)2% of Total Capital Investment91,015USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Property tax ($/yr)1% of Total Capital Investment45,508USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Insurance ($/yr)1% of Total Capital Investment45,508USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Capital recovery ($/yr)10.98% x Total Capital Investment499,674USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).IAC SubtotalIndirect Annual Costs (IAC)1,051,711= SUM of Indirect Annual Cost ItemsAnnualized CostsTotal Annual Cost ($/yr)DAC + IAC1,702,833= IAC Subtotal + DAC SubtotalControl Cost Effectiveness ($/ton)TAC / Tons SO2 Removed3,367 = Total Annual Cost ($/yr) / SO2 Removed by System (tpy)Annualized Cost EstimateKG6 Duct Injection Cost EstimateItemBasisValueCommentsPurchased equipment CostsDuct Injection System Cost (DISC)Vendor Quote + Plant Estimates1,344,000Includes injection system, reagent prep, piping, tanks, silos, and pumpsand duct work.Instrumentation= 0.10*DISC134,400USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Sales taxes= 0.03*DISC40,320USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Freight= 0.05*DISC67,200USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Purchased equipment cost (PEC)PEC = 1.18*DISC1,585,920= Duct Injection System Cost (DISC) + Instrumentation + Sales taxes +FreightDirect installation costsFoundations & supportsIncluded in PEC- Included in DISCHandling & erectionIncluded in PEC- Included in DISCElectricalIncluded in PEC- Included in DISCPipingIncluded in PEC- Included in DISCInsulationIncluded in PEC- Included in DISCPaintingIncluded in PEC- Included in DISCDirect installation costsIncluded in PEC- Included in DISCSite preparation & Buildings (SP + BLD.)As required500,000 Order of magnitude estimate.Total Direct Costs (DC)= PEC + SP +BLD.2,085,920= Site preparation & Buildings (SP + BLD.) + Purchased equipment cost(PEC)Indirect Costs (installation)Engineering= 0.10*PEC158,592USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Construction and field expenses= 0.10*PEC158,592USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Contractor fees= 0.10*PEC158,592USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Start-up= 0.01*PEC15,859USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Performance test= 0.01*PEC15,859USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Contingencies= 0.25*PEC317,184Conservative estimate of contingency based on level of engineering.Lost Production During Retrofit10 days of downtime/kiln1,536,000Based on lost production of$40/ton and a capacity of 160 tph.Total Indirect Costs (IC)= 0.35*PEC2,360,678= SUM of Indirect Cost ElementsTotal Capital Investment $ (TCI)= IC+ DC4,446,598= Total Direct Costs (DC) + Total Indirect Costs (IC)Capital Cost EstimateAnnual Cost InputsReagent Ratio (moles lime/mole SO2 removed) Estimate.1.0 1.0 reagent ration estiamted to achieve 20% reduction.Operating Labor Cost ($/hr)Lafarge Data; unburdened cost.23.78 Lafarge DataSupervisory Labor Cost ($/hr)Lafarge Data; unburdened cost.31.58 Lafarge DataMaintenance Labor Cost ($/hr)Lafarge Data; unburdened cost.24.78 Lafarge DataPower Cost ($/kW)Lafarge Data0.063 Lafarge DataLime Cost ($/ton)Lafarge Data80 EstimateWater Cost ($/1000 gal)Lafarge Data4.9 Lafarge DataCKD disposal cost ($/ton)Lafarge Data3.5 Lafarge DataSO2 to Scrubber (tpy)Based on 2004/2005 Average Emissions. 13,433SO2 Removal Efficiency (%)Design Estimate.25%FGD On-stream Time (%)Design Estimate.80%SO2 Removed by System (tpy)Calculated from above values.2,687= SO2 to Scrubber (tpy) * SO2 Removal Efficiency (%) * FGD On-streamTime (%)Ca(OH)2 MW (lb/lb-mole)Constant74SO2 MW (lb/lb-mole)Constant64Water Evaporation Rate (gpm)Estimate.50Direct Annual Costs (DAC)Operating labor• Operator ($/yr) 1.0 operators per shift 208,313 Estimate of staffing based on scrubber complexity.• Supervisor ($/yr) 15% of operator labor 41,496USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Operating materials• Water ($/yr) Based on evaporation rate. 103,018 Based on evaporation.• Lime ($/yr) Based on Reagent Ratio of 1.0. 248,504 Calculated based on Reagent Ratio & SO2 removal rate.• Wastewater disposal ($/yr) None (FGDis 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 complexity.• Material ($/yr) 100% of maintenance labor 108,536USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Electricity• Fans ($/yr) 50 kW for scrubber fans. 22,075 Design estimate.• Pumps ($/yr) 20 kW for scrubber pumps. 8,830 Design estimate.DAC SubtotalDirect Annual Costs (DAC) 868,114 = SUM of Direct Annual Cost ItemsIndirect Annual Costs (IAC)Overhead ($/yr)60% of total labor and material costs491,042USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Administrative charges ($/yr)2% of Total Capital Investment88,932USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Property tax ($/yr)1% of Total Capital Investment44,466USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Insurance ($/yr)1% of Total Capital Investment44,466USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Capital recovery ($/yr)10.98% x Total Capital Investment488,237USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).IAC SubtotalIndirect Annual Costs (IAC)1,157,142= SUM of Indirect Annual Cost ItemsAnnualized CostsTotal Annual Cost ($/yr)DAC + IAC2,025,256= IAC Subtotal + DAC SubtotalControl Cost Effectiveness ($/ton)TAC / Tons SO2 Removed754= Total Annual Cost ($/yr) / SO2 Removed by System (tpy)Annualized Cost EstimateKG5 SNCR Cost EstimateItemBasisValueCommentsPurchased equipment CostsSNCR System Cost (SNCRSC)Vendor Quote + Plant Estimates975,000Includes injection system, reagent prep, piping, tanks, silos, and pumpsand duct work.Instrumentation= 0.10*SNCRSC97,500USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Sales taxes= 0.03*SNCRSC29,250USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Freight= 0.05*SNCRSC48,750USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Purchased equipment cost (PEC)PEC = 1.18*SNCRSC1,150,500= SNCR System Cost (SNCRSC) + Instrumentation + Sales taxes +FreightDirect installation costsFoundations & supportsIncluded in PEC- Included in SNCRSCHandling & erectionIncluded in PEC- Included in SNCRSCElectricalIncluded in PEC- Included in SNCRSCPipingIncluded in PEC- Included in SNCRSCInsulationIncluded in PEC- Included in SNCRSCPaintingIncluded in PEC- Included in SNCRSCDirect installation costsIncluded in PEC- Included in SNCRSCGeneral Facilities (GF)= 0.05*PEC57,525USEPA Control Cost Manual, Sec. 4.2, C1, Table 1.4 (10/2000).Total Direct Costs (DC)= PEC + GF1,208,025= General Facilities (GF) + Purchased equipment cost (PEC)Indirect Costs (installation)Engineering= 0.10*PEC115,050USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Construction and field expenses= 0.10*PEC115,050USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Contractor fees= 0.10*PEC115,050USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Start-up= 0.01*PEC11,505USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Performance test= 0.01*PEC11,505USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Contingencies= 0.25*PEC230,100Conservative estimate of contingency based on level of engineering.Lost Production During Retrofit5 days of downtime/kiln720,000Based on lost production of$40/ton and a capacity of 150 tph.Total Indirect Costs (IC)= 0.35*PEC1,318,260= SUM of Indirect Cost ElementsTotal Capital Investment $ (TCI)= IC+ DC2,526,285= Total Direct Costs (DC) + Total Indirect Costs (IC)Capital Cost EstimateAnnual Cost InputsReagent Ratio (moles limestone/mole SO2 removed) Estimate. 1.0 1.0 reagent ration estiamted to achieve 40% reduction.Operating 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 ($/1000 gal) Lafarge Data 4.9 Lafarge DataNOx to SNCR (tpy) Based on 2004/2005 Average Emissions. 3,547NOx Removal Efficiency (%) Design Estimate. 44%SNCR On-stream Time (%) Design Estimate. 80%NOx Removed by System (tpy) Calculated from above values. 1,242= NOx to SNCR (tpy) * NOx Removal Efficiency (%) * SNCR On-streamTime (%)NH3 MW (lb/lb-mole) Constant 17NOx MW (lb/lb-mole) Constant 46Water Injection Rate (gpm) Based on 20% NH3/80% H2O by weight. 1.05 Calculated value.Direct Annual Costs (DAC)Operating labor• Operator ($/yr) 0.25 operators per shift 41,663 Estimate of staffing based on scrubber complexity.• Supervisor ($/yr) 15% of operator labor 8,299USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Operating materials• Water ($/yr) Based on evaporation rate. 2,157 Based on water used in injection system.• NH3 ($/yr) Based on Reagent Ratio of 1.0. 214,365 Calculated based on Reagent Ratio & SO2 removal rate.Maintenance• Labor & Materials ($/yr) 1.5% of TCI 37,894USEPA Control Cost Manual, Sec. 4.2, C1, Eqn. 1.21 (10/2000).Electricity• Vaporization System & Pumps ($/yr) 44 kW 19,426USEPA Control Cost Manual, Sec. 4.2, C1, Eqn. 1.23 (10/2000).DAC SubtotalDirect Annual Costs (DAC) 323,804 = SUM of Direct Annual Cost ItemsIndirect Annual Costs (IAC)Overhead ($/yr)60% of total labor and material costs182,626USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Administrative charges ($/yr)2% of Total Capital Investment50,526USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Property tax ($/yr)1% of Total Capital Investment25,263USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Insurance ($/yr)1% of Total Capital Investment25,263USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Capital recovery ($/yr)10.98% x Total Capital Investment277,386USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).IAC SubtotalIndirect Annual Costs (IAC)561,064= SUM of Indirect Annual Cost ItemsAnnualized CostsTotal Annual Cost ($/yr)DAC + IAC884,867= IAC Subtotal + DAC SubtotalControl Cost Effectiveness ($/ton)TAC / Tons NOx Removed713= Total Annual Cost ($/yr) / NOx Removed by System (tpy)Annualized Cost EstimateKG6 SNCR Cost EstimateItemBasisValueCommentsPurchased equipment CostsSNCR System Cost (SNCRSC)Vendor Quote + Plant Estimates800,000Includes injection system, reagent prep, piping, tanks, silos, and pumpsand duct work.Instrumentation= 0.10*SNCRSC80,000USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Sales taxes= 0.03*SNCRSC24,000USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Freight= 0.05*SNCRSC40,000USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Purchased equipment cost (PEC)PEC = 1.18*SNCRSC944,000= SNCR System Cost (SNCRSC) + Instrumentation + Sales taxes +FreightDirect installation costsFoundations & supportsIncluded in PEC- Included in SNCRSCHandling & erectionIncluded in PEC- Included in SNCRSCElectricalIncluded in PEC- Included in SNCRSCPipingIncluded in PEC- Included in SNCRSCInsulationIncluded in PEC- Included in SNCRSCPaintingIncluded in PEC- Included in SNCRSCDirect installation costsIncluded in PEC- Included in SNCRSCGeneral Facilities (GF)= 0.05*PEC47,200USEPA Control Cost Manual, Sec. 4.2, C1, Table 1.4 (10/2000).Total Direct Costs (DC)= PEC + GF991,200= General Facilities (GF) + Purchased equipment cost (PEC)Indirect Costs (installation)Engineering= 0.10*PEC94,400USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Construction and field expenses= 0.10*PEC94,400USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Contractor fees= 0.10*PEC94,400USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Start-up= 0.01*PEC9,440USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Performance test= 0.01*PEC9,440USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.3 (12/1995).Contingencies= 0.25*PEC188,800Conservative estimate of contingency based on level of engineering.Lost Production During Retrofit5 days of downtime/kiln768,000Based on lost production of$40/ton and a capacity of 160 tph.Total Indirect Costs (IC)= 0.35*PEC1,258,880= SUM of Indirect Cost ElementsTotal Capital Investment $ (TCI)= IC+ DC2,250,080= Total Direct Costs (DC) + Total Indirect Costs (IC)Capital Cost EstimateAnnual Cost InputsReagent Ratio (moles limestone/mole SO2 removed) Estimate. 1.0 1.0 reagent ration estiamted to achieve 40% reduction.Operating 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 ($/1000 gal) Lafarge Data 4.9 Lafarge DataNOx to SNCR (tpy) Based on 2004/2005 Average Emissions. 5,748NOx Removal Efficiency (%) Design Estimate. 50%SNCR On-stream Time (%) Design Estimate. 80%NOx Removed by System (tpy) Calculated from above values. 2,299= NOx to SNCR (tpy) * NOx Removal Efficiency (%) * SNCR On-streamTime (%)NH3 MW (lb/lb-mole) Constant 17NOx MW (lb/lb-mole) Constant 46Water Injection Rate (gpm) Based on 20% NH3/80% H2O by weight. 1.94 Calculated value.Direct Annual Costs (DAC)Operating labor• Operator ($/yr) 0.25 operators per shift 41,663 Estimate of staffing based on scrubber complexity.• Supervisor ($/yr) 15% of operator labor 8,299USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Operating materials• Water ($/yr) Based on evaporation rate. 3,994 Based on water used in injection system.• NH3 ($/yr) Based on Reagent Ratio of 1.0. 396,957 Calculated based on Reagent Ratio & SO2 removal rate.Maintenance• Labor & Materials ($/yr) 1.5% of TCI 33,751USEPA Control Cost Manual, Sec. 4.2, C1, Eqn. 1.21 (10/2000).Electricity• Vaporization System & Pumps ($/yr) 71 kW 31,347USEPA Control Cost Manual, Sec. 4.2, C1, Eqn. 1.23 (10/2000).DAC SubtotalDirect Annual Costs (DAC) 516,011 = SUM of Direct Annual Cost ItemsIndirect Annual Costs (IAC)Overhead ($/yr)60% of total labor and material costs290,798USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Administrative charges ($/yr)2% of Total Capital Investment45,002USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Property tax ($/yr)1% of Total Capital Investment22,501USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Insurance ($/yr)1% of Total Capital Investment22,501USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).Capital recovery ($/yr)10.98% x Total Capital Investment247,059USEPA Control Cost Manual, Sec. 5.2, C1, Table 1.4 (12/1995).IAC SubtotalIndirect Annual Costs (IAC)627,860= SUM of Indirect Annual Cost ItemsAnnualized CostsTotal Annual Cost ($/yr)DAC + IAC1,143,871= IAC Subtotal + DAC SubtotalControl Cost Effectiveness ($/ton)TAC / Tons NOx Removed498= Total Annual Cost ($/yr) / NOx Removed by System (tpy)Annualized Cost Estimate

## APPENDIX C

CALMET Meteorological StationsWBAN WMO StationTimeNumber Number Name Longitude Latitude EasterlyNortherlyEasterlyNortherlyZone Zone(deg) (deg) (km) (km) (km) (km)4874 726394 Charlevoix - Newberry Luce Co MI 85.47 46.32 885.399 757.221 155.894 5139.320 17 514808 726395 Wurtsmith AFB MI 83.40 44.45 1074.281 573.444 309.041 4924.657 17 514841 727347 Pellston Emmet County AP MI 84.78 45.57 949.275 681.352 205.051 5053.226 17 514847 727340 SAULT STE MARIE/NWSO MI 84.35 46.47 968.599 784.893 242.800 5151.391 17 514850 726387 TRAVERSE CITY/FAA AIRPORT MI 85.58 44.73 898.900 580.888 137.112 4963.516 17 514898 726450 GREEN BAY/AUSTIN STRAUBEL FIE WI 88.13 44.48 701.564 530.828 -67.248 4950.327 17 686399* 726399 Seul Choix Pt AMOS - false WBAN MI 85.92 45.92 856.439 708.678 118.499 5096.940 17 594814 726380 Houghton Lake Roscommon MI 84.68 44.37 975.025 550.216 206.794 4919.558 17 594849 726390 ALPENA/PHELPS COLLINS AP MI 83.57 45.07 1051.088 639.300 297.917 4993.599 17 594853 726480 Escanaba AWOS MI 87.03 45.75 773.078 679.921 31.008 5083.982 17 594896 726487 Menominee AWOS MI 87.63 45.13 733.824 606.346 -21.357 5018.818 17 5*Pseudo-WBAN number assigned for unknown WBAN number.Surface Stations2002, 2003 and 2004StateGeographic Location Lambert CC UTMStation StationTimeNumber NameLongitude Latitude Easterly NortherlyEasterly NortherlyZone Zone(deg) (deg) (km) (km) (km) (km)4837 GaylordMI 84.43 44.54 992.082 571.628 227.506 4937.577 17 514898 GREEN BAY/AUSTIN STRAUBEL FIE WI 88.13 44.48 701.564 530.828 -67.248 4950.327 17 6Upper Air Stations2002, 2003 and 2004StateGeographic Location Lambert CC UTMStation StationTimeNumber Name Longitude Latitude EasterlyNortherlyEasterlyNortherly Zone Zone(deg) (deg) (km) (km) (km) (km)200164* ALPENA WB AIRPORT MI 83.57 45.07 1050.806 639.596 297.692 4993.940 17 5200662 BELLAIRE MI 85.20 44.98 925.333 611.962 168.860 4989.315 17 5200766 BIG BAY 8 NW MI 87.87 46.88 695.537 798.422 -23.381 5214.786 17 5201486 CHATHAM EXP FARM 2 MI 86.92 46.33 774.419 745.086 44.371 5147.770 17 5202094 DETOUR VILLAGE MI 83.90 46.00 1010.299 738.259 275.450 5098.137 17 5202626 ESCANABAMI 87.03 45.75 773.078 679.921 31.008 5083.982 17 5202788 FIFE LAKE 1 NNW MI 85.35 44.58 919.318 566.356 154.653 4945.506 17 5203199 GLENNIE ALCONA DAM MI 83.80 44.57 1040.981 581.974 277.671 4938.999 17 5203391 GRAYLING MI 84.70 44.65 969.256 580.820 206.611 4950.733 17 5203516 GWINN 1 W MI 87.45 46.28 734.439 735.145 3.134 5145.413 17 5203936* HOUGHTON LAKE WSO AIRPORT MI 84.68 44.37 975.025 550.216 206.794 4919.558 17 5204090 IRON MTN-KINGSFORD WWTP MI 88.08 45.78 691.610 674.781 -50.350 5094.035 17 5205073 MANISTIQUE MI 86.25 45.95 830.658 708.932 93.133 5101.908 17 5205816 NEWBERRY STATE HOSPITL MI 85.50 46.33 882.967 758.035 153.648 5140.562 17 5206438 PELLSTON REGIONAL AP MI 84.79 45.56 948.651 680.145 204.218 5052.152 17 5207366 SAULT STE MARIE WSO MI 84.35 46.47 968.552 785.224 242.814 5151.724 17 5208246 TRAVERSE CITY MI 85.57 44.77 899.402 585.097 138.373 4967.569 17 5208293 TROUT LAKE MI 85.02 46.20 921.517 748.429 189.856 5124.128 17 5208417 VANDERBILT 11 ENE MI 84.45 45.17 980.874 640.766 228.893 5007.628 17 5476510 PESHTIGO WI 87.73 45.03 727.152 594.481 -30.148 5008.362 17 6478267 STURGEON BAY EXP FARM WI 87.33 44.87 760.302 580.063 -0.032 4988.036 17 6*Not used for 2002 (contained invalid characters)Geographic Location Lambert CC UTMPrecipitation Stations2002, 2003 and 2004State

## APPENDIX D

Seney Receptor Locati ons 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 CDClass 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

SO 2 --> 9734 4487 3852 1947
Modeled Rates (ton/day) All Kilns

NOx --> 47.4 29.4 29.4 29.4
SO 2 --> 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 Y ear of Meteorology

# Appendix 9D

Lafarge Global Settlement/Consent Decree - Alpena Facility

## _____________________________________ UNITED STATES DISTRICT COURT

FOR THE SOUTHERN DIST RICT 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

## V. NO

x 

## CONTROL TECHNOLOGY, EMISSI ON LIMITS, TONNAGE LIMITS, AND MONITORING REQUIREMENTS

A. NO

x 

## Control Technology, Emission Limits and Tonnage Limits.

11. Subject to Section VII (Temporary Cessa tion of Kiln Operation), the Lafarge

Companies shall install the NO

x 

## Control Technology and comply with the Emission Limits and

Tonnage Limits for the specific Facilities and Kiln s within their system according to Paragraphs

11 through 44. The Lafarge Companies shall Continuously Operate each NO

x 

## Control

Technology as applicable to each Kiln at all ti mes of Kiln Operation, except for periods of

Malfunction of the NO

x 

## Control Technology. Compliance with any requirement of this Section

V (NO

x 

## Control Technology, Emission Limits, Tonnage Limits, and Monitoring Requirements)

relating to any specific Facility or Kiln shall no t be required if the Lafarge Companies Retire any

such Facility or Kiln prior to any date for complian ce. If one or more K ilns at a Facility is in

Temporary Cessation, then the following provisi ons shall apply in ad dition 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 Emi ssion Limit at all other Kilns not in

Temporary Cessation at the Facility with in 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 Temp orary Cessation at th e 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 Temporar y Cessation on the dates required in this

Section V (NO

x 

## Control Technology, Emission Limits, Tonnage Limits and

Monitoring Requirements).

## Alpena

12. By January 1, 2011, the Lafarge Compan ies shall achieve and maintain

compliance with an interim Facility-Wide 12-Month Rolling Tonnage Limit for NO

x 

## of 8,650

tons.

13. Control Technology Retrofit Option.

a. Subject to Section VII (Temporary Cessa tion of Kiln Operation), the Lafarge

Companies shall have installed and Co mmenced Continuous Operation of the

SNCR technology specified in the table be low 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. NO

**x** 

## /Ton of clinker) Demonstration Phase Facility-Wide 12-Month Rolling Average

Emission Limit (lbs. NO

**x** 

## /Ton of clinker)

1 st 

## Kiln

in KG5 SNCR 10/1/2011 See Appendix

4.89 2 nd 

## Kiln

in KG5 SNCR 11/1/2011 See Appendix

3 rd 

## Kiln

in KG5 SNCR 12/1/2011 See Appendix

1 st 

## Kiln

in KG6 SNCR 1/1/2012 See Appendix

2 nd 

## Kiln

in KG6 SNCR 3/1/2012 See Appendix

## b. Upon installation of the Control Te chnology, the Lafarge Companies shall

Continuously Operate the SNCR technology during all times of Kiln Operation,

except during periods of SN CR 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 ach ieve and maintain compliance with

the Demonstration Phase Facility-Wide 12-Month Rolling Average

Emission Limit for NO

x 

## 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) iden tified 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 NO

x 

## 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 set ting a 30-Day Rolling Average Emission

Limit for NO

x 

## applicable to each Alpena Kiln that the Lafarge Companies have

not otherwise elected to Retire and/or Re place pursuant to Section VIII (Election

## to Retire and Replace Kilns). Within 30 Days after the establishment of a 30-Day

Rolling Average Emission Limit for NO

x 

## under the Appendix at any Alpena Kiln

that the Lafarge Companies have not otherw ise elected to Retire or Replace, the

Lafarge Companies shall achieve and maintain compliance with the 30-Day

Rolling Average Emission Limit for NO

x 

## 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 unde r the Clean Air Act and

the Michigan SIP for a permit to insta ll any Replacement Kiln(s) and thereafter

take all other actions necessary to obtain such permits or appr ovals after filing the

applications including, but not limited t o, 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 commen ce construction of the Replacement

## 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., whiche ver is earlier, then, in addition to any

other remedies available to the United Stat es 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 earlie r, 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 Paragra ph 14.a, whichever is earlier.

d. Commence Kiln Operation of any Replacem ent Kiln(s) within 42 months of the

date on which the Lafarge Companies comm ence construction of the Replacement

Kiln, or January 1, 2015, whichever is earlier;

e. Retire the Replaced Kiln(s) within 180 Da ys of commencement of Kiln Operation

of the Replacement Kiln(s);

f. Install and Commence Continuous Operat ion 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

-

## Day Rolling Average Emission Limit for NO

x 

## of 2.1 lb/Ton of clinker, or the

applicable New Source Performance Standard for NO

x 

## for Portland Cement

Manufacturing Facilities pr omulgated 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 sha ll, at Alpena, achieve and maintain compliance

with a Facility-Wide 12-Month Rolling Tonnage Limit for NO

x 

## of 7,160 Tons of NO

x 

## 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 impairi ng the Lafarge Companies’ ability to timely satisfy the

implementation schedule requirements of Paragr aph 14, the Lafarge Companies shall notify, in

writing, the U.S. EPA and the Stat e of Michigan of any such delay as soon as the Lafarge

Companies reasonably conclude th at the delay could affect their ability to comply with the

implementation schedule set forth in Paragraph 14.

a. If the Lafarge Companies provide the no tification required u nder this Paragraph

16, the Lafarge Companies shall propose in such notification, for approval by the

U.S. EPA and the State of Michigan pur suant 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

## 45. At each Kiln identified in Paragraph 7.z of this Decree (except for Joppa Kiln 3),

the Lafarge Companies shall install and make oper ational within 12 months of the Effective Date

a NO

x 

## 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

NO

x 

## Emission Limits established in Section V.A (NO

x 

## Control Technology, Emission Limits,

and Tonnage Limits) and the Appendix (Control Technology Demonstration Requirements), as

applicable, of this Consent Decree.

47. Each NO

x 

## CEMS required pursuant to Paragrap h 45 shall monitor and record the

applicable NO

x 

## emission rate from each Kiln stack in units of lbs of NO

x 

## per Ton of clinker

produced at such Kiln and sha ll 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 NO

x 

## shall be measured by

CEMS. During any time when CEMs are inoperab le and otherwise not measuring emissions of

NO

x 

## from any Kiln, the Lafarge Companies shall ap ply 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 appr opriate by the Affected State.

VI. SO 2 

## CONTROL TECHNOLOGY, EMISSION LIMITS, TONNAGE LIMITS, AND MONITORING REQUIREMENTS

A. SO 2 

## Control Technology, Emission Limits, and Tonnage Limits.

49. Subject to Section VII (Temporary Cessa tion of Kiln Operation), the Lafarge

## Companies shall install the SO 2 

## 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 SO 2 

## Control Technology as applicable to

each Kiln at all times of K iln Operation, except for periods of Malfunction of the SO 2 

## 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 mo re Kilns at a Facility is in Temporary Cessation,

then the following provisions shall apply in additi on 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 Emi ssion Limit at all other Kilns not in

Temporary Cessation at the Facility with in 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 Te mporary 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 Temporar y Cessation on the dates required in this

Section VI (SO 2 

## Control Technology, Emission Limits, Tonnage Limits and

Monitoring Requirements).

## Alpena

50. By January 1, 2011, the Lafarge Compan ies shall achieve and maintain

compliance with an interim Facility-Wide 12-Month Rolling Tonnage Limit for SO 2 

## of 13,100

tons per year.

51. Control Technology Retrofit Option

.

a. Subject to Section VII (Temporary Cessa tion of Kiln Operation), the Lafarge

Companies shall have installed and Commenced Continuous Operation of DAA

or Wet FGD technology in the table speci fied 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. SO 2 

## /Ton of clinker)

1 st 

## Kiln

in KG5 DAA 10/1/2011 See Appendix

3.68 2 nd 

## Kiln

in KG5 DAA 11/1/2011 See Appendix

3 rd 

## Kiln

in KG5 DAA 12/1/2011 See Appendix

1 st 

## Kiln

in KG6 Wet FGD 1/1/2014 See Appendix

2 nd 

## Kiln

in KG6 Wet FGD 3/1/2014 See Appendix

b. Upon installation of the SO 2 

## Control Technology, the Lafarge Companies shall

Continuously Operate the SO 2 

## Control Technology during all times of Kiln

Operation, except during periods of SO 2 

## Control Technology Malfunction.

## c. Lafarge shall design each Wet FGD to be installed at Alpena Kilns 22 and 23

(KG6) to achieve a removal efficiency for SO 2 

## 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 ach ieve and maintain compliance with

the Demonstration Phase Facility-Wide 12-Month Rolling Average

Emission Limit for SO 2 

## 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) iden tified 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 SO 2 

## 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 set ting a 30-Day Rolling Average Emission

Limit for SO 2 

## applicable to each Alpena Kiln that the Lafarge Companies have

not otherwise elected to Retire and/or Re place pursuant to Section VIII (Election

to Retire and Replace Kilns). Within 30 Days after the establishment of a 30-Day

## Rolling Average Emission Limit for SO 2 

## under the Appendix at any Alpena Kiln

that the Lafarge Companies have not otherw ise elected to Retire or Replace, the

Lafarge Companies achieve and maintain compliance with the 30-Day Rolling

Average Emission Limit for SO 2 

## 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 in cluding, but not limited to, responding to reasonable

requests for additional information by the pe rmitting authority in a timely fashion,

and conducting any environmental or othe r 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 commen ce construction of the Replacement

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 52.a., whiche ver is earlier, then, in addition to any

other remedies available to the United Stat es 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 earlie r, 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 w ithin 18 months of permit issuance

pursuant to Paragraph 52.a , whichever is earlier;

d. Commence Kiln Operation of the Replacem ent Kiln(s) within 42 months of the

date on which the Lafarge Companies comm ence construction of the Replacement

Kiln, or January 1, 2015, whichever is earlier;

e. Retire the Replaced Kiln(s) within 180 Da ys of commencement of Kiln Operation

of the Replacement Kiln(s);

f. Within 42 months of the date on wh ich 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 SO 2 

## 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 a nd approval by U.S. EPA and the Affected

State pursuant to Section XI (Review and Approval of Submittals), equivalent

## alternative SO 2 

## Control Technology that may incl ude but shall not be limited to

kiln system design, which is individually or collectively designed to achieve a

Control Efficiency for SO 2 

## equivalent to that of Wet FGD technology designed to

achieve a Control Efficiency for SO 2 

## 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 SO 2 

## of 1.4 lb/Ton of clinker,

or the New Source Performance Standard for SO 2 

## for Portland Cement

Manufacturing Facilities pr omulgated 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 sha ll, at Alpena, achieve and maintain compliance

with a Facility-Wide 12-Month Rolling Tonnage Limit for SO 2 

## of 5,762 Tons emitted per 12

-

month period.

54. Notification Regarding Alpena Re placement Kiln Compliance Date. If a

governmental entity's failure to act upon a tim ely-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 issu ance or effectiveness of a final valid permit or

approval, thereby impairing the Lafarge Companie s’ ability to timely satisfy the implementation

schedule requirements of Paragraph 52, the Lafarg e Companies shall notify, in writing, the U.S.

EPA and the State of Michigan of any such de lay as soon as the Lafarge Companies reasonably

## 88. The limitations on the generation and use of netting credits or offsets set forth in

Paragraphs 86 do not apply to emission reduction s achieved by the Lafarge Companies that are

surplus to those required under this Consent Decree (“surplu s emission reductions”). For

purposes of this Paragraph, surplus emission re ductions 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 im posed under this Consent Decree.

89. Nothing in this Consent Decree is inte nded to preclude the emission reductions

generated under this Consent Decr ee 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) NO

x 

## Emission Reduction Credits

pursuant to Georgia's Emission Reduction Credit Rule Ga. Comp. R. & Re gs. 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 th is Consent Decree requires the Lafarge

Companies to obtain a federal, State, or loca l permit or approval the Lafarge Companies shall

submit a timely and complete application for such permit or approval and take all other actions

## necessary to obtain all such permits or approvals, allowing for al l legally required processing and

review including requests for additional info rmation 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 fr om a failure to obtain, or a

delay in obtaining, any permit or approval require d to fulfill such oblig ation, if the Lafarge

Companies have submitted timely and complete applications and have taken all other actions

necessary to obtain all such permits or approva ls 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 Lafa rge Companies, within 12 months after the

Commencement of operation of each Control Tec hnology required to be in stalled, upgraded, or

operated on a Kiln under this Cons ent 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 au thority independent of the Affected State’s

authority to issue Title V permits. The permit or approval shall requir e 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 Sect ions 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 prom ptly submitting all information that such

permitting authority seeks following its receipt of the application for the permit.

## 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 Companies 1 

## shall comply with this Appendi x in proposing and establishing 30

- Day Rolling Average Emission Limits for Ni trogen 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, Jopp a, Paulding, Ravena, Seattle and Tulsa (Affected Kilns).

2. The Affected Kilns include kiln s 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 Av erage Emission Limits as requi red 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, S eattle 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 K iln, 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 in stallation of each Control Technology at each Affected Kiln, the Lafarg e Companies shall, consistent with the requirements of Sections V or VI of th e Consent Decree, undertake a startup and optimization program for each Control Technology;

d. Demonstration Program: Upon completion of the star tup and optimization program specified above, the Lafarge Companies sh all operate the Cont rol Technology in an optimized manner for a period of 12 months for the purpose of es tablishing a 30-Day Rolling Average Emission Limit for each Affected Kiln;

e. Final Report: The Lafarge Companies shall prepar e 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 w ith meanings specified in Section III, Definitions, of the Consent Decree into which this Appendix is incorporated.

# Appendix 9E

St Mary’s Cement BART Technical Analysis

# Appendix 9F

St. Mary’s Cement BART Letter

# DRAFT

BART Compliance Document
SMC



## St. Mary’s would apply for a permit modificatio n with the lim its 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 sati sfy 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 incorpo ration 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 determ ined 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 tim e 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 determ ined 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 tim e period determined at the

end of each calendar month SC VI.4

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 as h, fly ash, bauxite, m ill scales, slags, various sands, numerous iron sour ces, clay, overburden that are ground and mixed in EURAWMILLS. These raw

materials are then sent to the EUKILN wher e they are heated and become clinker.

Emission Units: EURAWMILLS, EUKILN



### POLLUTION CONTROL EQUIPMENT: Baghouse, Electrostatic Precipit ator, Selective Non-Catalytic Reduction (SNCR)



### I. EMISSION LIMIT(S)

Pollutant Limit Time Period/ Operating
Scenario Equipment Monitoring/ Testing

Metho d Underlying Applicable Requir ements

1. PM 0.30 lb/ton of dry feed 2 

### FGKILNRAWMILLS SC V.1 40 CFR

63.134 3(b)(1)

2. SO 2 

### 2800 lbs/hour 2 

### 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. SO 2 

### 550
tons/month 2 

### Calendar month. FGKILNRAWMILLS SC VI.4, VI.10 R 336.1201(3)

4. SO 2 

### 4404 tons/year 2 

### 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. NO

x 

### 6.50 lbs/ton of

clinker prod uced 1 

### 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),
Cons ent Order
AQD No. 25- 2006 Paragraph
10. A.1.
6. NO

x 

### 7.67 lbs/ton of

clinker prod uced 2 

### 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
AQ D No. 25- 2006 Paragraph

10. A.1.
7. D/F* 1.7 x 10 -10


### gr/dscf (TEQ)

corrected to 7 percent

oxygen 2# 

### FGKILNRAWMILLS SC III.4, V.2, VI.6, V I.17 40 CFR

63.134 3(b)(3)

8. Nickel

when burning

100% petroleum

coke 0.36 lb/hour 1 

### FGKILNRAWMILLS SC V.3 R 336.1224,

R 336.1 225

# Appendix 9H

Tilden Mining Company BART Technical Analysis

# 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 Combustion Units 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 of Remaining 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 of Remaining 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 of Remaining 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

Y:\22152\080 Tilden BARTIBART reportlTIIden BART Report (2006-12-28).doc

### 5.B.ii.b STEP 2 Eliminate TeclmicallyInfeasible Options

.. ; 62

5.B.ii.c STEP 3 - Evaluate Control Effectiveness of Remaining 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 of Remaining 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 All Available Retrofit Control Teclmologies 90

5.C.ii.b STEP 2 - Eliminate Teclmically Infeasible Options 90

5.C.ii.c STEP 3 - Evaluate Control Effectiveness of Remaining 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 of BART-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 NO

x 

### Control Technology

- Availability, Applicability, and

Teclmical Feasibility 45

11

Y:\22\52\080 Tilden BARnBART report\Tilden BART Report (2006-12-28).doc

### 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 NO

x 

### Control Technology Effectiveness --46

Table 5- I I Indurating Furnace NO

x 

### Control Cost Summary .....................................................•.. .47

Table 5-12 NO

x 

### Control Technology Impacts Assessment.. .48

Table 5-13 Post-Control NO

x 

### Modeling Scenarios ...................................................................•... 50

Control Scenario 50

Table 5-14 Post-Control NO x Modeling Scenarios

- Modeling Input Data 52

Table 5-15 Post-Control NO x Modeling Scenarios

- Visibility Modeling Results 53

Table 5-16 Post-Control NO x 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 NO

x 

### 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 of Visibility 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 NO

x 

### Control Technology

- Availability, Applicability and Technical Feasibility .......................................................................................................•.......... 98

Line 1 Dryer NOx Control Technology Effectiveness 99

Backup Process Boiler NO, Control Cost Summary 1 00

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 1 10

Post-Control Modeling Scenarios I 13

Post-Control NO x 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

Y:\221521080 Tilden BARTIBART reportlTilden BART Report (2006·12·28).doc

### 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

Y:\22\52\OBO Tilden BART\BART reportlTiiden BART Report (2006-12-2B).docY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 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 (SO 2 

### ). The kiln PM is controlled with

a n 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

• SO 2 

### 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### vi • P M emissions will be controlled as prescribed by the taconite maximum achievable control

technology (MACT) standard 1



### .

L ine 1 Cooler

• PM emissions will be controlled as prescribed by the taconite maximum achievable control

technology (MACT) standard 2



### .

B oilers 1 and 2

• SO 2 

### 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.

• NO

x 

### is good combustion practices

• P M emissions will be controlled as prescribed by the taconite maximum achievable control

technology (MACT) standard 3



### .

L ine 1 Dryer

• SO 2 

### 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 NO

x 

### emissions will be

c ontrolled

• NO

x 

### is good combustion practices

• P M emissions will be controlled as prescribed by the taconite maximum achievable control

technology (MACT) standard 4



### .

P rimary 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 ProcessingY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### vii • P M emissions will be controlled as prescribed by the taconite maximum achievable control

technology (MACT) standard 5



### .

C ALPUFF 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 ProcessingY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 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 20Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 2 worst days under natural conditions by 2064. 6 

### Assuming a uniform rate of progress, the default gl ide

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 thre e 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, PM 10 

### , PM 2.5 

### , SO 2 

### , NO

x 

### , and possibly Volatile Organic

C ompounds (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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 3 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 B ART 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:

S tep 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 YY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 4 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



### S tep 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 

### ”

H owever, 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 

### IBIDY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 5 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

technology 13 

### .” This also involves the identification of “irreso lvable 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 analysis 14



### .

I t 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 guarantees 15



### .

S tep 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 

### IBIDY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 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 protocol 16 

### , including receptor grid, meteorological

d ata, 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 7 plants in the same industry have been required to install BART controls if this

information is available. 17



### T o complete the BART process, the analysis must “establish enforceable emission limits that reflect

the BART requirements and requires compliance within a reasonable period of time 18 

### .” Those limits

m ust 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 basis 19 

### .” which could include the incorporation of

o ther 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 standards 20 

### .”

C ompliance 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 8 

# 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 analyses 21 

### . The streamlined approach will allow both states an d 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 visibil ity impairing pollutants: NO

x 

### , SO 2 

### , and PM.

R elative to NO

x 

### and SO 2 

### , PM is not a major visibility impairing pollutant. Further, the indurating

furnaces are subject to the taconite MACT standard 22 

### for the PM emissions. MDEQ requested that

T ilden 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 SO 2 

### . Any source subject to MACT standards must meet a l evel 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 ProcessingY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 9 (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 encour aging 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 NO

x 

### and SO 2 

### 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 NO

x 

### or SO 2 

### . The Ore Crushing source operates with control equ ipment 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: NO

x 

### , SO 2 

### , and PM.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 10 Tilden facility has two process boilers that are subject to the boiler MACT 23 

### . Since the boiler MACT

s tandards 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 NO

x 

### and SO 2 

### where applicable for the process boilers

a nd dryer.

23 

### 40 CFR 63 Subpart DDDDD-NESHAPS: ICI Boilers and Pr ocess HeatersY:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc11Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART AnalysisEmissionUnit #Emission UnitDescriptionNOxMax 24-hrActualEmissions(lbs/day)SO2Max 24-hrActualEmissions(lbs/day)PM10Max 24-hrActualEmissions(lbs/day)MACTPM EmissionLimit(gr/dscf)StackNumberActionsRequired3.AIndurating FurnaceEUKILN1Line 1 InduratingFurnace26208.0 6552.0 4948.50.01 magnetite0.03 hematiteSVP0051711(South) andSVP0051981(North)Full BARTAnalysis for SO2and NOx3.BPM-Only Taconite MACT Emission UnitsEUPRIMARYCRUSHERPrimary Crusher 1 -- --25.70.008 SVA0011570NoneEUCOOLER1Line 1 Pellet CoolerExhaust-- --5.90.008 SVP0025490None3.COther Combustion UnitsEUDRYER1 Line 1 Dryer88.3 199.2 529.00.61SVP0082951Full BARTAnalysis for SO2and NOxEUBOILER1 Process Boiler #1463.3 1.5 300.00.61SVBLR.STK.T1Full BARTAnalysis for SO2and NOxEUBOILER2 Process Boiler #2463.3 1.5 300.00.61SVBLR.STK.T1Full BARTAnalysis for SO2and NOx1PM – Filterable PM only as measured by U.S. EPA Method 5 including the applicable averaging and grouping provisions, as presented in the MACTregulation, effective 10/30/2006.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 12 

# 4. Baseline Conditions and Visibility Impacts for BART Eligible Units

As indicated in U.S. EPA’s final BART guidance 24 

### , one of the factors to consider when determining

B ART 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 NO

x 

### , SO 2, 

### PM 2.5, 

### PM 10 

### , and

b ackground 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 emissions 25



### .



# 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 YY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc14Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions DataEmissionUnitIDEmissionUnitDescriptionSO2Max.24-hrActualEmissions(lb/day)Basisfor SO224-hrActualEmissionsNOx Max.24-hrActualEmissions(lb/day)Basis forNOx 24-hrActualEmissionsPM2.5Max. 24-hr ActualEmissions (lb/day)BasisforPM2.524-hrActualEmissionsPM10Max. 24-hr ActualEmissions (lb/day)BasisforPM1024-hrActualEmissionsStackNo.LatitudeLongitudeHeightofopeningfromground(ft)BaseElevationofGround(ft)Stack length,width orDiameter (ft)Flow Rateat Exit(acfm)ExitGasTemperature(F)3.AIndurating FurnacesEUKILN1Line 1PelletInduration6552.0 COAL 26,208.0Natgas3,610.1 MACTSVP005198146.44084994-87.65340738240 1474 19.3 842,000 3001,338.4 MACTSVP005171146.44075383-87.65132336160 1474 13.5 306,000 3003.BPM-Only Taconite MACT Emission UnitsEUPRIMARYCRUSHERPRIMARYCRUSHER25.7 MACTSVA001157046.43933071-87.6515277015 1474 2.5 15,400 60EUCOOLERLine 1Cooler5.9 MACTSVP002549046.43979916-87.64827887151 1474 14.0 786,000 3333.CPM-Only Other Combustion MACT EmissionUnitsEUDRYER1Line 1Dryer199.2 COAL 88.3NAT.GAS529.0 MACTSVP008295146.44075383-87.65132336119 1474 6.3 57,135 150EUBOILER1ProcessBoiler #11.5FUELOIL463.3NAT.GAS300.0 MACTSVBLR.STK.T146.44091784-87.65412418130 1474 7.5 192,000 350EUBOILER2ProcessBoiler #21.5FUELOIL463.3NAT.GAS300.0 MACTSVBLR.STK.T146.44091784-87.65412418130 1474 7.5 192,000 350Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 15 

# 4.C Facility Baseline Modeling Results

The Michigan BART modeling protocol 26 

### describes the CALPUFF model inputs, including the

m eteorological 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:

• 98 th 

### Percentile: As defined by federal guidance, a sour ce "contributes to visibility

impairment” if the 98 th 

### percentile of any year’s modeling results (i.e. 7 th 

### highest day) meets

o r 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

98 th 

### percentile of the baseline conditions exceeds the t hreshold 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

98 th

Percentile
Value (deciview) No. of

days exceeding
0.5
deciview Modeled

98 th

Percentile
Value (deciview) No. of

days exceeding
0.5
deciview Modeled

98 th

Percentile
Value (deciview) No. of

days exceeding
0.5
deciview Modeled

98 th

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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 16 

# 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 SO 2 

### and NO

x 

### :

 L ine 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 processY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 17 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. NO

x 

### is

c ontrolled through furnace design and type of fuel usage. During high ozone alert days, coal is

burned to reduce the amount of NO

x 

### generation. The SO 2 

### is controlled through furnace design and

t ype of fuel usage. Kiln 1 has a SO 2 

### limit of 28,000 lbs per day.



## 5.A.i Sulfur Dioxide Controls

There are two sources of SO 2 

### emissions from the Line 1 Indurating Furnace:

1

. SO 2 

### emissions from the trace amounts of sulfur in the i ron concentrate and binding agents

present in the green balls; and

2. SO 2 

### 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 SO 2 

### emission reduction. Within

S tep 1, the technical feasibility of the control option was also discussed and determined. The

following describes retrofit SO 2 

### control technologies that were identified as availa ble 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 18 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 SO 2 

### removal,

c austic is added to the water spray system, allowing the WWESP spray system to function as an SO 2



### a bsorber.

The SO 2 

### control efficiency for a WWESP is dependent upon va rious process specific variables, such

as SO 2 

### flue gas concentration, fuel used, and ore compositi on. 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 SO 2 

### reduction for this BART analysis.

W et Scrubbing (High and Low Efficiency)

Wet scrubbing, when applied to remove SO 2 

### , 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 SO 2 

### in the waste gas. Crushed limestone, lime, or caust ic 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 SO 2 

### wet scrubber, the scrubber would require

d esigns for removal efficiency up to 95% SO 2 

### . Typical high efficiency SO 2 

### wet scrubbers are packedb ed spray towers using a caustic scrubbing solution. Whereas, a low efficiency SO 2 

### wet scrubber

c ould have a control efficiency of 30% or lower. A low efficiency SO 2 

### scrubber could be a venturi

r od 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 SO 2 

### from the flue gas as

c ollateral emission reduction.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 19 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:

CaCO 3 

### + SO 2 

### → CaSO 3 

### • 1/2 H2O + CO 2



### C aSO 3 

### •1/2 H 2 

### O + 3H 2 

### O + O 2 

### → 2 CaSO 4 

### •2 H 2 

### O

L ime 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 

### +SO 2 

### → CaSO 3 

### • 1/2 H 2 

### O + 1/2 H 2 

### O

C a(OH) 2 

### + SO 2 

### + 1/2 O 2 

### + H 2 

### O → CaSO 4 

### •2 H 2 

### O

W hen caustic (sodium hydroxide solution) is the scrubbing agent, the SO 2 

### removal reactions are as

f ollows:

Na+ + OH- + SO 2 

### + → Na 2 

### SO 3



### 2 Na+ + 2OH- + SO 2 

### + → Na 2 

### SO 3 

### + H 2 

### O

C austic 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 SO 2 

### removal, additional

e quipment 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 SO 2 

### control efficiency range for SO 2 

### 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 SO 2 

### concentrations are

t he highest. The indurating furnace SO 2 

### concentration would be considered low due to the hi gh 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 SO 2



### c oncentration as well as creates higher flow rates to control. Additionally, the varying sulfur

concentration within the pellet causes fluctuations of the SO 2 

### concentrations in the exhaust gas

s tream. This could also impact the SO 2 

### control efficiency of the wet scrubber.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 20 Based on the information contained within this report, a wet scrubber is considered a technically

feasible technology for SO 2 

### reduction for this BART analysis.

D ry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection)

Dry sorbent injection (DSI) of lime/limestone is a post-combustion SO 2 

### control technology in which

p ulverized lime or limestone is directly injected into the duct upstream of the fabric filter. Dry

sorption of SO 2 

### onto the lime or limestone particle occurs and the solid particles are collected with a

fabric filter. Further SO 2 

### removal occurs as the flue gas flows through the fi lter cake on the bags. The

normal SO 2 

### control efficiency range for dry SO 2 

### scrubbers is 70% to 90 % for coal fired utility

b oilers. 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 SO 2 

### reduction for this BART analysis.

S pray Dryer Absorption (SDA)

Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO 2 

### is

a bsorbed by the slurry, forming CaSO 3 

### /CaSO 4 

### . The liquid-to-gas ratio is such that the water

e vaporates 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 SO 2 

### , the term flue-gas

d esulfurization (FGD) may also be used.

Based on the information contain with this report, SDA is considered a technically feasible

technology for SO 2 

### reduction for this BART analysis.

E nergy 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 21 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 SO 2 

### emissions through alternative fuel usage, the sourc e must be

capable of burning fuels with lower sulfur content than the existing fuels. Switching fuels trades one

visibility impairment pollutant (SO 2 

### ) for another (NO

x 

### ), as induration furnaces emit significantly less

N O

x 

### 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



### T herefore, 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 SO 2 

### air pollution control technology will not be furthe r 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 SO 2 

### 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 interme diate 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 22 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 SO 2 

### reduction.

I n 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 SO 2 

### control technologies that are

a vailable 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 SO 2 

### Control Technology – Availability, Applicability, a nd Technical Feasibility



### SO 2 

### 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 NoY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 23 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 SO 2 

### Control Technology Effectiveness

SO 2 

### 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



### D irect 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 manual 29 

### and engineering experience, and were

a djusted 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, E PA Air Pollution Control Cost Manual, Sixth Edition

. 30 

### U.S. EPA, C UE Cost Workbook Version 1.0 . Page 2.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 24 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 SO 2 

### 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 areY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 25 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 pollutant 31 

### . Therefore, all air

p ollution 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 SO 2 

### 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 SO 2 

### control technologies for Tilden Line 1 furnace is s o high and

31 

### Michigan Department of Environmental Quality May 12 , 2006 meeting.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 26 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 SO 2 

### control for the

L ine 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 SO 2 

### , the

e missions from the sources undergoing a full BART SO 2 

### analysis were adjusted to reflect the

p rojected 24-hour maximum SO 2 

### emission rate when applying the control technologie s 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 SO 2 

### control technologies. Table 5-6 provides a summary

of the modeling input data.Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc27Table 5-5 Post-Control Modeling ScenariosScenario Control TechnologySO2NOxControlScenarioSV #Emission UnitSO2NOx% ReductionMax24-hour lbs/hr% ReductionMax24-hour lbs/hrBaseSVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1Base SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7Base SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.32SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.33SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.36SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.37SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.310SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.811SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.814SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc28Scenario Control TechnologySO2NOxControlScenarioSV #Emission UnitSO2NOx% ReductionMax24-hour lbs/hr% ReductionMax24-hour lbs/hrSVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.815SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.818SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.419SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.422SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.423SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.426SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.727SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.7Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc29Scenario Control TechnologySO2NOxControlScenarioSV #Emission UnitSO2NOx% ReductionMax24-hour lbs/hr% ReductionMax24-hour lbs/hr30SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.731SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.7Table 5-6 Post-Control SO2Modeling Scenarios - Modeling Input DataControl ScenarioSV #Emission UnitStack LatitudeStack LongitudeHeight ofOpening fromGround(ft)Base Elevationof Ground(ft)Stack length,width, orDiameter(ft)Flow Rate at exit(acfm)Exit Temp(oF)All ScenariosSVP0051981SVP0051711EUKILN146.4408499446.44075383-87.65340738-87.65132336240160147419.313.5842,000306,000300300SVP0082951 EUDRYER1 46.44075383-87.6513233611914746.357,135 150SVBLR.STK.T1EUBOILER1EUBOILER246.44091784-87.6541241813014747.5 192,000 350Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 30 Post-Control Visibility Impacts Modeling Results

Results of the post-control visibility impacts modeling for SO 2 

### are presented in Table 5-7. The

r esults 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 NO

x 

### controls are presented in Section 6.Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc31Table 5-7 Post-Control SO2Modeling Scenarios - Visibility Modeling Results2002200320042002 – 2004CombinedScenario #Class IArea withGreatestImpactModeled98thPercentileValue(deciview)No. of daysexceeding0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewBase IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 412 IRNP 0.610 15.0 0.620 10.000 0.535 8.000 0.600 333 IRNP 0.183 0.0 0.177 0.000 0.154 0.000 0.17306 IRNP 0.619 15.0 0.623 10.000 0.528 8.000 0.598 337 IRNP 0.182 0.0 0.177 0.000 0.155 0.000 0.169010 IRNP 0.618 15.0 0.607 10.000 0.527 8.000 0.590 3311 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161014 IRNP 0.627 15.0 0.608 9.000 0.544 8.000 0.585 3215 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160018 IRNP 0.626 15.0 0.605 9.000 0.542 8.000 0.596 3219 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163022 IRNP 0.625 15.0 0.602 9.000 0.291 3.000 0.588 2723 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165026 IRNP 0.623 15.0 0.605 9.000 0.550 8.000 0.597 3227 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165030 IRNP 0.613 14.0 0.614 9.000 0.542 8.000 0.588 3131 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.1640Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc32Table 5-8 Post-Control SO2Modeling Scenarios - Visibility ImprovementsModeling Results02002200320042002-2004ScenarioLimitingClass IAreaImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dVBaseIRNP0.714 19.0 0.722 11.000 0.599 11.000 0.674 412 IRNP 0.104 4 0.102 1 0.064 3 0.074 83 IRNP 0.531 19 0.545 11 0.445 11 0.501 416 IRNP 0.095 4 0.099 1 0.071 3 0.076 87 IRNP 0.532 19 0.545 11 0.444 11 0.505 4110 IRNP 0.096 4 0.115 1 0.072 3 0.084 811 IRNP 0.538 19 0.554 11 0.449 11 0.513 4114 IRNP 0.087 4 0.114 2 0.055 3 0.089 915 IRNP 0.538 19 0.551 11 0.449 11 0.514 4118 IRNP 0.088 4 0.117 2 0.057 3 0.078 919 IRNP 0.539 19 0.549 11 0.448 11 0.511 4122 IRNP 0.089 4 0.12 2 0.308 8 0.086 1423 IRNP 0.539 19 0.552 11 0.449 11 0.509 4126 IRNP 0.091 4 0.117 2 0.049 3 0.077 927 IRNP 0.538 19 0.55 11 0.448 11 0.509 4130 IRNP 0.101 5 0.108 2 0.057 3 0.086 1031 IRNP 0.541 19 0.55 11 0.448 11 0.51 41.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 33 

## 5.A.ii Nitrogen Oxide Controls

To be able to control NO

x 

### it is important to understand how NO

x 

### is formed. There are three

m echanisms by which NO

x 

### production occurs: thermal, fuel and prompt NO

x 

### .

• F uel bound NO

x 

### is formed from fuel combustion as nitrogen compound s in the fuel are

oxidized.

• Thermal NO

x 

### 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 NO

x 

### production is a function of the residence time, fre e oxygen,

and temperature, primarily in the flame area of the furnace.

• Prompt NO

x 

### is a form of thermal NO

x 

### which is generated at the flame boundary. It is th e

result of reactions between nitrogen and carbon radicals generated during combustion. Only

minor amounts of NO

x 

### are emitted as prompt NO

x 

### .

T he majority of NO

x 

### is emitted as NO. Minor amounts of NO 2 

### are formed in the furnaces.

5 .A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies

With the understanding of how NO

x 

### is formed, available and applicable control technol ogies 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 NO

x 

### emission reduction. Within

S tep 1, the technical feasibility of the control option was also discussed and determined. The

following describes retrofit NO

x 

### control technologies that were identified as availa ble 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 NO

x 

### formation. In an external flue gas recirculation sy stem, 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 oxygenY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 34 level in the combustion zone reduces flame temperatures; which in turn reduces NO

x 

### emissions. For

t his technology to be effective, the combustion conditions must have the ability to be controlled at

the burner tip.

The normal NO

x 

### control efficiency range for EFGR is 30% to 50%.

A pplication 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 2,400 o 

### F in order to meet

p roduct 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-NO

x 

### Burners

L ow-NO

x 

### burner (LNB) technology utilizes advanced burner de sign to reduce NO

x 

### formation through

t he 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, NO

x 

### formation is limited by a rich (high

f uel) condition. Oxygen levels and flame temperatures are low; this results in less NO

x 

### formation. In

t he secondary combustion zone, incomplete combustion products formed in the primary zone act asY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 35 reducing agents. In a reducing atmosphere, nitrogen compounds are preferentially converted to

molecular nitrogen (N 2 

### ) over nitric oxide (NO). The estimated NO

x 

### control efficiency for LNB in

h igh temperature applications is 10%. Low NO

x 

### burners have been installed in the preheating secti on

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 CO 2 

### with natural gas. Water injection to cool the

b urner peak flame temperature is also being investigated. This technique has already been

successfully used for reducing NO

x 

### emissions from gas turbines and a straight-grate ta conite

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-NO

x 

### burners, combine the benefits of

f lue gas recirculation and low-NO

x 

### 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 NO

x 

### control efficiency for IFGR

b urners 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 NO

x 

### reduction, and it would adversely affect

c ombustion 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 36 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 NO

x 

### formation. However, the technology vendor will not guarantee that ported kilns will

reduce NO

x 

### emissions because controlling the oxygen in the fir ing zone is not possible due to the

flow of air from the pellet cooler 32 

### . Any reduction in NO

x 

### would be minor and incidental to the

p rocess improvement and specific to the individual furnace. Therefore, although this may be an

available and applicable technology, its NO

x 

### reduction potential is small and may be unsuccessfu l

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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 37 gas. Reduction of NO

x 

### emissions through alternative fuel usage has been a chieved 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 (NO

x 

### ) for another (SO 2 

### ). Therefore, if this option is pursued, the

i mpact 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



### H owever, 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 NO

x 

### 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 interme diate 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 38To 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 NO

x 

### reduction.

I n 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 NO

x 

### formation.

• A t some operations, the operating parameters which generally influence the rate of NO

x



### g eneration 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 NO

x



### f ormation may not be dependent upon controllable operating parameters. In the absence of

controllable parameters, process optimization would not be effective at controlling NO

x



### e missions.

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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 39 Post Combustion Controls

NO

x 

### can be controlled using add-on systems located down stream 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 NO

x 

### 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 NO

x 

### ,

u nburdened hydrocarbons (UBH), and carbon monoxide (CO). Typically, NSCR can achieve NO

x



### e mission 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, NO

x 

### is reduced by CO,

r esulting in nitrogen (N 2 

### ) and carbon dioxide (CO 2 

### ). The most important reactions for NO

x 

### removal

a re:

2CO + 2NO → 2CO 2 

### + N 2 

### (1)

[ UBH] + NO → N 2 

### + CO 2 

### + H 2 

### O (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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 40 Selective Catalytic Reduction (SCR) and Regenerative Selective Catalytic Reduction

(R-SCR)

SCR is a post-combustion NO

x 

### control technology in which ammonia (NH 3 

### ) is injected into the flue

g as stream in the presence of a catalyst. NO

x 

### is removed through the following chemical reaction:

4 NO + 4 NH 3 

### + O 2 

### → 4 N 2 

### + 6 H 2 

### O ( 1)

2 NO 2 

### + 4 NH 3 

### + O 2 

### → 3 N 2 

### + 6 H 2 

### O (2 )

A catalyst bed containing metals in the platinum family is used to lower the activation energy

required for NO

x 

### 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 SO 2 

### and particulate controls.

• R -SCR has a thermal efficiency of 70% vs. standard heat exchangers which have a thermal

efficiency of 60% to 70%.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 41 • Application of R-SCR after SO 2 

### 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 42 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

NO

x 

### . In the system, the NO

x 

### in the flue gas is oxidized to form nitrogen pentox ide (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-NO

x 

### ® and LoTOx®.

N O + O 3 

### → N O 2 

### + O 2 

### (1)

N O 2 

### + O 3 

### → N O 3 

### + O 2 

### (2)

N O 3 

### + NO 2 

### → N 2 

### O 5 

### (3)

N 2 

### O 5 

### + H 2 

### O → 2 HNO 3 

### (4)

H NO 3 

### + NaOH → N aNO 3 

### + H 2 

### O (5)

L ow Temperature Oxidation (Tri-NO

x ® 

### )

T his technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO 2 

### in a

p rimary scrubbing stage. Then NO 2 

### is removed through caustic scrubbing in a secondary stage. The

reactions are as follows:

O 3 

### + NO → O 2 

### + NO 2 

### ( 1)

2NaOH + 2NO 2 

### + 1⁄2 O 2 

### → 2NaNO 3 

### + H2O ( 2)Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 43 Tri-NO

x ® 

### is a multi-staged wet scrubbing process in industri al 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 NO 2 

### . Subsequent

s tages reduce NO 2 

### to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NO

x ® 

### is

t ypically applied at small to medium sized sources with high NO

x 

### concentration in the exhaust gas

( 1,000 ppm NO

x 

### ). NO

x 

### concentrations in the exhaust at Tilden are typical ly less than 200 ppm.

Therefore, Tri-NO

x ® 

### is not applicable to taconite processing and will n ot be analyzed further in this

BART analysis.

Low Temperature Oxidation (LoTOx ® 

### )

B OC Gases’ Lo-TOx ® 

### is an example of a version of an LTO system. LoTOx ® 

### technology uses ozone

t o oxidize NO to NO 2 

### and NO 2 

### to N 2 

### O 5 

### in a wet scrubber (absorber). This can be done in t he same

scrubber used for particulate or sulfur dioxide removal, The N 2 

### O 5 

### is converted to HNO 3 

### in a

s crubber, and is removed with lime or caustic. Ozone for LoTOx ® 

### is generated on site with an

e lectrically powered ozone generator. The ozone generation rate is controlled to match the amount

needed for NO

x 

### control. Ozone is generated from pure oxygen. In order for LoTOx ® 

### to be

e conomically 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 –

3 5,000 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 largerY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 44 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 a pplications.

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 (Fe 3 

### O 4 

### ) which would react with the

o zone to form hematite (Fe 2 

### O 3 

### ); since the ozone injection point would be before t he 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 SO 2 

### , converting the

m aterial to SO 3 

### which could result in the generation of sulfuric ac id 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 ofY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 45 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 NO

x 

### control technologies that are

a vailable 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 NO
x 

### Control Technology – Availability, Applicability, a nd Technical Feasibility



### NO

x 

### Pollution Control Technology Available? Applicable? Technically
Feasible?

External Flue Gas Recirculation (EFGR) Yes No No

Low NO

x 

### Burners (LNB) Y es 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 NoY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 46 NO

x 

### 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 NO
x 

### Control Technology Effectiveness



### NO

x 

### 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 NO

x 

### burners and SCR

w ith 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 theY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 47 existing building would not support additional equipment on the roof. The detailed cost analysis is

provided in Appendix A.

Table 5-11 Indurating Furnace NO
x 

### 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 pollutant 35 

### . Therefore, all air

p ollution 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 48 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 NO

x 

### reduction technologies are cost effective, the incr emental 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 NO
x 

### 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 NO

x 

### to form

a mmonium nitrate and
SO 2 

### to form ammonium

s ulfate 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 49 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 NO

x 

### control and the

r esulting 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 NO

x 

### , the

e missions from the sources undergoing a full BART NO

x 

### analysis were adjusted to reflect the

p rojected 24-hour maximum NO

x 

### emission rate when applying the control technologie s 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 NO

x 

### control technologies. Table 5-14 provides a

s ummary of the modeling input data.Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc50Table 5-13 Post-Control NOxModeling ScenariosScenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrBaseSVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood CombustionPractice0.0%200.272.80.0%800.9291.1Base SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7Base SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 0.1 0.0% 19.31SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 0.1 0.0% 19.33SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 0.1 0.0% 19.35SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 0.1 0.0% 19.37SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 0.1 0.0% 19.39SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.811SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc51Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrSVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.813SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.815SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.817SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.419SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.421SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.423SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.425SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.727SVP0051981 EUKILN1 Wet ScrubberSCR w/reheat80% 40.0 80% 160.2Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc52Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrSVP005171180% 14.6 80% 58.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.729SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.731SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.7Table 5-14 Post-Control NOXModeling Scenarios - Modeling Input DataControl ScenarioSV #Emission UnitStack Easting(utm)Stack Northing(utm)Height ofOpening fromGround(ft)Base Elevationof Ground(ft)Stack length,width, orDiameter(ft)Flow Rate at exit(acfm)Exit Temp(oF)All ScenariosSVP0051981SVP0051711EUKILN146.4408499446.44075383-87.65340738-87.65132336240160147419.313.5842,000306,000300300SVP0082951 EUDRYER1 46.44075383-87.6513233611914746.357,135 150SVBLR.STK.T1EUBOILER1EUBOILER246.44091784-87.6541241813014747.5 192,000 350Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 53 Post-Control Visibility Impacts Modeling Results

Results of the post-control visibility impacts modeling for NO X 

### are presented in Table 5-15. The

r esults 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 SO 2 

### controls are presented in section 6.

Table 5-15 Post-Control NO X 

### 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 0Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 54 Table 5-16 Post-Control NO X 

### Modeling Scenarios - Visibility Improvements

Modeling Results

2002 2003 2004 2002-2004

Scenario Limiting

Class I
Area Improved

Modeled
98 th

Percentile
Value ( ∆ -dV) Decreased

No. of Days exceeding
0.5 dV Improved

Modeled
98 th

Percentile
Value ( ∆ -dV) Decreased

No. of Days exceeding
0.5 dV Improved

Modeled
98 th

Percentile
Value ( ∆ -dV) Decreased

No. of Days exceeding
0.5 dV Improved

Modeled
98 th

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 41Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 55 

# 5.B Process Boilers 1 and 2

Two natural gas and fuel oil fired process boilers r equire 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 SO 2 

### emissions from these boilers. The boilers have low

emissions of SO 2 

### due to the low sulfur content of the permitted fuel s.

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 SO 2 

### emission reduction. Within

S tep 1, the technical feasibility of the control option was also discussed and determined. The

following describes retrofit SO 2 

### control technologies that were identified as availa ble 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 SO 2 

### removal,

c austic is added to the water spray system, allowing the WWESP spray system to function as an SO 2



### a bsorber.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 56 The SO 2 

### control efficiency for a WWESP is dependent upon va rious process specific variables, such

as SO 2 

### flue gas concentration and fuel used. Based on the i nformation contained within this report, a

WWESP is considered a technically feasible technology for SO 2 

### reduction for this BART analysis.

W et Scrubbing (High and Low Efficiency)

Wet scrubbing, when applied to remove SO 2 

### , 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 SO 2 

### in the waste gas. Crushed limestone, lime or Causti c 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:

CaCO 3 

### + SO 2 

### → CaSO 3 

### • 1/2 H2O + CO 2



### C aSO 3 

### •1/2 H 2 

### O + 3H 2 

### O + O 2 

### → 2 CaSO 4 

### •2 H 2 

### O

L ime 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 

### +SO 2 

### → CaSO 3 

### • 1/2 H 2 

### O + 1/2 H 2 

### O

C a(OH) 2 

### + SO 2 

### + 1/2 O 2 

### + H 2 

### O → CaSO 4 

### •2 H 2 

### O

W hen that caustic (sodium hydroxide solution) is the scrubbing agent, the SO 2 

### removal reactions are

a s follows:

Na+ + OH- + SO 2 

### + → Na 2 

### SO 3



### 2 Na+ + 2OH- + SO 2 

### + → Na 2 

### SO 3 

### + H 2 

### O

C austic 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 SO 2 

### removal, additional

e quipment 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 57 The normal SO 2 

### control efficiency range for SO 2 

### scrubbers on coal fired utility boilers is 80% to 9 0%

for low efficiency scrubbers and 90% and more for high efficiency scrubbers. The highest control

efficiencies can be achieved when SO 2 

### concentrations are the highest. The process boiler ’s exhaust

would not have a high SO 2 

### concentration, so the low end of the efficiency ran ge would be expected.

Based on the information contained within this report, a wet scrubber is considered a technically

feasible technology for SO 2 

### reduction for this BART analysis.

D ry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection)

Dry sorbent injection (DSI) of lime/limestone is a post-combustion SO 2 

### control technology in which

p ulverized lime or limestone is directly injected into the duct upstream of the fabric filter. Dry

sorption of SO 2 

### onto the lime or limestone particle occurs and the solid particles are collected with a

fabric filter. Further SO 2 

### removal occurs as the flue gas flows through the fi lter cake on the bags. The

normal SO 2 

### control efficiency range for dry SO 2 

### scrubbers is 70% to 90 % for coal fired utility

b oilers.

Based on the information contained within this report, DSI is considered a technically feasible

technology for SO 2 

### reduction for this BART analysis.

S pray Dryer Absorption (SDA)

Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO 2 

### is

a bsorbed by the slurry, forming CaSO 3 

### /CaSO 4 

### . The liquid-to-gas ratio is such that the water

e vaporates 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 SO 2 

### reduction for this BART analysis.

E nergy 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 58 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 SO 2 

### emissions through alternative fuel usage, the sourc e 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 SO 2



### e mission 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



### T herefore, 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 SO 2



### r eductions.

STEP 2 Conclusion

Based upon the determination within Step 2, the remaining SO 2 

### control technologies that are

a vailable 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): 39164Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 59 Table 5-17 Process Boiler SO 2 

### Control Technology – Availability, Applicability, a nd Technical Feasibility

SO 2 

### 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 SO 2 

### Control Technology Effectiveness

SO 2 

### 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 60 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 37 

### as shown in the following equation:

Cost of equipment A = Cost of equipment B * (capacity of A/capacity of B) 0.6



### D irect 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 manual 38 

### and engineering experience, and were adjusted for t he specific flow rates

and pollutant concentrations.

The detailed cost analysis is provided in Appendix A.

Table 5-19 Process Boilers 1 and 2 SO 2 

### 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 P lant Design and Economics for Chemical Engineers, Fifth

Edition.

38 

### U.S. EPA, January 2002, E PA Air Pollution Control Cost Manual, Sixth Edition

.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 61 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 pollutant 39 

### . Therefore, all air

p ollution 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 SO 2 

### technologies are cost effective for the process boi lers, the energy and non-air

quality impacts were not assessed for the SO 2 

### control equipment technologies for the process boil ers.

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 SO 2 

### technologies are cost effective for the process boi lers, the visibility

impacts were not evaluated.

39 

### Michigan Department of Environmental Quality May 12 , 2006 meeting.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 62 

## 5.B.ii Nitrogen Oxide Controls

To be able to control NO

x 

### it is important to understand how NO

x 

### is formed. There are three

m echanisms by which NO

x 

### production occurs: thermal, fuel and prompt NO

x 

### .

• F uel bound NO

x 

### is formed as nitrogen compounds in the fuel is oxid ized in the combustion

process.

• Thermal NO

x 

### 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 NO

x 

### production is a function of the residence time, fre e oxygen, and temperature.

• Prompt NO

x 

### is a form of thermal NO

x 

### which is generated at the flame boundary. It is th e

result of reactions between nitrogen and carbon radicals generated during combustion. Only

minor amounts of NO

x 

### are emitted as prompt NO

x 

### .

T he majority of NO

x 

### is emitted as NO. Minor amounts of NO 2 

### are formed in the boiler.

5 .B.ii.a STEP 1 – Identify All Available Retrofit Control Technologies

With the understanding of how NO

x 

### is formed, available and applicable control technol ogies 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 NO

x 

### emission reduction. Within

S tep 1, the technical feasibility of the control option was also discussed and determined. The

following describes retrofit NO

x 

### control technologies that were identified as availa ble 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 63 External Flue Gas Recirculation (EFGR)

External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures

thereby reducing thermal NO

x 

### formation. In an external flue gas recirculation sy stem, 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 NO

x 

### emissions. For

t his 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-NO

x 

### burner (LNB) technology utilizes advanced burner de sign to reduce NO

x 

### formation through

t he 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 NO

x 

### formation. In the secondary zone, combustion produc ts formed in

the primary zone act to lower the local oxygen concentration, resulting in a decrease in NO

x



### f ormation. Low NO

x 

### burners typically achieve NO

x 

### emission reductions of 25% - 50% for process

b oilers.

Based on the information contained within this report, LNB is considered a technically feasible

technology for NO

x 

### reduction for this BART analysis.

O verfire 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 NO

x 

### control technology typically

u sed in boilers and is primarily geared to reduce thermal NO

x 

### . Staging of the combustion air creates

a n initial fuel-rich combustion zone for a cooler fuel-rich combustion zone. This reduces the

production of thermal NO

x 

### by lowering peak combustion temperature and limitin g the availability ofY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 64 oxygen in the combustion zone where NO

x 

### is most likely to be formed. OFA is considered

c ompatible with the LNB. The estimated NO

x 

### control efficiency for LNB with OFA is 50-67%.

B ased on the information contained within this report, OFA with LNB is considered a technically

feasible technology for NO

x 

### reduction for this BART analysis.

I nduced Flue Gas Recirculation (IFGR)

Induced flue gas recirculation burners, also called ultra low-NO

x 

### burners, combine the benefits of

f lue gas recirculation and low-NO

x 

### 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 NO

x 

### control efficiency for IFGR

b urners in high temperature applications is 50-75%.

Based on the information contained within this report, IFGR is considered a technically feasible

technology for NO

x 

### reduction for this BART analysis.

E nergy 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 NO

x 

### emissions through alternative fuel usage, the sourc e must be

currently burning a high NO

x 

### 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 65 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



### T herefore, 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 NO

x 

### . Operating a boiler with low excess air

a lso 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

NO

x 

### can be controlled using add-on systems located down stream 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): 39164Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 66 absorbing, or adsorbing NO

x 

### 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 NO

x 

### ,

u nburdened hydrocarbons (UBH), and carbon monoxide (CO). Typically, NSCR can achieve NO

x



### e mission 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, NO

x 

### is reduced by CO,

r esulting in nitrogen (N 2 

### ) and carbon dioxide (CO 2 

### ). The most important reactions for NO

x 

### removal

a re:

2CO + 2NO → 2CO 2 

### + N 2 

### (1)

[ UBH] + NO → N 2 

### + CO 2 

### + H 2 

### O (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 NO

x 

### control technology in which ammonia (NH 3 

### ) is injected into the flue

g as stream in the presence of a catalyst. NO

x 

### is removed through the following chemical reaction:

4 NO + 4 NH 3 

### + O 2 

### → 4 N 2 

### + 6 H 2 

### O ( 1)

2 NO 2 

### + 4 NH 3 

### + O 2 

### → 3 N 2 

### + 6 H 2 

### O (2 )

A catalyst bed containing metals in the platinum family is used to lower the activation energy

required for NO

x 

### 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 67 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 SO 2 

### 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 SO 2 

### 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 68 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, N 2 

### , 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 + NH 3 

## + 1⁄4O 2 

## → N 2 

## + 3/2 

## H 2 

## O (1)

N H 3 

## + 1⁄4O 2 

## → N O + 3/2H 2 

## O (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 NO

x 

### reduction for this BART analysis.

L ow Temperature Oxidation (LTO)

The LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including

NO

x 

### . In the system, the NO

x 

### in the flue gas is oxidized to form nitrogen pentox ide (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-NO

x 

### ® and LoTOx®.

N O + O 3 

### → N O 2 

### + O 2 

### (1)Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 69 NO 2 

### + O 3 

### → N O 3 

### + O 2 

### (2)

N O 3 

### + NO 2 

### → N 2 

### O 5 

### (3)

N 2 

### O 5 

### + H 2 

### O → 2 HNO 3 

### (4)

H NO 3 

### + NaOH → N aNO 3 

### + H 2 

### O (5)

L ow Temperature Oxidation (Tri-NO

x ® 

### )

T his technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO 2 

### in a

p rimary scrubbing stage. Then NO 2 

### is removed through caustic scrubbing in a secondary stage. The

reactions are as follows:

O 3 

### + NO → O 2 

### + NO 2 

### ( 1)

2NaOH + 2NO 2 

### + 1⁄2 O 2 

### → 2NaNO 3 

### + H2O ( 2)

Tri-NO

x ® 

### is a multi-staged wet scrubbing process in industri al 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 NO 2 

### . Subsequent

s tages reduce NO 2 

### to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NO

x ® 

### is

t ypically applied at small to medium sized sources with high NO

x 

### concentration in the exhaust gas

( 1,000 ppm NO

x 

### ).

L ow Temperature Oxidation (LoTOx ® 

### )

B OC Gases’ Lo-TOx ® 

### is an example of a version of an LTO system. LoTOx ® 

### technology uses ozone

t o oxidize NO to NO 2 

### and NO 2 

### to N 2 

### O 5 

### in a wet scrubber (absorber). This can be done in t he same

scrubber used for particulate or sulfur dioxide removal, The N 2 

### O 5 

### is converted to HNO 3 

### in a

s crubber, and is removed with lime or caustic. Ozone for LoTOx ® 

### is generated on site with an

e lectrically powered ozone generator. The ozone generation rate is controlled to match the amount

needed for NO

x 

### control. Ozone is generated from pure oxygen. In order for LoTOx ® 

### to be

e conomically 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 a pplications.

Therefore, although this is an emerging technology, the limited application means that it has not beenY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 70 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 NO

x 

### control technologies that are

a vailable 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 NO
x 

### Control Technology – Availability, Applicability an d 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 71 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 NO

x 

### controls. Capital costs were

c alculated 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 72 Table 5-22 Process Boiler NO
x 

### 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.



### B ased 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 pollutant 41 

### . Therefore, all air

p ollution 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 73 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 NO

x 

### 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 NO
x 

### 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 NO X 

### control and the

r esulting 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 aY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 74 maximum 24-hour average project emission rate. In the visibility impacts NO X 

### modeling analysis,

t he emissions from the sources undergoing a full BART NO

x 

### analysis were adjusted to reflect the

p rojected 24-hour maximum NO

x 

### emission rate when applying the control technologie s 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 NO

x 

### control technologies. Table 5-25 provides a

s ummary of the modeling input data.

Post-BART Visibility Impacts Modeling Results

Results of the post-BART visibility impacts modeling for NO X 

### for the process boilers are presented

i n 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 SO 2 

### controls are presented in section 6.Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc75Table 5-27 Process Boiler Post-BART Modeling ScenariosScenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrBaseSVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood CombustionPractice0.0%200.272.80.0%800.9291.1Base SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7Base SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 0.1 0.0% 19.38SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood CombustionPractice0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.89SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.810SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.811SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.812SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood CombustionPractice0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.813SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.814SVP0051981 EUKILN1 Wet Scrubber Good Combustion 80% 40.0 0.0% 800.9Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc76Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrSVP0051711Practice80% 14.6291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.815SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.816SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood CombustionPractice0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.417SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.418SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.419SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.420SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood CombustionPractice0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.421SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc77Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrSVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.422SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.423SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.424SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood CombustionPractice0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.725SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.726SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.727SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.728SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood CombustionPractice0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.729SVP0051981 EUKILN1 Low Sulfur Coal SCR w/reheat 0.0% 200.2 80% 160.2Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc78Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrSVP0051711Natural Gas72.8 80% 58.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.730SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.731SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.7Table 5-28 Process Boiler Post-BART NOxModeling Scenarios - Modeling Input DataControl ScenarioSV #Emission UnitStack Easting(utm)Stack Northing(utm)Height ofOpening fromGround(ft)Base Elevationof Ground(ft)Stack length,width, orDiameter(ft)Flow Rate at exit(acfm)Exit Temp(oF)All ScenariosSVP0051981SVP0051711EUKILN146.4408499446.44075383-87.65340738-87.65132336240160147419.313.5842,000306,000300300SVP0082951 EUDRYER1 46.44075383-87.6513233611914746.357,135 150SVBLR.STK.T1EUBOILER1EUBOILER246.44091784-87.6541241813014747.5 192,000 350Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc79Table 5-29 Process Boiler Post-BART NOxModeling Scenarios - Visibility Modeling ResultsModeling Results2002200320042002-2004ScenarioLimitingClass IAreaModeled98%ile∆dV# daysover0.5∆dVModeled98%ile∆dV# daysover0.5∆dVModeled98%ile∆dV# daysover0.5∆dVModeled98%ile∆dV# daysover0.5∆dVBaseIRNP0.714 19.0 0.722 11.000 0.599 11.000 0.674 418 IRNP0.714 19.0 0.711 11.000 0.583 11.000 0.653 419 IRNP0.314 2.0 0.252 0.000 0.213 1.000 0.248 210 IRNP 0.618 15.0 0.607 10.000 0.527 8.000 0.590 3311 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161 012 IRNP0.719 19.0 0.693 10.000 0.592 9.000 0.654 3813 IRNP0.315 2.0 0.246 0.000 0.218 1.000 0.243 214 IRNP 0.627 15.0 0.608 9.000 0.544 8.000 0.585 3215 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160 016 IRNP0.722 19.0 0.673 10.000 0.605 9.000 0.656 3817 IRNP0.326 2.0 0.243 0.000 0.218 1.000 0.243 218 IRNP 0.626 15.0 0.605 9.000 0.542 8.000 0.596 3219 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163 020 IRNP0.734 19.0 0.692 10.000 0.605 10.000 0.654 3921 IRNP0.324 2.0 0.241 0.000 0.215 1.000 0.241 222 IRNP 0.625 15.0 0.602 9.000 0.291 3.000 0.588 2723 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165 024 IRNP0.727 19.0 0.689 10.000 0.603 10.000 0.656 3925 IRNP0.326 2.0 0.245 0.000 0.207 1.000 0.241 226 IRNP 0.623 15.0 0.605 9.000 0.550 8.000 0.597 3227 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165 028 IRNP0.704 19.0 0.672 10.000 0.606 9.000 0.657 3829 IRNP0.325 2.0 0.239 0.000 0.198 1.000 0.240 230 IRNP 0.613 14.0 0.614 9.000 0.542 8.000 0.588 3131 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.164 0Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc80Table 5-30 Process Boiler Post-BART NOxModeling Scenarios – Comparison of Visibility Modeling Results to Baseline ModelingResultsModeling Results2002200320042002-2004ScenarioLimitingClass IAreaImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. ofDaysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. ofDaysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. ofDaysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. ofDaysexceeding0.5 dV8 IRNP 0 0 0.011 0 0.016 0 0.021 09 IRNP 0.4 17 0.47 11 0.386 10 0.426 3910 IRNP 0.096 4 0.115 1 0.072 3 0.084 811 IRNP 0.538 19 0.554 11 0.449 11 0.513 4112 IRNP -0.005 0 0.029 1 0.007 2 0.02 313 IRNP 0.399 17 0.476 11 0.381 10 0.431 3914 IRNP 0.087 4 0.114 2 0.055 3 0.089 915 IRNP 0.538 19 0.551 11 0.449 11 0.514 4116 IRNP -0.008 0 0.049 1 -0.006 2 0.018 317 IRNP 0.388 17 0.479 11 0.381 10 0.431 3918 IRNP 0.088 4 0.117 2 0.057 3 0.078 919 IRNP 0.539 19 0.549 11 0.448 11 0.511 4120 IRNP -0.02 0 0.03 1 -0.006 1 0.02 221 IRNP 0.39 17 0.481 11 0.384 10 0.433 3922 IRNP 0.089 4 0.12 2 0.308 8 0.086 1423 IRNP 0.539 19 0.552 11 0.449 11 0.509 4124 IRNP -0.013 0 0.033 1 -0.004 1 0.018 225 IRNP 0.388 17 0.477 11 0.392 10 0.433 3926 IRNP 0.091 4 0.117 2 0.049 3 0.077 927 IRNP 0.538 19 0.55 11 0.448 11 0.509 4128 IRNP 0.01 0 0.05 1 -0.007 2 0.017 329 IRNP 0.389 17 0.483 11 0.401 10 0.434 3930 IRNP 0.101 5 0.108 2 0.057 3 0.086 1031 IRNP 0.541 19 0.55 11 0.448 11 0.51 41Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 81 

# 5.C Line 1 Dryer

The Line 1 Dryer requires a BART analysis. This Lin e 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 SO 2 

### emissions from the dryer. The Line 1 Dryer has low

emissions of SO 2 

### due to the low sulfur content of the permitted fuel s. In addition, collateral SO 2



### r eductions occur within the existing impingment scrubbers, and therefore the existing scrubber is

considered a low-efficiency SO 2 

### 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 SO 2 

### emission reduction. Within

S tep 1, the technical feasibility of the control option was also discussed and determined. The

following describes retrofit SO 2 

### control technologies that were identified as availa ble 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 82 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 SO 2 

### removal,

c austic is added to the water spray system, allowing the WWESP spray system to function as an SO 2



### a bsorber.

The SO 2 

### control efficiency for a WWESP is dependent upon va rious process specific variables, such

as SO 2 

### flue gas concentration and fuel used. Since Line 1 D ryer currently employs a wet scrubber

designed for removal of particulate matter, the scrubber also performs as a low efficiency SO 2 

### wet

s crubber. The addition of a WWESP would act as a polishing SO 2 

### control device and would

e xperience reduced control efficiency due to lower SO 2 

### inlet concentrations.

B ased on the information contained within this report, a WWESP is considered a technically feasible

technology for SO 2 

### reduction for this BART analysis.

W et Scrubbing (High and Low Efficiency)

Wet scrubbing, when applied to remove SO 2 

### , 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 SO 2 

### in the waste gas. Crushed limestone, lime or Causti c 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:

CaCO 3 

### + SO 2 

### → CaSO 3 

### • 1/2 H2O + CO 2



### C aSO 3 

### •1/2 H 2 

### O + 3H 2 

### O + O 2 

### → 2 CaSO 4 

### •2 H 2 

### O

L ime 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 

### +SO 2 

### → CaSO 3 

### • 1/2 H 2 

### O + 1/2 H 2 

### O

C a(OH) 2 

### + SO 2 

### + 1/2 O 2 

### + H 2 

### O → CaSO 4 

### •2 H 2 

### OY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 83 When that caustic (sodium hydroxide solution) is the scrubbing agent, the SO 2 

### removal reactions are

a s follows:

Na+ + OH- + SO 2 

### + → Na 2 

### SO 3



### 2 Na+ + 2OH- + SO 2 

### + → Na 2 

### SO 3 

### + H 2 

### O

C austic 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 SO 2 

### removal, additional

e quipment 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 SO 2 

### control efficiency range for SO 2 

### scrubbers on coal fired utility boilers is 80% to 9 0%

for low efficiency scrubbers and 90% and more for high efficiency scrubbers. The highest control

efficiencies can be achieved when SO 2 

### concentrations are the highest. The dryer and proc ess boiler’s

exhaust would not have a high SO 2 

### concentration, so the low end of the efficiency ran ge 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 SO 2 

### in the exhaust. The addition of an additional

S O 2 

### scrubber would act as a polishing SO 2 

### control device and would experience reduced control

efficiency due to lower SO 2 

### 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 SO 2 

### removal could be

a ccomplished. 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 SO 2 

### emissions. The SO 2



### e missions 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 SO 2 

### control would not be

p ossible without a study, so this option could not be selected as BART.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 84 Based on the information contained within this report, a wet scrubber is considered a technically

feasible technology for SO 2 

### reduction for this BART analysis.

D ry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection)

Dry sorbent injection (DSI) of lime/limestone is a post-combustion SO 2 

### control technology in which

p ulverized lime or limestone is directly injected into the duct upstream of the fabric filter. Dry

sorption of SO 2 

### onto the lime or limestone particle occurs and the solid particles are collected with a

fabric filter. Further SO 2 

### removal occurs as the flue gas flows through the fi lter cake on the bags. The

normal SO 2 

### control efficiency range for dry SO 2 

### scrubbers is 70% to 90 % for coal fired utility

b oilers.

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 SO 2 

### is

a bsorbed by the slurry, forming CaSO 3 

### /CaSO 4 

### . The liquid-to-gas ratio is such that the water

e vaporates 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%.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 85 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 o 

### F to 150 o 

### F and is saturated with

w ater. For comparison, a utility boiler exhaust operates at 350 o 

### F or higher and is not saturated with

w ater. 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 SO 2 

### emissions through alternative fuel usage, the sourc e 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 SO 2



### e mission 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): 39164Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 86 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 SO 2



### r eductions.

STEP 2 Conclusion

Based upon the determination within Step 2, the remaining SO 2 

### control technologies that are

a vailable 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 87 Table 5-29 Line 1 Dryer SO 2 

### Control Technology – Availability, Applicability, a nd Technical Feasibility

SO 2 

### 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 SO 2 

### Control Technology Effectiveness

SO 2 

### 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) 0.6Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 88 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 manual 43 

### and engineering experience, and were adjusted for t he 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 SO 2 

### 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, E PA Air Pollution Control Cost Manual, Sixth Edition

.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 89 impact analyses at an annualized cost of $12,000 per ton of controlled pollutant 44 

### . Therefore, all air

p ollution 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 SO 2 

### control for the Line 1 Dryer have annualized contro l

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 SO 2 

### control for the

L ine 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 SO 2 

### technologies are cost effective for the process boi lers, the visibility

impacts were not evaluated.

44 

### Michigan Department of Environmental Quality May 12 , 2006 meeting.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 90 

## 5.C.ii Nitrogen Oxide Controls

To be able to control NO

x 

### it is important to understand how NO

x 

### is formed. There are three

m echanisms by which NO

x 

### production occurs: thermal, fuel and prompt NO

x 

### .

• F uel bound NO

x 

### is formed as nitrogen compounds in the fuel is oxid ized in the combustion

process.

• Thermal NO

x 

### 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 NO

x 

### production is a function of the residence time, fre e oxygen, and temperature.

• Prompt NO

x 

### is a form of thermal NO

x 

### which is generated at the flame boundary. It is th e

result of reactions between nitrogen and carbon radicals generated during combustion. Only

minor amounts of NO

x 

### are emitted as prompt NO

x 

### .

T he majority of NO

x 

### is emitted as NO. Minor amounts of NO 2 

### are formed in the dryer.

5 .C.ii.a STEP 1 – Identify All Available Retrofit Control Technologies

With the understanding of how NO

x 

### is formed, available and applicable control technol ogies 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 NO

x 

### emission reduction. Within

S tep 1, the technical feasibility of the control option was also discussed and determined. The

following describes retrofit NO

x 

### control technologies that were identified as availa ble 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 91 External Flue Gas Recirculation (EFGR)

External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures

thereby reducing thermal NO

x 

### formation. In an external flue gas recirculation sy stem, 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 NO

x 

### emissions. For

t his 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-NO

x 

### burner (LNB) technology utilizes advanced burner de sign to reduce NO

x 

### formation through

t he 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 NO

x 

### formation. In the secondary zone, combustion produc ts formed in

the primary zone act to lower the local oxygen concentration, resulting in a decrease in NO

x



### f ormation. Low NO

x 

### burners typically achieve NO

x 

### emission reductions of 25% - 50% for process

b oilers.

Based on the information contained within this report, LNB is considered a technically feasible

technology for NO

x 

### reduction for this BART analysis.

O verfire 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 NO

x 

### control technology typically

u sed in boilers and is primarily geared to reduce thermal NO

x 

### . Staging of the combustion air creates

a n initial fuel-rich combustion zone for a cooler fuel-rich combustion zone. This reduces the

production of thermal NO

x 

### by lowering peak combustion temperature and limitin g the availability ofY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 92 oxygen in the combustion zone where NO

x 

### is most likely to be formed. OFA is considered

c ompatible with the LNB. The estimated NO

x 

### control efficiency for LNB with OFA is 50-67%.

B ased on the information contained within this report, OFA with LNB is considered a technically

feasible technology for NO

x 

### reduction for this BART analysis.

I nduced Flue Gas Recirculation (IFGR)

Induced flue gas recirculation burners, also called ultra low-NO

x 

### burners, combine the benefits of

f lue gas recirculation and low-NO

x 

### 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 NO

x 

### control efficiency for IFGR

b urners in high temperature applications is 50-75%.

Based on the information contained within this report, IFGR is considered a technically feasible

technology for NO

x 

### reduction for this BART analysis.

E nergy 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 NO

x 

### emissions through alternative fuel usage, the sourc e must be

currently burning a high NO

x 

### 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 93 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



### T herefore, 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 NO

x 

### . Operating a burner with low excess air

a lso 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

NO

x 

### can be controlled using add-on systems located down stream 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): 39164Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 94 absorbing, or adsorbing NO

x 

### 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 NO

x 

### ,

u nburdened hydrocarbons (UBH), and carbon monoxide (CO). Typically, NSCR can achieve NO

x



### e mission 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, NO

x 

### is reduced by CO,

r esulting in nitrogen (N 2 

### ) and carbon dioxide (CO 2 

### ). The most important reactions for NO

x 

### removal

a re:

2CO + 2NO → 2CO 2 

### + N 2 

### (1)

[ UBH] + NO → N 2 

### + CO 2 

### + H 2 

### O (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 NO

x 

### control technology in which ammonia (NH 3 

### ) is injected into the flue

g as stream in the presence of a catalyst. NO

x 

### is removed through the following chemical reaction:

4 NO + 4 NH 3 

### + O 2 

### → 4 N 2 

### + 6 H 2 

### O ( 1)

2 NO 2 

### + 4 NH 3 

### + O 2 

### → 3 N 2 

### + 6 H 2 

### O (2 )

A catalyst bed containing metals in the platinum family is used to lower the activation energy

required for NO

x 

### 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 95 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 SO 2 

### 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 SO 2 

### 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 96 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, N 2 

### , 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 + NH 3 

## + 1⁄4O 2 

## → N 2 

## + 3/2 

## H 2 

## O (1)

N H 3 

## + 1⁄4O 2 

## → N O + 3/2H 2 

## O (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 NO

x 

### reduction for this BART analysis.

L ow Temperature Oxidation (LTO)

The LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including

NO

x 

### . In the system, the NO

x 

### in the flue gas is oxidized to form nitrogen pentox ide (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-NO

x 

### ® and LoTOx®.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 97 NO + O 3 

### → N O 2 

### + O 2 

### (1)

N O 2 

### + O 3 

### → N O 3 

### + O 2 

### (2)

N O 3 

### + NO 2 

### → N 2 

### O 5 

### (3)

N 2 

### O 5 

### + H 2 

### O → 2 HNO 3 

### (4)

H NO 3 

### + NaOH → N aNO 3 

### + H 2 

### O (5)

L ow Temperature Oxidation (Tri-NO

x ® 

### )

T his technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO 2 

### in a

p rimary scrubbing stage. Then NO 2 

### is removed through caustic scrubbing in a secondary stage. The

reactions are as follows:

O 3 

### + NO → O 2 

### + NO 2 

### ( 1)

2NaOH + 2NO 2 

### + 1⁄2 O 2 

### → 2NaNO 3 

### + H2O ( 2)

Tri-NO

x ® 

### is a multi-staged wet scrubbing process in industri al 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 NO 2 

### . Subsequent

s tages reduce NO 2 

### to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NO

x ® 

### is

t ypically applied at small to medium sized sources with high NO

x 

### concentration in the exhaust gas

( 1,000 ppm NO

x 

### ).

L ow Temperature Oxidation (LoTOx ® 

### )

B OC Gases’ Lo-TOx ® 

### is an example of a version of an LTO system. LoTOx ® 

### technology uses ozone

t o oxidize NO to NO 2 

### and NO 2 

### to N 2 

### O 5 

### in a wet scrubber (absorber). This can be done in t he same

scrubber used for particulate or sulfur dioxide removal, The N 2 

### O 5 

### is converted to HNO 3 

### in a

s crubber, and is removed with lime or caustic. Ozone for LoTOx ® 

### is generated on site with an

e lectrically powered ozone generator. The ozone generation rate is controlled to match the amount

needed for NO

x 

### control. Ozone is generated from pure oxygen. In order for LoTOx ® 

### to be

e conomically feasible, a source of low cost oxygen must be available from a pipeline or on site

generation.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 98 In addition, only two of BOC’s LoTOx ® 

### installations are fully installed and operational a pplications.

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 NO

x 

### control technologies that are

a vailable 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 NO
x 

### Control Technology – Availability, Applicability an d 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 99 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 NO

x 

### controls. Capital costs were

c alculated 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 100 Table 5-34 Line 1 Dryer NO
x 

### 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 pollutant 46 

### . Therefore, all air

p ollution 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 101 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 NO

x 

### control technologies for the Line 1 Dryer is so hig h 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 NO
x 

### 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 NO X 

### control and the

r esulting 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 NO X 

### modeling analysis,

t he emissions from the sources undergoing a full BART NO

x 

### analysis were adjusted to reflect the

p rojected 24-hour maximum NO

x 

### emission rate when applying the control technologie s 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 andY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 102 their computational basis for the evaluated NO

x 

### control technologies. Table 5-37 provides a

s ummary of the modeling input data.

Post-BART Visibility Impacts Modeling Results

Results of the post-BART visibility impacts modeling for NO X 

### for the process boilers are presented

i n 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 SO 2 

### controls are presented in section 6.Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc103Table 5-36 Line 1 Dryer Post-BART Modeling ScenariosScenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrBaseSVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1Base SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7Base SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.31SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.33SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.34SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.35SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.36SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilLNB0.0% 8.3 50.0% 1.8Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc104Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrNatural GasSVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.37SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.38SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.89SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.810SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.811SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.8Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc105Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hr12SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.813SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.814SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.815SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.816SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.417SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1 EUBOILER1 Low Sulfur FuelLNB w/OFA0.0% 0.1 67.0% 6.4Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc106Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrEUBOILER2OilNatural Gas18SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.419SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.420SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.421SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.422SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.423SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilLNB0.0% 8.3 50.0% 1.8Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc107Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrNatural GasSVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.424SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.725SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.726SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.727SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.728SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.729SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc108Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrSVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.730SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.731SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.7Table 5-37 Line 1 Dryer Post-BART NOxModeling Scenarios - Modeling Input DataControl ScenarioSV #Emission UnitStack Easting(utm)Stack Northing(utm)Height ofOpening fromGround(ft)Base Elevationof Ground(ft)Stack length,width, orDiameter(ft)Flow Rate at exit(acfm)Exit Temp(oF)All ScenariosSVP0051981SVP0051711EUKILN146.4408499446.44075383-87.65340738-87.65132336240160147419.313.5842,000306,000300300SVP0082951 EUDRYER1 46.44075383-87.6513233611914746.357,135 150SVBLR.STK.T1EUBOILER1EUBOILER246.44091784-87.6541241813014747.5 192,000 350Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 109 Table 5-38 Line 1 Dryer Post-BART NO
x 

### 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 0Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 110 Table 5-39 Line 1 Dryer Post-BART NO
x 

### Modeling Scenarios – Comparison of Visibility

M odeling Results to Baseline Modeling Results

Modeling Results

2002 2003 2004 2002-2004

Scenario Limiting

Class I
Area Improved

Modeled
98 th

Percentile
Value ( ∆ -dV) Decreased

No. of Days exceeding
0.5 dV Improved

Modeled
98 th

Percentile
Value ( ∆ -dV) Decreased

No. of Days exceeding
0.5 dV Improved

Modeled
98 th

Percentile
Value ( ∆ -dV) Decreased

No. of Days exceeding
0.5 dV Improved

Modeled
98 th

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 41Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 111 

# 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

SO 2 

### and NO

x 

### controls, and estimates the resulting degree of vis ibility improvement.



# 6.A Post-Control Modeling Scenarios

Steps 1-4 of the BART analysis identified the contro l 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 NO

x 

### , SO 2 

### and PM 10 

### can play a large part

i n 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 NO

x 

### controls. In addition,

t wo 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 p resented 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 modelingY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 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.Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc113Table 6-1 Post-Control Modeling ScenariosScenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrBaseSVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1Base SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7Base SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.31SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.32SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.33SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.34SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.35SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilLNB0.0% 8.3 50.0% 1.8Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc114Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrNatural GasSVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.36SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.37SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.38SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.89SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.810SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.811SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc115Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrSVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.812SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.813SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.814SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.815SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.816SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.4Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc116Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hr17SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.418SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.419SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.420SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.421SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.422SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1 EUBOILER1 Low Sulfur FuelLNB w/OFA0.0% 0.1 67.0% 6.4Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc117Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrEUBOILER2OilNatural Gas23SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.424SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.725SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.726SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.727SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.728SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilLNB0.0% 8.3 50.0% 1.8Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc118Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrNatural GasSVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.729SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.730SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.731SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.7Table 6-2 Post-Control NOXModeling Scenarios - Modeling Input DataControl ScenarioSV #Emission UnitStack Easting(utm)Stack Northing(utm)Height ofOpening fromGround(ft)Base Elevationof Ground(ft)Stack length,width, orDiameter(ft)Flow Rate at exit(acfm)Exit Temp(oF)All ScenariosSVP0051981SVP0051711EUKILN146.4408499446.44075383-87.65340738-87.65132336240160147419.313.5842,000306,000300300SVP0082951 EUDRYER1 46.44075383-87.6513233611914746.357,135 150SVBLR.STK.T1EUBOILER1EUBOILER246.44091784-87.6541241813014747.5 192,000 350Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 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 0Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

### 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
98 th

Percentile
Value ( ∆ -dV) Decreased

No. of Days exceeding
0.5 dV Improved

Modeled
98 th

Percentile
Value ( ∆ -dV) Decreased

No. of Days exceeding
0.5 dV Improved

Modeled
98 th

Percentile
Value ( ∆ -dV) Decreased

No. of Days exceeding
0.5 dV Improved

Modeled
98 th

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 41Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc121Table 6-5 Post-Control Modeling Results – Dollars per Deciview ImprovementScenario Control TechnologyControl ScenarioSV #Emission UnitSO2NOxAnnualized Cost($/yr)ImprovedModeled 98thPercentileValue (∆-dV)$/dVBaseSVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasGood CombustionPracticeBase SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeBase SVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasGood CombustionPractice1SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasSCR w/reheat$31,055,5810.447$69,475,573SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasGood CombustionPractice2SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice$6,048,5400.104$58,159,038SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasGood CombustionPractice3SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,104,1220.545$68,080,958SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasGood CombustionPractice4SVP0051981SVP0051711EUKILN1Low SulfurCoalGood CombustionPractice$61,0700.01$6,107,000Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc122Scenario Control TechnologyControl ScenarioSV #Emission UnitSO2NOxAnnualized Cost($/yr)ImprovedModeled 98thPercentileValue (∆-dV)$/dVNatural GasSVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasGood CombustionPractice5SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,165,1920.466$79,753,630SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasGood CombustionPractice6SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice$6,048,5400.099$61,493,020SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasGood CombustionPractice7SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,104,1210.545$68,153,011SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasGood CombustionPractice8SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasGood CombustionPractice$303,7580.016$18,984,875SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/FGR9SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasSCR w/reheat$31,055,5810.47$66,652,096SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeY:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc123Scenario Control TechnologyControl ScenarioSV #Emission UnitSO2NOxAnnualized Cost($/yr)ImprovedModeled 98thPercentileValue (∆-dV)$/dVSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/FGR10SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice$6,352,2980.115$55,237,373SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/FGR11SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,407,8800.554$67,523,250SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/FGR12SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasGood CombustionPractice$364,8280.029$12,580,275SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/FGR13SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasSCR w/reheat$31,420,4090.476$66,009,262SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/FGR14SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice$6,413,3680.114$56,257,614SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/FGR15 SVP0051981 EUKILN1 Wet Scrubber SCR w/reheat$37,165,1920.551$67,450,439Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc124Scenario Control TechnologyControl ScenarioSV #Emission UnitSO2NOxAnnualized Cost($/yr)ImprovedModeled 98thPercentileValue (∆-dV)$/dVSVP0051711SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/FGR16SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasGood CombustionPractice$390,7510.049$7,974,510SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/OFA17SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasSCR w/reheat$31,446,3330.479$65,649,965SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/OFA18SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice$6,439,2910.117$55,036,675SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/OFA19SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,494,8730.549$68,296,672SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/OFA20SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasGood CombustionPractice$451,8210.03$15,060,700SVP0082951 EUDRYER1Low SulfurFuel OilLNBY:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc125Scenario Control TechnologyControl ScenarioSV #Emission UnitSO2NOxAnnualized Cost($/yr)ImprovedModeled 98thPercentileValue (∆-dV)$/dVNatural GasSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/OFA21SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasSCR w/reheat$31,507,4030.481$65,503,956SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/OFA22SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice$6,500,3620.12$54,169,683SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/OFA23SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,555,9420.552$68,036,127SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/OFA24SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasGood CombustionPractice$286,9680.033$8,696,000SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB25SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,391,0890.477$78,388,027SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNBY:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc126Scenario Control TechnologyControl ScenarioSV #Emission UnitSO2NOxAnnualized Cost($/yr)ImprovedModeled 98thPercentileValue (∆-dV)$/dV26SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice$6,335,5080.117$54,149,641SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB27SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,391,0890.55$67,983,798SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB28SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasGood CombustionPractice$348,0380.05$6,960,760SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB29SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasSCR w/reheat$31,403,6190.483$65,017,845SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB30SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice$6,396,5780.108$59,227,574SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB31SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,452,1590.55$68,094,834SVP0082951 EUDRYER1Low SulfurFuel OilLNBY:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc127Scenario Control TechnologyControl ScenarioSV #Emission UnitSO2NOxAnnualized Cost($/yr)ImprovedModeled 98thPercentileValue (∆-dV)$/dVNatural GasSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNBY:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (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 SO 2 

### , add-on controls are not cost effective. Therefore , BART is determined to be existing

controls. The corresponding SO 2 

### emissions limit is 28,000 lb per day for Line 1 whe n coal is burned.

For NO

x 

### , the reduction due to good combustion practices on Line 1 is selected as BART. Other addon controls for NO

x 

### 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 SO 2 

### , add-on controls are not cost effective. Therefore , BART is determined to be existing

controls. The corresponding SO 2 

### 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 NO

x 

### , the reduction due to good combustion practices is selected as BART. Other add-on controls

for NO

x 

### are not cost effective.

F or 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 SO 2 

### , add-on controls are not cost effective. Therefore , BART is determined to be existing

controls. The corresponding SO 2 

### 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 NO

x 

### , the reduction due to good combustion practices is selected as BART. Other add-on controls

for NO

x 

### are not cost effective.Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (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.Michigan Operations - West (Tilden)12/28/2006BART Report - Attachment A: Emission Control Cost AnalysisTable A.1: Grate Kiln Cost SummaryNOxControl Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled Capital Cost$Annualized Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonSelective CatalyticReduction with Reheat80% 9233690$65,492,092$31,055,581$8,416n/aSO2Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled Capital Cost$Annualized Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonSpray Dry Baghouse 90% 115.3 1037.8 $167,260,397 $23,254,882$22,407n/aWet Scrubber (Absorber)(after existing ESP)80% 230.6922.5$34,869,327$6,048,540$6,557n/aSecondary Wet WalledElectrostatic Precipitator(WWESP)(after existing ESP)80% 230.6922.5$52,638,755$13,922,184$15,091n/aDSI Baghouse55% 518.9634.2$42,082,032$9,975,786$15,729n/aY:\22\52\080 Tilden BART\BART report\Appendix\Appendix A Tilden Furnace Control Costs.xlsCost SummaryPage 1 of 112/28/2006Michigan Operations - West (Tilden)12/27/2006BART Report - Attachment A: Emission Control Cost AnalysisTable A.1: Process Boilers 1 and 2 and Line 1 Dryer Cost SummaryNOxControl Cost SummaryControl TechnologyControl Eff%ControlledEmissionsT/yEmissionReductionT/yrInstalledCapital Cost $AnnualizedCost$/yrPollutionControlCost $/tonIncrementalCostSelective Catalytic Reduction (SCR) with ReheatProcess Boilers #1 and #280%15.8563.38$6,317,686$2,528,225$39,888n/aLine 1 Dryer80% 3.02 12.08 $6,439,029 $1,008,211 $83,472n/aLow NOXBurner / Flue Gas RecirculationProcess Boilers #1 and #275%19.8159.42$2,190,300$303,758$5,112n/aLine 1 Dryer75% 3.77 11.32 $1,087,058 $134,645 $11,891$19,493Regenerative Selective Catalytic Reduction (R-SCR)Process Boilers #1 and #270%23.7755.46$16,117,290$3,303,391$59,563n/aLine 1 Dryer70% 4.53 10.57 $5,445,064 $1,024,459 $96,934n/aLow NOXBurner / Overfire Air (OFA)Process Boilers #1 and #267%26.1553.08$3,031,714$390,751$7,361naLine 1 Dryer67% 4.98 10.12 $888,317 $116,686 $11,535$21,669Low NOXBurnerProcess Boilers #1 and #250%39.6139.61$1,320,909$286,968$7,244n/aLine 1 Dryer50% 7.55 7.55 $432,579 $61,070 $8,090n/aSelective Non-Catalytic Reduction (SNCR)Process Boilers #1 and #250%39.6139.61$1,501,420$468,772$11,833n/aLine 1 Dryer50% 7.55 7.55 $915,968 $278,929 $36,949n/aSO2Control Cost SummaryControl TechnologyControl Eff%ControlledEmissionsT/yEmissionReductionT/yrInstalledCapital Cost $AnnualizedCost$/yrPollutionControlCost $/tonIncrementalCostSpray Dry BaghouseProcess Boilers #1 and #290%0.030.23$56,323,180$8,640,697$38,403,097n/aLine 1 Dryer90% 0.03 0.23 $26,617,360 $4,025,029 $17,889,019n/aWet ScrubberProcess Boilers #1 and #280%0.050.20$9,309,297$1,489,576$7,447,882n/aLine 1 Dryer80% 6.81 27.26 $3,898,490 $684,207 $25,103n/aWet ESP (WWESP)Process Boilers #1 and #280%0.050.20$17,123,526$3,146,592$15,732,959n/aLine 1 Dryer80% 6.81 27.26 $7,674,618 $1,429,065 $52,432n/aDSI BaghouseProcess Boilers #1 and #255%0.110.14$32,010,048$4,892,432$35,581,325n/aLine 1 Dryer55% 0.04 0.14 $26,023,184 $4,079,117 $29,666,302n/aY:\22\52\080 Tilden BART\BART report\Appendix\Appendix A Tilden Process Boilers Control Costs.xlsCost Summary1 of 112/28/2006Michigan Operations - West (Tilden)BART Report - Changes to MDEQ BART Modeling ProtocolAppendix BCALMETVariableDescriptionValueDefaultCommentsNX Number of X grid cells66 n/aNY Number of Y grid cells39 n/aXORIGKM Reference point coordinates for grid180 n/aYORIGKM Reference point coordinates for grid612 n/aNOOBS No Observation Mode0 Y Include Surface, Upper Air and Precipitation ObservationsNSSTA Number of Surface Stations88 n/a 88 surface weather stationsNPSTA Number of Precipitation Stations99 n/a 99 precipitation stationsInput Group 5BIAS Surface/upper-air weighting factors-1, 11*0 12*0 Surface Layer is set to -1 since IEXTRP=-1ITPROG 3D temperature from observations or from prognostic data?0 Y Inclusion of Surface and Upper AirCALPUFFVariableDescriptionValueDefaultCommentsNX Number of X grid cells in met grid66 n/aNY Number of Y grid cells in met grid39 n/aXORIGKM Reference point coordinates for met grid180 n/aYORIGKM Reference point coordinates for met grid612 n/aIBCOMP X index of LL corner1 n/aJBCOMP Y index of LL corner1 n/aIECOMP X index of UR corner66 n/aJECOMPY index of UR corner39n/aInput Group 2Input Group 4Input Group 6Input Group 4Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix B Changes to MDEQ BART Modeling Protocol (WEST).xlsSheet11 of 112/28/2006Cleveland Cliffs Michigan Operations - Taconite BART AnalysisSO2 ControlIndurating FurnacesAvailable and Applicable ReviewRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Taconite BART Report and shouldnot be distributed without the full text of the report so that theinformation is not taken out of context.

Reference No. 1SO2Pollution ControlTechnology2 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?ApproximateControlEfficiencyCommentsBasic Principle1Wet Scrubbing (HighEfficiency)YYYY 90-95%Absorption and reaction using an alkaline reagent to produce a solid compound2Wet Scrubbing (LowEfficiency)YYYY<50%Absorption and reaction using an alkaline reagent to produce a solid compound3Wet Walled ElectrostaticPrecipitator (WWESP)YYYY80%Suspended particles are separated from the flue gas stream, attracted to plates, andcollected in hoppers4 Dry sorbent injectionY Y Y Y<55%Pulverized lime or limestone is directly injected into the duct upstream of thefabric filter. Dry sorption of SO2onto the lime or limestone particle occurs and thesolid particles are collected with a fabric filter5 Spray Dryer Absorption (SDA)Y Y Y Y<90%Lime slurry is sprayed into an absorption tower where SO2is absorbed by theslurry, forming CaSO3/CaSO46 Alternative FuelsYYY(for furnacescapable ofmultiple fuels)Y(not requiredby BART)Site-specificNatural gas is base caseUse a fuel with lower sulfur content.7 Load ReductionN------------Power plant technologyThis is a strategy to reduce load on a power plant by reducing the electricaldemand throught efficiency projects.8 Energy Efficiency ProjectsYYY(for largeprojects likeheat-recoup)Y(for largeprojects likeheat-recoup)Site-specificdecrease amount of fuel required to make an acceptable product9 Coal ProcessingYN---------Applies only to facilities that burn coalDry coal will increase the as-burned BTU value, and therefore less fuel is requiredto be burned. Specific energy efficiency project10 Bio FiltersN ------------Research levelGas stream passes through a packed bed of specially engineered biomedia whichsupports the growth of active bacterial species. The pollutants in the gas streamare biodegraded or biotransformed into innocuous products, such as carbondioxide, water, chlor11CANSOLV Regenerable SO2N------------Research levelAn aqueous solution of proprietary diamine captures SO2from the feed gas in acountercurrent absorption tower. The rich solvent is regenerated by steamstripping, giving a byproduct of pure, water saturated SO2gas and lean solvent forrecycling to the a12 Pahlman ProcessN------------Research levelGas stream is passed through a filter baghouse in which specially-developed, smallparticle, high-surface area metal oxide sorbent have been deployed. Pollutants areremoved from the gases by adsorption.Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Furnaces.xls1 of 212/28/2006Cleveland Cliffs Michigan Operations - Taconite BART AnalysisSO2 ControlIndurating FurnacesAvailable and Applicable ReviewRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Taconite BART Report and shouldnot be distributed without the full text of the report so that theinformation is not taken out of context.

Reference No. 1SO2Pollution ControlTechnology2 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?ApproximateControlEfficiencyCommentsBasic Principle13 SOx-NOx-Rox-BoxN ------------Technology has not been demonstratedDry sorbent injection upstream of the baghouse for removal of SOx and ammoniainjection upstream of a zeolitic selective catalytic reduction (SCR) catalystincorporated in the baghouse to reduce NOx emissions.14 Electron (E-Beam) ProcessN------------No operating commercial applications oncoalElectron beam irradiation in the presence of ammonia to initiate chemicalconversion of sulfur and nitrogen oxides into components which can be easilycollected by conventional methods such as an ESP or baghouse.15 Electrocatalytic OxidationN------------Similar to cold plasma. Will keep watchfor availability of this technologyUtilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogendioxide (NO2), sulfuric acid, and mercuric oxide respectively using non-thermalplasma.On recent project, the vender was doing final trials on full-scale applications.16NOXSON------------Commercial version of adsorption. Limitedexperience (proof-of-concept tests).Uses a regenerable sorbent to simultaneously adsorb SO2and NOx from flue gasfrom coal-fired utility and industrial boilers. In the process, the SO2is convertedto a saleable sulfur by-product (liquid SO2, elemental sulfur, or sulfuric acid) andthe NOx17 Copper-OxideN------------Absorption and SCR. Experience limited topilot scale.SO2in the flue gas reacts with copper oxide, supported on small spheres ofalumina, to form copper sulfate. Ammonia is injected into the flue gas before theabsorption reactor and a selective catalytic reduction-type reaction occurs thatreduces the nitr18SNOXN------------Early commercial development stageCatalytic reduction of NOx in the presence of ammonia (NH3), followed bycatalytic oxidation of SO2to SO3. The exit gas from the SO3converter passesthrough a novel glass-tube condenser in which the SO3is hydrated to H2SO4vaporand then condensed to a19 Cold PlasmaN ------------Research level1) 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 ReportsY:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Furnaces.xls2 of 212/28/2006Cleveland Cliffs Michigan Operations BART AnalysisSO2 ControlProcess BoilersAvailable and Applicable ReviewDRAFTRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Process Boiler BART Report and should not be distributedwithout the full text of the report so that the information is not taken out of context.

Reference No. 1SO2Pollution ControlTechnology2Is this agenerallyavailablecontroltechnology?Is the controltechnologyavailable topower boilers?Is the controltechnologyapplicable tothis specificsource?Is it technicallyfeasible for thissource?CommentsBasic Principle1Wet Scrubbing (HighEfficiency)YesYesYesYesAbsorption and reaction using an alkaline reagent to produce a solid compound2Wet Scrubbing (LowEfficiency)YesYesYesYesAbsorption and reaction using an alkaline reagent to produce a solid compound3Wet Walled ElectrostaticPrecipitator (WWESP)YesYesYesYesExisting fabric filtercontrolSuspended particles are separated from the flue gas stream, attracted to plates, and collected inhoppers4 Dry sorbent injection YesYesYesYesPulverized lime or limestone is directly injected into the duct upstream of the fabric filter. Drysorption of SO2onto the lime or limestone particle occurs and thesolid particles are collected witha fabric filter5Spray Dryer Absorption(SDA)YesYesYesYesLime slurry is sprayed into an absorption tower where SO2is absorbed by the slurry, formingCaSO3/CaSO46 Alternative FuelsYesYesYesYes (notrequired byBART)Not permitted forother fuels.Use a fuel with lower sulfur content.7 Load ReductionYesYesNo---Could reduceproductionThis is a strategy to reduce load on a power plant by reducing the electrical demand throughefficiency projects.8 Energy Efficiency Projects YesYesYesYesDecrease amount of fuel required to make an acceptable product9 Coal DryingYesYesNo---Requires availableexcess heat sourceDry coal will increase the as-burned BTU value, and therefore less fuel is required to be burned.Specific energy efficiency project10Bio FiltersNo--------- Research levelGas stream passes through a packed bed of specially engineered biomedia which supports thegrowth of active bacterial species. The pollutants in the gas stream are biodegraded orbiotransformed into innocuous products, such as carbon dioxide, water, chloride ion in water,sulfate or nitrate ions in water.11CANSOLV Regenerable SO2No--------- Research levelAn aqueous solution of proprietary diamine captures SO2from the feed gas in a countercurrentabsorption tower. The rich solvent is regenerated by steam stripping, giving a byproduct of pure,water saturated SO2gas and lean solvent for recycling to the absorber.12 Pahlman ProcessNo--------- Research levelGas stream is passed through a filter baghouse in which specially-developed, small-particle, highsurface area metal oxide sorbent have been deployed. Pollutants are removed from the gases byadsorption.Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Process Boilers.xlsSOx Process Boilers1 of 312/28/2006Cleveland Cliffs Michigan Operations BART AnalysisSO2 ControlProcess BoilersAvailable and Applicable ReviewDRAFTRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Process Boiler BART Report and should not be distributedwithout the full text of the report so that the information is not taken out of context.

Reference No. 1SO2Pollution ControlTechnology2Is this agenerallyavailablecontroltechnology?Is the controltechnologyavailable topower boilers?Is the controltechnologyapplicable tothis specificsource?Is it technicallyfeasible for thissource?CommentsBasic Principle13 SOx-NOx-Rox-BoxNo---------Technology has notbeen demonstratedDry sorbent injection upstream of the baghouse for removal of SOx and ammonia injectionupstream of a zeolitic selective catalytic reduction (SCR) catalyst incorporated in the baghouse toreduce NOx emissions.14 Electron (E-Beam) Process No---------No operatingcommercialapplications on coalElectron beam irradiation in the presence of ammonia to initiate chemical conversion of sulfur andnitrogen oxides into components which can be easily collected by conventional methods such asan ESP or baghouse.15 Electrocatalytic Oxidation No---------Similar to coldplasma. Will keepwatch for availabilityof this technologyUtilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogen dioxide(NO2), sulfuricacid, and mercuric oxide respectively using non-thermal plasma.On recent project, the vender was doing final trials on full-scale applications.16NOXSONo---------Commercial versionof adsorption.Limited experience(proof-of-concepttests).Uses a regenerable sorbent to simultaneously adsorb SO2and NOx from flue gas from coal-firedutility and industrial boilers. In the process, the SO2is converted to a saleable sulfur by-product(liquid SO2, elemental sulfur, or sulfuric acid) and the NOx isconverted to nitrogen and oxygen.17 Copper-OxideNo---------Absorption and SCR.Experience limited topilot scale.SO2in the flue gas reacts with copper oxide, supportedon small spheres of alumina, to formcopper sulfate. Ammonia is injected into the flue gas before the absorption reactor and a selectivecatalytic reduction-type reaction occurs that reduces the nitric oxides in the flue gas. In theregeneration step, the copper sulfate is reduced in a regenerator with a reducing agent, such asnatural gas, producing a concentrated stream of SO2.18SNOXNo---------Early commercialdevelopment stageCatalytic reduction of NOx in the presence of ammonia (NH3), followed by catalytic oxidation ofSO2to SO3. The exit gas from the SO3converter passes through a novel glass-tube condenser inwhich the SO3is hydrated to H2SO4vapor and then condensed to a concentrated liquid sulfuricacid (H2SO4).19 Cold PlasmaNo--------- Research level1) 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.xlsSOx Process Boilers2 of 312/28/2006Cleveland Cliffs Michigan Operations BART AnalysisSO2 ControlProcess BoilersAvailable and Applicable ReviewDRAFTRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Process Boiler BART Report and should not be distributedwithout the full text of the report so that the information is not taken out of context.

Reference No. 1SO2Pollution ControlTechnology2Is this agenerallyavailablecontroltechnology?Is the controltechnologyavailable topower boilers?Is the controltechnologyapplicable tothis specificsource?Is it technicallyfeasible for thissource?CommentsBasic Principle2) 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.htmc) New and Emerging Environmental Technologies, http://neet.rti.org/d) ND BART ReportsY:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Process Boilers.xlsSOx Process Boilers3 of 312/28/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlDryerAvailableandApplicableReviewRevised:December1,2006OverfircAir(OFA)YesYesYesYesCombustionairisseparatedintoprimaryandsecondaryflowsectionstoachievecompleteburnoutandtoencouragetheformationofN2ratherthanNOx2ExternalFlueGasYesYesYesNoMixesfluegaswithcombustionairwhichreducesoxygencontentandthereforeRecirculation(EFGR)reducesflametemperature3Low-NOxBurnersYesYesYesYesBurnersaredesignedtoreduceNOxformationthroughrestrictionofoxygen,flametemperature,and/orresidencetimeInducedFlueGasNeedtobeupfired.Need4RecirculationBurnersYesYesYesYesconvectivelooptogetgasDrawsfluegastodilutethefuelinordertoreducetheflametemperaturerecirculated5LowExcessAirYesYesYesYesReducesroductionReducesoxencontentinflueasandreducesflameterneratureBurnersoutofServiceNeedcapacityofallShutoffthefuelflowfi·omoneburnerormoretocreatefuelrichandfuellean6YesYesYesNoburnersforworstcase(BOOS)scenariozones7FuelBiasingYesYesYesNoCombustionisstagedbydivertingfuelfromtheupperlevelburnerstotheloweronesorfromthecentertothesideburnerstocreateandfucl·lcanzonesPartofthetotalfuelheatinputisinjectedintothefurnaceinaregionabovethe8RebumingYesYesYesNoprimary(mainburners)flamestocreateareducingatmospherezone),wherehydrocarbonradicalsrcactwithNOxtoproduccclementalnitrogen9LoadReductionYesYesNoThisisastrategytoreduceloadonapowerplantbyreducingtheelcctricaldemandthroughefficiencyrojects,10EnerEfficiencPro'ectsYesYesYesYesDecreaseamountoffuelreuircdtomakeanaccetableroduct11CoalDryingYesYesNoRequiresavailableexcessDrycoalwillincreasetheas-burnedBTUvalue,andthereforelessfuelisrequiredheat.tobeburned,Specificenergyefficiencyproject14CombustionZoneCoolingYesYesNoCouldreduceloadCoolingoftheprimaryflamezonebyheattransfertosurroundingsurfacescapabilitiesY:\22\52\OBOTildenBART\BARTreport\Appendix\Appendix0MichiganOperationsControlTechnologiesDryer.xlsNOxDryer1of412/21/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlOryerAvailableandApplicableReviewRevised:December1,2006RequirescasebycaseYes(notanalysis.Typically,Lowercombustiontempswithsolidfuelsvsgas.MayalsoreducefuelNOxby15AlternateFuelsYesYesYesrequiredbyfacilitiesexperiencelowerBART)NOxwhenburningsolidusingafuelwithlessnitrogen.fuels.16OxygenEnhancedNoResearchlevelAsmallfractionofthecombustionairisreplacedwithoxygen.CombustionPulverizedcoalpreheatedandvolatilesandnitrogencompoundsare17PreheatCombustionNoResearchlevelreleasedinacontrolledreducingatmospherewherethenitrogencompoundsarereducedtoNz.ThisisaddressedthroughCombinationnfGFAandSCR.Wall-firedorfurnacethat18ROFA-ROTAMIXYesYesYes'Yesthescenariothatcombinesutilizeshighvelocityoverflreair.AdditionalNOxreductionsareachievedwithOFAandSCRanunoniainjection(Rotamix)Currentequipmentcannot19NOxCEMSYesYesYes"'-'-No---""---·'"betunedto'impactNOxOptimizationofcombustionemissionsCUrrente,quipmentcannot20ParametricMonitoringYesYesYesNobetunedtoimpactNOxOptimizationofcombustionemissionsCatalystInjectionAcombustioncatalystisdirectlyinjectedintotheairintakestreamanddelivered38NoResearchLeveltothecombustionsite,initiatingchemicalreactionsthatchangethedynamicsof(EPSTechnologies)theflame.21Non-SelectiveCatalyticYesYesYesYesNot,efficientasotherUndernear stoichiometricconditions,inthepresenceofacatalyst,NOxisReduction(NSCR)reducedbyCO,resultinginnitrogen(N2)andcarbondioxide(CO2),22LowTemperatureOxidationYesYesNoRequiresozonegenerationUtilizesanoxidizingagentsuchasozonetooxidizevariouspollutantsincluding(LTD)Tri-NOx®NOxY:\22\52\OBOTildenBART\BARTreport\Appendix\Appendix0MichiganOperationsControlTechnologiesMDryer.xlsNOxDryer20f412/21/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxCOl")trolDryer.AvailableandApplicableReviewRevised:December1,200623LowTemperatureOxidationYes(LTO)-LoTOx24SelectiveCatalyticReductionYes(SCR)NoYesYesYesHasbeenincludedasan"innovative"technologyinrecentBACTanalysesfrommultiplefacilities.Needtoinjectatappropriatetemperature.Applicabletocleanservices.UtilizesanoxidizingagentsuchasozonetooxidizevariouspollutantsincludingNOxAmmonia(NH))isinjectedintothefluegasstreaminthepresenceofacatalysttoconvertNOxintoNzandwater25RegenerativeSCR26SelectiveNon-CatalyticReduction(SNCR)27AdsOition28Absorption29OxidizerYesYesNoYesYesNoYesYesYesYesYesYesYesYesYes•..j.",Forcleanservices.ToomuchdebrisinfluegaswouldpoisoncatalystStillinresearchstaes.SimilartoTriNOxRedundanttoregenerative....,r;Ureaorammonia·basedchemicalsareinjectedintothefluegasstreamtoCOnvertNOtomolecularnitrogen,N2,andwaterUseofcharactivatedcarbontoadsorboxidesofnitroenUseofwater,hydroxideandcarbonatesolutions,sulfuricacid,organicsolutions,moltenalkalicarbonates,orhydroxidestoabsorboxidesofnitrogen.Gasstreamissentthroughtheregenerative, recuperative,catalyticordirectfiredoxidizerwherepollutantsareheatedtoacombustionpointanddestroyed.3031SNOXSOx-NOx-Rox-BoxNoNoEarly'col1li:nercialdevelopmentstageTechnologyhasnotbeendemonstratedCatalyticreductionofNOxinthepresenceofammonia(NH]),followedbycatalyticoxidationofS02toSO].TheexitgasfromtheSO)converterpassesthroughanovelglass-tubecondenserinwhichtheSO]ishydratedtoH2S04vaporandthencondensedtoaconcentratedliquidsulfuricacid(H2S04),DrysorbentinjectionupstreamofthebaghouseforremovalofSOxandammoniainjectionupstreamofazeoliticselectivecatalyticreduction(SCR)catalystincorporatedinthebaghousetoreduceNOxemissions.Y:\22\52\080TildenBARnBARTreport\Appendix\AppendixDMichiganOperationsControlTechnologies7Dl)Ier.xlsNOxDryer.30f41212112006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlDryerAvailableandApplicableReviewRevised:December1,2006NooperatingcommercialElectronbeamirradiationinthepresenceofammoniatoinitiatechemical32Electron(E-Beam)ProcessNoapplicationsoncoalconversionofsulfurandnitrogenoxidesintocomponentswhichcanbeeasilycollectedbyconventionalmethodssuchasanESPorbaghouse.Similartocoldplasma.UtilizesareactorinwhichS02'NOx,andmercuryareoxidizedtonitrogenWillkeepwatchfordioxide(N02),sulfuricacid,andmercuricoxiderespectivelyusingnon-thermal33ElectrocatalyticOxidationNoavailabilityofthisplasma.technologyOnrecentproject,thevenderwasdoingfinaltrialsonapplications.CommercialversionofUsesaregenerablesorbenttosimultaneouslyadsorb502andNOxfromfluegas34NOXSONoadsorption.Limitedfromutilityandindustrialboilers.Intheprocess,theS02isconvertedexperiencetoasaleablesulfurby-product(liquidSOz,elementalsulfur,orsulfuricacid)andconcepttests).theNOxisconvertedtonitrogenandoxygen.S02inthefluegasreactswithcopperoxide,supportedonsmallspheresofAbsorptionandSCR.alumina,tofonncoppersulfate.Ammoniaisinjectedintothefluegasbeforetheabsorptionreactorandaselectivecatalyticreactionoccursthat35Noe,·.ExperitmceJimitedtopilotreducesthenitricoxidesinthefluegas.Intheregenerationstep,thecopperscale.sulfateisreducedinaregeneratorwithareducingagent,suchasnaturalgas,producingaconcentratedstreamofS02.36ColdPlasmaNoResearchLevelGasstreamispassedthroughafiltermediumofsoilandmicrobes.Pollutantsare37BiofiltersNoResearchleveladsorbedanddegradedbymicrobialmetabolismfonningtheproductscarbondioxideandwater.Gasstreamispassedthroughafilterbaghouseinwhich38PahlmanProcessNoResearchLevelareametaloxidesorbenthavebeendeployed.Pollutantsareremovedfromthegasesbyadsortion.I)Thisnumberisforreferenceonly.Itdoesnotinanywayrankthecontroltechnologies.2)a)AirPollution:ItsOriginAndControl.Wark,Kenneth;Warner,CecilF.;andDavis,WayneT.1998.AddisonWesleyLongman,Inc.b)USEPABasicConceptsinEnvironmentalScience,Module6,http://www.epa.gov/eogaptil/inodule6/index.htmc)NewandEmergingEnvironmentalTechnologies,http://neet.rti.orgld)NDBARTReportsY:\22\52\080TildenBART\8ARTreport\Appendix\Appendix0MichiganOperationsControlTechnologies,.Dryer,xisNOxDryer4of412/21/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,2006OverfireAir(OFA)YesYesYesYesCombustionairisseparatedintoprimaryandsecondaryflowsectionstoachievecompleteburnoutandtoencouragethefonnationofN1ratherthanNOx2ExtemalFlueGasYesYesYesNoMixesfluegaswithcombustionairwhichreducesoxygencontentandthereforeRecirculation(EFGR)reducesflametemperatureJLow·NOxBurnersYesYesYesYesBurnersaredesignedtoreduceNOxfonnationthroughrestrictionofoxygen,flametemperature,and/orresidencetimeInducedFlueGasNeedtobeupfired.Need4RecirculationBurnersYesYesYesYesconvectivelooptogetgasDrawsfluegastodilutethefuelinordertoreducetheflametemperaturerecirculated5LowExcessAirYesYesYesYesReducesroductionReducesoxencontentinflueasandreducesflametemeratureBU111el'SoutofServiceNeedcapacityofallShutoffthefuelflowfromoneburnerormoretocreatefuelrichandfuellean6YesYesYesNobU111ersforworstcase(BOOS)scenariozones7FuelBiasingYesYesYesNoCombustionisstagedbydivertingfuelfromtheupperlevelburnerstotheloweronesorfromthecentertothesideburnerstocreatefuel-richandfuel-leal).zonesPaltofthetotalfuelheatinputisinjectedintothefurnaceinaregionabovethe8ReburningYesYesYesYesprimary(mainburners)flamestocreateareducingatmosphere(re-bumzone),wherehydrocarbonradicalsreactwithNOxtoproduceelementalnitrogen9LoadReductionYesYesNoThisisastrategytoreduceloadonapowerplantbyreducingtheelectricaldemandthroughefficiencyprojects,toEnergEfficienePro'ectsYesYesYesYesDecreaseamountoffuelreuiredtomakeanaccetableroduetIICoalDryingYesYesNoRequiresavailableexcessDrycoalwillincreasetheas-burnedBTUvalue,andthereforelessfuelisrequiredheat.tobeburned.Specificenergyefficiencyproject14CombustionZoneCoolingYesYesNoCouldreduceloadCoolingoftheprimaryflamezonebyheattransfertosurroundingsurfacescapabilitiesY:\22\52\OBOTildenBARnBARTreport\Appendix\Appendix0-MichiganOperationsControlTechnologies-ProcessBoilers.xlsNOxProcessBoilers1of512/20/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,2006RequirescasebycaseYes(notanalysis.Typically,Lowercombustiontempswithsolidfuelsvsgas.MayalsoreducefuelNOxby15AltemateFuelsYesYesYesrequiredbyfacilitiesexperiencelowerusingafuelwithlessnitrogen.BART)NOxwhenburningsolidfuels.16OxygenEnhancedNoResearchlevelAsmallfractionofthecombustionairisreplacedwithoxygen.CombustionPulverizedcoalpreheatedandvolatilesandfuel-boundnitrogencompoundsare17PreheatCombustionNoResearchlevelreleasedinacontrolledreducingatmospherewherethenitrogencompoundsarereducedtoNz.ThisisaddressedthroughCombinationafCFAandSCR.Wall-firedortangentially-firedfurnacethat18ROFA-ROTAMIXYesYesYesYesthescenariothatcombinesutilizeshighvelocityoverfireair.AdditionalNOxreductionsareachievedwithOFAandSCRammoniainjection(Rotamix)Currentequipmentcannot19NOxCEMSYesYesYesNobetunedtoimpactNOxOptimizationofcombustionemissionsCurrentequipmentcannot20ParametricMonitoringYesYesYesNohetunedtoimpactNOxOptimizationofcombustionemissionsCatalystInjectionAcombustioncatalystisdirectlyinjectedintotheairintakestreamanddelivered38NoResearchLeveltothecombustionsite,initiatingchemicalreactionsthatchangethedynamicsof(EPSTechnologies)theflame.CatalyticForcleanservices.TooUndernearstoichiometricconditions,inthepresenceofacatalyst,NOxis21Reduction(NSCR)YesYesYesYesmuchdebrisinfluegasreducedbyCO,resultinginnitrogen(N2)andcarbondioxide(CO2),wouldpoisoncatalystY:\22\52\080TildenBART\BARTreport\Appendix\Appendix0 -MichiganOperationsConlrolTechnologiesProcessBoilers.xlsNOxProcessBoilers20f51212012006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,200622LowTemperatureOxidationYesYesNoRequiresozonegenerationUtilizesanoxidizingagentsuchasozonetooxidizevariouspollutantsincluding(LTD)Tri·NOx®NOxHasbeenincludedasan23LowTemperatureOxidationYesNo"innovative"technologyinUtilizesanoxidizingagentsuchasozonetooxidizevariouspollutantsincluding(LTO)-LoTOxrecentBACTanalysesNOxfrommultiplefacilities.Needtoinjectat24SelectiveCatalyticReductionYesYesYesYesappropriatetemperature.Ammonia(NH3)isinjectedintothefluegasstreaminthepresenceofacatalystto(SCR)ApplicabletocleanconvertNOxintoN2andwaterservices.Forcleanservices.Too25RegenerativeSCRYesNomuchdebrisinfluegaswouldpoisoncatalyst26SelectiveNon-CatalyticYesYesYesYesUreaorammonia-basedchemicalsareinjectedintothefluegasstreamtoconvertReduction(SNCR)NOtomolecularnitrogen,N2,andwater27AdsoHonNoStillinresearchstages.Uscofcharactivatedcarbontoadsorboxidesofnitroen28AbsorptionYesYesNoSimilartoTriNOxUseofwater,hydroxideandcarbonatesolutions,sulfuricacid,organicsolutions,moltenalkalicarbonates,orhydroxidestoabsorboxidesofnitrogen.29OxidizerYesYesYesYesRedundanttoregenerativeGasstreamissentthroughtheregenerative,recuperative,catalyticordirectfiredSCRoxidizerwherepollutantsareheatedtoacombustionpointanddestroyed.Y:\22\52\080TildenBARnBARTreport\Appendix\Appendix0 -MichiganOperationsControlTechnologiesProcessBoilers.xlsNOxProcessBoilers30f512/20/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,200630313233343S36SNOXSOx-NOx-Rox-BoxElectron(E-Beam)ProcessElectrocatalyticOxidationNOXSOCopper-OxideColdPlasmaNoNoNoNoNoNoNoEarlycommercialstageTechnologyhasnotbeendemonstratedNooperatingcommercialapplicationsoncoalSimilartocoldplasma.Willkeepwatchforavailabilityofthi5Commercialversionofadsorption.Limitedexperienceconcepttests).AbsorptionandSCR.Experiencelimitedtopilotscale.ResearchLevelCatalyticreductionofNOxinthepresenceofammonia(NH3),followed,bycatalyticoxidationofS02toS03'TheexitgasfromtheSOJconvelierpassesthroughanovelglass-tubecondenserinwhichtheS03ishydratedtoH2S04vaporandthencondensedtoaconcentratedliquidsulfuricacid(H2S04).DrysorbentinjectionupstreamofthebaghouseforremovalofSOxandammoniainjectionupstreamofazeoliticselectivecatalyticreduction(SCR)catalystincorporatedinthebaghousetoreduceNOxemissions.ElectronbeamirradiationinthepresenceofammoniatoinitiatechemicalconversionofsulfurandnitrogenoxidesintocomponentswhichcanbeeasilycollectedbyconventionalmethodssuchasanESPorbaghouse.UtilizesareactorinwhichS02'NOx,andmercuryareoxidizedtonitrogendioxide(N0z),sulfuricacid,andmercuricoxiderespectivelyusingplasma.Onrecentproject,thevenderwasdoingfinaltrialsonapplications.UsesaregenerablesorbenttosimultaneouslyadsorbSOzandNOxfromfluegasfi'omutilityandindustrialboilers.Intheprocess,theSOzisconvertedtoasaleablesulfurby-product(liquidS02,elementalsulfur,orsulfuricacid)andtheNOxisconvertedtonitrogenandoxygen.S02inthefluegasreactswithcopperoxide,supportedonsmallspheresofalumina,tofonncoppersulfate.Ammoniaisinjectedintothefluegasbeforetheabsorptionreactorandaselectivecatalyticreduction-typereactionoccursthatreducesthenitricoxidesinthefluegas.Intheregenerationstep,thecoppersulfateisreducedinaregeneratorwithareducingagent,suchasnaturalgas,producingaconcentratedstreamofS02'Y:\22\52\OBOTildenBART\BARTreport:\Appendlx\Appendix0MichiganOperationsControlTechnologiesProcessBoilers.xisNOxProcessBoilers4of512/20/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,20063738BiofiltersPahlmanProcessNoNoResearchlevelResearchLevelGasstreamispassedthroughafiltermediumofsoilandmicrobes.Pollutantsareadsorbedanddegradedbymicrobialmetabolismformingtheproductscarbondioxideandwater.Gasstreamispassedthroughafilterbaghouseinwhichspecially-developed,small-particle,high-surfaceareametaloxidesorbenthavebeendeployed.Pollutantsareremovedfromthegasesbadsortion.1)Thisnumberisforreferenceonly.Itdoesnotinanywayrankthecontroltechnologies.2)a)AirPollution:ItsOriginAndControl.Wark,Kenneth;Wamer,CecilF.;andDavis,WayneT.1998.AddisonWesleyLongman,Inc.b)USEPABasicConceptsinEnvironmentalScience,Module6,http://www.epa.gov/eogaptillmodule6/index.htmc)NewandEmergingEnvironmentalTechnologies,http://neet.rti.org!d)NDBARTReportsY:\22\52\080TildenBART\BARTreport\Appendix\Appendix0 -MichiganOperationsControlTechnologiesProcessBoilers.xlsNOxProcessBoilers50f512120/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,2006OverfireAir(OFA)YesYesYesYesCombustionairisseparatedintoprimaryandsecondaryflowsectionstoachievecompleteburnoutandtoencouragethefonnationofN1ratherthanNOx2ExtemalFlueGasYesYesYesNoMixesfluegaswithcombustionairwhichreducesoxygencontentandthereforeRecirculation(EFGR)reducesflametemperatureJLow·NOxBurnersYesYesYesYesBurnersaredesignedtoreduceNOxfonnationthroughrestrictionofoxygen,flametemperature,and/orresidencetimeInducedFlueGasNeedtobeupfired.Need4RecirculationBurnersYesYesYesYesconvectivelooptogetgasDrawsfluegastodilutethefuelinordertoreducetheflametemperaturerecirculated5LowExcessAirYesYesYesYesReducesroductionReducesoxencontentinflueasandreducesflametemeratureBU111el'SoutofServiceNeedcapacityofallShutoffthefuelflowfromoneburnerormoretocreatefuelrichandfuellean6YesYesYesNobU111ersforworstcase(BOOS)scenariozones7FuelBiasingYesYesYesNoCombustionisstagedbydivertingfuelfromtheupperlevelburnerstotheloweronesorfromthecentertothesideburnerstocreatefuel-richandfuel-leal).zonesPaltofthetotalfuelheatinputisinjectedintothefurnaceinaregionabovethe8ReburningYesYesYesYesprimary(mainburners)flamestocreateareducingatmosphere(re-bumzone),wherehydrocarbonradicalsreactwithNOxtoproduceelementalnitrogen9LoadReductionYesYesNoThisisastrategytoreduceloadonapowerplantbyreducingtheelectricaldemandthroughefficiencyprojects,toEnergEfficienePro'ectsYesYesYesYesDecreaseamountoffuelreuiredtomakeanaccetableroduetIICoalDryingYesYesNoRequiresavailableexcessDrycoalwillincreasetheas-burnedBTUvalue,andthereforelessfuelisrequiredheat.tobeburned.Specificenergyefficiencyproject14CombustionZoneCoolingYesYesNoCouldreduceloadCoolingoftheprimaryflamezonebyheattransfertosurroundingsurfacescapabilitiesY:\22\52\OBOTildenBARnBARTreport\Appendix\Appendix0-MichiganOperationsControlTechnologies-ProcessBoilers.xlsNOxProcessBoilers1of512/20/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,2006RequirescasebycaseYes(notanalysis.Typically,Lowercombustiontempswithsolidfuelsvsgas.MayalsoreducefuelNOxby15AltemateFuelsYesYesYesrequiredbyfacilitiesexperiencelowerusingafuelwithlessnitrogen.BART)NOxwhenburningsolidfuels.16OxygenEnhancedNoResearchlevelAsmallfractionofthecombustionairisreplacedwithoxygen.CombustionPulverizedcoalpreheatedandvolatilesandfuel-boundnitrogencompoundsare17PreheatCombustionNoResearchlevelreleasedinacontrolledreducingatmospherewherethenitrogencompoundsarereducedtoNz.ThisisaddressedthroughCombinationafCFAandSCR.Wall-firedortangentially-firedfurnacethat18ROFA-ROTAMIXYesYesYesYesthescenariothatcombinesutilizeshighvelocityoverfireair.AdditionalNOxreductionsareachievedwithOFAandSCRammoniainjection(Rotamix)Currentequipmentcannot19NOxCEMSYesYesYesNobetunedtoimpactNOxOptimizationofcombustionemissionsCurrentequipmentcannot20ParametricMonitoringYesYesYesNohetunedtoimpactNOxOptimizationofcombustionemissionsCatalystInjectionAcombustioncatalystisdirectlyinjectedintotheairintakestreamanddelivered38NoResearchLeveltothecombustionsite,initiatingchemicalreactionsthatchangethedynamicsof(EPSTechnologies)theflame.CatalyticForcleanservices.TooUndernearstoichiometricconditions,inthepresenceofacatalyst,NOxis21Reduction(NSCR)YesYesYesYesmuchdebrisinfluegasreducedbyCO,resultinginnitrogen(N2)andcarbondioxide(CO2),wouldpoisoncatalystY:\22\52\080TildenBART\BARTreport\Appendix\Appendix0 -MichiganOperationsConlrolTechnologiesProcessBoilers.xlsNOxProcessBoilers20f51212012006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,200622LowTemperatureOxidationYesYesNoRequiresozonegenerationUtilizesanoxidizingagentsuchasozonetooxidizevariouspollutantsincluding(LTD)Tri·NOx®NOxHasbeenincludedasan23LowTemperatureOxidationYesNo"innovative"technologyinUtilizesanoxidizingagentsuchasozonetooxidizevariouspollutantsincluding(LTO)-LoTOxrecentBACTanalysesNOxfrommultiplefacilities.Needtoinjectat24SelectiveCatalyticReductionYesYesYesYesappropriatetemperature.Ammonia(NH3)isinjectedintothefluegasstreaminthepresenceofacatalystto(SCR)ApplicabletocleanconvertNOxintoN2andwaterservices.Forcleanservices.Too25RegenerativeSCRYesNomuchdebrisinfluegaswouldpoisoncatalyst26SelectiveNon-CatalyticYesYesYesYesUreaorammonia-basedchemicalsareinjectedintothefluegasstreamtoconvertReduction(SNCR)NOtomolecularnitrogen,N2,andwater27AdsoHonNoStillinresearchstages.Uscofcharactivatedcarbontoadsorboxidesofnitroen28AbsorptionYesYesNoSimilartoTriNOxUseofwater,hydroxideandcarbonatesolutions,sulfuricacid,organicsolutions,moltenalkalicarbonates,orhydroxidestoabsorboxidesofnitrogen.29OxidizerYesYesYesYesRedundanttoregenerativeGasstreamissentthroughtheregenerative,recuperative,catalyticordirectfiredSCRoxidizerwherepollutantsareheatedtoacombustionpointanddestroyed.Y:\22\52\080TildenBARnBARTreport\Appendix\Appendix0 -MichiganOperationsControlTechnologiesProcessBoilers.xlsNOxProcessBoilers30f512/20/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,200630313233343S36SNOXSOx-NOx-Rox-BoxElectron(E-Beam)ProcessElectrocatalyticOxidationNOXSOCopper-OxideColdPlasmaNoNoNoNoNoNoNoEarlycommercialstageTechnologyhasnotbeendemonstratedNooperatingcommercialapplicationsoncoalSimilartocoldplasma.Willkeepwatchforavailabilityofthi5Commercialversionofadsorption.Limitedexperienceconcepttests).AbsorptionandSCR.Experiencelimitedtopilotscale.ResearchLevelCatalyticreductionofNOxinthepresenceofammonia(NH3),followed,bycatalyticoxidationofS02toS03'TheexitgasfromtheSOJconvelierpassesthroughanovelglass-tubecondenserinwhichtheS03ishydratedtoH2S04vaporandthencondensedtoaconcentratedliquidsulfuricacid(H2S04).DrysorbentinjectionupstreamofthebaghouseforremovalofSOxandammoniainjectionupstreamofazeoliticselectivecatalyticreduction(SCR)catalystincorporatedinthebaghousetoreduceNOxemissions.ElectronbeamirradiationinthepresenceofammoniatoinitiatechemicalconversionofsulfurandnitrogenoxidesintocomponentswhichcanbeeasilycollectedbyconventionalmethodssuchasanESPorbaghouse.UtilizesareactorinwhichS02'NOx,andmercuryareoxidizedtonitrogendioxide(N0z),sulfuricacid,andmercuricoxiderespectivelyusingplasma.Onrecentproject,thevenderwasdoingfinaltrialsonapplications.UsesaregenerablesorbenttosimultaneouslyadsorbSOzandNOxfromfluegasfi'omutilityandindustrialboilers.Intheprocess,theSOzisconvertedtoasaleablesulfurby-product(liquidS02,elementalsulfur,orsulfuricacid)andtheNOxisconvertedtonitrogenandoxygen.S02inthefluegasreactswithcopperoxide,supportedonsmallspheresofalumina,tofonncoppersulfate.Ammoniaisinjectedintothefluegasbeforetheabsorptionreactorandaselectivecatalyticreduction-typereactionoccursthatreducesthenitricoxidesinthefluegas.Intheregenerationstep,thecoppersulfateisreducedinaregeneratorwithareducingagent,suchasnaturalgas,producingaconcentratedstreamofS02'Y:\22\52\OBOTildenBART\BARTreport:\Appendlx\Appendix0MichiganOperationsControlTechnologiesProcessBoilers.xisNOxProcessBoilers4of512/20/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,20063738BiofiltersPahlmanProcessNoNoResearchlevelResearchLevelGasstreamispassedthroughafiltermediumofsoilandmicrobes.Pollutantsareadsorbedanddegradedbymicrobialmetabolismformingtheproductscarbondioxideandwater.Gasstreamispassedthroughafilterbaghouseinwhichspecially-developed,small-particle,high-surfaceareametaloxidesorbenthavebeendeployed.Pollutantsareremovedfromthegasesbadsortion.1)Thisnumberisforreferenceonly.Itdoesnotinanywayrankthecontroltechnologies.2)a)AirPollution:ItsOriginAndControl.Wark,Kenneth;Wamer,CecilF.;andDavis,WayneT.1998.AddisonWesleyLongman,Inc.b)USEPABasicConceptsinEnvironmentalScience,Module6,http://www.epa.gov/eogaptillmodule6/index.htmc)NewandEmergingEnvironmentalTechnologies,http://neet.rti.org!d)NDBARTReportsY:\22\52\080TildenBART\BARTreport\Appendix\Appendix0 -MichiganOperationsControlTechnologiesProcessBoilers.xlsNOxProcessBoilers50f512120/2006ClevelandCliffsMichiganOperations·TaconiteBARTAnalysis502ControlInduratingFurnacesAvailableandApplicableReviewRevised:December1.2006Absorptionaudreactionusingallalkalinereagenttoproduceasolidcompound<50%yyyy2WetScrubbing(High__-1f+-/-If-__---11---------------f----------------------------11co;WetScrubbing(LowEfficiency)WetWalledElectrostaticPreciitator(WWESP)yyyy80%Suspcndedparticlesarescparatedfromlhefluegasstrealil,attractedtoplates,andcollectedinhoers4Drysorbentinjectionyyyy<55%Pulverizedlimeorlimestoneisdirectly injectedintotheductlIpstreamoftllefabricfilter,DrysorptionofS02ontothelimeorlimestoneparticleoccursandthesolid particlesarccollectedwitltafabricfilter5SprayDryerAbsorption6AllemativeFuels7LoadReduction8EnergyEfficiencyProjects9CoalProcessing10BioFiltersyyNyyNyyyNyy(forfurnacescapableofmultiplefLlels)y(forlargeprojectsheat-recouyy(notrequiredbyBART)y(forlargeprqjects.llke<90%Site-specificNaturalgasisbasecasePowcrplanttechnologySite-specificAppliesonlytofacilitiestllatburncoallevelUseafuelwithlowersulfurcontent.Tbisisastrategytorcduceloadallapowerplantbyreducingtheelectricaldemandthrallhtcfficiencro·ccts.decreaseamountoffuelrequiredtomakeallacceptableproductDrycoalwillincreasetheas-buntedBTUvalue,alidthereforelessfuelisrequiredtobebunted,8ecificenerefficiencro'ectGasstreampassesthroughapackedbedofspeciallyenginceredbiomediawhicltsupportstltegrowthofactivebacterialspecies,Tltepollutantsillthegasstreamarebiodegradedorbiotransfonnedintoinnocuousproducts,suchascarbOlldioxide,water,clilorIICANSOLVRegenerableS02NResearchlevelAllaqueoussolutionofproprietarydiaminecaptures802fromthefeedgasillacountercurreutabsorptiontower.Therichsolventisregeneratedbysteamstripping,givingabyproductofpure,watersaturated802gasandleansolventforrecyclingtothea12PahlmanProcessNRcsearchlevelGasstreamispassedthroughafilterbaghollseinwltichspecially.developed,smallparticlc,high·surfaceareametaloxidesorbellthavebeendeployed.Pollutantsareremovedfromthegascsbyadsotion.13SOx-NOx-Rox-BoxNTeclmologyhasnotbeendemonstratedDrysorbcnt injectionnpstreamoftbebaghouseforremovalofSOxandammoniainjectionupstreamofazeoliticselectivecatalyticreduction(SCR)catalystincorporatedintltebagltousetoreduceNOxemissions.Y:\22\52\080TildenBART\BARTrepor1\Appendix\AppendixD·MichiganOperationsControlTechnologies_Furnaces.xls502Tables-Furnace10f212120{2006ClevelandCliffsMichiganOperations·TaconiteBARTAnalysis502ControlInduratingFurnacesAvailableandApplicableReviewRevised:December1,20061415161718Electron(E-Scam)ProcessElectrocatalyticOxidationNOXSOCopper-OxideSNOXNNNNNNooperatingcommercialapplicationsallcoalSimilartocoldplasma.WillkeepwatchfaavailabilityOfl11istechnologyCommercialversionofadsorption.Limitedexperience(proof-of-concepttests).AbsorptionandSCR.Experiencelimitedtopilotscale.arlycommercialdevelopmentstageElectronbeamirradiationinthepresenceofammoniatoinitiatechemicalconversionofsulfurandnitrogenoxidesintocomponentswl\ic1\canbeeasilycollectedbyconventionalmethodssuchasanESPorbaghouse.Utilizesareactorinwhic1\S02'NOll,andmercuryareoxidizedtonitrogendioxide(N02),sulfuricacid,andmercuricoxiderespectivelyusinglloll-thenllalplasma.Onrecentproject,thevenderwasdoingfInaltrialsallfull-scaleapplications.UsesaregenerablesorbenttosimultaneouslyadsorbS02andNOxfromfluegasfromcoal-firedutilityandindustrialboilers.Intheprocess,dieS02isconvertedtasaleablesulfilrby-product(liquidS02,elementalsulfur,orsulfuricacid)andtheNO,S02inthefluegasreactswitllcopperoxide,supportedonsmallspheresofalumina,tofonncoppersnlfate.Ammoniaisinjectedintothefluegasbeforetheabsorptionreactorandaselectivecatalyticreduction-typereactionoccursthatreducesthenitrCatalyticreductionofNOxinthepresenceofammonia(NHl),followedbycatalyticoxidationofS02toSOl'TheexitgasfromtheS03converterpassesthroughanovelglass-tubecondenserinwhichtheS03ishydratedtoH2S04vaporandthencondensedtoa19ColdPlasmaNhlevel1)Thisnumberisforreferenceonly.Itdoesnotinany wayrankthecontroltcclmologies.2)a)AirPollntion:itsOriginAndControl.Wark,Kennetll;Warner,CecilF.;andDavis,WayneT.1998.AddisonWesleyLongman,Tuc.2)b)USEPABasicConceptsinEnvironmentalScience,Module6,http://www.epa.gov/eogaptillmodllle6/index.1Jtm2)c)NewandEmergingEnvironmentalTechnologies,llttp:llncet..rti.orgl2)d)NDBARTReportsY:\22\52\080TildenBARnBARTreportlAppendixlAppendixo·MichiganOperationsControlTechnologies-Furnaces.xls502Tables-Furnace20f212/20/2006Cleveland Cliffs Michigan Operations BART AnalysisNOx ControlDryerAvailable and Applicable ReviewRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Process Boiler BART Report and should notbe distributed without the full text of the report so that the information isnot taken out of context.

Reference No. 1NOxPollution ControlTechnology2Is this agenerallyavailablecontroltechnology?Is the controltechnologyavailable topower boilers?Is the controltechnologyapplicable tothis specificsource?Is it technicallyfeasible for thissource?CommentsBasic PrincipleCombustion Controls1 Overfire Air (OFA) YesYesYesYesCombustion air is separated into primary and secondary flow sections to achievecomplete burnout and to encourage the formation of N2rather than NOx2External Flue GasRecirculation (EFGR)YesYesYesNoMixes flue gas with combustion air which reduces oxygen content and thereforereduces flame temperature3 Low-NOx BurnersYesYesYesYesBurners are designed to reduce NOx formation through restriction of oxygen,flame temperature, and/or residence time4Induced Flue GasRecirculation BurnersYesYesYesYesNeed to be upfired. Needconvective loop to get gasrecirculatedDraws flue gas to dilute the fuel in order to reduce the flame temperature5 Low Excess AirYesYesYesYes Reduces production Reduces oxygen content in flue gas and reduces flame temperature6Burners out of Service(BOOS)YesYesYesNoNeed capacity of allburners for worst casescenarioShut off the fuel flow from one burner or more to create fuel rich and fuel leanzones7 Fuel Biasing YesYesYesNoCombustion is staged by diverting fuel from the upper level burners to the lowerones or from the center to the side burners to create fuel-rich and fuel-lean zones8 ReburningYesYesYesNoPart of the total fuel heat input is injected into the furnace in a region above theprimary (main burners) flames to create a reducing atmosphere (re-burn zone),where hydrocarbon radicals react with NOx to produce elemental nitrogen9 Load Reduction YesYesNo---This is a strategy to reduce load on a power plant by reducing the electricaldemand through efficiency projects.10 Energy Efficiency Projects YesYesYesYesDecrease amount of fuel required to make an acceptable product11 Coal DryingYesYesNo---Requires available excessheat.Dry coal will increase the as-burned BTU value, and therefore less fuel isrequired to be burned. Specific energy efficiency project14 Combustion Zone Cooling Yes Yes No ---Could reduce loadcapabilitiesCooling of the primary flame zone by heat transfer to surrounding surfacesY:\22\52\080 Tilden BART\BART report\Appendix\Appendix D Michigan Operations Control Technologies - Dryer.xlsNOx Dryer1 of 512/28/2006Cleveland Cliffs Michigan Operations BART AnalysisNOx ControlDryerAvailable and Applicable ReviewRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Process Boiler BART Report and should notbe distributed without the full text of the report so that the information isnot taken out of context.

Reference No. 1NOxPollution ControlTechnology2Is this agenerallyavailablecontroltechnology?Is the controltechnologyavailable topower boilers?Is the controltechnologyapplicable tothis specificsource?Is it technicallyfeasible for thissource?CommentsBasic Principle15 Alternate FuelsYesYesYesYes (notrequired byBART)Requires case by caseanalysis. Typically,facilities experience lowerNOx when burning solidfuels.Lower combustion temps with solid fuels vs gas. May also reduce fuel NOx byusing a fuel with less nitrogen.16Oxygen EnhancedCombustionNo --- ------ Research levelA small fraction of the combustion air is replaced with oxygen.17 Preheat CombustionNo--------- Research levelPulverized coal preheated and volatiles and fuel-bound nitrogen compounds arereleased in a controlled reducing atmosphere where the nitrogen compounds arereduced to N2.18 ROFA-ROTAMIXYesYesYesYesThis is addressed throughthe scenario that combinesOFA and SCRCombination of OFA and SCR. Wall-fired or tangentially-fired furnace thatutilizes high velocity overfire air. Additional NOx reductions are achieved withammonia injection (Rotamix)19 NOx CEMSYesYesYesNoCurrent equipment cannotbe tuned to impact NOxemissionsOptimization of combustion20 Parametric Monitoring Yes YesYesNoCurrent equipment cannotbe tuned to impact NOxemissionsOptimization of combustion38Catalyst Injection(EPS Technologies)No --- ------ Research LevelA combustion catalyst is directly injected into the air intake stream and deliveredto the combustion site, initiating chemical reactions that change the dynamics ofthe flame.Post Combustion Controls21Non-Selective CatalyticReduction (NSCR)YesYesYesYesNot as efficient as othercontrol technologiesUnder near stoichiometric conditions, in the presence of a catalyst, NOx isreduced by CO, resulting in nitrogen (N2) and carbon dioxide (CO2).22Low Temperature Oxidation(LTO) - Tri-NOx®YesYesNo--- Requires ozone generationUtilizes an oxidizing agent such as ozone to oxidize various pollutants includingNOxY:\22\52\080 Tilden BART\BART report\Appendix\Appendix D Michigan Operations Control Technologies - Dryer.xlsNOx Dryer2 of 512/28/2006Cleveland Cliffs Michigan Operations BART AnalysisNOx ControlDryerAvailable and Applicable ReviewRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Process Boiler BART Report and should notbe distributed without the full text of the report so that the information isnot taken out of context.

Reference No. 1NOxPollution ControlTechnology2Is this agenerallyavailablecontroltechnology?Is the controltechnologyavailable topower boilers?Is the controltechnologyapplicable tothis specificsource?Is it technicallyfeasible for thissource?CommentsBasic Principle23Low Temperature Oxidation(LTO) - LoTOxYesNo------Has been included as an"innovative" technology inrecent BACT analysesfrom multiple facilities.Utilizes an oxidizing agent such as ozone to oxidize various pollutants includingNOx24Selective Catalytic Reduction(SCR)YesYesYesYesNeed to inject atappropriate temperature.Applicable to cleanservices.Ammonia (NH3) is injected into the flue gas stream in the presence of a catalystto convert NOx into N2and water25 Regenerative SCRYesNo------For clean services. Toomuch debris in flue gaswould poison catalyst26Selective Non-CatalyticReduction (SNCR)YesYesYesYesUrea or ammonia-based chemicals are injected into the flue gas stream to convertNO to molecular nitrogen, N2, and water27 Adsorption No --- ------ Still in research stages. Use of char (activated carbon) to adsorb oxides of nitrogen28 AbsorptionYesYesYesYes Similar to TriNOxUse of water, hydroxide and carbonate solutions, sulfuric acid, organic solutions,molten alkali carbonates, or hydroxides to absorb oxides of nitrogen.29 OxidizerYesYesYesYesRedundant to regenerativeSCRGas stream is sent through the regenerative, recuperative, catalytic or direct firedoxidizer where pollutants are heated to a combustion point and destroyed.30SNOXNo---------Early commercialdevelopment stageCatalytic reduction of NOx in the presence of ammonia (NH3), followed bycatalytic oxidation of SO2to SO3. The exit gas from the SO3converter passesthrough a novel glass-tube condenser in which the SO3is hydrated to H2SO4vapor and then condensed to a concentrated liquid sulfuric acid (H2SO4).31 SOx-NOx-Rox-BoxNo---------Technology has not beendemonstratedDry sorbent injection upstream of the baghouse for removal of SOx and ammoniainjection upstream of a zeolitic selective catalytic reduction (SCR) catalystincorporated in the baghouse to reduce NOx emissions.Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D Michigan Operations Control Technologies - Dryer.xlsNOx Dryer3 of 512/28/2006Cleveland Cliffs Michigan Operations BART AnalysisNOx ControlDryerAvailable and Applicable ReviewRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Process Boiler BART Report and should notbe distributed without the full text of the report so that the information isnot taken out of context.

Reference No. 1NOxPollution ControlTechnology2Is this agenerallyavailablecontroltechnology?Is the controltechnologyavailable topower boilers?Is the controltechnologyapplicable tothis specificsource?Is it technicallyfeasible for thissource?CommentsBasic Principle2) 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.htmc) New and Emerging Environmental Technologies, http://neet.rti.org/d) ND BART ReportsY:\22\52\080 Tilden BART\BART report\Appendix\Appendix D Michigan Operations Control Technologies - Dryer.xlsNOx Dryer5 of 512/28/2006Appendix ESummary of Relevant Economic Feasility ($/ton) Control Costs12/28/2006Appendix E Clean Air Interstate Rule (CAIR), Cost-Effective Air Pollution ControlsCommentsReferenceRegulatory Body/RuleSO2NOxSO2NOxBART100 to 1000100 to 100070 FR 39135BART281 to 129670 FR 39135 Table 3BART91970 FR 39133BARTGuidelines disparagingly reference "thousands ofdollars per ton" in commenting on the need toexceed MACT and its general unreasonableness.70_FR_25210_CAIR.pdfCAIR1300Estimated Marginal cost 2009BART(proposed rule) 200-1000BART proposed lists this as values for 90-95%SO2 control, which is still assumed, or .1 to .15lb/MMBtu. Dropped from final to give statesflexibility to require more. Says for scrubbers,bypasses aren't BART, only 100% scrubbing isBART.BART(proposed rule)0.2 lb/MMBtu for NOx is assumed reasonble.Recognizes that some sources may need SCR toget this level. For those, state discretion of the thecost vs. visibility value is necessary.CAIR(using IPM)10001500CAIR ( 2009 in 1999$) 9002400CAIR ( 2015 in 1999$) 18003000CAIR (depending on Nat'lemissions)1200 - 3000 1400- 2100This was modeled with TRUM (TechnologlyRetrofitting Updating Model) to develop themarginal values.Kammer_EPA_Decision.docKammer Decisionover 1000 over 1000LADCO_MidwestRPO_Boiler Analysis.pdf LADCO/Midwest RPO 1240 to 3822 607 to 4493MANE-VU_BART_Control_Assessment.pdf MANE-VU200-500 200-1500Bowers_vs_SWAPCA.txtBowers vs SWAPCA30030010001000954-1134 was ruled too much, in favor of 256-310for SO2. This did consider incremental value.Sections XVII to XIXWRAP3000EPA - Referenced by WrapReferences EPA-600S\7-90-018. Low is<$500/ton, Moderate is $500-3000/ton, High isover $3000/tonWRAP_Trading_program_methodology.pdfAvg. Expected Values ($/ton) Limiting/Marginal values ($/ton)MidwestRPO_rept_referencing_CAIR.pdfFR_Notice_5MAY04_Proposed_Rule.pdfFR_Notice_6JULY05_Final_Rule.pdfY:\22\52\080 Tilden BART\BART report\Appendix\Appendix E - Table of Costs_per_ton.xls

### 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 thre e 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), PM 10 

### ,

P M 2.5 

### , sulfur dioxide (SO 2 

### ), nitrous oxide (NO

x 

### ), 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 B ART 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

### DRAFT – BART Analysis Procedures 8/29/2006

P :\22-52\CCMO BART\BART General Documents\BART Analysis Procedures.doc 

### 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:

S tep 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



### S tep 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

### DRAFT – BART Analysis Procedures 8/29/2006

P :\22-52\CCMO BART\BART General Documents\BART Analysis Procedures.doc 

### 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 “d o 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 technology 7 

### .” This also involves the

i dentification 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

### DRAFT – BART Analysis Procedures 8/29/2006

P :\22-52\CCMO BART\BART General Documents\BART Analysis Procedures.doc 

### 4 should be considered technically feasible and the technological difficulty

evaluated as part of the economic analysis 8



### .

I t 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 guarantees 9



### .

S tep 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 protocol 10 

### , including receptor grid,

m eteorological 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

.

### DRAFT – BART Analysis Procedures 8/29/2006

P :\22-52\CCMO BART\BART General Documents\BART Analysis Procedures.doc 

### 5 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



### T o complete the BART process, the analysis must “establish enforceable emission limits that

reflect the BART requirements and requires compliance within a reasonable period of

time 12 

### .” Those limits must be developed for inclusion in t he 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

basis 13 

### ;” which could include the incorporation of other re gulatory 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.

### DRAFT – BART Analysis Procedures 8/29/2006

P :\22-52\CCMO BART\BART General Documents\BART Analysis Procedures.doc 

### 6 BART limit can “instead prescribe a design, equipment, work practice, operation standard, or

combination of these types of standards 14 

### .”

C ompliance with the BART emission limits will be required within 5 years of U.S. EPA

approval of the Michigan SIP.

14 

### IBID.8/29/2006

P:\22-52\CCMO BART\BART General Documents\Streamline d BART Approach.doc Page 1 of 3 

## 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: NO

x 

## , SO 2 

## , and PM.

R elative to NO

x 

## and SO 2 

## , 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 SO 2 

## . Any source subject to MACT standards must meet a l evel 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)

I t 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 NO

x 

## and SO 2 

## 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 NO

x



## o r SO 2 

## . The Ore Crushing and Handling sources and the Fin ished 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].8/29/2006

P:\22-52\CCMO BART\BART General Documents\Streamline d BART Approach.doc Page 2 of 3 

## 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 (NO

x 

## and SO 2 

## )

I t 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, e ach 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 Air8/29/2006

P:\22-52\CCMO BART\BART General Documents\Streamline d BART Approach.doc Page 3 of 3



## Directors Consortium (LADCO). One modeling analysis will be conducted for each facility.

B. Count the days with a 98 th 

## percentile (21 over 3-yrs, 7 each year) change in v isibility 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 98 th 

## percentile change in visibility less

t han 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 98 th 

## percentile change in visibility greater than or

e qual to 0.05 deciviews, a full BART analysis will be conducted on the emission

sources.

# Appendix 9I

Tilden Mining Company BART LetterY:\Mpls\22 MI\52\2252080 Tilden BART\WorkFiles\_MovedFromMpls_P\MDEQ BART Followup\Tilden Unit 1 BART Recommendations 2-2010.do c 

### 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

(SO 2 

### ) limits for Tilden Unit 1 grate/kiln to satisfy Best Available Retrofit Technology (BART)

requirements.

As requested by MDNRE, Cliffs proposes the fo llowing as BART emission limits for Tilden Unit 1

grate/kiln:

• SO 2 

### – 28,800 lb SO 2 

### per calendar day, and

• NOx – Similar to the Minnesota Regional Haze St ate Implementation Plan, the new NOx limits will

be set after testing to determine appropria te 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 consider ed 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.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 c onditions), 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 (SO 2 

### ). 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 SO 2 

### emissions. The modeling results show SO 2 

### emissions do not cause visibility impairment

to the Class I areas. Therefore, the BART propo sal will primarily focus on NOx emissions.

Proposed BART

The visibility impairment pollutants from indurating furnaces are PM, NOx and SO 2 

### . BART allows

application of other standards to regulate a pollu tant, such as maximum achievable control technology

(MACT). Since the Taconite MACT regulates PM as a su rrogate 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 SO 2 

### emission limit for the Tilden Unit 1 grate/kiln.

As the modeling results from 100% co al usage scenario showed, the SO 2 

### emissions are not causing or

contributing to visibility impairment. Therefore, the current Tilden’s Title V permit limits for SO 2 

### emissions

of 28,800 lbs per calendar day are sufficient. Cliffs proposes to continue to limit the SO 2 

### emissions for

Tilden Unit 1 grate/kiln as establishe d in the Tilden Title V permit.

MDNRE has also requested Cliffs to propose an em ission 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 Regi onal 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.

# 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 receiv es 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

pro cess 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

Furna ce 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

Furna ce 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

Furna ce 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

Furna ce 40 CFR 63 Subparts

RRRRR and A 40 CFR Part 63 Subparts RRRRR

and A

(see TACONITE
MACT
REQUIREMENTS below)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

Furna ce 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

Furna ce 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

F urnace 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 Induratin g Furnace unless the electrostatic precipitators are operating properly. 2 [R336.1910]



### 2. The oil burned in Unit 1 Indurating Furnace sha ll 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

# 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

# EU-BOILERS1-2

EMISSION UNIT CONDITIONS

PROCESS AND CONTROL EQUIPMENT

EU-BOILERS1-2 - Boilers #1 and #2 are each rated at 225 m illion BTU per hour heat input capacity and are fired with natural gas and used oil supplied from the 1.5 million gall on 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]

# Appendix 9K

New Page Paper Company BART Technical Analysis

### r

· ---- ----·- -- - - -- ·

· ·· ---· 

# -- ·--- · · -- - ---- - - - ----- -- - · - · -- ·- - · - - · -- --·--··--·· · --·**--··--·-·--·-·-~--** I


### I

,---... ,



## r

. : r \

\ :**~**

........ . .**· ~:(**  

# ) "

\



# - 

# 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:



# ALL 4 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 ANALYS IS

. . ..................... .. .......... . .............. .. ..... . :

. 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 Eva l uate Vis i bility Impacts (Step 5)

.................. .. ............................................ 

# 4-9

4.2.6 Identify BART

........ ... .......................... .. ................ . ....................................... 4-10

4.3 S0 2 

## BART ANALYSIS

............................................................. . ..... . .......................... 4-10

4.3.1 Identification of All Avai lable 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 Feasib l e 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 I dentify 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

.

1

F inal EPC 1 26 07 .doc 1 12 612007

2

## 1N

I N 

### ( 

# )**~~ --------------------------------** **------------------------------ -----** 

MN



# I 

# I I 

# I I \ 

# \ \ \ 

# \

\ 

# \ \ 

# ', WI 

# ', ', --------

........ __,- 

# ....... 

# , ............... 

# ..,..,.,..

........ 

### / 

# __, , ,, 

# '•1J'ie

NP '-, 

# '

....... 

# ,

0 

# '

........ 

# ...............

Scale In Kilometers



### 150 

### 300 

# ' 

# ',

\ 

# \ 

# \ 

# \ 

# \ \ 

# \ 

# \



# '

J 

# I

I

F i gure 2-1

Location of Class I Areas



## Within 300 km of 

## the EPC Mill**~--**



### ]**~**



# ) 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 D issolving Tank

, and Lime Kiln) are provided in Tables

3-1, 3-2, 3-3,3-4, and 3-5 respectively. The table s include the following i nformation:

• YIPs id entified for each source;

• Identification of control technologies for each sourceNIP scenario;

• Control effectiveness of each technically feasib le 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 n ex t BART evaluation s t e p 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 98 th Percenti le deciview values for the pre

- control and

Anal EPC 1 26 07

. doc 

## 3-1 27 1126120070--- · · ·· · · - --



## Escanaba Paper Company Case-by-Case BART analysis

(



## - , . ,

\. 1 

## 4.2.2.3 Selective Non-Catalytic Reduction (SNCR)

The SNCR process involve s the injection of a nitrogen-containing chemical, typically either

ammonia or urea into a turbulen t reg ion of the boiler where the gas temperature is in the range of

approximately 1600 ° to 2100°F with a corresponding residence tim e of at least 1 seco nd. 

## 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 cata l ytic

converter.

The pri mary SNCR process by-products are NH 3

, C0 2

, and N 2 0 emissions. N 2 0 and C02 are

both greenhouse gases. IfN 2

0 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-p ro duct NH 3 

## (i.e., ammonia s lip) can lead to adverse

impacts down stream of the SNCR system, including 

## air h eater fouling, and plume formation.

When assessing SNCR feasibility, these impacts must be considered, along with any regulatory

requirements to limi t NH 3 

## emissions.

EPC spoke with one vendor that indicated SNCR can be applied to an oil/gas-fired boiler that

swings load

. 

## On a swing boi le r, lik e 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

techno lo gy can be designed with nozzles that ti lt up and down to inject the urea.

NOx reductions range from 20 to 50% at full lo ad,

. depending on a variety of interdependent,

unit-specific boiler and proce ss parameters. These inclu de:

• Physical locat ions 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

Fi nal EPC 1 2 6 0 7 .doc 1 126120 07 

### 38

## • 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 dio xide (S02) emiss ions from the No. 8 Boiler are largely the result o f th e combustion of

No. 6 fuel oil due to the oxidation of sulfur in t he fuel to S0 2 • 

## Natural gas combustion

contributes negligible quantitie s of 

# so2

.

4.3.1 Identification of All Available Retrofit Control Technologies (Step 1)

Based on the data review process · described previously, a li st of potential technologies for

controlling S0 2 emissions from No. 8 Boiler was formulated. EPC identified

. the following

potential control technologies:

• Low Sulfur Fuels;

• Wet Scrubbing;

• Dry Scrubbing; and

• S e mi

- Dry Scrubbing.



## 4.3.2 Discussion of Technical Feasibility (Step 2)

The next step in 

## the top -d own BART analysis is an evaluation of the technical feasibility of each

of the identified control options. Each of the potential control teclmo l ogies considered is

described below along with a discussion of the teclmical feasib ility with respect to the No. 8

Boile r

.

4.3.2.1 Low Sulfur Fuels



## In addition to natural gas, the No. 8 Boiler is p 'e rmitted to burn No. 6 fu el oil with a sulfur

) content of 1.0%. 

## Baseline S0 2 

## emissions are approxima tely 115 tpy, which are driven by the

4- 1 0

Final EPC 1 26 07.doc 1/W2007


### 44r--

- - 

### !

!

(

--

' · ·---

.. .... .......... ·-·--·

.... -·**~·-** ---·---

... --- - · ·- · -- · -·

. . ·-- ---··-**-·~ ··-**  

### - ·

...**-- --** 



## 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 r eage nt 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 collec t ed 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 re tention time for evaporative cooling**an~** 

## lime s lurry spray-dry absorption of

acid gases. All of the sprayed liquid would evaporate as it travels in the tower, l eaving only dry

) reagent products at the discharge

. The partially reacted lime powder and ash would then b e

transported from the SDA vessel into the flue gas to ESP or fabric fi lte r for final treatment. The

reag e nt used would be calcium hydroxide, which is hydrated lime.

A vendor for this control option was able to guarantee no mo r e than 25% potential control

efficiency due to the low inle t concentration. No applica ti ons of this technolog y on fuel oil and

natural gas fired boi l ers such as t h e No. 8 Boiler we r e identified in our research of potential

control technologies; therefore, E PC does not consid er this teclmology to be t echnica ll y feasi bl e.

In 

## order t o be conservative, EPC considers this technology to potentially be transferable t o 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

techno l ogies as teclmically feasib l e, ranked in order of most effective to least e f fective:



# ) • Lower Su l fur Fuels

- 99% control switching to natural gas only;

4-13

Fina l EPC 1 26 07

. doc 112612007 

### 47N

# (j 8.4 PM 10 

## 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 ineffic i ent washing, while the ca l cium particulates result

principa ll y from entrainment. Thus, the particulate emissions are affected by the efficiency of

the mud washing system and the gas velocity and tu r bulence in th e kiln (EPA 1976a).

The typical first step in the BART analysis is the identification of all availab l e retrofit control

options. However, 40 CFR Part 51, Appendix Y (IV, C) identifies an exception to the BAR T

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 comp l iance 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 contro l particulate emissions .from lime kilns.

While both are capabl e of a high degree of particulate removal, the .issue of which d evice

represents the best system of emission reduction is c loud ed 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 S0 2 load on the kiln. Unlike an ESP, the venturi scrubber reduces emissions of

S02 as well as particulate as described in the S0 2 

## BART analysis section above.

EPC has concluded that the existing venturi scrubber represents BART for PM contro l based on

the following key issues:

8-9

Final EPC 1 26 07 .doc 1126/2007



### 86

# )

) UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

R ESEAR CH TRIAN GL E PA RK, NC 277 11



## JUL 1 9 2006

OFFICE OF

A I R QUALITY ?LANN I NG

AND STANDARDS



## MEMORANDUM

SUBJECT:

FROM:

TO : Regional Haze Regu l ations and Guidelines for Best Available Retrofit Technology (BART) De termi na tions

## ~~**·** Joseph 

## w. Paisie

, Group

# Lead~ . J 

### 1

# -[~ ' 

## Geographic Strateg i es Group

# (hlc~&r-2)**~**

Kay Prince, Branch Chie f

EPA

, Region 4

In Ju l y 2005, EPA issued BART Guidelines thai provide guidance t o 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 

## u se to detennine 

## whether a 

## source should be subject to review for BAR T

, 

## or whe the r 

## it 

## should be 

## exempt from 

## the BART r equirements. 

## As

you 

## know, BART applies 

## to existing 

## sources of a 

## certain type, 

## age, and size 

## that 11 

## emit 

## any ai r 

## pollutant 

## which may reasonab l y 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 

## thresho ld 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 spec i fic basis

, or whether EPA in t ended CALPUFF to be used to

model a source ' s 

## visibility impacts based on 

## its total emissions 

## of visibility-impairing pollutants.

We have also re ceived a ques ti on regarding the process for e stimating natural backgro un d

condit i ons, 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 compl e x i ty 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 thres h old test for 

## BART. In

l ntemet Address (URL)**.g~ttp :J** **/www.ep gov**  Rocyclod/Recyclablo • Ptlnreo wkh Vego l abto Oil BtiSild lnl<s on Recyc l ed Paper (MinJmum 25% Poslconsumer)

# Appendix 9L

New Page- Paper Company BART Letter

# =:J NewPageFebruary 2,2010 

# RECEIVED

FEB I) 

# 5 2010



# AIR QUALITY Of\/. Delivering on the Promise of**Paper'~**



## Mr. Bob Irvine Michigan Department of Natural 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 of the BART guidance contained in 40 CFR Part 51 Appendix Y as well as the current U.S. EPA interpretation of BART 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 of the

five emission units) at the mill. The results of the 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 of Protected 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 of VIP 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

### 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 NO x burners on the No.8 Power Boiler would result 

## in 0.12

deciview change in the 98 th 

## 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 of the overall BART process and that even if modeled 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 98 th 

## percentile results above 0.5

deciview can be judged to be acceptable.

Considering all of the 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 9 M

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 Requir ements
1. NOx The Permittee shall comply with the appropriate NOx emission limitations

averag ed 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. (R336.18 01) 1



### (R336.1801(13) 1



### (R336.1801(13) 1



### (R336.1801(1)(f)) 1



### II. MATERIAL LIMIT(S)

Material Limit Underlying Applicable Requir ements
1. Fuel Oil The fuel oil burned in #8 Boiler shall not exceed a maximum sulfur content of 1.0 percent b y weight, calculated on the basis of 18,000 BTU per pound. (R336.1201,

R33 6.1401)



### 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 us ing a NOX CEMS during the ozone control period in accordance with the provisions of R336.1801(11). (R336.18 01(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 ea ch 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

# 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 h our 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 core s. 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 Requir ements
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 fi red emission unit per the definition in R336.1801(1)(b). (R336.1801) 1



### 2. Particulate If the wood residue heat input to # 9 bo iler 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,

R33 6.1331)

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 bo iler, 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,

R33 6.1331)

4. Particulate The particulate emission from the cyclone dust colle ctor 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 whil e 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 resi d ue input feed to EU9B03, consistent with safe operating procedures, upon initiation of scrubber bypass . During a scrubber by pass, the permittee shall burn only natural gas in EU9B03. Wood residue fuel i nput shall not be restart ed until the scrubber is back on line and functioning properly. (R336.1201, R336.1331, R336.1910)

# EU Chemical R ecovery Furnace System
EMISSION UNIT CONDITIONS

DESCRIPTION : The Chemical Recovery Furnace System is used to regenerate chemicals used in the kraft process. The #10 Recovery Furn ace is rated for 565,000 pounds of steam per hour (approximately 950 million BTU per hour heat input), a nd burns black liquor, natural gas, #6 fuel oil, and used oil. Also, the #10 Recovery Furnace receiv es and incinerates HVLC noncondensible gases from the Digester System, Brownstock System, Evaporator System, and Chemical Reco very 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

Metho d Underlying Applicable Requir ements

1. Arsenic The arsenic emission from EURF15 while burning used oil
and/or # 6 fu el 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 em issi on 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 5 2.21)

4. Carbon Monoxide The carbon monoxide em issi on 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 5 2.21)

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

### 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 followin g 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, an d lime kiln that operates 6,3 00 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 6 3.865(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 5 2.21)

8. Particulate The particulate em ission from EURF15 shall not exceed 0.033g rains per dry standard cubi c 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 perc ent 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 reasona ble 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 alternat e particulate limit is the limit that reflects the level of emission that can be reasonably

achieved on a consistent basis. (R336.1201,

R33 6.1331, 40

CFR 52.21)

9. Polychlorinated Biphenyls The polychlorinated biphenyls emission from EURF15 while

burni ng 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 pa rts per million by volume, nor 407 pounds per hour. R336.1201, 40
CFR 5 2.21)

11. Total Reduced
Sulfur The total reduced sulfur emission from EURF15 shall not

excee d 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 5 2.21, 40 CFR 60.283)

# 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

Metho d Underlying Applicable Requir ements

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,

R33 6.1331, 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 5 2.21)



### 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 redu ced 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))

### 2. Performance tests shall be conducted accordi ng 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

# 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

Metho d Underlying Applicable Requir ements

1. HAP Metals

measured as Particulate Matter (PM) Pursuant to 4 0 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 pou nds per 1000 pounds of exhaust gases measured at operating conditions. (R336.1201,

R33 6.1331)

3. Particulate The particulate emission from the two Lime Storage Bins

shall n ot 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 poun ds per hour. (R336.1201)

5. Total Reduced
Sulfur The TRS concentration from EULK29 exhaust gases shall

not excee d 20 parts per million by volume, based on a twelve hour average, corrected to 10 percent oxygen. (R336.1201)

# Appendix 9N

Smurfit-Stone Container Company BART Technical Analysis

# Table of Contents

Smurfit-Stone Corporation - BART Applicability Determination Page 1 of 21 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

Smurfit-Stone Corporation - BART Applicability Determination Page 2 of 21 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

Smurfit-Stone Corporation - BART Applicability Determination Page 3 of 21 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

Smurfit-Stone Corporation - BART Applicability Determination Page 4 of 21 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

Smurfit-Stone Corporation - BART Applicability Determination Page 5 of 21 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

Smurfit-Stone Corporation - BART Applicability Determination Page 6 of 21 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

Smurfit-Stone Corporation - BART Applicability Determination Page 7 of 21 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

Smurfit-Stone Corporation - BART Applicability Determination Page 8 of 21 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 98 th



### 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

Smurfit-Stone Corporation - BART Applicability Determination Page 9 of 21 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

Smurfit-Stone Corporation - BART Applicability Determination Page 10 of 21 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

Smurfit-Stone Corporation - BART Applicability Determination Page 11 of 21 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 98 th 

### 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

Smurfit-Stone Corporation - BART Applicability Determination Page 12 of 21 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 98 th 

### 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

Smurfit-Stone Corporation - BART Applicability Determination Page 13 of 21 Sebesta Blomberg Project No. 556500.20 March 31, 2007



# Appendix A

CALPUFF Protocol

# Appendix A:
CALPUFF Protocol

Smurfit-Stone Corporation - BART Applicability Determination Page 14 of 21 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 (PM 10 

### ) are the species modeled for the SSCC facility. Sulfur dioxide,

nitrogen oxides and PM 10 

### 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 (PM 10 

### ) 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 ( μ g/m 3 

### )

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 ( μ g/m 3 

### ) 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 App lication 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 EN FORCEABILITY

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 ar e 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 en forceable and state enforceab le 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 fede rally enforceable Source-wi de 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 ar e designated as federally enforceable are enforceable by
the Administrator of the United States Environmenta l 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 enforc ement action that it would hav e 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 notificat ion of planned changes or anticipated noncompliance does not stay any ROP term or condition. This does not su persede 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 aut horized representative of th e 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 emi ssions-related activity is

conducted or where records must be ke pt 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 compli ance 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 Admi nistrator of the USEPA, or the departm ent 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 f ee schedule and requirements pursuant to Section 5522 of

Act 451. (R 336.1213(1)(g))

8. This ROP does not convey any prope rty 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 ai r. Transport of collected ai r 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 proc ess equipment a visible emission of a density greater than the most stringent of Rule 301(1)(a) or (b) unless otherwi se 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 feder al new source performance standard.

12. The permittee shall not cause or permi t the emission of an air contaminant or water vapor in quantities that cause,

alone or in reaction with other air co ntaminants, 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 comf ortable 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 expens e, 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 Ai r Quality Division (AQD) in the format prescribed by the applicable reference test method within 60 day s following the last date of the test. (R 336.2001(4))

### Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c Expiration Date: December 31, 2011
PTI No: MI-PTI-A5754-2007c

Page 

### 8 of 

### 32 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 me thod 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 para meters 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 sa mple, 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 instrument ation 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 certific ation 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 certif y to the appropriate AQD District Offi ce 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 AQ D District Office pursuant to Rule 213(3)(c). This

certification shall include all the info rmation specified in Rule 213(4)(c)(i) through (v) and shall state that, based on information and belief formed after reasonable inquiry, t he 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 annua lly 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 defi ned in Rule 213(3)(c)(ii) as follows, unless otherwise
described in this ROP. (R 336.1213(3)(c))

a. For deviations that exceed t he emissions allowed under the ROP, prompt reporting means reporting consistent with the requirements of Rule 912 as detail ed in Condition 25. All reports submitted pursuant to this paragraph shall be promptly certif ied as specified in Rule 213(3)(c)(iii).

b. For deviations which exceed the emissions allow ed 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 exc eed the emissions allowed under the RO P, prompt reporting means the reporting of all deviations in the semiannual reports requi red by Rule 213(3)(c)(i). The report shall describe

the reasons for each deviation and the actions ta ken 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 ei ther of the following (R 336.1213(3)(c)) :

### Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c Expiration Date: December 31, 2011
PTI No: MI-PTI-A5754-2007c

Page 

### 9 of 

### 32 a. Submitting a certification by a resp onsible 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 cale ndar 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 certific ation by a responsible official which st ates 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 we re true, accurate, and complete”. The ce rtification shall include a listing of the reports that are being certif ied. 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 certificati on 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 fr equently if specified, the permittee shall submit certified reports of any required monitoring to the app ropriate 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 regulat ed air pollutant as defined in Rule 212(6) for each emi ssion unit utilizing the emissions inventory form s provided by the department. (R 336.1212(6))

25. The permittee shall provide notice of an abnormal condition, start-up, shutdo wn, or malfunction that results in emissions of a hazardous or toxic air pollutant which cont inue for more than one hour in excess of any applicable standard or limitation, or emissions of any air contami nant 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, in cluding electronic, telephonic, or oral communication. Written reports, if required under Rule 912, must be submit ted 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 condi tions 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 su mmary 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 ha ve been identified as non-applicable to this ROP and are included in the permit shield.

27. Nothing in this ROP shall alte r or affect any of the following: a. The provisions of Section 303 of the CAA, emergency orders, incl uding 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 fo r 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 prog ram, consistent with Sect ion 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 Se ction 114 of the CAA. (R 336.1213(6)(b)(iv))

### Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c Expiration Date: December 31, 2011
PTI No: MI-PTI-A5754-2007c

Page 

### 10 of 

### 32 28. The permit shield shall not apply to provisions incor porated 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 cove red 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 ap plication 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 t he 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 co mply 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 stati onary 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))

### Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c Expiration Date: December 31, 2011
PTI No: MI-PTI-A5754-2007c

Page 

### 11 of 

### 32 Renewals

35. For renewal of this ROP, an administratively complete appl ication 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 vehi cle 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 per forms 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 Vehicl e Air Conditioners. The term “motor vehicle” as used in Subpart B does not include a vehicle in which final as sembly of the vehicle has not been completed by the original equipment manufacturer. The term MVAC as us ed 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 t he risk management plan for reduci ng 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 quant ities, 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, Pa rt 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 pr esent 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 necessar y 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 redu ction credit trading are allowed pursua nt to any applicable interstate or regional emission trading program th at has been approved by the Admini strator of the USEPA as a part of Michigan’s State Implementation Plan. Such activi ties must comply with Rule 215 and Rule 216. (R 336.1213(12))

### Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c Expiration Date: December 31, 2011
PTI No: MI-PTI-A5754-2007c

Page 

### 12 of 

### 32 Permit To Install (PTI)

43. The process or proc ess equipment included in this permit shall not be reconstructed, relocated, or modified unless a PTI authorizing such action is issued by the depa rtment, except to the ext ent 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 perfor ming 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. T he request must include all of the information required by Subrules (1)(a), (b) and (c) of Rule 219. T he 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 sh all become void unless otherwise authorized by the department. Furthermore, the person to whom that PT I was issued, or the designated authorized agent, shall notify the department via the Supervisor, Permit Secti on, MDEQ, AQD, P. O. Box 30260, Lansing, Michigan 48909, if it is decided not to pursue the installation, reco nstruction, 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 Term s 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 appl y to this source, N/A (not applicable) has been used in
the table. If there are no Source-Wide C onditions, this section will be left blank.

### Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c Expiration Date: December 31, 2011
PTI No: MI-PTI-A5754-2007c

Page 

### 13 of 

### 32 

# 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 condi tion type does not apply, N/A (not applic able) 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 fire d by natural gas. It is also capable of incinerating NCGs in compliance with 40 CFR 63 Subpart S. 06/01/1989 N/A

### Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c Expiration Date: December 31, 2011
PTI No: MI-PTI-A5754-2007c

Page 

### 14 of 

### 32 

# 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/hour 2 

### Per hour limit based on 3 hour average. EUCOPE V.1 R 336.1331,
40 CFR 52.21

2. Sulfur Dioxide

(SO 2 

### ) a. 2.62 lbs/hour 2 

### EUCOPE V.1 R 336.1402(2),
40 CFR 52.21

b. Less than 0.02 lbs per MM BTUs heat input 2 

### 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 scrubber 2 

### 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

scrubber 2 

### 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 RTO 2 

### 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 RTO 2 

### 24 hour average EUCOPE V.1 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 

### 15 of 

### 32 II. MATERIAL LIMIT(S) N/A



### III. PROCESS/OPERATIO NAL RESTRICTION(S)

1. Permittee shall operate the Copeland reactor in acco rdance with a malfunction abatement plan to prevent, detect, and correct malfunctions or equipment failure s 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 unl ess 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 Copel and/RTO, at the owner’s expe nse, to verify compliance with the CO, PM, NOx, SO 2 

### , RTO (VOC/HAP) destruction efficiency, and Gaseous organic HAPs. Testing shall be within the five year life of this permit and in acco rdance 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, SO 2 

### , 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 Genera l Conditions 19 and 20 of Part A. The report shall be postmarked or received by the appropriate AQD District O ffice 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 

### 16 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.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 temperat ure 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 monito ring 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 re cordkeeping 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 sha ll 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).

### Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c Expiration Date: December 31, 2011
PTI No: MI-PTI-A5754-2007c

Page 

### 17 of 

### 32 

# 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. SO 2 

### a. The SO 2 

### 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 SO 2 

### 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 coal 2 

### 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/OPERATIO NAL RESTRICTION(S)

1. Upon initiation of collector bypas s, 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 enclos ed 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 emission s 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 me thod acceptable to the department.

3. The permittee shall obtain and keep records of the sulf ur, 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 sy stem shall comply with the instrument span requirements specified in Rule 1154. ( R 336.2154)

6. The continuous opacity monitoring syst em 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 subm it a summary report in an acceptable format to the Air Quality Division to incl ude 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 Genera l Conditions 19 and 20 of Part A. The report shall be postmarked or received by the appropriate AQD District O ffice 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 basis 2 

### Test Protocol Ash Silo N/A R 336.1331



### II. MATERIAL LIMIT(S) N/A



### III. PROCESS/OPERATIO NAL 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 Genera l Conditions 19 and 20 of Part A. The report shall be postmarked or received by the appropriate AQD District O ffice 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 cont rol or suppression mechanisms. The log shall also include observations of the Ash Handling and Storage activi ties 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. SO 2 

### a. SO 2 

### emissions shall
not exceed 1.67 lbs. per billion BTUs heat input 2 

### Per 24 hour period. # 2A Package

Boiler Test Protocol R 336.1401,

Table 42

b. SO 2 

### emissions shall

not exceed117 tons 2 

### 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 percent 2 

### 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/OPERATIO NAL 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 wi thin five years of issuance of this ROP. The package boiler tested and the test method sh all be approved by the Department. (R 336.1213(3), R 336.2001)

2. Visible observation of the boiler emissions shall be co nducted 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 Insp ection and Maintenance Program, specified in IX. The records shall include but not be limited to, records of insp ections, problems identified, repairs and or corrective action taken, scheduled and completed maintenance, and re cords 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))

### Smurfit-Stone Container ROP No: MI-ROP-A5754-2007c Expiration Date: December 31, 2011
PTI No: MI-PTI-A5754-2007c

Page 

### 24 of 

### 32 4. Annual certification of compliance pursuant to Genera l Conditions 19 and 20 of Part A. The report shall be postmarked or received by the appropriate AQD District O ffice 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 Maint enance Program for the No. 2A Package boiler, including keeping a log, to assure that the process equipment is maintained and operat ed in a satisfactory manner and in accordance with the Michigan Air Pollu tion 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. SO 2 

### SO 2 

### emissions shall not exceed 1.67 pounds per million BTUs heat input 2 

### 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 oil 2 

### N/A No. 3 boiler Test protocol R 336.1201(3)



### III. PROCESS/OPERATIO NAL 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 wi thin five years of issuance of this ROP. The package boiler tested and the test method sh all 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 SO 2 

### emissions. The SO 2 

### emissions may be calculated from the fuel usage. (R 336.1201(3))

2. Records shall be kept in accordance with the Insp ection and Maintenance Program, specified in IX. The records shall include but not be limited to, records of insp ections, problems identified, repairs and or corrective action taken, scheduled and completed maintenance, and re cords 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 usa ge 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 Genera l Conditions 19 and 20 of Part A. The report shall be postmarked or received by the appropriate AQD District O ffice 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 Main tenance Program for the No. 3 Package boiler, including keeping a log, to assure that the process equipment is maintained and operat ed in a satisfactory manner and in accordance with the Michigan Air Pollu tion 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/OPERATIO NAL 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 wi thin five years of issuance of this ROP. The package boiler tested and the test method sh all be approved by the Department. (R 336.1213(3), R 336.2001)

2. Visible observation of the boiler emissions shall be co nducted 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 Genera l Conditions 19 and 20 of Part A. The report shall be postmarked or received by the appropriate AQD District O ffice 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 Main tenance Program for the No.4 Package boiler, including keeping a log, to assure that the process equipment is maintained and operat ed in a satisfactory manner and in accordance with the Michigan Air Pollu tion 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 condi tion type does not apply, N/A (not applic able) 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 deter mined 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 abbrevia tions/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 N SPS New Source Performance Standards

CO Carbon Monoxide NSR New Source Review

COM Continuous Opacity Monitoring PM Particulate Matter

department Michigan Department of Environmental Qualit y 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 Preventi on 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

H 2 S 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 SO 2 Sulfur Dioxide

LAER Lowest Achievable Emission Ra te 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 me asured 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 sp ecifications 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 fo rmats must be approved by t he AQD District Supervisor.

1. Coal Analysis

a) For each coal shipment received, th e permittee shall obtain from the coal supplier a laboratory analysis of the ash content, sulfur content, and the BT U 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 ma de 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 averagi ng 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 e ffective 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 Certificat ion form (EQP 5736) and MDEQ Deviation Report form (EQP 5737) for the annual, semiannual and deviation certificat ion 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), res pectively, and be approved by t he AQD District Supervisor.

B. Other Reporting

Specific reporting requirement format s 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.